UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Market-Based Rates for Public Utilities
Docket No. RM04-7-000
COMMENTS OF
THE AMERICAN PUBLIC POWER ASSOCIATION AND
THE TRANSMISSION ACCESS POLICY STUDY GROUP
Pursuant to the Commission’
s February 11, 2005 “
Notice Inviting Comments,”the
American Public Power Association (“
APPA”
) and the Transmission Access Policy Study Group
(“
TAPS”
) submit these joint comments on the generation market power prong of the
Commission’
s market-based rate (“
MBR”
) test. APPA and TAPS support the Commission’
s
continued re-examination of its MBR program. APPA and TAPS members want –and the
Commission’
s reliance upon market pricing under the Federal Power Act (“
FPA”
) requires –a
wholesale market that offers meaningful choices among competing power suppliers. The
Commission’
s MBR test must support with factual evidence, not market theory, the conclusion
that sufficient supply choices exist to discipline MBR sales to just and reasonable levels, and that
specific MBR sellers either lack or have mitigated their market power. To ensure that the MBR
test meets these statutory requirements, APPA and TAPS submit these comments.
The Interim Screens, Delivered Price Test (“
DPT”
), rebuttable presumptions, and default
mitigation adopted last year in the MBR orders, AEP Power Marketing, Inc., 107 F.E.R.C.
¶ 61,018 (2004) (“
MBR Order”
), order on rehearing, 108 F.E.R.C. ¶ 61,026 (2004) (“
MBR
Rehearing Order”
), are a significant improvement over prior Commission practice, because the
Commission now examines a broader array of evidence bearing on the ability and incentive of a
seller to exercise market power. APPA and TAPS strongly oppose efforts to weaken this
-2regimen, for example, by adoption of the so-called “
Contestable Load Analysis”promoted by the
Edison Electric Institute and a number of its members. While such proposals are premised on
the claimed unfair result that a majority of vertically integrated, control-area operating public
utilities failed the Interim Screens, particularly the Market Share Screen, the Commission should
not shy away from the closer look it has undertaken in the ongoing Section 206 investigations.
The investigated public utilities are dominant suppliers in their regions, and it is entirely
appropriate that the Commission undertake a more thorough assessment of their market power
potential.
The Commission should also not be overly concerned about “
false positives.”Sellers
who in fact do not possess market power will presumably be able to make the requisite showings
in their Section 206 investigations to overcome any initial, false positive results. The far greater
risk is the false negative –sellers with market power that nonetheless pass the Screens.1 Unless a
separate complaint proceeding is initiated, customers will not have no vehicle in which to rectify
a false negative result. As noted by Professor Darren Bush in his attached Affidavit,2 the
Contestable Load Analysis will only significantly increase the risk of false negatives. Bush Aff.
at ¶ 26.
APPA and TAPS propose refinements to the interim MBR test intended to fill holes that
could cause the Commission to overlook important evidence bearing on the seller’
s market
power or that create analytical flaws. We also propose a Generation Market Power Test that
APPA and TAPS believe is better suited to the dynamic nature of electricity markets and allows
1
Accord January 27, 2005 Technical Conference Transcript (Tr.) at 35 (Goulet) (“
We believe that an entity can pass
the interim screens and yet still possess the potential to exert market power.”
). All transcript cites are to the
January 27, 2005 technical conference in RM04-7-000, unless otherwise indicated.
2
Professor Bush as an assistant professor at the University of Houston Law Center where he teaches courses and
writes on antitrust, regulated industries, and law and economics. He also holds a Ph.D. in economics.
-3consideration of the specific and non-uniform impacts of retail rate regimes and long-term
contracts on the ability and incentive of a seller to exercise market power.
EXECUTIVE SUMMARY

 The Commission should replace its Interim Screens with APPA/TAPS’
s proposed
Generation Market Power Test. Elements of the Generation Market Power Test include a
Horizontal Market Power Screen, which utilizes pivotal supplier, concentration and supply
curve metrics, and the examination of Effects Factors (sales and transactions, native load
obligations, entry conditions, transmission control, demand elasticity and other regional or
local factors). The Generation Market Power Test is detailed in the Appendix to these
Comments.

 Assuming the Commission does not adopt the APPA/TAPS proposal, the Commission
should refine, not weaken, the existing MBR test, by:
o Conducting the Pivotal Supplier Screen on a monthly basis to account for the fact that
suppliers can be pivotal at times other than the annual system peak.
o Calculating Uncommitted Capacity under the Market Share Screen to include all capacity
available to compete in wholesale markets at some point during the season by deducting
an applicant’
s minimum load, not just minimum peak day load, from installed capacity.
o Including a concentration metric, such as the Herfindahl-Hirschman Index (“
HHI”
), in
the Market Share Screen to measure collusion risks.
o Rejecting the “
Contestable Load Analysis”and its variants, because the approach is
fatally flawed, affords applicants excessive discretion, and is not necessary to overcome
claimed defects of the Market Share Screen.
o Encouraging analysis of historical data and other market-specific facts as a supplement
to, not a substitute for, the Delivered Price Test (“
DPT”
).
o Lowering the threshold for passing the HHI component of the DPT to 1800, because the
current 2500 threshold is excessive and improperly transplanted from its origins.

 The Commission must take realistic account of transmission constraints, not merely give
them lip service, when it defines relevant geographic markets and determines transmission
import capability.
o The Interim Screens’default geographic market definition –the applicant’
s home control
area or, in the case of ISO/RTO markets, the ISO/RTO footprint –must be genuinely
rebuttable.
o Simultaneously Available Transmission Capability (“
ATC”
) should be used as the
measure of transmission capacity when performing the MBR test.
-4
 Where an applicant is found to possess market power, remedies should be targeted to
effectively eliminate the seller’
s ability and incentive to exercise market power. With its
ample authority, the Commission should adopt remedial conditions to achieve structurally
competitive markets, including:
o Reducing the seller’
s dominant generation position by putting the ownership or control
of generation capacity into the hands of competitors.
o Providing customers embedded in a dominant MBR seller’
s own transmission system
access to broader markets through transmission set-asides and clarification of network
customer roll-over rights.
o Increasing the ability of buyers and sellers to reach each other by promoting
development of a robust transmission grid through targeted upgrades, inclusive
transmission planning on a regional basis, and expanding ownership and participation
in transmission to all load serving entities (IOUs, municipalities, and cooperatives).

 The Commission correctly requires cost-based rates and sales where a seller has not
mitigated its market power.

 Where necessary to address market power, MBR authority should be denied even outside
an applicant’
s control area, due to the discriminatory and market-distorting effects of the
seller’
s failure to provide embedded customers access to the broader market.

 The Commission should not exempt from the MBR test sellers solely with post-1996 units,
because market power risk can be posed by any seller, regardless of the age of its facilities.

 The Commission should not automatically accept ISO/RTO mitigation as adequate to
mitigate an MBR seller’
s market power. Instead, there must be fact-based findings that the
mitigation measures address the market power problems presented by the applicant.

 The Commission should organize MBR reviews on a regional basis to improve the
availability and access to data needed for such reviews. However, such regional review
does not mean pre-defining geographic markets as regional absent a proper, fact-based
definition of the geographic market.

 The Commission should not extend the Interim Screens to ancillary services markets,
because of the greater competitive concerns presented by such markets.

 The apparent over-designation of data as Critical Energy Infrastructure Information
(“
CEII”
) and the inability of intervenors to conduct a DPT in 21 days greatly impairs
meaningful participation. The Commission needs to remedy the great difficulty market
participants have obtaining and using data necessary to assess an MBR filing by
automatically extending the response time by up to 60 days where an intervenor seeks
needed CEII or intends to submit a DPT.
-5
 The Commission should condition MBR sales to require regular reporting of the sales and
transmission data it and market participants need to conduct the MBR test.
COMMENTS
I.
THE COMMISSION SHOULD REFINE, NOT WEAKEN, THE EXISTING
TEST
A.
The Commission Has a Legal Obligation to Examine the Market Power
Risk Posed by MBR Applicants
To find a market-based rate lawful, the Commission must find that a seller “
lacks market
power (or has taken sufficient steps to mitigate market power), coupled with strict reporting
requirements to ensure that the rate is ‘
just and reasonable’and that markets are not subject to
manipulation.”Cal. ex rel. Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004). Pursuant to
its MBR policy, the “
Commission allows power sales at market-based rates if the seller and its
affiliates do not have, or have adequately mitigated, market power in generation and
transmission and cannot erect other barriers to entry. The Commission also considers whether
there is evidence of affiliate abuse or reciprocal dealing.”See Alliant Energy Corp. Servs., Inc.,
109 F.E.R.C. ¶ 61,289, P 27 (2004).3 The Commission’
s determinations cannot be abstract or
theoretical. Rather, there must be “
empirical proof”that “
existing competition would ensure that
the actual price is just and reasonable.”Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d
1486, 1510 (D.C. Cir. 1984). The Commission’
s MBR test must satisfy its legal obligations.
B.
The Pivotal Supplier Screen Should Be Conducted For Monthly, Not
Just Annual, Peaks
The Pivotal Supplier Screen examines an extreme case –the peak month (MBR Order
P 91) -- and ignores the fact that a supplier could be pivotal at other times. In the affidavit
3
Citing Progress Power Marketing, Inc., 76 F.E.R.C. ¶ 61,155 at 61,921-22 (1996); Northwest Power Marketing
Co., L.L.C., 75 F.E.R.C. ¶ 61,281 at 61,899-900 (1996); accord Heartland Energy Services, Inc., et al., 68 F.E.R.C.
¶ 61,223 at 62,062-63 (1994).
-6accompanying APPA/TAPS’
s February 4, 2004 SMA Comments (hereafter “
Kirsch SMA
Affidavit),4 economist Dr. Laurence Kirsch explained (at 8-9):
Screens should recognize that the ability to exercise market power
changes over time with changes in load levels, generation output,
and the availability of generation and transmission facilities. At a
minimum, screens should examine market power for the on-peak
and off-peak periods of the different seasons and, as appropriate,
for forthcoming years.
The Commission Staff has previously proposed to conduct the pivotal supplier analysis on a
monthly basis to capture changes in the applicant’
s market power.5 But for the Commission’
s
decision to use a native load proxy reflecting the average peak loads in the peak month, MBR
Order P 91, the pivotal suppler analysis would measure only the most extreme and rare situation
in which a suppler can single-handedly reduce operating reserves margins to levels that trigger
emergency procedures or even require load shedding. As Dr. Kirsch has pointed out: “
This
ability to cause system distress is certainly sufficient to establish the ability to exercise market
power; but there are many other situations in which a supplier can exercise market power
without having such an ability.”Kirsch SMA Affidavit at 9. See also Tr. at 11 (Bushnell).
A monthly analysis is particularly important to gauge the effect of outages. Both the
seller’
s and its competitors’planned outages could have dramatic effects on the pivotal supplier
result. More generation should be on-line during peak seasons, and the larger amount of supply
4
February 4, 2004 “
Post-Technical Conference Comments of the American Public Power Association and the
Transmission Access Policy Study Group,”filed in Docket No. PL02-8-000, Conference on Supply Margin
Assessment (“
February 4, 2004 SMD Comments”
), available at
http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=10057963 (last visited March 11, 2005). APPA and
TAPS filed Dr. Kirsch’
s affidavit in RM04-7-000 on June 30, 2004.
5
Conference on Supply Margin Assessment, Notice of Technical Conference, Staff Paper at 6-7 (December 19,
2003) available at http://www.ferc.gov/EventCalendar/Files/20040112104841-PL02-8-000-notice.pdf (last viewed
March 11, 2005). Given the data that applicants must already gather, running the Pivotal Supplier Screen for each
month represents an insignificant amount of additional work.
-7available to the market presents competitive conditions different from the supply situation when
plants are on scheduled outage.6
A monthly Pivotal Supplier Screen is also needed to help ensure that suppliers with
market power, but that pass the Market Share Screen because they have less than 20 percent
market share in any season, are captured. In the MBR Order (P 104), the Commission observed
that: “
While a supplier with less than a 20 percent market share, in certain circumstances, can
affect the market price during periods of limited supply alternatives, our pivotal supplier analysis
addresses such situations by examining whether there are sufficient competing supply
alternatives to meet the market’
s peak load.”However, the Pivotal Supplier Screen will only do
this if the supplier happens to be pivotal during the peak month. It is plainly insufficient under
the FPA for the Commission to needlessly narrow its Pivotal Supplier Screen to just the single
peak month, ignoring the potential for exercise of market power in other months.
C.
The Market Share Screen Should Be Made More Accurate and Robust
1.
The Market Share Screen’
s Calculation of Uncommitted Capacity
Ignores Generation Available to Compete in the Wholesale Market
The Market Share Screen’
s calculation of Uncommitted Capacity uses a native load
proxy based upon the minimum peak demand day in a given season. MBR Order P 92.7 The
6
The MBR Order (P 97) does not require that the annual peak-based Pivotal Suppler Screen reflect scheduled
outages. If conducted on a monthly basis, the Pivotal Supplier Screen should reflect planned outages.
7
As explained below in Part V.B., the Commission’
s blunt elimination of native load obligations is analytically
insupportable. However, if the Commission continues to examine just a portion of a seller’
s total capacity, that
capacity must in turn define the extent of the MBR authorization. MBR sellers wanting the freedom to sell from all
of their capacity at MBRs must be willing to have the impact of that capacity on wholesale markets considered.
MBR sellers that insist on denominating part of their generation holdings as “
committed”to serve retail native load
must live with the consequences –cost-based rates for sales from such capacity. Native load will still benefit from
cost-based sales revenues (assuming the state regulatory authority requires revenue crediting). If dominant MBR
sellers want a bigger upside potential associated with market-based sales, and they succeed in their attempt to
convince the Commission to enact generation market power screens that do not fully capture the extent of their
potential to exercise generation market power, they should not be authorized to make MBR sales from capacity they
themselves claim is unavailable to make such sales.
-8Commission claimed in the MBR Order (P 90) that this proxy is conservative, but in fact it is
inconsistent with the Commission’
s desire for a proxy that reflects “
all of the capacity that is
available to compete in wholesale markets at some point during the season.”Id. P 92. To fulfill
the Commission’
s intent, the proxy should be the minimum load day of each season.
The Commission stated:
By subtracting the generation needed to serve native load on the
minimum load day of the season, we identify all of the capacity
that is available to compete in wholesale markets at some point
during the season. In other words, the use of this proxy for native
load reflects the fact that the rest of the applicant’
s generation was
uncommitted and available at some point during that season to sell
in wholesale markets. For the purpose of constructing a
reasonably balanced conservative screen, we will consider all such
available capacity for both applicants and competing suppliers.
Id. P 92 (emphasis added); see also P 89 (quoting Louisville Gas & Elec. Co., 62 F.E.R.C.
¶ 61,016, at 61,146 (1993)). However, the MBR Order’
s proxy –minimum peak day load in a
season –identifies only some of the capacity available to compete in wholesale markets during
the season. It considers only the capacity measured by the difference between the needle peak
and the minimum peak while ignoring the capacity measured by the difference between the
minimum peak and the minimum load. It thus fails to reflect the Commission’
s intent that the
Market Share Screen measure market power during off-peak times. Id. P 72.
2.
The Market Share Screen Needs a Concentration Metric, Such As
HHI, to Assess Collusion Risks
The Commission intends the Market Share Screen to measure the risk of “
coordinated
interaction with other sellers”and an “
applicant’
s size relative to others in the market.”MBR
Order P 72. However, the Commission has left out the critical ingredient needed to assess the
risk of coordinated interaction among sellers: a concentration measure. To complete the recipe,
the Commission should incorporate the HHI metric into the Market Share Screen.
-9A seller’
s market share alone gives an incomplete picture of collusion risk. Professor
Bush explains that (Aff. ¶ 15):
HHI recognizes that differences in the relative size of the market
participants matter. Concentration measures utilized prior to the
adoption of the HHI methodology did not account for the presence
of dominant firms in a market. In contrast, HHIs explicitly
recognize that disparities in power between firms may lead to
heightened market power –firms may merely follow the behavior
of the firm with the greatest market share, for example.
Collusion risk in a 2-seller market where one seller has 25% market share and the other seller has
75% market share looks far different from a 6-seller market where the 25%-share seller competes
against 5 other sellers each having 15% market share. In the first market, the 25% seller may not
be dominant vis-à-vis the 75% seller, but the collusion risk will be very high. In the second
market, the 25% seller is dominant, but the collusion risk is relatively lower because of the
existence of five competitors. See also Tr. at 189 (Wroblewski).
Thus, the Commission needs to incorporate a concentration measure. HHI is widely
accepted, including by the Commission, and easily calculated once market shares are known. It
is simply the sum of the squared market shares. For the reasons discussed in Part I.F. below, the
Commission should use the Horizontal Merger Guidelines and FERC Merger Policy HHI
thresholds: Unconcentrated < 1000 < Moderately Concentrated < 1800 Highly Concentrated. In
the first market above, the HHI would be 6250, indicating very high concentration with great
collusion risk. In the second, the HHI is 1750, indicating close to high concentration with
potential collusion risk –enough that the Commission should take a closer look –but not nearly
as high as the first market.
- 10 The Commission, while retaining the current rebuttable presumption associated with
passing or failing the Market Share Screen, should incorporate the HHI in the following
manner:8

A seller with a market share of 20% or more, regardless of concentration, would fail the
screen, because of the risks posed by its dominance. See MBR Order P 103.

