Market-Based Rates:
Lessons from the Trenches
EBA YLC Brown Bag Seminar
April 23, 2013
Jane E. Rueger, Counsel
jrueger@whitecase.com
Agenda
I. A Brief History
 The path to market-based rates (“MBR”) in the US
II. MBR Application Framework
 Overview of FERC’s requirements for obtaining MBR Authority
III. Spotlight on Market Power
 Presented by Julie Solomon
IV. Maintaining MBR Authority
 Ongoing compliance obligations
V. “Tips from the Trenches”
VI. Q&A
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I. A BRIEF HISTORY
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Federal Rate Regulation Starts With The Federal Power Act
 Under Part II of the Federal Power Act, FERC has jurisdiction over wholesale
sales of electric energy in interstate commerce and the transmission of electric
energy in interstate commerce.
 FPA Section 205 requires that public utilities file with FERC all rates and
charges subject to FERC’s jurisdiction, and such rates and charges must be
“just and reasonable.”
 Traditionally, rates were (and many still are) cost-based, allowing a public
utility to recover its cost of service plus a reasonable return on equity.
 In the late 1980s, FERC began to approve market-based rates for wholesale
sales of electric energy in order to incentivize participation in the energy
markets by non-traditional suppliers such as independent power producers
and power marketers.
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Development of FERC’s Market-Based Rate Program
 While the FPA does not require rates to be cost-based, FERC must exercise
its oversight to ensure ex ante that market-based rates are just and reasonable
when granted.
 Farmers Union Central Exchange, Inc. v. FERC, 734 F.2d 1486 (D.C. Cir. 1984).
 FERC must also engage in effective regulatory oversight after market-based
rate authority is granted to ensure that market-based rates continue to be just
and reasonable over time.
 State of California ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 2004).
 Order No. 697 and orders on rehearing and clarification of Order No. 697
provide the essential roadmap for FERC’s current approach to these two
requirements.
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II. MBR APPLICATION
FRAMEWORK
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Essential Components of MBR Application
1
Describe Applicant & Affiliates
2
Address Market Power
3
Address Ancillary Services, Category Status, and Other Waivers and
Limitations
4
eTariff and Appendices
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1. Describe Applicant & Affiliates

Describe the applicant and the
facilities it owns and controls.

Describe the corporate
ownership structure of the
applicant



Upstream holding companies
Downstream subsidiaries
Describe affiliates of the
applicant that own or control




generation facilities
transmission facilities
natural gas transmission, storage
or distribution facilities
inputs to electric power
production
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2. Address Market Power
 Explain how the applicant meets the legal standard …
FPA § 205
a.
b.
Rates and charges made or received by any public utility for the sale of
electric energy subject to the Commission’s jurisdiction must be “just and
reasonable” and not unduly discriminatory or preferential.
Applicant and affiliates do not have, or have adequately mitigated, horizontal
(generation) market power.
Applicant and affiliates do not have, or have adequately mitigated, vertical market
power.
 Transmission market power
 Ability to erect barriers to entry in the relevant market: “Applicant affirmatively
states that it has not erected barriers to entry into the relevant market and
will not erect barriers to entry into the relevant market”
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3. Address Ancillary Services, Category Status, and Other
Waivers and Limitations
 Sellers must separately request authorization to sell ancillary services into
relevant markets.
 Sellers must request and justify appropriate category status in each FERC
designated region

Category 1 sellers are defined in Section 35.36 of FERC’s regulations
 Sellers may request appropriate waivers and blanket authorizations




Waiver of the accounting, reporting, and other requirements of Parts 41, 101, and 141 of the
Commission’s regulations, with the exception of 18 C.F.R. Sections 141.14 and 141.15;
Blanket authorization under Section 204 of the FPA and Part 34 of the Commission’s
regulations for future issuances of securities and assumptions of liability;
Waiver of the full filing requirements of subparts B and C of Part 35 of the Commission’s
regulations, except the transmittal requirements of 18 C.F.R. Sections 35.12(a), 35.13(b), and
the notification of succession and cancellation of service requirements of 18 C.F.R. Sections
35.15 and 35.16
Waiver of the affiliate code of conduct
 Sellers must notify FERC whether they will engage in the reporting of
transactions to publishers of electric or natural gas prices indices.
