Update on FERC, Legislation, and the Courts

Transcription

1 Update on FERC, Legislation, and the Courts WSPP Joint Committee Meeting Arnold Podgorsky and Patrick Morand February

2 Overview of the Legal Update FERC Updates Developments Initiatives Open Items Enforcement Legislative & Agency Updates Recent Court Decisions 2

3 FERC Recent Developments Allocation of Capacity on Merchant and Participant-Funded Transmission Projects Update on Order No Update on Complaint Against BPA 3

4 Allocation of Capacity on New Merchant Transmission Projects and New Cost-Based, Participant-Funded Transmission Projects (Docket No. AD ) FERC Staff will hold a workshop on February 28, 2012 to examine the process of allocating transmission capacity of new merchant transmission projects and new cost based, participant-funded projects. AD12-9 The purpose of the workshop is to obtain input on possible policy reforms, balancing open access principles with the needs of transmission developers to allocate capacity created by [these projects] What is this about? Most projects are not financeable until capacity is committed under precedent agreements BUT, the Commission balances the financing concern against open transmission goals. 4

5 Allocation of Capacity on New Transmission Projects (cont.) As to Merchant Transmission Projects Prior to 2009, FERC required that all merchant transmission capacity be allocated in an open season Now, FERC permits flexible capacity allocations on a case-by-case basis with some share of capacity allowed for prospective anchor customers and the remainder allocated in a subsequent open season. See, e.g., Chinook Power Transmission, LLC, 126 FERC 61,134 (2009) FERC imposed on the New Mexico SunZia project 50% anchor tenant and 50% open season 5

6 Allocation of Capacity on New Transmission Projects (cont.) FERC to consider for merchant transmission: Possibly reverting to only open seasons (no anchor) Allowing for distinctions among customers on objective criteria Possibly allowing 100% to a single customer Requiring any particular capacity size? Consideration of characteristics of an open season? Is current reporting requirement sufficient to assure the open season is open enough? 6

7 Allocation of Capacity on New Transmission Projects (cont.) FERC to consider for Cost-Based, Participant- Funded Transmission Projects (developer builds line for a pre-identified customer and recovers costs under a cost-based rate) FERC has not required open seasons FERC has not required an OATT Possible considerations for capacity allocations in future projects For incumbent utilities, would such projects be subject to service request rules in the OATT? For non-incumbents, should an open season as for merchant lines? 7

8 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC 61,051 (2011) On July 21, 2011, FERC issued Order No Order No became effective on October 11, Public utility transmission providers are required to make compliance filings by October 11, Various rehearings filed, now before the FERC 8

9 Iberdrola Renewables, Inc. et al. v. Bonneville Power Administration, 137 FERC 61,185 (2011) On December 7, 2011, FERC granted the petition filed by certain wind generators in the Pacific Northwest against Bonneville Power Administration ( BPA ), concerning BPA s curtailment of wind facilities for environmental reasons. BPA is not a public utility subject to FERC jurisdiction under 201, 205 or 206 of FPA (except for a limited refund obligation under 206 for sales at unjust/unreasonable rates BPA provides transmission that it does not require for its own power sales, and that would not conflict with BPA s marketing obligations BPA must maintain a reciprocity OATT, which currently is not compliant 9

10 Iberdrola Renewables, Inc. et al. v. Bonneville Power Administration, 137 FERC 61,185 (2011) BPA asserts that Environmental Redispatch (ER) is to assure compliance with environmental and other statutory responsibilities During ER, all customers receive scheduled energy, but from federal resources and not other generating resources, avoiding environmentally damaging spill; procedure is to issues dispatch orders to substitute its energy for the generation of others BPA will rediispatch thermal first and then variable; it redispatches to avoid paying negative prices arising from over generation BOA imposed the ER policy by unilateral amendment of LGIAs under asserted bases of reliability and other obligations 2/29/2012 Wright & Talisman, P.C. All rights reserved. 10

