Uplift Cost Allocation and Transparency in Markets Operated by Regional Transmission Organizations and Independent System Operators, 9539-9555 [2017-02332]

Download as PDF Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules cause the rudder pedal mechanism to detach from the brake cylinder. We are issuing this proposed AD to detect and correct discrepancies of the brake master cylinder pivot pin, which could lead to detachment of the rudder pedal mechanism from the brake master cylinder with consequent loss of control. (f) Actions and Compliance Unless already done, do the following actions in paragraphs (f)(1) through (3) of this AD: (1) Within 300 hours time-in-service (TIS) after the effective date of this AD or within 300 hours TIS after the last inspection required by AD 2015–11–01, whichever occurs first, and repetitively thereafter at intervals not to exceed 300 hours TIS or 12 months, whichever occurs first, inspect the brake master cylinder pivot pins part number (P/N) T67M–45–539 installed on rudder pedal assemblies number 1 and number 4. Do this action following paragraph C. INSPECTION of the Accomplishment Instructions in Marshall Aerospace and Defense Group Service Bulletin SBM 200, Revision 2, dated December 2015 (SBM 200, Revision 2). (2) If any cracking or distortion of the brake master cylinder pivot pins is found or the pivot pin fails the dimensional check during any of the inspections required in paragraph (f)(1) of this AD, before further flight, replace the affected pivot pin with a serviceable part following paragraph C. INSPECTION of the Accomplishment Instructions in SBM 200, Revision 2. (3) Replacement of the brake master cylinder pivot pins as required by paragraph (f)(2) of this AD does not terminate the repetitive inspections required by paragraph (f)(1) of this AD. If both brake master cylinder pivot pins are replaced at the same time, the first repetitive inspection after replacement of the pivot pins can be deferred until 1,000 hours TIS after replacement of the pivot pins. Lhorne on DSK30JT082PROD with PROPOSALS (g) Credit for Actions Accomplished in Accordance With Previous Service Information This AD provides credit for any inspections required in paragraph (f)(1) of this AD if completed before the effective date of this AD following the Accomplishment Instructions of Marshall Aerospace and Defense Group Service Bulletin SBM 200, Revision 1, dated April 2015. (h) Other FAA AD Provisions The following provisions also apply to this AD: (1) Alternative Methods of Compliance (AMOCs): The Manager, Standards Office, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. Send information to ATTN: Jim Rutherford, Aerospace Engineer, FAA, Small Airplane Directorate, 901 Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329–4165; fax: (816) 329– 4090; email:. 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For service information related to this AD, contact Marshall Aerospace and Defence Group, The Airport, Newmarket Road, Cambridge, CB5 8RX, UK; telephone: +44 (0) 1223 399856; fax: +44 (0) 7825365617; email: mark.bright@marshalladg.com; Internet: www.marshalladg.com. You may review copies of the referenced service information at the FAA, Small Airplane Directorate, 901 Locust, Kansas City, Missouri 64106. For information on the availability of this material at the FAA, call (816) 329–4148. Issued in Kansas City, Missouri, on January 18, 2017. Melvin Johnson, Acting Manager, Small Airplane Directorate, Aircraft Certification Service. [FR Doc. 2017–01768 Filed 2–6–17; 8:45 am] BILLING CODE 4910–13–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM17–2–000] Uplift Cost Allocation and Transparency in Markets Operated by Regional Transmission Organizations and Independent System Operators Federal Energy Regulatory Commission. ACTION: Notice of proposed rulemaking. AGENCY: The Federal Energy Regulatory Commission (Commission) is proposing to revise its regulations to require that each regional transmission organization (RTO) and independent system operator (ISO) that currently SUMMARY: 9539 allocates the costs of real-time uplift due to deviations should allocate such realtime uplift costs only to those market participants whose transactions are reasonably expected to have caused the real-time uplift costs. The Commission also proposes to revise its regulations to enhance transparency by requiring that each RTO/ISO post uplift costs paid (dollars) and operator-initiated commitments (megawatts) on its Web site; and define in its tariff its transmission constraint penalty factors, as well as the circumstances under which those penalty factors can set locational marginal prices, and any procedure for changing those factors. DATES: Comments are due April 10, 2017. Comments, identified by docket number, may be filed in the following ways: • Electronic Filing through http:// www.ferc.gov. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. • Mail/Hand Delivery: Those unable to file electronically may mail or handdeliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426. Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures Section of this document. FOR FURTHER INFORMATION CONTACT: Stanley Wolf (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502– 6841, Stanley.Wolf@ferc.gov Keatley Adams (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502– 8678, Keatley.Adams@ferc.gov Colin Beckman (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502–8049, Colin.Beckman@ferc.gov SUPPLEMENTARY INFORMATION: ADDRESSES: Table of Contents Paragraph I. Background ............................................................................................................................................................................................ II. Discussion ............................................................................................................................................................................................ A. Uplift Cost Allocation .................................................................................................................................................................. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 PO 00000 Frm 00007 Fmt 4702 Sfmt 4702 E:\FR\FM\07FEP1.SGM 07FEP1 9 12 12 9540 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules Paragraph Lhorne on DSK30JT082PROD with PROPOSALS 1. Uplift Cost Allocation Background ....................................................................................................................................... 2. Current RTO/ISO Practices ................................................................................................................................................... 3. Comments ............................................................................................................................................................................... a. Practices for Allocating Uplift Costs to Deviations ...................................................................................................... b. Virtual Transactions and Uplift ..................................................................................................................................... c. Coordinated Transaction Scheduling ............................................................................................................................ d. Additional Comments .................................................................................................................................................... 4. Need for Reform ..................................................................................................................................................................... 5. Proposal .................................................................................................................................................................................. a. Real-Time Uplift Categories ........................................................................................................................................... b. Netting ............................................................................................................................................................................. c. Deviations That Result From Following Dispatch ........................................................................................................ d. Settlement ....................................................................................................................................................................... e. Other Comments Sought ................................................................................................................................................. B. Transparency ................................................................................................................................................................................. 1. Background ............................................................................................................................................................................. 2. Current RTO/ISO Practices ................................................................................................................................................... a. Reporting Uplift .............................................................................................................................................................. b. Reporting Operator-Initiated Commitments .................................................................................................................. c. Transmission Constraint Penalty Factors ...................................................................................................................... 3. Comments ............................................................................................................................................................................... a. General Comments .......................................................................................................................................................... b. Comments on Uplift Reporting ...................................................................................................................................... c. Comments on Reporting Operator-Initiated Commitments .......................................................................................... d. Comments on Transmission Constraint Penalty Factors ............................................................................................. 4. Need for Reform ..................................................................................................................................................................... 5. Proposal .................................................................................................................................................................................. a. Uplift Reporting .............................................................................................................................................................. b. Reporting Operator-Initiated Commitments .................................................................................................................. c. Transmission Constraint Penalty Factors ...................................................................................................................... d. Comment Sought on Transmission Outages ................................................................................................................. e. Comment Sought on Availability of Market Models .................................................................................................... III. Compliance ......................................................................................................................................................................................... IV. Information Collection Statement ...................................................................................................................................................... V. Environmental Analysis ...................................................................................................................................................................... VI. Regulatory Flexibility Act .................................................................................................................................................................. VII. Comment Procedures ........................................................................................................................................................................ VIII. Document Availability ..................................................................................................................................................................... 1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) proposes to revise its regulations to address potentially unjust and unreasonable approaches to real-time uplift cost allocation and transparency practices by regional transmission organizations (RTOs) and independent system operators (ISOs). 2. While the Commission and RTOs/ ISOs have taken steps to reduce the amount of uplift in the energy and ancillary services markets, the complexity inherent in the electric system and limitations in the tools available to maintain reliable operations can lead to system operators taking outof-market actions to manage reliability. When they do so, energy and ancillary service prices may not reflect the marginal cost of production and some resources may therefore need makewhole payments to ensure recovery of operating costs. Since the limitations in representing the complexity of the electric system in market models are unlikely to ever be fully resolved, uplift costs are also unlikely to be completely eliminated. As a result, RTOs/ISOs need VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 to have a method for allocating these costs to market participants. At the highest level, the allocation of uplift costs should, to the extent possible, encourage behavior that will reduce the need for uplift-creating actions and avoid discouraging market participant behavior that lowers total production costs (i.e., enhances efficiency). The reforms proposed in this NOPR are designed to achieve these objectives. 3. Given that RTOs/ISOs are likely going to need to take some out-of-market actions, there is a need to provide transparency regarding those actions and the associated uplift costs. The lack of transparency regarding uplift and operator-initiated commitments,1 which can cause uplift, hinders a market participant’s ability to plan and efficiently respond to system needs. Market participants may lack the information necessary to evaluate the 1 An operator-initiated commitment is a commitment that is not associated with a resource clearing the day-ahead or real-time market on the basis of economics and that is not self-scheduled. See FERC, Operator Initiated Commitments in RTO and ISO Markets, Docket No. AD14–14–000 at 8– 20 (Dec. 2014), http://www.ferc.gov/legal/staffreports/2014/AD14-14-operator-actions.pdf. PO 00000 Frm 00008 Fmt 4702 Sfmt 4702 13 16 23 23 27 29 30 31 35 40 45 51 55 56 57 58 59 59 63 66 67 67 68 72 75 77 82 83 90 96 100 101 102 105 110 111 113 117 need for and value of additional investment, such as transmission upgrades or new generation. Also, without sufficient transparency, market participants may not be able to assess each RTO’s/ISO’s operator-initiated commitment practices and raise any issues of concern through the stakeholder process. The transparency reforms proposed in this NOPR are designed to allow market participants to understand the actions RTOs/ISOs are taking and respond accordingly. 4. First, we preliminarily find that certain practices of allocating the cost of real-time uplift 2 to market participants who deviate from day-ahead market schedules (deviations) are inconsistent with cost causation, which may distort market outcomes, potentially resulting in unjust and unreasonable rates. 2 Real-time uplift refers to uplift payments to resources committed after the close of the dayahead market, including any uplift associated with reliability commitments, whether or not the RTO/ ISO considers such commitments outside of the day-ahead market, e.g., the Reliability Unit Commitment or RUC process. As such, uplift payments to resources committed in a reliability unit commitment process would be considered realtime uplift for the purposes of this NOPR). E:\FR\FM\07FEP1.SGM 07FEP1 Lhorne on DSK30JT082PROD with PROPOSALS Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules Specifically, some RTO/ISO practices of allocating real-time uplift costs to deviations that could not reasonably be expected to have caused those uplift costs can distort market outcomes by inappropriately penalizing behavior that can improve price formation. Therefore, we propose to require that, if an RTO/ ISO allocates real-time uplift costs to deviations, it must do so based on cost causation, as further discussed below. For the purposes of allocating uplift costs to deviations, we propose that deviations are megawatt hour differences between a market participant’s scheduled deliveries or receipts at particular points—as determined by the day-ahead market clearing process—and those amounts actually delivered or received in realtime that are not related to real-time economic or reliability-related operator dispatch instructions. This proposal would apply only to real-time uplift cost allocation to deviations. This NOPR does not apply to other methods used by RTOs/ISOs to allocate uplift costs. If an RTO/ISO does not currently allocate real-time uplift costs to deviations, this NOPR does not impose a requirement on those RTOs/ISOs to allocate real-time uplift costs to deviations. 5. Second, we preliminarily find that current practices with respect to reporting uplift payments, operatorinitiated commitments, and transmission constraint penalty factors 3 are unjust and unreasonable. The lack of transparency into the costs allocated to market participants, and into the causes of such costs, hinders the ability of market participants to assess the effectiveness of current operational practices or to evaluate the need for additional investment, such as transmission upgrades or new generation. Similarly, the lack of transparency with respect to transmission constraint penalty factors may hinder a market participant’s ability to effectively understand how an RTO’s/ISO’s actions affect energy prices and thus, hinder its ability to hedge energy market transactions. As discussed further below, for these reasons we preliminarily find that these practices may result in rates that are unjust and unreasonable. We therefore propose to require that each RTO/ISO: (1) Report total uplift payments for each transmission zone, broken out by day and uplift category; (2) report total uplift payments for each resource on a 3 Transmission constraint penalty factors are the values at which an RTO’s/ISO’s market software will relax the limit on a transmission constraint rather than continue to re-dispatch resources to relieve congestion associated with that constraint. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 monthly basis; (3) report megawatts (MW) of operator-initiated commitments in or near real-time and after the close of the day-ahead market, broken out by transmission zone and commitment reason; and (4) define in its tariff the transmission constraint penalty factors, as well as the circumstances under which those factors can set locational marginal prices (LMPs), and the process by which they can be changed. 6. The goals of the price formation proceeding are to: (1) Maximize market surplus for consumers and suppliers; (2) provide correct incentives for market participants to follow commitment and dispatch instructions, make efficient investments in facilities and equipment, and maintain reliability; (3) 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 (4) ensure that all suppliers have an opportunity to recover their costs.4 7. The reforms proposed in this NOPR address two of the Commission’s price formation goals. First, the proposed reforms to uplift costs allocated to deviations should improve market participants’ incentives to perform in real-time consistent with operator instructions and bid into the day-ahead market and submit day-ahead schedules consistent with expected real-time system conditions. Second, the proposed transparency reforms will help market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system. 8. We seek comment on these proposed reforms 60 days after publication of this NOPR in the Federal Register. I. Background 9. In June 2014, the Commission initiated a proceeding, in Docket No. AD14–14–000, Price Formation in Energy and Ancillary Services Markets in Regional Transmission Organizations and Independent System Operators, to evaluate issues regarding price formation in the energy and ancillary services markets operated by RTOs/ISOs (Price Formation Proceeding). The 4 See Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators, Notice Inviting Post-Technical Workshop Comments, Docket No. AD14–14–000, at 1 (Jan. 16, 2015) (Notice Inviting Comments); Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators, Notice, Docket No. AD14–14–000 (June 19, 2014) (Price Formation Notice). PO 00000 Frm 00009 Fmt 4702 Sfmt 4702 9541 notice initiating that proceeding stated that there may be opportunities for the RTOs/ISOs to improve the price formation process in the energy and ancillary services markets. As set forth in the notice, prices used in energy and ancillary services markets ideally ‘‘would reflect the true marginal cost of production, taking into account all physical system constraints, and these prices would fully compensate all resources for the variable cost of providing service.’’ 5 Pursuant to the notice, staff conducted outreach and convened technical workshops on the following four general issues: (1) Use of uplift payments; (2) offer price mitigation and offer price caps; (3) scarcity and shortage pricing; and (4) operator actions that affect prices.6 10. In January 2015, the Commission requested comments on questions that arose from the price formation technical workshops.7 As a result of these comments, the Commission identified, among other things, five topics with potential for reform to improve price formation, but for which further information was needed. 11. In November 2015, the Commission issued an order that directed each RTO/ISO to report on these five price formation topics: Faststart pricing; managing multiple contingencies; look-ahead modeling; uplift allocation; and transparency.8 Specifically, the order directed each RTO/ISO to file a report providing an update on its current practices in the five topic areas, outlining the status of its efforts (if any) to address issues in each of the five topic areas, and responding to specific questions contained in the order. In the reports filed and the subsequent comments, RTOs/ISOs and other commenters addressed the issues of uplift cost allocation and transparency,9 which are the subject of this NOPR. II. Discussion A. Uplift Cost Allocation 12. In this section, we first provide a brief background on uplift payments and deviations between day-ahead and real-time schedules as a way to determine uplift cost allocation. We 5 Price Formation Notice, Docket No. AD14–14– 000, at 2 (June 19, 2014). 6 Id. at 1, 3–4. 7 Notice Inviting Comments, Docket No. AD14– 14–000 (Jan. 16, 2015). 8 Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators, 153 FERC ¶ 61,221 (2015) (Order Directing Reports). 9 A list of commenters and the abbreviated names used in this NOPR appears in the Appendix. E:\FR\FM\07FEP1.SGM 07FEP1 9542 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules then review current RTO/ISO practices and comments regarding these practices submitted prior to and after the issuance of the Order Directing Reports. Finally, we explain the need for reform and set forth the proposal in detail. Lhorne on DSK30JT082PROD with PROPOSALS 1. Uplift Cost Allocation Background 13. Uplift generally refers to payments that RTOs/ISOs make to a resource whose commitment and dispatch result in a shortfall between the costs in a resource’s offer and the revenue earned through market clearing prices.10 For example, if a resource is committed and is not able to fully recover its costs from the energy and ancillary services markets, it would receive an uplift payment. As noted in the Staff Analysis of Uplift, modeling, software, and certain other limitations are inherent in the complexity of the electric system and the tools available to maintain reliable operations. As a result, system operators may have to take out-ofmarket actions to manage reliability, with resulting energy and ancillary service prices not reflecting the marginal cost of production. Uplift, or make-whole, payments may therefore be needed to ensure that resources committed and dispatched out-ofmarket are able to recover their operating costs. These modeling, software, and other limitations will likely persist, making uplift an inherent element of centralized wholesale energy and ancillary services markets that may not be completely eliminated. Therefore, RTOs/ISOs must have a method to allocate these costs to market participants. Generally, RTOs/ISOs allocate uplift costs either directly to market participants who caused the uplift or to load. Allocation of uplift costs to load is motivated by several considerations. Load can be viewed as the ultimate beneficiary of the actions the system operator takes to maintain reliability. Further, one principle of cost allocation is to allocate costs in a way that is least likely to distort market participant behavior. In electricity markets, load is the class of market participants that is currently the least sensitive to price and for whom an allocation of uplift costs is arguably least likely to distort behavior. For shorthand, allocating uplift costs to load is referred to as ‘‘beneficiary pays.’’ In practice, RTOs/ISOs often use a combination of the two approaches, with load receiving all of the uplift costs that are not allocated through cost10 FERC, Staff Analysis of Uplift in RTO and ISO Markets, Docket No. AD14–14–000, at 1–2 (Aug. 2014), https://www.ferc.gov/legal/staff-reports/ 2014/08-13-14-uplift.pdf. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 causation methods, such as a deviations-based approach. 14. In its Order Directing Reports, the Commission asked the RTOs/ISOs to explain whether and how the RTO/ISO allocates real-time energy and ancillary services market uplift costs based on deviations from market participants’ day-ahead schedules, and whether deviations that increase the need for actions that cause real-time uplift payments (harming deviations) are netted against deviations that reduce the need for actions that cause real-time uplift payments (helping deviations).11 15. In response, most RTOs/ISOs state that they classify certain schedule differences between the day-ahead and real-time markets as deviations and allocate at least some portion of realtime uplift costs to those deviations. Allocation of real-time uplift costs to deviations is the focus of this NOPR because deviations may increase the need for operator actions that cause realtime uplift, such as additional unit commitments in real-time to replace a shortfall in generation or an increase in load compared to the day-ahead market solution. This NOPR does not address other methods of uplift cost allocation, such as allocation to load obligations, and does not propose to require RTOs/ ISOs to allocate real-time uplift costs to deviations. 2. Current RTO/ISO Practices 16. All of the RTOs/ISOs state that they use some form of beneficiary pays or cost-causation principles to allocate uplift costs.12 However, the current uplift cost allocation methods of the RTOs/ISOs vary significantly, both in terms of granularity and the exemption of certain types of transactions. The definition of what precisely constitutes a deviation also varies across RTOs/ ISOs. 17. NYISO generally allocates uplift costs based on the beneficiary pays principle.13 NYISO allocates uplift costs associated with state-wide reliability to all loads in the New York Control Area, and allocates uplift costs associated with local reliability to load within the transmission district where the reliability actions were taken. NYISO allocates real-time uplift costs on a beneficiary pays basis to load obligations, using real-time metered load during the hours in which uplift costs were incurred.14 NYISO also 11 Order Directing Reports, 153 FERC ¶ 61,221 at P 64, question 3.b. 12 NYISO Report at 45; PJM Report at 28; SPP Report at 19; MISO Report at 42; ISO–NE Report at 43; CAISO Report at 35. 13 NYISO Report at 46. 14 Id. at 40. PO 00000 Frm 00010 Fmt 4702 Sfmt 4702 explains that it eliminated all uplift costs associated with Coordinated Transaction Scheduling (CTS) 15 in a reciprocal fashion with ISO–NE, and that it supports the elimination of all uplift cost allocation and fees on exports because these fees reduce trade between regions and adversely impact total production costs.16 18. CAISO explains that it has many categories of uplift, and that it allocates uplift costs to transmission owners (who pass uplift costs to transmission customers), loads, and exports, depending on whether the system operator made the dispatch decision to address transmission constraints, energy imbalance, real-time congestion, or bid cost recovery.17 CAISO asserts that any allocation based on deviations should consider the wide variability in scheduling and metering granularity for different resources and that there might be implementation challenges in a more granular cost allocation.18 19. ISO–NE states that roughly half of its uplift costs are allocated to deviations, which include generator deviations, load deviations, increment (virtual) deviations, and import deviations.19 ISO–NE calculates each market participant’s deviations hourly, netting virtual demand bids and deviations from day-ahead load across all locations.20 However, hourly generator and virtual supply deviations are not subject to netting in ISO–NE.21 ISO–NE does not allocate uplift costs to CTS transactions.22 20. PJM allocates uplift costs incurred for reasons other than reliability to deviations, including cleared virtual bids, transaction deviations, and load deviations.23 PJM states that it assesses deviations daily by netting deviations separately within three different categories (demand, supply, and generation) at a single transmission zone, hub, or interface.24 PJM explains that its current netting rule allows a supply or demand deviation from a virtual transaction in the day-ahead energy market to be netted against 15 CTS is a set of real-time market rules that allow imports and exports to be scheduled based on a bidder’s willingness to purchase energy sourced from one RTO/ISO and sell the energy at a sink in another, adjacent RTO/ISO, if the difference between the forecasted prices at the sink and source is greater than or equal to the dollar value specified in the CTS Interface Bid (spread bid). 