A seller with a market share of less than 20% in a highly concentrated market may be
deemed to pass the screen if it also makes a showing that collusion risks are not elevated
despite the concentration level.

A seller with less than 20% market share in a moderately or unconcentrated market would
pass the screen. Id. P 102.
D.
The Commission Should Not Adopt a “Contestable Load Analysis”
EEI, along with a number of its members, have promoted an approach labeled “
Historical
Contestable Load Analysis”(“
HCLA”
) as an alternative to the Market Share Screen and as
additional evidence in Section 206 investigations where an applicant has failed one or both
screens. According to EEI, HCLA “
focuses on the determination of the relationship between the
wholesale loads that were actually seeking competitive supply alternatives (contestable loads) in
the relevant market and the competitive generation resources that were available to serve those
9
loads.”
Another version of HCLA, propounded by AEP, reduces the capacity shares of the
applicant and competing suppliers to the extent that estimated capacity of each exceeds the
amount of contestable load.10 The Commission should reject HCLA and its variants. It is
8
As demonstrated in Part I.F. below, in applying the HHI component of the Delivered Price Test, the Commission
should not use a 2500 HHI, but instead use 1800, unless it also uses a 15% market share threshold.
9
Testimony of Louis R. Jahn, Director, Wholesale Market Policy, Edison Electric Institute, Before the Federal
Energy Regulatory Commission on Generation Market Power Screens, distributed at January 27, 2005 Technical
Conference, at 2 (hereafter “
Jahn”
).
10
AEP Power Mktg, Inc., 109 F.E.R.C. ¶ 61,276, P 23 (2004); November 19, 2004 Response of AEP to October 29,
2004 Deficiency Letter, at 8, Docket No. ER96-2495-023, et al.
- 11 analytically flawed, provides applicants with too much discretion to define the analysis,11 and is
unnecessary to overcome claimed shortcomings in the Market Share Screen.
1.
Contestable Load Analysis Has Fatal Analytical Flaws
HCLA suffers from a number of insurmountable flaws that make it an unacceptable
approach to market power analysis. These flaws cause HCLA to present a distorted picture of
the applicant and its place in the market. It thus provides no basis for concluding that an MBR
applicant lacks market power.
In the form EEI proposes, HCLA ignores the applicant’
s capacity altogether. It compares
the “
ratio of total competitive generation resources to total contestable load by product and
season during the historical test period.”Jahn at 14. The applicant’
s own capacity does not
enter the analysis, even if it is the dominant seller. However, ignoring the elephant in the room
does not prevent it from breaking the furniture.
Professor Darren Bush explains in the attached affidavit that the size and make-up of
firms’supply portfolios, as well as a firm’
s position vis-à-vis other firms, matters greatly in
competitive analysis (Affidavit ¶ 12):
One limitation of the contestable load analysis is that it ignores
differences among potential suppliers of products desired by
buyers. In particular, buyers may seek to purchase multiple
products from what are typically not homogenous suppliers. Such
products include capacity, energy, load-following service, and the
like. It is possible that some generation assets are able to provide
all of these products, but others are unable to do so. In such a
situation, it cannot be said that merely because a generator owns an
asset that could provide some of the buyer’
s needs (e.g., energy)
that it necessarily is a competitor to a generation owner that is able
to supply all of these products (e.g., load following service).
Rather, it is the combination of products that the buyer may seek.
The buyer, in seeking to purchase these products, will take offers
11
Even if applicant discretion could be reined in, HCLA’
s analytical flaws cannot be fixed.
- 12 from firms that can provide them. Thus, buyers could only turn to
a subset of the firms that would be included in either the AEP or
EEI contestable market analysis for supply.
The effect of supply portfolios on a firm’
s ability to compete is evident in the
marketplace. The fleet of a dominant seller allows it to compete for a wider variety of products,
whether load-following type contracts or firm capacity sales.12 Sellers with these capabilities can
economically add a new 25 MW wholesale load (backed by reserves) to their existing load
obligations, providing both firm power and load-following type services. By contrast, if an IPP
has just a single plant, it may have trouble “
firming up”the sale to ensure deliveries at times of
plant outages. Further, an IPP with a single, 500 MW combined cycle plant often can’
t make a
25 MW unit capacity sale unless it has an “
anchor tenant”to purchase the bulk of its plant output
and ensure efficient plant operation. The 25 MW sale will not be a viable option. The IPP is
also unlikely to be in a position to provide a load-following type service and is subject to
substantial energy imbalance penalties under the Order No. 888 Open Access Transmission
Tariffs (“
OATTs”
) that the dominant seller with its own control area (usually the transmission
provider) doesn’
t have to worry about.
Professor Bush further explains “
contestable load analysis dispenses with both structural
and effects analysis, instead favoring an ‘
add ‘
em up’approach to calculating market shares for
12
These combined merchant and rate base fleets together support wholesale marketing activities. According to The
Cruthirds Report, Southern Company reported that “
it earned about $220 million from its ‘
competitive generation’
business in 2004 - $111 million from Southern Power´s generation (unregulated affiliate — a large percentage of
those sales are to Southern Company regulated utility affiliates resulting from questionably managed RFPs) and
$109 million from Southern’
s‘
embedded’(rate based) generation. Southern projected profits of $200 million from
the competitive generation business for 2005 - $90 million from Southern Power and $100 million from the
embedded generation. Southern earned about $53 million in “
opportunity sales”(trading floor profits) during 2004,
but is only projecting earnings of $35-38 million during 2005. The other $166 million expected to be earned by the
competitive generation business in 2005 is attributable to capacity payments under long-term PPAs.”See “
Special
Report: Southern Company Conference Call - 4th Quarter 2004 Financial Results,”The Cruthirds Report, January
26, 2004, available at http://www.thecruthirdsreport.com.
- 13 only the capacity that is excess to the supplier’
s own when it is the supplier’
s own capacity that
is of interest,”and in so doing “
forgos the hard work of determining whether a firm has the
incentive and ability to exercise market power.”Bush Aff. ¶ 20.
Calculations of market share serve a particularly important role in
providing enforcement agencies with insights into a market—
insights that would be lost under a contestable load approach.
First, the Guidelines’method of calculating market shares (i.e.,
HHIs) recognizes that differences in the relative size of the market
participants matter. Concentration measures utilized prior to the
adoption of the HHI methodology did not account for the presence
of dominant firms in a market. In contrast, HHIs explicitly
recognize that disparities in power between firms may lead to
heightened market power–firms may merely follow the behavior of
the firm with the greatest market share, for example.12 The
contestable load analysis, however, misses the whole point of
calculating HHIs in the first place. As EEI proposes it, the
dominant firm drops out of the picture altogether. As AEP
proposes it, competitors are truncated down to the same size.
Another important component of the Guidelines approach to
market share calculation is the focus on the merging parties (in
merger cases) or the firm whose conduct is alleged to violate
Section 2 of the Sherman Act (as monopolization or an attempt to
monopolize). The focus is on the firms that are of the most
competitive concern because the determination of the
anticompetitive effects/procompetitive benefits often arises from
their conduct. In other words, the purpose of the calculation of
market share is to determine whether the firms under antitrust
scrutiny might exercise market power. It is typically not the mouse
frolicking across the competitive field that is the problem, but
rather the elephant undaintedly stomping everything in its path that
the Guidelines seek to examine. By ignoring the disparate roles of
the firms in question and compiling only aggregate (and therefore
poor) indicators of a market’
s competitiveness, EEI’
s approach to
market analysis would not prove useful in detecting, preventing
and restraining exercises of market power.13
__________________________
12
An example from my antitrust course is helpful. In Industry X,
suppose there are five equally sized firm, each controlling 20
percent of the market. 20² + 20² + 20² + 20² + 20² = 2000 HHI.
In Industry Y, suppose there is one firm with 60% of the market,
and the rest are relatively small. 60² + 10² + 5² + 5² + 5² + 5² + 5²
+ 5² = 3850 HHI. A traditional measure of concentration (the four-
- 14 firm concentration ratio known as “
CR4") would indicate that the
first market is equally as troublesome as the second (CR4 would
equal 80 in both). The HHI, however, indicates that the second
market is far more troublesome.
13
While the EEI approach purports to examine concentration
among the competitive suppliers, Jahn Testimony at 8, such an
examination would be meaningless because it leaves out the firm
whose market power potential is the subject of the inquiry.
Bush Aff. ¶¶ 15-16.
Another failing of the contestable load analysis is its focus on the preferences of sellers,
rather than buyers, when defining markets. According to Professor Bush (Aff. ¶ 13):
The EEI contestable load analysis ignores the question that drives
market definition analysis under the Guidelines. Specifically, the
market definition portion of the Guidelines “
focuses solely on
9
demand substitution factors—i.e., possible consumer responses.”
In order to determine to whom the customers might turn for
supplies of these multiple products, antitrust enforcers would
typically ask the consumer to answer these questions, not the
supplier. “
Supply substitution factors—i.e., possible production
10
responses—are considered elsewhere in the Guidelines.”
However, it appears that the contestable load analysis gets it
exactly backwards. The EEI analysis requires identification of the
“
all loads within the relevant market that were actually subject to
competition (contestable loads),”but only after relevant markets
have been identified from the perspective of a supplier looking at
which market it can sell its product and who else is selling it.
Under the EEI analysis, it would be difficult for an antitrust
investigator to unearth whether buyers were subject to market
power by a small number of firms offering the full range of
products the buyer seeks.
____________________________
9
Guidelines at § 1.0.
10
Id.
In the form AEP proposes, the contestable load analysis also wrongly assumes that
potential alternative suppliers are equally able to compete. Claimed support for this approach
includes the Horizontal Merger Guidelines, § 1.41 n.15, which states: “
Where all firms share, on
a forward-looking basis, an equal likelihood of securing sales, the Agency will assign firms equal
- 15 shares.”Professor Bush explains that this provision of the Guidelines provides no support for
the use of a contestable load analysis in the electric utility industry.
Proponents of the AEP version of contestable load analysis point to
Guidelines Section 1.41 Footnote 15.14 As one of the Guideline’
s
authors points out, the “
one-over-n market”approach is useful
when the market in question has “
two essential characteristics:”
(1) a finite number of entitities possess a readily
identifiable set of assets essential for successful
competition; and (2) the extent of ownership or control
over the essential assets does not distinguish among these
entities in any important way. In the clearest case, all
competitors have the same costs, and each can supply the
entire market demand.15
Dr. Werden’
s discussion of the “
one-over-n market”takes place in
a section titled “
market shares based upon intangible assets”and is
essentially a discussion of auction markets. In contrast, Dr.
Werden’
s discussion of electricity takes place in a section titled
“
capacity-based market shares.”In that section, Dr. Werden notes
that there is substantial cost heterogeneity across generation units,
in part due to the type of facility (base load as opposed to peaking),
16
but also due to “
differences in fuel choice and unit age.”
Both
the AEP and the EEI forms of contestable load analysis ignore this
heterogeneity.
____________________________
14
Footnote 15 describes a “
one-over-n market”in which market
shares are assigned equally to all sellers in the market when “
all
firms have , on a forward looking basis, an equal likelihood of
securing sales.”Guidelines Section 1.41 n. 15. Examples of such
markets include “
markets for technologies or innovation and
Schumpetarian industries, in which competition occurs largely
through the introduction of new products or technologies and
competition is apt to be more ‘
for the market’than ‘
in the
market.’
”Gregory Werden, Assigning Market Shares, 70 Antitrust
L.J. 67, 86 (2002). While not limited solely to intangible goods,
the “
one over n market’approach has in fact been quite limited in
application. For a rare glimpse at the analysis, see United States v.
Ingersoll-Dresser Pump Co., 65 Fed. Reg. 55,271 (Sept. 13, 2000).
15
Gregory Werden, Assigning Market Shares, 70 Antitrust L.J. 67,
86 (2002).
16
Id. at 84.
- 16 As noted by Professor Bush, markets where the competitive interaction would support
use of the equal market share approach often involve auctions. For example, in United States v.
Ingersoll-Dresser Pump Co., 65 Fed. Reg. 55,271 (Sept. 13, 2000), the DOJ assigned, after an
extensive factual investigation of the relevant market,13 equal market shares “
based on capability
and bidding history”of the three or four pump manufacturers that could compete for contracts to
provide, among other things, pumps for power plants.14 DOJ also uses the equal market share
approach to assess competition in school milk auction markets where the competing dairies all
have sufficient route structures in a school district to supply the district’
s school milk needs.
In measuring the level of concentration within each of the affected
districts, all dairies and distributors that have sufficient route
structure in a school district to allow them to bid competitively on
that district’
s contract have been attributed an equal market share
for such school district. Merger Guidelines, at ¶ 1.41 n.15. This is
because all milk processors and distributors with an adequate route
structure in place within a school district may win such school
district’
s milk contract in any given year.15
Use of the equal market shares approach in MBR proceedings would require the
Commission to assume that in each of the possible product markets for which MBR
authorization would apply –long-term load following contracts, unit capacity sales, short-term
energy, to name just a few –all competitors are equally positioned to provide the product or
service. Such a picture of electricity markets strays far from reality. Particularly in the case of
vertically integrated, control area-operating public utilities holding MBR authority, other
13
The case involved a DoJ challenge to a proposed merger of two pump manufacturers. In the typical merger case
that results in a DoJ challenge, a complaint is filed only after the Department has conducted an investigation,
including through the use of its Second Request authority. See Clayton Act, 15 U.S.C. §§ 18a(e), 25 (2000).
14
15
65 Fed. Reg. 55,271, at 55,272 (quoting PP 23-26 of Complaint).
United States v. Suiza Foods Corp., “
Memorandum of United States in Support of its Motion for Preliminary
Injunction,”at 11 (Mar. 1999), available at http://www.usdoj.gov/atr/cases/f2300/2328.pdf (last viewed December
6, 2004).
- 17 competitors do not have the necessary fleet of generation units to provide the full array of
products many wholesale purchasers (including APPA and TAPS members) require or the
necessary route structure, i.e., transmission access, to compete on an equal footing in that control
area. As Anne Kimber testified,16 the inability of network customers to change Network
Resources materially limits the ability of competing supply to access contestable loads on an
equal basis with the transmission provider MBR applicant.17
Finally, there is no evident support for EEI’
s proposed criterion that: “
If the total
competitive generation resources were at least twice the total contestable load, the applicant will
be deemed to have passed the Historical Contestable Load Analysis.”Jahn at 14. Even if one
assumed that customers could cobble together a supply portfolio from among competing
generation resources, there is no logic or reason for selecting twice the contestable load as the
decisional rule. Contestable load could be 500 MW and non-applicant generation could be 2000
MW. If no one customer’
s demand exceeded 100 MW and the minimum amount of capacity the
competitive supplier had available for sale was a 200 MW block, the fact that supply exceeded
load by twice or more would not mean that load had meaningful alternatives.
16
Written Statement of Anne Kimber on Behalf of MMTG and TAPS for the December 7 Technical Conference,
filed December 7, 2004 available at http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10328815 (last
viewed March 13, 2005).
17
While EEI says that the applicant would “
provide a demonstration that transmission constraints would not have
limited access by the contestable loads to competitive generation during the historical test period,”Jahn at 14,
having the OATT on file cannot be deemed a sufficient demonstration. In addition to Ms. Kimber, Terry Huval at
the January 28, 2005 Technical Conference made clear that the Order No. 888 OATT is not sufficient to overcome
MBR applicant’
s transmission market power. Written Statement of Terry Huval on Behalf of the Lafayette Utilities
System and the Transmission Access Policy Study Group, prepared for the January 28, 2005 Technical Conference,
at 5, available at http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10391023 (last viewed March 12,
2005).
- 18 2.
Contestable Load Analysis Affords Excessive Discretion,
Allowing All Applicants to Pass
HCLA is a test that no savvy applicant should fail. According to EEI: “
the applicant
would have the opportunity to develop specific methodologies to meet the evidentiary thresholds
contained in the guidelines.”Jahn at 6. The only apparent “
bright line”evidentiary threshold is
the requirement that competitive generation resources exceed contestable load by two. Jahn at
14. All of the inputs are otherwise determined by the applicant. Given the discretion afforded to
an applicant to “
customize”these inputs, few, if any, competent applicants would fail the HCLA.
According to EEI, “
the applicant is given the opportunity under the guidelines to define
multiple product markets for use in the analysis, e.g., on-peak, off-peak, short-term, long-term,
etc.”Jahn at 6. While EEI says that where “
the total competitive generation resources were at
least twice the total contestable load, the applicant will be deemed to have passed the Historical
Contestable Load Analysis for the specified product and seasons,”Jahn at 14, EEI does not say
that the applicant’
s MBR authorization would be limited to just those products and seasons. So,
for example, the applicant could, at least in theory, claim blanket MBR authorization simply by
having “
passed”the HCLA performed for off-peak markets. The ease with which an applicant
could pass a tailor-made HCLA would make the now-discarded hub and spoke test look difficult.
Applicants would also get to “
identify all loads within the relevant market that were actually
subject to competition (contestable loads) by product for the historical test period.”Jahn at 6.
Determining just what wholesale customers are shopping for any particular product at some
point in time would be a difficult and imprecise undertaking. There is no central clearinghouse
for RFPs. The specific loads buying short-term energy could change day-to-day, or even hourto-hour, depending upon the economics of generation. The opportunities for creative counting
would be limited only the applicant’
s imagination. In fact, testimony at the January 27th
- 19 Technical Conference attested to the “
challenge”of calculating native load obligations, Tr. at 97
(Henderson). This implies that calculation of loads subject to competition will be similarly
challenging. The burden will inevitably lead HCLA’
s proponents to claim that the Commission
should defer to the applicant’
s calculation.
Further, while HCLA purports to impose a requirement that transmission be available to
the competing supply, it also allows the applicant to determine how transmission access is
measured. Jahn at 7. As described below, applicants have already found ways to perform the
simultaneous import capability studies required under the MBR Orders so that they overstate
actual transmission capacity. APPA/TAPS expect that the wide discretion given to applicants
under the proposed HCLA would result in even greater overstatements.
In sum, the extreme discretion that EEI proposes to allow applicants under its HCLA to
customize the assumptions used in their analyses all but assures each would pass. The track
record so far bears this out. EEI conceded at the January 27th Technical Conference that each
company that had included an HCLA or one of its variants in its MBR compliance filing had
passed. Tr. at 79-80 (Jahn). The 100% pass rate is no coincidence. EEI’
s proposal is truly an
illustration of the old saying, “
if you can’
t raise the bridge, lower the river,”thus allowing all of
its members’ships to pass unimpeded.
3.
HCLA is Not Needed to Overcome Claimed Flaws in the Market
Share Screen
EEI objects not only to what it believes to be the Market Share Screen’
s excessive flunk
rate. Tr. at 5-6 (Jahn), but it also claims that the “
Screen does not take into account the relative
size of total market demand to total uncommitted generation capacity which is a major factor in
assessing whether the applicant can exercise market power.”Jahn at 3-4. However, there are
very good reasons not to do as EEI suggests. The applicant that fails the Market Share Screen
- 20 can perform the DPT which examines supply and demand factors at peak, shoulder and off-peak
periods and examines what generation is in the market through the economic capacity measure.
EEI also claims that the “
native load proxy in the Market Share Screen seriously understates the
generation capacity actually required by the applicant to meet seasonal native load obligations
and therein overstates the generation capacity available to the applicant for wholesale market
sales.”Jahn at 4. In fact, the Market Share Screen suffers from the opposite problem: it
understates the capacity available to the applicant to compete. See Part I.C.1. above.