11 Iberdrola Renewables, Inc. et al. v. Bonneville Power Administration, 137 FERC 61,185 (2011) Petitioners argued BPA has fully protected its preference customers (receiving allocations of BPA power) and fully burdened its transmission interconnection customers; in violation of OATT and causes discrimination FERC has jurisdiction under FPA 211A, which allows FERC to require unregulated transmission utilities to provide open access to transmission similar to that required of jurisdictional utilities BPA argued that under the Northwest Project Act, challenges to the ER Policy are within exclusive jurisdiction of the Ninth Circuit US Court of Appeals 2/29/2012 Wright & Talisman, P.C. All rights reserved. 11

12 Iberdrola Renewables, Inc. et al. v. Bonneville Power Administration, 137 FERC 61,185 (2011) The FERC concluded It has authority under FPA 211A to require BPA to file an OATT providing for terms comparable to the terms that BPA provides for itself, without undue discrimination or preference. FERC, therefore, requires BPA to file a compliant tariff to govern future service Ninth circuit review of past actions does not restrict FERC from acting under 211A The ER policy is unduly discriminatory The LGIAs do not permit this unilateral modification BPA must file its revised OATT by March 6, /29/2012 Wright & Talisman, P.C. All rights reserved. 12

13 FERC Initiatives Order No. 745, Demand Response Compensation in Organized Wholesale Markets Order No. 755, Frequency Regulation Compensation in Organized Wholesale Markets 13

14 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, III FERC Stats. & Regs., Regs. Preambles 31,322, order on reh g, Order No. 745-A, 137 FERC 61,215 (2011) In Order No. 745, FERC amended its regulations to require RTOs and ISOs to pay demand response resources participating in day-ahead and real-time energy markets the market price for energy (i.e., LMP) where: the demand response resource has the capability to balance supply and demand as an alternative to a generation resource; and when dispatch of that demand response resource is costeffective as determined by a net benefits test. 14

15 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745 (cont.) The RTOs/ISOs must allocate the costs associated with demand response compensation proportionally to all entities in the relevant energy market. On December 15, 2011, FERC denied rehearing of Order No. 745, but granted clarification in part regarding certain provisions: specifically, FERC clarified that RTOs/ISOs must pay all demand response resources that qualify for compensation the LMP when the LMP is equal to or greater than the threshold price; and if the LMP is less than the threshold price, the regulation set forth in Order No. 745 does not apply instead, the payment will be determined by the existing RTO/ISO tariff. 15

16 Frequency Regulation Compensation in the Organized Wholesale Power Markets, Order No. 755, 137 FERC 61,064 (2011), reh g denied, Order No. 755-A, 138 FERC 61,123 (2012) Order No. 755 requires RTOs/ISOs to compensate frequency regulation resources based on the actual service provided, including: a capacity payment that includes the marginal unit s opportunity costs; and a payment for performance that reflects the quantity of frequency regulation service provided by the resource when it is accurately following the dispatch signal. Frequency regulation service is the injection or withdrawal of power by facilities capable of responding to transmission system operators automatic generation control ( AGC ) signals; it is not the same as frequency response which involves the automatic, autonomous and rapid action of turbine governor controls to change a generator s output or a demand response resource s consumption. 16

17 Frequency Regulation Compensation in the Organized Wholesale Power Markets, Order No. 755 (cont.) FERC explained that the market rules of RTOs/ISOs for frequency regulation services were unduly discriminatory because resources were being compensated at the same level regardless of the amount of frequency regulation service they provided. On February 16, 2012, FERC denied a request for rehearing on two discrete issues: FERC rejected a request that the rule not apply to performance payments made where a resource s limitations cause the RTO/ISO to issue a dispatch instruction that is against its overall area control error ( ACE ); i.e., FERC specifically declined to tie the performance payment to a resource s ACE correction. FERC also rejected a request to find that the phrase uniform payment to all cleared resources means that all cleared resources in the same zone or pricing region should receive the same payment; rather each RTO/ISO should determine how it will apply the requisite uniform payment in its particular pricing regions. 17

18 FERC Open Items Variable Energy Resources NOPR (Docket No. RM ) Third-Party Ancillary Services NOI (Docket No. RM ) Transmission Incentives NOI (Docket No. RM ) 18

