Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators; Notice Inviting Post-Technical Workshop Comments, 3580-3583 [2015-01139]

Download as PDF 3580 Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices Dated: January 15, 2015. Kimberly D. Bose, Secretary. [FR Doc. 2015–01043 Filed 1–22–15; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Project No. 14640–000] tkelley on DSK3SPTVN1PROD with NOTICES South Maui Pumped Storage, LLC; Notice of Preliminary Permit Application Accepted for Filing and Soliciting Comments, Motions To Intervene, and Competing Applications On October 20, 2014, South Maui Pumped Storage, LLC, filed an application for a preliminary permit, pursuant to section 4(f) of the Federal Power Act (FPA), proposing to study the feasibility of the South Maui Pumped Storage Project (South Maui Project or project) to be located on the Pacific Ocean, in unincorporated Maui County, Hawaii. The sole purpose of a preliminary permit, if issued, is to grant the permit holder priority to file a license application during the permit term. A preliminary permit does not authorize the permit holder to perform any land-disturbing activities or otherwise enter upon lands or waters owned by others without the owners’ express permission. The proposed project would consist of the following new features: (1) Four 400-foot-long, 200-foot-wide, 50-foothigh oval concrete storage tanks; (2) a 12,000-foot-long, 4.5-foot-diameter buried steel penstock; (3) a 150-footlong, 68-foot-wide concrete powerhouse; (4) two 15 megawatt (MW) Pelton turbine/generators; (5) three 10 MW multi-stage variable speed pumps; (6) an approximately 400-foot-wide, 450-foot-long tailrace/forebay; 1 (7) a 12,000-foot-long, 4.5-foot-diameter buried steel supply pipeline; (8) two 28kilovolt transmission lines totaling 8,000 feet long, interconnecting with the existing Sempra Gas and Power-owned Auwahi wind turbine transmission line; (9) a 5.6-mile-long paved access road; and (10) appurtenant facilities. The estimated annual generation of the South Maui Project would be 5.2 gigawatt-hours. Applicant Contact: Mr. Bart O’Keefe, United Power Corporation, P.O. Box 1 The tailrace/forebay would be a small constructed inlet from the Pacific Ocean. Flows from the turbines would discharge into the tailrace/ forebay. Return flows for filling of the storage tanks would be pumped from the tailrace/forebay. VerDate Sep<11>2014 18:05 Jan 22, 2015 Jkt 235001 1916, Discovery Bay, California 94505; phone: (510) 634–1550. FERC Contact: Sean O’Neill; phone: (202) 502–6462. Deadline for filing comments, motions to intervene, competing applications (without notices of intent), or notices of intent to file competing applications: 60 days from the issuance of this notice. Competing applications and notices of intent must meet the requirements of 18 CFR 4.36. The Commission strongly encourages electronic filing. Please file comments, motions to intervene, notices of intent, and competing applications using the Commission’s eFiling system at https:// www.ferc.gov/docs-filing/efiling.asp. Commenters can submit brief comments up to 6,000 characters, without prior registration, using the eComment system at https://www.ferc.gov/docs-filing/ ecomment.asp. You must include your name and contact information at the end of your comments. For assistance, please contact FERC Online Support at FERCOnlineSupport@ferc.gov, (866) 208–3676 (toll free), or (202) 502–8659 (TTY). In lieu of electronic filing, please send a paper copy to: Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426. The first page of any filing should include docket number P–14640–000. More information about this project, including a copy of the application, can be viewed or printed on the ‘‘eLibrary’’ link of Commission’s Web site at https://www.ferc.gov/docs-filing/ elibrary.asp. Enter the docket number (P–14640) in the docket number field to access the document. For assistance, contact FERC Online Support. Dated: January 16, 2015. Kimberly D. Bose, Secretary. [FR Doc. 2015–01140 Filed 1–22–15; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Docket No. AD14–14–000] Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators; Notice Inviting Post-Technical Workshop Comments On September 8, October 28, and December 9, 2014, the Federal Energy Regulatory Commission (Commission) staff conducted a series of technical workshops to evaluate issues regarding PO 00000 Frm 00034 Fmt 4703 Sfmt 4703 price formation in the energy and ancillary services markets operated by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) (RTOs/ISOs). All interested persons are invited to file post-technical workshop comments on any or all of the questions listed in the attachment to this Notice. We emphasize that commenters need not answer all of the questions. Commenters should organize responses consistent with the structure of the attached questions and take care to identify to which RTO/ISO the comment applies. Commenters are also invited to reference material previously filed in this docket, including technical workshop transcripts. These comments must be filed with the Commission no later than 5:00 p.m. Eastern Standard Time on February 19, 2015. For more information about this Notice, please contact: Mary Wierzbicki (Technical Information), Office of Energy Policy and Information, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502–6337, mary.wierzbicki@ ferc.gov. Joshua Kirstein (Legal Information), Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502– 8519, joshua.kirstein@ferc.gov. Dated: January 16, 2015. Kimberly D. Bose, Secretary. Post-Technical Conference Questions for Comment The goals of proper price formation are to: Maximize market surplus for consumers and suppliers; provide correct incentives for parties to follow commitment and dispatch instructions, make efficient investments in facilities and equipment, and maintain reliability; provide transparency so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system; and ensure that all suppliers have an opportunity to recover their costs. With proper price formation, the RTO/ISO would ideally not need to commit any additional resources beyond those resources scheduled economically through the market processes, and load would reduce consumption in response to price signals such that market prices would reflect the value of electricity consumption without the need to curtail load administratively. E:\FR\FM\23JAN1.SGM 23JAN1 Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices In reality, RTO/ISO energy and ancillary services market outcomes are impacted by a number of technical and operational considerations.1 At three workshops on price formation—Uplift Workshop, held September 8, 2014 (Uplift Workshop); Shortage Pricing, Offer Price Mitigation, and Offer Price Caps Workshop, held October 28, 2014 (Shortage Pricing/Mitigation Workshop); and Operator Actions Workshop, held December 9, 2014 (Operator Actions Workshop)—panelists described software limitations, operational uncertainty, and limited flexibility of resources as challenges to achieving efficient price formation. These limitations are to some extent inherent in the complexity of the electric system and the tools available today to maintain reliable operations, and are unlikely to be addressed fully for the foreseeable future.2 Notwithstanding the foregoing technical limitations and operational realities, the Commission believes there may be opportunities for RTOs/ISOs to improve the energy and ancillary service price formation process. Based on discussions during the three price formation workshops, Staff developed the following questions to better understand the ways in which to improve price formation in RTOs/ISOs. When responding to the questions below, please also comment on any relevant differences among RTOs/ISOs, the time needed to implement any potential solutions, and impediments to implementing any potential solutions. 