E.
Historical Data Should Supplement, Not Supplant, the Delivered Price
Test
The MBR Orders specified that if an applicant failed either of the Interim Screens and did
not go straight to mitigation, it must submit a DPT.
With respect to Southern Companies’request for guidance
concerning the additional types of data applicants may submit to
rebut the presumption [arising from failure of either of the
indicative screens], we clarify that applicants and intervenors may
present historical data including analyses that they believe most
accurately represent market conditions. With respect to forwardlooking analyses or studies, however, the Delivered Price Test is
the only market power study applicants may submit.
MBR Rehearing Order at P 27. While applicants and intervenors “
may also present evidence
based on historical wholesale sales or transmission data,”MBR Rehearing Order at P 25
(emphasis added), the MBR Orders makes clear that applicants that fail one or both screens and
do not proceed directly to mitigation “
must present a more thorough analysis using the
Commission’
s Delivered Price Test.”MBR Order at P 105.
The Commission should not accept historical data as a substitute for the DPT. The DPT
provides a known framework, based upon the well-accepted Horizontal Merger Guidelines, to
allow the Commission to make judgments about the risk of market power exercise on a forward-
- 21 looking basis. This perspective is appropriate. The MBR authorization is a forward-looking
authorization that is supposed to last three years.
Historical data, along with other actual experiences in the market, have a role: they serve
as vital, real world checks on the DPT. For example, the results of RFPs offer evidence about
whether customers have, in fact, found the supply options suggested by the DPT. The
Commission should consider such factual evidence. However, it needs to be considered as part
of a record that includes the DPT, not instead of the DPT.
F.
The 2500 Threshold for the HHI Component of the Delivered Price Test
is Unjustified and Too High
Applicants failing the Pivotal Supplier and Market Share Screens that submit a DPT to
demonstrate they lack market power must show an HHI of less than 2500 in the relevant market
for all seasons/load conditions, as well as show they are neither pivotal nor possess more than
20% market share. MBR Order P 111. The Commission’
s adoption of the 2500 HHI standard is
an unsupported, unjustifiable departure from its prior reliance on HHIs, and is contrary to
accepted antitrust economics. The Commission should instead establish 1800 as the threshold.
If the Commission retains a 2500 threshold, then consistency demands that it be used with the
15% market share standard the DoJ advocated in the oil pipeline industry comments from which
the 2500 HHI was lifted.18
There is no basis for using in the electric utility industry an HHI threshold proposed in
the context of the oil pipeline industry. Electricity generation markets present far different
economic characteristics. For example, oil pipeline transportation can be substituted with truck
18
See Comments of the United States Department of Justice in response to Notice of Inquiry Regarding MarketBased Ratemaking for Oil Pipelines, Docket No. RM94-1-000 (January 18, 1994) (“
Comments”
); U.S. Department
of Justice, Oil Pipeline Deregulation: Report of the U.S. Department of Justice (May 1986) (“
Oil Pipeline Report”
).
- 22 or ship transportation. Oil can be stored. Substitutability and storability, characteristics that do
not appear in electric generation markets, both provide means for market participants to defeat an
attempted price increase, which would make use of the higher 2500 HHI less risky for
consumers.
The Commission should adhere to the “
Unconcentrated < 1000 < Moderately
Concentrated < 1800 Highly Concentrated”schema set forth in its Merger Policy, which is based
upon the Horizontal Merger Guidelines. With respect to the Merger Guidelines’1800 threshold,
“
there has been fairly little quibbling about the precise thresholds that the government has
selected for creating presumptions about legality.”IV PHILLIP E. AREEDA ET AL., ANTITRUST
LAW ¶ 932a, at 154 (Revised Ed. 1998).19 In specific circumstances where justified by facts,
applicants or intervenors can seek to demonstrate that HHIs above or below 1800 do not or do
raise market power concerns.20
However, if the Commission does retain the 2500 standard, it should at least be consistent
with the DoJ Comments, which advocated a 15% — as opposed to the proposed 20% — market
share as the standard for presumption of no significant market power. See DOJ Comments at 13.
Nothing in the DoJ Comments suggests that the Commission gets to play pick and choose.
From a consumer protection standpoint, if a more generous HHI level is selected, it must be
married to a less generous market share threshold.
19
Even an 1800 HHI may be higher than appropriate. See, e.g., Thomas E. Kauper, The 1982 Horizontal Merger
Guidelines: Of Collusion, Efficiency, and Failure, in ANTITRUST POLICY IN TRANSITION: THE CONVERGENCE OF
LAW AND ECONOMICS 171, 189 (Eleanor M. Fox & James T. Halverson eds., 1984) (“
This [1800] level … is both
higher than economic analysis dictates, and too great a departure from judicially developed standards.”
)
20
Cf. Horizontal Merger Guidelines, § 1.5 (noting that thresholds provide a framework, not precise lines of
demarcation).
- 23 II.
THE COMMISSION MUST TAKE REALISTIC ACCOUNT OF
TRANSMISSION CONSTRAINTS, NOT GIVE THEM LIP SERVICE
A.
Geographic Market Definition Must Reflect Market Reality
The MBR Orders noted the role that transmission constraints play in defining geographic
markets, whether outside of ISO/RTO markets or in them. For example, in the MBR Rehearing
Order (P 177), the Commission expressly recognized that even in an RTO with Commissionapproved market monitoring and a single energy market, an RTO-wide geographic market is
rebuttable on a case-specific basis:
[S]ome parties claim that the Commission should not have allowed
participants in ISO/RTO markets to use that region as the default
relevant geographic market because internal transmission
constraints can give rise to relevant geographic areas smaller than a
single control area and/or an entire ISO/RTO. We recognize,
however, that the ISO/RTO footprint or control area will not
always be the appropriate geographic area to consider and have
afforded the opportunity for the default relevant geographic market
to be rebutted on a case-specific basis.
This rebuttable presumption is consistent with prior Commission recognition of the role that
transmission constraints can play in separating markets, even in ISO/RTOs. For example, in
Wisvest-Connecticut, LLC, the Commission rejected arguments that the entire ISO-NE footprint
should serve as the relevant geographic market, citing the role of transmission constraints in
creating smaller geographic markets:
Clearly, during periods when transmission becomes so constrained
such that no additional imports from outside the region are possible
and generators located inside the region are the only suppliers that
can sell inside the region (i.e., the region is a "load pocket"), the
region should be defined as a separate relevant geographic market.
Wisvest Connecticut, LLC, 96 F.E.R.C. ¶ 61,101, at 61,401 (2001). See also Tr. at 38 (Goulet).
Despite statements that it would take transmission constraints into account in determining
relevant geographic markets, Commission practice so far reveals those statements to be empty
- 24 promises. For example, the Commission has ruled that sellers into MISO’
s Day-2 markets can
assume that the entire MISO footprint represents the relevant geographic market, without even
considering clear evidence and Commission findings that sub-regions of MISO were cut-off
from the rest of the market because of transmission constraints. See Alliant Energy Corporate
Services, Inc., 109 F.E.R.C. ¶ 61,289 (2004), reh’
g pending. If known load pockets such as the
Wisconsin Upper Michigan System, the Delmarva Peninsula, Southwest Connecticut, or the City
of San Francisco do not rebut the geographic market presumption, or at least make the issue
appropriate for investigation, the rebuttable presumption effectively becomes irrebuttable.21
Indeed, ignoring the effect of these constraints on price separation in ISO/RTO regions is
inconsistent with the locational pricing that is Commission policy in RTO markets. Pricing
becomes locational because generation from outside an area cannot compete with generation
within an area due to transmission constraints. Prices then separate between the areas. In
Merger Guidelines parlance, buyers within the constrained area cannot turn to suppliers outside
the area in response to a price increase caused by sellers within the area, thus making the area a
separate geographic market. Horizontal Merger Guidelines, § 1.21. Failure to take account of
the economic realities of the Commission’
s LMP-policy renders the geographic market
presumption irrebuttable.
B.
The Simultaneous Import Capability Study Fails to Reflect Actual
Transmission Constraints
In the MBR Orders (P 82), the Commission announced that it would make a more
realistic evaluation of transmission capability:
Given the experience we have gained regarding market power
issues and competitive markets in general, and in concert with our
21
See also Tr. at 133 (Solomon noting that the “
hurdle is fairly steep”for overcoming the presumption).
- 25 improved and more robust generation market power studies
adopted herein, we find that a more realistic evaluation of
transmission in general is warranted. Thus, rather than continuing
to assume an unrealistically high degree of transmission access for
competitors, we will adopt a more realistic measure for such
import capability. We will require a transmission-providing
applicant to conduct simultaneous transmission import capability
studies for its home control area and each of its interconnected
first-tier control areas. These studies will be used in the pivotal
supplier screen and market share screen to approximate the
transmission import capability.
While this innovation was certainly well intentioned, experience so far with the actual
implementation of the simultaneous import capability study requirement is that it largely fails to
provide “
a more realistic evaluation of transmission.”APPA and TAPS understand that in MBR
compliance filings so far, transmission providers have claimed significant amounts of
simultaneous import capability. At the same time, the Commission has heard from market
participants that transmission capacity needed for economic transactions cannot be obtained from
the same transmission providers. For example, on behalf of TAPS and MMTG, Anne Kimber
testified at the December 7, 2004 Technical Conference to the inability of loads of less than a
megawatt to secure firm transmission paths into the MidAmerican Energy system in Iowa.22
Terry Huval, appearing on behalf of TAPS and Lafayette Utilities System at the January 28,
2005 Technical Conference, described Lafayette’
s difficulty bringing power into the Entergy
system from CLECO, despite Lafayette’
s having a firm path.23 In other instances in the West
22
Written Statement of Anne Kimber on behalf of MMTG and TAPS for the December 7 Technical Conference,
filed December 7, 2004 available at http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10328815 (last
viewed January 21, 2005).
23
Written Statement of Terry Huval on Behalf of the Lafayette Utilities System and the Transmission Access Policy
Study Group, prepared for the January 28, 2005 Technical Conference, at 5, available at
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10391023 (last viewed March 12, 2005).
- 26 and Midwest incumbent utilities have fully reserved key interfaces in both directions, yet still
reflect that transmission as available to competitors.
The simultaneous import capability study requirement is failing to present a realistic
picture of transmission availability. The Commission therefore needs to switch to a measure that
does: Simultaneously Available Transmission Capacity (“
ATC”
). The Commission already
requires ATC for the Appendix A merger analysis. In the MBR context, it must also base its
analysis on what market participants must rely upon when seeking to transact in the market.
OASIS sites post ATC for both firm and non-firm transactions. While ATC measures are not
perfect, they reflect the transmission capacity market participants are told is available when they
determine the feasibility of a transaction. The requirement that Commission MBR decisions be
based on empirical proof means that the Commission must take markets as it finds them. If the
Commission looks at markets as they operate today, it will find ATC as the measure of
transmission capability. Thus, the Commission should require sellers to calculate the
simultaneous available import capability of their systems, which would take account (and
deduct) existing firm reservations, CBM, TRM and other transmission commitments.24
III.
REMEDIES SHOULD BE TARGETED TO ELIMINATE THE
INCENTIVE AND ABILITY OF THE MBR APPLICANT TO EXERCISE
MARKET POWER
At the outset, APPA and TAPS urge the Commission to convene a separate technical
conference on the issue of remedies. Such a conference should explore how remedies can be tied
to the specific market power concerns associated with a particular MBR applicant. The need to
carefully craft the remedy to the facts presented is the flip-side of the Commission’
s obligations
24
Consideration could be given to adjusting firm ATC figures where it can be shown that a reserved path represents
a genuine source of competing supply into the relevant geographic market. However, if the path is committed to a
long-term power sale, an adjustment would be inappropriate.
- 27 to make factual finding that an MBR applicant does not possess or has adequately mitigated its
market power. The factual record regarding a seller’
s market power should give rise to
mitigation that is effective to address that market power.
In addition to being targeted, remedies need to be effective. Thus, the Commission
should develop a compliance process to ensure that remedies are actually implemented as
intended. Remedies should also be monitored to ensure that they achieve the desired ends.
The Commission clearly has the authority to condition the grant of market-based rates on
the adoption of appropriate mitigation, including the structural remedies described below. “
The
authorization to sell power at market-based rates . . . –as opposed to traditional, cost-based rates
–is a privilege, and granted if, and only if, the Commission determines that an applicant’
s use of
such rates will be just and reasonable.”Enron Power Mktg., Inc., 106 F.E.R.C. ¶ 61,024, P 13
(2004).25 Where a seller seeks the privilege to sell at market-based rates and where the
Commission is pursuing its goal of regulation through reliance on competitive forces, the
26
Commission’
s conditioning authority is at “
zenith.”
Particularly in the context of market-based
rates, the Commission must include conditions that ensure that underlying competitive
circumstances support reliance upon market forces to adequately discipline rates. If those
conditions do not obtain, it cannot approve the rate.27
25
See generally, Pennsylvania Water & Power Co. v. FPC, 343 U.S. 414, 418 (1952) (“
A major purpose of the
whole Act is to protect power consumers against excessive prices.”
).
26
Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153, 159 (D.C. Cir. 1967). See also Northern Natural Gas Co.
v. FERC, 785 F.2d 338, 341 (D.C. Cir. 1986).
27
Farmers Union, 734 F.2d at 1509; Interstate Natural Gas Ass’
n v. FERC, 285 F.3d 18, 34 (D.C. Cir. 2002)
(relying upon Commission “
monitoring and assurance of remedies in the event of insufficient competition, on which
Farmers Union set great store”
). See also Revised Pub. Util. Filing Requirements, III F.E.R.C. Stats. & Regs.,
¶ 31,127, at P 111 (2002), 67 Fed. Reg. 31,043, 31,054 (May 8, 2002) (“
[T]he Commission’
s market-based rate
findings do not absolve the Commission from its continuing responsibility to assure that rates are just and
reasonable.”
).
- 28 The D.C. Circuit’
s decision in California Indep. Sys. Operator Corp. v. FERC,
372 F.3d 395 (D.C. Cir. 2004) strongly supports the Commission’
s authority to establish
structural conditions that must be met prior to award of market-based rate authorization. The
court confirmed that if the California ISO did not meet FERC’
s conditions for qualification as an
ISO, FERC need not approve it as one.
If FERC concludes that CAISO lacks the independence or other
necessary attributes to constitute an ISO for purposes of Order No.
888, then it need not approve CAISO as an ISO. ISO membership
is not an end in itself; it is merely a method jurisdictional utilities
can use to comply with Order No. 888’
s mandate for those entities
to file nondiscriminatory open access tariffs.… The Commission,
in Order No. 888 and other rulings made pursuant thereto, has
defined ISOs according to the terms it wishes. FERC has the
authority not to accept something which it does not deem an ISO.
372 F.3d at 404. The court specifically recognized the Commission’
s power to condition
jurisdictional utility rate filings. Id. at 402 (citing Central Iowa Power Coop. v. FERC, 606 F.2d
1156 (D.C. Cir. 1979)).
The same analysis applies to the privilege of charging market-based rates. The
Commission has the authority to identify the conditions under which it will authorize marketbased rates, and it is up to the applicant to decide whether to accept them. If the competitive
conditions necessary to make market-based rates just and reasonable do not exist, and the
applicant refuses to accept ameliorative conditions, the Commission need not –indeed, cannot –
authorize them.
A.
Remedies Should Focus on Ensuring Structurally Competitive Markets
The Commission should give priority to remedies that promote structurally competitive
markets. APPA and TAPS members want to be able to choose a power supplier in a competitive
- 29 market, but need the protection of cost-based rates if that choice is illusory. Remedies focused
on fostering structurally competitive markets will help to ensure that the choice is real.
A hallmark of competitive markets is many buyers and many sellers. The Commission
can aid in increasing the number of sellers by encouraging diverse ownership and control of
generation. If the record indicates that the seller holds a dominant position in the market, the
Commission must condition the MBR authorization on the seller’
s taking steps to reduce its
dominant position. The MBR applicant can choose to accept the condition or not. The seller can
put control of capacity necessary address its dominance into the hands of competitors through
sales of capacity, whether by selling the capacity outright (i.e., divestiture) or turning control of
that capacity over to a third party (e.g., long-term contract with full-dispatch rights, auction of
capacity rights, tolling agreements). The Commission has required such remedies in the merger
context to address market power concerns. See American Elec. Power Co., Central and South
West Corp., 90 F.E.R.C. ¶ 61,242 (2000), order on reh’
g, 91 F.E.R.C. ¶ 61,129, at 61,489 (2000)
(capacity sale); Allegheny Energy, Inc., 84 F.E.R.C. ¶ 61,223 (1998) (divestiture). Similar
remedies could be made condition to MBR authorization. The seller can also invite market
participants, especially wholesale customers who may be captive to the seller’
s transmission
system, to participate in new generation projects.
In many cases, the position of a dominant MBR seller that also operates a transmission
system is attributable to the inadequacy of that transmission system, an inadequacy that the seller
itself may have contributed to by failing to adequately plan for the needs of network customers
and eschewing efforts to develop regional solutions to transmission problems. If the presence of
substantial and continuing transmission constraints in a dominant transmission provider’
s control
area allow it to charge supra-competitive “
market-based”rates for generation in its control area,
- 30 it is appropriate for the Commission to require these constraints to be addressed, if it is going to
allow that transmission provider to charge MBR. The appropriate structural remedy is
expanding transmission capacity, access and ownership to create a more robust grid that enables
buyers and sellers to reach one another. In such circumstances, the Commission should impose
mitigating conditions on MBR authority to increase access to existing facilities as well as
investments in new transmission.
For existing facilities, an MBR applicant that controls transmission should set aside
capacity for use by wholesale customers trapped in the applicant’
s control area by transmission
constraints, so that the customers can obtain access to alternative suppliers. Such capacity can
also be created through redispatch, at least as a temporary remedy until new transmission is
built.28 Other solutions involving existing grid capacity include clarifying and strengthening
network customer rollover rights under OATT § 2.2, so that those rights encompass reasonable
access to sources other than those from which the customer is currently served.29 Such rights
would reinforce an obligation to plan to enable more flexible usage of the system. They would
also be consistent with the assumption underlying the Commission’
s control area-based approach
to relevant markets—that transmission is readily available within the host control area if there is
access to the border. The Commission should also enforce the OATT’
s existing requirement
(§ 28.2 and Preamble to Part III) that the transmission owner plan and construct the system to
accommodate a network customer’
s existing and planned designated network resources. A
vertically-integrated transmission owner that fails to do so should be held accountable, e.g., by
conditioning MBR authority on the transmission owner’
s willingness to accommodate the
28
See Oklahoma Gas & Electric Company, et al., 108 F.E.R.C. ¶ 61,004 (2004) (requiring redispatch under 600
MW transmission “
bridge”was in place).
- 31 network customer’
s timely designation of a new network resource even where such
accommodation would, pending construction of the needed transmission upgrades, require
redispatching of the TO’
s own resources. The associated redispatch costs could be shared on a
load ratio basis similar to OATT § 34.1).
Longer term solutions require transmission expansion so that the transmission grid
enables willing buyers and sellers to make deals. The Commission can tie the grant of MBR
authority to vertically-integrated transmission owners seeking MBR rates to their demonstrated
commitment to make upgrades that allow their wholesale customers cost-effective access to
competitive alternatives. Cf. Oklahoma Gas & Electric Company, et al., 108 F.E.R.C. ¶ 61,004
(2004) (construction of transmission “
bridge”as remedy to market power concerns). It can also
tie the grant of MBR authority to the demonstrated willingness of such vertically-integrated
transmission owners to jointly plan transmission with their network customers, to participate in
collaborative and inclusive regional transmission planning processes,30 and to permit such
customers to invest in the transmission system on a comparable basis. Customer investments
