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FERC’s April 14 Orders on Market Power

FERC’s Recent Orders on Market Power in Wholesale Electric Markets Stephen P. Rodgers, Director, Division of Tariffs and Rates South Office of Markets, Tariffs & Rates Federal Energy Regulatory Commission. FERC’s April 14 Orders on Market Power.

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FERC’s April 14 Orders on Market Power

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  1. FERC’s Recent Orders on Market Power in Wholesale Electric MarketsStephen P. Rodgers, Director, Division of Tariffs and Rates SouthOffice of Markets, Tariffs & RatesFederal Energy Regulatory Commission

  2. FERC’s April 14 Orders on Market Power • One order established new interim generation market power screens and mitigation • A second order initiated a new generic rulemaking proceeding on all aspects of market-based rate (MBR) authorizations

  3. High Level Overview n  SMA test replaced by two interim screens that are indicative of generation market power (MP) n  If applicant passes both screens, presumption of no MP, but interveners can provide evidence to disprove n  If applicant fails either screen, presumption of MP, but applicant can provide evidence to disprove n  If applicant found to have MP, it can offer mitigation or cost-based rates

  4. Indicative Screen #1: Uncommitted Pivotal Supplier nMeasures applicant’s ability to exercise MP at time of the annual peak nScreen is adept at measuring MP exercised unilaterally, in spot markets, and at peak n  Recognizes applicant’s commitments to native load, operating reserves and long-term firm wholesale sales. nDeduction for native load is based on the average of the daily native load peaks during the peak month

  5. Indicative Screen #2: Uncommitted Market Share nMeasures the potential of an applicant to exercise MP in all four seasons nScreen is adept at measuring if applicant is dominant, MP at both peak and off-peak, and the potential for coordinated interaction n  Screen recognizes applicant’s commitments to native load, operating reserves, long-term firm wholesale sales, and planned outages nApplicant passes the screen if its market share of uncommitted capacity less than 20%

  6. What happens if applicant passes both screens? nRebuttable presumption applicant doesn’t have MP . . . n. . . but interveners can present evidence to disprove (including historical sales data, and evidence that competing suppliers can’t access the market) nIf no evidence to rebut the presumption, then applicant obtains/retains its MBR

  7. What happens if applicant fails either screen? nRebuttable presumption applicant has MP n. . . but applicant can either present evidence to disprove (including historical sales data and the Delivered Price Test), OR n. . . applicant can propose mitigation to eliminate its ability to exercise MP. nApplicant passes DPT if HHI is under 2500 nIf applicant found to have MP, its denied MBR in all geographical markets where it has MP

  8. Cost-based rate mitigation nIf applicant is denied MBR, it must use cost-based rates – either default or an applicant proposal approved by FERC. nThree types of default cost-based rates, based on length of sale: 1.Incremental plus 10% for sales of one week or less

  9. Cost-based rate mitigation (con’t) 2.Embedded cost “up to” rates based on cost of the unit(s) involved for sales more than one week and less than one year 3. Rates not-to-exceed embedded cost of service for sales of one year or more – and contract must be approved by FERC before transacting

  10. Relevant Geographic Market nDefault markets are any control areas where applicant has generation, plus each first-tier market nApplicant/interveners can provide evidence to show actual relevant market is smaller or larger than the control area nFlexibility to recognize evidence of load pockets 

  11. Transmission limitations nTotal Transfer Capability (TTC) used under SMA is abandoned for simultaneous transmission import capability nTTC unrealistic because its not possible for that amount of generation to be imported at once nThe simultaneous transmission import capability should also reflect limits such as stability, voltage, CBM and TRM

  12. Historical data nHistorical data used because its more objective, readily available and less subject to manipulation than projections nApplicant must use most recent 12 months’ historical data nA “snapshot in time” approach

  13. No RTO/ISO exemption. However, . . . nApplicants can incorporate the mitigation they’re subject to in RTO/ISO as part of their MP analysis nApplicants located in RTOs/ISOs with sufficient market structure and a single energy market may regard entire footprint of the RTO/ISO as the relevant market nThose with such markets now are ISO-NE, NYISO, PJM, and CAISO

  14. No “safe harbor” size exemption However . . . Any applicant can submit a streamlined application or simplifying assumptions, where appropriate (e.g., if you pass even without allowing competing imports, then no need to consider such imports)

  15. Recognition of hydro and Western issues nApplicants can de-rate their hydro capacity (because such plants are energy limited) nThose de-rating must use a 5-year average capacity factor and a sensitivity test using the lowest capacity factor in the last 5 years nRecognition that the West may have larger regional markets than typical, and applicants can present evidence to that effect – interveners can challenge.

  16. Revocation of mitigation that had been ordered under SMA nNo requirement to post incremental or decremental costs nNo “must offer” requirement of uncommitted capacity nNo mandatory purchase requirement nNo requirement for independent OASIS administration  nBut, these issues may be addressed in other proceedings

  17. Native load protections nRecognition given to utility commitments to native load and operating reserves nEnsures that utilities will not be overcharged when they purchase power in wholesale markets nProvides greater transparency into how utilities with MP derive rates, so state regulators can be sure retail customers are getting fare share of revenue credits from wholesale sales

  18. Implementation process nAEP, Southern Company and Entergy have 60 days to file revised market power studies nFERC will issue subsequent orders on those filings nA screen failure would . . . ocreate rebuttable presumption of MP, oinitiate a FERC 206 investigation, and omake market-based rates subject to refund

  19. Implementation process (con’t) nBut . . . refunds would only be due if FERC ultimately found MP in a later order (i.e., after reviewing applicant’s DPT and/or mitigation proposal) nFERC will apply these same procedures to other pending MBR filings – a later order will provide details

  20. New generic rulemaking case on MBR (Docket No. RM04-7) nWill address adequacy of FERC’s current 4-part test for granting MBR: generation, transmission, barriers to entry and affiliate abuse nNeeded since much has changed in industry in 15 years, and there are no comprehensive codified regulations for obtaining MBR nWill examine issues on vertical market power and ancillary services

  21. New generic rulemaking case on MBR (con’t) nKick-off technical conference on June 9 nStaff proposed another technical conference soon on competitive solicitation processes

  22. Summary nNew MP screens reflect lots of due process: rehearing requests, 3 rounds of comments, a staff policy paper and a 2-day technical conference nMany procedural options ahead for applicants and interveners, with symmetrical rights and opportunities for each to make their case nBalances regulatory certainty with flexibility for those seeking MBR authority nMore to come through the new generic rulemaking proceeding

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