1. Offer Caps High natural gas prices during the winter of 2013–2014, as discussed at the price formation workshops, indicated that the current generic $1,000/MWh cap on energy offers (‘‘offer cap’’) might be insufficient to allow natural gas-fired generators to recover their costs when natural gas prices spike during constrained winter periods. a. Should the $1,000/MWh offer cap be modified? i. If the offer cap is modified, what form should the offer cap take? For instance, should a modified cap be set at a level greater than the current $1,000/MWh cap and apply even if a tkelley on DSK3SPTVN1PROD with NOTICES 1 Although the discussion herein focuses on RTO/ ISO markets, similar technical and operational limitations impact the efficient commitment of resources by electric utilities operating in other market structures, such as vertically integrated utilities. 2 Other efforts, like Staff’s annual meeting with RTO/ISO operations staff and the annual market software conference, are intended to make progress on these longer term issues. See https:// www.ferc.gov/industries/electric/indus-act/marketplanning.asp. VerDate Sep<11>2014 18:05 Jan 22, 2015 Jkt 235001 resource has costs greater than the new cap or should the offer cap be replaced with a structure that allows offers at the higher of marginal cost or the existing $1,000/MWh cap? Should it be a fixed cap or a floating cap that varies with the price of fuel (e.g., natural gas)? If a modified cap were set as a fixed offer cap, what should the new offer cap be? What should be the basis for determining the fixed offer cap? ii. If the offer cap should not be modified or set such that marginal costs could be greater than $1000/MWh, how should the Commission ensure that suppliers with costs greater than the cap have the opportunity to recover those costs? iii. Do the real-time and day-ahead market clearing processes allow sufficient time to verify the cost-basis of the marginal resources that exceed the offer cap? Does the settlement process allow sufficient time to verify costs of resources that receive uplift associated with offers that exceed the offer cap? b. What are the advantages and disadvantages of having offer caps be set at the same level across all RTOs/ISOs? Would different offer caps across the RTOs/ISOs exacerbate interface pricing issues at RTO/ISO borders? If so, how? Would an offer cap that takes the form of the higher of marginal cost or $1,000/ MWh create the same issues as setting different offer caps across RTOs/ISOs? c. What impact would adjusting the offer cap have on other aspects of RTO/ ISO price formation (e.g., mitigation rules or shortage pricing rules)? Would other market rule changes be necessary if offer cap levels were adjusted? Do other challenges associated with modifying offer cap rules exist? If so, what are they? If offer cap rules are adjusted, how quickly could RTOs/ISOs incorporate adjusted offer cap rules into their software and the market clearing process? d. Should the same offer cap that applies to generation also apply to load bids? What are the advantages and disadvantages of applying an offer cap to load bids? 2. Transparency At the Uplift and Operator Actions Workshops, some panelists addressed issues concerning insufficient transparency of uplift and operator actions.3 Improved transparency could 3 See, e.g., Operator Actions Workshop, Docket No. AD14–14–000, Tr. 180:8–183:4 (Dec. 9, 2014); Uplift Workshop, Docket No. AD14–14–000, Tr. 168:1–16 (Sept. 8, 2014). For this purpose we are defining uplift credits as payments made to resources whose commitment and dispatch by an RTO/ISO result in a shortfall between the resource’s offer and the revenue earned through market clearing prices. PO 00000 Frm 00035 Fmt 4703 Sfmt 4703 3581 inform resource entry and exit and market rule discussions; improved transparency could also improve market understanding, predictability, and confidence. a. What should RTOs/ISOs do to improve transparency of uplift credits and charges, unit commitment, and other operator actions? Please comment on the type of information that would be useful, why it is necessary, whether it should be shared with specific resources or available to all, the timing of its release, and whether it is feasible to release the information in real-time. b. What types of information should not be shared publicly? Why? What are the concerns with commercially sensitive information? c. Commission Staff’s August 2014 report on uplift noted several issues with the consistency and granularity of uplift data provided as part of the Electric Quarterly Reports.4 What steps could be taken to improve the quality of uplift data required to be reported as part of the Electric Quarterly Reports? 3. Pricing Fast-Start Resources Commission Staff’s December 2014 paper about operator-initiated commitments discussed how RTOs/ ISOs relax the minimum operating level of resources to make certain blockloaded fast-start resources appear dispatchable to the pricing software, and thus eligible to set the market clearing price as the marginal resource.5 The paper also discussed how some RTOs/ISOs have modified the locational marginal price (LMP) framework to include start-up and no-load costs of certain fast start resources (e.g., New York Independent System Operator, Inc.’s (NYISO’s) Hybrid Pricing).6 a. During the Operator Actions Workshop, panelists explained that relaxing resource minimum operating limits can lead to incentive and operational issues such as overgeneration.7 What tradeoffs are involved with relaxing the minimum operating limits of block-loaded resources to zero for purposes of price setting? Should relaxing the minimum operating level be limited to block-loaded fast-start 4 FERC, Staff Analysis of Uplift in RTO and ISO Markets, Docket No. AD14–14–000, at 21–28 (Aug. 2014), available at https://www.ferc.gov/legal/staffreports/2014/08-13-14-uplift.pdf. 5 FERC, Price Formation in Organized Wholesale Electricity Markets: Staff Analysis of OperatorInitiated Commitments in RTO and ISO Markets, Docket No. AD14–14–000, at 28–30 (Dec. 2014), available at https://www.ferc.gov/legal/staff-reports/ 2014/AD14-14-operator-actions.pdf. 6 Id. 7 Operator Actions Workshop, Docket No. AD14– 14–000, Tr. 282:9–25 (Dec. 9, 2014). E:\FR\FM\23JAN1.SGM 23JAN1 3582 Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices resources, or should relaxation be available to a larger set of resources? b. What are the merits of expanding the set of costs included in the energy component of LMP (i.e., start-up and noload costs)? What factors should be considered when expanding the set of costs included in the energy component of LMP? If the start-up and no-load costs of block-loaded fast-start resources are included in the LMP, how should they be included? For example, should startup costs only be included during intervals when the resource starts up? c. Should off-line resources be eligible to set the LMP? If so, should start-up and no-load costs be included in the price, or just incremental energy costs? 