must be treated comparably to the transmission provider’
s own through credits and recovery of
costs through the transmission owner’
s revenue requirement.
B.
The Commission Correctly Requires Cost-Based Sales Until a Seller
Mitigates its Market Power
In the MBR Orders, the Commission correctly adopted revocation or denial of marketbased rates and default cost-based mitigation for those sellers that do not show they lack or have
adequately mitigated market power. Cost-based rates may be necessary during the period that an
29
30
See also Kimber Affidavit.
At minimum, the Commission should reduce the current incentive for TOs to avoid joint planning, by modifying
OATT § 30.9 so that where the transmission owner declines to engage in joint planning needed to serve the
customer, credits will be deemed appropriate if the facilities are constructed by the network customer.
- 32 MBR applicant is undertaking transmission upgrades that will give wholesale customers trapped
by transmission constraints within its control area access to the larger market. The
Commission’
s default mitigation for short-term transactions (caps reflecting marginal costs plus
10% for sales of less than a week) also works in RTO-administered spot markets, because offers
in competitive spot markets should reflect marginal costs.31 The Commission should not be
swayed by inevitable claims from generators that the default mitigation somehow undermines its
efforts to foster competitive markets in regions with ISOs and RTOs.
While cost-based rates address the problem of the exercise of market power through
economic withholding, there remains the problem of physical withholding. An MBR applicant,
particularly one that is also a transmission provider and thus controls transmission access in its
control area, may respond to a cost-based rate requirement for sales in that control area by
simply refusing to sell to customers located in its control area. If that were to occur, and
wholesale customers in the control area therefore lacked sufficient supply alternatives due to the
withdrawal from the market of a dominant supplier (if, for example, they were located in a
transmission-constrained load pocket), the predicate underlying Order No. 888’
s elimination of a
wholesale obligation to serve –that captive transmission customers have a choice of suppliers –
would no longer exist.32 Under those circumstances, the Commission would be justified in
31
Bids reflecting marginal costs are consistent with the theory underlying RTO spot markets. In a competitive
market, the incentive should be for the seller to bid its marginal cost, because failure to do so could cause the seller
to price itself out of the market when it otherwise would have been profitable to make a sale. Further, bids that do
not reflect marginal cost can distort economic dispatch, and thus raise consumer costs, by causing inefficient units to
be called before more efficient ones.
32
Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public
Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Stats. & Regs., Proposed
- 33 requiring the dominant supplier to offer cost-based sales to captive customers located in its
control area.
However, such an obligation to sell should not be a permanent solution. APPA and
TAPS would much prefer to see the structural changes necessary to support competitive
wholesale markets implemented, rather than to return to a cost-based wholesale rate regime.33
Customers and markets will be better off if the Commission enforces the obligation under Order
No. 888 on transmission providers to plan and build sufficient transmission facilities so that
captive customers can access the broader wholesale market beyond such an MBR applicant’
s
control area.
C.
In Appropriate Cases, the Applicant Should Be Denied MBR Authority
Outside Its Control Area Unless It Provides Wholesale Customers
Embedded in Its Own Control Area Adequate Access to the Broader
Regional Market
There may be cases where denying MBR authority within an applicant’
s control area will
still not remedy the market power problem. By choosing to maintain a constrained transmission
system and refusing to sell power to wholesale customers embedded in that system, such a
transmission provider denies these wholesale customers access to regional power markets and
prevents otherwise willing buyers and sellers from transacting business. Such acts also weaken
the regional power markets that the Commission must rely on to keep market-based rates just
and reasonable, by reducing the number of active buyers and sellers. If the transmission provider
also competes with the embedded wholesale customers on its system for end use loads (as is the
Regs., ¶ 32,514, at 33,110 (1995).
33
Nor do APPA and TAPS want to see a new wave of unjustified stranded cost claims based upon public utilities
having to undertake generation construction for trapped wholesale customers.
- 34 case in many instances), anticompetitive concerns, including price/supply squeeze issues, are
also raised.
To remedy the market power problem in these instances, the Commission should deny
MBR authorization even outside such a dominant vertically-integrated utility’
s own control area,
until such an applicant provides customers that must use its transmission system cost-effective
access to competitive alternatives.34 Where transmission customers are foreclosed access to the
broader market, the resulting wholesale rate the transmission provider charges outside its control
area cannot be deemed lawful.35 That wholesale rate is unduly discriminatory and preferential,
because it is available only to purchasers who do not depend upon the transmission provider’
s
system and unavailable to those on-system customers that have been foreclosed by the
transmission provider’
s failure to maintain a sufficient transmission system.36
IV.
THE COMMISSION MUST AVOID HARMFUL ANALYTICAL SHORTCUTS
A.
The Commission Should Eliminate the Automatic Exemption for Post1996 Generation Units
In its recent final rule, Reporting Requirement for Changes in Status for Public Utilities
with Market-Based Rate Authority, 110 F.E.R.C. ¶ 61,097, P 38 (2005), the Commission said it
would address in this proceeding “
whether the Commission should retain the exemption for post-
34
Self-build is not necessarily an alternative, as the Commission found in the MBR Order (P 155 and n.151).
35
See also Testimony of Steve Schleimer for Calpine Corporation, December 7, 2004 Technical Conference, Tr. at
207: “
But I also think that, you know, there is potential FERC angle, and that is to the extent that the utility wants to
have market-based rates and participate in the wholesale competitive markets outside of its service territory, it has to
have a wholesale competitive market inside its service territory.”
36
Cutting off the embedded customer from the broader market can also distort that market by artificially reducing its
size and scope, including through blocking competitive merchant generators’access to potential wholesale
customers, which produces unjust and unreasonable rates.
- 35 1996 generation in section 35.27 of the Commission’
s regulations.”The Commission should
eliminate the exemption, because there is no principled basis for maintaining it.
At first blush, one would not expect an applicant entering a market for the first time to
raise competitive concerns. After all, new entry and increasing output in a market is generally
pro-competitive. However, simply because the generator’
s action de-concentrates ownership in
the market does not mean there is no risk of market power exercise. The new facility could be
going into a market where there are too few competitors. The addition of a new competitor,
while helpful, may not be sufficient to eliminate the market power risk such that the FPA’
s
standards for market-based rates are satisfied.37
The issue is more clear-cut where the applicant is adding generation to a market where it
already owns or controls other facilities. In the MBR Order (at P 38) the Commission stated that
“
if an applicant sites generation in an area where it or its affiliates own or control other
generation assets, the applicant must address whether its new capacity, when added to existing
capacity, raises generation market power concerns.”In the MBR Reh’
g Order (P 110), the
Commission clarified that “
in circumstances where construction on all of an applicant’
s
generation commenced after July 9, 1996, no interim generation market power analysis need be
performed.”There should be no blanket exemption for facilities built after 1996.38 That the
37
The Commission should not import merger principles into the analysis here. The typical issue in a merger case is
whether a transaction will lessen competition. New entry into a market increases competition, and merger law
would not condemn it. However, under Section 205 of the FPA, the question is not whether the transaction lessens
competition. It is whether the applicant has no market power, or has adequately mitigated it. A new entrant could
possess such market power, even if its entry does incrementally improve conditions in a market.
38
See PJM Interconnection, LLC, 110 F.E.R.C. ¶ 61,053, P 53 (2005).
- 36 facilities were built before or after 1996 is immaterial to whether market power may be
exercised.39 The addition of a new plant increases a seller’
s market share in either case.
Instead of a blanket exemption, the applicant should be permitted to demonstrate that the
pro-competitive benefits of its adding generation to the market outweigh any risk of market
power exercise. Such a showing will depend upon the underlying competitive conditions. If
there is a risk of market power exercise, mitigation measures can be developed that are targeted
to the risk presented, taking into account the pro-competitive benefits of the new entry.
B.
The Commission Should Not Automatically Accept RTO Mitigation
Regimens as Adequate Mitigation of an Applicant’
s Market Power
In the MBR Orders and in recent cases, the Commission has expressed a willingness to
rely upon Commission-approved ISO/RTO market mitigation measures as sufficient to address
the market power harm posed by an MBR applicant. See MBR Order P 189; MBR Rehearing
Order P 174; AEP Power Marketing, Inc., 109 F.E.R.C. ¶ 61,276, P 21 (2004). The Commission
also said in the MBR Rehearing Order (P 174) that it “
must independently verify the
effectiveness of any alternative mitigation measures, including the ISO/RTO mitigation, which
would serve to replace the default mitigation adopted in the April 14 Order.”However, in
practice the Commission has not undertaken the promised independent verification. In Alliant
Energy Corporate Services, 109 F.E.R.C. ¶ 61,289, P 35, the Commission ruled, without any
particularized inquiry, that MISO’
s mitigation measures addressed intervenor concerns about the
applicant’
s market power in the load pocket. There was no record on whether and how the
MISO mitigation measures in fact addressed the applicant’
s market power. If the Commission is
39
See also Tr. at 39 (Goulet) (“
There’
s no reason to distinguish between an entity’
s ability to exert market power
based on unit age, a factor that really bears no nexus to the potential to exert market power”
).
- 37 going permit reliance on ISO/RTO mitigation, then it must be shown that the mitigation is
effective at addressing the particular MBR seller’
s market power.40
ISO/RTO mitigation regimes are typically designed to allow the exercise of some market
power with the expectation that competitive market response, rather than a mitigation measure,
will step in to make the market power exercise unprofitable. For example, in parts of MISO,
ISO-NE/and the NYISO, prices can rise by up to the lesser of $100 per MWh or 200 percent
before market mitigation measures apply. In some parts of these ISO/RTO markets, the
tolerance is smaller but still substantial. However, much smaller increases in price, if sustained,
as well as short-lived but large increases, can cause considerable consumer harm. The Merger
Guidelines use a 5% non-transitory price increase as an indicator of market power exercise when
defining markets. Merger Guidelines, § 1.11.41 If a five percent increase in price can represent
an anticompetitive price increase, a threshold that tolerates a price increase of more than 200
percent clearly leaves room for consumer harm. Where a market is not competitive, the market
response will not occur or will be too weak to remedy the seller’
s market power. Under those
circumstances, the Commission cannot rely upon the mitigation regime.
The foregoing concerns are confirmed in the February 4, 2004 affidavit of Dr. Laurence
Kirsch,42 which explained that the failure of ISO/RTO mitigation to look at bilateral markets or
for collusion, combined with the generous conduct and market impact thresholds applied under
40
Reliance on market-based pricing requires empirical proof that market power is absent or is mitigated. See Part
I.A. above. The Commission is also expected to make specific inquiry into the market power risks posed by an
applicant. See Cal. ex rel. Lockyer v. FERC, 383 F.3d at 1013. Unless the Commission makes factual findings
regarding the market power risk posed by an applicant and the mitigation necessary to address those risks, the
Commission cannot approve market-based rates. Generic reliance upon ISO/RTO mitigation does not satisfy the
Commission’
s legal obligations.
41
Note that 5% is not a tolerance level for permissible competitive harm. Merger Guidelines, § 1.0. Consumers can
suffer competitive harm when prices increase by less than 5%, if such price increases are sustained.
42
See Kirsch SMA Affidavit at 7.
- 38 ISO/RTO mitigation regimes, “
means that concentrated generation ownership will allow
generation firms to raise prices in spot markets above competitive levels without triggering
mitigation, and will allow such firms to raise prices in forward markets to whatever abovecompetitive level that the market will bear.”He further concluded (at 7) that failure of these
regimes to mitigate market power could cost consumers millions of dollars in excessive prices
and that current market monitoring regimes are poorly equipped to provide the consumer
protection the FPA demands:
[I]t is difficult for market monitors to identify misbehavior by
market participants and costly for market monitors to force
participants to change their behavior. While the infrequency of
market monitors’disciplinary actions has been touted by some as
an indication of the success of the market monitoring in RTO and
ISO markets, the truth may be that this infrequency arises also (or
instead) from the difficulties and costs of identifying and
mitigating the exercise of market power.
Another risk of relying on ISO/RTO mitigation measures is that the measures approved
by the Commission apply only to short-term markets and do not address market power in longterm markets. The Commission correctly concluded in the MBR Order (P 155) that long-term
markets present distinct competitive concerns to which the FPA requires attention. An absence
of available long-term transmission service or existing congestion hedges, as well as generation
siting barriers, could render long-term market power concerns quite real.
Finally, ISO/RTO state of the market reports reveal that withholding behavior often goes
unchecked. The charts labeled Figures 18 and 19 (below) are taken from the 2003 State of the
Market Report, New York Electricity Markets, prepared by Potomac Economics, Ltd., the
NYISO independent market advisor.43 The figures show how an “
output gap”varies by load
43
Available at
http://www.nyiso.com/topics/articles/news_releases/2004/patton_report/2003_state_of_the_market_report_final_full
- 39 level, where “
The output gap is the quantity of generation capacity that is economic at the market
clearing price, but is not running due to the owner’
s offer price or is setting the LBMP with an
offer price substantially above competitive levels.”Id. at 27. In other words, the output gap is
the quantity of capacity that should be running (because it is in-merit) but is not running because
the supplier bid “
well above”(that is, at least $50/MWh or 100% above) the proxy for the
generator’
s marginal cost. Id. at 27-28. In plainer English, the “
output gap”is economic
withholding. Figure 19, presented first below, shows the hours where offers exceeded the actual
NYISO conduct threshold in East New York –the lesser of $100/MWh or 300 percent.44 (Each
dot is an hour.) Figure 18 (shown second), shows the number of hours offers would exceed a
lower threshold of the lesser of $50/MWh or 100 percent. Dr. Patton took comfort in the fact
that in both cases the output gap declined as load (and therefore prices) increased. However,
what provides Dr. Patton solace should deeply disturb the Commission. The chart shows the
consistent presence of numerous hours of economic withholding in East New York (just one part
of the state) in amounts ranging from a couple hundred megawatts to nearly 1500 MW. The
chart also shows that generous thresholds mask withholding. Such a mitigation regime plainly
does not suffice to remedy market power sufficient to support a lawful grant of MBR authority.
_text.pdf (last viewed March 11, 2005).
44
In parts of New York where this generous conduct threshold applies, generator bids are not mitigated unless they
increase prices by the lesser of $100 per MWh or 200 percent.
- 40 -
C.
The Commission Should Organize MBR Reviews on a Regional Basis,
But Should Not Rely Upon General Findings that a Region is
Competitive to Grant of Market-Based Rates to Specific Sellers
The Commission can better manage MBR reauthorizations,45 which will both streamline
the process and make needed data more readily available. One potentially valuable tool is to
45
Most public utilities currently have MBR authority, so the most pressing task facing the Commission is how to
- 41 synchronize consideration of renewals for a specified geographic region, such as a regional
reliability council (“
RRC”
). Among the greatest benefits of such coordination would be the
likely improved quality and availability of data. Regional proceedings provide a means to
require applicants to simultaneously produce data for the region, thus allowing such data to be
used to develop a more complete picture of the market in which the applicants compete.
Certain common issues in a region could also be consolidated for decision. For example,
differing regional practices (e.g., RRC rules on calculation of TTC) might affect how much
transmission capacity is practically available along an interface shared by multiple applicants,
and transmission data from several adjacent systems would facilitate resolution of any
transmission capacity discrepancies among operators of common transmission interfaces. By
contrast, other issues, especially ones involving seller-specific facts, may require separate
decision. For example, a seller’
s geographic market, market shares, or load obligations, and the
effect of retail rate regulation on the seller’
s incentive and ability to exercise market power,
would fall into this category. Similarly, the proper mitigation to apply where a market power
problem exists will depend on a specific analysis of that seller’
s market power.46
While MBR review can be coordinated on a regional basis, such an approach does not
translate to the conclusion the relevant geographic market is that specific region. Proper
competitive analysis requires that the Commission define the relevant geographic market based
upon factual evidence, such as transmission constraints, control area boundaries, and trading
address triennial updates.
46
Further streamlining could come from consolidation of reauthorizations of affiliated sellers. Instead of multiple,
repetitive applications, a company with affiliated sellers in a market or in several markets should be required to
consolidate applications for Commission consideration. This step would also address the problem of the
Commission’
s authorizing MBR applications for which market participants had inadequate notice of affiliate
relationships due, for example, to creative naming. Even if this consolidation is not required, at minimum an
applicant’
s draft notice of filing should identify all affiliated sellers with MBR authorization (or seeking it).
- 42 patterns.47 A regional approach does not relieve the Commission of its obligations to make a
fact-based inquiry regarding a specific seller’
s potential to exercise market power. The
requirement that a seller lack or have mitigated market power remains.
D.
The Commission Should Not Extend the Market Power Screens to
Ancillary Services Markets
The January 27, 2005 Technical Conference agenda also asked whether the Commission
should extend its generation market power screens “
to cover capacity and generation based
ancillary services, such as reserves and regulation.”Such extension is premature. While the
Commission has made substantial progress in developing workable screens in the context of
energy and capacity markets, extension of the screens to ancillary services markets presents
additional complexity. Where a MBR seller that also owns or operates a transmission system
seeks to sell ancillary services at MBRs in its home control area, the Commission should
undertake a full investigation and not rely upon the results of indicative screens.
The fundamental problem is that ancillary services markets remain very much dependent
upon control area operation and are closely connected to the operation of the transmission
system. This is reflected, inter alia, in the Commission’
s policy of authorizing MBR outside a
transmission provider’
s system. Avista Corp., 87 F.E.R.C. ¶ 61, 223, order on reh’
g,
89 F.E.R.C. ¶ 61,136 (1999). Capacity on automatic generation control (“
AGC”
) cannot easily
sell regulation service in its home market today and switch to sales in an adjoining market
tomorrow. With respect to reserves markets, the Commission has been pushing ISO/RTOs to
adopt locational reserve markets which, because of the effect of transmission constraints, can
47
Tr. at 124 (Wroblewski) (“
Using a regional approach makes sense if this means that FERC will examine all the
applicants for market-based rate authority in a particular region at the same time. Doing so will allow FERC to
properly delineate product and geographic markets within that particular region. If using a regional approach means
using one geographic region as the geographic market, then I’
d say this is no more accurate than using control areas
- 43 limit the ability of capacity to compete outside of its “
home”market. Thus, limitations of
transmission and technology counsel against adopting short-cuts for assessing the
appropriateness of market-based pricing of ancillary services.
While some ISOs/RTOs have moved to implement market-based pricing for some
ancillary services, concerns remain.48 For example, PJM recently sought and the Commission
allowed to take effect by operation of law market-based rates for regulation services in PJMWest and PJM-South,49 despite the fact that PJM’
s market monitor recommended against
adoption of market-based rates without further study given highly concentrated markets in these
regions.50 Even if the Commission finds that conditions exist to permit market-based pricing of
some ancillary services in ISO/RTO-administered markets, such pricing would not be