19 Integration of Variable Energy Resources, Notice of Proposed Rulemaking, 133 FERC 61,149 (2010) On November 18, 2010, FERC issued the VER NOPR in which it proposed to amend the pro forma OATT as follows: to require intra-hourly transmission scheduling; to incorporate into the LGIA provisions requiring meteorological and operational data from VERs in order to provide for improved power production forecasting; and to add a generic ancillary service rate schedule requiring transmission providers to provide generator regulation service for the delivery of energy from a generator located within the transmission provider s balancing authority area (proposed Schedule 10). Comments were due on March 2, FERC has taken no action since receiving comments. 19

20 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Notice of Inquiry, IV FERC Stats. & Regs., Notices 35,573 (2011) On June 16, 2011, FERC issued the Third-Party Ancillary Services NOI in which it recognized the growing interest in rate flexibility for ancillary services and that resources capable of providing ancillary services may be frustrated by the Avista restriction prohibiting third-party market-based sales of ancillary services to transmission providers seeking to meet their ancillary service obligations under their OATTs, absent a market power study. Comments were due on August 22, FERC has taken no action since receiving comments, but Staff indicates that an order will be issued soon. 20

21 Promoting Transmission Investment Through Pricing Reform, Notice of Inquiry, 135 FERC 61,146 (2011). On May 19, 2011, FERC issued the Transmission Incentives NOI in which it sought comment on whether the transmission incentives set forth in Order No. 679 encourage the development of transmission infrastructure consistent with FPA sections 219 and 205 and 206. The Commission posed a number of overarching questions about its incentives policies under Order No. 679, including: the statutory threshold and other goals under FPA section 219; the nexus test; the interrelationship of requested incentives; the role of cost estimates; and questions about the individual incentives themselves. Comments were due on September 12, FERC has taken no action since receiving comments and, notably, in two recent orders on transmission rate incentives refused to stay the proceedings pending outcome of the NOI. See MidAmerican Energy Co., 137 FERC 61,250, at P 17 & n.37 (2011); Otter Tail Power Co., 137 FERC 61,255, at P 20 & n.24 (2011). 21

22 FERC Enforcement In re Holyoke Gas and Electric Department, 137 FERC 61,159 (2011) In re Joseph Polidoro, 138 FERC 61,018 (2012) PacifiCorp, 137 FERC 61,176 (2011) In re Xcel Energy Inc., 138 FERC 61,026 (2012) 22

23 In re Holyoke Gas and Electric Department, 137 FERC 61,159 (2011) Holyoke Gas and Electric Department ( Holyoke ) registered two of its units as capacity resources in the ISO New England capacity market, and each month Holyoke received a capacity payment for each unit. Holyoke experienced three outages involving the two units, but never notified ISO New England of the outages or scheduled them as required by the ISO New England tariff. Instead, Holyoke offered the units into the day-ahead and real-time markets and when ISO New England sought to dispatch an out-of-service unit, Holyoke responded by placing the unit on forced outage status. 23

24 In re Holyoke Gas and Electric Department, 137 FERC 61,159 (2011) (cont.) Nonetheless, Holyoke continued to receive capacity payments during the three outages totaling $336,267. ISO New England s market monitor referred one outage, and Holyoke subsequently self-reported the other two outages, to FERC s Office of Enforcement. Enforcement found Holyoke s actions to have violated FERC s anti-market manipulation regulations (18 C.F.R. 1c.2) and, as part of its settlement, required Holyoke to disgorge the $336,267 plus interest and to make certain compliance reports to Enforcement. 24

25 In re Joseph Polidoro, 138 FERC 61,018 (2012) Mr. Joseph Polidoro was a founding partner of North American Power Partners ( NAPP ) and had been involved in developing the PJM Interconnection, L.L.C. ( PJM ) demand response programs while previously employed by PJM. In a prior proceeding, Enforcement found that certain NAPP conduct in the PJM demand response programs violated FERC s anti-market manipulation regulations (18 C.F.R. 1c.2) and, pursuant to a settlement, NAPP agreed to pay a civil penalty of $500,000, to disgorge $2,258,127 plus interest, and to undertake compliance monitoring. Enforcement subsequently investigated Mr. Polidoro regarding his role in NAPP s violations of PJM s demand response programs. 25

26 In re Joseph Polidoro, 138 FERC 61,018 (2012) (cont.) Enforcement found that Mr. Polidoro personally submitted offers on behalf of resources at times when he knew the resources were unavailable to respond; was responsible for NAPP s failure to submit required meter data to PJM; and had directed NAPP employees to register over 100 resources before obtaining their authorization or verification of their willingness and ability to participate in a particular PJM demand response program. Enforcement found that Mr. Polidoro s conduct violated FERC s antimarket manipulation regulations and, pursuant to a settlement with Enforcement, Mr. Polidoro agreed to pay a civil penalty of $50,000 and to accept a two-year ban from participating in any PJM demand response activities. Enforcement considered Mr. Polidoro s limited financial circumstances and noted that it would have sought a significantly higher penalty for similar conduct. 26

27 PacifiCorp, 137 FERC 61,176 (2011) On February 14, 2008, PacifiCorp experienced a fault in one of its transformers at a generating plant in Utah. The fault triggered a series of events that eventually led to PacifiCorp shedding 183 MW of firm load, resulting in 74,000 customers losing power for about 25 minutes. Enforcement initiated an investigation into the cause of the outage, and, because PacifiCorp serves as a Balance Authority and Transmission Operator, NERC initiated an investigation to determine whether any Reliability Standards had been violated. 27

28 PacifiCorp, 137 FERC 61,176 (2011) (cont.) Enforcement and NERC coordinated their investigations and ultimately determined that PacifiCorp had violated 23 different Requirements of 15 Reliability Standards. Consideration was given to the serious nature of the outage, the harm caused by the firm load shedding, and the risk of harm posed to the Western Interconnection, as well as the remedial efforts made by PacifiCorp. PacifiCorp agreed to a civil penalty of $3,925,000, to be apportioned and paid equally between the United States Treasury and NERC. In addition, PacifiCorp agreed to improve its training and procedures and to make certain compliance reports to Enforcement. 28

29 In re Xcel Energy Inc., 138 FERC 61,026 (2012) From the time the Lamar Tie Line came online in 2005, Public Service Company of Colorado ( PSCo ) and Southwestern Public Service Company ( SPS ), interconnected subsidiaries of Xcel Energy Inc. ( Xcel ), reserved the full capacity of the tie line through long-term firm network transmission service reservations. In 2007, PSCo and SPS executed with one another network integration transmission service agreements, which provided for compensation between the two companies for service across the line. SPS is a member of SPP. During the relevant period, neither Schedule E of Xcel s Joint Operating Agreement (governing capacity and energy exchanges across the tie line) nor the network integration transmission service agreements between PSCo and SPS were listed as grandfathered agreements in the SPP OATT. 29

30 In re Xcel Energy Inc., 138 FERC 61,026 (2012) (cont.) Enforcement found that Xcel violated the Xcel OATT and the SPP OATT because it used firm network integration transmission service between PSCo and SPS when those transactions were not eligible to use that service. Enforcement explained that the resources used in the transactions between PSCo and SPS did not qualify as designated network resources and that the load to be served by them did not qualify as designated network load. Enforcement concluded that PSCo and SPS should have used point-to-point service instead of network integration transmission service, and that PSCo should have sought point-to-point service from SPP using its OASIS. Xcel agreed to pay a civil penalty of $2,000,000 for the violations and to make certain compliance reports to Enforcement. 30

31 Legislative & Agency Updates Dodd-Frank Act EPA Rules California Cap & Trade California RPS 31

32 Dodd-Frank Act The CFTC has yet to issue many of the final rules and interpretive orders related to the Dodd-Frank Act. On December 23, 2011, the CFTC issued an order extending the deadline for issuing those final rules and interpretive orders until July 16, The CFTC website indicates that it tentatively plans to issue the final rules for the End-User Exception and for Product Definitions, two areas of particular concern to the energy industry, by March