4. Settlement Intervals Panelists at the Shortage Pricing/ Mitigation and Operator Actions Workshops generally supported subhourly, rather than hourly, settlement intervals as providing better incentives for resources to perform during shortage events and to make investments to enhance resource flexibility.8 a. What are the advantages and disadvantages of moving to sub-hourly settlements for the real-time market as they relate to price signals, market efficiency, and operations? b. What metering and RTO/ISO software changes would be needed to change settlement intervals from hourly to sub-hourly for the real-time market, and how long would these changes take to implement? Are there significant costs to RTOs/ISOs, and to market participants, of such changes? Are there any other impediments to adjusting settlement intervals? c. What are the advantages and disadvantages of changing from hourly to sub-hourly settlements in the dayahead market? 5. New Products To Incent Flexibility tkelley on DSK3SPTVN1PROD with NOTICES Flexible resources that are capable of ramping up and down and/or starting up quickly provide value to the electric system. Panelists at the Operator Actions Workshop said that market designs which reward flexibility may stimulate investment in flexible capacity and provide resources more incentive to submit flexible offers.9 One panelist at the Operator Actions Workshop commented that existing 8 See Operator Actions Workshop, Docket No. AD14–14–000, Tr. 253:23–254:2 (Dec. 9, 2014); Scarcity and Shortage Pricing, Offer Mitigation and Offer Price Caps Workshop, Docket No. AD14–14– 000, Tr. 52:21–22, 53:11–16, 54:10–17 (Oct. 28, 2014). 9 Operator Actions Workshop, Docket No. AD14– 14–000, Tr. 149:7–11; 151:3–6; 291:6–8 (Dec. 9, 2014). VerDate Sep<11>2014 18:05 Jan 22, 2015 Jkt 235001 market rules can create disincentives for resources to submit supply offers that reflect the full flexibility (for example, ramp rate, minimum run time, minimum operating level, maximum operating level, minimum down time) of their resources.10 In addition, panelists at the workshops discussed the need for locational reserve products to better reflect local needs for flexibility. a. How do RTOs/ISOs currently ensure that they will have sufficient flexibility during real-time? Specifically, to what extent are residual unit commitments used to acquire anticipated needed flexibility? b. How are flexible resources compensated for the value that they provide to the system? Does that compensation reflect the value? Why or why not? If compensation to flexible resources does not reflect their value, how should RTOs/ISOs compensate flexible resources for the service they provide? c. What are the tradeoffs between sending a price signal through a shortduration shortage event versus establishing a ramping product that is priced separately? d. What are the tradeoffs among procuring flexibility through unit commitments (e.g., headroom requirements) rather than through the ten-minute reserve products or through ramp products? e. Does allowing combined-cycle natural gas resources to submit different offers for different configurations facilitate more efficient price formation? 11 What are the advantages and disadvantages to generators of bidding these configurations? 6. Operating Reserve Zones A lack of sufficiently granular reserve zones could be muting efficient price signals. At the Shortage Pricing/ Mitigation workshop, the NYISO panelist noted that NYISO is considering establishing a new reserve zone 12 and the PJM Interconnection, L.L.C. (PJM) external market monitor indicated that he believed PJM’s shortage pricing rules were not sufficiently locational. For instance, last year PJM experienced shortages in the American Transmission System, Inc. (ATSI) footprint that did not trigger shortage pricing because the ATSI zone is not a reserve zone.13 10 See id. at 291:9–22. e.g., Cal. Indep. Sys. Operator Corp., 132 FERC ¶ 61,087, order on compliance filing, 132 FERC ¶ 61,273 (2010). 12 Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, Docket No. AD14–14– 000, Tr.21:16–21 (Oct. 28, 2014). 13 Id. at 133:6–15. 11 See, PO 00000 Frm 00036 Fmt 4703 Sfmt 4703 a. How does the establishment, elimination or reconfiguration of reserve zones affect price formation? What should the triggers be? From experience, do the RTOs/ISOs have the appropriate reserve zones defined? Are additional, fewer, or different reserve zones needed? b. Are processes in place for adding, removing, or changing reserve zones adequate for efficient price formation? 7. Uplift Allocation Uplift allocation rules might impact resource participation decisions in RTO/ISO markets. For example, uplift allocation rules might incent participation in day-ahead markets or drive decisions on how to use financial products. a. Do uplift allocation rules reflect cost causation or mute potential investment signals? If so, how? b. What philosophy should govern uplift allocation? Do any of the RTOs/ ISOs have a best practice? What is it and why is it a best practice? c. Should uplift allocation categories reflect the reasons for committing a unit and incurring uplift? Would disclosing these reasons through publicly available data improve uplift transparency and provide information to facilitate modifications of the allocation of uplift costs? 8. Market and Modeling Enhancements At the Uplift and Operator Actions Workshops, panelists highlighted various drivers of persistent, concentrated uplift and operator actions, including constraints that are not incorporated into market models.14 Panelists also noted that certain constraints are difficult to model accurately or to incorporate into both the day-ahead and real-time market models.15 These include local voltage constraints and reliability constraints such as N–1–1 contingency constraints.16 a. Assuming that RTOs/ISOs should improve their market models to better reflect the cost of honoring reliability constraints in energy and ancillary services market clearing prices, what types of constraints should RTOs/ISOs include in their market models, and 14 See, e.g., Uplift Workshop, Docket No. AD14– 14–000, Tr. 49:7–11 (Sept. 8, 2014); Operator Actions Workshop, Docket No. AD14–14–000, Tr. 16:5–18 (Dec. 9, 2014). 15 See, e.g., Uplift Workshop, Docket No. AD14– 14–000, Tr. 192:12–18 (Sept. 8, 2014); Operator Actions Workshop, Docket No. AD14–14–000, Tr. 21:7–23 (Dec. 9, 2014). 