appropriate where vertically-integrated utilities with MBR authority are also control area
operators, because of the increased risk of competitive harm associated with such operation.
E.
Neither Market Participants nor the Commission Are Receiving Timely
and Sufficient Data to Perform Market Analyses
1.
Market Participants Continue to Face Great Difficulty in Obtaining
and Analyzing Data in a Timely Manner
APPA and TAPS member experiences with the Interim Screens so far have revealed
serious issues regarding the availability of data and the sufficiency of time to make productive
use of data. The Commission must address these problems if intervenors are going to
as the geographic market for assessing market power.”
). Accord Tr. at 133 (Solomon).
48
Tr. at 37 (Goulet).
49
See, generally, record in PJM Interconnection, LLC, Docket No. ER05-10-000. It is not clear that the
Commission has satisfied its obligations to undertake a fact-based inquiry into the permissibility of market-based
rates if such rates are allowed to go into effect by operation of law.
50
The Commission’
s handing of the filing can only be called Kafkaesque. After allowing the rate to go into effect
by operation of law, the Commission dismissed the rehearing petition of American Municipal Power-Ohio, Inc.,
stating “
the pleading does not lie because the Commission did not issue an order in the proceeding.”PJM
Interconnection, LLC, Docket No. ER05-10-001, “
Notice Dismissing Pleading,”(January 31, 2005).
- 44 meaningfully participate in MBR proceedings. At a minimum, the Commission needs to grant
intervenor requests for a longer response time, e.g., 60 days, for MBR authorization filings.51
One of the problems is the widespread designation of simultaneous import capability
studies as CEII. Our experience indicates that most such studies are labeled CEII, and
sometimes the CEII designation may bleed over to the entire MBR filing. It seems highly
unlikely that every element of the simultaneous import capability study is CEII. However, by so
designating their studies, applicants erect a significant road-block to the ability of intervenors to
review and respond to the filings. While we do not have specific evidence suggesting that
applicants are purposefully abusing CEII designations, the extent of such designations in the
context of time sensitive MBR filings should prompt the Commission to investigate the problem.
Commission procedures for the designation of CEII do not solve this problem. As APPA
and TAPS have explained previously,52 even if the timelines established by the CEII request
procedures work flawlessly, most of the standard 21 days permitted for responding to an MBR
filing would be consumed, leaving no time to use CEII data once obtained.53 However, it does
not appear that those procedures do in fact work flawlessly. Undersigned counsel’
s request for
CEII access in one case took nearly two months to process.54 Further, it does not appear that the
51
As noted above, most such filings are MBR updates for which a 60-day time limit on Commission action does not
apply.
52
See March 25, 2002 Comments of the American Public Power Association on the Commission’
s Notice of Inquiry
and Guidance for Filings in the Interim (Docket Nos. RM02-4-000 and PL02-1-000); November 14, 2002
Comments of the Transmission Access Policy Study Group (Docket Nos. RM02-4-000 and PL02-1-000); March 21,
2003 Petition for Rehearing of the Transmission Access Policy Study Group (Docket Nos. RM02-4-001 and PL021-000); May 16, 2003 Comments of the American Public Power Association and Transmission Access Policy Study
Group (Docket No. RM03-6-000); May 27, 2003 Motion of Transmission Access Policy Study Group to
Supplement and For Reconsideration (Docket Nos. RM02-4-001 and PL02-1-001).
53
Further, in many cases intervenors do not have the full 21 days. While the Commission starts the clock from the
time the filing is made, interested parties often do not receive notice of the filing until several days later.
54
See Docket No. CE05-69-000. Even allowing for the fact that the time period ran over the Christmas and New
Year holidays, the processing would have taken longer than the time contemplated by the CEII procedures.
- 45 Commission staff reviews CEII designations until a request for CEII access is submitted. Thus,
a Commission check on over-designation of CEII is not automatic.
The current 21-day response time is also not enough for intervenors to prepare a DPT to
rebut the results of the Interim Screens. In the MBR Rehearing Order (P 28), the Commission
correctly clarified that intervenors could submit a DPT to rebut an applicant’
s passage of the
Interim Screens. However, even assuming there are no problems obtaining and using the data
needed to perform a DPT –an assumption that likely never applies –more than three weeks is
required to prepare the DPT. Indeed, the Commission itself has given applicants for whom it has
ordered Section 206 investigations 60 days to submit a DPT. See, e.g., AEP Power Marketing,
Inc., 109 F.E.R.C. ¶ 61,276, Order Paragraph (E).
To give intervenors a fighting chance, the Commission should expand its “
standard”
notice period for MBR triennial updates or at least grant an extension of up to 60 days at the
request of intervenors seeking CEII or intending to perform a DPT.
2.
The Commission Must Require Regular Reporting of Needed
Information
The FPA’
s requirement that rates be just and reasonable demands that the Commission
and market participants have sufficient analytical and data resources to support the assessment of
market power. Simply performing a Google search will not yield data on peak loads,
transmission reliability margins, maintenance outages and the like required to perform Interim
Screens and the DPT. Rather, the Commission needs to update its information reporting
requirements so that they fully support the MBR program.
The Commission must require public utilities to submit the data necessary to permit
proper market analysis. The Commission’
s authority to impose information filing requirements
on utilities is more than adequate to obtain such data. 16 U.S.C. §§ 824l(b), 825 (2000). As a
- 46 condition attached to their MBR authorizations, sellers should regularly provide transaction data
necessary to perform the Screens and DPT.55 The quarterly transaction reports required under
Order No. 2001 are inadequate for the task, because the information is too aggregated.
Similarly, the Commission should impose a condition on transmission providers with MBR
authorization that requires production of transmission capacity and operation data sufficient to
assess transmission capacity and its availability.
V.
THE APPA/TAPS GENERATION MARKET POWER TEST IMPROVES
UPON THE INTERIM SCREENS
As noted at the outset, APPA and TAPS believe that the Interim Screens, in combination
with the rebuttable presumptions, the DPT, and the default mitigation, come closer to providing
the Commission with the kind of MBR test the FPA requires. Nonetheless, two important
shortcomings in the screens increase the risk of false negatives. One involves the absence of any
kind of analysis of supply or fuel curves to determine whether a generator owns or controls
capacity in a market that allows it to profitability raise prices, even where it is neither pivotal nor
dominant. Testimony at the January 27, 2005 Technical Conference confirmed that fuel cost
curves do matter. Tr. at 60-61 (Bushnell). The second involves how native load and long-term
contractual obligations affect a seller’
s ability and incentive to exercise market power. The
Technical Conference also showed that while these obligations are important, they impact
specific sellers differently. Tr. at 63-64 (Bushnell, Hegedus). However, the Commission’
s
current approach of deducting native load obligations from installed capacity to calculate
55
The Commission can use protective orders to address concerns about confidential information while making it
available to intervenors. However, it should not avoid collecting and sharing this information out of excessive
concern for confidentiality.
- 47 Uncommitted Capacity uses an axe to account for these obligations when only a carving knife is
necessary and appropriate.
The APPA/TAPS Generation Market Power Test addresses these shortcomings by
explicitly incorporating fuel or supply curves into the analysis and requiring the applicant to
explain with specificity how its retail native load and long-term contractual obligations affect its
incentives and ability to exercise market power. The APPA/TAPS Test retains (though in
slightly revised forms) the Interim Screens’use of pivotal supplier and market share metrics.
The APPA/TAPS test also calibrates filing requirements to the market power risk a particular
applicant poses, to ease burdens on both sellers and the Commission.
A.
The Commission Must Incorporate Supply Curve Analysis To Capture
the Dynamic Nature of Electricity Markets
An assessment of supply curves reveals incentives and abilities of a specific seller to
exercise market power by providing information about the shape and composition of the supply
curve and the seller’
s place on it. Neither pivotal supplier nor concentration/market share
metrics provide this important perspective. In its August 2002 Strawman on Market Metrics, the
FERC Staff explained the need for
some measure of structural incentives for withholding, where firms
with units near the market clearing price (typically peaking units)
hold large amounts of lower priced (typically baseload) capacity
that could profit from economic withholding of the marginal units,
or from physical withholding of small amounts of baseload
capacity that would force the peaking units to set the marginal
price.56
56
See “
Strawman”Staff Discussion Paper on Market Metrics SMD Staff Conference on Market Monitoring, Docket
No. RM01-12, Remedying Undue Discrimination Through Open-Access Transmission Service and Standard
Electricity Market Design, at 12, available at http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=9567029
(last viewed March 11, 2005).
- 48 In his article, Analyzing Gas and Electricity Convergence Mergers: A Supply Curve is Worth a
Thousand Words, FERC OMTR Staffer David Hunger explained that “
[e]stimating supply
curves for the downstream electricity market gives analysts an additional tool for predicting
57
future market outcomes.”
Professor Bush notes that “
[a] straight-up counting of capacity may
not detect market power arising from a fuel curve problem. Bush Aff. ¶ 22. Paul Joskow and
Edward Kahn, when examining withholding behavior in California markets, recognized the
importance of supply curves:58
whether withdrawing capacity is in the self-interest of a portfolio
generator will depend critically upon the slope of the supply curve.
It must be steep enough to result in MCPs sufficiently high so that
the increase in profit on generation still tendered to the market
more than offsets the profits lost on the capacity withdrawn.
Analysis of the supply curve involves its composition and shape, the elasticity of supply
along the curve, and the location of the seller’
s own units on the curve. Consider the example of
an applicant with a baseload unit and a peaker unit in a load pocket subject to LMP. The
applicant is not a pivotal supplier nor has a market share of greater than 20%. Its peaking unit,
an aero-derivative combustion turbine, is located on the rightward portion of the curve as it starts
to slope steeply upward. Other peaking units, such as frame units and diesel generators, are less
efficient and located further to the right on the curve. The marginal cost difference between the
applicant’
s peaking unit and the next one further up the curve is $15 per MWh. Because of the
relative efficiency of the applicant’
s peaking unit, it is in-merit, even at times other than the
57
David Hunger, Analyzing Gas and Electric Convergence Mergers: A Supply Curve is Worth a Thousand Words,
24:2 JOURNAL OF REGULATORY ECONOMICS 161 (2003).
58
Paul Joskow and Edward Kahn, A Quantitative Analysis of Pricing Behavior in California’
s Wholesale Electricty
Market During Summer 2000: The Final Word, at 20 (February 4, 2002), available at
http://www.ksg.harvard.edu/hepg/Papers/Joskow-Kahn%20Final%20Word%20Feb2002.pdf (last viewed March 10,
2005).
- 49 system peak, on days when the load pocket is cut off from the larger market. The $15 per MWh
difference between the applicant’
s unit and the next peaker on the curve provides the applicant
with the ability to raise price in the market by raising its offer by up to $14.99 per MWh without
worry about a competitive response.59 The applicant’
s inframarginal generation, which earns the
increased LMP due to the applicant’
s economic withholding, provides the applicant with an
incentive to withhold. Neither the Pivotal Supplier Screen nor the Market Share Screen would
capture this market power risk. However, examining the supply curve reveals that the applicant
has market power within a portion of the supply curve and has the incentive to exercise it.60
Data needed to construct supply curves should be readily available to most applicants.61
A key piece of information is heat rate data, because the efficiency of a unit gives a good
approximation of the likely order in which the units should be dispatched, if the units are bidding
based upon marginal costs. Sources of this data include the Environmental Protection Agency
(because heat rate data is also used to monitor air emissions) and commercial sources, such as
RDI and Platt’
s.
B.
The Commission Should Assess the Impact of Native Load on Market
Power Rather than Exclude It Entirely
The second major shortcoming in the Interim Screens is the use of an Uncommitted
Capacity measure derived by deducting from an applicant’
s installed (or total nameplate)
capacity the capacity used for operating reserves, native load commitments (including
59
Let us also assume that the peaking unit has a marginal cost of $60 per MWh such economic withholding would
be possible in a number of RTO markets, for example, in ISO-NE where the market’
s mitigation measures permit
offer increases of the lesser of $25 per MWH or 50 percent, or NYISO and MISO where offers exceeding reference
levels by the lesser of $100 per MWh or 300 percent are tolerated. In contrast, if the example market were in PJM,
the unit would presumably be subject to a marginal cost plus 10% bid cap when transmission constraints bind.
60
As described below in Part V.C., the supply curve analysis is incorporated into the Generation Market Power Test.
61
January 27, 2005 Tr. at 60 (Bushnell).
- 50 requirements sales). Any gain in administrative simplicity associated with using the Interim
Screens’“
standard deduction”causes too much harm to consumers. The Commission should
instead require applicants to take “
itemized deductions”for native load and long-term
commitments.
Capacity deducted because it is claimed to be dedicated to native load is clearly part of
the market. According to Dr. Rodney Frame, a chief proponent of the adjustment, if capacity
“
dedicated”to native load were not permitted to make sales into wholesale markets, prices in
those markets would go up, because there would be less supply competing for the market’
s
demand:
And if you draw your supply and demand curves, if you take some
supply out of the market, the prices are going to rise. And when
the prices rise, that's what I call anti-competitive. It's harmful to
customers.
January 13, 2004 PL02-8-000 Technical Conference, Tr. at 243-44. Dr. Frame’
s testimony
demonstrates that capacity “
dedicated”to native load competes in wholesale markets and should
not be excluded.
The wholesale deduction of capacity dedicated to native load is also suspect analytically.
In the context of antitrust analysis, the issue of how to treat a vertically integrated firm’
s internal
consumption is analogous, if not identical, to the native load capacity question. The Antitrust
Division’
s treatment of such capacity is instructive. In a case presenting industry characteristics
similar to the electric utility industry,62 the Antitrust Division counted capacity used for internal
production (downstream production of aluminum) in a vertically-integrated firm’
s share of
capacity for the production of alumina (the product of refining bauxite ore). United States v.
62
Report of the Antitrust Committee, 23 ENERGY L. J. 211, 245 (2002).
- 51 Alcoa, Inc., 152 F. Supp. 2d 37, 41-42 (D.D.C. 2001). The alumina market was characterized by
vertically integrated firms that used a significant portion of their capacity (about two-thirds) for
internal consumption as well as an active third-party spot and forward (long-term) market.63 In
addition, demand for alumina was highly inelastic, barriers to entry were high, and the industry
showed a susceptibility to collusion.64 In concluding that the alumina market was highly
concentrated, the Antitrust Division included both capacity used for internal consumption and
that used for third party sales in the relevant product market.65
The Alcoa decision is consistent with competition authorities’approaches to the
treatment of internal production capacity. According to the United Kingdom Office of Fair
Trading, the question is one of “
the ease with which production can or could be switched from
66
internal to external sales.”
The Horizontal Merger Guidelines (§ 1.4) state that the Agency will
not include such “
capacity to the extent that the firm’
s capacity is committed or so profitably
employed outside the relevant market that it would not be available to respond to an increase in
price in the market.”If capacity is sometimes available and sometimes not, the answer is not to
pretend that it is never available. Rather, a more refined approach, as described in the
Generation Market Power Test, is required. In this regard, the December 19, 2003 Staff Paper
correctly asked about “
the ability of the applicant and vertically integrated utilities to segregate
63
United States v. Alcoa, Inc., et al., Civil No. 00-CV-954 (RMU), Complaint of the United States, ¶ 11 (available at
http://www.usdoj.gov/atr/cases/f4600/4663.pdf) (last viewed March 13, 2005).
64
Id. at ¶¶ 18-21.
65
Id. at ¶¶ 11, 16-17.
66
Assessment of Market Power, Office of Fair Trading, Publication OFT 415, ¶ 4.6 (September 1999) (available at
http://www.rail-reg.gov.uk/upload/pdf/oft415.pdf) (last viewed March 14, 2005).
- 52 wholesale opportunity sales from retail sales and the reasonableness of seeking to isolate
67
wholesale and retail supplies.”
The Interim Screens blunt deduction of these commitments does not work. Professor
Bushnell stated at the January 27, 2005 Technical Conference (Tr. at 13):
Concentration measures and even pivotal supply measures just
don't accommodate consideration of net position [effect of native
load obligations] very well. You can't just plug net position into a
formula. That really makes sense if you try to develop a modified
concentration measure that utilizes net position in a way that is
consistent with underlying economic power the way the original
concentration methods are consistent with an underlying model.
In contrast, the APPA/TAPS Generation Market Power Test adopts a Native Load
Obligation Factor.68 This Factor considers how a seller’
s obligations to native load and other
long-term customers affects its incentives and ability to raise prices. For example, the ability of
a seller to use the capacity to cause competitive injury in the wholesale market will depend on
facts such as the extent to which price increases in the wholesale market caused by the seller’
s
anticompetitive activity must be borne by the seller or may be passed along to the seller’
s native
load customers, such as through a fuel and purchased power adjustment clause. Similarly, the
retail ratemaking regime may permit the seller to pass along to shareholders increased profits
from sales at supra-competitive prices in wholesale markets.69
67
Conference on Supply Margin Assessment, Notice of Technical Conference, Staff Paper at 9 (December 19,
2003) available at http://www.ferc.gov/EventCalendar/Files/20040112104841-PL02-8-000-notice.pdf (last viewed
March 11, 2005).
68
See Part V.C. below.
69
Professor Bushnell described variables associated with these factors. Tr. at 63.
- 53 C.
The Commission Should Adopt the APPA/TAPS Generation Market
Power Test
The APPA/TAPS Generation Market Power Test is predictable and practical, includes
filing requirements calibrated for the market power potential of the applicants, and yields
relevant, probative and substantial evidence for assessing market power, while minimizing the
potential for false negatives and false positives that can leave consumers and market participants
exposed to harm.70 The Horizontal Market Power Screen prescribes examination of three
indicative, complementary metrics –market share and concentration, pivotal supplier and supply
curves –to reveal the underlying market structure and a seller’
s place in it. Where looking at
structure alone may not reveal a clear or complete picture, evidence on Effects Factors (load and
sales obligations, entry conditions, transmission control, demand elasticity and other regional or
local factors) are examined. The resulting market-specific evidence generated by the Screen and
the Effects Factors will permit the Commission to exercise its best judgment to decide whether a
seller’
s market-based rates would be just and reasonable.
The proposed framework permits streamlined applications and, in appropriate case,
expedited consideration of a seller’
s request. Pure power marketers and generators who have
sold the entirety of their capacity and all rights to dispatch it qualify for a Safe Harbor involving
minimal filing requirements. Sellers that have generation dispatch rights but that are not likely to
hold dominant or pivotal positions in a market, such as a load pocket, may file using an
Abbreviated Application that requires only a Horizontal Market Power Screen conducted using
simplifying, conservative assumptions designed to ease filing burdens while avoiding false
70
The framework is not, however, intended to be a regulatory smorgasbord. For example, that the Safe Harbor
discussed below may reasonably apply to some power marketers does not mean it should be available to dominant
vertically integrated sellers.
- 54 negatives. Sellers filing these applications will be presumed to pass the Generation Market
Power Test if the Horizontal Market Power Screen indicates that they are neither dominant nor
pivotal and there is no substantial evidence to the contrary. Where the risk of market power
exercise is higher, e.g., applications by dominant, vertically integrated public utilities or
merchant generators with a fleet of plants in the same market, the framework prescribes a more
probing inquiry, the Standard Application, requiring submission of the Horizontal Market Power
Screen as well as evidence on Effects Factors. The calibrated filing requirements envisioned by
this framework are entirely appropriate to the stakes: application costs will pale compared to the
billions of dollars of MBR sales authorized by the Commission as well as the hundreds of
millions, if not billions, of dollars of higher rates paid by consumers if firms with market power
sell without FPA-required mitigation.71
Below we summarize the key elements of the Generation Market Power Test. In the
Appendix attached hereto, we provide greater detail and justification for each element.
APPA/TAPS Generation Market Power Test