16 NYISO Report at 45–46. 17 CAISO Report at 40–45. 18 Id. at 37. 19 ISO–NE Report at 54–55. 20 Id. at 50. 21 Id. 22 ISO–NE Report at 53. 23 PJM Report at 30–31. 24 Id. at 31. E:\FR\FM\07FEP1.SGM 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules Lhorne on DSK30JT082PROD with PROPOSALS internal bilateral transactions 25 occurring at the same location.26 PJM does not consider up-to-congestion transactions 27 to be deviations and does not allocate uplift to them.28 PJM considers CTS transactions (and other imports and exports) to be deviations, and allocates uplift to them. 21. SPP states that it allocates uplift costs based on causation when the cause is identifiable and the cost of doing so does not outweigh the benefit.29 For example, real-time uplift costs are allocated to deviations from day-ahead schedules and SPP dispatch instructions.30 SPP states that virtual transactions are considered deviations, but virtual supply offers are netted against a countervailing deviation between day-ahead and real-time schedules (i.e., a load or export decrease, or import increase, relative to its day-ahead schedule) at the same settlement location.31 22. MISO has a granular approach to allocating uplift costs that it states is based on determining cost-causation where possible. MISO has several categories of uplift, but, for example, MISO’s Revenue Sufficiency Guarantee uplift category has six different methodologies for distributing costs based on the reason a resource was committed.32 MISO also allocates uplift costs according to a set of defined categories based on what MISO determines to be the cause of the uplift. Uplift costs resulting from real-time capacity commitments are largely allocated to deviations, including physical supply and demand deviations, virtual transactions, and import and export physical schedules.33 A portion of uplift resulting from transmission constraint relief is assigned to the deviations that caused the congestion.34 MISO has also noted that it will not 25 Internal bilateral transactions are a type of bilateral transaction used to purchase or sell one or more electricity market product(s) within a region. In all of the RTOs/ISOs, internal bilateral transactions are financial agreements that the two parties report to the RTO/ISO to streamline accounting and settlement. None of the RTOs/ISOs model internal bilateral transactions in the real-time or day-ahead market, and internal bilateral transactions do not affect market dispatch or power flows. 26 PJM Report at 33. 27 An up-to-congestion transaction is a form of virtual transaction that combines an offer to sell energy at a source, with a bid to buy the same MW quantity of energy at a sink where such transaction specifies the maximum difference between the LMP at the source and sink. 28 PJM Report at 33. 29 SPP Report at 20. 30 Id. at 22. 31 Id. at 38. 32 MISO Report at 42–43. 33 Id. at 44. 34 Id. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 allocate uplift costs to CTS between itself and PJM, which is expected to be implemented in the spring of 2017.35 3. Comments a. Practices for Allocating Uplift Costs to Deviations 23. Some commenters criticize the practice of allocating uplift costs to realtime deviations from day-ahead schedules. For example, Appian Way asserts that deviations-based approaches to uplift cost allocation create market inefficiencies in the form of unnecessary and inappropriate barriers to market participants accessing the spot market, and also shift the cost responsibility for uplift from load to other market participants.36 24. Others, however, support allocating uplift costs to deviations from day-ahead schedules, but argue that such deviations should be netted based on whether they contribute to or alleviate the condition causing uplift.37 Some commenters contend, for example, that netting such deviations is consistent with cost causation principles because it ensures that only market participants deviating from their day-ahead schedules in a manner that increases uplift payments will incur those costs.38 25. Multiple commenters also recommend the creation of more specific uplift cost allocation categories that are better aligned with cost causation. To this end, some commenters suggest creating a congestion management category that would distinguish uplift incurred for congestion management from uplift incurred for capacity needs or voltage and local reliability and allocate uplift costs accordingly.39 26. MISO Market Monitor asserts that uplift costs should be minimized to the extent possible by incorporating reliability requirements into marketbased products, but any remaining uplift costs should then be allocated based on cost causation. MISO Market Monitor believes that allocating uplift costs to those that cause it or benefit from it gives market participants an incentive to act to minimize it. MISO Market Monitor also asserts that MISO’s uplift cost allocation approach is the best practice in the industry because it determines why the uplift was incurred 35 Midcontinent Indep. Sys. Operator, Inc., 155 FERC ¶ 61,038, at P 3 (2016). 36 Appian Way Comments at 1, 7. 37 Financial Marketers Coalition Comments at 31. 38 Id. at 14, 31. 39 Id. at 14; XO Energy Comments at 24. PO 00000 Frm 00011 Fmt 4702 Sfmt 4702 9543 and allocates the costs accordingly.40 MISO Market Monitor also argues that for both capacity-related and congestion-related uplift, cost allocations should be based on deviations from the market participants’ day-ahead schedules.41 b. Virtual Transactions and Uplift 27. Allocation of uplift costs to virtual transactions is a contentious issue, and commenters hold disparate opinions. Some commenters argue that virtual transactions contribute to price convergence between the day-ahead and real-time markets, thus reducing, rather than increasing, uplift. They also argue that virtual transactions are easily forced out of the market by added fees, such as uplift. These commenters support either reducing or eliminating the allocation of uplift costs to virtual transactions.42 For example, XO Energy argues that it is unjust and unreasonable to allocate energy deviation-related uplift costs to virtual transactions as XO Energy asserts these transactions do not impact unit commitment because the energy impacts ‘‘net out’’ and do not affect the system’s power balance.43 28. Other commenters disagree, arguing that virtual transactions should be allocated uplift costs because they affect day-ahead commitment and dispatch, and thus can impact uplift.44 For example, PJM states that allocating uplift costs to virtual transactions is consistent with cost causation, and that up-to-congestion transactions should be allocated uplift costs similar to other virtual transactions, although they are not currently allocated such costs.45 Several commenters also contend that cost allocation rules for virtual transactions may need to be revised.46 For example, EEI notes that in PJM, virtual transactions, including increment offers and decrement bids, are allocated uplift costs, while up-tocongestion transactions are not. EEI asserts that up-to-congestion transactions should not be given preferential treatment and should instead be allocated a share of uplift costs.47 40 MISO Market Monitor Feb. 24, 2015 Comments at 16–17. 41 Id. at 17. 42 Appian Way Comments at 10; Financial Marketers Coalition Comments at 14–15; XO Energy Comments at 21. 43 XO Energy Comments at 19–21. 44 PSEG Companies Comments at 10; EEI Comments at 4. 45 PJM Report at 33. 46 EPSA/P3 Comments at 12; DC Energy, Inertia Power, and Vitol Comments at 4–5. 47 EEI Comments at 4. E:\FR\FM\07FEP1.SGM 07FEP1 9544 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules c. Coordinated Transaction Scheduling 29. CTS transactions are scheduled in real-time by the participating RTO/ ISOs 48 based on forecasted prices. CTS is not used in all RTO/ISO markets and the allocation of uplift costs to CTS varies by market, as described herein. Some RTOs/ISOs, such as MISO, view CTS transactions as economically dispatched, similar to the economic dispatch of a generator, and therefore do not consider them to be deviations for the purpose of allocating uplift costs. NYISO and ISO–NE do not allocate uplift costs to CTS transactions between their markets. PJM, however, views CTS transactions as deviations, indistinguishable in effect from other deviations that cause uplift. d. Additional Comments 30. Commenters also provide feedback on several other market design mechanisms related to uplift. For example, several commenters discuss the netting of internal bilateral transactions against other deviations when allocating uplift costs in PJM. While some advocate eliminating this market rule,49 others support it, contending that internal bilateral transactions are valuable hedging tools which allow market participants to counteract a deviation from a virtual transaction in the day-ahead market and promote convergence between dayahead and real-time prices.50 Lhorne on DSK30JT082PROD with PROPOSALS 4. Need for Reform 31. We preliminarily find that some existing RTO/ISO practices of real-time uplift cost allocation to deviations may be unjust and unreasonable. Specifically, these real-time uplift cost allocation practices may result in unjust and unreasonable rates by allocating costs to deviations that could not reasonably be expected to have caused those costs. Allocating costs to deviations that did not cause these costs can inappropriately penalize certain types of transactions that may be beneficial to price formation. We note that the Commission is not proposing to require RTOs/ISOs to allocate any amount of uplift costs to deviations, rather we are simply proposing reforms to uplift cost allocation to deviations to the extent an RTO/ISO chooses to allocate some uplift costs to deviations. 32. While there are several approaches to allocating uplift costs, 48 Currently, CTS is effective between NYISO and ISO–NE and NYISO and PJM. MISO and PJM expect to implement CTS in 2017. 49 PJM Market Monitor Comments at 13; PJM Report at 33; Appian Way Comments at 8. 50 EPSA/P3 Comments at 12–13. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 most RTOs/ISOs allocate at least a portion of real-time uplift costs to market participants that deviate from their day-ahead market schedules. When market participants deviate from their day-ahead schedule, RTOs/ISOs may have to take actions in real-time to address differences between the dayahead market solution and real-time system conditions. These actions, such as committing additional resources, can result in real-time uplift costs. 33. However, RTOs/ISOs do not always consider whether a deviation likely contributed to increasing or decreasing real-time uplift costs when allocating real-time uplift costs. Deviations from day-ahead market schedules that create the need for additional resource commitments in real-time tend to increase real-time uplift costs. On the other hand, deviations can also contribute to the convergence of the day-ahead and realtime markets by helping to ensure that the day-ahead market solution and the attendant day-ahead schedule reduces the need for system operator actions in real-time. If real-time uplift costs are assigned improperly, such costs may impact market behavior in a manner that limits otherwise beneficial transactions, which in turn may distort prices and market outcomes. This distortion can lead to increased realtime uplift payments, higher overall costs to consumers, and potentially unjust and unreasonable rates.51 34. Therefore, we preliminarily find unjust and unreasonable real-time uplift cost allocation rules that fail to distinguish between deviations that help converge day-ahead and real-time markets 52 and those that harm efforts to address system needs. Such rules fail to appropriately assign real-time uplift costs to market participants that are likely to cause such costs and inappropriately deter transactions that are likely to minimize these costs. 5. Proposal 35. To remedy the potentially unjust and unreasonable rates resulting from allocating real-time uplift costs to deviations in a manner inconsistent with cost causation, we propose that, pursuant to section 206 of the Federal Power Act,53 each RTO/ISO that currently allocates real-item uplift costs 51 FERC, Staff Analysis of Uplift in RTO and ISO Markets, Docket No. AD14–14–000, at 5–7 (Aug. 2014), https://www.ferc.gov/legal/staff-reports/ 2014/08-13-14-uplift.pdf. 52 Deviations that help converge day-ahead and real-time markets are deviations that bring dayahead and real-time prices, commitments, and dispatch closer together. 53 16 U.S.C. 824e. PO 00000 Frm 00012 Fmt 4702 Sfmt 4702 to deviations must follow the practices described below when allocating such costs. Specifically, the following practices ensure that if an RTO/ISO chooses to allocate real-time uplift costs to deviations, it must do so consistent with cost causation. Accordingly, we first propose that RTOs/ISOs categorize real-time uplift costs allocated to deviations into at least two categories based on the reason uplift costs were incurred, a system-wide capacity category and a congestion management category as discussed in more detail below. Second, we propose to require each RTO/ISO to distinguish between deviations that are ‘‘helping’’ to address system needs and those that are ‘‘harming’’ efforts to address system needs. Further, within each uplift category, uplift costs must be allocated to a market participant’s net ‘‘harming’’ deviations, i.e., relevant ‘‘harming’’ deviations net of relevant ‘‘helping’’ deviations. Third, we propose to clarify that a resource responding to an RTO/ ISO-initiated real-time dispatch instruction should not be allocated deviations-related real-time uplift costs. Finally, we propose that real-time uplift costs allocated to deviations must be settled using hourly uplift rate calculations. Each proposed practice is described in detail below. 36. This proposal would apply only to real-time uplift costs allocated to deviations. The NOPR does not propose to require that RTOs/ISOs allocate uplift costs to deviations, and we recognize that there are other methods for allocating uplift costs that are not based on deviations, such as allocations based on load obligation. Further, we recognize that there are many causes of uplift and this NOPR does not propose to address the allocation of all uplift costs. Rather, to improve upon existing RTO/ISO cost allocation practices, this NOPR addresses the allocation of uplift costs caused by market participants that deviate from their day-ahead market schedules. 37. Most RTOs/ISOs allocate some real-time uplift costs to deviations, although their methods for doing so vary. We set forth here a definition of deviations to delineate what type of real-time uplift cost allocation is the subject of this NOPR. We propose that deviations are megawatt hour differences between a market participant’s scheduled deliveries or receipts at particular points cleared in the day-ahead market and those amounts actually delivered or received at those points in real-time that are not related to real-time economic or reliability-related operator dispatch instructions. We propose that, to the E:\FR\FM\07FEP1.SGM 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules Lhorne on DSK30JT082PROD with PROPOSALS extent an RTO/ISO allocates real-time uplift costs to deviations, it must do so consistent with this proposed definition. We seek comment on the proposed definition of deviations. 38. We propose that if an RTO/ISO allocates real-time uplift costs to deviations, it must allocate such costs only to deviations that can reasonably be expected to have caused those costs. Real-time uplift costs are most likely to be incurred when, for various reasons, the day-ahead market clearing process does not schedule sufficient resources to satisfy the system’s real-time needs, and instead, RTOs/ISOs must procure additional resources after the day-ahead market has cleared. Market participants that deviate from their day-ahead schedules will either more closely align the day-ahead market solution with actual real-time system needs or contribute to a divergence from the dayahead solution. Scheduling practices that contribute to these divergences may require operator actions, such as operator-initiated commitments, in realtime. 39. RTO/ISO day-ahead and real-time price signals provide economic incentives to respond to system needs. Allocating real-time uplift costs to deviations consistent with cost causation would help ensure that realtime uplift cost allocation does not discourage or deter behavior that may converge day-ahead and real-time market solutions. By eliminating the allocation of real-time uplift costs to transactions that are beneficial to meeting system needs, this proposal strengthens the economic incentives for market participants to respond to system needs. Further, allocating realtime uplift costs consistent with cost causation rewards the ability to perform in real-time consistent with operator instructions and disciplines forward scheduling practices by encouraging market participants to bid into the dayahead market and submit day-ahead schedules consistent with expected realtime system conditions. a. Real-Time Uplift Categories 40. We propose to require each RTO/ ISO to categorize real-time uplift costs allocated to deviations into at least two categories based on the reason the uplift cost was incurred: (1) A system-wide capacity category and (2) a congestion management category. The system-wide capacity category would include realtime uplift related to resource commitments made to ensure sufficient system-wide online capacity to meet energy and operating reserve requirements. The congestion management category would include VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 real-time uplift related to resource commitments to manage transmission congestion on specific constraints. Under this proposal, we require that an RTO/ISO establish at least these two categories for real-time uplift cost allocation to deviations, but propose to provide flexibility to an RTO/ISO to establish additional categories. 41. We propose distinguishing the two categories, system-wide capacity and congestion management. The distinction ensures real-time uplift costs are allocated more specifically to the market participant that caused the uplift. Two examples illustrate how delineating these two categories is consistent with cost causation. 42. As a first example, consider a market participant that owns a generator that in real-time produces less than the output set forth in its day-ahead schedule when it did not receive dispatch instructions to do so. That generator’s deviation impacted the RTO’s/ISO’s ability to maintain realtime energy and operating reserve requirements and required a new commitment to make up for the generator’s deviation. However, absent impacting the power flows on a system constraint, the generator did not contribute to congestion on any constraint. Such a generator should be allocated real-time uplift costs for capacity but not congestion management. The generator caused a need for more capacity to come online, but did not cause a need to relieve congestion on a constraint. 43. As a second example, suppose that the same generator is owned by a market participant that also serves realtime load. If the market participant reduces its real-time load in an amount that equals the generator’s deviation (i.e., its reduced supply), the market participant’s behavior on net did not impact the RTO’s/ISO’s ability to maintain real-time energy and operating reserve requirements. However, if this behavior—on net—impacts congestion on the system, the market participant should be allocated real-time uplift costs related to congestion management. 44. We request comments on whether the proposed reforms should recognize the need for regional flexibility with regard to the uplift categories. We also request comment on whether other categories should be required. b. Netting 45. In allocating uplift costs to deviations, we propose to require each RTO/ISO to distinguish between deviations that are ‘‘helping’’ efforts to address system needs and those that are ‘‘harming’’ efforts to address system PO 00000 Frm 00013 Fmt 4702 Sfmt 4702 9545 needs. The particular system need of relevance will depend on the category of uplift costs at issue, as discussed further below. Within each uplift category, uplift costs must be allocated to a market participant’s net ‘‘harming’’ deviations, i.e., relevant ‘‘harming’’ deviations net of relevant ‘‘helping’’ deviations. Such allocation should be commensurate with a market participant’s share of total net ‘‘harming’’ deviations. 46. Under the proposed system-wide capacity category, a market participant would be allocated a portion of the total real-time uplift costs incurred to maintain energy and operating reserve requirements in the real-time market based on the net contributions of its deviations to those costs. This method would require an RTO/ISO to determine if each market participant’s deviations are, on net, ‘‘helping’’, by converging the day-ahead scheduled unit commitment and dispatch to the unit commitment and dispatch needed to meet real-time energy and operating reserve requirements, or if they are ‘‘harming’’, by exacerbating the difference between the day-ahead scheduled unit commitment and dispatch and the unit commitment and dispatch needed to meet real-time energy and operating reserve requirements. For example, if the system operator committed an additional resource to maintain energy and operating reserve requirements in the real-time market, a market participant with net deviations that increased demand (or decreased supply) would be allocated a portion of realtime uplift costs in the system-wide category, while a market participant with net deviations that increased supply (or decreased demand) would not. 47. Under the proposed congestion management category, a market participant would be allocated real-time uplift costs if its net deviations contributed to a difference between the congestion on a specific constraint in the day-ahead market and the real-time congestion on that constraint. This method would require an RTO/ISO to determine if each market participant’s deviations are, on net, ‘‘helping’’, by converging day-ahead and real-time congestion patterns, or if they are ‘‘harming’’, by exacerbating the difference between day-ahead and realtime congestion on a constraint. Market participants would be allocated realtime uplift costs in this category only if their net deviations are harming by contributing to differences between dayahead and real-time congestion on a constraint. E:\FR\FM\07FEP1.SGM 07FEP1 9546 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules Lhorne on DSK30JT082PROD with PROPOSALS 48. For netting within this congestion management category, we propose to require each RTO/ISO to determine realtime uplift cost allocation based on the net impact of a market participant’s deviations on a constraint. To make this determination, an RTO/ISO should net the deviations that relieve real-time congestion on the constraint with those that contribute to it. 49. Deviations caused by non-market transactions (such as internal bilateral transactions) would not be netted in either the proposed system-wide capacity category or the proposed congestion management category because they take place outside of the day-ahead and real-time markets. Transactions that take place outside of the markets do not affect real-time scheduling or dispatch and therefore should not offset transactions that do affect real-time scheduling or dispatch. 50. We seek comment on whether there should be advanced notification requirements in determining helpful deviations. That is, is there a period of time prior to the operating hour at which a deviation should no longer be considered helpful because notification of the deviation was provided to the RTO/ISO too close to the operating hour? If so, we seek comment on what the advanced notification requirement should be.54 Under the proposed definition of deviations, transactions related to real-time economic or reliability-related operator dispatch instructions would not be used in determining a market participant’s net deviations for both the system-wide capacity and congestion management categories. We also request comment on whether and how such transactions should be used to determine a market participant’s net deviations. c. Deviations That Result From Following Dispatch 51. Based on the discussion above and consistent with the proposed definition of deviations, we clarify that if the RTO/ ISO instructs a resource to deviate from its day-ahead schedule, be that a market-based or out-of-market instruction, that resource would not be regarded as deviating for purposes of this NOPR, and should not be allocated real-time deviation-related uplift costs, because it is helping to address differences between the day-ahead 54 For example, MISO determines whether a deviation is helpful based on whether it occurred before or after a notification deadline which is four hours prior to the operating hour. See generally MISO, FERC Electric Tariff, Definitions, ‘‘Notification Deadline’’, 1.N & Real-Time Energy and Operating Reserve Market Settlement Cal, 40.3.3. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 market solution and real-time system needs. 52. Consistent with this clarification, first, we propose that an RTO/ISO may not allocate deviation-related real-time uplift costs to a transaction that is economically evaluated by the RTO/ISO in the real-time market. Such transactions include real-time energy transactions and CTS transactions. Such real-time transactions are responding to real-time market price signals and are not deviations for the purposes of this NOPR. These transactions are helping to address real-time system needs and allocating real-time deviation-related uplift costs to such transactions could distort incentives to respond to these signals. Conversely, transactions that are not economically evaluated in the realtime market and do not have day-ahead schedules, such as self-scheduled realtime transactions, should be treated as deviations for the purposes of allocating real-time deviation-related uplift costs. 53. Second, consistent with this clarification, we further propose that instructed deviations (those initiated by the RTO/ISO) are not deviations for the purposes of allocating real-time uplift costs, and therefore, an RTO/ISO may not allocate real-time uplift costs based on deviations that result from a market participant following a reliabilityrelated dispatch instruction. Following such a dispatch instruction, by definition, helps the system. Allocating real-time uplift costs to market participants who follow dispatch instructions unfairly penalizes market participants that are responding to system needs in real-time. Further, assessing real-time uplift costs to such deviations could discourage a market participant from following dispatch instructions. At times of system stress, it is essential that resources follow dispatch instructions. For instance, an RTO/ISO may issue out-of-market dispatch instructions or deploy reserves to address immediate reliability issues. A resource that responds to such an RTO/ISO instruction performs an essential reliability function and should not be allocated real-time deviationrelated uplift costs for following the dispatch instruction. 54. By excluding instructed deviations from the definition of a deviation, the Commission is also proposing that instructed deviations would not be used in any ‘helping’ and ‘harming’ netting process. We seek comment on whether instructed deviations should be included in any netting calculations. PO 00000 Frm 00014 Fmt 4702 Sfmt 4702 d. Settlement 55. Regarding settlement of uplift costs, under both the system-wide capacity category and the congestion management category, we propose to require RTOs/ISOs to allocate and net real-time uplift costs on an hourly basis. RTOs/ISOs typically allocate uplift costs either hourly or daily. Hourly allocation would most closely align the imposition of costs with the incentives to behave efficiently in the market, since the costs of real-time uplift and the actions that cause that real-time uplift can and usually do change from hour to hour. Under hourly cost allocation, the costs for real-time uplift during a particular hour are allocated only to those market participants that contribute to the need for that uplift in that hour. e. Other Comments Sought 56. We recognize that considering real-time uplift cost allocation to deviations for system-wide capacity and congestion management separately may require a method for dividing costs between the two categories for circumstances in which real-time uplift is incurred for the benefit of both categories (e.g., committing a unit to relieve transmission congestion will also impact system-wide capacity requirements). We seek comment on the best methods to quantify this impact and to perform the appropriate cost allocation. We also seek comment on the process for netting of transactions and deviations set forth in the proposal for each category. Finally, we seek comment on the clarifications provided herein regarding those transactions that should not be considered deviations for the purpose of real-time uplift cost allocation and whether there are additional transactions that should be included in this category. B. Transparency 57. In this section, we first provide a brief background on the benefits of transparency in the wholesale electric power markets operated by RTOs/ISOs with respect to reporting uplift, operator-initiated commitments, and transmission constraint penalty factors. We then review current RTO/ISO practices with regard to reporting uplift and operator-initiated commitments, and summarize comments on transparency requirements, frequency of reporting, type of uplift information to be reported, inclusion of reasons for uplift or operator-initiated commitments, granularity with respect to location, and the inclusion of transmission constraint penalty factors in RTO/ISO tariffs. Then, we explain the E:\FR\FM\07FEP1.SGM 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules need for the reform regarding reporting of uplift, operator-initiated commitments, and transmission constraint penalty factors. Finally, we request comment on two additional topics: Reporting of transmission outages and availability of network models. 