1. Jane E. Rueger, Counsel jrueger@whitecase.com
Market-Based Rates: Lessons from the Trenches EBA YLC Brown Bag Seminar April 23, 2013
Jane E. Rueger, Counsel

2. Agenda I. A Brief History II. MBR Application Framework
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

3. I. A Brief History

4. 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.

5. 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.

6. II. MBR Application Framework

7. Essential Components of MBR Application1
Describe Applicant & Affiliates 2
Address Market Power
Address Ancillary Services, Category Status, and Other Waivers and Limitations 3 4
eTariff and Appendices
(18 C.F.R. Part 35)

8. 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

9. 2. Address Market Power
Explain how the applicant meets the legal standard …
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”
FPA § 205
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.

10. 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 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 and ;
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 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.
“[W]holesale power marketers and wholesale power producers that own or control 500 MW or less of generation in aggregate per region; that do not own, operate or control transmission facilities other than limited equipment necessary to connect individual generating facilities to the transmission grid (or have been granted waiver of the requirements of Order No. 888); that are not affiliated with anyone that owns, operates or controls transmission facilities in the same region as the seller’s generation assets; that are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and that do not raise other vertical market power issues.”

11. 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
But note it is just a tool and can sometimes be slightly incorrect.

12. 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.

13. III. Addressing Market Power

14. FERC Market-Based Rates
EBA Young Lawyers Committee
April 23, 2013

15. Table of Contents 1 Measures of Market Power 2
FERC Horizontal Analysis 3
Implications

16. Table of Contents 1 Measures of Market Power 2
FERC Horizontal Analysis 3
Implications

17. 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.

18. 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.

19. Table of Contents 1 Measures of Market Power 2
FERC Horizontal Analysis 3
Implications

20. 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

21. 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

22. Study Period FERC Indicative Screens
An historical one-year period, December-November
Updated market power analyses (triennial reviews) for transmission- owning applicants
Study period based on Order No. 697 schedule
Updated market power analyses for applicants that do not own transmission
Transmission-owning applicants for initial market-based rate authorization or submission of a change in status filing
Most recent available actual historical data
All other applicants
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
Most recently available actual historical data for December-November period, or
the same seasons in their market share studies that were used in the most recently filed triennial studies, with explanation

23. Change in Status Filing
FERC Indicative Screens
Triennial Schedule
Exemption: Category 1 sellers, less than 500 MW per region
Change in Status Filing
Within 30 days after event
Materiality threshold: net change of 100 MW
Transmission Owners
Others
Region
Filing Date
Northwest
June 2013
Northeast
December 2013
Southeast
June 2014
Central
December 2014
SPP
June 2015
Southwest
December 2015
Region
Filing Date
Northwest
December 2013
Northeast
June 2014
Southeast
December 2014
Central
June 2015
SPP
December 2015
Southwest
June 2016

24. Indicative Screen: Pivotal Supplier Analysis

25. Indicative Screen: Market Share Analysis

26. Market-Based Rate Implementation Process
Pass
Indicative Screens
Rely on RTO Market Monitoring and Mitigation
Keep MBR Authority
RTOs/ISOs
Fail
Pass
Balancing Authority Areas
Pass+
Keep MBR Authority
Indicative Screens
Fail
DPT+
Fail
Mitigation (Cost-based Rates)

27. 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.

28. 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)

29. Sample DPT Results for DPT

30. 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

31. Table of Contents 1 Measures of Market Power 2
FERC Horizontal Analysis 3
Implications

32. Market-based Rates Implications
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
Applicants can use default cost-based mitigation or propose tailored mitigation
Some results for merchant generators are unexpected

33. Julie R. Solomon| Managing Director julie.solomon@navigant.com
ENERGY

34. IV. Maintaining MBR

35. 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
Also market manipulation rules that are generally applicable and increased OE Staff.

36. 4. Triennial Market Power Update Regions

37. V. Some Tips from the Trenches

38. Tips from the Trenches
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.
Describe all affiliates in all regions.
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.
Ask lots of questions of your clients!
Do not deviate from standard language for barriers to entry affirmative statement or required tariff provisions.

39. Tips from the Trenches
Check your asset appendices, and then check them again. Do not deviate from the form the Commission requires.
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.
Consider whether to seek waiver of the open access requirements with regard to interconnection facilities.
Change in status filings are required for net increases in generation of 100 MW or more and separately for affiliation with new generation-owning entities that were not previously divulged.
Think through the eTariff program requirements well in advance of filing.

40. Questions? For more information:
Jane Rueger, Counsel:
Julie Solomon, Managing Director: