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 Department of Energy Federal Energy Regulatory Commission 18 CFR Part 35
[Docket No. RM16-5-000]
 AGENCY: Federal Energy Regulatory Commission, Energy.
 ACTION: Notice of proposed rulemaking.
 SUMMARY: The Federal Energy Regulatory Commission is proposing to revise its regulations to require that each regional transmission organization (RTO) and independent system operator (ISO) cap each resource's incremental energy offer to the higher of $1,000/MWh or that resource's verified cost-based incremental energy offer.
 DATES: Comments are due April 4, 2016.
 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:  Emma Nicholson (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8846, 
                        *emma.nicholson@ferc.gov.* Pamela Quinlan (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6179, 
                        *pamela.quinlan@ferc.gov.* Anne Marie Hirschberger (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8387, 
                        *annemarie.hirschberger@ferc.gov.*


SUPPLEMENTARY INFORMATION:  Table of Contents Paragraph Nos.I. Background
6.A. Offer Caps and Market Power Mitigation in RTOs/ISOs
8.B. Offer Cap Waivers and Tariff Changes
12.C. Comments About Offer Caps
18.1. Need To Modify the Offer Cap
19.2. Role of the Offer Cap in Market Power Mitigation
23.3. Alternative Offer Cap Designs
27.4. RTO/ISO Seams and the Offer Cap
38.5. Other Considerations
40.II. Need for Reform and Commission Proposal
42.A. Need for Reform
43.( print page 5952)B. Alternative Offer Cap Proposals Discussed in Comments
49.C. Commission Proposal
52.1. Offer Cap Structure
53.2. Cost-Based Incremental Energy Offer Verification
56.3. Resource Neutrality
69.4. Seams Issues
70.5. Other Considerations
72.6. Comments Sought on This Proposal
73.III. Compliance
74.IV. Information Collection Statement
76.V. Regulatory Flexibility Act Certification
80.VI. Environmental Analysis
82.VII. Comment Procedures
83.VIII. Document Availability
87.Appendix A: 
                                 List of Short Names/Acronyms of Commenters
 1. In this Notice of Proposed Rulemaking (NOPR), 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) cap each resource's incremental energy offer [1]
                    
                     to the higher of $1,000/MWh or that resource's verified cost-based incremental energy offer. Under this proposal, verified cost-based incremental energy offers above $1,000/MWh would be used for purposes of calculating Locational Marginal Prices (LMPs). 2. The Commission preliminarily finds that the offer cap [2]
                    
                     on incremental energy offers (offer cap) may no longer be just and reasonable for several reasons. The offer cap may unjustly prevent a resource from recouping its costs by not permitting that resource to include all of its short-run marginal costs within its energy supply offer (supply offer). The offer cap may result in unjust and unreasonable rates because it can suppress LMPs to a level below the marginal cost of production. Further, because of the offer cap, a resource with short-run marginal costs above that cap may choose not to offer its supply to the RTO/ISO, even though the market may be willing to purchase that supply.[3]
                    
                     Finally, when several resources have short-run marginal costs above the offer cap but are unable to reflect those costs within their incremental energy offers due to the offer cap, the RTO/ISO is not able to dispatch the most efficient set of resources because it will not have access to the underlying costs associated with the multiple incremental energy offers above the offer cap. 3. To remedy these potential problems associated with the offer cap, the Commission proposes to require that each RTO/ISO cap each resource's incremental energy offer to the higher of $1,000/MWh or an incremental energy offer based on that resource's short-run marginal cost (cost-based incremental energy offer). Under the proposal, the costs underlying each cost-based incremental energy offer above $1,000/MWh must be verified before that offer could be used for purposes of calculating LMPs. Under this proposal, the Market Monitoring Unit or the RTO/ISO, as prescribed in the RTO/ISO tariff and consistent with Order No. 719,[4]
                    
                     must verify the costs within a cost-based incremental energy offer.[5]
                    
                     The proposed offer cap would be resource neutral, that is, any resource, regardless of fuel-type, would be eligible to submit a cost-based incremental energy offer above $1,000/MWh. 4. The Commission proposes to make a generic change to the offer cap applicable to all RTOs/ISOs through a rulemaking to avoid exacerbating seams issues. Seams issues could arise if one RTO/ISO has an offer cap that materially differed from a neighboring RTO/ISO's offer cap. Different offer caps in neighboring RTOs/ISOs could result in flows that depend on the level of the two offer caps as opposed to economics or reliability needs. 5. The Commission seeks comment on these proposed reforms sixty (60) days after publication of this NOPR in the 
                    **Federal Register**
                    . I.  Background 6. On June 19, 2014, the Commission initiated the price formation proceeding.[6]
                    
                     In initiating that proceeding, the Commission stated that there may be opportunities for the RTOs/ISOs to improve the energy and ancillary service price formation process. Staff conducted outreach and convened technical workshops on the following four general issues: (1) Use of uplift payments; (2) offer price mitigation and offer caps; (3) scarcity and shortage pricing; and (4) operator actions that affect prices.[7]
                    
                     During the fall of 2014, Commission staff convened three technical workshops and Commission staff issued reports on these topics. At the October 28, 2014 technical workshop, Commission staff explored, among other topics, the $1,000/MWh offer cap, including the purpose of the offer cap and the role it plays in market power mitigation.[8]( print page 5953)
                    While this action proposes to address mitigation relevant to energy offers above $1,000/MWh in RTO/ISO markets, the Commission has also instructed staff to undertake a more comprehensive review of the market power mitigation rules in the RTO/ISO markets. 7. Two of the Commission's goals in the price formation proceeding are relevant here. First, clearing prices in the energy and ancillary services markets should ideally “reflect the true marginal cost of production, taking into account all physical system constraints.” [9]
                    
                     Second, LMPs should “ensure that all suppliers have an opportunity to recover their costs.” [10]
                    
                     Establishing LMPs that accurately reflect the marginal cost of production is a central goal of the price formation effort. This goal is important because LMPs are an effective way to communicate information to market participants about the cost of providing the next unit of energy. In the short-run, accurate price signals from LMPs are particularly important during high price periods because they provide a signal to customers to reduce consumption and a signal to suppliers to increase production or to offer new supplies to the market. In the long-run, accurate price signals from LMPs are important because they inform investment decisions. It is also important that RTOs/ISOs give resources the opportunity to recover their costs because failing to do so may discourage resources from participating in RTO/ISO energy markets. Adequate investment in resources and participation of resources in RTO/ISO energy markets are necessary to ensure economic and reliable energy for consumers. A.  Offer Caps and Market Power Mitigation in RTOs/ISOs 8. Supply offers in day-ahead and real-time energy markets consist of both physical components and financial components. The physical components of a supply offer describe the resource's physical operating parameters, such as its minimum and maximum operating limits in a given day-ahead or real-time interval, and are denominated in MW, MWh, time, or some combination thereof. The financial components of a supply offer are denominated in dollars (
                    *e.g.,*
                     $/start and $/MWh) and represent the costs underlying a resource's offer to supply electricity in a given interval. The key financial components of a supply offer are the start-up cost, no-load cost, and incremental energy offers. A resource includes its costs that vary with output in its incremental energy offer, which typically consists of a supply curve made up of multiple (price, quantity) pairs that indicate the price, expressed in $/MWh, that a resource is willing to accept to produce a given quantity of energy.[11] 9. The LMP reflects the marginal cost of serving load at a specific location, given the set of generators that are dispatched and the limitations of the transmission system.[12]
                    
                     The LMP is calculated by an RTO/ISO as the sum of three components: An energy charge, a congestion charge, and a charge for transmission losses. The energy and congestion components of the LMP are established based on several factors, including the marginal resource's incremental energy offer, specifically the $/MWh price associated with the MW output of the marginal resource. 10. All six Commission-jurisdictional RTOs/ISOs have imposed a $1,000/MWh cap on incremental energy offers.[13]
                    
                     The offer cap remains at $1,000/MWh in all RTOs/ISOs except PJM because, as discussed further below, the Commission recently approved PJM's proposal to raise the offer cap on cost-based offers in PJM to $2,000/MWh.[14]
                    
                     In each RTO/ISO, a resource's incremental energy offer is subject not only to the offer cap, but also to market power mitigation provisions.[15]
                    
                     The Market Monitoring Unit for each RTO/ISO currently oversees, and in some cases implements, the market power mitigation provisions. In general, when a resource's incremental energy offer is mitigated, that offer is replaced with an estimate of a competitive offer or an estimate of that resource's short-run marginal cost.[16]
                    
                     In most instances, once mitigated, a resource's offer is eligible to set LMP.[17]
                    
                     Mechanically, the RTOs/ISOs have adopted mitigation rules that either develop a proxy for a competitive offer or explicitly estimate short-run marginal cost. Because we expect that a competitive offer will closely track a resource's short-run marginal cost, both methods for mitigating offers should arrive at roughly the same result. The Market Monitoring Units in CAISO, MISO, ISO-NE., and NYISO typically mitigate the resource's incremental energy offer to the proxy of a competitive offer that is calculated by the Market Monitoring Unit.[18]
                    
                     However, these RTOs/ISOs also have provisions whereby the Market Monitoring Unit, often after consultation with the resource itself, can estimate the resource's short-run marginal cost, which will form the basis of that resource's mitigated incremental energy offer. In PJM and SPP, resource owners develop cost-based incremental energy offers consistent with the requirements of these RTOs' tariffs and business practice manuals and those cost-based offers are subject to review by the Market Monitoring Unit.[19] 11. While the offer cap restricts incremental energy offers, the offer cap does not limit LMPs to the level of the offer cap (be it $1,000/MWh or $2,000/MWh) because the congestion and loss components of the LMP can cause the LMP to exceed the offer cap. Scarcity pricing and emergency purchases can 
                    ( print page 5954)
                    also cause LMPs to exceed the offer cap even though incremental energy offers are limited by the offer cap. B.  Offer Cap Waivers and Tariff Changes 12. The $1,000/MWh offer cap dates back to 1999 when PJM first launched its market.[20]
                    
                     According to PJM's market monitor, PJM's offer cap was then set to a level that stakeholders considered “beyond the possible pale” of a resource's short-run marginal cost.[21]
                    
                     PJM states that its $1,000/MWh offer cap was never intended to limit incremental energy offers below a resource's marginal cost to produce energy.[22] 13. Extreme weather during the winter of 2013/14, dubbed the “Polar Vortex,” caused PJM and NYISO to request tariff waivers associated with the $1,000/MWh offer cap. During the Polar Vortex, various weather-related conditions led to a significant increase in the price of natural gas.[23]
                    
                     Natural gas prices at two key pricing points in PJM rose above $120 per million British Thermal Units (MMBtu), which could have caused some PJM resources with must-offer requirements to operate at a loss because their short-run marginal costs were above the $1,000/MWh offer cap.[24] 14. In response, on January 23, 2014, PJM filed concurrently two tariff waiver requests related to its offer cap. In its first request, which the Commission granted for the January 24-February 10, 2014 period, PJM requested that certain resources with cost-based offers above $1,000/MWh receive uplift payments to recoup those costs.[25]
                    
                     In its second request, which the Commission granted for the February 11-March 31, 2014 period, PJM requested that certain resources be allowed to submit cost-based offers in excess of $1,000/MWh and cost-based offers were used for purposes of calculating LMPs.[26] 15. Similarly, high natural gas prices in New York prompted NYISO to file a waiver request related to its offer cap.[27]
                    
                     Natural gas prices at the Transco Zone 6 NY hub in New York rose above $120/MMBtu in January 2014. In response, NYISO requested that resources be permitted to recover any unrecovered costs above $1,000/MWh through uplift payments. The Commission granted NYISO's requested waiver for the January 22-February 28, 2014 period.[28] 16. In the following winter of 2014/15, citing concerns about the potential for a repeat of the high natural gas prices experienced during the Polar Vortex, PJM and MISO submitted fillings to allow recovery of costs above $1,000/MWh during the winter months. Both PJM [29]
                    
                     and MISO [30]
                    
                     expressed concerns that the $1,000/MWh offer cap could prevent a resource from recouping its short-run marginal costs. The Commission accepted tariff provisions that temporarily raised PJM's offer cap on cost-based offers to $1,800/MWh during the January 16-March 31, 2015 period.[31]
                    
                     The Commission granted a waiver that permitted resources in MISO to include incremental energy costs in excess of $1,000/MWh in the no-load component of their supply offers during the December 20, 2014-April 30, 2015 period.[32]
                    
                     When accepting PJM's proposal and granting MISO's waiver request, the Commission reasoned that market conditions during the previous 2013/14 winter demonstrated that the $1,000/MWh offer cap could prevent resources from submitting incremental energy offers that reflect their marginal costs and could therefore force resources to offer to sell electricity below cost.[33]
                    
                     Tariff provisions related to the offer cap in both MISO and PJM reverted back to their original form in spring 2015. 17. For the winter of 2015/16, PJM [34]
                    
                     and MISO [35]
                    
                     again filed requests to modify their respective offer caps. The Commission accepted tariff revisions in PJM that would raise the offer cap on cost-based offers to $2,000/MWh for purposes of calculating LMPs going forward.[36]
                    
                     In accepting the changes, the Commission reasoned that PJM's proposal would send transparent market signals, promote efficient resource selection, and address the risks caused by high natural gas prices while protecting consumers by requiring cost verification of incremental energy offers above $1,000/MWh.[37]
                    
                     The Commission granted MISO's request to waive provisions related to the offer cap for the January 1, 2016-April 30, 2016 period. The MISO waiver for the winter of 2015/16 was virtually identical to the waiver for the winter of 2014/15 and allowed MISO resources to include incremental energy costs in excess of $1,000/MWh in the no-load component of their offers.[38] C.  Comments About Offer Caps 18. In its January 2015 notice inviting post-technical workshop comments in the price formation proceeding, the Commission asked specific questions about the $1,000/MWh offer cap and asked stakeholders to comment on various alternative offer cap designs.[39]
                    
                     Comments about the $1,000/MWh offer cap focus on the need to modify the offer cap, the role that the offer cap plays in market power mitigation, alternative offer cap designs, potential seams issues, and other considerations. 1.  Need To Modify the Offer Cap 19. Commenters differ about the need to raise or remove the $1,000/MWh offer cap. Several commenters argue that the $1,000/MWh offer cap should be raised or removed entirely, given recent occurrences of high natural gas prices. 
                    ( print page 5955)
                    Some commenters cite the recent offer cap waiver orders as evidence that the current offer cap is not just and reasonable.[40]
                    
                     Several commenters reference the Polar Vortex in the winter of 2013/14, when resources experienced marginal production costs in excess of $1,000/MWh, as evidence that the current offer cap is inappropriate.[41]
                    
                     For example, OMS states that it is appropriate to consider an upward revision or removal of the offer cap to ensure supply adequacy during extreme events such as those that occurred during the winter of 2013/14.[42] 20. Several commenters also assert that the offer cap distorts price signals and creates market inefficiencies.[43]
                    
                     Commenters state that the offer cap artificially suppresses clearing prices.[44]
                    
                     Some commenters believe that the offer cap restricts market participants from receiving appropriate compensation for costs incurred legitimately.[45] 21. Several commenters stress that the offer cap should be high enough to ensure that resources can reflect their actual costs in supply offers.[46]
                    
                     EPSA maintains that the offer cap was never intended to suppress marginal cost bidding.[47]
                    
                     MISO states that the offer cap should be modified to ensure that all resources are able to recover at least the costs they incur to produce energy.[48]
                    
                     MISO and PJM contend that an offer cap that prevents resource cost recovery can increase the likelihood that resources will be unavailable to system operators.[49]
                    
                     SPP and Western Power Trading Forum state that raising the offer cap might reduce out-of-market operator actions and uplift.[50] 22. Some commenters oppose modifying the $1,000/MWh offer cap.[51]
                    
                     CAISO, ISO-NE, and NYISO assert that, because resource marginal costs are well below $1,000/MWh, there is no evidence that the $1,000/MWh offer cap should be raised in their respective markets.[52]
                    
                     CAISO opposes any effort to increase the offer cap until sufficient benefits are identified.[53]
                    
                     NCPA, PG&E, and SCE state that the current offer cap ensures just and reasonable rates and mitigates market power in CAISO.[54]
                    
                     NCPA and SCE state that the offer cap is sufficient in CAISO because generators there have never experienced costs above $1,000/MWh.[55]
                    
                     SCE adds that the marginal cost of the least efficient CAISO resource at the highest natural gas price seen in the region is only $390/MWh.[56]
                    
                     APPA and NRECA assert that there is insufficient justification to remove offer caps nationwide.[57] 2.  Role of the Offer Cap in Market Power Mitigation 23. At the October 28, 2014 price formation technical workshop, several market monitors discussed the backstop role that the $1,000/MWh offer cap plays in market power mitigation. NYISO's internal market monitor stated that the offer cap provided a “backstop” assurance to protect consumers in the event that NYISO's market mitigation measures fail.[58]
                    
                     Similarly, ISO-NE's internal market monitor stated that the offer cap is a device that limits the potential damage to consumers or the market in the event that market power mitigation measures are unsuccessful.[59]
                    
                     CAISO's internal market monitor stated that the offer cap primarily functions as a “damage control cap” but also noted that the offer cap affects the penalty prices of constraints in CAISO's market software.[60]
                    
                     Potomac Economics, which serves as an external market monitor for MISO, ISO-NE., and NYISO, stated that the offer cap is too high to address general market power concerns, but explained that the offer cap addresses gaming strategies that market participants may engage in to collect undue uplift payments.[61] 24. In response to the Commission's request for comments on price formation topics, several commenters suggest that the offer cap's purpose has been supplanted by improvements in market monitoring and mitigation and the Commission's enforcement activity.[62]
                    
                     Wisconsin Electric asserts that the offer cap is irrelevant because RTO/ISO market monitors have effective mitigation measures in place and can refer suspected manipulation to the Commission's Office of Enforcement.[63]
                    
                     Direct Energy states that an offer cap is not necessary when resources cannot exercise market power because competition will discipline offers.[64]
                    
                     GDF SUEZ argues that offer caps are the least efficient method of protection against uncompetitive offers because offer caps are indifferent to the specifics of a supply offer and do not reflect potentially changed circumstances since the offer cap level was established over ten years ago.[65] 25. Several other commenters assert that the offer cap is a backstop measure to protect consumers against the exercise of market power during tight system conditions.[66]
                    
                     Other commenters emphasize the importance of strengthening market monitoring and mitigation provisions if offer caps are eliminated or increased.[67]
                    
                     ISO-NE asserts that while the offer cap has become less important with market power mitigation, the offer cap still serves as a “fail-safe” mechanism to protect consumers in the unlikely event that the market is not competitive and market power mitigation fails to assure competitive supply offers.[68]
                    
                     OMS warns that any effort to raise or remove the offer cap must be based on the Commission's confidence not only in the ability of RTO/ISO market power mitigation provisions to prevent 
                    ( print page 5956)
                    generator market power abuses, but also in whether the prices of input costs were developed in a competitive market.[69] 26. Potomac Economics maintains that the offer cap is necessary to keep resources from exploiting any previously unknown flaws in market rules.[70]
                    
                     Some commenters assert that due to load's inelastic demand for electricity, offer caps are necessary to protect consumers from excessive prices and to maintain confidence that rate structures are fair and nondiscriminatory.[71]
                    
                     TAPS states that on normal days when there are no generators with marginal costs “anywhere close to” $1,000/MWh, there are still 3,000 to 4,000 MW offered at the offer cap.[72]
                    
                     TAPS suggests that weakening the offer cap is particularly dangerous because energy markets cannot be halted, so if widespread abuse occurs, after-the-fact resettlements incur massive costs and diversion of resources.[73]
                    
                     APPA and NRECA assert that the offer cap should only be increased if RTOs/ISOs can guarantee that all offers are cost-based in order to guarantee appropriate prices and prevent the need to re-run markets after-the-fact.[74] 3.  Alternative Offer Cap Designs 27. In its January 2015 notice inviting post-technical workshop comments in the price formation proceeding, the Commission sought comment on potential alternative offer cap designs, including (1) maintaining the $1,000/MWh offer cap and compensating resources for incremental energy costs above the $1,000/MWh offer cap through uplift; (2) adopting a floating offer cap that changes with natural gas prices; (3) raising the offer cap to a higher fixed level; and (4) allowing resources to submit cost-based offers above $1,000/MWh and allowing verified cost-based offers above $1,000/MWh to set LMP. a.  Maintain Current Offer Cap With Uplift 28. Some commenters assert that infrequent events where production costs exceed $1,000/MWh can be addressed effectively through uplift payments without raising the offer cap or otherwise including such costs in the LMP.[75]
                    
                     APPA and NRECA state they support generator recovery of legitimate and verified costs but assert that such costs should not necessarily be included in LMP.[76]
                    
                     APPA and NRECA add that uplift will ensure cost recovery without risking market power abuse and what APPA and NRECA say would be the attendant increased unjust and unreasonable rates.[77] 29. APPA and NRECA assert that the market clearing process does not allow sufficient time to verify whether incremental energy offers above $1,000/MWh are in fact cost-based; thus, these commenters argue, such cost verification should occur after-the-fact, with costs in excess of the offer cap recovered through uplift.[78]
                    
                     SCE and PG&E state that CAISO has tools to accommodate the rare instances when the $1,000/MWh offer cap is insufficient to recover a resource's costs.[79] b.  Floating Offer Cap 30. Several commenters support a floating offer cap that changes with generator input costs, such as the price of natural gas. Calpine asserts that offer caps should be flexible and responsive to changes in natural gas prices,[80]
                    
                     and recommends that the Commission encourage each RTO/ISO to implement a floating offer cap.[81]
                    
                     Powerex suggests that the offer cap could equal the higher of $1,000/MWh or some multiple of a pre-defined regional natural gas index.[82]
                    
                     SPP states that a seasonal fixed offer cap might be appropriate.[83]
                    
                     Similarly, OMS maintains that the offer cap need not be constant throughout the year if resource costs vary throughout the year.[84] 31. ISO-NE and MISO, however, argue that a floating offer cap would be difficult to implement.[85]
                    
                     ISO-NE opposes basing the offer cap on an index that attempts to track fuel prices, arguing that doing so would be complex and difficult to implement because intra-day natural gas indices are opaque and day-ahead natural gas indices, while arguably less opaque, can become “stale” during the operating day.[86]
                    
                     MISO argues that although it may consider a floating offer cap in the longer term, a transition to such an offer cap would likely require substantial system changes.[87]
                    
                     ISO-NE asserts that if the Commission is concerned that a fixed offer cap lacks flexibility, the Commission should revisit the offer cap over time as the markets for the major fuels used in power generation continue to evolve.[88] c.  Higher Fixed Offer Cap 32. Some commenters support raising the offer cap to a higher level. ANGA states that, at a minimum, the offer cap should be increased significantly to reduce unnecessary market distortions.[89]
                    
                     Exelon argues that the current $1,000/MWh cap on market-based offers in PJM should be eliminated, but maintains that, if the offer cap remains in place, it should be raised to account for the highest reasonably expected offer, and that cost-based offers should be allowed to exceed the market-based offer cap.[90] 33. If the Commission chooses to raise the offer cap, ISO-NE urges using a simple numerical value rather than a more complicated formula.[91]
                    
                     ISO-NE is neutral on raising the offer cap but suggests that any changes to the offer cap level be made in a straightforward manner so that participants know with certainty what the offer cap will be when they make advance fuel-supply arrangements.[92]
                    
                     MISO does not oppose raising the offer cap but favors a fixed offer cap to a floating offer cap in the short term.[93]
                    
                     MISO states that a fixed offer cap simplifies the process of implementing related market mechanisms such as scarcity or shortage pricing, ancillary services, and transmission demand curves and notes that MISO's current market software systems were designed based upon a fixed offer cap.[94] 34. TAPS asserts that permanently increasing the offer cap to allow incremental energy offers above $1,000/MWh “day-in and day-out” would sacrifice the benefits of the current offer cap as a “backstop” protection against market power abuse to address “extreme circumstances” that rarely, if ever, 
                    ( print page 5957)
                    occur.[95]
                    
                     APPA and NRECA argue that it is not necessary to increase the offer cap broadly because APPA and NRECA say there is no evidence that the $1,000/MWh offer cap is persistently flawed.[96]
                    
                     APPA and NRECA add that resources' incremental energy offers only exceeded $1,000/MWh in PJM on “just a few days in one month of one year.” [97] d.  Permitting Cost-Based Incremental Energy Offers Above $1,000/MWh 35. Some commenters argue that cost-based incremental energy offers should not be capped.[98]
                    
                     PJM states that cost-based offers should not be subject to offer caps because offer caps impose arbitrary limits.[99]
                    
                     PJM suggests that one approach may be to set a market-based offer cap on an annual basis at some percentage above the highest cost-based incremental energy offer from previous time periods.[100]
                    
                     PJM Power Providers and PSEG Companies assert that cost-based offers should not be capped and should be eligible to set the LMP.[101]
                    
                     APPA and NRECA state that if the Commission wishes to revise the offer cap, it should limit any increase in the offer cap to periods when production costs exceed $1,000/MWh and ensure that any changes to the offer cap are accompanied by assurances that protect consumers against market power abuse.[102]
                    
                     Although TAPS does not support increasing the $1,000/MWh offer cap, TAPS similarly states that if the Commission wants to take temporary or seasonal action, the Commission should at the very least require that any incremental energy offer above $1,000/MWh be verified by the market monitor to be cost-justified.[103] 36. APPA and NRECA, CAISO and NCPA, however, argue that cost-based incremental offers must be verified 
                    *before*
                     the market clears in order to avoid potentially disruptive after-the-fact corrections to clearing prices, and these commenters raise concerns that it is not feasible to do so.[104]
                    
                     CAISO does not believe there is a firm basis to verify the natural gas price included in supply offers because market participants might not purchase natural gas before submitting offers and because natural gas quotes might not be available. CAISO also states that natural gas prices and quotes may be subject to manipulation, thereby making fuel cost verification difficult.[105]
                    
                     CAISO requests that if the Commission directs RTOs/ISOs to pay resources uplift for fuel costs above the offer cap, then only incremental fuel costs associated with the incremental energy offer be reimbursable. In contrast, CAISO states that costs such as natural gas pooling, imbalance penalties, or risk premiums should be recovered through capacity payments.[106] 37. TAPS contends that advance review and verification of cost-based incremental offers should be possible for most generators.[107]
                    
                     Direct Energy states that RTOs/ISOs have sufficient time to verify natural gas costs in the day-ahead and real-time markets and suggests that LMPs can be “flagged” and revised after-the-fact should the RTOs/ISOs have any concerns.[108] 4.  RTO/ISO Seams and the Offer Cap 38. Most commenters state that offer caps should be the same for each RTO/ISO, to minimize potential seams issues.[109]
                    
                     IRC, PJM, and PSEG Companies assert that transmission congestion and other market-to-market coordination will be disrupted if offer caps differ across markets.[110]
                    
                     ISO-NE and NYISO contend that different offer caps in neighboring markets could create perverse interchange flows resulting from the level of the offer caps instead of based on economic merit or reliability needs.[111]
                    
                     NYISO states that materially different offer caps between regions that depend on the same natural gas supply could require out-of-market operator actions to avoid reliability issues when natural gas prices are high.[112]
                    
                     MISO maintains that consistent offer caps across RTOs/ISOs will also establish consistent shortage pricing between neighboring RTOs/ISOs.[113] 39. In contrast, APPA and NRECA and NCPA state that offer cap levels should be set according to the needs of each individual RTO/ISO.[114]
                    
                     APPA and NRECA assert that the Commission should only consider raising the offer cap on a region-by-region basis where the evidence demonstrates a need for a higher offer cap.[115]
                    
                     Direct Energy and PJM Utilities Coalition, respectively, state that different offer caps may be appropriate if the RTOs/ISOs use the same methodology to determine the offer caps or where the different offer cap levels represent true differences in cost.[116] 5.  Other Considerations 40. CAISO and MISO note that the offer cap level impacts other market parameters that affect LMPs, such as penalty prices associated with violating thermal or operating constraints that are contained in the RTO/ISO software used to calculate LMPs. SCE explains that when CAISO relaxes a transmission constraint, it uses the offer cap to set the congestion price.[117]
                    
                     CAISO states it would have to increase constraint penalty prices, currently set to levels above the offer cap, to ensure that the market operators would dispatch economic offers prior to relaxing transmission constraints.[118]
                    
                     MISO notes that some market parameters may be intrinsically tied to the maximum LMP in the energy market, including transmission constraint demand curves, emergency or scarcity pricing regimes, and some pricing of ancillary services.[119] 41. IRC and New York Transmission Owners state that changing the offer cap could affect natural gas markets.[120]
                    
                     New York Transmission Owners argue that allowing higher offers to set the LMP might increase the price generators will pay for spot natural gas beyond competitive levels since there is no mitigation procedure to test whether resources paid too much for natural gas.[121]
                    
                     IRC states that the Commission should focus on ensuring transparency and flexibility in natural gas markets to 
                    ( print page 5958)
                    assist RTOs/ISOs with gas price verification and to ameliorate natural gas price spikes.[122] II.  Need for Reform and Commission Proposal 42. In the following section, the Commission first explains the need to reform the current offer caps. The Commission next summarizes the alternative proposals that the Commission considered but declined to adopt. Finally, the Commission describes its proposal and the three requirements that underlie it. A.  Need for Reform 43. As stated above, five of the six Commission-jurisdictional RTOs/ISOs currently have a $1,000/MWh offer cap.[123]
                    
                     As noted previously, PJM currently has a $2,000/MWh offer cap on cost-based incremental energy offers used for purposes of calculating LMPs.[124]
                    
                     When the Commission first accepted these offer caps, the Commission did so, in many instances, as temporary measures until larger market reforms were implemented.[125]
                    
                     The offer caps have persisted, and are now viewed as a component of the market power mitigation measures adopted by RTOs/ISOs.[126]
                    
                     The Commission has reviewed the offer caps and preliminarily finds that the offer caps currently in effect in all RTOs/ISOs are unjust and unreasonable for several reasons. 44. First, the offer cap can prevent a resource from recouping its short-run marginal costs. With the current $1,000/MWh offer cap, a resource whose short-run marginal cost exceeds $1,000/MWh may operate at a loss. For example, in January 2014, resources in PJM faced high natural gas prices that caused their short-run marginal costs to exceed the $1,000/MWh offer cap in place at the time.[127]
                    
                     Similarly, MISO states that high natural gas prices in January and March 2014 caused some MISO resources to experience costs in excess of the $1,000/MWh offer cap.[128] 45. Second, the offer cap can impair price formation because it can result in LMPs that are suppressed below the marginal cost of production. An LMP that is less than the marginal cost of production may not be just and reasonable because it sends an inaccurate signal to load about the actual cost of producing the electricity, and to resources about the value of the next increment of supply. For example, if the marginal resource at a given location has a $1,100/MWh short-run marginal cost but faces a $1,000/MWh cap, that resource's incremental energy offer will be constrained to $1,000/MWh, and as a result, the energy component of LMP will be $100/MWh below the marginal cost of production. In a properly functioning market, the LMP should accurately reflect the costs of serving load and both customers and resources will be aware of that cost through an accurate and transparent price signal. 46. Third, the offer cap may discourage resources from offering their supply to the RTO/ISO when their short-run marginal costs exceed the offer cap, even though market participants may be willing to purchase that supply. For example, a resource may not be subject to a must-offer requirement, and thus be under no obligation to offer its supply to the energy market and therefore simply decide not to offer its supply to the market if its short-run marginal cost exceeds the offer cap. Both PJM and MISO state that an offer cap that prevents cost recovery can reduce the likelihood that resources with short-run marginal costs above the cap will offer their supply to the RTO/ISO.[129] 47. Fourth and finally, if several resources have short-run marginal costs above $1,000/MWh, the $1,000/MWh offer cap requires those resources to submit incremental energy offers equal to $1,000/MWh, even if the resources face different costs. Under this scenario, the $1,000/MWh offer cap will prevent the RTO/ISO from observing the cost differences among these resources and the RTO/ISO will not be able to select the most efficient resources because the resources with costs above $1,000/MWh were not able to submit incremental energy offers consistent with their short-run marginal cost. For these reasons, the Commission preliminarily finds that the current offer caps result in rates that are unjust and unreasonable. In addition, these reasons illustrate that the current offer caps may not achieve the price formation goals discussed above. 48. The Commission considered several alternatives to achieve the price formation goals. On balance, the Commission has preliminarily determined that the alternative that best achieves the price formation goals is to retain the existing $1,000/MWh offer cap except in circumstances when a resource has verifiable short-run marginal costs in excess of $1,000/MWh. The discussion at the technical workshop and subsequent comments received suggest that the $1,000/MWh offer cap is appropriate in most circumstances and serves as an appropriate backstop to the existing market power mitigation rules. However, recent experience also suggests that some resources may face short-run marginal costs greater than $1,000/MWh and, in such infrequent circumstances, the $1,000/MWh offer cap inappropriately limits those resources' incremental energy offers and the resulting LMP. To the extent incremental energy offers can be verified, we believe a generic reform to allow offers and LMPs to exceed $1,000/MWh will enhance market efficiency and mitigate the potential for seams issues. B.  Alternative Offer Cap Proposals Discussed in Comments 49. This section briefly discusses why the Commission has not proposed the other alternative offer cap designs. The Commission is not proposing the alternative that uses uplift payments to compensate resources with costs above the offer cap because, while uplift payments may ensure that a resource recoups its costs, such a proposal would not ensure that LMPs accurately reflect the marginal cost of production—a key goal of the price formation effort.[130] 50. The Commission is not proposing a floating offer cap that would change with natural gas prices. This alternative proposal would be unduly preferential to natural gas-fueled resources and discriminatory towards resources that do not use natural gas as fuel because such a cap would only vary with the cost inputs of resources that use natural gas as fuel. As such, this alternative proposal could prevent a resource that does not use natural gas as a fuel to generate electricity from submitting a legitimate cost-based incremental energy offer if that offer is above the natural gas-based floating cap. Although natural gas fueled resources are currently the most likely resources to have short-run marginal costs above $1,000/MWh, this may not always be 
                    ( print page 5959)
                    the case. Furthermore, setting the offer cap for all resources based on the price of natural gas would allow non-natural gas resources to submit offers above $1,000/MWh and below the natural-gas based offer cap with no cost basis for doing so, thereby potentially allowing them to exercise market power when natural gas prices rise but when these resources' costs do not similarly rise. 51. Finally, the Commission is not proposing to raise the offer cap to a higher fixed level. A higher fixed offer cap could still limit a resource's incremental energy offer below its short-run marginal cost and potentially suppress LMPs if that resource's costs rose above the fixed offer cap. Additionally, like the floating offer cap, a higher fixed offer cap could raise market power concerns. C.  Commission Proposal 52. To remedy any potentially unjust and unreasonable rates, the Commission proposes, pursuant to section 206 of the Federal Power Act (FPA),[131]
                    
                     to revise its regulations to require that each RTO/ISO cap a resource's incremental energy offer used for purposes of setting LMPs to the higher of $1,000/MWh or that resource's verified cost-based incremental energy offer. Under the proposal, consistent with Order No. 719 [132]
                    
                     and as prescribed in the RTO/ISO tariffs, the Market Monitoring Unit or the RTO/ISO would verify the costs within such a cost-based incremental energy offer before that offer could be used to calculate LMPs. The proposed offer cap would apply to incremental energy offers in both the day-ahead and real-time energy markets. Under the proposal, each RTO/ISO must comply with the following three requirements: an offer cap structure, cost-based incremental energy offer verification, and resource neutrality, discussed in detail below. The Commission would not prescribe the precise manner in which the RTO/ISO must comply with the requirements in implementing the proposal. Each requirement, as established in the proposed regulations, is discussed in turn below. 1.  Offer Cap Structure 53. The first proposed requirement is as follows: *A resource's incremental energy offer used for purposes of calculating Locational Marginal Prices in energy markets must be capped at the higher of $1,000/MWh or that resource's cost-based incremental energy offer.* This requirement would ensure that a resource is given the opportunity to recoup its short-run marginal costs during intervals when those costs exceed $1,000/MWh because the resource could include such costs within its cost-based incremental energy offer. Additionally, this requirement would ensure that LMPs are no longer suppressed by the offer cap when marginal production costs exceed $1,000/MWh. This requirement would permit RTOs/ISOs to accept cost-based incremental energy offers above $1,000/MWh and use those offers in the market clearing process that calculates LMPs, but only when such offers are cost-based. Accordingly, all incremental energy offers above $1,000/MWh would be subject to market power mitigation and the attendant requirement that the offer be equal to the short-run marginal cost of the associated resource. Incremental energy offers at or below $1,000/MWh will continue to be subject to existing market power mitigation provisions. 54. The Commission preliminarily finds that it is necessary to permit resources to submit cost-based incremental energy offers above $1,000/MWh, because as PJM and MISO indicated in recent filings, the $1,000/MWh offer cap appears to have limited some resources' incremental energy offers to a level below their short-run marginal cost during intervals with high natural gas prices.[133]
                    
                     In addition, allowing all resources to offer consistent with short-run marginal cost will enhance an RTO/ISO's ability to dispatch the lowest cost resources, particularly when multiple resources have short-run marginal cost greater than $1,000/MWh. Furthermore, allowing a resource to submit a cost-based incremental energy offer above $1,000/MWh would help ensure that resources with short-run marginal costs above $1,000/MWh have an incentive to offer electricity into the market during high price periods, when their electricity may be needed. Allowing LMPs to reflect a given RTO/ISO's marginal cost of production could result in more economic power flows across seams because electricity would flow to where it is most valued. 55. The Commission, however, does not propose to eliminate the $1,000/MWh offer cap entirely because the $1,000/MWh functions as a backstop for existing market power mitigation rules. Several market monitors at the Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop held on October 28, 2014,[134]
                    
                     as well as many commenters [135]
                    
                     noted this function of the offer cap. For example, ISO-NE states that the $1,000/MWh offer cap still serves as a “fail-safe” mechanism to protect consumers in the unlikely event that the market is not competitive and market power mitigation fails to assure competitive supply offers.[136]
                    
                     Additionally, ISO-NE, NYISO, and CAISO indicate that the $1,000/MWh offer cap is currently above the short-run marginal cost of resources in those RTOs/ISOs (
                    *i.e.,*
                     the offer cap does not currently force a resource to submit an incremental energy offer below its short-run marginal cost).[137]
                    
                     Under this proposal, verified cost-based incremental energy offers are not capped. The Commission recently approved tariff revisions in PJM that required all incremental energy offers above $1,000/MWh to be cost-based and also placed a $2,000/MWh hard cap on cost-based incremental energy offers used for purposes of calculating LMPs.[138]
                    
                     The Commission seeks comment on whether such a hard cap should be included in any final rule in this proceeding and, if so, whether the hard cap should equal $2,000/MWh or another value. 2. Cost-Based Incremental Energy Offer Verification 56. The second proposed requirement is as follows: *The costs underlying a resource's cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used for purposes of calculating Locational Marginal Prices. If a resource submits an incremental energy offer above $1,000/MWh and the costs underlying that offer cannot be verified before the market clearing process begins, that resource's incremental energy offer in excess of $1,000/MWh may not be used to calculate Locational Marginal Prices. In such circumstances a resource would be eligible for a make-whole payment if that resource clears the energy market and the resource's costs are verified after-the-fact.* 
 
 This requirement would ensure that the proposal results in LMPs that reflect the marginal cost of production during intervals when the marginal resource's short-run marginal cost exceeds $1,000/MWh. 57. The Commission preliminarily finds that verification of the costs underlying cost-based incremental energy offers above $1,000/MWh is warranted to reduce the potential exercise of market power. Without such verification, a resource may be able to submit an offer above $1,000/MWh not because its costs exceed $1,000/MWh, but rather because it recognizes that its energy is necessary to serve load and that it does not face competition from other resources. Using such an uncompetitive offer to calculate LMPs could result in unjust and unreasonable rates. 58. Under the proposal, the Market Monitoring Unit or the RTO/ISO would be required to verify that each cost-based incremental energy offer above $1,000/MWh is in fact cost-based. The Market Monitoring Unit or the RTO/ISO would verify that a resource's cost-based offer is an accurate reflection of that resource's short-run marginal cost. The Commission notes that for purposes of mitigation, the RTO/ISO tariffs use different terminology to describe the market power mitigation process, short-run marginal costs, and mitigated offers.[139]
                    
                     The Market Monitoring Units in some RTOs/ISOs currently have processes whereby the Market Monitoring Unit or the market participant itself can derive cost-based incremental energy offers that are specific to a given resource.[140]
                    
                     Additionally, ISO-NE and NYISO currently have processes in place where a resource can contact, before the close of the day-ahead or real-time markets, the Market Monitoring Unit to update the resource's cost-based incremental energy offer (
                    *e.g.,*
                     due to a change in fuel prices).[141]
                    
                     These updates are subject to verification by the Market Monitoring Unit. 59. Under the proposal, the Market Monitoring Unit or the RTO/ISO must verify the costs within a cost-based incremental energy offer above $1,000/MWh 
                    *before*
                     that offer is used for purposes of calculating LMPs. The Commission seeks comment regarding the Market Monitoring Unit's or the RTO/ISO's ability to timely verify the costs within incremental energy offers above $1,000/MWh prior to the day-ahead or real-time market clearing process, including whether the verification of physical offer components is also necessary. The Commission seeks comment on whether the Market Monitoring Unit or RTO/ISO may need additional information to ensure that all short-run marginal cost components that are difficult to quantify, such as certain opportunity costs, are accurately reflected in a resource's cost-based incremental energy offer. For example, cost-based offers in PJM include a ten percent adder, which may account for such cost components. To the extent that RTOs/ISOs currently include an adder above cost in cost-based incremental energy offers, is such an adder appropriate for incremental energy offers above $1,000/MWh? The Commission also seeks comment on whether the Market Monitoring Unit or RTO/ISO may need additional information or new authority to require revisions or corrections to cost-based incremental energy offers to ensure that a cost-based incremental energy offer is an accurate reflection of a resource's short-run marginal cost. 60. Under this proposal, each RTO/ISO would be required to include in its tariff a process by which the Market Monitoring Unit or RTO/ISO verifies the costs included in cost-based incremental energy offers above $1,000/MWh. To create such a verification process, the Commission expects that the Market Monitoring Unit or RTO/ISO would build on its existing mitigation processes for calculating or updating cost-based incremental energy offers. The Commission notes that the nature of before-the-fact and after-the-fact cost verification processes often differ. The Commission expects that a market participant that seeks to submit a cost-based incremental energy offer above $1,000/MWh must provide appropriate documentation to the Market Monitoring Unit or the RTO/ISO. The Market Monitoring Unit or RTO/ISO should then have a before-the-fact verification process that would allow for timely cost verification such that an offer submitted in a reasonable period of time could be used for purposes of calculating LMPs. As noted already, the Commission emphasizes that this before-the-fact verification should build upon existing procedures. 61. Currently, RTOs/ISOs use different processes to develop and update offers for mitigation purposes. Under this proposal, the Commission would not require RTOs/ISOs to adopt the same approach to implement the cost-based incremental energy offer verification requirement. 62. RTOs/ISOs also differ in how they define the components of cost-based incremental energy offers for purposes of mitigation.[142]
                    
                     Each RTO/ISO has tariff provisions that set out the elements of a resource's short-run marginal cost for purposes of mitigation.[143]
                    
                     The Commission expects each RTO/ISO to use the elements set forth in its tariff provisions for purposes of determining a resource's cost-based incremental energy offer. Thus, the Commission is not proposing to define the elements of a short-run marginal cost as part of this proceeding. 63. Given that the verification process for cost-based incremental energy offers is intended to build on an RTO/ISO's existing mitigation processes, as proposed, external RTO/ISO resources (
                    *i.e.,*
                     imports) would not be eligible to submit cost-based incremental energy offers above $1,000/MWh because RTO/ISO processes to develop cost-based incremental energy offers for mitigation purposes typically apply to internal resources alone. However, the Commission would consider RTO/ISO proposals to develop cost-based incremental energy offers for external transactions in their respective compliance filings for any final rule in this proceeding.[144]
                    
                     The Commission seeks comments on whether the offer cap proposal should apply to imports and whether a cost verification process for import transactions is feasible. 64. The Commission preliminarily finds that, as financial instruments, virtual transactions have no short-run marginal production costs and, thus, could not provide a cost-basis for a virtual transaction above $1,000/MWh. Accordingly, virtual transactions in RTOs/ISOs which currently limit virtual transaction bid/offer caps to existing incremental energy offer caps, could not exceed $1,000/MWh under the proposal.[145]
                    
                     The Commission seeks 
                    ( print page 5961)
                    comment on whether prohibiting virtual transactions above $1,000/MWh could limit hedging opportunities, present opportunities for manipulation or gaming, create market inefficiencies, or have other undesirable consequences. Additionally, the Commission seeks comment on alternatives which would allow virtual increment offers and decrement bids to be submitted and cleared at prices above $1,000/MWh.[146] 65. The cost-based incremental energy offer verification requirement also ensures that a resource with short-run marginal costs above $1,000/MWh recoups its costs in the event that the Market Monitoring Unit or RTO/ISO cannot verify that resource's costs prior to the market clearing process. The Commission emphasizes that RTOs/ISOs would be expected to adopt a verification process that allows timely submitted and appropriately documented cost-based incremental energy offers to be used to calculate LMPs; compensating resources through make-whole payments should be treated only as a backstop. Under this proposal, the RTO/ISO would adopt a procedure to include the offer, modified as discussed below, in its market clearing process. Accordingly, if such an offer clears the energy market, that resource may be entitled to a make-whole payment if the Market Monitoring Unit or RTO/ISO can verify after-the-fact that the resource's short-run marginal cost was above $1,000/MWh. The basis of the make-whole payment would be the difference between a given resource's energy market revenues and that resource's total offer costs, including the cost-based incremental energy offer.[147] 66. The Commission's proposal would permit regional variation in the process for treating incremental energy offers above $1,000/MWh that the Market Monitoring Unit or RTO/ISO cannot verify prior to the start of the market clearing process. For example, the RTO/ISO could have procedures to change the incremental energy offer to $1,000/MWh and to mitigate that offer further to a level below $1,000/MWh pursuant to other applicable market power mitigation provisions. The Commission continues to find that regional variation is acceptable here because incremental energy offers are currently subject to the existing RTO/ISO mitigation procedures that vary across RTOs/ISOs to appropriately account for regional differences. Further, RTO/ISO mitigation procedures only affect resources within the RTO/ISO. However, as discussed below, the offer cap also affects inter-regional trading such that generic action is required to avoid exacerbating seams. 67. Existing Commission regulations, as described below, already create a framework that ensures cost-based incremental energy offers submitted as part of a supply offer are based on legitimate costs.[148]
                    
                     In existing mitigation processes, a resource must submit accurate cost information to the market monitor. In submitting a cost-based incremental energy offer above $1,000/MWh, a resource that misrepresents its costs would be in violation of the Commission's regulations requiring accurate statements. Section 35.41(b) of the Commission's regulations requires market participants to provide “accurate and factual information and not submit false or misleading information, or omit material information, in any communication with the Commission, Commission-approved market monitors . . . [or] Commission-approved independent system operators.” [149]
                    
                     Additionally, a resource that intentionally misrepresents its costs could violate the Commission's Anti-Manipulation Rule. That rule prohibits a market participant from intentionally making “any untrue statement of a material fact or to omit[ting] to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading.” [150]
                    
                     Thus, any resource that misrepresents its costs may be in violation of the Commission's regulations, even if its offer does not clear the day-ahead or real-time energy market. 68. Some commenters express concern that verification of cost-based incremental energy offers prior to the market clearing process may require RTOs/ISOs to re-run the market if the Market Monitoring Unit or RTO/ISO initially accepts a cost-based incremental energy offer above $1,000/MWh and subsequently determines through an after-the-fact review that the offer that established the LMP was not in fact cost-based.[151]
                    
                     The Commission preliminarily finds that the verification requirement in this proposal addresses this concern because cost-based incremental energy offers above $1,000/MWh should result in LMPs that are appropriate because they will accurately reflect the marginal cost of production. Accordingly, such LMPs will not require recalculation after-the-fact. 3. Resource Neutrality 69. The third proposed requirement is as follows: *All resources, regardless of type, are eligible to submit cost-based incremental energy offers in excess of $1,000/MWh.* This requirement would ensure that the eligibility to submit cost-based incremental energy offers in excess of $1,000/MWh would not be applied in an unduly discriminatory or unduly preferential manner. During the Polar Vortex, natural gas prices reached levels that caused the short-run marginal cost of natural gas-fueled resources that purchased gas on the natural gas spot market to exceed $1,000/MWh. However, limiting the opportunity to submit cost-based incremental energy offers in excess of $1,000/MWh to a particular resource type, such as natural-gas fueled resources, would be unduly preferential to those resources.[152]
                    
                     Even though natural gas resources are currently most likely to have cost-based incremental energy offers above $1,000/MWh, market conditions may change causing other resource types to have short-run marginal costs above $1,000/MWh. Accordingly, the Commission proposes that all resource types be eligible to submit a cost-based incremental energy offer above $1,000/MWh. The resource neutrality requirement is consistent with prior Commission orders related to the offer cap in PJM and MISO.[153] 4. Seams Issues 70. The Commission proposes to make a generic change to the offer cap applicable to all RTOs/ISOs through a rulemaking to avoid exacerbating seams issues. Seams issues could arise if one RTO/ISO has an offer cap that materially differed from a neighboring 
                    ( print page 5962)
                    RTO/ISO's offer cap. For example, NYISO states that offer caps that are materially different in neighboring RTOs/ISOs that rely on the same natural gas market could require out-of-market operator actions to avoid reliability concerns.[154]
                    
                     ISO-NE and NYISO also note that different offer caps in neighboring RTOs/ISOs could result in flows that depend on the level of the two offer caps as opposed to economics or reliability needs.[155]
                    
                     The Commission also has indicated in prior orders approving temporary waivers or tariff changes related to MISO and PJM's respective offer caps that the Commission would address seams issues related to the offer cap beyond the winter of 2014/15 in the price formation proceeding.[156]
                    
                     Therefore, this proposal would revise the market rules in all RTOs/ISOs in a similar manner to ensure that market prices accurately reflect the marginal cost of production. 71. Some commenters have expressed concern that different offer caps in neighboring markets could create seams issues. The Commission acknowledges that the instant proposal could result in neighboring markets having different effective offer caps in a given interval because the marginal cost of production in one RTO/ISO may differ from other neighboring markets due to different resources with different short-run marginal costs being on the margin. Nonetheless, the Commission believes these differences will not adversely affect seams because these differences would be driven by actual costs and not by offer caps artificially suppressing LMPs. Therefore, the associated differences in LMPs will encourage efficient interchange transactions. The Commission seeks comment on this preliminary finding and other seams issues related to this proposal. 5. Other Considerations 72. In several RTO/ISOs, factors affecting LMPs and other market outcomes depend on the offer cap. For example, CAISO's shortage pricing and penalty factors that apply when transmission constraints are relaxed are based on the $1,000/MWh offer cap.[157]
                    
                     Such relationships may have to be revised because they may require that the value of the offer cap be known prior to the market clearing process. Under this proposal, the ultimate value of the offer cap may not be known in advance in periods when marginal production costs exceed $1,000/MWh. Accordingly, given this proposal, RTOs/ISOs may wish to revise certain market features that relate to or are affected by the offer cap. RTOs/ISOs and their stakeholders may also wish to consider additional tariff revisions, such as changes to scarcity or shortage pricing, raising or removing caps on price-sensitive demand bids, and other means by which load can express its willingness to pay for electricity. Although they are not required to do so, the Commission would consider other market design changes, such as changes to scarcity or shortage pricing or other penalty prices, associated with adopting this proposal in the compliance filing. 6. Comments Sought on This Proposal 73. The Commission seeks comment on its proposal as described herein. Specifically, the Commission seeks comment on the following items: (1) Whether a hard cap on cost-based incremental energy offers used for purposes of calculating LMPs should be included in any final rule in this proceeding and, if so, whether the hard cap should equal $2,000/MWh or another value; (2) the ability to timely verify the costs within incremental energy offers above $1,000/MWh prior to the day-ahead or real-time market clearing process, including whether the verification of physical offer components is also necessary; (3) whether the Market Monitoring Unit or RTO/ISO may need additional information to ensure that all short-run marginal cost components that are difficult to quantify, such as certain opportunity costs, are accurately reflected in a resource's cost-based incremental energy offer and to the extent that RTOs/ISOs currently include an adder above cost in cost-based incremental energy offers, whether such an adder is appropriate for incremental energy offers above $1,000/MWh; (4) whether the Market Monitoring Unit or RTO/ISO may need additional information or new authority to require revisions or corrections to a cost-based incremental energy offer to ensure that a resource's cost-based incremental energy offer is an accurate reflection of that resource's short-run marginal cost; (5) whether the proposal should apply to imports and whether a cost verification process for import transactions is feasible; (6) whether excluding virtual transactions above $1,000/MWh could limit hedging opportunities, present opportunities for manipulation or gaming, create market inefficiencies, or have other undesirable consequences, and whether alternatives exist which would allow virtual increment offers and decrement bids to be submitted and cleared at prices above $1,000/MWh; and (7) the impact the proposal would have on seams. Comments must be submitted within sixty (60) days of publication of this NOPR in the 
                    **Federal Register.** III. Compliance 74. The Commission proposes to require that each RTO/ISO submit a compliance filing no later than four months from the effective date of the final rule in this proceeding to demonstrate that it meets the proposed requirements set forth in the final rule. The Commission will accept RTO/ISO proposals that satisfy the three requirements described above and notes that proposals may vary regionally based on the existing RTO/ISO tariff provisions that are used to develop cost-based incremental energy offers and to implement market power mitigation provisions that are to be used as a basis for implementing this proposal. As noted previously, the Commission is also willing to consider proposed revisions to other market design features that may require revision in light of this proposal, such as changes to scarcity or shortage pricing or other market parameters. 75. To the extent that any RTO/ISO believes that it already complies with the reforms adopted in a final rule in this proceeding, the RTO/ISO would be required to demonstrate, in the compliance filing, how it complies. IV. Information Collection Statement 76. The Paperwork Reduction Act (PRA) [158]
                    