1. Background 58. Visibility into the process by which prices are developed in energy and ancillary services markets supports the functioning of efficient markets by enhancing predictability, identifying system needs, and facilitating investment decisions. Moreover, understanding how RTOs/ISOs calculate prices and how events impact those prices is critical to hedging, investment, and resource entry and exit decisions. While all RTOs/ISOs release some information, either through periodic reports or making data available on their Web sites, as discussed below, there is significant variation in the timing, granularity, and types of data released. Lhorne on DSK30JT082PROD with PROPOSALS 2. Current RTO/ISO Practices a. Reporting Uplift 59. All RTOs/ISOs report information about uplift payments. However, the extent of the information reported varies widely. For example, ISO–NE and NYISO provide monthly reports of uplift that generally provide information that is aggregated across zones and over the month.55 NYISO also makes aggregated uplift costs (in dollars) available to stakeholders on a daily basis through its daily reconciliation reports.56 MISO provides a number of monthly reports to market participants on categories of uplift costs; the reports aggregate the uplift data by category by month and provide historical monthly data for comparison.57 CAISO aggregates uplift data to its 10 existing local capacity requirement areas and reports daily total uplift costs for each month by the market in which the uplift is incurred (e.g., day-ahead or real-time), and by the type of costs incurred, i.e., start-up costs, minimum load costs or energy bid costs.58 PJM has recently adopted new rules to allow the reporting of daily uplift information by transmission zone, with certain exceptions for confidentiality reasons.59 SPP provides uplift information in a report that divides uplift costs into seven categories.60 60. RTO/ISO reporting practices are driven, in part, by the time needed to complete the settlement process. Some settlement periods last three to five business days and CAISO provides uplift cost information based on its 12business day recalculation statement, although the settlement period is shorter.61 Because of this lag, RTOs/ ISOs typically report uplift on a monthly basis, with the information aggregated to a zonal or settlement area level. 61. Most RTOs/ISOs cite confidentiality issues as an additional reason for their current reporting practices, particularly in regions with few market participants.62 Uplift information is typically aggregated to avoid publishing information for individual resources. All RTOs/ISOs assert that they are prohibited from publicly revealing resource-specific data, as specified in their confidentiality rules.63 Some RTOs/ISOs note that they cannot provide information on a more granular basis without changes to their confidentiality rules or information policies.64 62. It is worth noting that market participants with market-based and traditional cost of service rate authority are required to report uplift payments in the Electric Quarterly Report (EQR). Pursuant to EQR reporting requirements, uplift payments are required to be reported at a granular level. Those reporting requirements require market participants to report when the uplift payment changes. Because many resources are commercially organized as stand-alone limited liability corporations, many individual resources report uplift payments to EQR within 30 days following the end of a quarter. While EQR provides a significant amount of information, it does not provide detailed information regarding uplift. For example, EQR contains only a single ‘‘uplift’’ category which does not differentiate between different types of uplift (e.g., day-ahead, voltage and local reliability). 60 SPP Report at 40. Report at 64–65; PJM Report at 51; CAISO Report at 58. 62 PJM Report at 48, 54–55; SPP Report at 41, 44; ISO–NE Report at 61, 67; NYISO Report at 60. 63 CAISO Report at 59; NYISO Report at 58; PJM Report at 50–51; SPP Report at 42; ISO–NE Report at 63–64; MISO Report at 58–59. 64 PJM Report at 48; ISO–NE Report at 61. 61 ISO–NE 55 ISO–NE Report at 60; NYISO Report at 56–57. Report at 59. 57 MISO Report at 60. 58 CAISO Report at 56. 59 PJM, Business Practice Manual 33: Administrative Services for the PJM Interconnection Operating Agreement at 23–24. 56 NYISO VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 PO 00000 Frm 00015 Fmt 4702 Sfmt 4702 9547 b. Reporting Operator-Initiated Commitments 63. RTOs/ISOs also vary in the amount, granularity, and timing of information that is reported on operatorinitiated commitments. For example, CAISO, MISO, and NYISO provide information regarding operator-initiated commitments either shortly after the operating day or in near real-time. CAISO and MISO both report total operator-initiated commitments aggregated across the RTO/ISO, including the reasons for the commitments.65 MISO provides its reports in near real-time, while CAISO releases its report several days after the operating day. Throughout the operating day, NYISO posts operational announcements providing information about individual operator-initiated commitments, including the units involved, level of unit commitment, and the reason for the commitment, with a reference to the relevant reliability rule, if applicable.66 64. In addition, all RTOs/ISOs provide summary reports of operatorinitiated commitments over longer time periods. CAISO’s monthly performance report provides metrics on exceptional dispatch 67 and operator-initiated commitments organized by market (i.e., day-ahead or real-time), trade date, reason, or local area.68 CAISO also files a monthly report on the frequency and volume of exceptional dispatch, pursuant to directives in previous Commission orders.69 ISO–NE publishes weekly, monthly, and quarterly reports that describe notable operational events, but it does not provide any information regarding the location or capacity of committed units.70 ISO–NE also reports the number of units committed after the close of the day-ahead market (but not including real-time commitments) each day.71 SPP reports monthly the MW of operatorinitiated commitments.72 65. PJM states that, although its confidentiality provisions prevent it from reporting individual operatorinitiated commitments in real-time, it 65 MISO Report at 60; CAISO, Daily Exceptional Dispatch Report, http://www.caiso.com/market/ Pages/DailyExceptionalDispatch/Default.aspx. 66 NYISO Report at 56–57 and n.32. 67 CAISO states that its system operator issues exceptional dispatches to resources to address system issues that cannot be addressed by the constraints modeled within the market. CAISO Report at 41. 68 Id. at 56. 69 Id. See also Cal. Indep. Sys. Operator Corp., 131 FERC ¶ 61,100 (2010) (clarifying the reporting timeline for reporting exceptional dispatches). 70 ISO–NE Report at 60. 71 Id. at 61–62. 72 SPP Report at 40. E:\FR\FM\07FEP1.SGM 07FEP1 9548 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules does provide regionally aggregated information on uneconomic commitments in the day-ahead market at the end of the business day. In addition, PJM posts total capacity committed during the Reliability Assessment and Commitment period to meet forecasted load and reserves, as well as resources committed for transmission constraints, voltage/ reactive constraints, or conservative operations.73 ISO–NE also states its confidentiality provisions prohibit reporting of operator-initiated commitments in real-time, while CAISO states providing information about exceptional dispatches more frequently than monthly would require significant changes to its systems.74 SPP states it is technically feasible to report commitments resulting from operator actions in real-time, but notes such reporting could disclose sensitive reliability information.75 c. Transmission Constraint Penalty Factors 66. Transmission constraint penalty factors are the values at which an RTO’s/ISO’s market software will relax the flow-based limit on a transmission element to relieve a constraint caused by that limit rather than re-dispatch resources to relieve the constraint. The cost of re-dispatching resources can be regarded as the re-dispatch price. Transmission constraint penalty factors represent the maximum re-dispatch price that the system will pay before allowing flows to exceed a given transmission element’s limit.76 The penalty factors should be set at levels that are high enough to avoid relaxing constraints too frequently, but low enough to avoid extremely expensive redispatch solutions that are more expensive than the expected cost of exceeding a given transmission element’s limit. While these penalty factors can have significant impacts on prices, changes are not always made public nor do all RTOs/ISOs file them with the Commission. Specifically, PJM and ISO–NE do not include transmission constraint penalty factors in their respective tariffs.77 Further, MISO is the only RTO/ISO that details in its tariff how transmission constraint 73 PJM Report at 49–50. Report at 65; CAISO Report at 58, 62. 75 SPP Report at 41. 76 Transmission constraint penalty factors create a cap on the shadow price of a transmission constraint. See MISO Market Monitor Comments, Docket No. AD14–14–000, at 20–21 (Feb. 24, 2015). 77 CAISO, MRTU Tariff 27.4.3.1–27.4.3.3; SPP, OATT, Sixth Revised Volume No. 1, Attachment AE, 8.3.2, Addendum 1; NYISO Tariffs, NYISO Markets and Services Tariff 1.20; MISO, FERC Electric Tariff, Schedule 28A. Lhorne on DSK30JT082PROD with PROPOSALS 74 ISO–NE VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 penalty factors are temporarily changed.78 3. Comments a. General Comments 67. Various commenters recommend reporting of uplift and operator-initiated commitments that is more regular, more geographically granular, more specific about the size of the action (in MW), and/or more informative of the reason for uplift or operator action. Numerous commenters argue that such reporting about uplift and operator-initiated commitments should be mandatory.79 Exelon urges the Commission to require RTOs/ISOs to identify out-of-market actions and the resulting uplift in regular reports.80 Several commenters propose that RTOs/ISOs be required to post information in a way that is uniform, consistent, and comparable across RTOs/ISOs.81 b. Comments on Uplift Reporting 68. In terms of frequency, some commenters recommend monthly reporting of uplift to improve transparency.82 Energy Storage Association requests that RTOs/ISOs provide daily summary data on uplift credits. Energy Storage Association asserts that such information should, at a minimum, be at a zonal level and should be made available by all RTOs/ ISOs several days after the operating day.83 Several commenters request more granular locational information regarding uplift.84 These commenters argue that it is difficult to reduce or eliminate uplift when market participants do not know where it originates. To address this request, many commenters, including CAISO, ISO–NE, and PJM, support reporting uplift on a zonal basis.85 CAISO, ISO– NE, and PJM state that zonal reporting 78 MISO, FERC Electric Tariff, Schedule 28A. Energy, Inertia Power, and Vitol Comments at 18; EPSA Comments (on MISO Report) at 22; EPSA/NEPGA Comments at 14; Energy Storage Association Comments at 2–3; Exelon Comments at 17–18; PSEG Companies Comments at 16. 80 Exelon Comments at 17–18. 81 DC Energy, Inertia Power, and Vitol Comments at 18; EPSA Comments (on price formation) at 22; EPSA Comments (on MISO Report) at 22; EPSA/ IPPNY Comments at 13; EPSA Comments (on SPP Report) at 10; EPSA/NEPGA Comments at 14–15; EPSA/P3 Comments at 15; EPSA/WPTF Comments at 10. 82 EPSA Comments (on MISO Report) at 21–22; EPSA/NEPGA Comments at 13. 83 Energy Storage Association Comments at 2–3. 84 Financial Marketers Coalition Comments at 45; Energy Storage Association Comments at 6; Golden Spread Comments at 8–9. 85 Financial Marketers Coalition Comments at 45; Energy Storage Association Comments at 6; PJM Market Monitor Comments at 20; CAISO Report at 61; PJM Report at 52; ISO–NE Report at 64, 66. 79 DC PO 00000 Frm 00016 Fmt 4702 Sfmt 4702 strikes a balance between granularity and confidentiality.86 In contrast, SPP and MISO caution that reporting uplift on a zonal basis could reveal sensitive market participant information.87 69. Commenters have differing views on what uplift information should be reported. PSEG Companies argue that uplift can be effectively reported on a dollar basis.88 Energy Storage Association states that RTOs/ISOs should share daily summary data on uplift in dollars, including the reasons for the uplift and the location (at a minimum at a zonal level) of the resources that receive it.89 The PJM Market Monitor recommends reporting uplift charges by resource as well as detailed reasons for incurring uplift.90 EPSA and EPSA/NEPGA recommend reporting the settled uplift dollar impact on a MW basis, as well as the reasons for out-of-market commitments every month.91 EPSA asserts that reporting additional information on the drivers of uplift and out-of-market dispatch can be made public without compromising sensitive information, because NYISO currently does so in monthly reports.92 70. EPSA/IPPNY warns that reporting uplift more frequently than daily could potentially reveal confidential information.93 Energy Storage Association suggests that, given confidentiality concerns, the Commission could allow an RTO/ISO to request an exemption from reporting zonal or locational information in certain situations where there are few participants in a zone or location.94 ISO–NE and MISO suggest that the level of aggregation be adjusted to ensure that confidentiality is maintained.95 c. Comments on Reporting OperatorInitiated Commitments 71. Several commenters recommend monthly reporting of operator-initiated actions, including the reasons for out-ofmarket actions, to improve 86 PJM Report at 53; ISO–NE Report at 66; CAISO Report at 61. 87 MISO Report at 60–61; SPP Report at 43. 88 PSEG Companies Comments at 12, 15–16. 89 Energy Storage Association Comments at 2. 90 PJM Market Monitor Comments at 20–21. 91 EPSA and its joint commenters support several variations of ‘‘reporting actual settled uplift dollar impacts, on a Megawatt (MW) basis.’’ It is unclear whether this is referring to reporting uplift dollars divided by the total capacity of resources that receive uplift payments, or reporting the total capacity of committed resources in lieu of identifying specific units. EPSA Comments (on price formation) at 23; EPSA Comments (on MISO Report) at 21–22; EPSA/NEPGA Comments at 13. 92 EPSA Comments (on price formation) at 23. 93 EPSA/IPPNY Comments at 12–13. 94 Energy Storage Association Comments at 3. 95 ISO–NE Report at 66; MISO Report at 61. E:\FR\FM\07FEP1.SGM 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules transparency.96 Commenters argue that understanding the reasons for out-ofmarket commitments will help market participants discern what types of investments are needed to meet system needs.97 Moreover, the Financial Marketers Coalition states that, when out-of-market commitments are identified by location and explained, financial participants will refrain from bidding because they know that prices will not converge and uplift is likely.98 72. Some commenters also suggest that RTOs/ISOs report operator-initiated commitments closer to real-time. In particular, PSEG Companies suggest that NYISO’s approach to disclosing out-ofmarket commitment and dispatch decisions should be considered a best practice.99 74. Several commenters request more granular locational information regarding out-of-market operator actions.100 PSEG Companies note that when RTOs/ISOs provide only aggregated data, it is not possible to discern whether the RTO/ISO needed those units or how many MW were actually required.101 Lhorne on DSK30JT082PROD with PROPOSALS d. Comments on Transmission Constraint Penalty Factors 75. The MISO Market Monitor asserts that transmission constraint penalty factors substantially affect market outcomes but are not filed with or approved by the Commission for some RTOs/ISOs. MISO Market Monitor adds that increasing transmission constraint penalty factors during real-time operations to relieve constraints may indicate that constraints were undervalued previously, and lowering transmission constraint penalty factors during real-time operations may indicate that the RTO/ISO is attempting to manually reduce congestion costs. MISO Market Monitor contends that these concerns can be addressed by: (1) Establishing parameters that reflect the reliability value of managing the constraints, which likely varies by constraint; (2) filing these values in the RTO’s/ISO’s tariffs so they are known and approved by the Commission; and (3) filing tariff provisions that specify 96 EPSA Comments (on MISO Report) at 21–22; EPSA/NEPGA Comments at 13; Exelon Comments at 18; EPSA Comments (on price formation) at 23 EPSA/IPPNY Comments at 13; EPSA/P3 Comments at 15–16. 97 EPSA Comments (on price formation) at 23; EPSA/P3 Comments at 15–16. 98 Financial Marketers Coalition Comments at 42. 99 PSEG Companies Comments at 11. 100 Financial Marketers Coalition Comments at 45 (referring to SPP); Energy Storage Association Comments at 6 (referring to MISO and SPP); Golden Spread Comments at 8–9. 101 PSEG Companies Comment at 14. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 the procedures and authority for RTOs/ ISOs to modify transmission constraint penalty factors.102 76. XO Energy states that transmission constraint penalty factors can have a significant impact on prices; however, there is not necessarily clear insight as to how transmission constraint penalty factors are determined or calculated in the pricing and dispatch algorithms.103 XO Energy contends that, in some cases, the default transmission constraint penalty factors can be arbitrarily assigned and modified on a case-by-case basis.104 4. Need for Reform 77. We preliminarily find that some existing RTO/ISO practices of reporting uplift, operator-initiated commitments, and transmission constraint penalty factors may result in unjust and unreasonable rates. The lack of transparency regarding uplift and operator-initiated commitments, which can cause uplift, hinders market participants’ ability to plan and efficiently respond to system needs. Market participants may lack the information necessary to evaluate the need for and value of additional investment, such as transmission upgrades or new generation. Also, without sufficient transparency, market participants may not be able to assess each RTO’s/ISO’s operator-initiated commitment practices and raise any issues of concern through the stakeholder process. 78. Reporting that specifies the location and causes of uplift and operator-initiated commitments will help incent appropriate market responses to system needs. For example, if resources are routinely committed out-of-market to resolve a local voltage issue and require uplift payments as a result, it may be beneficial to release information on the uplift associated with using such resources to alert market participants about the problem. Providing more detailed information about the uplift incurred to address a local reliability issue could potentially incent market participants to advocate for changes to the RTO/ISO’s operational procedures or to undertake investments that could resolve the local reliability issue more efficiently (e.g., install additional capacitors). 79. While all RTOs/ISOs provide some information regarding the locations and causes of uplift and operator-initiated commitments, the 102 Comments of MISO Market Monitor, Docket No. AD14–14–000, at 20–21 (Feb. 24, 2015). 103 XO Energy Comments at 67–68. 104 Id. at 68. PO 00000 Frm 00017 Fmt 4702 Sfmt 4702 9549 information is often highly aggregated or lacks detail, limiting its usefulness. Information about the location and causes of uplift and operator-initiated commitments that is overly aggregated or lacks detail hinders the ability of a market participation to evaluate RTO/ ISO operating practices and potentially respond to system needs by undertaking new investments. For example, reports that aggregate uplift payments over the month may not provide sufficient information, since monthly reports can obscure daily trends, which may be more relevant to those evaluating operating practices or potential investments. Therefore, increasing transparency with respect to the location and cause of uplift can provide market participants additional information to evaluate the effectiveness of current operating practices. Without sufficient information to evaluate existing operating practices or the need for additional investment, market efficiency may be reduced, resulting in unjust and unreasonable rates. Allowing market participants to better evaluate the need for changes in operating practices or additional investment could ultimately reduce the level of uplift, thereby resulting in rates that are just and reasonable. 80. Similarly, the lack of transparency with respect to transmission constraint penalty factors may hinder the ability of market participants to undertake efficient transactions. For example, if market participants are unaware of what transmission constraint penalty factors are used and whether they will be used to set LMPs, market participants may not be able to adequately understand how an RTO’s/ISO’s actions affect clearing prices and thus may not be able to hedge transactions appropriately or effectively assess the RTO’s/ISO’s actions and raise concerns through the stakeholder process. Without the ability to appropriately hedge transactions, market participants may either overhedge or under-hedge their positions, reducing market efficiency. Also, if market participants are not able to raise concerns about changes in transmission constraint penalty factors, RTOs/ISOs may alter transmission constraint penalty factors more often than necessary, which impacts market clearing prices. Therefore, the resulting rates may be unjust and unreasonable. 81. Some RTOs/ISOs report that there are a variety of stakeholder initiatives and discussions underway to improve transparency,105 while others do not 105 CAISO Report at 55; MISO Report at 56; NYISO Report at 55; PJM Report at 47. E:\FR\FM\07FEP1.SGM 07FEP1 9550 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules mention any specific plans.106 Despite these efforts, it is not clear that the transparency concerns discussed in this NOPR will be addressed through existing stakeholder initiatives. Accordingly, we preliminarily find that some existing RTO/ISO practices with respect to reporting uplift, operatorinitiated commitments, and transmission constraint penalty factors may be unjust and unreasonable. Lhorne on DSK30JT082PROD with PROPOSALS 5. Proposal 82. To remedy these potentially unjust and unreasonable reporting practices, we propose, pursuant to section 206 of the Federal Power Act, to require that each RTO/ISO: (1) Report total uplift payments for each transmission zone on a monthly basis, broken out by day and uplift category; (2) report total uplift payments for each resource on a monthly basis; (3) report the MW of operator-initiated commitments in or near real-time and after the close of the day-ahead market, broken out by zone and commitment reason; and (4) list in its tariff the transmission constraint penalty factors, the circumstances under which they can set LMPs, and the procedure by which they can be temporarily changed. a. Uplift Reporting 83. We propose to require that, within 20 days of the end of each month, each RTO/ISO post on its Web site two reports, at minimum, regarding uplift payments. First, the RTO/ISO should report the total uplift payments in dollars paid daily to the resources in each transmission zone, subject to certain exceptions described below. Each RTO/ISO must post the total amount of uplift in dollars in each category (e.g., day-ahead, real-time, voltage and local reliability) paid to resources in each transmission zone for each day within the calendar month. We propose to require that each RTO/ISO post uplift payment amounts based on its specific uplift categories to allow market participants to distinguish between different types of uplift. Second, each RTO/ISO must post the resource name and the total amount of uplift paid in dollars aggregated across the month to each resource that received uplift payments within the calendar month. We seek comment on whether these resource-specific reports should also be broken out by uplift category, be reported using a different time duration, or contain other additional details. 84. Information on uplift payments should be posted in a machine readable format on a publicly accessible portion 106 ISO–NE Report at 59; SPP Report at 39. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 of the RTO’s/ISO’s Web site. With this information, market participants may be able to evaluate possible solutions to reduce the incurrence of uplift. For example, with more granular information on the location, amounts, and types of uplift, market participants can better evaluate the benefits of additional transmission upgrades that could reduce the need for unit commitments. 85. We also propose to define ‘‘transmission zone’’ as a geographic area that is used for the local allocation of charges. For example, this could include a load zone that is used to settle charges for energy. We request comments on this proposed definition of transmission zone, including the appropriate level of geographic granularity. 86. Regarding the timeliness of posting this information, we recognize that each RTO/ISO has a different settlement window and uplift is finalized during the settlement process. As such, it is not possible for an RTO/ ISO to release information immediately at the end of the month. In order to account for differences in settlement periods and the time necessary to prepare the uplift data for publication, we propose to require that both reports described above be released no later than 20 calendar days following the end of the month. While we believe this is a reasonable timeframe for release, we seek comment on the timeframe for releasing the information after the end of each month. In addition, we seek comment on the proposed requirement for a daily breakdown of uplift categories by charge code, including any obstacles or difficulties related to such reporting and whether different categorizations would be more useful. 87. Many commenters express concern that greater transparency in uplift reporting could unintentionally disclose a resource’s uplift payments or energy offers, which some characterize as confidential or commerciallysensitive information. Commenters’ core concerns appear to relate to two issues: first, that disclosing a resource’s uplift payments will allow other market participants to calculate energy offers and may result in collusion between market participants.107 Second, commenters appear to be concerned that revealing uplift payments may put a resource at a competitive disadvantage 107 In conjunction with other information, uplift payments could potentially be used to determine a resource’s energy offers. For example, if a market participant knew a resource’s output, LMP, and uplift payments, it could potentially calculate the resource’s energy offer because the uplift would make the resource whole up to its offer costs. PO 00000 Frm 00018 Fmt 4702 Sfmt 4702 by disclosing commercially sensitive information like fuel procurement strategies. 88. While we understand the need to protect certain types of information, we are not persuaded that revealing a resource’s daily uplift payments or energy offer, after some minimal time lag, would result in any significant harm to competition or individual market participants. First, many individual resources already publicly report their uplift payments pursuant to Electric Quarterly Reporting requirements (with a 90-day lag). Second, RTO/ISO energy markets are mitigated, so concerns about the potential for collusion can be addressed through must offer requirements and market power mitigation rules. Third, after the 20-day lag for reporting following the end of the month, fuel costs and other conditions have often changed, diminishing the potential usefulness of any resource offer information. These three factors limit the potential for anti-competitive behavior and any harm to market participants. 89. Nevertheless, to address commenters’ concerns, we seek to balance the benefits of greater transparency with the desire to preserve a reasonable level of confidentiality. Specifically, for the reporting requirements aggregated by transmission zone, we propose that transmission zones with fewer than four resources need not be reported individually; rather, transmission zones with fewer than four resources may be aggregated with a neighboring transmission zone and reported collectively. If only one transmission zone exists and it has fewer than four resources or, if when combined with a neighboring transmission zone the combined transmission zone still has fewer than four resources, then these transmission zones would be exempted from reporting the uplift information described above. Similarly, for the resource-specific reporting requirements proposed above, we will require that uplift payment data for each resource be aggregated across the month, rather than reporting daily uplift payments to each resource. We expect that this temporal aggregation should mask daily behavior that some commenters have expressed concerns over revealing. b. Reporting Operator-Initiated Commitments 90. We also propose to require that each RTO/ISO post all operator-initiated commitments on its Web site. For the purposes of this NOPR, we propose to define operator-initiated commitments as a commitment that is not associated E:\FR\FM\07FEP1.SGM 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules Lhorne on DSK30JT082PROD with PROPOSALS with a resource clearing the day-ahead or real-time market on the basis of economics and that is not selfscheduled.108 This definition would include any commitment, whether manual or automated, made after the execution of the day-ahead market that is made outside of the real-time market. Such commitments include commitments made through a residual unit commitment processes after the execution of the day-ahead market, commitments made through look-ahead commitment processes, and manual commitments made in real-time. We acknowledge that this definition of operator-initiated actions could result in reporting most commitments that occur after the day-ahead market. Moreover, we understand that whether a commitment cleared the market on the basis of economics could be a point of confusion, particularly with respect to look-ahead commitment processes. Therefore, we request comment on this aspect of the definition of operatorinitiated actions. 