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4. eTariff and Appendices
 The MBR application including a proposed tariff must be submitted through
FERC’s eTariff program
 Use standard tariff language for
 Ancillary services available for sale in each organized market and outside organized
markets
 Statement of ongoing compliance with Part 35 Subpart H of FERC’s regulations
 Limitations and Waivers that have been granted to seller
 Seller’s Category Status in all regions
 Consult FERC website for guidance on standard language
 http://www.ferc.gov/industries/electric/gen-info/mbr.asp
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4. eTariff and Appendices
 List all affiliates with MBR
authority, identifying all
generation assets owned
or controlled by the
corporate family by
balancing authority area
and geographic region.
 List all electric
transmission and natural
gas intrastate pipelines
and/or gas storage
facilities owned or
controlled by the corporate
family.
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III. ADDRESSING MARKET POWER
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FERC Market-Based Rates
EBA Young Lawyers Committee
April 23, 2013
©2013 Navigant Consulting, Inc.
Confidential and proprietary. Do not distribute or copy.
D I S P U T E S & I N V E S T I G AT I O N S • E C O N O M I C S • F I N A N C I A L A D V I S O RY • M A N A G E M E N T C O N S U LT I N G
Table of Contents
1
Measures of Market Power
2
FERC Horizontal Analysis
3
Implications
©2013 Navigant Consulting, Inc.
Confidential and proprietary. Do not distribute or copy.
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Table of Contents
1
Measures of Market Power
2
FERC Horizontal Analysis
3
Implications
©2013 Navigant Consulting, Inc.
Confidential and proprietary. Do not distribute or copy.
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Definition of Market Power
Ability to profitably sustain an increase in the market price
(through unilateral action or tacit collusion).
›
Horizontal Market Power. Strategic withholding
(withholding some capacity to profit on capacity actually
sold).
› Physical withholding (taking generation out of service).
› Economic withholding (bidding above expected market
clearing price).
›
Vertical Market Power.
›
Control over inputs to production (e.g., transmission or
natural gas transportation) to raise competitors’ costs or
deny access.
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Typical Measures of Market Power
Various quantitative measures are used to evaluate market
power – by FERC, antitrust agencies, and market
monitoring units of RTOs/ISOs
›
›
Market Share.
Market Concentration. Measured by Herfindahl-Hirschman
Index (HHI). Unconcentrated, moderately concentrated, highly
concentrated markets.
›
Pivotal Supply. Whether the supply of a single or multiple
suppliers is required to meet demand.
›
Residual Supply Index. Percentage of demand that can be met
without relying on an individual seller’s capacity.
›
Lerner Index or Price-Cost Markup. Price minus marginal cost
divided by price.
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Table of Contents
1
Measures of Market Power
2
FERC Horizontal Analysis
3
Implications
©2013 Navigant Consulting, Inc.
Confidential and proprietary. Do not distribute or copy.
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FERC Market-Based Rates Horizontal Analysis
FERC requires analysis of horizontal market power in
context of granting generators/marketers authority to sell
into wholesale markets at market-based rates, for triennial
reviews, and for notices of change in status
›
Primary analytical tool (Indicative screens)
› Simplified Pivotal Supplier Analysis
› Simplified Market Share Analysis
› Brightline tests: not a pivotal supplier, market share less than
20% in all seasons
›
Secondary analytical tool (if indicative screens are failed)
› Delivered Price Test
› Historical Sales
› No brightline tests
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FERC Indicative Screens
FERC’s Indicative Screens consist of “Pivotal Supplier
Analysis” and “Market Share Analysis”
›
Relevant Market
› Balancing authority area (“BAA”) or RTO/ISO based on where
generation is located
› Transmission owners/operators must analyze own BAA and
first-tier interconnected markets (unless relevant market is
RTO/ISO
›
Relevant Submarket
› FERC has identified relevant submarkets in certain RTOs
•
•
•
PJM: PJM East, AP South, 5004/5005 interface
