Market-Based Rates: Lessons from the Trenches EBA YLC Brown Bag Seminar April 23, 2013

Market-Based Rates: Lessons from the Trenches

EBA YLC Brown Bag Seminar

April 23, 2013

Jane E. Rueger, [email protected]

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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&A2

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I. A BRIEF HISTORY

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Federal Rate Regulation Starts With The Federal Power Act

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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

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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

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Describe Applicant & Affiliates

Address Market Power

Address Ancillary Services, Category Status, and Other Waivers and Limitations

eTariff and Appendices

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1. Describe Applicant & Affiliates

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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

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Explain how the applicant meets the legal standard …

a. Applicant and affiliates do not have, or have adequately mitigated, horizontal (generation) market power.

b. 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.

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3. Address Ancillary Services, Category Status, and Other Waivers and Limitations

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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

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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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D I S PU TE S & I N V E S T IG AT I ON S • EC O N O MI CS • F I N A N C I AL A D V I SO RY • MA N A G E ME N T C ON S U LTI N G

©2013 Navigant Consulting, Inc. Confidential and proprietary. Do not distribute or copy.

April 23, 2013

FERC Market-Based RatesEBA Young Lawyers Committee

15©2013 Navigant Consulting, Inc. Confidential and proprietary. Do not distribute or copy. E N E R G Y

3 Implications

2 FERC Horizontal Analysis

1 Measures of Market Power

Table of Contents


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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.

Definition of Market Power


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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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


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



› Study Period› An historical one-year period, December-November

• Updated market power analyses (triennial reviews) for transmission-owning applicantso Study period based on Order No. 697 schedule

• Updated market power analyses for applicants that do not own transmissiono Study period based on Order No. 697 schedule

• Transmission-owning applicants for initial market-based rate authorization or submission of a change in status filingo Most recent available actual historical data

• All other applicantso 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



› 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

Region Filing DateNorthwest June 2013Northeast December

2013Southeast June 2014Central December

2014SPP June 2015Southwest December

2015

Region Filing DateNorthwest December

2013Northeast June 2014Southeast December

2014Central June 2015SPP December

2015Southwest June 2016

Transmission Owners

Others


Indicative Screen: Pivotal Supplier Analysis


Indicative Screen: Market Share Analysis


Market-Based Rate Implementation Process

RTOs/ISOs

Balancing Authority

Areas

Pass

Fail

Keep MBR Authority

Rely on RTO Market

Monitoring and

Mitigation

Mitigation (Cost-based Rates)

Indicative Screens

Indicative Screens

Pass

Fail

Keep MBR Authority

Pass+

Fail DPT+


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.


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)


Sample DPT Results for DPT

Available Economic CapacityPivotal Supplier Test Market Share Test

Period Market Price

Applicant MW

Mkt Size

Rival Capacity

Wholesale Market Load

Pass Pivotal

Supplier?

Mkt Share

Pass Market Share Test? HHI

Pass HHI Test?

a b c d e f g h i j k S_SP1 100$ 1,900 8,000 6,100 6,400 Yes 24% No 2,700 NoS_SP2 50$ 1,500 7,900 6,400 6,320 Yes 19% Yes 2,600 NoS_P 40$ 1,500 6,000 4,500 4,800 Yes 25% No 2,100 YesS_OP 30$ 0 3,500 3,500 2,800 Yes 0% Yes 1,700 YesW_SP 40$ 1,800 7,500 5,700 6,000 Yes 24% No 2,000 YesW_P 30$ 1,400 6,000 4,600 4,800 Yes 23% No 1,800 YesW_OP 25$ 0 3,500 3,500 2,800 Yes 0% Yes 2,000 YesSH_SP 40$ 1,800 9,000 7,200 7,200 Yes 20% No 2,100 YesSH_P 30$ 0 7,500 7,500 6,000 Yes 0% Yes 1,800 YesSH_OP 25$ 0 3,500 3,500 2,800 Yes 0% Yes 2,000 YesWholesale market load is proxy from Indicative Screens Pivotal Supplier Test.

Economic Capacity

Pivotal Supplier Test Market Share Test

Period Market Price

Applicant MW

Mkt Size

Rival Capacity

Wholesale Market Load

Pass Pivotal

Supplier?

Mkt Share

Pass Market Share Test? HHI

Pass HHI Test?

a b c d e f g h i j k S_SP1 100$ 1,900 14,400 12,500 11,520 Yes 13% Yes 5,000 NoS_SP2 50$ 1,500 14,220 12,720 11,376 Yes 11% Yes 5,000 NoS_P 40$ 1,500 10,800 9,300 8,640 Yes 14% Yes 4,500 NoS_OP 30$ 0 8,000 8,000 6,400 Yes 0% Yes 4,800 NoW_SP 40$ 1,900 13,500 11,600 10,800 Yes 14% Yes 4,400 NoW_P 30$ 1,500 10,800 9,300 8,640 Yes 14% Yes 4,000 NoW_OP 25$ 0 8,000 8,000 6,400 Yes 0% Yes 3,000 NoSH_SP 40$ 1,900 16,200 14,300 12,960 Yes 12% Yes 4,000 NoSH_P 30$ 0 13,500 13,500 10,800 Yes 0% Yes 3,900 NoSH_OP 25$ 0 8,000 8,000 6,400 Yes 0% Yes 2,500 No

Market

Market


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

FERC Horizontal Analysis (continued)


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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

› Applicants can use default cost-based mitigation or propose tailored mitigation

› Some results for merchant generators are unexpected

KeyC O N T A C T S


KeyC O N T A C T S


KeyC O N T A C T S


KeyC O N T A C T S


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Julie R. Solomon| Managing [email protected] direct

E N E R G Y

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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

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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

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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 generation-owning 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: [email protected]; 202-626-6534Julie Solomon, Managing Director: [email protected]; 202-481-8492

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mailto:[email protected]

mailto:[email protected]

Documents

Market-Based Rates: Lessons from the Trenches EBA YLC Brown Bag Seminar April 23, 2013