16 An N–1–1 contingency constraint is a constraint to ensure that following any single contingency (N–1), the system can withstand any other contingency (N–1–1). E:\FR\FM\23JAN1.SGM 23JAN1 Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices tkelley on DSK3SPTVN1PROD with NOTICES what types of constraints should be handled by manual commitments? Of those reliability constraints that should be in the market models, which reliability constraints should RTOs/ISOs prioritize? b. In 2013, ISO New England Inc. (ISO–NE) increased its replacement reserve requirement to ‘‘reduce the need to schedule additional resources above the load and reserve requirements’’ in its Reserve Adequacy Analysis.17 PJM has a similar proposal to increase dayahead and real-time reserve requirements when extreme weather is expected.18 In what circumstances can such practices improve efficiency of price formation? c. Do transmission constraint relaxation penalty factors improve the efficiency of price formation? 19 If so, should these penalty factors be allowed to set the energy price if a transmission constraint is relaxed? d. Are there any new constraints that represent other physical characteristics of the system (with corresponding penalty factors), such as N–1–1 reliability constraints, that could be included in the model to improve the efficiency of price formation? If so, what types of constraints should be included and how should the penalty factors be determined? e. Should RTOs/ISOs create new products that procure the capacity necessary to address reliability constraints that cannot be captured in market models? If so, what should these products look like, and what process should RTOs/ISOs use to design these products? f. In some cases, creating new products to satisfy system needs (e.g., ramp capability, local reliability product, or additional reserves to account for operational uncertainty) may amount to procuring a level of spinning or non-spinning reserves above the mandatory reliability requirement. If the ‘‘new product’’ can be satisfied by an existing ancillary service product (e.g., ten minute reserves), is it necessary to create a new and separate product with its own price and cooptimization? Rather than developing a new product, could RTOs/ISOs change the cost allocation of any additional 17 ISO–NE., Transmittal Letter, Docket No. ER13– 1736–000 at 10 (filed June 20, 2013). 18 PJM Tariff Filing, Docket No. ER15–643–000 (filed December 17, 2014). 19 Transmission constraint penalty factors are parameters within the market model that place a cost, known as a penalty factor, on a transmission constraint. These parameters allow the model to ‘‘relax’’ the transmission constraint for a short time at a cost equal to the penalty factor, allowing flow over a given transmission element to exceed its normal limit. VerDate Sep<11>2014 18:05 Jan 22, 2015 Jkt 235001 ancillary services procured above the mandatory reliability requirement? 9. Shortage Prices In the questions below, the term ‘‘shortage pricing’’ refers generically to any pricing action taken in response to a shortage event. Not all RTOs/ISOs use this phrase in the same way.20 In responding to the questions below, please define terms and distinguish between ‘‘shortage pricing’’ and ‘‘scarcity pricing,’’ if such a distinction is intended. a. What principles should be used to establish shortage price levels? Should there be one price for any shortage or a set of escalating prices for greater levels of shortage? Is it important to have shortage price levels consistent across adjacent RTOs/ISOs to avoid seams issues? b. What are the advantages and disadvantages of implementing shortage pricing in the day-ahead market as well as in the real-time market? If shortage pricing is established only in the realtime market but not in the day-ahead market, are other policies needed to facilitate price convergence between the day-ahead and real-time markets during periods of shortage? If so, what are these other policies? If not, why not? 10. Transient Shortage Events At the Shortage Pricing/Mitigation Workshop, panelists stated different positions regarding pricing transient, or short-duration, shortage events.21 Transient shortage events are shortage events that last only a short time, perhaps as short as one or two fiveminute dispatch intervals.22 For instance, PJM’s market clearing process will not invoke shortage pricing if it can resolve the shortage within a certain time.23 However, even transient shortage events need a price signal to provide incentives to develop capabilities to respond to the shortage.24 a. Should there be a minimum duration for a shortage event before it triggers shortage pricing? Why or why not? How would one determine that minimum time, and how does it relate to the settlement interval? b. Do RTO/ISO rules regarding transient shortage events result in appropriate price signals? Why or why not? To the extent possible, please provide empirical evidence supporting your answer. 20 See, e.g., Scarcity and Shortage Pricing, Offer Mitigation and Offer Price Caps Workshop, Docket No. AD14–14–000, Tr. 20:1–21:7 (Oct. 28, 2014). 21 Id. at 38:19–51:8. 22 Id. at 40:19–24; 41:7–10; 44:16–23; 46:1–6. 23 Id. at 48:5–12. 24 Id. at 47:7–11. PO 00000 Frm 00037 Fmt 4703 Sfmt 9990 3583 c. Should treatment of transient shortages be consistent across all RTOs/ ISOs? Why or why not? 11. Interchange Uncertainty Due to the lag between price signals and interchange scheduling for import and export transactions, trade between RTOs/ISOs can result in volatile prices and variable system conditions because the ability of importers to schedule flows across the seam can lag behind actual system needs, creating uncertainty in interchange and contributing to operational issues.25 Several RTOs/ISOs have instituted new rules, such as NYISO’s and PJM’s Coordinated Transaction Scheduling (CTS), which attempt to better coordinate interchange schedules and price signals in order to improve interRTO/ISO flows. a. What can the RTOs/ISOs do to reduce interchange uncertainty? Does CTS help to reduce the uncertainty in interchange created by the lag between price posting and interchange schedules? Does the ability to reduce uncertainty depend on whether all interchange spread bids are incorporated into the RTO/ISO dispatch model (as proposed for the CTS implementation between NYISO and ISO–NE) rather than simply allowing interchange spread bids on a voluntary basis (as proposed for the CTS implementation between NYISO and PJM)? Are there other steps that should be taken to reduce interchange uncertainty? b. What information do market participants need to better respond to interchange price signals? 12. Next Steps a. Are there other price formation issues that, if addressed, would improve energy and ancillary services price formation in RTO/ISO markets? What are they? b. What are the highest-priority price formation issues to address? Is the priority of issues different in different RTO/ISO markets? If so, what are the priorities for each RTO/ISO and are the RTOs/ISOs currently addressing those issues sufficiently? [FR Doc. 2015–01139 Filed 1–22–15; 8:45 am] BILLING CODE 6717–01–P 25 See, e.g., the experience of Midcontinent System Operator, Inc. and PJM on July 6, 2012 as discussed in FERC, Price Formation in Organized Wholesale Electricity Markets: Staff Analysis of Shortage Pricing, Docket No. AD14–14–000, at 21– 22 (Oct. 2014), available at https://www.ferc.gov/ legal/staff-reports/2014/AD14-14-pricing-rto-isomarkets.pdf. E:\FR\FM\23JAN1.SGM 23JAN1

Agencies

[Federal Register Volume 80, Number 15 (Friday, January 23, 2015)]
[Notices]
[Pages 3580-3583]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2015-01139]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. AD14-14-000]


Price Formation in Energy and Ancillary Services Markets Operated 
by Regional Transmission Organizations and Independent System 
Operators; Notice Inviting Post-Technical Workshop Comments

    On September 8, October 28, and December 9, 2014, the Federal 
Energy Regulatory Commission (Commission) staff conducted a series of 
technical workshops to evaluate issues regarding price formation in the 
energy and ancillary services markets operated by Regional Transmission 
Organizations (RTOs) and Independent System Operators (ISOs) (RTOs/
ISOs).
    All interested persons are invited to file post-technical workshop 
comments on any or all of the questions listed in the attachment to 
this Notice. We emphasize that commenters need not answer all of the 
questions. Commenters should organize responses consistent with the 
structure of the attached questions and take care to identify to which 
RTO/ISO the comment applies. Commenters are also invited to reference 
material previously filed in this docket, including technical workshop 
transcripts. These comments must be filed with the Commission no later 
than 5:00 p.m. Eastern Standard Time on February 19, 2015.
    For more information about this Notice, please contact:

Mary Wierzbicki (Technical Information), Office of Energy Policy and 
Information, Federal Energy Regulatory Commission, 888 First Street 
NE., Washington, DC 20426, (202) 502-6337, mary.wierzbicki@ferc.gov.
Joshua Kirstein (Legal Information), Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8519, 
joshua.kirstein@ferc.gov.

    Dated: January 16, 2015.
Kimberly D. Bose,
Secretary.

Post-Technical Conference Questions for Comment

    The goals of proper price formation are to: Maximize market surplus 
for consumers and suppliers; provide correct incentives for parties to 
follow commitment and dispatch instructions, make efficient investments 
in facilities and equipment, and maintain reliability; provide 
transparency so that market participants understand how prices reflect 
the actual marginal cost of serving load and the operational 
constraints of reliably operating the system; and ensure that all 
suppliers have an opportunity to recover their costs. With proper price 
formation, the RTO/ISO would ideally not need to commit any additional 
resources beyond those resources scheduled economically through the 
market processes, and load would reduce consumption in response to 
price signals such that market prices would reflect the value of 
electricity consumption without the need to curtail load 
administratively.

[[Page 3581]]

    In reality, RTO/ISO energy and ancillary services market outcomes 
are impacted by a number of technical and operational 
considerations.\1\ At three workshops on price formation--Uplift 
Workshop, held September 8, 2014 (Uplift Workshop); Shortage Pricing, 
Offer Price Mitigation, and Offer Price Caps Workshop, held October 28, 
2014 (Shortage Pricing/Mitigation Workshop); and Operator Actions 
Workshop, held December 9, 2014 (Operator Actions Workshop)--panelists 
described software limitations, operational uncertainty, and limited 
flexibility of resources as challenges to achieving efficient price 
formation. These limitations are to some extent inherent in the 
complexity of the electric system and the tools available today to 
maintain reliable operations, and are unlikely to be addressed fully 
for the foreseeable future.\2\
---------------------------------------------------------------------------

    \1\ Although the discussion herein focuses on RTO/ISO markets, 
similar technical and operational limitations impact the efficient 
commitment of resources by electric utilities operating in other 
market structures, such as vertically integrated utilities.
    \2\ Other efforts, like Staff's annual meeting with RTO/ISO 
operations staff and the annual market software conference, are 
intended to make progress on these longer term issues. See https://www.ferc.gov/industries/electric/indus-act/market-planning.asp.
---------------------------------------------------------------------------

    Notwithstanding the foregoing technical limitations and operational 
realities, the Commission believes there may be opportunities for RTOs/
ISOs to improve the energy and ancillary service price formation 
process.
    Based on discussions during the three price formation workshops, 
Staff developed the following questions to better understand the ways 
in which to improve price formation in RTOs/ISOs. When responding to 
the questions below, please also comment on any relevant differences 
among RTOs/ISOs, the time needed to implement any potential solutions, 
and impediments to implementing any potential solutions.

1. Offer Caps

    High natural gas prices during the winter of 2013-2014, as 
discussed at the price formation workshops, indicated that the current 
generic $1,000/MWh cap on energy offers (``offer cap'') might be 
insufficient to allow natural gas-fired generators to recover their 
costs when natural gas prices spike during constrained winter periods.
    a. Should the $1,000/MWh offer cap be modified?
    i. If the offer cap is modified, what form should the offer cap 
take? For instance, should a modified cap be set at a level greater 
than the current $1,000/MWh cap and apply even if a resource has costs 
greater than the new cap or should the offer cap be replaced with a 
structure that allows offers at the higher of marginal cost or the 
existing $1,000/MWh cap? Should it be a fixed cap or a floating cap 
that varies with the price of fuel (e.g., natural gas)? If a modified 
cap were set as a fixed offer cap, what should the new offer cap be? 
What should be the basis for determining the fixed offer cap?
    ii. If the offer cap should not be modified or set such that 
marginal costs could be greater than $1000/MWh, how should the 
Commission ensure that suppliers with costs greater than the cap have 
the opportunity to recover those costs?
    iii. Do the real-time and day-ahead market clearing processes allow 
sufficient time to verify the cost-basis of the marginal resources that 
exceed the offer cap? Does the settlement process allow sufficient time 
to verify costs of resources that receive uplift associated with offers 
that exceed the offer cap?
    b. What are the advantages and disadvantages of having offer caps 
be set at the same level across all RTOs/ISOs? Would different offer 
caps across the RTOs/ISOs exacerbate interface pricing issues at RTO/
ISO borders? If so, how? Would an offer cap that takes the form of the 
higher of marginal cost or $1,000/MWh create the same issues as setting 
different offer caps across RTOs/ISOs?
    c. What impact would adjusting the offer cap have on other aspects 
of RTO/ISO price formation (e.g., mitigation rules or shortage pricing 
rules)? Would other market rule changes be necessary if offer cap 
levels were adjusted? Do other challenges associated with modifying 
offer cap rules exist? If so, what are they? If offer cap rules are 
adjusted, how quickly could RTOs/ISOs incorporate adjusted offer cap 
rules into their software and the market clearing process?
    d. Should the same offer cap that applies to generation also apply 
to load bids? What are the advantages and disadvantages of applying an 
offer cap to load bids?

2. Transparency

    At the Uplift and Operator Actions Workshops, some panelists 
addressed issues concerning insufficient transparency of uplift and 
operator actions.\3\ Improved transparency could inform resource entry 
and exit and market rule discussions; improved transparency could also 
improve market understanding, predictability, and confidence.
---------------------------------------------------------------------------

    \3\ See, e.g., Operator Actions Workshop, Docket No. AD14-14-
000, Tr. 180:8-183:4 (Dec. 9, 2014); Uplift Workshop, Docket No. 
AD14-14-000, Tr. 168:1-16 (Sept. 8, 2014). For this purpose we are 
defining uplift credits as payments made to resources whose 
commitment and dispatch by an RTO/ISO result in a shortfall between 
the resource's offer and the revenue earned through market clearing 
prices.
---------------------------------------------------------------------------

    a. What should RTOs/ISOs do to improve transparency of uplift 
credits and charges, unit commitment, and other operator actions? 
Please comment on the type of information that would be useful, why it 
is necessary, whether it should be shared with specific resources or 
available to all, the timing of its release, and whether it is feasible 
to release the information in real-time.
    b. What types of information should not be shared publicly? Why? 
What are the concerns with commercially sensitive information?
    c. Commission Staff's August 2014 report on uplift noted several 
issues with the consistency and granularity of uplift data provided as 
part of the Electric Quarterly Reports.\4\ What steps could be taken to 
improve the quality of uplift data required to be reported as part of 
the Electric Quarterly Reports?
---------------------------------------------------------------------------

    \4\ FERC, Staff Analysis of Uplift in RTO and ISO Markets, 
Docket No. AD14-14-000, at 21-28 (Aug. 2014), available at https://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf.
---------------------------------------------------------------------------

3. Pricing Fast-Start Resources

    Commission Staff's December 2014 paper about operator-initiated 
commitments discussed how RTOs/ISOs relax the minimum operating level 
of resources to make certain block-loaded fast-start resources appear 
dispatchable to the pricing software, and thus eligible to set the 
market clearing price as the marginal resource.\5\ The paper also 
discussed how some RTOs/ISOs have modified the locational marginal 
price (LMP) framework to include start-up and no-load costs of certain 
fast start resources (e.g., New York Independent System Operator, 
Inc.'s (NYISO's) Hybrid Pricing).\6\
---------------------------------------------------------------------------

    \5\ FERC, Price Formation in Organized Wholesale Electricity 
Markets: Staff Analysis of Operator-Initiated Commitments in RTO and 
ISO Markets, Docket No. AD14-14-000, at 28-30 (Dec. 2014), available 
at https://www.ferc.gov/legal/staff-reports/2014/AD14-14-operator-actions.pdf.
    \6\ Id.
---------------------------------------------------------------------------

    a. During the Operator Actions Workshop, panelists explained that 
relaxing resource minimum operating limits can lead to incentive and 
operational issues such as over-generation.\7\ What tradeoffs are 
involved with relaxing the minimum operating limits of block-loaded 
resources to zero for purposes of price setting? Should relaxing the 
minimum operating level be limited to block-loaded fast-start

[[Page 3582]]

resources, or should relaxation be available to a larger set of 
resources?
---------------------------------------------------------------------------

    \7\ Operator Actions Workshop, Docket No. AD14-14-000, Tr. 
282:9-25 (Dec. 9, 2014).
---------------------------------------------------------------------------

    b. What are the merits of expanding the set of costs included in 
the energy component of LMP (i.e., start-up and no-load costs)? What 
factors should be considered when expanding the set of costs included 
in the energy component of LMP? If the start-up and no-load costs of 
block-loaded fast-start resources are included in the LMP, how should 
they be included? For example, should start-up costs only be included 
during intervals when the resource starts up?
    c. Should off-line resources be eligible to set the LMP? If so, 
should start-up and no-load costs be included in the price, or just 
incremental energy costs?

4. Settlement Intervals

    Panelists at the Shortage Pricing/Mitigation and Operator Actions 
Workshops generally supported sub-hourly, rather than hourly, 
settlement intervals as providing better incentives for resources to 
perform during shortage events and to make investments to enhance 
resource flexibility.\8\
---------------------------------------------------------------------------

    \8\ See Operator Actions Workshop, Docket No. AD14-14-000, Tr. 
253:23-254:2 (Dec. 9, 2014); Scarcity and Shortage Pricing, Offer 
Mitigation and Offer Price Caps Workshop, Docket No. AD14-14-000, 
Tr. 52:21-22, 53:11-16, 54:10-17 (Oct. 28, 2014).
---------------------------------------------------------------------------

    a. What are the advantages and disadvantages of moving to sub-
hourly settlements for the real-time market as they relate to price 
signals, market efficiency, and operations?
    b. What metering and RTO/ISO software changes would be needed to 
change settlement intervals from hourly to sub-hourly for the real-time 
market, and how long would these changes take to implement? Are there 
significant costs to RTOs/ISOs, and to market participants, of such 
changes? Are there any other impediments to adjusting settlement 
intervals?
    c. What are the advantages and disadvantages of changing from 
hourly to sub-hourly settlements in the day-ahead market?

5. New Products To Incent Flexibility

    Flexible resources that are capable of ramping up and down and/or 
starting up quickly provide value to the electric system. Panelists at 
the Operator Actions Workshop said that market designs which reward 
flexibility may stimulate investment in flexible capacity and provide 
resources more incentive to submit flexible offers.\9\ One panelist at 
the Operator Actions Workshop commented that existing market rules can 
create disincentives for resources to submit supply offers that reflect 
the full flexibility (for example, ramp rate, minimum run time, minimum 
operating level, maximum operating level, minimum down time) of their 
resources.\10\ In addition, panelists at the workshops discussed the 
need for locational reserve products to better reflect local needs for 
flexibility.
---------------------------------------------------------------------------

    \9\ Operator Actions Workshop, Docket No. AD14-14-000, Tr. 
149:7-11; 151:3-6; 291:6-8 (Dec. 9, 2014).
    \10\ See id. at 291:9-22.
---------------------------------------------------------------------------

    a. How do RTOs/ISOs currently ensure that they will have sufficient 
flexibility during real-time? Specifically, to what extent are residual 
unit commitments used to acquire anticipated needed flexibility?
    b. How are flexible resources compensated for the value that they 
provide to the system? Does that compensation reflect the value? Why or 
why not? If compensation to flexible resources does not reflect their 
value, how should RTOs/ISOs compensate flexible resources for the 
service they provide?
    c. What are the tradeoffs between sending a price signal through a 
short-duration shortage event versus establishing a ramping product 
that is priced separately?
    d. What are the tradeoffs among procuring flexibility through unit 
commitments (e.g., headroom requirements) rather than through the ten-
minute reserve products or through ramp products?
    e. Does allowing combined-cycle natural gas resources to submit 
different offers for different configurations facilitate more efficient 
price formation? \11\ What are the advantages and disadvantages to 
generators of bidding these configurations?
---------------------------------------------------------------------------

    \11\ See, e.g., Cal. Indep. Sys. Operator Corp., 132 FERC ] 
61,087, order on compliance filing, 132 FERC ] 61,273 (2010).
---------------------------------------------------------------------------

6. Operating Reserve Zones

    A lack of sufficiently granular reserve zones could be muting 
efficient price signals. At the Shortage Pricing/Mitigation workshop, 
the NYISO panelist noted that NYISO is considering establishing a new 
reserve zone \12\ and the PJM Interconnection, L.L.C. (PJM) external 
market monitor indicated that he believed PJM's shortage pricing rules 
were not sufficiently locational. For instance, last year PJM 
experienced shortages in the American Transmission System, Inc. (ATSI) 
footprint that did not trigger shortage pricing because the ATSI zone 
is not a reserve zone.\13\
---------------------------------------------------------------------------

    \12\ Scarcity and Shortage Pricing, Offer Mitigation and Offer 
Caps Workshop, Docket No. AD14-14-000, Tr.21:16-21 (Oct. 28, 2014).
    \13\ Id. at 133:6-15.
---------------------------------------------------------------------------

    a. How does the establishment, elimination or reconfiguration of 
reserve zones affect price formation? What should the triggers be? From 
experience, do the RTOs/ISOs have the appropriate reserve zones 
defined? Are additional, fewer, or different reserve zones needed?
    b. Are processes in place for adding, removing, or changing reserve 
zones adequate for efficient price formation?

7. Uplift Allocation

    Uplift allocation rules might impact resource participation 
decisions in RTO/ISO markets. For example, uplift allocation rules 
might incent participation in day-ahead markets or drive decisions on 
how to use financial products.
    a. Do uplift allocation rules reflect cost causation or mute 
potential investment signals? If so, how?
    b. What philosophy should govern uplift allocation? Do any of the 
RTOs/ISOs have a best practice? What is it and why is it a best 
practice?
    c. Should uplift allocation categories reflect the reasons for 
committing a unit and incurring uplift? Would disclosing these reasons 
through publicly available data improve uplift transparency and provide 
information to facilitate modifications of the allocation of uplift 
costs?

8. Market and Modeling Enhancements

    At the Uplift and Operator Actions Workshops, panelists highlighted 
various drivers of persistent, concentrated uplift and operator 
actions, including constraints that are not incorporated into market 
models.\14\ Panelists also noted that certain constraints are difficult 
to model accurately or to incorporate into both the day-ahead and real-
time market models.\15\ These include local voltage constraints and 
reliability constraints such as N-1-1 contingency constraints.\16\
---------------------------------------------------------------------------

    \14\ See, e.g., Uplift Workshop, Docket No. AD14-14-000, Tr. 
49:7-11 (Sept. 8, 2014); Operator Actions Workshop, Docket No. AD14-
14-000, Tr. 16:5-18 (Dec. 9, 2014).
    \15\ See, e.g., Uplift Workshop, Docket No. AD14-14-000, Tr. 
192:12-18 (Sept. 8, 2014); Operator Actions Workshop, Docket No. 
AD14-14-000, Tr. 21:7-23 (Dec. 9, 2014).
    \16\ An N-1-1 contingency constraint is a constraint to ensure 
that following any single contingency (N-1), the system can 
withstand any other contingency (N-1-1).
---------------------------------------------------------------------------

    a. Assuming that RTOs/ISOs should improve their market models to 
better reflect the cost of honoring reliability constraints in energy 
and ancillary services market clearing prices, what types of 
constraints should RTOs/ISOs include in their market models, and

[[Page 3583]]

what types of constraints should be handled by manual commitments? Of 
those reliability constraints that should be in the market models, 
which reliability constraints should RTOs/ISOs prioritize?
    b. In 2013, ISO New England Inc. (ISO-NE) increased its replacement 
reserve requirement to ``reduce the need to schedule additional 
resources above the load and reserve requirements'' in its Reserve 
Adequacy Analysis.\17\ PJM has a similar proposal to increase day-ahead 
and real-time reserve requirements when extreme weather is 
expected.\18\ In what circumstances can such practices improve 
efficiency of price formation?
---------------------------------------------------------------------------

    \17\ ISO-NE., Transmittal Letter, Docket No. ER13-1736-000 at 10 
(filed June 20, 2013).
    \18\ PJM Tariff Filing, Docket No. ER15-643-000 (filed December 
17, 2014).
---------------------------------------------------------------------------

    c. Do transmission constraint relaxation penalty factors improve 
the efficiency of price formation? \19\ If so, should these penalty 
factors be allowed to set the energy price if a transmission constraint 
is relaxed?
---------------------------------------------------------------------------