NYISO: New York City, Long Island
ISO-NE: Southwest Connecticut, Connecticut Interface
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FERC Indicative Screens
›
Study Period
› An historical one-year period, December-November
•
Updated market power analyses (triennial reviews) for transmissionowning applicants
o Study period based on Order No. 697 schedule
•
Updated market power analyses for applicants that do not own
transmission
o Study period based on Order No. 697 schedule
•
Transmission-owning applicants for initial market-based rate
authorization or submission of a change in status filing
o Most recent available actual historical data
•
All other applicants
o Same vintage data that were used in the triennial reviews filed by the transmission
owners in their region within the past year; or, if not available
o Most recently available actual historical data for December-November period, or
o the same seasons in their market share studies that were used in the most recently
filed triennial studies, with explanation
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FERC Indicative Screens
›
Triennial Schedule
› Exemption: Category 1 sellers, less than 500 MW per region
Transmission Owners
Region
›
Others
Filing Date
Region
Filing Date
Northwest
June 2013
Northwest
December 2013
Northeast
December 2013
Northeast
June 2014
Southeast
June 2014
Southeast
December 2014
Central
December 2014
Central
June 2015
SPP
June 2015
SPP
December 2015
Southwest
December 2015
Southwest
June 2016
Change in Status Filing
› Within 30 days after event
› Materiality threshold: net change of 100 MW
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Indicative Screen: Pivotal Supplier Analysis
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Indicative Screen: Market Share Analysis
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Market-Based Rate Implementation Process
Pass
RTOs/ISOs
Indicative
Screens
Keep MBR
Authority
Rely on RTO
Market
Monitoring and
Mitigation
Fail
Pass
Balancing
Authority
Areas
Keep MBR
Authority
Pass+
Indicative
Screens
Fail
DPT+
Fail
Mitigation
(Cost-based
Rates)
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FERC Horizontal Analysis
FERC relies on a Delivered Price Test (“DPT”) to evaluate
mergers and as a secondary analysis in market-based rate
proceedings where applicants fail indicative screens
› Geographic Market.
RTOs/ISOs or submarkets (constrained areas within
RTO/ISO), or BAAs.
› Product Market. Primary focus on energy (capacity), but also ancillary
services where information is available.
› Economic Capacity. Energy that is economic and deliverable to the
market (including transmission costs and losses) at a cost within 105%
of market price. Ignores native load commitments.
› Available Economic Capacity.
Same as Economic Capacity but
takes into account native load commitments.
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FERC Horizontal Analysis (continued)
› For market based rates, DPT is analyzed in the context of pivotal
supplier test, market share and market concentration. Typically ten
load/time period snapshots are examined.
•
•
•
Pivotal supplier (pass/fail)
Market share (~20%, not bright-line test)
Market concentration (<2500, also not bright-line test)
› Market concentration (HHI) calculated based on market shares
squared.
•
•
4 equal sized suppliers (25% each), HHI is 2500 (25%^2*4)
2 large suppliers (40% each), plus 4 small suppliers (5%) each, HHI
is 3300 (40%^2*2+5%^2*4)
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Sample DPT Results for DPT
Available Economic Capacity
Period
a
Market
Price
b
S_SP1
S_SP2
S_P
S_OP
W_SP
W_P
W_OP
SH_SP
SH_P
SH_OP
$
$
$
$
$
$
$
$
$
$
Applicant
MW
c
100
50
40
30
40
30
25
40
30
25
1,900
1,500
1,500
0
1,800
1,400
0
1,800
0
0
Mkt
Size
d
8,000
7,900
6,000
3,500
7,500
6,000
3,500
9,000
7,500
3,500
Pivotal Supplier Test
Market Share Test
Pass
Pass
Wholesale Pivotal
Market
Rival
Market
Supplier
Mkt
Share
Capacity
Load
?
Share
Test?
e
f
g
h
i
6,100
6,400
4,500
3,500
5,700
4,600
3,500
7,200
7,500
3,500
6,400
6,320
4,800
2,800
6,000
4,800
2,800
7,200
6,000
2,800
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
24%
19%
25%
0%
24%
23%
0%
20%
0%
0%
No
Yes
No
Yes
No
No
Yes
No
Yes
Yes
Market
Pass HHI
Test?
k
HHI
j
2,700
2,600
2,100
1,700
2,000
1,800
2,000
2,100
1,800
2,000
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Wholesale market load is proxy from Indicative Screens Pivotal Supplier Test.