33 EPA Rules Mercury and Air Toxics Standards ( MATS ) Final Rule MATS sets standards for emissions of mercury and other heavy metals from coal-fired and oil-fired electric generating units ( EGUs ) with a capacity of 25 MW or greater. Existing EGUs will have 3 years to comply per the Clean Air Act; state authorities may provide 1 additional year for compliance. Mercury and Air Toxics Standards, 77 Fed. Reg. 9,304 (Feb. 16, 2012) (to be codified at 40 C.F.R. pts. 60 & 63) 33

34 EPA Rules (cont.) MATS Final Rule (cont.) In addition, owners/operators can seek an administrative order permitting their noncompliance for 1 additional year where compliance could affect reliability due to deactivation of EGUs or delays in their operation caused by the installation of controls. The EPA will seek advice, on a case-by-case basis, from FERC and/or other entities with reliability expertise. Approval of an administrative order, however, will not depend on the findings of FERC or the entities. 34

35 California Cap & Trade On October 20, 2011, the California Air Resources Board ( CARB ) approved regulations to adopt a cap and trade program to regulate green house gas ( GHG ) emissions. The program sets a limit on GHGs from major emissions sources ( Covered Entities ), and permits the Covered Entities to purchase allowances at auction or from others, and to purchase offsets. The GHGs regulated by the program include carbon dioxide (CO 2 ) and other emissions, which are measured in metric tons of carbon dioxide equivalent ( MTCO 2 e ). 35

36 California Cap & Trade (cont.) The program went into effect on January 1, 2012, with the first phase requiring Covered Entities, which include electricity generation and imports, and large industrial entities with GHG emissions of 25,000 MTCO 2 e or more, to register with CARB by January 31, CARB initially will distribute the allowances at no cost to the Covered Entities, and the total number of allowances will equal the aggregate cap on all emissions. Compliance will begin on January 1, 2013, with the cap declining from 2013 through In 2015, the cap will be expanded to include GHG emissions from fuel suppliers. The cap then will continue to decline from 2015 to 2020 with the objective of reducing GHG emissions to 1990 levels by

37 California RPS California Renewable Energy Resources Act, Senate Bill X1-2 (1st extraordinary session) ( SB 2 ) SB 2, which went into effect on December 10, 2011, increases California s RPS requirements to 33% by 2020; in other words, by 2020, 33% of retail sales by investor-owned utilities, electric service providers, community choice aggregators, and publicly-owned utilities must come from eligible renewable resources. The California Public Utilities Commission ( CPUC ) has issued two significant orders implementing SB 2 to date. 37

38 California RPS (cont.) CPUC issued Decision No (Dec. 5, 2011) to set the procurement quantities for retail sellers in the periods up to 2020: for the period , each retail seller must procure an average of 20% of its retail sales from eligible renewable resources; for 2014, the requirement increases to 21.7%; for 2015, it increases to 23.3%; for 2016, it increases to 25%; for 2017, it increases to 27%; for 2018, it increases to 29%; for 2019, it increases to 31%; and for 2020, the requirement increases to 33%. 38

39 California RPS (cont.) CPUC issued Decision No (Dec. 20, 2011) to establish 3 portfolio content categories for RPS-eligible generation: 1. Eligible renewable energy resource electricity products that (a) have a first point of interconnection with a California balancing authority; (b) have a first point of interconnection with distribution facilities that serve end-users within a California balancing authority; (c) are scheduled into a California balancing authority without substituting electricity from another source; or (d) have an agreement to dynamically transfer electricity to a California balancing authority. 2. Firmed and shaped eligible renewable energy resource electricity products scheduled into a California balancing authority. 3. Unbundled renewable energy credits. 39

40 California RPS (cont.) Decision No also set minimum and maximum amounts that may be used from the 3 portfolio content categories over three compliance periods; by 2017: a minimum of 75% from Category 1 products; a maximum of 10% from Category 3 products; and the remainder, if any, from Category 2 products. On February 1, 2012, the CPUC sought comments to address RPS reporting requirements, the relationship between the requirements of Decision No and Decision No , and rules previously issued prohibiting the unbundling of RECs. Comments were due on February 10, 2012, and reply comments were due on February 21,