91. The report posted on each RTO’s/ ISO’s Web site would include the following: (1) The upper economic operating limit of the committed resource in MW (i.e., its economic maximum); (2) the transmission zone in which the resource is located; and (3) the reason for commitment.109 We propose that each RTO/ISO post this information on a publicly accessible portion of its Web site in machinereadable format as soon as practicable after the resource has been committed (i.e., directed to start up by the RTO/ ISO). As above, we propose to define ‘‘transmission zone’’ as a geographic area that is used for the local allocation of charges. We request comments on this proposed definition, including the appropriate level of geographic granularity. Also, as discussed further below, we propose that real-time commitments be posted as soon as practicable after they occur, but no later than four hours after the commitment. 92. Many commenters express concern about the lack of transparency surrounding operator-initiated commitments and request that the Commission require RTOs/ISOs to provide more information.110 We agree that current RTO/ISO practices may not 108 See supra text accompanying note 1. example, if a resource with two combustion turbines with a capacity of 50 MW each was committed to manage congestion on a transmission facility, the RTO/ISO would be required to report the committed capacity (100 MW) and the reason (e.g., constraint management). 110 E.g., EPSA Comments at 22–23; Exelon Comments at 17–18; Financial Marketers Coalition Comments at 42; PSEG Comments at 12. 109 For VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 provide sufficient transparency regarding operator-initiated commitments and that a minimum level of transparency is necessary as operatorinitiated commitments can affect rates. In particular, operator-initiated commitments can affect energy and ancillary service prices and can result in uplift. In addition, greater transparency will allow stakeholders to better assess the RTO’s/ISO’s operator-initiated commitment practices and raise any issues of concern through the stakeholder process. 93. While most commenters focus on reporting of manual operator-initiated commitments (i.e. not through automated software),111 operatorinitiated commitments made through automated processes like look-ahead commitment can also have a significant impact on uplift. In addition, as noted by several RTOs/ISOs, manual operatorinitiated commitments are generally infrequent. Because posting all operatorinitiated commitments, whether manual or automated, would help market participants to better understand the drivers behind the incurrence of uplift in each zone and the impact of such commitments on rates, we propose that all operator-initiated commitments be posted, whether manual or automated. We also seek comment on the types of unit commitments that should be reported as operator-initiated commitments. 94. In addition, we propose that realtime commitments be posted as soon as practicable after they occur, but no later than four hours after the commitment. We understand that this type of reporting could require significant changes to current RTO/ISO systems and processes. Accordingly, we seek comment on the proposed reporting timeframe, including the potential software upgrades necessary to facilitate reporting in near real-time and other potential implementation challenges. We also seek comment on whether a different reporting timeframe (e.g., reporting once daily or monthly) would provide sufficient transparency. 95. We also understand that reporting the reason for an operator-initiated commitment may require the development of new internal processes. In particular, we understand that the reasons for operator-initiated commitments can vary based on the particular situation. Therefore, our proposal would only require RTOs/ISOs to report the commitment reason within broad categories (e.g., voltage support, 111 CAISO Report at 60; ISO–NE Report at 65; SPP Report at 42; PSEG Companies Comments at 12, 14– 16, 21. PO 00000 Frm 00019 Fmt 4702 Sfmt 4702 9551 capacity-related). We seek comment on whether the Commission should define a common set of categories for use across all RTOs/ISOs and, if so, what categories should be included, or whether it is more appropriate to allow each RTO/ISO to establish a set of appropriate operator-initiated commitment reasons on compliance. In addition, we note that some RTOs/ISOs currently provide more granular or detailed information about the reason for operator-initiated commitments.112 Therefore, we seek comment on whether the proposal provides sufficient transparency, or if more information is needed (e.g., specific constraint name), as well as any potential concerns with requiring additional information (e.g., required software upgrades or impact on operational processes). c. Transmission Constraint Penalty Factors 96. We propose to require that all RTOs/ISOs include certain provisions related to transmission constraint penalty factors in their tariffs because transmission constraint penalty factors can significantly impact market clearing prices. 97. First, we propose to require that all RTOs/ISOs include their transmission constraint penalty factor values in their tariffs. This requirement would only apply to penalty factors used for transmission constraints and would not include other penalty factors used in commitment and dispatch algorithms. If the RTO/ISO uses different transmission constraint penalty factors for different processes, we propose to require that all sets of transmission constraint penalty factors be included in the tariff. For example, if an RTO/ISO uses different transmission constraint penalty factors in its security constrained unit commitment and its security constrained economic dispatch, it should include both sets of transmission constraint penalty factors in its tariff. 98. Second, we propose to require that RTOs/ISOs include in their tariffs an explanation as to if and when transmission constraint penalty factors may be used to set LMPs. If the RTO/ ISO has different processes for allowing transmission constraint penalty factors to set LMPs in different circumstances, this should be explained in the tariff. As part of its explanation, the RTO/ISO should also make clear whether there are any specific restrictions or 112 For example, for real-time commitments made to manage congestion, MISO identifies the specific constraint that prompted the commitment. MISO Report at 60. E:\FR\FM\07FEP1.SGM 07FEP1 9552 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules conditions under which transmission constraint penalty factors are allowed to set LMPs, such as a minimum duration for transmission constraint violations. 99. Finally, if RTOs/ISOs wish to have the flexibility to temporarily change transmission constraint penalty factors to account for changes in system conditions, they must include the procedures for doing so in their tariffs. We also propose to require these procedures to include a requirement that notice of the temporary change be provided to market participants. For example, an RTO/ISO could notify market participants of the temporary change by posting on its Web site. d. Comment Sought on Transmission Outages 100. We seek comment on whether additional reporting of transmission outages should be required. Transmission outages can affect RTO/ ISO commitment and dispatch decisions and resulting market clearing prices, and thus are an important facet of price formation. Though the current record on this issue is limited, we seek comment as to whether additional transparency in this regard would be beneficial to stakeholders and if RTOs/ISOs have any limitations in providing more detailed data in this regard, including any appropriate time lag for reporting. Lhorne on DSK30JT082PROD with PROPOSALS e. Comment Sought on Availability of Market Models 101. Some commenters indicate that distribution of the network model may be limited to certain market participants.113 For the purposes of this NOPR we define network model as the RTO’s/ISO’s model used in its energy management system for the real-time operation of the transmission system (e.g., state-estimation, contingency analysis). We seek comment on whether certain classes of market participants are prohibited from obtaining the network model in certain RTOs/ISOs. Moreover, if there are limitations to which market participants are able to obtain the model, we seek comment on the justification for any such limitations. III. Compliance 102. We propose to require that each RTO/ISO submit a compliance filing within 90 days of the effective date of any eventual Final Rule in this proceeding to demonstrate that it meets the proposed requirements set forth in 113 DC Energy, Inertia Power, and Vitol Comments at 21, 26; Financial Marketers Coalition Comments at 43. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 the Final Rule. We note that this compliance deadline is for RTOs/ISOs to submit proposed tariff changes or otherwise demonstrate compliance with the Final Rule. We understand that implementing the reforms required by any Final Rule in this proceeding may be a complex endeavor. However, we preliminarily find that implementation of these reforms is important to ensure rates are just and reasonable. Therefore, we propose that tariff changes filed in response to a Final Rule in this proceeding must become effective no more than six months after compliance filings are due. 103. We seek comment on whether 90 days is sufficient time for RTOs/ISOs to develop new tariff language in response to the Final Rule. 104. To the extent that any RTO/ISO believes that it already complies with the reforms proposed in this NOPR, the RTO/ISO would be required to demonstrate how it complies in the compliance filing required 90 days after the effective date of any Final Rule in this proceeding. To the extent that any RTO/ISO believes that its existing market rules are consistent with or superior to the reforms adopted in any Final Rule, the Commission will entertain those at that time.114 IV. Information Collection Statement 105. The Paperwork Reduction Act (PRA) 115 requires each federal agency to seek and obtain Office of Management and Budget (OMB) approval before undertaking a collection of information directed to ten or more persons or contained in a rule of general applicability. OMB’s regulations 116 require approval of certain information collection requirements imposed by agency rules. Upon approval of a collection of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of an agency rule will not be penalized for failing to respond to the collection of information 114 See, e.g., Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 825, FERC Stats. & Regs. ¶ 31,384, at P 72 (2016); Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322, at P 4 & n.7, order on reh’g and clarification, Order No. 745–A, 137 FERC ¶ 61,215 (2011), reh’g denied, Order No. 745–B, 138 FERC ¶ 61,148 (2012), vacated sub nom. Elec. Power Supply Ass’n v. FERC, 753 F.3d 216 (D.C. Cir. 2014), rev’d & remanded sub nom. FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760 (2016). 115 44 U.S.C. 3507 (2012). 116 5 CFR 1320 (2016). PO 00000 Frm 00020 Fmt 4702 Sfmt 4702 unless the collection of information displays a valid OMB control number. 106. The reforms proposed in this NOPR would amend the Commission’s regulations to improve the operation of organized wholesale electric power markets operated by RTOs/ISOs. The Commission proposes to require each RTO/ISO that allocates the costs of realtime uplift due to deviations should allocate such real-time uplift costs to only those market participants whose transactions are reasonably expected to have caused the real-time uplift. The Commission also proposes to revise its regulations to enhance transparency by requiring that each RTO/ISO post uplift costs paid (dollars) and operatorinitiated commitments (megawatts) on its Web site; and define in its tariff its transmission constraint penalty factors, as well as the circumstances in which the penalty factors can set locational marginal prices, and any procedure for changing the penalty factors. The reforms proposed in this NOPR would require one-time filings of tariffs with the Commission and potential software upgrades to implement the reforms proposed in this NOPR. The Commission anticipates the reforms proposed in this NOPR, once implemented, would not significantly change currently existing burdens on an ongoing basis. The Commission will submit the proposed reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.117 107. While the Commission expects the adoption of the reforms proposed in this NOPR to provide significant benefits, the Commission understands implementation can be a complex endeavor. The Commission solicits public comments on its need for this information, whether the information will have practical utility, the accuracy of burden and cost estimates, ways to enhance the quality, utility, and clarity of the information to be collected or retained, and any suggested methods for minimizing respondents’ burden, including the use of automated information techniques. 108. Public Reporting Burden Estimate and Information Collection Costs: The Commission believes that the burden estimates that follow are representative of the average burden on respondents, including necessary communications with stakeholders. 117 44 E:\FR\FM\07FEP1.SGM U.S.C. 3507(d). 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules 9553 FERC–516G, AS MODIFIED BY THE NOPR IN DOCKET RM17–2–000 Number of respondents 118 Annual number of responses per respondent Total number of responses Average burden (hours) & cost per response 119 Total annual burden hours & total annual cost Cost per respondent ($) (1) (2) (1) × (2) = (3) (4) (3) × (4) = (5) (5) ÷ (1) Uplift Allocation ........................................ 6 1 6 500; $36,500 Transparency ........................................... 6 1 6 500; $36,500 Cost to Comply: The Commission has projected the total cost of compliance, within Year 1 to be $438,000. After Year 1, the reforms proposed in this NOPR, once implemented, would not significantly change existing burdens on an ongoing basis. Title: FERC–516G, Electric Rate Schedules and Tariff Filings in Docket RM17–2–000. Action: Proposed revisions to an existing information collection. OMB Control No.: TBD. Respondents for this Rulemaking: RTOs/ISOs. Frequency of Information: One-time. Necessity of Information: The Federal Energy Regulatory Commission implements this rule to improve competitive wholesale electric markets in the RTO/ISO regions. Internal Review: The Commission has reviewed the changes and has determined that such changes are necessary. These requirements conform to the Commission’s need for efficient information collection, communication, and management within the energy industry. The Commission has specific, 118 Respondent entities are either RTOs or ISOs. estimated hourly cost (salary plus benefits) provided in this section are based on the salary figures for May 2015 posted by the Bureau of Labor Statistics for the Utilities sector (available at http://www.bls.gov/oes/current/naics2_ 22.htm#00-0000) and scaled to reflect benefits using the relative importance of employer costs in employee compensation from December 2015 (available at http://www.bls.gov/news.release/ ecec.nr0.htm). The hourly estimates for salary plus benefits are: Legal (code 23–0000), $129.12 Computer and Mathematical (code 15–0000), $60.63 Information Security Analyst (code 15–1122), $58.08 Accountant and Auditor (code 13–2011), $53.86 Information and Record Clerk (code 43–4199), $37.75 Electrical Engineer (code 17–2071), $64.29 Economist (code 19–3011), $74.53 Computer and Information Systems Manager (code 11–3021), $91.76 Management (code 11–0000), $89.07 The average hourly cost (salary plus benefits), weighting all of these skill sets evenly, is $73.23. For the calculations here, the Commission rounds it to $73 per hour. Lhorne on DSK30JT082PROD with PROPOSALS 119 The VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 objective support for the burden estimates associated with the information collection requirements. 109. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: DataClearance@ferc.gov, Phone: (202) 502–8663, fax: (202) 273–0873. Comments concerning the collection of information and the associated burden estimate(s) may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. Due to security concerns, comments should be sent electronically to the following email address: oira_submission@ omb.eop.gov. Comments submitted to OMB should refer to FERC–516G and OMB Control No TBD. V. Environmental Analysis 110. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.120 We conclude that neither an Environmental Assessment nor an Environmental Impact Statement is required for this NOPR under section 380.4(a)(15) of the Commission’s regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the FPA relating to the filing of schedules containing all rates and charges for the transmission or sale of electric energy subject to the Commission’s jurisdiction, plus the classification, practices, contracts and regulations that affect rates, charges, classifications, and services.121 120 Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987). 121 18 CFR 380.4(a)(15) (2016). PO 00000 Frm 00021 Fmt 4702 Sfmt 4702 3,000; $219,000 3,000; $219,000 $36,500 36,500 VI. Regulatory Flexibility Act 111. The Regulatory Flexibility Act of 1980 (RFA) 122 generally requires a description and analysis of proposed rules that will have significant economic impact on a substantial number of small entities. The RFA does not mandate any particular outcome in a rulemaking. It only requires consideration of alternatives that are less burdensome to small entities and an agency explanation of why alternatives were rejected. 112. This rule would apply to six RTOs/ISOs (all of which are transmission organizations). The average estimated annual cost to each of the RTOs/ISOs is $73,000. The RTOs/ ISOs are not small entities, as defined by the RFA.123 This is because the relevant threshold between small and large entities is 500 employees and the Commission understands that each RTO/ISO has more than 500 employees. Furthermore, because of their pivotal roles in wholesale electric power markets in their regions, none of the RTOs/ISOs meet the last criterion of the two-part RFA definition of a small entity: ‘‘not dominant in its field of operation.’’ As a result, the Commission certifies that the reforms proposed in this NOPR would not have a significant economic impact on a substantial number of small entities. VII. Comment Procedures 113. The Commission invites interested persons to submit comments on the matters and issues proposed in this document to be adopted, including any related matters or alternative proposals that commenters may wish to 122 5 U.S.C. 601–12 (2012). RFA definition of ‘‘small entity’’ refers to the definition provided in the Small Business Act, which defines a ‘‘small business concern’’ as a business that is independently owned and operated and that is not dominant in its field of operation. The Small Business Administrations’ regulations at 13 CFR 121.201 define the threshold for a small Electric Bulk Power Transmission and Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 632. 123 The E:\FR\FM\07FEP1.SGM 07FEP1 9554 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules discuss. Comments are due April 10, 2017. Comments must refer to Docket No. RM17–2–000, and must include the commenter’s name, the organization they represent, if applicable, and their address. 114. The Commission encourages comments to be filed electronically via the eFiling link on the Commission’s Web site at http://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing. 115. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426. 116. All comments will be placed in the Commission’s public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters. Lhorne on DSK30JT082PROD with PROPOSALS VIII. Document Availability 117. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission’s Home Page (http:// www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 118. From the Commission’s Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 119. User assistance is available for eLibrary and the Commission’s Web site during normal business hours from the Commission’s Online Support at 202– 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202) 502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 List of Subjects in 18 CFR Part 35 Electric power rates, Electric utilities, Reporting and recordkeeping requirements. By direction of the Commission. Issued: January 19, 2017. Nathaniel J. Davis, Sr., Deputy Secretary. Regulatory Text In consideration of the foregoing, the Commission proposes to amend Part 35, Chapter 1, Title 18, Code of Federal Regulations, as follows: PART 35—FILING OF RATE SCHEDULES AND TARIFFS 1. The authority citation for part 35 continues to read as follows: ■ Authority: 16 U.S.C. 791a–825r, 2601– 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. 2. Amend § 35.28, by adding new paragraph (g)(11) to read as follows: ■ § 35.28 Non-discriminatory open access transmission tariff. * * * * * (g) * * * (11) Uplift allocation and transparency—(i) Uplift allocation. Each Commission-approved independent system operator or regional transmission organization that allocates the costs of real-time uplift to deviations must allocate such costs only to those market participants whose transactions are reasonably expected to cause the uplift costs. For purposes of this allocation, deviations are megawatt hour differences between a market participant’s scheduled deliveries or receipts at particular points cleared in the day-ahead market and those amounts actually delivered or received in real-time that are not related to realtime economic or reliability-related operator dispatch instructions. Costs of uplift payments must be allocated to at least two distinct categories: Systemwide capacity and congestion management. For purposes of this allocation, each Commission-approved independent system operator or regional transmission organization must distinguish between deviations that help efforts to address system needs and those that harm efforts to address system needs. A market participant’s net harmful deviations are its harmful deviations less its helpful deviations. Within each uplift category, uplift costs must be allocated to a market participant’s net harmful deviations commensurate with the extent to which those deviations harm efforts to address system needs. Within the system-wide capacity category, a market participant PO 00000 Frm 00022 Fmt 4702 Sfmt 4702 shall be allocated a portion of the total real-time uplift costs incurred to maintain energy and operating reserve requirements in the real-time market based on the net contributions of its deviations to those costs. Within the congestion management category, costs shall be allocated based on whether a market participant’s deviations on net contributed to the real-time congestion at a given constraint. For the purposes of real-time uplift allocated to deviations, a market participant’s deviations must be netted hourly. Realtime uplift allocated to deviations must be settled on an hourly basis. (ii) Transparency—(A) Uplift reporting. Each Commission-approved independent system operator or regional transmission organization must post two reports, at minimum, regarding uplift on a publicly accessible portion of its Web site. Such postings shall be made within 20 calendar days of the end of each month. First, each Commissionapproved independent system operator or regional transmission organization must post uplift, paid in dollars, and categorized by transmission zone, day, and uplift category. Transmission zone shall be defined as the geographic area that is used for the local allocation of charges. Transmission zones with fewer than four resources may be aggregated with a neighboring transmission zone and reported collectively. If, for any given monthly report, only one transmission zone exists and it has fewer than four resources or, if when combined with a neighboring transmission zone, the combined transmission zones still have fewer than four resources, these transmission zones may be omitted from the reporting requirements described in this section. Second, each Commission-approved independent system operator or regional transmission organization must post the resource name and the total amount of uplift paid in dollars aggregated across the month to each resource that received uplift payments within the calendar month. (B) Reporting operator-initiated commitments. Each Commissionapproved independent system operator or regional transmission organization must post operator-initiated commitments in megawatts, categorized by transmission zone and commitment reason, on a publicly accessible portion of its Web site as soon as practicable after the resource has been committed, but no later than four hours after the commitment. Transmission zone shall be defined as a geographic area that is used for the local allocation of charges. (C) Transmission constraint penalty factors. Each Commission-approved E:\FR\FM\07FEP1.SGM 07FEP1 Federal Register / Vol. 82, No. 24 / Tuesday, February 7, 2017 / Proposed Rules independent system operator or regional transmission organization must include, in its tariff, its transmission constraint penalty factor values; the circumstances, if any, under which the transmission constraint penalty factors can set locational marginal prices; and the procedure, if any, for temporarily changing the transmission constraint penalty factor values. Any procedure for temporarily changing transmission constraint penalty factor values must provide for notice of the change to market participants. 9555 Note: The following appendix will not be published in the Code of Federal Regulations. Appendix: List of Short Names/ Acronyms of Commenters Short name/acronym Commenter Appian Way ........................................................ CAISO ................................................................. DC Energy, Inertia Power, and Vitol .................. EEI ...................................................................... EPSA .................................................................. EPSA/IPPNY ....................................................... EPSA/NEPGA ..................................................... EPSA/P3 ............................................................. EPSA/Western Power Trading Forum ................ Energy Storage Association ............................... Entergy ................................................................ Appian Way Energy Partners, LLC. California Independent System Operator Corporation. DC Energy, LLC, Inertia Power, LP, and Vitol Inc. Edison Electric Institute. Electric Power Supply Association. Electric Power Supply Association and Independent Power Producers of New York. Electric Power Supply Association and New England Power Generators Association, Inc. Electric Power Supply Association and PJM Power Providers. Electric Power Supply Association and Western Power Trading Forum. Energy Storage Association. Entergy Services, Inc. commented on behalf of the Entergy Operating Companies (Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy New Orleans, Inc.; and Entergy Texas, Inc.). Exelon Corporation. Financial Marketers Coalition. Golden Spread Electric Cooperative, Inc. ISO New England Inc. Midcontinent Independent System Operator, Inc. Potomac Economics, LLC. Monitoring Analytics, LLC. New York Independent System Operator, Inc. PJM Interconnection, L.L.C. PSEG Companies (Public Service Electric and Gas Company, PSEG Power LLC and PSEG Energy Resources & Trade LLC). Public Interest Organizations. Southwest Power Pool, Inc. XO Energy, LLC. Exelon ................................................................. Financial Marketers Coalition ............................. Golden Spread Electric ....................................... ISO–NE ............................................................... MISO ................................................................... MISO Market Monitor ......................................... PJM Market Monitor ........................................... NYISO ................................................................. PJM ..................................................................... PSEG Companies ............................................... Public Interest Organizations .............................. SPP ..................................................................... XO Energy .......................................................... BILLING CODE 6717–01–P DEPARTMENT OF DEFENSE Department of the Army, U.S. Army Corps of Engineers 33 CFR Part 209 [COE–2016–0016] RIN 0710–AA72 Use of U.S. Army Corps of Engineers Reservoir Projects for Domestic, Municipal & Industrial Water Supply Army Corps of Engineers, DoD. Notice of proposed rulemaking; correction and extension of time for public comments. AGENCY: ACTION: The U.S. Army Corps of Engineers (USACE) is correcting a notice of proposed rulemaking that appeared in the Federal Register of December 16, 2016 and extending the comment period on this rulemaking. DATES: The comment period for the proposed rule published December 16, 2016 at 81 FR 91556 is extended until May 15, 2017. Lhorne on DSK30JT082PROD with PROPOSALS SUMMARY: VerDate Sep<11>2014 13:37 Feb 06, 2017 Jkt 241001 You may submit comments, identified by docket number and/or Regulatory Information Number (RIN) and title, by any of the following methods: Federal eRulemaking Portal: http:// www.regulations.gov. Follow the instructions for submitting comments. Email: WSRULE2016@ usace.army.mil. Include the docket number, COE–2016–0016, in the subject line of the message. Mail: U.S. Army Corps of Engineers, ATTN: CECC–L, U.S. Army Corps of Engineers, 441 G St. NW., Washington, DC 20314. Hand Delivery/Courier: Due to security requirements, we cannot receive comments by hand delivery or courier. FOR FURTHER INFORMATION CONTACT: Technical information: Jim Fredericks, 503–808–3856. Legal information: Daniel Inkelas, 202–761–0345. SUPPLEMENTARY INFORMATION: In response to requests from multiple parties, USACE is extending the time for public comments by 90 days. The date listed in the DATES section by which comments must be received is changed from February 14, 2017 to May 15, 2017. Additionally, the document contained ADDRESSES: [FR Doc. 2017–02332 Filed 2–6–17; 8:45 am] PO 00000 Frm 00023 Fmt 4702 Sfmt 4702 an incorrect docket number in the section. The second docket number referenced in that section, for submission of public comments, is corrected as: COE–2016–0016. ADDRESSES Dated: January 31, 2017. Theodore A. Brown, Chief, Policy and Planning Division, Directorate of Civil Works, U.S. Army Corps of Engineers. [FR Doc. 2017–02415 Filed 2–6–17; 8:45 am] BILLING CODE 3720–58–P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 180 [EPA–HQ–OPP–2015–0032; FRL–9956–86] Receipt of Several Pesticide Petitions Filed for Residues of Pesticide Chemicals in or on Various Commodities Environmental Protection Agency (EPA). ACTION: Notice of filing of petitions and request for comment. AGENCY: This document announces EPA’s receipt of several initial filings of SUMMARY: E:\FR\FM\07FEP1.SGM 07FEP1