Filing requirements based upon market power risk posed by the applicant.
o Safe Harbor Application:

Qualifications: Seller that does not operate or control transmission facilities and
that is:

A power marketer that does not own generation, that has no capacity with
dispatch rights and that has no tolling agreements; or

A generator that has sold the entirety of its capacity and all rights to
dispatch it.

71
Filing Requirements: Certification of facts qualifying seller for Safe Harbor.
Meaningful review upfront helps to nip potential market power problems in the bud, making it less likely that the
Commission and market participants will have to endure the pain and suffering of after-the-fact refund proceedings.
- 55 o Abbreviated Application:

Qualifications: Seller that does not operate or control transmission facilities, that
has not otherwise sold the entirety of its capacity and all rights to dispatch it and
that in each properly defined geographic market is:

A seller that owns or controls either a single plant or total capacity of less
than 100 MW; or

A seller into an ISO/RTO market that does not own or control generation
located in a load pocket or having a significant effect on whether a
transmission constraint is binding.

Filing Requirements: Horizontal Market Power Screen conducted using
conservative, simplifying assumptions.
o Standard Application:

Qualifications: Seller that does not qualify for Safe Harbor or Abbreviated
Application or seller that filed Abbreviated Application but failed the Screen.

Filing Requirements: Horizontal Market Power Screen and Effects Factors.

Expedited consideration of MBR applications:
o Applications that do not present disputed or missing facts and that involve straight
forward questions of interpreting proffered evidence (e.g., absence of disputes over
geographic market definition or passage of Screen) will be decided “
on the pleadings.”
Generally, Safe Harbor and Abbreviated Applications should be decided on the
pleadings. Depending upon the record and issues presented, Standard Applications may
also qualify.
o Applications with disputed or missing facts or with complex questions of evidentiary
interpretation should be set for Section 206 investigation with opportunities for
discovery. Where possible, hearings should be expedited.

Meaningful Generation Market Power Test:
o A Horizontal Market Power Screen and Effects Factors provide the Commission the
relevant, probative and substantial evidence it must have to make a reasoned decision
about seller market power. Based upon the evidentiary record, the Commission will
exercise its judgment regarding the just and reasonableness of the seller’
s proposed
market-based rates and the need for mitigation.
o Geographic Market Analysis (required for Abbreviated and Standard applications):

Applicant will file the Screen using its home control or transmission area as the
geographic market and will address whether the control area or transmission area,
- 56 or a smaller or larger area, is the correct geographic market. The analysis will
focus particularly on the role of transmission constraints in defining geographic
markets.

Transmission capacity should be calculated based upon Simultaneous Available
Transmission Capacity (“
ATC”
). Applicants operating transmission must also
submit data on Total Transmission Capacity (“
TTC”
), Transmission Reliability
Margin (“
TRM”
), Capacity Benefit Margin (“
CBM”
), the incidence and extent of
Transmission Loading Relief (“
TLR”
) and other transmission curtailments, and
their own transmission reservations.
o Horizontal Market Power Screen Conducted for the Geographic Market(s) (required for
Abbreviated and Standard Applications):

Screen uses three indicative, complementary metrics to provide a more accurate
picture of market structure and seller’
s place in it.

Abbreviated Application Provisions:

Sellers filing an Abbreviated Application may run the Horizontal Market
Power Screen assuming no import capability for competing supply.

Absent contrary evidence, sellers filing Abbreviated Applications will be
presumed to pass the Generation Market Power Test if the Horizontal
Market Power Screen demonstrates (a) the Applicant has less than 20% of
the capacity in the total market as well as in any portion of the supply
curve,72 (b) the market is not concentrated, and (c) the Applicant is not a
pivotal supplier, either singly or jointly, in any month.

Market Share and Concentration Metric:

A metric such as HHI is needed to assess overall market structure and
risks of collusion. Based on the horizontal merger Appendix A analysis,
the framework requires calculation of market shares and concentration for
a properly defined geographic market for Economic Capacity and
Available Economic Capacity in off-peak, shoulder and peak periods.

The data burdens of the Appendix A analysis are reduced significantly
through use of a no-competing–imports-assumption (in the case of
Abbreviated Applications), and use of appropriately defined geographic
markets rather than Destination Markets.
72
For example, a seller may have a concentration of units within, straddling or throughout baseload, intermediate or
peak portions of the supply curve.
- 57 
Pivotal Supplier Metric: In recognition of the heightened market power concerns
during peak periods, applicant will submit a pivotal supplier metric, the “
pivotal
supplier HHI,”that assesses whether it is pivotal singly as well as jointly with
other sellers to gauge potential for coordinated exercises of market power. The
pivotal supplier metric should be run for the peak hour of each month to provide
evidence of seasonal variations of supply and demand.

Supply Curve Metric: The shape and composition of the supply curve allows the
Commission to assess whether an applicant’
s generation fleet provides it with an
incentive and ability to exercise market power. The same data sources that
support the HHI metric will allow construction of the supply curve.
o Effects Factors Analysis to permit interpretation of Horizontal Market Power Screen
(required for Standard Applications only).

Sales and Transaction Factor: The factor examines actual activity in the relevant
market as a real-world test of the Horizontal Market Power Screen results. It
allows the applicant and intervenors to show whether the sales and transaction
experience in the market is consistent with what the structural metrics show. One
kind of evidence that could be examined is RFP results, particularly to gauge how
many sellers responded to an RFP and difficulties the respondents might have
encountered, such as difficulties of securing transmission paths. The Factor also
allows an examination of the applicant’
s level of sales activity to understand
better whether an applicant is active in making third party sales, to whom, at what
prices and, where the seller is not active, why not.

Load Obligation Factor: Applicant will describe its native load and long-term
sales obligations, the rate-setting mechanism for its obligations, including
distribution of profits from opportunity sales and the ability of the seller to pass
through wholesale purchased power costs to customers. This factor allows the
applicant to explain, and the Commission to analyze, any differences between the
Economic Capacity and Available Economic Capacity results of the Appendix A
analysis to determine their affect on the ability and incentive to exercise market
power. With this specific information, the Commission can determine the
appropriate treatment of the Native Load Obligation.

Entry Conditions Factor: Entry that is timely, likely and sufficient can lessen or
defeat a seller’
s market power. An applicant will submit evidence on entry
conditions, such as planned entry (projects under construction), past entry, site
availability and control, siting authority and procedures, transportation
infrastructure (electricity transmission and natural gas transportation) and the
applicant’
s control over fuel inputs (e.g., natural gas pipelines). Applicants
should address both short-term and long-term markets.