    \19\ Transmission constraint penalty factors are parameters 
within the market model that place a cost, known as a penalty 
factor, on a transmission constraint. These parameters allow the 
model to ``relax'' the transmission constraint for a short time at a 
cost equal to the penalty factor, allowing flow over a given 
transmission element to exceed its normal limit.
---------------------------------------------------------------------------

    d. Are there any new constraints that represent other physical 
characteristics of the system (with corresponding penalty factors), 
such as N-1-1 reliability constraints, that could be included in the 
model to improve the efficiency of price formation? If so, what types 
of constraints should be included and how should the penalty factors be 
determined?
    e. Should RTOs/ISOs create new products that procure the capacity 
necessary to address reliability constraints that cannot be captured in 
market models? If so, what should these products look like, and what 
process should RTOs/ISOs use to design these products?
    f. In some cases, creating new products to satisfy system needs 
(e.g., ramp capability, local reliability product, or additional 
reserves to account for operational uncertainty) may amount to 
procuring a level of spinning or non-spinning reserves above the 
mandatory reliability requirement. If the ``new product'' can be 
satisfied by an existing ancillary service product (e.g., ten minute 
reserves), is it necessary to create a new and separate product with 
its own price and co-optimization? Rather than developing a new 
product, could RTOs/ISOs change the cost allocation of any additional 
ancillary services procured above the mandatory reliability 
requirement?

9. Shortage Prices

    In the questions below, the term ``shortage pricing'' refers 
generically to any pricing action taken in response to a shortage 
event. Not all RTOs/ISOs use this phrase in the same way.\20\ In 
responding to the questions below, please define terms and distinguish 
between ``shortage pricing'' and ``scarcity pricing,'' if such a 
distinction is intended.
---------------------------------------------------------------------------

    \20\ See, e.g., Scarcity and Shortage Pricing, Offer Mitigation 
and Offer Price Caps Workshop, Docket No. AD14-14-000, Tr. 20:1-21:7 
(Oct. 28, 2014).
---------------------------------------------------------------------------

    a. What principles should be used to establish shortage price 
levels? Should there be one price for any shortage or a set of 
escalating prices for greater levels of shortage? Is it important to 
have shortage price levels consistent across adjacent RTOs/ISOs to 
avoid seams issues?
    b. What are the advantages and disadvantages of implementing 
shortage pricing in the day-ahead market as well as in the real-time 
market? If shortage pricing is established only in the real-time market 
but not in the day-ahead market, are other policies needed to 
facilitate price convergence between the day-ahead and real-time 
markets during periods of shortage? If so, what are these other 
policies? If not, why not?

10. Transient Shortage Events

    At the Shortage Pricing/Mitigation Workshop, panelists stated 
different positions regarding pricing transient, or short-duration, 
shortage events.\21\ Transient shortage events are shortage events that 
last only a short time, perhaps as short as one or two five-minute 
dispatch intervals.\22\ For instance, PJM's market clearing process 
will not invoke shortage pricing if it can resolve the shortage within 
a certain time.\23\ However, even transient shortage events need a 
price signal to provide incentives to develop capabilities to respond 
to the shortage.\24\
---------------------------------------------------------------------------

    \21\ Id. at 38:19-51:8.
    \22\ Id. at 40:19-24; 41:7-10; 44:16-23; 46:1-6.
    \23\ Id. at 48:5-12.
    \24\ Id. at 47:7-11.
---------------------------------------------------------------------------

    a. Should there be a minimum duration for a shortage event before 
it triggers shortage pricing? Why or why not? How would one determine 
that minimum time, and how does it relate to the settlement interval?
    b. Do RTO/ISO rules regarding transient shortage events result in 
appropriate price signals? Why or why not? To the extent possible, 
please provide empirical evidence supporting your answer.
    c. Should treatment of transient shortages be consistent across all 
RTOs/ISOs? Why or why not?

11. Interchange Uncertainty

    Due to the lag between price signals and interchange scheduling for 
import and export transactions, trade between RTOs/ISOs can result in 
volatile prices and variable system conditions because the ability of 
importers to schedule flows across the seam can lag behind actual 
system needs, creating uncertainty in interchange and contributing to 
operational issues.\25\ Several RTOs/ISOs have instituted new rules, 
such as NYISO's and PJM's Coordinated Transaction Scheduling (CTS), 
which attempt to better coordinate interchange schedules and price 
signals in order to improve inter-RTO/ISO flows.
---------------------------------------------------------------------------

    \25\ See, e.g., the experience of Midcontinent System Operator, 
Inc. and PJM on July 6, 2012 as discussed in FERC, Price Formation 
in Organized Wholesale Electricity Markets: Staff Analysis of 
Shortage Pricing, Docket No. AD14-14-000, at 21-22 (Oct. 2014), 
available at https://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricing-rto-iso-markets.pdf.
---------------------------------------------------------------------------

    a. What can the RTOs/ISOs do to reduce interchange uncertainty? 
Does CTS help to reduce the uncertainty in interchange created by the 
lag between price posting and interchange schedules? Does the ability 
to reduce uncertainty depend on whether all interchange spread bids are 
incorporated into the RTO/ISO dispatch model (as proposed for the CTS 
implementation between NYISO and ISO-NE) rather than simply allowing 
interchange spread bids on a voluntary basis (as proposed for the CTS 
implementation between NYISO and PJM)? Are there other steps that 
should be taken to reduce interchange uncertainty?
    b. What information do market participants need to better respond 
to interchange price signals?

12. Next Steps

    a. Are there other price formation issues that, if addressed, would 
improve energy and ancillary services price formation in RTO/ISO 
markets? What are they?
    b. What are the highest-priority price formation issues to address? 
Is the priority of issues different in different RTO/ISO markets? If 
so, what are the priorities for each RTO/ISO and are the RTOs/ISOs 
currently addressing those issues sufficiently?

[FR Doc. 2015-01139 Filed 1-22-15; 8:45 am]
BILLING CODE 6717-01-P
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