Agencies

[Federal Register Volume 82, Number 24 (Tuesday, February 7, 2017)]
[Proposed Rules]
[Pages 9539-9555]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-02332]


=======================================================================
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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM17-2-000]


Uplift Cost Allocation and Transparency in Markets Operated by 
Regional Transmission Organizations and Independent System Operators

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
proposing to revise its regulations to require that each regional 
transmission organization (RTO) and independent system operator (ISO) 
that currently allocates the costs of real-time uplift due to 
deviations should allocate such real-time uplift costs only to those 
market participants whose transactions are reasonably expected to have 
caused the real-time uplift costs. The Commission also proposes to 
revise its regulations to enhance transparency by requiring that each 
RTO/ISO post uplift costs paid (dollars) and operator-initiated 
commitments (megawatts) on its Web site; and define in its tariff its 
transmission constraint penalty factors, as well as the circumstances 
under which those penalty factors can set locational marginal prices, 
and any procedure for changing those factors.

DATES: Comments are due April 10, 2017.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways:
     Electronic Filing through http://www.ferc.gov. Documents 
created electronically using word processing software should be filed 
in native applications or print-to-PDF format and not in a scanned 
format.
     Mail/Hand Delivery: Those unable to file electronically 
may mail or hand-deliver comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT: 
Stanley Wolf (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-6841, Stanley.Wolf@ferc.gov

Keatley Adams (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-8678, Keatley.Adams@ferc.gov
Colin Beckman (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, (202) 502-8049, Colin.Beckman@ferc.gov

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                               Paragraph
 
I. Background...............................................           9
II. Discussion..............................................          12
    A. Uplift Cost Allocation...............................          12

[[Page 9540]]

 
        1. Uplift Cost Allocation Background................          13
        2. Current RTO/ISO Practices........................          16
        3. Comments.........................................          23
            a. Practices for Allocating Uplift Costs to               23
             Deviations.....................................
            b. Virtual Transactions and Uplift..............          27
            c. Coordinated Transaction Scheduling...........          29
            d. Additional Comments..........................          30
        4. Need for Reform..................................          31
        5. Proposal.........................................          35
            a. Real-Time Uplift Categories..................          40
            b. Netting......................................          45
            c. Deviations That Result From Following                  51
             Dispatch.......................................
            d. Settlement...................................          55
            e. Other Comments Sought........................          56
    B. Transparency.........................................          57
        1. Background.......................................          58
        2. Current RTO/ISO Practices........................          59
            a. Reporting Uplift.............................          59
            b. Reporting Operator-Initiated Commitments.....          63
            c. Transmission Constraint Penalty Factors......          66
        3. Comments.........................................          67
            a. General Comments.............................          67
            b. Comments on Uplift Reporting.................          68
            c. Comments on Reporting Operator-Initiated               72
             Commitments....................................
            d. Comments on Transmission Constraint Penalty            75
             Factors........................................
        4. Need for Reform..................................          77
        5. Proposal.........................................          82
            a. Uplift Reporting.............................          83
            b. Reporting Operator-Initiated Commitments.....          90
            c. Transmission Constraint Penalty Factors......          96
            d. Comment Sought on Transmission Outages.......         100
            e. Comment Sought on Availability of Market              101
             Models.........................................
III. Compliance.............................................         102
IV. Information Collection Statement........................         105
V. Environmental Analysis...................................         110
VI. Regulatory Flexibility Act..............................         111
VII. Comment Procedures.....................................         113
VIII. Document Availability.................................         117
 

    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy 
Regulatory Commission (Commission) proposes to revise its regulations 
to address potentially unjust and unreasonable approaches to real-time 
uplift cost allocation and transparency practices by regional 
transmission organizations (RTOs) and independent system operators 
(ISOs).
    2. While the Commission and RTOs/ISOs have taken steps to reduce 
the amount of uplift in the energy and ancillary services markets, the 
complexity inherent in the electric system and limitations in the tools 
available to maintain reliable operations can lead to system operators 
taking out-of-market actions to manage reliability. When they do so, 
energy and ancillary service prices may not reflect the marginal cost 
of production and some resources may therefore need make-whole payments 
to ensure recovery of operating costs. Since the limitations in 
representing the complexity of the electric system in market models are 
unlikely to ever be fully resolved, uplift costs are also unlikely to 
be completely eliminated. As a result, RTOs/ISOs need to have a method 
for allocating these costs to market participants. At the highest 
level, the allocation of uplift costs should, to the extent possible, 
encourage behavior that will reduce the need for uplift-creating 
actions and avoid discouraging market participant behavior that lowers 
total production costs (i.e., enhances efficiency). The reforms 
proposed in this NOPR are designed to achieve these objectives.
    3. Given that RTOs/ISOs are likely going to need to take some out-
of-market actions, there is a need to provide transparency regarding 
those actions and the associated uplift costs. The lack of transparency 
regarding uplift and operator-initiated commitments,\1\ which can cause 
uplift, hinders a market participant's ability to plan and efficiently 
respond to system needs. Market participants may lack the information 
necessary to evaluate the need for and value of additional investment, 
such as transmission upgrades or new generation. Also, without 
sufficient transparency, market participants may not be able to assess 
each RTO's/ISO's operator-initiated commitment practices and raise any 
issues of concern through the stakeholder process. The transparency 
reforms proposed in this NOPR are designed to allow market participants 
to understand the actions RTOs/ISOs are taking and respond accordingly.
---------------------------------------------------------------------------

    \1\ An operator-initiated commitment is a commitment that is not 
associated with a resource clearing the day-ahead or real-time 
market on the basis of economics and that is not self-scheduled. See 
FERC, Operator Initiated Commitments in RTO and ISO Markets, Docket 
No. AD14-14-000 at 8-20 (Dec. 2014), http://www.ferc.gov/legal/staff-reports/2014/AD14-14-operator-actions.pdf.
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    4. First, we preliminarily find that certain practices of 
allocating the cost of real-time uplift \2\ to market participants who 
deviate from day-ahead market schedules (deviations) are inconsistent 
with cost causation, which may distort market outcomes, potentially 
resulting in unjust and unreasonable rates.

[[Page 9541]]

Specifically, some RTO/ISO practices of allocating real-time uplift 
costs to deviations that could not reasonably be expected to have 
caused those uplift costs can distort market outcomes by 
inappropriately penalizing behavior that can improve price formation. 
Therefore, we propose to require that, if an RTO/ISO allocates real-
time uplift costs to deviations, it must do so based on cost causation, 
as further discussed below. For the purposes of allocating uplift costs 
to deviations, we propose that deviations are megawatt hour differences 
between a market participant's scheduled deliveries or receipts at 
particular points--as determined by the day-ahead market clearing 
process--and those amounts actually delivered or received in real-time 
that are not related to real-time economic or reliability-related 
operator dispatch instructions. This proposal would apply only to real-
time uplift cost allocation to deviations. This NOPR does not apply to 
other methods used by RTOs/ISOs to allocate uplift costs. If an RTO/ISO 
does not currently allocate real-time uplift costs to deviations, this 
NOPR does not impose a requirement on those RTOs/ISOs to allocate real-
time uplift costs to deviations.
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    \2\ Real-time uplift refers to uplift payments to resources 
committed after the close of the day-ahead market, including any 
uplift associated with reliability commitments, whether or not the 
RTO/ISO considers such commitments outside of the day-ahead market, 
e.g., the Reliability Unit Commitment or RUC process. As such, 
uplift payments to resources committed in a reliability unit 
commitment process would be considered real-time uplift for the 
purposes of this NOPR).
---------------------------------------------------------------------------

    5. Second, we preliminarily find that current practices with 
respect to reporting uplift payments, operator-initiated commitments, 
and transmission constraint penalty factors \3\ are unjust and 
unreasonable. The lack of transparency into the costs allocated to 
market participants, and into the causes of such costs, hinders the 
ability of market participants to assess the effectiveness of current 
operational practices or to evaluate the need for additional 
investment, such as transmission upgrades or new generation. Similarly, 
the lack of transparency with respect to transmission constraint 
penalty factors may hinder a market participant's ability to 
effectively understand how an RTO's/ISO's actions affect energy prices 
and thus, hinder its ability to hedge energy market transactions. As 
discussed further below, for these reasons we preliminarily find that 
these practices may result in rates that are unjust and unreasonable. 
We therefore propose to require that each RTO/ISO: (1) Report total 
uplift payments for each transmission zone, broken out by day and 
uplift category; (2) report total uplift payments for each resource on 
a monthly basis; (3) report megawatts (MW) of operator-initiated 
commitments in or near real-time and after the close of the day-ahead 
market, broken out by transmission zone and commitment reason; and (4) 
define in its tariff the transmission constraint penalty factors, as 
well as the circumstances under which those factors can set locational 
marginal prices (LMPs), and the process by which they can be changed.
---------------------------------------------------------------------------

    \3\ Transmission constraint penalty factors are the values at 
which an RTO's/ISO's market software will relax the limit on a 
transmission constraint rather than continue to re-dispatch 
resources to relieve congestion associated with that constraint.
---------------------------------------------------------------------------

    6. The goals of the price formation proceeding are to: (1) Maximize 
market surplus for consumers and suppliers; (2) provide correct 
incentives for market participants to follow commitment and dispatch 
instructions, make efficient investments in facilities and equipment, 
and maintain reliability; (3) 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 (4) ensure that all suppliers have an opportunity to 
recover their costs.\4\
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    \4\ See Price Formation in Energy and Ancillary Services Markets 
Operated by Regional Transmission Organizations and Independent 
System Operators, Notice Inviting Post-Technical Workshop Comments, 
Docket No. AD14-14-000, at 1 (Jan. 16, 2015) (Notice Inviting 
Comments); Price Formation in Energy and Ancillary Services Markets 
Operated by Regional Transmission Organizations and Independent 
System Operators, Notice, Docket No. AD14-14-000 (June 19, 2014) 
(Price Formation Notice).
---------------------------------------------------------------------------

    7. The reforms proposed in this NOPR address two of the 
Commission's price formation goals. First, the proposed reforms to 
uplift costs allocated to deviations should improve market 
participants' incentives to perform in real-time consistent with 
operator instructions and bid into the day-ahead market and submit day-
ahead schedules consistent with expected real-time system conditions. 
Second, the proposed transparency reforms will help market participants 
understand how prices reflect the actual marginal cost of serving load 
and the operational constraints of reliably operating the system.
    8. We seek comment on these proposed reforms 60 days after 
publication of this NOPR in the Federal Register.

I. Background

    9. In June 2014, the Commission initiated a proceeding, in Docket 
No. AD14-14-000, Price Formation in Energy and Ancillary Services 
Markets in Regional Transmission Organizations and Independent System 
Operators, to evaluate issues regarding price formation in the energy 
and ancillary services markets operated by RTOs/ISOs (Price Formation 
Proceeding). The notice initiating that proceeding stated that there 
may be opportunities for the RTOs/ISOs to improve the price formation 
process in the energy and ancillary services markets. As set forth in 
the notice, prices used in energy and ancillary services markets 
ideally ``would reflect the true marginal cost of production, taking 
into account all physical system constraints, and these prices would 
fully compensate all resources for the variable cost of providing 
service.'' \5\ Pursuant to the notice, staff conducted outreach and 
convened technical workshops on the following four general issues: (1) 
Use of uplift payments; (2) offer price mitigation and offer price 
caps; (3) scarcity and shortage pricing; and (4) operator actions that 
affect prices.\6\
---------------------------------------------------------------------------

    \5\ Price Formation Notice, Docket No. AD14-14-000, at 2 (June 
19, 2014).
    \6\ Id. at 1, 3-4.
---------------------------------------------------------------------------

    10. In January 2015, the Commission requested comments on questions 
that arose from the price formation technical workshops.\7\ As a result 
of these comments, the Commission identified, among other things, five 
topics with potential for reform to improve price formation, but for 
which further information was needed.
---------------------------------------------------------------------------

    \7\ Notice Inviting Comments, Docket No. AD14-14-000 (Jan. 16, 
2015).
---------------------------------------------------------------------------

    11. In November 2015, the Commission issued an order that directed 
each RTO/ISO to report on these five price formation topics: Fast-start 
pricing; managing multiple contingencies; look-ahead modeling; uplift 
allocation; and transparency.\8\ Specifically, the order directed each 
RTO/ISO to file a report providing an update on its current practices 
in the five topic areas, outlining the status of its efforts (if any) 
to address issues in each of the five topic areas, and responding to 
specific questions contained in the order. In the reports filed and the 
subsequent comments, RTOs/ISOs and other commenters addressed the 
issues of uplift cost allocation and transparency,\9\ which are the 
subject of this NOPR.
---------------------------------------------------------------------------

    \8\ Price Formation in Energy and Ancillary Services Markets 
Operated by Regional Transmission Organizations and Independent 
System Operators, 153 FERC ] 61,221 (2015) (Order Directing 
Reports).
    \9\ A list of commenters and the abbreviated names used in this 
NOPR appears in the Appendix.
---------------------------------------------------------------------------

II. Discussion

A. Uplift Cost Allocation

    12. In this section, we first provide a brief background on uplift 
payments and deviations between day-ahead and real-time schedules as a 
way to determine uplift cost allocation. We

[[Page 9542]]

then review current RTO/ISO practices and comments regarding these 
practices submitted prior to and after the issuance of the Order 
Directing Reports. Finally, we explain the need for reform and set 
forth the proposal in detail.
1. Uplift Cost Allocation Background
    13. Uplift generally refers to payments that RTOs/ISOs make to a 
resource whose commitment and dispatch result in a shortfall between 
the costs in a resource's offer and the revenue earned through market 
clearing prices.\10\ For example, if a resource is committed and is not 
able to fully recover its costs from the energy and ancillary services 
markets, it would receive an uplift payment. As noted in the Staff 
Analysis of Uplift, modeling, software, and certain other limitations 
are inherent in the complexity of the electric system and the tools 
available to maintain reliable operations. As a result, system 
operators may have to take out-of-market actions to manage reliability, 
with resulting energy and ancillary service prices not reflecting the 
marginal cost of production. Uplift, or make-whole, payments may 
therefore be needed to ensure that resources committed and dispatched 
out-of-market are able to recover their operating costs. These 
modeling, software, and other limitations will likely persist, making 
uplift an inherent element of centralized wholesale energy and 
ancillary services markets that may not be completely eliminated. 
Therefore, RTOs/ISOs must have a method to allocate these costs to 
market participants. Generally, RTOs/ISOs allocate uplift costs either 
directly to market participants who caused the uplift or to load. 
Allocation of uplift costs to load is motivated by several 
considerations. Load can be viewed as the ultimate beneficiary of the 
actions the system operator takes to maintain reliability. Further, one 
principle of cost allocation is to allocate costs in a way that is 
least likely to distort market participant behavior. In electricity 
markets, load is the class of market participants that is currently the 
least sensitive to price and for whom an allocation of uplift costs is 
arguably least likely to distort behavior. For shorthand, allocating 
uplift costs to load is referred to as ``beneficiary pays.'' In 
practice, RTOs/ISOs often use a combination of the two approaches, with 
load receiving all of the uplift costs that are not allocated through 
cost-causation methods, such as a deviations-based approach.
---------------------------------------------------------------------------

    \10\ FERC, Staff Analysis of Uplift in RTO and ISO Markets, 
Docket No. AD14-14-000, at 1-2 (Aug. 2014), https://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf.
---------------------------------------------------------------------------

    14. In its Order Directing Reports, the Commission asked the RTOs/
ISOs to explain whether and how the RTO/ISO allocates real-time energy 
and ancillary services market uplift costs based on deviations from 
market participants' day-ahead schedules, and whether deviations that 
increase the need for actions that cause real-time uplift payments 
(harming deviations) are netted against deviations that reduce the need 
for actions that cause real-time uplift payments (helping 
deviations).\11\
---------------------------------------------------------------------------

    \11\ Order Directing Reports, 153 FERC ] 61,221 at P 64, 
question 3.b.
---------------------------------------------------------------------------

    15. In response, most RTOs/ISOs state that they classify certain 
schedule differences between the day-ahead and real-time markets as 
deviations and allocate at least some portion of real-time uplift costs 
to those deviations. Allocation of real-time uplift costs to deviations 
is the focus of this NOPR because deviations may increase the need for 
operator actions that cause real-time uplift, such as additional unit 
commitments in real-time to replace a shortfall in generation or an 
increase in load compared to the day-ahead market solution. This NOPR 
does not address other methods of uplift cost allocation, such as 
allocation to load obligations, and does not propose to require RTOs/
ISOs to allocate real-time uplift costs to deviations.
2. Current RTO/ISO Practices
    16. All of the RTOs/ISOs state that they use some form of 
beneficiary pays or cost-causation principles to allocate uplift 
costs.\12\ However, the current uplift cost allocation methods of the 
RTOs/ISOs vary significantly, both in terms of granularity and the 
exemption of certain types of transactions. The definition of what 
precisely constitutes a deviation also varies across RTOs/ISOs.
---------------------------------------------------------------------------

    \12\ NYISO Report at 45; PJM Report at 28; SPP Report at 19; 
MISO Report at 42; ISO-NE Report at 43; CAISO Report at 35.
---------------------------------------------------------------------------

    17. NYISO generally allocates uplift costs based on the beneficiary 
pays principle.\13\ NYISO allocates uplift costs associated with state-
wide reliability to all loads in the New York Control Area, and 
allocates uplift costs associated with local reliability to load within 
the transmission district where the reliability actions were taken. 
NYISO allocates real-time uplift costs on a beneficiary pays basis to 
load obligations, using real-time metered load during the hours in 
which uplift costs were incurred.\14\ NYISO also explains that it 
eliminated all uplift costs associated with Coordinated Transaction 
Scheduling (CTS) \15\ in a reciprocal fashion with ISO-NE, and that it 
supports the elimination of all uplift cost allocation and fees on 
exports because these fees reduce trade between regions and adversely 
impact total production costs.\16\
---------------------------------------------------------------------------

    \13\ NYISO Report at 46.
    \14\ Id. at 40.
    \15\ CTS is a set of real-time market rules that allow imports 
and exports to be scheduled based on a bidder's willingness to 
purchase energy sourced from one RTO/ISO and sell the energy at a 
sink in another, adjacent RTO/ISO, if the difference between the 
forecasted prices at the sink and source is greater than or equal to 
the dollar value specified in the CTS Interface Bid (spread bid).
    \16\ NYISO Report at 45-46.
---------------------------------------------------------------------------

    18. CAISO explains that it has many categories of uplift, and that 
it allocates uplift costs to transmission owners (who pass uplift costs 
to transmission customers), loads, and exports, depending on whether 
the system operator made the dispatch decision to address transmission 
constraints, energy imbalance, real-time congestion, or bid cost 
recovery.\17\ CAISO asserts that any allocation based on deviations 
should consider the wide variability in scheduling and metering 
granularity for different resources and that there might be 
implementation challenges in a more granular cost allocation.\18\
---------------------------------------------------------------------------

    \17\ CAISO Report at 40-45.
    \18\ Id. at 37.
---------------------------------------------------------------------------

    19. ISO-NE states that roughly half of its uplift costs are 
allocated to deviations, which include generator deviations, load 
deviations, increment (virtual) deviations, and import deviations.\19\ 
ISO-NE calculates each market participant's deviations hourly, netting 
virtual demand bids and deviations from day-ahead load across all 
locations.\20\ However, hourly generator and virtual supply deviations 
are not subject to netting in ISO-NE.\21\ ISO-NE does not allocate 
uplift costs to CTS transactions.\22\
---------------------------------------------------------------------------

    \19\ ISO-NE Report at 54-55.
    \20\ Id. at 50.
    \21\ Id.
    \22\ ISO-NE Report at 53.
---------------------------------------------------------------------------

    20. PJM allocates uplift costs incurred for reasons other than 
reliability to deviations, including cleared virtual bids, transaction 
deviations, and load deviations.\23\ PJM states that it assesses 
deviations daily by netting deviations separately within three 
different categories (demand, supply, and generation) at a single 
transmission zone, hub, or interface.\24\ PJM explains that its current 
netting rule allows a supply or demand deviation from a virtual 
transaction in the day-ahead energy market to be netted against

[[Page 9543]]

internal bilateral transactions \25\ occurring at the same 
location.\26\ PJM does not consider up-to-congestion transactions \27\ 
to be deviations and does not allocate uplift to them.\28\ PJM 
considers CTS transactions (and other imports and exports) to be 
deviations, and allocates uplift to them.
---------------------------------------------------------------------------

    \23\ PJM Report at 30-31.
    \24\ Id. at 31.
    \25\ Internal bilateral transactions are a type of bilateral 
transaction used to purchase or sell one or more electricity market 
product(s) within a region. In all of the RTOs/ISOs, internal 
bilateral transactions are financial agreements that the two parties 
report to the RTO/ISO to streamline accounting and settlement. None 
of the RTOs/ISOs model internal bilateral transactions in the real-
time or day-ahead market, and internal bilateral transactions do not 
affect market dispatch or power flows.
    \26\ PJM Report at 33.
    \27\ An up-to-congestion transaction is a form of virtual 
transaction that combines an offer to sell energy at a source, with 
a bid to buy the same MW quantity of energy at a sink where such 
transaction specifies the maximum difference between the LMP at the 
source and sink.
    \28\ PJM Report at 33.
---------------------------------------------------------------------------

    21. SPP states that it allocates uplift costs based on causation 
when the cause is identifiable and the cost of doing so does not 
outweigh the benefit.\29\ For example, real-time uplift costs are 
allocated to deviations from day-ahead schedules and SPP dispatch 
instructions.\30\ SPP states that virtual transactions are considered 
deviations, but virtual supply offers are netted against a 
countervailing deviation between day-ahead and real-time schedules 
(i.e., a load or export decrease, or import increase, relative to its 
day-ahead schedule) at the same settlement location.\31\
---------------------------------------------------------------------------

    \29\ SPP Report at 20.
    \30\ Id. at 22.
    \31\ Id. at 38.
---------------------------------------------------------------------------

    22. MISO has a granular approach to allocating uplift costs that it 
states is based on determining cost-causation where possible. MISO has 
several categories of uplift, but, for example, MISO's Revenue 
Sufficiency Guarantee uplift category has six different methodologies 
for distributing costs based on the reason a resource was 
committed.\32\ MISO also allocates uplift costs according to a set of 
defined categories based on what MISO determines to be the cause of the 
uplift. Uplift costs resulting from real-time capacity commitments are 
largely allocated to deviations, including physical supply and demand 
deviations, virtual transactions, and import and export physical 
schedules.\33\ A portion of uplift resulting from transmission 
constraint relief is assigned to the deviations that caused the 
congestion.\34\ MISO has also noted that it will not allocate uplift 
costs to CTS between itself and PJM, which is expected to be 
implemented in the spring of 2017.\35\
---------------------------------------------------------------------------

    \32\ MISO Report at 42-43.
    \33\ Id. at 44.
    \34\ Id.
    \35\ Midcontinent Indep. Sys. Operator, Inc., 155 FERC ] 61,038, 
at P 3 (2016).
---------------------------------------------------------------------------

3. Comments
a. Practices for Allocating Uplift Costs to Deviations
    23. Some commenters criticize the practice of allocating uplift 
costs to real-time deviations from day-ahead schedules. For example, 
Appian Way asserts that deviations-based approaches to uplift cost 
allocation create market inefficiencies in the form of unnecessary and 
inappropriate barriers to market participants accessing the spot 
market, and also shift the cost responsibility for uplift from load to 
other market participants.\36\
---------------------------------------------------------------------------

    \36\ Appian Way Comments at 1, 7.
---------------------------------------------------------------------------

    24. Others, however, support allocating uplift costs to deviations 
from day-ahead schedules, but argue that such deviations should be 
netted based on whether they contribute to or alleviate the condition 
causing uplift.\37\ Some commenters contend, for example, that netting 
such deviations is consistent with cost causation principles because it 
ensures that only market participants deviating from their day-ahead 
schedules in a manner that increases uplift payments will incur those 
costs.\38\
---------------------------------------------------------------------------

    \37\ Financial Marketers Coalition Comments at 31.
    \38\ Id. at 14, 31.
---------------------------------------------------------------------------

    25. Multiple commenters also recommend the creation of more 
specific uplift cost allocation categories that are better aligned with 
cost causation. To this end, some commenters suggest creating a 
congestion management category that would distinguish uplift incurred 
for congestion management from uplift incurred for capacity needs or 
voltage and local reliability and allocate uplift costs 
accordingly.\39\
---------------------------------------------------------------------------

    \39\ Id. at 14; XO Energy Comments at 24.
---------------------------------------------------------------------------

    26. MISO Market Monitor asserts that uplift costs should be 
minimized to the extent possible by incorporating reliability 
requirements into market-based products, but any remaining uplift costs 
should then be allocated based on cost causation. MISO Market Monitor 
believes that allocating uplift costs to those that cause it or benefit 
from it gives market participants an incentive to act to minimize it. 
MISO Market Monitor also asserts that MISO's uplift cost allocation 
approach is the best practice in the industry because it determines why 
the uplift was incurred and allocates the costs accordingly.\40\ MISO 
Market Monitor also argues that for both capacity-related and 
congestion-related uplift, cost allocations should be based on 
deviations from the market participants' day-ahead schedules.\41\
---------------------------------------------------------------------------

    \40\ MISO Market Monitor Feb. 24, 2015 Comments at 16-17.
    \41\ Id. at 17.
---------------------------------------------------------------------------

b. Virtual Transactions and Uplift
    27. Allocation of uplift costs to virtual transactions is a 
contentious issue, and commenters hold disparate opinions. Some 
commenters argue that virtual transactions contribute to price 
convergence between the day-ahead and real-time markets, thus reducing, 
rather than increasing, uplift. They also argue that virtual 
transactions are easily forced out of the market by added fees, such as 
uplift. These commenters support either reducing or eliminating the 
allocation of uplift costs to virtual transactions.\42\ For example, XO 
Energy argues that it is unjust and unreasonable to allocate energy 
deviation-related uplift costs to virtual transactions as XO Energy 
asserts these transactions do not impact unit commitment because the 
energy impacts ``net out'' and do not affect the system's power 
balance.\43\
---------------------------------------------------------------------------

    \42\ Appian Way Comments at 10; Financial Marketers Coalition 
Comments at 14-15; XO Energy Comments at 21.
    \43\ XO Energy Comments at 19-21.
---------------------------------------------------------------------------

    28. Other commenters disagree, arguing that virtual transactions 
should be allocated uplift costs because they affect day-ahead 
commitment and dispatch, and thus can impact uplift.\44\ For example, 
PJM states that allocating uplift costs to virtual transactions is 
consistent with cost causation, and that up-to-congestion transactions 
should be allocated uplift costs similar to other virtual transactions, 
although they are not currently allocated such costs.\45\ Several 
commenters also contend that cost allocation rules for virtual 
transactions may need to be revised.\46\ For example, EEI notes that in 
PJM, virtual transactions, including increment offers and decrement 
bids, are allocated uplift costs, while up-to-congestion transactions 
are not. EEI asserts that up-to-congestion transactions should not be 
given preferential treatment and should instead be allocated a share of 
uplift costs.\47\
---------------------------------------------------------------------------

    \44\ PSEG Companies Comments at 10; EEI Comments at 4.
    \45\ PJM Report at 33.
    \46\ EPSA/P3 Comments at 12; DC Energy, Inertia Power, and Vitol 
Comments at 4-5.
    \47\ EEI Comments at 4.

---------------------------------------------------------------------------

[[Page 9544]]

c. Coordinated Transaction Scheduling
    29. CTS transactions are scheduled in real-time by the 
participating RTO/ISOs \48\ based on forecasted prices. CTS is not used 
in all RTO/ISO markets and the allocation of uplift costs to CTS varies 
by market, as described herein. Some RTOs/ISOs, such as MISO, view CTS 
transactions as economically dispatched, similar to the economic 
dispatch of a generator, and therefore do not consider them to be 
deviations for the purpose of allocating uplift costs. NYISO and ISO-NE 
do not allocate uplift costs to CTS transactions between their markets. 
PJM, however, views CTS transactions as deviations, indistinguishable 
in effect from other deviations that cause uplift.
---------------------------------------------------------------------------

    \48\ Currently, CTS is effective between NYISO and ISO-NE and 
NYISO and PJM. MISO and PJM expect to implement CTS in 2017.
---------------------------------------------------------------------------

d. Additional Comments
    30. Commenters also provide feedback on several other market design 
mechanisms related to uplift. For example, several commenters discuss 
the netting of internal bilateral transactions against other deviations 
when allocating uplift costs in PJM. While some advocate eliminating 
this market rule,\49\ others support it, contending that internal 
bilateral transactions are valuable hedging tools which allow market 
participants to counteract a deviation from a virtual transaction in 
the day-ahead market and promote convergence between day-ahead and 
real-time prices.\50\
---------------------------------------------------------------------------

    \49\ PJM Market Monitor Comments at 13; PJM Report at 33; Appian 
Way Comments at 8.
    \50\ EPSA/P3 Comments at 12-13.
---------------------------------------------------------------------------

4. Need for Reform
    31. We preliminarily find that some existing RTO/ISO practices of 
real-time uplift cost allocation to deviations may be unjust and 
unreasonable. Specifically, these real-time uplift cost allocation 
practices may result in unjust and unreasonable rates by allocating 
costs to deviations that could not reasonably be expected to have 
caused those costs. Allocating costs to deviations that did not cause 
these costs can inappropriately penalize certain types of transactions 
that may be beneficial to price formation. We note that the Commission 
is not proposing to require RTOs/ISOs to allocate any amount of uplift 
costs to deviations, rather we are simply proposing reforms to uplift 
cost allocation to deviations to the extent an RTO/ISO chooses to 
allocate some uplift costs to deviations.
    32. While there are several approaches to allocating uplift costs, 
most RTOs/ISOs allocate at least a portion of real-time uplift costs to 
market participants that deviate from their day-ahead market schedules. 
When market participants deviate from their day-ahead schedule, RTOs/
ISOs may have to take actions in real-time to address differences 
between the day-ahead market solution and real-time system conditions. 
These actions, such as committing additional resources, can result in 
real-time uplift costs.
    33. However, RTOs/ISOs do not always consider whether a deviation 
likely contributed to increasing or decreasing real-time uplift costs 
when allocating real-time uplift costs. Deviations from day-ahead 
market schedules that create the need for additional resource 
commitments in real-time tend to increase real-time uplift costs. On 
the other hand, deviations can also contribute to the convergence of 
the day-ahead and real-time markets by helping to ensure that the day-
ahead market solution and the attendant day-ahead schedule reduces the 
need for system operator actions in real-time. If real-time uplift 
costs are assigned improperly, such costs may impact market behavior in 
a manner that limits otherwise beneficial transactions, which in turn 
may distort prices and market outcomes. This distortion can lead to 
increased real-time uplift payments, higher overall costs to consumers, 
and potentially unjust and unreasonable rates.\51\
---------------------------------------------------------------------------

    \51\ FERC, Staff Analysis of Uplift in RTO and ISO Markets, 
Docket No. AD14-14-000, at 5-7 (Aug. 2014), https://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf.
---------------------------------------------------------------------------

    34. Therefore, we preliminarily find unjust and unreasonable real-
time uplift cost allocation rules that fail to distinguish between 
deviations that help converge day-ahead and real-time markets \52\ and 
those that harm efforts to address system needs. Such rules fail to 
appropriately assign real-time uplift costs to market participants that 
are likely to cause such costs and inappropriately deter transactions 
that are likely to minimize these costs.
---------------------------------------------------------------------------

    \52\ Deviations that help converge day-ahead and real-time 
markets are deviations that bring day-ahead and real-time prices, 
commitments, and dispatch closer together.
---------------------------------------------------------------------------

5. Proposal
    35. To remedy the potentially unjust and unreasonable rates 
resulting from allocating real-time uplift costs to deviations in a 
manner inconsistent with cost causation, we propose that, pursuant to 
section 206 of the Federal Power Act,\53\ each RTO/ISO that currently 
allocates real-item uplift costs to deviations must follow the 
practices described below when allocating such costs. Specifically, the 
following practices ensure that if an RTO/ISO chooses to allocate real-
time uplift costs to deviations, it must do so consistent with cost 
causation. Accordingly, we first propose that RTOs/ISOs categorize 
real-time uplift costs allocated to deviations into at least two 
categories based on the reason uplift costs were incurred, a system-
wide capacity category and a congestion management category as 
discussed in more detail below. Second, we propose to require each RTO/
ISO to distinguish between deviations that are ``helping'' to address 
system needs and those that are ``harming'' efforts to address system 
needs. Further, within each uplift category, uplift costs must be 
allocated to a market participant's net ``harming'' deviations, i.e., 
relevant ``harming'' deviations net of relevant ``helping'' deviations. 
Third, we propose to clarify that a resource responding to an RTO/ISO-
initiated real-time dispatch instruction should not be allocated 
deviations-related real-time uplift costs. Finally, we propose that 
real-time uplift costs allocated to deviations must be settled using 
hourly uplift rate calculations. Each proposed practice is described in 
detail below.
---------------------------------------------------------------------------

    \53\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    36. This proposal would apply only to real-time uplift costs 
allocated to deviations. The NOPR does not propose to require that 
RTOs/ISOs allocate uplift costs to deviations, and we recognize that 
there are other methods for allocating uplift costs that are not based 
on deviations, such as allocations based on load obligation. Further, 
we recognize that there are many causes of uplift and this NOPR does 
not propose to address the allocation of all uplift costs. Rather, to 
improve upon existing RTO/ISO cost allocation practices, this NOPR 
addresses the allocation of uplift costs caused by market participants 
that deviate from their day-ahead market schedules.
    37. Most RTOs/ISOs allocate some real-time uplift costs to 
deviations, although their methods for doing so vary. We set forth here 
a definition of deviations to delineate what type of real-time uplift 
cost allocation is the subject of this NOPR. We propose that deviations 
are megawatt hour differences between a market participant's scheduled 
deliveries or receipts at particular points cleared in the day-ahead 
market and those amounts actually delivered or received at those points 
in real-time that are not related to real-time economic or reliability-
related operator dispatch instructions. We propose that, to the

[[Page 9545]]

extent an RTO/ISO allocates real-time uplift costs to deviations, it 
must do so consistent with this proposed definition. We seek comment on 
the proposed definition of deviations.
    38. We propose that if an RTO/ISO allocates real-time uplift costs 
to deviations, it must allocate such costs only to deviations that can 
reasonably be expected to have caused those costs. Real-time uplift 
costs are most likely to be incurred when, for various reasons, the 
day-ahead market clearing process does not schedule sufficient 
resources to satisfy the system's real-time needs, and instead, RTOs/
ISOs must procure additional resources after the day-ahead market has 
cleared. Market participants that deviate from their day-ahead 
schedules will either more closely align the day-ahead market solution 
with actual real-time system needs or contribute to a divergence from 
the day-ahead solution. Scheduling practices that contribute to these 
divergences may require operator actions, such as operator-initiated 
commitments, in real-time.
    39. RTO/ISO day-ahead and real-time price signals provide economic 
incentives to respond to system needs. Allocating real-time uplift 
costs to deviations consistent with cost causation would help ensure 
that real-time uplift cost allocation does not discourage or deter 
behavior that may converge day-ahead and real-time market solutions. By 
eliminating the allocation of real-time uplift costs to transactions 
that are beneficial to meeting system needs, this proposal strengthens 
the economic incentives for market participants to respond to system 
needs. Further, allocating real-time uplift costs consistent with cost 
causation rewards the ability to perform in real-time consistent with 
operator instructions and disciplines forward scheduling practices by 
encouraging market participants to bid into the day-ahead market and 
submit day-ahead schedules consistent with expected real-time system 
conditions.
a. Real-Time Uplift Categories
    40. We propose to require each RTO/ISO to categorize real-time 
uplift costs allocated to deviations into at least two categories based 
on the reason the uplift cost was incurred: (1) A system-wide capacity 
category and (2) a congestion management category. The system-wide 
capacity category would include real-time uplift related to resource 
commitments made to ensure sufficient system-wide online capacity to 
meet energy and operating reserve requirements. The congestion 
management category would include real-time uplift related to resource 
commitments to manage transmission congestion on specific constraints. 
Under this proposal, we require that an RTO/ISO establish at least 
these two categories for real-time uplift cost allocation to 
deviations, but propose to provide flexibility to an RTO/ISO to 
establish additional categories.
    41. We propose distinguishing the two categories, system-wide 
capacity and congestion management. The distinction ensures real-time 
uplift costs are allocated more specifically to the market participant 
that caused the uplift. Two examples illustrate how delineating these 
two categories is consistent with cost causation.
    42. As a first example, consider a market participant that owns a 
generator that in real-time produces less than the output set forth in 
its day-ahead schedule when it did not receive dispatch instructions to 
do so. That generator's deviation impacted the RTO's/ISO's ability to 
maintain real-time energy and operating reserve requirements and 
required a new commitment to make up for the generator's deviation. 
However, absent impacting the power flows on a system constraint, the 
generator did not contribute to congestion on any constraint. Such a 
generator should be allocated real-time uplift costs for capacity but 
not congestion management. The generator caused a need for more 
capacity to come online, but did not cause a need to relieve congestion 
on a constraint.
    43. As a second example, suppose that the same generator is owned 
by a market participant that also serves real-time load. If the market 
participant reduces its real-time load in an amount that equals the 
generator's deviation (i.e., its reduced supply), the market 
participant's behavior on net did not impact the RTO's/ISO's ability to 
maintain real-time energy and operating reserve requirements. However, 
if this behavior--on net--impacts congestion on the system, the market 
participant should be allocated real-time uplift costs related to 
congestion management.
    44. We request comments on whether the proposed reforms should 
recognize the need for regional flexibility with regard to the uplift 
categories. We also request comment on whether other categories should 
be required.
b. Netting
    45. In allocating uplift costs to deviations, we propose to require 
each RTO/ISO to distinguish between deviations that are ``helping'' 
efforts to address system needs and those that are ``harming'' efforts 
to address system needs. The particular system need of relevance will 
depend on the category of uplift costs at issue, as discussed further 
below. Within each uplift category, uplift costs must be allocated to a 
market participant's net ``harming'' deviations, i.e., relevant 
``harming'' deviations net of relevant ``helping'' deviations. Such 
allocation should be commensurate with a market participant's share of 
total net ``harming'' deviations.
    46. Under the proposed system-wide capacity category, a market 
participant would be allocated a portion of the total real-time uplift 
costs incurred to maintain energy and operating reserve requirements in 
the real-time market based on the net contributions of its deviations 
to those costs. This method would require an RTO/ISO to determine if 
each market participant's deviations are, on net, ``helping'', by 
converging the day-ahead scheduled unit commitment and dispatch to the 
unit commitment and dispatch needed to meet real-time energy and 
operating reserve requirements, or if they are ``harming'', by 
exacerbating the difference between the day-ahead scheduled unit 
commitment and dispatch and the unit commitment and dispatch needed to 
meet real-time energy and operating reserve requirements. For example, 
if the system operator committed an additional resource to maintain 
energy and operating reserve requirements in the real-time market, a 
market participant with net deviations that increased demand (or 
decreased supply) would be allocated a portion of real-time uplift 
costs in the system-wide category, while a market participant with net 
deviations that increased supply (or decreased demand) would not.
    47. Under the proposed congestion management category, a market 
participant would be allocated real-time uplift costs if its net 
deviations contributed to a difference between the congestion on a 
specific constraint in the day-ahead market and the real-time 
congestion on that constraint. This method would require an RTO/ISO to 
determine if each market participant's deviations are, on net, 
``helping'', by converging day-ahead and real-time congestion patterns, 
or if they are ``harming'', by exacerbating the difference between day-
ahead and real-time congestion on a constraint. Market participants 
would be allocated real-time uplift costs in this category only if 
their net deviations are harming by contributing to differences between 
day-ahead and real-time congestion on a constraint.

[[Page 9546]]

    48. For netting within this congestion management category, we 
propose to require each RTO/ISO to determine real-time uplift cost 
allocation based on the net impact of a market participant's deviations 
on a constraint. To make this determination, an RTO/ISO should net the 
deviations that relieve real-time congestion on the constraint with 
those that contribute to it.
    49. Deviations caused by non-market transactions (such as internal 
bilateral transactions) would not be netted in either the proposed 
system-wide capacity category or the proposed congestion management 
category because they take place outside of the day-ahead and real-time 
markets. Transactions that take place outside of the markets do not 
affect real-time scheduling or dispatch and therefore should not offset 
transactions that do affect real-time scheduling or dispatch.
    50. We seek comment on whether there should be advanced 
notification requirements in determining helpful deviations. That is, 
is there a period of time prior to the operating hour at which a 
deviation should no longer be considered helpful because notification 
of the deviation was provided to the RTO/ISO too close to the operating 
hour? If so, we seek comment on what the advanced notification 
requirement should be.\54\ Under the proposed definition of deviations, 
transactions related to real-time economic or reliability-related 
operator dispatch instructions would not be used in determining a 
market participant's net deviations for both the system-wide capacity 
and congestion management categories. We also request comment on 
whether and how such transactions should be used to determine a market 
participant's net deviations.
---------------------------------------------------------------------------

    \54\ For example, MISO determines whether a deviation is helpful 
based on whether it occurred before or after a notification deadline 
which is four hours prior to the operating hour. See generally MISO, 
FERC Electric Tariff, Definitions, ``Notification Deadline'', 1.N & 
Real-Time Energy and Operating Reserve Market Settlement Cal, 
40.3.3.
---------------------------------------------------------------------------

c. Deviations That Result From Following Dispatch
    51. Based on the discussion above and consistent with the proposed 
definition of deviations, we clarify that if the RTO/ISO instructs a 
resource to deviate from its day-ahead schedule, be that a market-based 
or out-of-market instruction, that resource would not be regarded as 
deviating for purposes of this NOPR, and should not be allocated real-
time deviation-related uplift costs, because it is helping to address 
differences between the day-ahead market solution and real-time system 
needs.
    52. Consistent with this clarification, first, we propose that an 
RTO/ISO may not allocate deviation-related real-time uplift costs to a 
transaction that is economically evaluated by the RTO/ISO in the real-
time market. Such transactions include real-time energy transactions 
and CTS transactions. Such real-time transactions are responding to 
real-time market price signals and are not deviations for the purposes 
of this NOPR. These transactions are helping to address real-time 
system needs and allocating real-time deviation-related uplift costs to 
such transactions could distort incentives to respond to these signals. 
Conversely, transactions that are not economically evaluated in the 
real-time market and do not have day-ahead schedules, such as self-
scheduled real-time transactions, should be treated as deviations for 
the purposes of allocating real-time deviation-related uplift costs.
    53. Second, consistent with this clarification, we further propose 
that instructed deviations (those initiated by the RTO/ISO) are not 
deviations for the purposes of allocating real-time uplift costs, and 
therefore, an RTO/ISO may not allocate real-time uplift costs based on 
deviations that result from a market participant following a 
reliability- related dispatch instruction. Following such a dispatch 
instruction, by definition, helps the system. Allocating real-time 
uplift costs to market participants who follow dispatch instructions 
unfairly penalizes market participants that are responding to system 
needs in real-time. Further, assessing real-time uplift costs to such 
deviations could discourage a market participant from following 
dispatch instructions. At times of system stress, it is essential that 
resources follow dispatch instructions. For instance, an RTO/ISO may 
issue out-of-market dispatch instructions or deploy reserves to address 
immediate reliability issues. A resource that responds to such an RTO/
ISO instruction performs an essential reliability function and should 
not be allocated real-time deviation-related uplift costs for following 
the dispatch instruction.
    54. By excluding instructed deviations from the definition of a 
deviation, the Commission is also proposing that instructed deviations 
would not be used in any `helping' and `harming' netting process. We 
seek comment on whether instructed deviations should be included in any 
netting calculations.
d. Settlement
    55. Regarding settlement of uplift costs, under both the system-
wide capacity category and the congestion management category, we 
propose to require RTOs/ISOs to allocate and net real-time uplift costs 
on an hourly basis. RTOs/ISOs typically allocate uplift costs either 
hourly or daily. Hourly allocation would most closely align the 
imposition of costs with the incentives to behave efficiently in the 
market, since the costs of real-time uplift and the actions that cause 
that real-time uplift can and usually do change from hour to hour. 
Under hourly cost allocation, the costs for real-time uplift during a 
particular hour are allocated only to those market participants that 
contribute to the need for that uplift in that hour.
e. Other Comments Sought
    56. We recognize that considering real-time uplift cost allocation 
to deviations for system-wide capacity and congestion management 
separately may require a method for dividing costs between the two 
categories for circumstances in which real-time uplift is incurred for 
the benefit of both categories (e.g., committing a unit to relieve 
transmission congestion will also impact system-wide capacity 
requirements). We seek comment on the best methods to quantify this 
impact and to perform the appropriate cost allocation. We also seek 
comment on the process for netting of transactions and deviations set 
forth in the proposal for each category. Finally, we seek comment on 
the clarifications provided herein regarding those transactions that 
should not be considered deviations for the purpose of real-time uplift 
cost allocation and whether there are additional transactions that 
should be included in this category.

B. Transparency

    57. In this section, we first provide a brief background on the 
benefits of transparency in the wholesale electric power markets 
operated by RTOs/ISOs with respect to reporting uplift, operator-
initiated commitments, and transmission constraint penalty factors. We 
then review current RTO/ISO practices with regard to reporting uplift 
and operator-initiated commitments, and summarize comments on 
transparency requirements, frequency of reporting, type of uplift 
information to be reported, inclusion of reasons for uplift or 
operator-initiated commitments, granularity with respect to location, 
and the inclusion of transmission constraint penalty factors in RTO/ISO 
tariffs. Then, we explain the

[[Page 9547]]

need for the reform regarding reporting of uplift, operator-initiated 
commitments, and transmission constraint penalty factors. Finally, we 
request comment on two additional topics: Reporting of transmission 
outages and availability of network models.
1. Background
    58. Visibility into the process by which prices are developed in 
energy and ancillary services markets supports the functioning of 
efficient markets by enhancing predictability, identifying system 
needs, and facilitating investment decisions. Moreover, understanding 
how RTOs/ISOs calculate prices and how events impact those prices is 
critical to hedging, investment, and resource entry and exit decisions. 
While all RTOs/ISOs release some information, either through periodic 
reports or making data available on their Web sites, as discussed 
below, there is significant variation in the timing, granularity, and 
types of data released.
2. Current RTO/ISO Practices
a. Reporting Uplift
    59. All RTOs/ISOs report information about uplift payments. 
However, the extent of the information reported varies widely. For 
example, ISO-NE and NYISO provide monthly reports of uplift that 
generally provide information that is aggregated across zones and over 
the month.\55\ NYISO also makes aggregated uplift costs (in dollars) 
available to stakeholders on a daily basis through its daily 
reconciliation reports.\56\ MISO provides a number of monthly reports 
to market participants on categories of uplift costs; the reports 
aggregate the uplift data by category by month and provide historical 
monthly data for comparison.\57\ CAISO aggregates uplift data to its 10 
existing local capacity requirement areas and reports daily total 
uplift costs for each month by the market in which the uplift is 
incurred (e.g., day-ahead or real-time), and by the type of costs 
incurred, i.e., start-up costs, minimum load costs or energy bid 
costs.\58\ PJM has recently adopted new rules to allow the reporting of 
daily uplift information by transmission zone, with certain exceptions 
for confidentiality reasons.\59\ SPP provides uplift information in a 
report that divides uplift costs into seven categories.\60\
---------------------------------------------------------------------------

    \55\ ISO-NE Report at 60; NYISO Report at 56-57.
    \56\ NYISO Report at 59.
    \57\ MISO Report at 60.
    \58\ CAISO Report at 56.
    \59\ PJM, Business Practice Manual 33: Administrative Services 
for the PJM Interconnection Operating Agreement at 23-24.
    \60\ SPP Report at 40.
---------------------------------------------------------------------------

    60. RTO/ISO reporting practices are driven, in part, by the time 
needed to complete the settlement process. Some settlement periods last 
three to five business days and CAISO provides uplift cost information 
based on its 12-business day recalculation statement, although the 
settlement period is shorter.\61\ Because of this lag, RTOs/ISOs 
typically report uplift on a monthly basis, with the information 
aggregated to a zonal or settlement area level.
---------------------------------------------------------------------------

    \61\ ISO-NE Report at 64-65; PJM Report at 51; CAISO Report at 
58.
---------------------------------------------------------------------------

    61. Most RTOs/ISOs cite confidentiality issues as an additional 
reason for their current reporting practices, particularly in regions 
with few market participants.\62\ Uplift information is typically 
aggregated to avoid publishing information for individual resources. 
All RTOs/ISOs assert that they are prohibited from publicly revealing 
resource-specific data, as specified in their confidentiality 
rules.\63\ Some RTOs/ISOs note that they cannot provide information on 
a more granular basis without changes to their confidentiality rules or 
information policies.\64\
---------------------------------------------------------------------------

    \62\ PJM Report at 48, 54-55; SPP Report at 41, 44; ISO-NE 
Report at 61, 67; NYISO Report at 60.
    \63\ CAISO Report at 59; NYISO Report at 58; PJM Report at 50-
51; SPP Report at 42; ISO-NE Report at 63-64; MISO Report at 58-59.
    \64\ PJM Report at 48; ISO-NE Report at 61.
---------------------------------------------------------------------------

    62. It is worth noting that market participants with market-based 
and traditional cost of service rate authority are required to report 
uplift payments in the Electric Quarterly Report (EQR). Pursuant to EQR 
reporting requirements, uplift payments are required to be reported at 
a granular level. Those reporting requirements require market 
participants to report when the uplift payment changes. Because many 
resources are commercially organized as stand-alone limited liability 
corporations, many individual resources report uplift payments to EQR 
within 30 days following the end of a quarter. While EQR provides a 
significant amount of information, it does not provide detailed 
information regarding uplift. For example, EQR contains only a single 
``uplift'' category which does not differentiate between different 
types of uplift (e.g., day-ahead, voltage and local reliability).
b. Reporting Operator-Initiated Commitments
    63. RTOs/ISOs also vary in the amount, granularity, and timing of 
information that is reported on operator-initiated commitments. For 
example, CAISO, MISO, and NYISO provide information regarding operator-
initiated commitments either shortly after the operating day or in near 
real-time. CAISO and MISO both report total operator-initiated 
commitments aggregated across the RTO/ISO, including the reasons for 
the commitments.\65\ MISO provides its reports in near real-time, while 
CAISO releases its report several days after the operating day. 
Throughout the operating day, NYISO posts operational announcements 
providing information about individual operator-initiated commitments, 
including the units involved, level of unit commitment, and the reason 
for the commitment, with a reference to the relevant reliability rule, 
if applicable.\66\
---------------------------------------------------------------------------

    \65\ MISO Report at 60; CAISO, Daily Exceptional Dispatch 
Report, http://www.caiso.com/market/Pages/DailyExceptionalDispatch/Default.aspx.
    \66\ NYISO Report at 56-57 and n.32.
---------------------------------------------------------------------------

    64. In addition, all RTOs/ISOs provide summary reports of operator-
initiated commitments over longer time periods. CAISO's monthly 
performance report provides metrics on exceptional dispatch \67\ and 
operator-initiated commitments organized by market (i.e., day-ahead or 
real-time), trade date, reason, or local area.\68\ CAISO also files a 
monthly report on the frequency and volume of exceptional dispatch, 
pursuant to directives in previous Commission orders.\69\ ISO-NE 
publishes weekly, monthly, and quarterly reports that describe notable 
operational events, but it does not provide any information regarding 
the location or capacity of committed units.\70\ ISO-NE also reports 
the number of units committed after the close of the day-ahead market 
(but not including real-time commitments) each day.\71\ SPP reports 
monthly the MW of operator-initiated commitments.\72\
---------------------------------------------------------------------------

    \67\ CAISO states that its system operator issues exceptional 
dispatches to resources to address system issues that cannot be 
addressed by the constraints modeled within the market. CAISO Report 
at 41.
    \68\ Id. at 56.
    \69\ Id. See also Cal. Indep. Sys. Operator Corp., 131 FERC ] 
61,100 (2010) (clarifying the reporting timeline for reporting 
exceptional dispatches).
    \70\ ISO-NE Report at 60.
    \71\ Id. at 61-62.
    \72\ SPP Report at 40.
---------------------------------------------------------------------------

    65. PJM states that, although its confidentiality provisions 
prevent it from reporting individual operator-initiated commitments in 
real-time, it

[[Page 9548]]

does provide regionally aggregated information on uneconomic 
commitments in the day-ahead market at the end of the business day. In 
addition, PJM posts total capacity committed during the Reliability 
Assessment and Commitment period to meet forecasted load and reserves, 
as well as resources committed for transmission constraints, voltage/
reactive constraints, or conservative operations.\73\ ISO-NE also 
states its confidentiality provisions prohibit reporting of operator-
initiated commitments in real-time, while CAISO states providing 
information about exceptional dispatches more frequently than monthly 
would require significant changes to its systems.\74\ SPP states it is 
technically feasible to report commitments resulting from operator 
actions in real-time, but notes such reporting could disclose sensitive 
reliability information.\75\
---------------------------------------------------------------------------

    \73\ PJM Report at 49-50.
    \74\ ISO-NE Report at 65; CAISO Report at 58, 62.
    \75\ SPP Report at 41.
---------------------------------------------------------------------------

c. Transmission Constraint Penalty Factors
    66. Transmission constraint penalty factors are the values at which 
an RTO's/ISO's market software will relax the flow-based limit on a 
transmission element to relieve a constraint caused by that limit 
rather than re-dispatch resources to relieve the constraint. The cost 
of re-dispatching resources can be regarded as the re-dispatch price. 
Transmission constraint penalty factors represent the maximum re-
dispatch price that the system will pay before allowing flows to exceed 
a given transmission element's limit.\76\ The penalty factors should be 
set at levels that are high enough to avoid relaxing constraints too 
frequently, but low enough to avoid extremely expensive re-dispatch 
solutions that are more expensive than the expected cost of exceeding a 
given transmission element's limit. While these penalty factors can 
have significant impacts on prices, changes are not always made public 
nor do all RTOs/ISOs file them with the Commission. Specifically, PJM 
and ISO-NE do not include transmission constraint penalty factors in 
their respective tariffs.\77\ Further, MISO is the only RTO/ISO that 
details in its tariff how transmission constraint penalty factors are 
temporarily changed.\78\
---------------------------------------------------------------------------

    \76\ Transmission constraint penalty factors create a cap on the 
shadow price of a transmission constraint. See MISO Market Monitor 
Comments, Docket No. AD14-14-000, at 20-21 (Feb. 24, 2015).
    \77\ CAISO, MRTU Tariff 27.4.3.1-27.4.3.3; SPP, OATT, Sixth 
Revised Volume No. 1, Attachment AE, 8.3.2, Addendum 1; NYISO 
Tariffs, NYISO Markets and Services Tariff 1.20; MISO, FERC Electric 
Tariff, Schedule 28A.
    \78\ MISO, FERC Electric Tariff, Schedule 28A.
---------------------------------------------------------------------------

3. Comments
a. General Comments
    67. Various commenters recommend reporting of uplift and operator-
initiated commitments that is more regular, more geographically 
granular, more specific about the size of the action (in MW), and/or 
more informative of the reason for uplift or operator action. Numerous 
commenters argue that such reporting about uplift and operator-
initiated commitments should be mandatory.\79\ Exelon urges the 
Commission to require RTOs/ISOs to identify out-of-market actions and 
the resulting uplift in regular reports.\80\ Several commenters propose 
that RTOs/ISOs be required to post information in a way that is 
uniform, consistent, and comparable across RTOs/ISOs.\81\
---------------------------------------------------------------------------

    \79\ DC Energy, Inertia Power, and Vitol Comments at 18; EPSA 
Comments (on MISO Report) at 22; EPSA/NEPGA Comments at 14; Energy 
Storage Association Comments at 2-3; Exelon Comments at 17-18; PSEG 
Companies Comments at 16.
    \80\ Exelon Comments at 17-18.
    \81\ DC Energy, Inertia Power, and Vitol Comments at 18; EPSA 
Comments (on price formation) at 22; EPSA Comments (on MISO Report) 
at 22; EPSA/IPPNY Comments at 13; EPSA Comments (on SPP Report) at 
10; EPSA/NEPGA Comments at 14-15; EPSA/P3 Comments at 15; EPSA/WPTF 
Comments at 10.
---------------------------------------------------------------------------

b. Comments on Uplift Reporting
    68. In terms of frequency, some commenters recommend monthly 
reporting of uplift to improve transparency.\82\ Energy Storage 
Association requests that RTOs/ISOs provide daily summary data on 
uplift credits. Energy Storage Association asserts that such 
information should, at a minimum, be at a zonal level and should be 
made available by all RTOs/ISOs several days after the operating 
day.\83\
---------------------------------------------------------------------------

    \82\ EPSA Comments (on MISO Report) at 21-22; EPSA/NEPGA 
Comments at 13.
    \83\ Energy Storage Association Comments at 2-3.
---------------------------------------------------------------------------

    Several commenters request more granular locational information 
regarding uplift.\84\ These commenters argue that it is difficult to 
reduce or eliminate uplift when market participants do not know where 
it originates. To address this request, many commenters, including 
CAISO, ISO-NE, and PJM, support reporting uplift on a zonal basis.\85\ 
CAISO, ISO-NE, and PJM state that zonal reporting strikes a balance 
between granularity and confidentiality.\86\ In contrast, SPP and MISO 
caution that reporting uplift on a zonal basis could reveal sensitive 
market participant information.\87\
---------------------------------------------------------------------------

    \84\ Financial Marketers Coalition Comments at 45; Energy 
Storage Association Comments at 6; Golden Spread Comments at 8-9.
    \85\ Financial Marketers Coalition Comments at 45; Energy 
Storage Association Comments at 6; PJM Market Monitor Comments at 
20; CAISO Report at 61; PJM Report at 52; ISO-NE Report at 64, 66.
    \86\ PJM Report at 53; ISO-NE Report at 66; CAISO Report at 61.
    \87\ MISO Report at 60-61; SPP Report at 43.
---------------------------------------------------------------------------

    69. Commenters have differing views on what uplift information 
should be reported. PSEG Companies argue that uplift can be effectively 
reported on a dollar basis.\88\ Energy Storage Association states that 
RTOs/ISOs should share daily summary data on uplift in dollars, 
including the reasons for the uplift and the location (at a minimum at 
a zonal level) of the resources that receive it.\89\ The PJM Market 
Monitor recommends reporting uplift charges by resource as well as 
detailed reasons for incurring uplift.\90\ EPSA and EPSA/NEPGA 
recommend reporting the settled uplift dollar impact on a MW basis, as 
well as the reasons for out-of-market commitments every month.\91\ EPSA 
asserts that reporting additional information on the drivers of uplift 
and out-of-market dispatch can be made public without compromising 
sensitive information, because NYISO currently does so in monthly 
reports.\92\
---------------------------------------------------------------------------

    \88\ PSEG Companies Comments at 12, 15-16.
    \89\ Energy Storage Association Comments at 2.
    \90\ PJM Market Monitor Comments at 20-21.
    \91\ EPSA and its joint commenters support several variations of 
``reporting actual settled uplift dollar impacts, on a Megawatt (MW) 
basis.'' It is unclear whether this is referring to reporting uplift 
dollars divided by the total capacity of resources that receive 
uplift payments, or reporting the total capacity of committed 
resources in lieu of identifying specific units. EPSA Comments (on 
price formation) at 23; EPSA Comments (on MISO Report) at 21-22; 
EPSA/NEPGA Comments at 13.
    \92\ EPSA Comments (on price formation) at 23.
---------------------------------------------------------------------------

    70. EPSA/IPPNY warns that reporting uplift more frequently than 
daily could potentially reveal confidential information.\93\ Energy 
Storage Association suggests that, given confidentiality concerns, the 
Commission could allow an RTO/ISO to request an exemption from 
reporting zonal or locational information in certain situations where 
there are few participants in a zone or location.\94\ ISO-NE and MISO 
suggest that the level of aggregation be adjusted to ensure that 
confidentiality is maintained.\95\
---------------------------------------------------------------------------

    \93\ EPSA/IPPNY Comments at 12-13.
    \94\ Energy Storage Association Comments at 3.
    \95\ ISO-NE Report at 66; MISO Report at 61.
---------------------------------------------------------------------------

c. Comments on Reporting Operator-Initiated Commitments
    71. Several commenters recommend monthly reporting of operator-
initiated actions, including the reasons for out-of-market actions, to 
improve

[[Page 9549]]

transparency.\96\ Commenters argue that understanding the reasons for 
out-of-market commitments will help market participants discern what 
types of investments are needed to meet system needs.\97\ Moreover, the 
Financial Marketers Coalition states that, when out-of-market 
commitments are identified by location and explained, financial 
participants will refrain from bidding because they know that prices 
will not converge and uplift is likely.\98\
---------------------------------------------------------------------------

    \96\ EPSA Comments (on MISO Report) at 21-22; EPSA/NEPGA 
Comments at 13; Exelon Comments at 18; EPSA Comments (on price 
formation) at 23 EPSA/IPPNY Comments at 13; EPSA/P3 Comments at 15-
16.
    \97\ EPSA Comments (on price formation) at 23; EPSA/P3 Comments 
at 15-16.
    \98\ Financial Marketers Coalition Comments at 42.
---------------------------------------------------------------------------

    72. Some commenters also suggest that RTOs/ISOs report operator-
initiated commitments closer to real-time. In particular, PSEG 
Companies suggest that NYISO's approach to disclosing out-of-market 
commitment and dispatch decisions should be considered a best 
practice.\99\
---------------------------------------------------------------------------

    \99\ PSEG Companies Comments at 11.
---------------------------------------------------------------------------

    74. Several commenters request more granular locational information 
regarding out-of-market operator actions.\100\ PSEG Companies note that 
when RTOs/ISOs provide only aggregated data, it is not possible to 
discern whether the RTO/ISO needed those units or how many MW were 
actually required.\101\
---------------------------------------------------------------------------

    \100\ Financial Marketers Coalition Comments at 45 (referring to 
SPP); Energy Storage Association Comments at 6 (referring to MISO 
and SPP); Golden Spread Comments at 8-9.
    \101\ PSEG Companies Comment at 14.
---------------------------------------------------------------------------

d. Comments on Transmission Constraint Penalty Factors
    75. The MISO Market Monitor asserts that transmission constraint 
penalty factors substantially affect market outcomes but are not filed 
with or approved by the Commission for some RTOs/ISOs. MISO Market 
Monitor adds that increasing transmission constraint penalty factors 
during real-time operations to relieve constraints may indicate that 
constraints were undervalued previously, and lowering transmission 
constraint penalty factors during real-time operations may indicate 
that the RTO/ISO is attempting to manually reduce congestion costs. 
MISO Market Monitor contends that these concerns can be addressed by: 
(1) Establishing parameters that reflect the reliability value of 
managing the constraints, which likely varies by constraint; (2) filing 
these values in the RTO's/ISO's tariffs so they are known and approved 
by the Commission; and (3) filing tariff provisions that specify the 
procedures and authority for RTOs/ISOs to modify transmission 
constraint penalty factors.\102\
---------------------------------------------------------------------------

    \102\ Comments of MISO Market Monitor, Docket No. AD14-14-000, 
at 20-21 (Feb. 24, 2015).
---------------------------------------------------------------------------

    76. XO Energy states that transmission constraint penalty factors 
can have a significant impact on prices; however, there is not 
necessarily clear insight as to how transmission constraint penalty 
factors are determined or calculated in the pricing and dispatch 
algorithms.\103\ XO Energy contends that, in some cases, the default 
transmission constraint penalty factors can be arbitrarily assigned and 
modified on a case-by-case basis.\104\
---------------------------------------------------------------------------

    \103\ XO Energy Comments at 67-68.
    \104\ Id. at 68.
---------------------------------------------------------------------------

4. Need for Reform
    77. We preliminarily find that some existing RTO/ISO practices of 
reporting uplift, operator-initiated commitments, and transmission 
constraint penalty factors may result in unjust and unreasonable rates. 
The lack of transparency regarding uplift and operator-initiated 
commitments, which can cause uplift, hinders market participants' 
ability to plan and efficiently respond to system needs. Market 
participants may lack the information necessary to evaluate the need 
for and value of additional investment, such as transmission upgrades 
or new generation. Also, without sufficient transparency, market 
participants may not be able to assess each RTO's/ISO's operator-
initiated commitment practices and raise any issues of concern through 
the stakeholder process.
    78. Reporting that specifies the location and causes of uplift and 
operator-initiated commitments will help incent appropriate market 
responses to system needs. For example, if resources are routinely 
committed out-of-market to resolve a local voltage issue and require 
uplift payments as a result, it may be beneficial to release 
information on the uplift associated with using such resources to alert 
market participants about the problem. Providing more detailed 
information about the uplift incurred to address a local reliability 
issue could potentially incent market participants to advocate for 
changes to the RTO/ISO's operational procedures or to undertake 
investments that could resolve the local reliability issue more 
efficiently (e.g., install additional capacitors).
    79. While all RTOs/ISOs provide some information regarding the 
locations and causes of uplift and operator-initiated commitments, the 
information is often highly aggregated or lacks detail, limiting its 
usefulness. Information about the location and causes of uplift and 
operator-initiated commitments that is overly aggregated or lacks 
detail hinders the ability of a market participation to evaluate RTO/
ISO operating practices and potentially respond to system needs by 
undertaking new investments. For example, reports that aggregate uplift 
payments over the month may not provide sufficient information, since 
monthly reports can obscure daily trends, which may be more relevant to 
those evaluating operating practices or potential investments. 
Therefore, increasing transparency with respect to the location and 
cause of uplift can provide market participants additional information 
to evaluate the effectiveness of current operating practices. Without 
sufficient information to evaluate existing operating practices or the 
need for additional investment, market efficiency may be reduced, 
resulting in unjust and unreasonable rates. Allowing market 
participants to better evaluate the need for changes in operating 
practices or additional investment could ultimately reduce the level of 
uplift, thereby resulting in rates that are just and reasonable.
    80. Similarly, the lack of transparency with respect to 
transmission constraint penalty factors may hinder the ability of 
market participants to undertake efficient transactions. For example, 
if market participants are unaware of what transmission constraint 
penalty factors are used and whether they will be used to set LMPs, 
market participants may not be able to adequately understand how an 
RTO's/ISO's actions affect clearing prices and thus may not be able to 
hedge transactions appropriately or effectively assess the RTO's/ISO's 
actions and raise concerns through the stakeholder process. Without the 
ability to appropriately hedge transactions, market participants may 
either over-hedge or under-hedge their positions, reducing market 
efficiency. Also, if market participants are not able to raise concerns 
about changes in transmission constraint penalty factors, RTOs/ISOs may 
alter transmission constraint penalty factors more often than 
necessary, which impacts market clearing prices. Therefore, the 
resulting rates may be unjust and unreasonable.
    81. Some RTOs/ISOs report that there are a variety of stakeholder 
initiatives and discussions underway to improve transparency,\105\ 
while others do not

[[Page 9550]]

mention any specific plans.\106\ Despite these efforts, it is not clear 
that the transparency concerns discussed in this NOPR will be addressed 
through existing stakeholder initiatives. Accordingly, we preliminarily 
find that some existing RTO/ISO practices with respect to reporting 
uplift, operator-initiated commitments, and transmission constraint 
penalty factors may be unjust and unreasonable.
---------------------------------------------------------------------------

    \105\ CAISO Report at 55; MISO Report at 56; NYISO Report at 55; 
PJM Report at 47.
    \106\ ISO-NE Report at 59; SPP Report at 39.
---------------------------------------------------------------------------

5. Proposal
    82. To remedy these potentially unjust and unreasonable reporting 
practices, we propose, pursuant to section 206 of the Federal Power 
Act, to require that each RTO/ISO: (1) Report total uplift payments for 
each transmission zone on a monthly basis, broken out by day and uplift 
category; (2) report total uplift payments for each resource on a 
monthly basis; (3) report the MW of operator-initiated commitments in 
or near real-time and after the close of the day-ahead market, broken 
out by zone and commitment reason; and (4) list in its tariff the 
transmission constraint penalty factors, the circumstances under which 
they can set LMPs, and the procedure by which they can be temporarily 
changed.
a. Uplift Reporting
    83. We propose to require that, within 20 days of the end of each 
month, each RTO/ISO post on its Web site two reports, at minimum, 
regarding uplift payments. First, the RTO/ISO should report the total 
uplift payments in dollars paid daily to the resources in each 
transmission zone, subject to certain exceptions described below. Each 
RTO/ISO must post the total amount of uplift in dollars in each 
category (e.g., day-ahead, real-time, voltage and local reliability) 
paid to resources in each transmission zone for each day within the 
calendar month. We propose to require that each RTO/ISO post uplift 
payment amounts based on its specific uplift categories to allow market 
participants to distinguish between different types of uplift. Second, 
each RTO/ISO must post the resource name and the total amount of uplift 
paid in dollars aggregated across the month to each resource that 
received uplift payments within the calendar month. We seek comment on 
whether these resource-specific reports should also be broken out by 
uplift category, be reported using a different time duration, or 
contain other additional details.
    84. Information on uplift payments should be posted in a machine 
readable format on a publicly accessible portion of the RTO's/ISO's Web 
site. With this information, market participants may be able to 
evaluate possible solutions to reduce the incurrence of uplift. For 
example, with more granular information on the location, amounts, and 
types of uplift, market participants can better evaluate the benefits 
of additional transmission upgrades that could reduce the need for unit 
commitments.
    85. We also propose to define ``transmission zone'' as a geographic 
area that is used for the local allocation of charges. For example, 
this could include a load zone that is used to settle charges for 
energy. We request comments on this proposed definition of transmission 
zone, including the appropriate level of geographic granularity.
    86. Regarding the timeliness of posting this information, we 
recognize that each RTO/ISO has a different settlement window and 
uplift is finalized during the settlement process. As such, it is not 
possible for an RTO/ISO to release information immediately at the end 
of the month. In order to account for differences in settlement periods 
and the time necessary to prepare the uplift data for publication, we 
propose to require that both reports described above be released no 
later than 20 calendar days following the end of the month. While we 
believe this is a reasonable timeframe for release, we seek comment on 
the timeframe for releasing the information after the end of each 
month. In addition, we seek comment on the proposed requirement for a 
daily breakdown of uplift categories by charge code, including any 
obstacles or difficulties related to such reporting and whether 
different categorizations would be more useful.
    87. Many commenters express concern that greater transparency in 
uplift reporting could unintentionally disclose a resource's uplift 
payments or energy offers, which some characterize as confidential or 
commercially-sensitive information. Commenters' core concerns appear to 
relate to two issues: first, that disclosing a resource's uplift 
payments will allow other market participants to calculate energy 
offers and may result in collusion between market participants.\107\ 
Second, commenters appear to be concerned that revealing uplift 
payments may put a resource at a competitive disadvantage by disclosing 
commercially sensitive information like fuel procurement strategies.
---------------------------------------------------------------------------

    \107\ In conjunction with other information, uplift payments 
could potentially be used to determine a resource's energy offers. 
For example, if a market participant knew a resource's output, LMP, 
and uplift payments, it could potentially calculate the resource's 
energy offer because the uplift would make the resource whole up to 
its offer costs.
---------------------------------------------------------------------------

    88. While we understand the need to protect certain types of 
information, we are not persuaded that revealing a resource's daily 
uplift payments or energy offer, after some minimal time lag, would 
result in any significant harm to competition or individual market 
participants. First, many individual resources already publicly report 
their uplift payments pursuant to Electric Quarterly Reporting 
requirements (with a 90-day lag). Second, RTO/ISO energy markets are 
mitigated, so concerns about the potential for collusion can be 
addressed through must offer requirements and market power mitigation 
rules. Third, after the 20-day lag for reporting following the end of 
the month, fuel costs and other conditions have often changed, 
diminishing the potential usefulness of any resource offer information. 
These three factors limit the potential for anti-competitive behavior 
and any harm to market participants.
    89. Nevertheless, to address commenters' concerns, we seek to 
balance the benefits of greater transparency with the desire to 
preserve a reasonable level of confidentiality. Specifically, for the 
reporting requirements aggregated by transmission zone, we propose that 
transmission zones with fewer than four resources need not be reported 
individually; rather, transmission zones with fewer than four resources 
may be aggregated with a neighboring transmission zone and reported 
collectively. If only one transmission zone exists and it has fewer 
than four resources or, if when combined with a neighboring 
transmission zone the combined transmission zone still has fewer than 
four resources, then these transmission zones would be exempted from 
reporting the uplift information described above. Similarly, for the 
resource-specific reporting requirements proposed above, we will 
require that uplift payment data for each resource be aggregated across 
the month, rather than reporting daily uplift payments to each 
resource. We expect that this temporal aggregation should mask daily 
behavior that some commenters have expressed concerns over revealing.
b. Reporting Operator-Initiated Commitments
    90. We also propose to require that each RTO/ISO post all operator-
initiated commitments on its Web site. For the purposes of this NOPR, 
we propose to define operator-initiated commitments as a commitment 
that is not associated