Transmission Factor: An applicant will address whether transmission operations
have been turned over to an independent entity. Where they have not, the
applicant should address the prospect for and barriers to independent operation.
- 58 The applicant will describe expected changes in transmission capacity, either due
to future reservations from the applicant itself (or others, if known) or the
construction of new transmission facilities.

Demand Elasticity Factor: Generally, the Commission should assume that
demand elasticity is very low, unless evidence suggests otherwise. An applicant
in a market where demand response programs exist will address the extent to
which buyers can reduce usage or shift to other sellers or products in response to a
price increase.

Optional Regional and Local Factors: The applicant may introduce other relevant
and probative evidence that affects a seller’
s ability to exercise market power or
the interpretation of the Horizontal Market Power Screen results. For example, an
applicant in a market where hydropower is prevalent would want to address the
effect of high- and low-water years. Other relevant evidence includes the
applicant’
s prior anticompetitive activity in the market.
With the evidentiary record produced by the Generation Market Power Test, the
Commission can exercise its judgment about whether the applicant has market power. If the
Commission concludes that the seller has market power, the record provides a basis to consider
mitigation measures specifically targeted to the market power concerns revealed through the
analysis. Possible mitigation measures are described above in Part IV above.
CONCLUSION
APPA and TAPS believe that their Generation Market Power Test improves upon the
Commission’
s current generation market power test for MBR authorizations in ways that will
ensure that the Commission’
s decisions about market-based rates are supported by empirical
proof that a seller does not possess market power or has adequately mitigated it. At a minimum,
the Commission should refine the existing Interim Screens and application of the DPT, as
described above. The Commission must also genuinely consider the role that transmission
constraints play in defining geographic markets and determining who may compete within a
market. Finally, the Commission should focus on structural remedies so that wholesale
APPENDIX TO COMMENTS OF AMERICAN PUBLIC POWER ASSOCIATION
AND THE TRANSMISSION ACCESS POLICY STUDY GROUP IN MARKET-BASED
RATES FOR PUBLIC UTILITIES, DOCKET NO. RM04-7-000
MARCH 14, 2005
The APPA/TAPS Generation Market Power Test
The APPA/TAPS Generation Market Power Test is designed to be a workable test
with filing requirements calibrated for the market power potential of the applicants. It
should yield relevant, probative and substantial evidence for assessing market power,
while minimizing the potential for false negatives and false positives that can leave
consumers and market participants exposed to harm.1 The Test utilizes a Horizontal
Market Power Screen and Effects Factors framework. The Horizontal Market Power
Screen prescribes examination of three indicative, complementary metrics –market share
and concentration, pivotal supplier and supply curves –to reveal the underlying market
structure and a seller’
s place in it. Where looking at structure alone may not reveal a
clear or complete picture, evidence on Effects Factors (sales and transactions, native load
obligations, entry conditions, transmission control, demand elasticity and other regional
or local factors) are examined. The resulting market-specific evidence generated by the
Screen and the Effects Factors will permit the Commission to exercise its judgment to
decide whether a seller’
s market-based rates would be just and reasonable.
1
The framework is not intended to be a regulatory smorgasbord. For example, that the Safe Harbor
discussed below may reasonably apply to some power marketers does not mean it should be available to
vertically integrated sellers seeking MBR authorization.
- ii Where appropriate, the proposed framework permits streamlined applications and
expedited consideration of a seller’
s request. Pure power marketers and generators who
have sold the entirety of their capacity and all rights to dispatch it qualify for a Safe
Harbor involving minimal filing requirements. Sellers that have generation dispatch
rights but that are not likely to hold dominant or pivotal positions in a market, such as a
load pocket, may file using an Abbreviated Application that requires only a Horizontal
Market Power Screen conducted using simplifying, conservative assumptions designed to
ease filing burdens while avoiding false negatives. Sellers filing these applications will
be presumed to pass the Generation Market Power Test if the Horizontal Market Power
Screen indicates that they are neither dominant nor pivotal and there is no substantial
evidence to the contrary. Where the risk of market power exercise is higher, e.g.,
applications by dominant, vertically integrated utilities or merchant generators with a
fleet of plants in a market, the framework prescribes a more probing inquiry, the Standard
Application, requiring submission of the Horizontal Market Power Screen as well as
evidence on Effects Factors. The calibrated filing requirements envisioned by this
framework are entirely appropriate to the stakes: application costs will pale compared to
the billions of dollars of MBR sales authorized by the Commission as well as the
hundreds of millions, if not billions, of dollars of higher rates paid by consumers if firms
with market power sell without FPA-required mitigation.2
2
Meaningful review upfront helps to nip potential market power problems in the bud, making it less likely
that the Commission and market participants will have to endure the pain and suffering of after-the-fact
refund proceedings.
- iii I.
THE GENERATION MARKET POWER TEST IS WORKABLE
A.
The Test Defines Filing Requirements Based Upon the Risk of
Market Power Exercise
The Commission faces the challenge of ensuring that its test for generation market
power is effective in determining whether it may, consistent with the FPA’
s just and
reasonable rate mandate, authorize a public utility to sell at market-based rates, while at
the same time not overwhelming its administrative resources and over-taxing the
financial resources of market participants. The Commission should calibrate applicants’
filing requirements based upon the risk they pose for the exercise of market power. The
Generation Market Power Test features the following calibration of application
requirements:
o Safe Harbor Application:

Qualifications: Seller that does not operate or control transmission
facilities and that is:

A power marketer that does not own generation, that has no
capacity with dispatch rights and that has no tolling agreements; or

A generator that has sold the entirety of its capacity and all rights
to dispatch it.

Filing Requirements: Certification of facts qualifying seller for Safe
Harbor.
o Abbreviated Application:

Qualifications: Seller that does not operate or control transmission
facilities, that has not otherwise sold the entirety of its capacity and all
rights to dispatch it and that in each properly defined geographic market
is:

A seller that owns or controls a single plant or total capacity of less
than 100 MW; or

A seller into an ISO/RTO market that does not own or control
generation located in a load pocket or have a significant effect on
whether a transmission constraint is binding.
- iv 
Filing Requirements: Horizontal Market Power Screen conducted using
conservative, simplifying assumptions; demonstration of facts to qualify
seller for Abbreviated Application.
o Standard Application:

Qualifications: Seller that does not qualify for Safe Harbor or
Abbreviated Application or seller that filed Abbreviated Application but
failed the Screen.

Filing Requirements: Horizontal Market Power Screen and Effects
Factors.
The Safe Harbor category recognizes that certain applicants pose so little risk of
market power exercise that requiring them to make more than the most basic filing would
waste both their and the Commission’
s resources. Sellers eligible for the Safe Harbor
must not have control over transmission facilities. Such sellers must not possess rights to
control dispatch of generation, so that they cannot withhold supply, either physically or
economically, from the market. Power marketers that have no generation, have no
capacity with dispatch rights or have no tolling agreements, as well as generators that
have sold their capacity and all rights to dispatch it, are the mostly likely sellers eligible
for the Safe Harbor.
An Abbreviated Application would be available to sellers with small amounts of
generation relative to the size of the geographic market, because of the reduced risk of
market power harm they are likely to pose. If such sellers own transmission assets, they
must have turned control of them over to an independent entity (e.g., an ISO/RTO) to
ensure that transmission cannot be used to favor their own generation. In any properly
defined geographic market, eligible sellers could own or control only one facility or less
than 100 MW of generation in order to minimize the risk of withholding some or all of
the output of a plant so as to raise price and earn additional profit on other sales in the
-vsame market. Where a seller owns or controls generation in multiple geographic markets,
it must qualify for the Abbreviated Application in each market. Eligible sellers would
also include firms selling into ISO/RTO markets with no generation located in load
pockets or no generation that has a significant effect on whether a transmission constraint
is binding.
To examine the potential market power risks they pose, sellers eligible for the
Abbreviated Application would prepare the Horizontal Market Power Screen, described
below, for the relevant geographic market and could do so using a conservative,
simplifying assumption that no competing generation could be imported into the
market.3 A seller filing an Abbreviated Application would be presumed to pass the
Generation Market Power Test if the results of the Screen showed that the seller has less
than 20% market share in an unconcentrated market, both in the total market as well as
along any portion of the supply curve,4 and that it is not a pivotal supplier, either singly
or jointly with other sellers. Intervenors would be permitted to demonstrate that, despite
passing the Horizontal Market Power Screen, the seller otherwise qualified for the
Abbreviated Application poses a more serious risk of market power and should be
required to file the Standard Application. The 20% threshold is similar to the one
proposed in the December 19, 2003 Staff Paper (at 7-9) for the Market Share Screens,5
3
Such applicants would not prepare the Effects Factor Analysis, unless they failed the Horizontal Market
Power Screen.
4
For example, a seller may have a concentration of units within, straddling or throughout base,
intermediate or peak portions of the supply curve.
5
Staff Paper, Attachment to December 19, 2003 Notice of Technical Conference on Supply Margin
Assessment Screen and Alternatives, available at
http://www.ferc.gov/EventCalendar/Files/20040112104841-PL02-8-000-notice.pdf (last viewed March 11,
2005).
- vi but unlike that proposal the threshold as applied under the Horizontal Market Power
Screen would significantly reduce the chances of an erroneous result by requiring that the
market be unconcentrated, that the seller not be pivotal, and that the seller not exceed
20% of the entire market or any portion of the supply curve. The effect of the threshold,
as applied here, is to ensure, for example, that an owner of a large plant in a load pocket
is not in a position to profitably exercise market power.
The Standard Application sellers are those that do not qualify for the Safe Harbor
or the Abbreviated Application and for whom the results of the Horizontal Market Power
Screen cannot or should not be interpreted without an assessment of the Effects Factors
outlined below. Standard Applications would be filed by “
big fish,”including those in
large or small ponds, whose market characteristics raise the risk of market power
exercise, namely dominant sellers: vertically integrated utilities that have not divested
generation, merchant generators with fleets of facilities and retained rights to dispatch
their capacity, and sellers in concentrated load pockets. If in a position to exercise
market power, such sellers stand to earn hundreds of millions if not billions of
unwarranted profits from sales at supra-competitive rates. It is both appropriate and
obligatory for the Commission to examine such sellers’market-based rate requests
closely. Through this more probing inquiry, the Standard Application should reduce the
likelihood of false positives and false negatives, which benefits both sellers and
consumers.
These filing requirements work in conjunction with the Horizontal Market Power
Screen and Effects Factors to provide a robust Generation Market Power Test that
protects buyers and sellers. Treatment of the elements of the Test in à la carte fashion,
- vii however, can seriously jeopardize that protection. For example, the Commission should
not make the Safe Harbor available to a power marketer that controls the dispatch of
generation. Nor should the Commission make the Abbreviated Application available to a
merchant generator with a fleet of units in a geographic market. Both examples have
presented the Commission with serious market problems.6 Such problems could be
overlooked if the Generation Market Power Test were disaggregated and applied without
consideration for the relationship among its constituent parts.
B.
The Test Provides for Expedited Treatment of Straight-Forward
MBR Applications
Depending upon the complexity of an application, the Generation Market Power
Test contemplates (1) summary decision based upon pleadings of applications or (2) an
FPA Section 206 investigation. Applications presenting factual disputes, lacking needed
data, or involving complex or difficult issues concerning the interpretation of evidence
(e.g., disputes over geographic market definitions or passage of the Horizontal Market
Power Screen) should be set for hearing. However, the Commission can expedite the
hearing process itself by encouraging settlement conferences at the outset to identify
missing data, to determine means of obtaining it, and to identify issues subject to
resolution via stipulation. After settlement discussions, outstanding disputes and issues
can be addressed through hearing, including on an expedited basis.
Decisions based upon the application and pleadings (as well as responses to any
deficiency letters) could be appropriate for those cases that do not present factual disputes
or do not involve complex interpretative questions. Safe Harbor and Abbreviated
6
See Enron Power Marketing, Inc., et al., 106 F.E.R.C. ¶ 61,024 (2004), and Wisvest-Connecticut, LLC
and NRG Connecticut Power Assets, LLC, 96 F.E.R.C. ¶ 61,101 (2001).
- viii Applications are the most likely candidates for this kind of procedural treatment,
although Standard Applications would not be excluded. To help develop a factual record
that could permit summary disposition, the Commission should make use of deficiency
letters where applications are incomplete or do not appear to qualify for a specific
procedural category (for example, the application should be filed as a Standard rather
than Abbreviated one). After the applicant responds and intervenors have an opportunity
to assess the response, the Commission may then be able to decide the case without a
hearing.
II.
THE GENERATION MARKET POWER TEST PRODUCES
RELEVANT, PROBATIVE AND SUBSTANTIAL EVIDENCE TO
ASSESS SELLER MARKET POWER
A.
The Test Examines a Range of Metrics and Factors, Because
Reliance on a Single Metric Will Not Yield Reliable Results
The Generation Market Power Test, which is supported in the affidavit of
Dr. Laurence Kirsch attached to APPA/TAP’
s February 4, 2004 Post-Technical
Conference Comments in PL02-8-000 (hereafter “
Kirsch SMA Affidavit”
),7 reasonably
captures various aspects of a seller’
s market power and permits the Commission to make
evidence-backed decisions.8 According to Dr. Kirsch, a reasonable market power test
should include the following:
7
Dr. Kirsch’
s Affidavit originally accompanied the February 4, 2004 “
Post-Technical Conference
Comments of the American Public Power Association and the Transmission Access Policy Study Group,”
filed in Docket No. PL02-8-000, Conference on Supply Margin Assessment (“
February 4, 2004 SMA
Comments”
), available at http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10057963 (last
viewed March 11, 2005). APPA and TAPS also filed it in this docket on June 30, 2004.
8
The Test will permit examination of evidence relevant to market power in ancillary services markets, or
can be adapted to that purpose. It builds on the approach set forth in the October 23, 2002 Comments of
the American Public Power Association and Transmission Access Policy Study Group on Market Power,
Market Monitoring, and Market Mitigation Issues in Supply Margin Assessment and Standard Market
Design, Docket Nos. PL02-8-000 and RM01-12-000, at 15, 48-54 (available at
http://ferris.ferc.gov/idmws/common/OpenNat.asp?fileID=9581911) (last viewed on March 11, 2005).
- ix 
Screens should be able to identify situations in
which suppliers, alone or through parallel or
coordinated behavior (tacit or express collusion)
with other suppliers, are able to raise prices
significantly above competitive levels.
***