Economic Capacity
Period
a
Market
Price
b
S_SP1
S_SP2
S_P
S_OP
W_SP
W_P
W_OP
SH_SP
SH_P
SH_OP
$
$
$
$
$
$
$
$
$
$
Applicant
MW
c
100
50
40
30
40
30
25
40
30
25
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1,900
1,500
1,500
0
1,900
1,500
0
1,900
0
0
Mkt
Size
d
14,400
14,220
10,800
8,000
13,500
10,800
8,000
16,200
13,500
8,000
Pivotal Supplier Test
Market Share Test
Pass
Pass
Wholesale Pivotal
Market
Rival
Market
Supplier
Mkt
Share
Capacity
Load
?
Share
Test?
e
f
g
h
i
12,500
12,720
9,300
8,000
11,600
9,300
8,000
14,300
13,500
8,000
11,520
11,376
8,640
6,400
10,800
8,640
6,400
12,960
10,800
6,400
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
13%
11%
14%
0%
14%
14%
0%
12%
0%
0%
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Market
HHI
j
5,000
5,000
4,500
4,800
4,400
4,000
3,000
4,000
3,900
2,500
Pass HHI
Test?
k
No
No
No
No
No
No
No
No
No
No
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FERC Horizontal Analysis (continued)
Whether the more important measure is Economic Capacity
(ignoring load obligations) or Available Economic Capacity
(taking into account load obligations) depends...
›
In restructured markets (e.g., RTOs/ISOs)
› Economic Capacity is more relevant
› Utilities have largely divested generation
› Utilities generally meet load obligations through contracts
›
In non-restructured markets
› Available Economic Capacity is more relevant
› Utilities remain vertically-integrated
› Utilities have continuing load obligations
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Table of Contents
1
Measures of Market Power
2
FERC Horizontal Analysis
3
Implications
©2013 Navigant Consulting, Inc.
Confidential and proprietary. Do not distribute or copy.
30
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Implications
›
Market-based Rates
› FERC’s approach provides roadmap for standards to be met
› RTO market mitigation and monitoring has been acceptable
mitigation
› Some parties are losing market-based rate authority in BAAs
where they own generation
›
›
Mostly, this affects incumbent utilities
›
Some results for merchant generators are unexpected
Applicants can use default cost-based mitigation or propose
tailored mitigation
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Key
CONTACTS
ENERGY
Julie R. Solomon| Managing Director
julie.solomon@navigant.com
202.481.8492 direct
©2010 Navigant Consulting, Inc.
©2013
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IV. MAINTAINING MBR
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Primary FERC Tools For Monitoring MBR Sellers
 MBR sellers must file Electric Quarterly Reports containing contract and
transaction data relevant to their market-based sales, even if no sales have
occurred
 Order Nos. 768 and 770 revised content and filing system effective 3Q 2013
 MBR sellers must abide by the Market Behavior Rules codified in Part 35 of
FERC’s regulations
 MBR sellers must file change in status notifications within 30 days of the
effective date of a change “that would reflect a departure from the
characteristics that FERC relied upon in granting market-based rate authority.”
 If Category 2, MBR sellers must make triennial market power filings reaffirming
that they do not have, or have adequately mitigated, horizontal and vertical
market power.
 MBR sellers must abide by RTO/ISO market rules designed to mitigate market
power
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4. Triennial Market Power Update Regions
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V. SOME TIPS FROM THE TRENCHES
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Tips from the Trenches
1. Don’t get sloppy with the MWs from partially owned affiliates. FERC
has specific rules governing how to attribute MWs, and it differs
between partially owned plants and partially owned affiliates.
2. Describe all affiliates in all regions.
3. If you complete the market screens using data filed by someone else,
use the most recent market data on file. And, indicate whose screens
you are relying upon.
4. Ask lots of questions of your clients!
5. Do not deviate from standard language for barriers to entry affirmative
statement or required tariff provisions.
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Tips from the Trenches
6. Check your asset appendices, and then check them again. Do not
deviate from the form the Commission requires.
7. Project companies can be Category 1 sellers in regions where they are
affiliated with over 500 MWs of generation if they do not have any MWs
themselves in those regions.
8. Consider whether to seek waiver of the open access requirements with
regard to interconnection facilities.
9. Change in status filings are required for net increases in generation of
100 MW or more and separately for affiliation with new generationowning entities that were not previously divulged.
10. Think through the eTariff program requirements well in advance of
filing.
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Questions?
For more information:
Jane Rueger, Counsel: jrueger@whitecase.com; 202-626-6534
Julie Solomon, Managing Director: julie.solomon@navigant.com; 202-481-8492
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