[[Page 9551]]

with a resource clearing the day-ahead or real-time market on the basis 
of economics and that is not self-scheduled.\108\ This definition would 
include any commitment, whether manual or automated, made after the 
execution of the day-ahead market that is made outside of the real-time 
market. Such commitments include commitments made through a residual 
unit commitment processes after the execution of the day-ahead market, 
commitments made through look-ahead commitment processes, and manual 
commitments made in real-time. We acknowledge that this definition of 
operator-initiated actions could result in reporting most commitments 
that occur after the day-ahead market. Moreover, we understand that 
whether a commitment cleared the market on the basis of economics could 
be a point of confusion, particularly with respect to look-ahead 
commitment processes. Therefore, we request comment on this aspect of 
the definition of operator-initiated actions.
---------------------------------------------------------------------------

    \108\ See supra text accompanying note 1.
---------------------------------------------------------------------------

    91. The report posted on each RTO's/ISO's Web site would include 
the following: (1) The upper economic operating limit of the committed 
resource in MW (i.e., its economic maximum); (2) the transmission zone 
in which the resource is located; and (3) the reason for 
commitment.\109\ We propose that each RTO/ISO post this information on 
a publicly accessible portion of its Web site in machine-readable 
format as soon as practicable after the resource has been committed 
(i.e., directed to start up by the RTO/ISO). As above, we propose to 
define ``transmission zone'' as a geographic area that is used for the 
local allocation of charges. We request comments on this proposed 
definition, including the appropriate level of geographic granularity. 
Also, as discussed further below, we propose that real-time commitments 
be posted as soon as practicable after they occur, but no later than 
four hours after the commitment.
---------------------------------------------------------------------------

    \109\ For example, if a resource with two combustion turbines 
with a capacity of 50 MW each was committed to manage congestion on 
a transmission facility, the RTO/ISO would be required to report the 
committed capacity (100 MW) and the reason (e.g., constraint 
management).
---------------------------------------------------------------------------

    92. Many commenters express concern about the lack of transparency 
surrounding operator-initiated commitments and request that the 
Commission require RTOs/ISOs to provide more information.\110\ We agree 
that current RTO/ISO practices may not provide sufficient transparency 
regarding operator-initiated commitments and that a minimum level of 
transparency is necessary as operator-initiated commitments can affect 
rates. In particular, operator-initiated commitments can affect energy 
and ancillary service prices and can result in uplift. In addition, 
greater transparency will allow stakeholders to better assess the 
RTO's/ISO's operator-initiated commitment practices and raise any 
issues of concern through the stakeholder process.
---------------------------------------------------------------------------

    \110\ E.g., EPSA Comments at 22-23; Exelon Comments at 17-18; 
Financial Marketers Coalition Comments at 42; PSEG Comments at 12.
---------------------------------------------------------------------------

    93. While most commenters focus on reporting of manual operator-
initiated commitments (i.e. not through automated software),\111\ 
operator-initiated commitments made through automated processes like 
look-ahead commitment can also have a significant impact on uplift. In 
addition, as noted by several RTOs/ISOs, manual operator-initiated 
commitments are generally infrequent. Because posting all operator-
initiated commitments, whether manual or automated, would help market 
participants to better understand the drivers behind the incurrence of 
uplift in each zone and the impact of such commitments on rates, we 
propose that all operator-initiated commitments be posted, whether 
manual or automated. We also seek comment on the types of unit 
commitments that should be reported as operator-initiated commitments.
---------------------------------------------------------------------------

    \111\ CAISO Report at 60; ISO-NE Report at 65; SPP Report at 42; 
PSEG Companies Comments at 12, 14-16, 21.
---------------------------------------------------------------------------

    94. In addition, we propose that real-time commitments be posted as 
soon as practicable after they occur, but no later than four hours 
after the commitment. We understand that this type of reporting could 
require significant changes to current RTO/ISO systems and processes. 
Accordingly, we seek comment on the proposed reporting timeframe, 
including the potential software upgrades necessary to facilitate 
reporting in near real-time and other potential implementation 
challenges. We also seek comment on whether a different reporting 
timeframe (e.g., reporting once daily or monthly) would provide 
sufficient transparency.
    95. We also understand that reporting the reason for an operator-
initiated commitment may require the development of new internal 
processes. In particular, we understand that the reasons for operator-
initiated commitments can vary based on the particular situation. 
Therefore, our proposal would only require RTOs/ISOs to report the 
commitment reason within broad categories (e.g., voltage support, 
capacity-related). We seek comment on whether the Commission should 
define a common set of categories for use across all RTOs/ISOs and, if 
so, what categories should be included, or whether it is more 
appropriate to allow each RTO/ISO to establish a set of appropriate 
operator-initiated commitment reasons on compliance. In addition, we 
note that some RTOs/ISOs currently provide more granular or detailed 
information about the reason for operator-initiated commitments.\112\ 
Therefore, we seek comment on whether the proposal provides sufficient 
transparency, or if more information is needed (e.g., specific 
constraint name), as well as any potential concerns with requiring 
additional information (e.g., required software upgrades or impact on 
operational processes).
---------------------------------------------------------------------------

    \112\ For example, for real-time commitments made to manage 
congestion, MISO identifies the specific constraint that prompted 
the commitment. MISO Report at 60.
---------------------------------------------------------------------------

c. Transmission Constraint Penalty Factors
    96. We propose to require that all RTOs/ISOs include certain 
provisions related to transmission constraint penalty factors in their 
tariffs because transmission constraint penalty factors can 
significantly impact market clearing prices.
    97. First, we propose to require that all RTOs/ISOs include their 
transmission constraint penalty factor values in their tariffs. This 
requirement would only apply to penalty factors used for transmission 
constraints and would not include other penalty factors used in 
commitment and dispatch algorithms. If the RTO/ISO uses different 
transmission constraint penalty factors for different processes, we 
propose to require that all sets of transmission constraint penalty 
factors be included in the tariff. For example, if an RTO/ISO uses 
different transmission constraint penalty factors in its security 
constrained unit commitment and its security constrained economic 
dispatch, it should include both sets of transmission constraint 
penalty factors in its tariff.
    98. Second, we propose to require that RTOs/ISOs include in their 
tariffs an explanation as to if and when transmission constraint 
penalty factors may be used to set LMPs. If the RTO/ISO has different 
processes for allowing transmission constraint penalty factors to set 
LMPs in different circumstances, this should be explained in the 
tariff. As part of its explanation, the RTO/ISO should also make clear 
whether there are any specific restrictions or

[[Page 9552]]

conditions under which transmission constraint penalty factors are 
allowed to set LMPs, such as a minimum duration for transmission 
constraint violations.
    99. Finally, if RTOs/ISOs wish to have the flexibility to 
temporarily change transmission constraint penalty factors to account 
for changes in system conditions, they must include the procedures for 
doing so in their tariffs. We also propose to require these procedures 
to include a requirement that notice of the temporary change be 
provided to market participants. For example, an RTO/ISO could notify 
market participants of the temporary change by posting on its Web site.
d. Comment Sought on Transmission Outages
    100. We seek comment on whether additional reporting of 
transmission outages should be required. Transmission outages can 
affect RTO/ISO commitment and dispatch decisions and resulting market 
clearing prices, and thus are an important facet of price formation. 
Though the current record on this issue is limited, we seek comment as 
to whether additional transparency in this regard would be beneficial 
to stakeholders and if RTOs/ISOs have any limitations in providing more 
detailed data in this regard, including any appropriate time lag for 
reporting.
e. Comment Sought on Availability of Market Models
    101. Some commenters indicate that distribution of the network 
model may be limited to certain market participants.\113\ For the 
purposes of this NOPR we define network model as the RTO's/ISO's model 
used in its energy management system for the real-time operation of the 
transmission system (e.g., state-estimation, contingency analysis). We 
seek comment on whether certain classes of market participants are 
prohibited from obtaining the network model in certain RTOs/ISOs. 
Moreover, if there are limitations to which market participants are 
able to obtain the model, we seek comment on the justification for any 
such limitations.
---------------------------------------------------------------------------

    \113\ DC Energy, Inertia Power, and Vitol Comments at 21, 26; 
Financial Marketers Coalition Comments at 43.
---------------------------------------------------------------------------

III. Compliance

    102. We propose to require that each RTO/ISO submit a compliance 
filing within 90 days of the effective date of any eventual Final Rule 
in this proceeding to demonstrate that it meets the proposed 
requirements set forth in the Final Rule. We note that this compliance 
deadline is for RTOs/ISOs to submit proposed tariff changes or 
otherwise demonstrate compliance with the Final Rule. We understand 
that implementing the reforms required by any Final Rule in this 
proceeding may be a complex endeavor. However, we preliminarily find 
that implementation of these reforms is important to ensure rates are 
just and reasonable. Therefore, we propose that tariff changes filed in 
response to a Final Rule in this proceeding must become effective no 
more than six months after compliance filings are due.
    103. We seek comment on whether 90 days is sufficient time for 
RTOs/ISOs to develop new tariff language in response to the Final Rule.
    104. To the extent that any RTO/ISO believes that it already 
complies with the reforms proposed in this NOPR, the RTO/ISO would be 
required to demonstrate how it complies in the compliance filing 
required 90 days after the effective date of any Final Rule in this 
proceeding. To the extent that any RTO/ISO believes that its existing 
market rules are consistent with or superior to the reforms adopted in 
any Final Rule, the Commission will entertain those at that time.\114\
---------------------------------------------------------------------------

    \114\ See, e.g., Settlement Intervals and Shortage Pricing in 
Markets Operated by Regional Transmission Organizations and 
Independent System Operators, Order No. 825, FERC Stats. & Regs. ] 
31,384, at P 72 (2016); Demand Response Compensation in Organized 
Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ] 
31,322, at P 4 & n.7, order on reh'g and clarification, Order No. 
745-A, 137 FERC ] 61,215 (2011), reh'g denied, Order No. 745-B, 138 
FERC ] 61,148 (2012), vacated sub nom. Elec. Power Supply Ass'n v. 
FERC, 753 F.3d 216 (D.C. Cir. 2014), rev'd & remanded sub nom. FERC 
v. Elec. Power Supply Ass'n, 136 S. Ct. 760 (2016).
---------------------------------------------------------------------------

IV. Information Collection Statement

    105. The Paperwork Reduction Act (PRA) \115\ requires each federal 
agency to seek and obtain Office of Management and Budget (OMB) 
approval before undertaking a collection of information directed to ten 
or more persons or contained in a rule of general applicability. OMB's 
regulations \116\ require approval of certain information collection 
requirements imposed by agency rules. Upon approval of a collection of 
information, OMB will assign an OMB control number and an expiration 
date. Respondents subject to the filing requirements of an agency rule 
will not be penalized for failing to respond to the collection of 
information unless the collection of information displays a valid OMB 
control number.
---------------------------------------------------------------------------

    \115\ 44 U.S.C. 3507 (2012).
    \116\ 5 CFR 1320 (2016).
---------------------------------------------------------------------------

    106. The reforms proposed in this NOPR would amend the Commission's 
regulations to improve the operation of organized wholesale electric 
power markets operated by RTOs/ISOs. The Commission proposes to require 
each RTO/ISO that allocates the costs of real-time uplift due to 
deviations should allocate such real-time uplift costs to only those 
market participants whose transactions are reasonably expected to have 
caused the real-time uplift. The Commission also proposes to revise its 
regulations to enhance transparency by requiring that each RTO/ISO post 
uplift costs paid (dollars) and operator-initiated commitments 
(megawatts) on its Web site; and define in its tariff its transmission 
constraint penalty factors, as well as the circumstances in which the 
penalty factors can set locational marginal prices, and any procedure 
for changing the penalty factors. The reforms proposed in this NOPR 
would require one-time filings of tariffs with the Commission and 
potential software upgrades to implement the reforms proposed in this 
NOPR. The Commission anticipates the reforms proposed in this NOPR, 
once implemented, would not significantly change currently existing 
burdens on an ongoing basis. The Commission will submit the proposed 
reporting requirements to OMB for its review and approval under section 
3507(d) of the Paperwork Reduction Act.\117\
---------------------------------------------------------------------------

    \117\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    107. While the Commission expects the adoption of the reforms 
proposed in this NOPR to provide significant benefits, the Commission 
understands implementation can be a complex endeavor. The Commission 
solicits public comments on its need for this information, whether the 
information will have practical utility, the accuracy of burden and 
cost estimates, ways to enhance the quality, utility, and clarity of 
the information to be collected or retained, and any suggested methods 
for minimizing respondents' burden, including the use of automated 
information techniques.
    108. Public Reporting Burden Estimate and Information Collection 
Costs: The Commission believes that the burden estimates that follow 
are representative of the average burden on respondents, including 
necessary communications with stakeholders.

[[Page 9553]]



                                                 FERC-516G, as Modified by the NOPR in Docket RM17-2-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Average burden   Total annual
                                                             Number of     Annual number   Total number   (hours) & cost  burden hours &     Cost per
                                                            respondents    of responses    of responses    per response    total annual   respondent ($)
                                                               \118\      per respondent                       \119\           cost
                                                                     (1)             (2)     (1) x (2) =             (4)     (3) x (4) =       (5) / (1)
                                                                                                     (3)                             (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Uplift Allocation.......................................               6               1               6    500; $36,500          3,000;         $36,500
                                                                                                                                $219,000
Transparency............................................               6               1               6    500; $36,500          3,000;          36,500
                                                                                                                                $219,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the total cost of 
compliance, within Year 1 to be $438,000. After Year 1, the reforms 
proposed in this NOPR, once implemented, would not significantly change 
existing burdens on an ongoing basis.
---------------------------------------------------------------------------

    \118\ Respondent entities are either RTOs or ISOs.
    \119\ The estimated hourly cost (salary plus benefits) provided 
in this section are based on the salary figures for May 2015 posted 
by the Bureau of Labor Statistics for the Utilities sector 
(available at http://www.bls.gov/oes/current/naics2_22.htm#00-0000) 
and scaled to reflect benefits using the relative importance of 
employer costs in employee compensation from December 2015 
(available at http://www.bls.gov/news.release/ecec.nr0.htm). The 
hourly estimates for salary plus benefits are:
    Legal (code 23-0000), $129.12
    Computer and Mathematical (code 15-0000), $60.63
    Information Security Analyst (code 15-1122), $58.08
    Accountant and Auditor (code 13-2011), $53.86
    Information and Record Clerk (code 43-4199), $37.75
    Electrical Engineer (code 17-2071), $64.29
    Economist (code 19-3011), $74.53
    Computer and Information Systems Manager (code 11-3021), $91.76
    Management (code 11-0000), $89.07
    The average hourly cost (salary plus benefits), weighting all of 
these skill sets evenly, is $73.23. For the calculations here, the 
Commission rounds it to $73 per hour.
---------------------------------------------------------------------------

    Title: FERC-516G, Electric Rate Schedules and Tariff Filings in 
Docket RM17-2-000.
    Action: Proposed revisions to an existing information collection.
    OMB Control No.: TBD.
    Respondents for this Rulemaking: RTOs/ISOs.
    Frequency of Information: One-time.
    Necessity of Information: The Federal Energy Regulatory Commission 
implements this rule to improve competitive wholesale electric markets 
in the RTO/ISO regions.
    Internal Review: The Commission has reviewed the changes and has 
determined that such changes are necessary. These requirements conform 
to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has specific, objective support for the burden estimates 
associated with the information collection requirements.
    109. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 
Comments concerning the collection of information and the associated 
burden estimate(s) may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission]. Due to security concerns, comments 
should be sent electronically to the following email address: 
oira_submission@omb.eop.gov. Comments submitted to OMB should refer to 
FERC-516G and OMB Control No TBD.

V. Environmental Analysis

    110. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\120\ We 
conclude that neither an Environmental Assessment nor an Environmental 
Impact Statement is required for this NOPR under section 380.4(a)(15) 
of the Commission's regulations, which provides a categorical exemption 
for approval of actions under sections 205 and 206 of the FPA relating 
to the filing of schedules containing all rates and charges for the 
transmission or sale of electric energy subject to the Commission's 
jurisdiction, plus the classification, practices, contracts and 
regulations that affect rates, charges, classifications, and 
services.\121\
---------------------------------------------------------------------------

    \120\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \121\ 18 CFR 380.4(a)(15) (2016).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    111. The Regulatory Flexibility Act of 1980 (RFA) \122\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities. 
The RFA does not mandate any particular outcome in a rulemaking. It 
only requires consideration of alternatives that are less burdensome to 
small entities and an agency explanation of why alternatives were 
rejected.
---------------------------------------------------------------------------

    \122\ 5 U.S.C. 601-12 (2012).
---------------------------------------------------------------------------

    112. This rule would apply to six RTOs/ISOs (all of which are 
transmission organizations). The average estimated annual cost to each 
of the RTOs/ISOs is $73,000. The RTOs/ISOs are not small entities, as 
defined by the RFA.\123\ This is because the relevant threshold between 
small and large entities is 500 employees and the Commission 
understands that each RTO/ISO has more than 500 employees. Furthermore, 
because of their pivotal roles in wholesale electric power markets in 
their regions, none of the RTOs/ISOs meet the last criterion of the 
two-part RFA definition of a small entity: ``not dominant in its field 
of operation.'' As a result, the Commission certifies that the reforms 
proposed in this NOPR would not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \123\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administrations' regulations at 13 CFR 121.201 define 
the threshold for a small Electric Bulk Power Transmission and 
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 
632.
---------------------------------------------------------------------------

VII. Comment Procedures

    113. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this document to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to

[[Page 9554]]

discuss. Comments are due April 10, 2017. Comments must refer to Docket 
No. RM17-2-000, and must include the commenter's name, the organization 
they represent, if applicable, and their address.
    114. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    115. Commenters that are not able to file comments electronically 
must send an original of their comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    116. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

VIII. Document Availability

    117. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    118. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    119. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By direction of the Commission.

    Issued: January 19, 2017.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Regulatory Text

    In consideration of the foregoing, the Commission proposes to amend 
Part 35, Chapter 1, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

     Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.28, by adding new paragraph (g)(11) to read as 
follows:


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (g) * * *
    (11) Uplift allocation and transparency--(i) Uplift allocation. 
Each Commission-approved independent system operator or regional 
transmission organization that allocates the costs of real-time uplift 
to deviations must allocate such costs only to those market 
participants whose transactions are reasonably expected to cause the 
uplift costs. For purposes of this allocation, deviations are megawatt 
hour differences between a market participant's scheduled deliveries or 
receipts at particular points cleared in the day-ahead market and those 
amounts actually delivered or received in real-time that are not 
related to real-time economic or reliability-related operator dispatch 
instructions. Costs of uplift payments must be allocated to at least 
two distinct categories: System-wide capacity and congestion 
management. For purposes of this allocation, each Commission-approved 
independent system operator or regional transmission organization must 
distinguish between deviations that help efforts to address system 
needs and those that harm efforts to address system needs. A market 
participant's net harmful deviations are its harmful deviations less 
its helpful deviations. Within each uplift category, uplift costs must 
be allocated to a market participant's net harmful deviations 
commensurate with the extent to which those deviations harm efforts to 
address system needs. Within the system-wide capacity category, a 
market participant shall be allocated a portion of the total real-time 
uplift costs incurred to maintain energy and operating reserve 
requirements in the real-time market based on the net contributions of 
its deviations to those costs. Within the congestion management 
category, costs shall be allocated based on whether a market 
participant's deviations on net contributed to the real-time congestion 
at a given constraint. For the purposes of real-time uplift allocated 
to deviations, a market participant's deviations must be netted hourly. 
Real-time uplift allocated to deviations must be settled on an hourly 
basis.
    (ii) Transparency--(A) Uplift reporting. Each Commission-approved 
independent system operator or regional transmission organization must 
post two reports, at minimum, regarding uplift on a publicly accessible 
portion of its Web site. Such postings shall be made within 20 calendar 
days of the end of each month. First, each Commission-approved 
independent system operator or regional transmission organization must 
post uplift, paid in dollars, and categorized by transmission zone, 
day, and uplift category. Transmission zone shall be defined as the 
geographic area that is used for the local allocation of charges. 
Transmission zones with fewer than four resources may be aggregated 
with a neighboring transmission zone and reported collectively. If, for 
any given monthly report, only one transmission zone exists and it has 
fewer than four resources or, if when combined with a neighboring 
transmission zone, the combined transmission zones still have fewer 
than four resources, these transmission zones may be omitted from the 
reporting requirements described in this section. Second, each 
Commission-approved independent system operator or regional 
transmission organization must post the resource name and the total 
amount of uplift paid in dollars aggregated across the month to each 
resource that received uplift payments within the calendar month.
    (B) Reporting operator-initiated commitments. Each Commission-
approved independent system operator or regional transmission 
organization must post operator-initiated commitments in megawatts, 
categorized by transmission zone and commitment reason, on a publicly 
accessible portion of its Web site as soon as practicable after the 
resource has been committed, but no later than four hours after the 
commitment. Transmission zone shall be defined as a geographic area 
that is used for the local allocation of charges.
    (C) Transmission constraint penalty factors. Each Commission-
approved

[[Page 9555]]

independent system operator or regional transmission organization must 
include, in its tariff, its transmission constraint penalty factor 
values; the circumstances, if any, under which the transmission 
constraint penalty factors can set locational marginal prices; and the 
procedure, if any, for temporarily changing the transmission constraint 
penalty factor values. Any procedure for temporarily changing 
transmission constraint penalty factor values must provide for notice 
of the change to market participants.

    Note:  The following appendix will not be published in the Code 
of Federal Regulations.

Appendix: List of Short Names/Acronyms of Commenters



------------------------------------------------------------------------
      Short name/acronym                       Commenter
------------------------------------------------------------------------
Appian Way...................  Appian Way Energy Partners, LLC.
CAISO........................  California Independent System Operator
                                Corporation.
DC Energy, Inertia Power, and  DC Energy, LLC, Inertia Power, LP, and
 Vitol.                         Vitol Inc.
EEI..........................  Edison Electric Institute.
EPSA.........................  Electric Power Supply Association.
EPSA/IPPNY...................  Electric Power Supply Association and
                                Independent Power Producers of New York.
EPSA/NEPGA...................  Electric Power Supply Association and New
                                England Power Generators Association,
                                Inc.
EPSA/P3......................  Electric Power Supply Association and PJM
                                Power Providers.
EPSA/Western Power Trading     Electric Power Supply Association and
 Forum.                         Western Power Trading Forum.
Energy Storage Association...  Energy Storage Association.
Entergy......................  Entergy Services, Inc. commented on
                                behalf of the Entergy Operating
                                Companies (Entergy Arkansas, Inc.;
                                Entergy Louisiana, LLC; Entergy
                                Mississippi, Inc.; Entergy New Orleans,
                                Inc.; and Entergy Texas, Inc.).
Exelon.......................  Exelon Corporation.
Financial Marketers Coalition  Financial Marketers Coalition.
Golden Spread Electric.......  Golden Spread Electric Cooperative, Inc.
ISO-NE.......................  ISO New England Inc.
MISO.........................  Midcontinent Independent System Operator,
                                Inc.
MISO Market Monitor..........  Potomac Economics, LLC.
PJM Market Monitor...........  Monitoring Analytics, LLC.
NYISO........................  New York Independent System Operator,
                                Inc.
PJM..........................  PJM Interconnection, L.L.C.
PSEG Companies...............  PSEG Companies (Public Service Electric
                                and Gas Company, PSEG Power LLC and PSEG
                                Energy Resources & Trade LLC).
Public Interest Organizations  Public Interest Organizations.
SPP..........................  Southwest Power Pool, Inc.
XO Energy....................  XO Energy, LLC.
------------------------------------------------------------------------

[FR Doc. 2017-02332 Filed 2-6-17; 8:45 am]
 BILLING CODE 6717-01-P