Screens should recognize that the ability to exercise
market power changes over time with changes in
load levels, generation output, and the availability
of generation and transmission facilities. At a
minimum, screens should examine market power
for the on-peak and off-peak periods of the different
seasons and, as appropriate, for forthcoming years.
Kirsch SMA Affidavit at 8-9. He concludes that: “
At the present time, there is no single
screen that can serve all of these purposes.”Dr. Kirsch also warns about the dangers of
relying on a single metric.
The proposed SMA, for example looks only at the most
extreme situations in which a supplier can single-handedly
reduce operating reserve margins to levels that trigger
emergency procedures or even require load shedding. This
ability to cause system distress is certainly sufficient to
establish the ability to exercise market power; but there are
many other situations in which a supplier can exercise
market power without having such an ability. The tests for
market power therefore need to include a variety of screens
that together provide a range of evidence needed to assess
the ability and incentives to exercise market power.
Kirsch SMA Affidavit at 9.
B.
The Horizontal Market Power Screen Provides Structural
Evidence of the Potential for Market Power Exercise
To make an informed decision about seller market power, the Commission must
have evidence revealing the relevant market’
s structure and the seller’
s place in it.
Because of the insufficiency of a single structural metric to provide this evidence, the
Horizontal Market Power Screen employs three metrics: Market Share and
-xConcentration, Pivotal Supplier and Supply Curve. The Commission Staff’
s Strawman
Discussion Paper on Market Metrics included similar metrics for assessing market
structure (Strawman at 18), and observed (at 11-12, footnote omitted):9
Concentration measures form the principal measure of
market structure, with the HHI being used most commonly
by the DoJ and in FERC analyses for mergers and market
based rates. In the analysis of market based rates, FERC
also employs the concept of a pivotal supplier, measuring
the degree to which the supply of a single firm is needed to
meet market demand in an area. These measures are
designed to provide an indication of market power for a
defined market, with market power being defined as the
ability to raise the price above the competitive level.
Although it can be argued that the link between
concentration and market power is not always conclusive, it
still provides a useful measure of competitive market
structure, particularly when used in conjunction with other
measures.
These metrics, or similar ones, are also employed by market monitors to assess market
power.10
Market share and concentration evidence, as produced by metrics such as HHI,
builds upon the Commission’
s familiarity with such metrics as part of the Appendix A
Analysis required by its merger regulations, 18 C.F.R. Part 33, as well as upon
acceptance of the metrics by the antitrust agencies and courts. See, e.g., FTC v. H.J.
Heinz Co., 246 F.3d 708, 716 n.9 (D.C. Cir. 2001) (noting judicial acceptance of HHI
9
See “
Strawman”Staff Discussion Paper on Market Metrics SMD Staff Conference on Market Monitoring,
Docket No. RM01-12, Remedying Undue Discrimination Through Open-Access Transmission Service and
Standard Electricity Market Design, available at
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=9567029 (last viewed March 11, 2005).
10
See ISO New England, Annual Markets Report, May –December 2002, at 34-45 (August 13, 2003)
(available at http://www.isone.com/smd/market_analysis_and_reports/public_forum_and_annual_report/2003_Annual_Forum/2002_A
nnual_Market_Report_Final.pdf) (last viewed on March 11, 2005).
- xi based upon DoJ, FTC and economist use of same). As adapted from the Appendix A
analysis, the Horizontal Market Power Screen will be easier to perform. The number of
geographic markets should, in most cases, be fewer with the Screen because it will not
have to be performed for every Destination Market. Rather, in many instances, a
properly calculated geographic market will capture several relevant Destination
Markets.11 The Screen would reflect Appendix A’
s use of seasonal and load level
calculations to “
recognize that the ability to exercise market power changes over time
with changes in load levels, generation output, and the availability of generation and
transmission facilities.”Kirsch Affidavit at 8-9.
More acute market power concerns arise during periods of peak demand,12 and so
the Horizontal Market Power Screen uses a pivotal supplier metric to determine the
extent to which a supplier’
s output is required to meet the market demand. The particular
metric urged here, the “
pivotal supplier HHI,”explained by Dr. Kirsch in his October
2002 affidavit (at 3-11) included with APPA/TAPS October 23, 2002 Market Power
Comments,13 measures pivotal supply at peak, like other similar metrics, but also
examines the collusion risk associated with suppliers who may be jointly pivotal. The
pivotal supplier HHI can also measure pivotal supply in non-peak hours, and so like the
11
There may be situations, however, where a load pocket within a destination market, will produce the
opposite result. This may occur when a single load-serving entity has customers inside and outside a load
pocket. In those cases, the load pocket must be analyzed as a separate geographic market.
12
13
Kirsch SMA Affidavit at 9.
See October 23, 2002 “
Comments of American Public Power Association and Transmission Access
Policy Study Group on Market Power, Market Monitoring, and Market Mitigation Issues in Supply Margin
Assessment and Standard Market Design,”Docket Nos. PL02-8 and RM01-12, available at
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=9581912 (last viewed March 11, 2005).
- xii December 19, 2003 Staff Paper’
s monthly peak approach (at 6-7),14 it can capture the
variations in potential market power that accompany seasonal variations in load and
supply.15
The Horizontal Market Power Screen also uses a supply curve metric to gauge the
incentives and abilities of a seller to exercise market power based upon the shape and
composition of the supply curve and the seller’
s place on it. A supply curve metric
serves the need identified by Staff’
s September 20, 2002 Strawman for “
some measure of
structural incentives for withholding, where firms with units near the market clearing
price (typically peaking units) hold large amounts of lower priced (typically baseload)
capacity that could profit from economic withholding of the marginal units, or from
physical withholding of small amounts of baseload capacity that would force the peaking
units to set the marginal price.”Strawman at 12. See also APPA/TAPS October 23,
2002 Market Power Comments at 51-52.16 Data from commercial sources, such as RDI,
provide basic information (plant ownership, fuel source, costs, location) that allows
construction of a straight forward supply curve to assess whether its composition and
shape, including the location of the seller’
s own units on the curve, can provide the seller
with the ability and incentive to profitably withhold.
14
The Staff Paper’
s recommendation to adjust capacity calculations for planned outages merits further
analysis so that it produces a more accurate picture of the market. For example, outages that reduce a
seller’
s market share during shoulder months should not similarly reduce its market share during peak
months when the outage has ended. Outages of both the applicant and other sellers are relevant as well. In
addition, the Commission should understand what effects an outage (including forced) has on transmission
constraints and whether the seller can dispatch its units to profitably raise prices above competitive levels.
15
See Kirsch SMA Affidavit at 8-9.
16
See n.13 supra.
- xiii It bears noting that the framework set forth here creates other opportunities to
make the Horizontal Market Power Screen practical and not unduly burdensome. First,
sellers eligible to file Abbreviated Applications may perform the Screen using the
conservative assumption that no transmission capacity exists to permit imports from
competing capacity.17 This assumption reduces considerably the amount of transmission
price and capacity data required to run the Screen. Second, the same data set should
enable an applicant to calculate all three metrics, especially when the no-competitiveimports assumption applies. Third, the Commission itself can facilitate the availability of
data to run the Screen, and make the Screen results more robust, if it adopts the regionbased MBR review described in the main body of the APPA/TAPS March 14, 2005
Comments.
C.
Sellers Posing Higher Market Power Risk Must Submit Evidence
Regarding “Effects Factors”
As emphasized above, market power analysis is not mechanistic. The Horizontal
Market Power Screen, while providing indicative data, is not determinative of the market
power question, especially where a seller’
s market position suggests a greater or a lesser
ability or incentive to exercise market power. Like competition authorities,18 the
Commission should view the structural data as a starting point of the analysis and
continue with an assessment of the role of other factors. These Effects Factors are not
duplicative of the Screen metrics, but complement the screen by allowing consideration
17
Sellers which are neither dominant nor pivotal with diminished competitor presence will not become
dominant or pivotal when a larger amount of competing capacity is included in the calculation of the
metrics.
18
See Horizontal Merger Guidelines, § 2.0; Assessment of Market Power, Office of Fair Trading,
Publication OFT 415, ¶ 3.6 (September 1999) (available at http://www.railreg.gov.uk/upload/pdf/oft415.pdf) (last viewed March 11, 2005).
- xiv of market-specific facts that would suggest that the screen results understate or overstate
a seller’
s ability and incentive to exercise market power. As such, sellers and purchasers
should view the Effects Factors as a meaningful and important addition to the Generation
Market Power Test to ensure the Commission reaches the right result.
The Sales and Transaction Factor examines actual activity in the relevant market
as a real-world test of the Horizontal Market Power Screen results. It allows the
applicant and intervenors to show whether the sales and transaction experience in the
market is consistent with what the structural metrics show. One kind of evidence that
could be examined is RFP results, particularly to gauge how many sellers responded to an
RFP and difficulties the respondents might have encountered, such as difficulties of
securing transmission paths. The Factor also allows an examination of the applicant’
s
level of sales activity to understand better whether an applicant is or is not active in
making third party sales, to whom, at what prices and, where the seller is not active, why
not.
The Load Obligations Factor considers how a seller’
s obligations to native load
and other long-term requirements customers affects its incentives and ability to raise
prices. For example, it is clear that capacity “
dedicated”to serve native load often is
available to and does participant in wholesale markets. The ability of a seller to use the
capacity to cause competitive injury in the wholesale market will depend on facts such as
the extent to which price increases in the wholesale market caused by the seller’
s
anticompetitive activity must be borne by the seller or may be passed along to the seller’
s
customers, such as through a fuel and purchased power adjustment clause. Similarly, the
retail ratemaking regime may permit the seller to pass along to shareholders increased
- xv profits from sales at supra-competitive prices in wholesale markets. The structural
metrics described above cannot be satisfactorily adjusted to account for these facts.
Thus, it is appropriate to assess them as Effects Factors to determine based upon sellerspecific facts haw they should be accounted for in the market analysis. The Factor also
allows the applicant to explain, and the Commission to analyze, any differences between
the Economic Capacity and Available Economic Capacity results of the Appendix A
analysis to determine their affect on the ability and incentive to exercise market power.
The Entry Conditions Factor considers where entry can defeat an attempt to
increase prices and help to deconcentrate markets.19 An applicant should submit
evidence on entry conditions, such as planned entry (projects under construction), past
entry, site availability and control, siting authority and procedures, and transportation
infrastructure (electricity transmission and natural gas transportation), control over fuel
inputs for electric generation (e.g. natural gas pipelines or capacity contracts) and
profitability of entry.20 Assessment of entry conditions should address both short-term
and long-term horizons.
As Dr. Kirsch details, the Commission cannot assume that entry will be likely,
timely and sufficient to defeat seller market power.21 Among other things, “
generation
investment may be lumpy,”“
transmission access may be insufficient,”and “
access to
fuels may be insufficient.”Kirsch SMA Affidavit at 5-6. LSEs in many parts of the
19
APPA and TAPS also addressed entry conditions in their October 23, 2002 Market Power Comments (at
52-54).
20
The price necessary to make entry attractive may be high and leave considerable room for a dominant
incumbent to exercise market power.
21
See Horizontal Merger Guidelines, § 3.0.
- xvi country feel the impact of the entry difficulties described by Dr. Kirsch. According to
Mr. Jesse Tilton at the Commission’
s January 13, 2004 Technical Conference on the
Supply Margin Assessment, Docket No. PL02-8-000:22
While in other parts of the Southeast there is a generation
glut, we can’
t access it. Meanwhile, building our own plant
in eastern North Carolina is not economically justified
because of the absence of basic transportation infrastructure
-- pipes and wires. Purchases from merchants are not a
viable alternative, because there is very little merchant
capacity in the CPL-East control area.
It is clear from the SMA record that the Generation Market Power Test must consider
entry conditions.
The Transmission Factor: An applicant should address whether transmission
operations have been turned over to an independent entity. Where they have not, the
applicant should address the prospect for and barriers to independent operation. The
applicant should describe expected changes in transmission capacity, either due to future
reservations from the applicant itself (or others, if known) or the construction of new
transmission facilities. This Factor also provides evidence to assess the credibility of a
transmission owning seller’
s data on transmission capacity, especially where the seller
has not turned over control of its transmission to an independent entity. Vertically
integrated generators should demonstrate that transmission limits do not now and will not
in the future impose binding limits on the geographic market. Probative evidence in this
regard includes the availability of firm transfer capability for imports and exports along
major interfaces as well as the frequency with which transmission is constrained in the
22
Conference on Supply Margin Assessment, Statement of Jesse C. Tilton III for the January 13 Technical
Conference at 4 (available at http://ferris.ferc.gov/idmws/common/OpenNat.asp?fileID=10040946) (last
viewed March 11, 2005).
- xvii geographic market, for example as indicated by the frequency of TLR calls. The
applicant should describe expected changes in transmission capacity during the
authorization period, though the Commission must take care to separate promised
upgrades from ones that are certain to be constructed. The Commission should also look
at evidence regarding whether available transmission capacity will change over the long
term (e.g., as a result of load-growth, generation location decisions, transmission
expansion).
The Demand Elasticity Factor examines the extent to which buyers can reduce or
shift consumption in response to a price increase, because it affects whether a seller may
profitably exercise market power. Where demand response programs have developed,
sellers can choose to submit evidence that demand elasticity limits their ability to
exercise market power. For sellers choosing not to submit evidence on this factor,
demand elasticity will be assumed to be very low. Sellers choosing to address this factor
should include information on both short-term and long-term elasticity.
The Optional Regional and Local Factors allow introduction of other relevant
and probative evidence that affects a seller’
s ability and incentive to exercise market
power. For example, an applicant in a market where hydropower is prevalent would want
to address the effect of high- and low-water years, as well as license conditions and
regional agreements governing hydro dispatch. Other possibly relevant evidence
includes past anticompetitive behavior in which the seller has engaged.23
23
See Horizontal Merger Guidelines, § 2.1; City of Cleveland, 68 F.3d 1361, 1368 (D.C. Cir. 1995).
- xviii D.
The Generation Market Power Test Is Applied to a Properly
Defined Geographic Market
Any market power metric must be applied to a properly defined, rather than
assumed, geographic market. The Generation Market Power Test sets forth a practical,
fact-based mechanism to define the geographic market. It requires the applicant to apply
the Horizontal Market Power Screen to its control area or transmission service area and to
examine whether the control area or transmission service area, based upon marketspecific evidence, should be defined as the relevant geographic market. In some cases,
the geographic market will be larger,24 or smaller,25 than a control area or transmission
service area.
Dr. Kirsch’
s discussion of relevant considerations for geographic market
definition supports not assuming a control area as the market.
Screens should recognize that the ability to manipulate
market prices critically depends upon transmission
limitations, because transmission constraints (and, to a
lesser extent, losses) limit generators’ability to compete
with one another. Consequently, although control areas
may be a reasonable starting point for drawing the
geographic boundaries of electricity markets, they in fact
define the physical boundaries only for regulation and
frequency control service. The physical boundaries for
energy and reserve services markets, by contrast, are
determined primarily by prevalent transmission constraints.
Institutional boundaries such as those established by
control areas, RTOs and ISOs, and state lines can also
inhibit trade in these services, however, and thus need to be
considered in determining market boundaries.
Kirsch SMA Affidavit at 8.
24
25
DeSoto County Generating Co., 105 F.E.R.C. ¶ 61,245 (2003).
Wisvest-Connecticut, LLC and NRG Connecticut Power Assets, LLC, 96 F.E.R.C. ¶ 61,101, at 61,399400 (2001).
- xix Proper geographic market definition matters not only from the perspective of
performing the Test correctly, but also to ensure that market participants subject to
competitive injury due to the seller’
s market power have access to the mitigation
remedy. For example, a control area focus inappropriately may exclude consideration of,
and potentially relief for, small systems whose loads are dynamically scheduled out of the
control area but who nevertheless are economically in the market and are affected by
physical transmission limitations into the service area. In some other instances, analyses
of sub-regional markets will be necessary to detect market power problems in areas that
comprise more than an applicant’
s control or service area but less than an entire region.
Not only will some applicants fail the applicable metric for their own areas, they will also
fail it in the wider region. For example, when Progress Energy Corporation sought
authorization for its generating and power marketing affiliates to sell at market-based
rates in Peninsular Florida, the companies not only would have failed the SMA for the
control area of Florida Power Corp., Progress Energy’
s retail subsidiary in Florida (in
which control area Progress did not seek MBR authority), but also failed the SMA for
entirety of Peninsular Florida.26 However, if the Commission had adhered to a
predetermined, control area application of SMA, the harm in Peninsular Florida would be
ignored, and rates outside the Florida Power Corp. control area would have been
26
See October 16, 2003 “
Motion to Intervene, Motion to Consolidate, and Protest of Seminole Electric
Cooperative, Inc. and Florida Municipal Power Agency”filed in Docket Nos. ER03-1389-000 and ER031838-000 (available at http://ferris.ferc.gov/idmws/File_list.asp?document_id=4144938) (last viewed
March 11, 2005).
- xx adversely affected.27 This example underscores the need to define the geographic market
by reference to market-specific facts.
E.
The Geographic Market Power Test Uses Transmission Capacity
Available to Competitors: Simultaneous ATC
Because TTC in no way reflects transmission capacity actually available to
competing suppliers, a realistic figure such as ATC must be used. The inquiry must also
examine other data, such as TTC, TRM, CBM, the incidence and extent of TLRs and
other transmission curtailments, and the applicant’
s own reservations, for their effects on
capacity.28
Another problem with TTC is that it can double count capacity available to import
competing supply to the market. Holders of long-term firm transmission rights usually
use such rights to import firm capacity into a market, which means that the capacity
supported by the transmission reservation should be reflected in the importing firm’
s
market share. However, TTC calculations do not deduct that reserved capacity but
assume that it available for more competing supply to be brought into the market. As a
result, the TTC calculation causes an overstatement of the amount of competing supply.
Mr. Tilton also testified to the need not to rely solely on ATC:29
The Commission needs to be open to further adjustments as
the facts require. Unfortunately, long-term ATC is not
regularly available, and the Commission should work to
find a way to make such information available.
27
The Commission set Progress Energy’
s request for hearing, including on the issue of the appropriate
geographic market. DeSoto, 105 F.E.R.C. ¶ 61,245 (2003). Progress Energy subsequently withdrew its
MBR request.
28
See also Tilton SMA Statement at 9.
29
Id.at 9.
- xxi The Commission can best deal with the issue of transmission capacity measures if it has
before it information necessary to make an informed calculation. ATC is clearly better
than TTC, should be readily available from OASIS sites and is the measure used by the
Commission’
s Merger Regulations.30 However, as Mr. Tilton observed, ATC provides
limited insight on longer term availability. Thus, the Commission should also require
that owners/operators of transmission include data on TTC, TRM, CBM, the frequency
and extent of TLRs, as well as long-term reservations, so that the Commission and
intervenors can have an accurate picture of transmission actually available to support
competition in the market.
With the evidentiary record produced by the Generation Market Power Test, the
Commission can then exercise its judgment about whether the applicant has market
power. If the Commission concludes that the seller has market power, the record
provides a basis to consider mitigation measures specifically targeted to the market power
concerns revealed through the analysis. Possible mitigation measures are described in the
APPA/TAPS March 14, 2005 Comments.
30
18 C.F.R. § 33.3(c)(4)(i)(C).