41 Recent Court Decisions Alabama Municipal Electric Authority v. FERC, 662 F.3d 571 (D.C. Cir. 2011) PSEG Energy Resources & Trade LLC v. FERC, No , 2011 U.S. App. LEXIS (D.C. Cir. Dec. 23, 2011) Indiana Utility Regulatory Commission v. FERC, No , 2012 U.S. App. LEXIS 918 (D.C. Cir. Jan. 17, 2012) 41

42 Alabama Municipal Electric Authority v. FERC, 662 F.3d 571 (D.C. Cir. 2011) Alabama Municipal Electric Authority alleged that the rate it paid Southern Company for unbundled transmission service provided by one of Southern s subsidiaries, Alabama Power Company, violated FERC s comparability standard because it was higher than the rate Southern charged itself for its bundled retail sales using the Alabama component of its transmission system. The comparability standard, or golden rule of pricing, provides that a transmission owner should charge itself on the same or comparable basis that it charges others for the same service. FERC argued, and the court agreed, that unbundled transmission service and the transmission component of bundled retail sales are not the same service because, if not for any other reason, the former is jurisdictional and the latter is not. 42

43 PSEG Energy Resources & Trade LLC v. FERC, No , 2011 U.S. App. LEXIS (D.C. Cir. Dec. 23, 2011) PSEG Energy Resources & Trade LLC ( PSEG ) challenged FERC orders accepting results of an ISO New England capacity auction. The ISO New England capacity auction is a descending auction in which the ISO announces a starting price, and suppliers respond with bids for how much capacity they are willing to provide at that price; then the price is gradually reduced, and the suppliers reduce their capacity bids accordingly, until the bids equal the amount of capacity required to maintain reliability (the installed capacity requirement or ICR ). The capacity auction has a price floor that stops the auction when reached. A problem arises when the price floor is reached at a point where capacity bids exceed the ICR (i.e., purchasers would end up buying too much power). At this point, each supplier has its capacity obligation, and the payment it receives, reduced proportionally, subject to reliability review. 43

44 PSEG Energy Resources & Trade LLC v. FERC, No , 2011 U.S. App. LEXIS (D.C. Cir. Dec. 23, 2011) (cont.) ISO New England s reliability review resulted in it not reducing PSEG s capacity obligation, but nonetheless reducing proportionally the payment PSEG received. PSEG argued that the tariff provision regarding the proportional reduction of capacity obligations and payments after a reliability review was ambiguous because it also could be read to mean that both capacity obligations and payments must be reduced (not just the payments, as ISO New England had interpreted it). FERC held that the tariff was unambiguous and that ISO New England s action was consistent with its tariff. But FERC later acknowledged in a subsequent proceeding and in oral argument before the court that the tariff language was ambiguous and that the outcome was problematic. Consequently, the court remanded the matter back to FERC for further proceedings. 44

45 Indiana Utility Regulatory Commission v. FERC, No , 2012 U.S. App. LEXIS 918 (D.C. Cir. Jan. 17, 2012) Indiana Utility Regulatory Commission ( IURC ) challenged a FERC order approving a PJM Interconnection, L.L.C. ( PJM ) tariff revision made pursuant to Order No. 719 on jurisdictional grounds and as unreasoned decision-making. Order No. 719 requires operators of wholesale electricity markets to allow trading in retail as well as wholesale Demand Response by granting access to third-party aggregators of retail customers or ARCs, except where prohibited by state regulators. The PJM tariff revision permitted its members to act as an ARC, and required the ARC s customers (i.e., retail utilities), and not the ARC itself, to confirm whether the individual retail customers are eligible to participate in the demand response program. 45

46 Indiana Utility Regulatory Commission v. FERC, No , 2012 U.S. App. LEXIS 918 (D.C. Cir. Jan. 17, 2012) (cont.) IURC argued that the burden for confirming a customer s eligibility should be on the ARC and not on the retail utility. Order No. 719 did not specify who should bear this responsibility, but instead allowed for flexibility. The court dismissed IURC s jurisdictional challenges because they were not raised in its rehearing request, and dismissed its challenge on the merits, finding that, given the flexibility in Order No. 719, FERC s approval of PJM s tariff revision was reasonable. 46

47 Contact For more information, please contact: Arnold Podgorsky, Managing Shareholder Patrick Morand, Associate