                     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,[159]
                    
                     in turn, require approval of certain information collection requirements imposed by agency rules. Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collection(s) of information unless the collection(s) of information display a valid OMB control number. 77. The reforms proposed in this NOPR would amend the Commission's regulations to improve the operation of organized wholesale electric power 
                    ( print page 5963)
                    markets operated by RTOs/ISOs. The Commission proposes to require that each RTO/ISO cap a resource's incremental energy offer used for purposes of calculating LMPs in energy markets to the higher of $1,000/MWh or that resource's cost-based incremental energy offer, as verified by the Market Monitoring Unit or the RTO/ISO. 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. With regard to those RTOs/ISOs that believe that they already comply with the reforms proposed in this NOPR, they could demonstrate their compliance in the compliance filing required four months after the effective date of the final rule in this proceeding. The Commission will submit the proposed reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.[160] 78. 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 comments on the accuracy of provided burden and cost estimates and any suggested methods for minimizing the respondents' burdens, including the use of automated information techniques. Specifically, the Commission seeks detailed comments on the potential cost and time necessary to implement aspects of the reforms proposed in this NOPR, including (1) software and business processes changes, including market power mitigation; (2) increased time spent validating cost-based incremental energy offers; and (3) processes for RTOs/ISOs to vet proposed changes amongst their stakeholders. *Burden Estimate and Information Collection Costs:*
                     The Commission believes that the burden estimates below are representative of the average burden on respondents, including necessary communications with stakeholders. The estimated burden and cost for the requirements contained in this NOPR follow.[161] Software or Hardware Upgrades May Not Be Required
[FERC-516, as modified by NOPR in Docket RM16-5-000]
Number of
                             respondents
Annual
                             number of 
                             responses per 
                             respondent
Total number of responses
Average burden (hours) & cost per response
Total annual burden hours & total annual cost
Cost per
                             respondent 
                             ($)(1)
(2)
(1) × (2) = (3)
(4)
(3) × (4) = (5)
(5) ÷ (1)One-Time Tariff Filings (Year 1)
6
1
6
500 hrs.; $36,000 163
3,000 hrs.; $216,000
$36,000
 The Commission
                    
                     notes that these cost estimates below do not include costs for software or hardware or for increased time spent validating cost-based incremental energy offers above $1,000/MWh.162 *Cost to Comply:*
                     The Commission has projected the total cost of compliance, all within four months of a Final Rule plus initial implementation, to be $216,000. After Year 1, the reforms proposed in this NOPR, once implemented, would not significantly change existing burdens on an ongoing basis. The Commission notes that these estimates do not include costs for software or hardware. Software or hardware upgrades may not be required. *Title:*
                     FERC-516, Electric Rate Schedules and Tariff Filings. *Action:*
                     Proposed revisions to an information collection. *OMB Control No.*
                     1902-0096. *Respondents for this Rulemaking:*
                     RTOs/ISOs. *Frequency of Information:*
                     One-time during. *Necessity of Information:*
                     The Federal Energy Regulatory Commission proposes this rule to improve competitive wholesale electric markets in the RTO/ISO regions. *Internal Review:*
                     The Commission has reviewed the proposed 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. 79. 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, phone: (202) 395-0710, fax (202) 395-7285]. Due to security concerns, comments should be sent electronically to the following email address: 
                    *oira_submission@omb.eop.gov.*
                     Comments submitted to OMB should include FERC-516 and OMB Control No. 1902-0096. 
 
 V. Regulatory Flexibility Act Certification 80. The Regulatory Flexibility Act of 1980 (RFA) [164]
                    
                     generally requires a description and analysis of 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. 81. 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 $36,000, all in Year 1. This one-time cost of filing and implementing these changes is not significant.[165]
                    
                     Additionally, the RTOs/ISOs are not small entities, as defined by the RFA.[166]
                    
                     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 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. The Commission does not expect other entities to incur compliance costs as a result of the reforms proposed in this NOPR, but seeks detailed comments on whether other entities, such as load-serving entities, would incur costs as a result of the reforms proposed in this NOPR. VI. Environmental Analysis 82. 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.[167]
                    
                     The Commission concludes 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.[168] VII. Comment Procedures 83. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due April 4, 2016. Comments must refer to Docket No. RM16-5-000, and must include the commenter's name, the organization they represent, if applicable, and their address. 84. 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. 85. 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. 86. 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 87. 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. 88. 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 of this document, excluding the last three digits, in the docket number field. 89. 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
Non-discriminatory open access transmission tariffs
 By direction of the Commission. Issued: January 21, 2016. Nathaniel J. Davis, Sr., Deputy Secretary.
 In consideration of the foregoing, the Commission proposes to amend part 35, chapter I, 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 paragraph (g)(9) to read as follows: § 35.28
  
 (g) * * * (9) 
                        *Incremental energy offer caps.*
                         A resource's incremental energy offer used for purposes of calculating Locational Marginal Prices in energy markets must be capped at the higher of $1,000/MWh or that resource's cost-based incremental energy offer. The costs underlying a resource's cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used for purposes of calculating Locational Marginal Prices. If a resource submits an incremental energy offer above $1,000/MWh and the costs underlying that offer cannot be verified before the market clearing process begins, that resource's incremental energy offer in excess of $1,000/MWh may not be used to calculate Locational Marginal Prices. In such circumstances a resource would be eligible for a make-whole payment if that resource clears the energy market and the resource's costs are verified after-the-fact. All resources, regardless of type, are eligible to submit cost-based incremental energy offers in excess of $1,000/MWh. The following appendix will not appear in the Code of Federal Regulations. Appendix A: List of Short Names/Acronyms of Commenters Short name/acronym
CommenterAPPA and NRECA
American Public Power Association and National Rural Electric Cooperative Association.ANGA
America's Natural Gas Alliance.Brookfield
Brookfield Renewable Energy Marketing LP.California State Water Project
California Department of Water Resources State Water Project.CAISO
California Independent System Operator Corporation.Calpine
Calpine Corporation.Direct Energy
Direct Energy Business Marketing, LLC, Direct Energy Business, LLC and affiliated companies.EEI
Edison Electric Institute.EPSA
Electric Power Supply Association.ELCON
Electricity Consumers Resource Council.Entergy Nuclear Power Marketing
Entergy Nuclear Power Marketing, LLC.Exelon
Exelon Corporation.GDF SUEZ
GDF SUEZ North America, Inc.ISO-NE
ISO New England, Inc.IRC
ISO/RTO Council.MISO
Midcontinent Independent System Operator, Inc.NYISO
New York Independent System Operator, Inc.New York Transmission Owners
New York Transmission Owners (Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc., Power Supply of Long Island, New York Power Authority, New York State Electric & Gas Corporation, Niagara Mohawk Power Corporation d/b/a National Grid, Orange and Rockland Utilities, Inc., and Rochester Gas and Electric Corporation).NCPA
Northern California Power Agency.OMS
Organization of MISO States.PG&E
Pacific Gas and Electric Company.PJM
PJM Interconnection, L.L.C.PJM Power Providers
PJM Power Providers Group.PJM Utilities Coalition
PJM Utilities Coalition (American Electric Power Service Corporation, the Dayton Power and Light Company, FirstEnergy Service Company, Buckeye Power, Inc., and East Kentucky Power Cooperative).Potomac Economics
Potomac Economics, Ltd.Powerex
Powerex Corp.PSEG Companies
PSEG Companies (Public Service Electric and Gas Company, PSEG Power LLC and PSEG Energy Resources & Trade LLC).SCE
Southern California Edison Company.SPP
Southwest Power Pool, Inc.TAPS
Transmission Access Policy Study Group.Western Power Trading Forum
Western Power Trading Forum.Wisconsin Electric
Wisconsin Electric Power Company.Xcel
Xcel Energy Services Inc.


# Footnotes

1.
    
                         The incremental energy offer is the portion of a resource's energy supply offer that varies with the output of the generator. Back to Citation
 2.
    
                         The offer cap for purposes of this NOPR refers to the $/MWh limit on day-ahead and real-time incremental energy offers, and not any limits or penalty rates that may apply in the capacity or ancillary services markets. Back to Citation
 3.
    
                         Resources that are subject to must-offer requirements, such as resources with a capacity supply obligation, are required to submit a supply offer to the energy market. Many resources are subject to must-offer requirements in either the day-ahead or real-time markets. The proposed reform would ensure that such a resource has an economic incentive that matches its tariff obligation. It would also provide an economic incentive to those resources that are not subject to a must-offer requirement. Back to Citation
 4.
    
                         
                        *Wholesale Competition in Regions with Organized Electric Markets,*
                         Order No. 719, FERC Stats. & Regs. ¶ 31,281, at PP 370-375 (2008), 
                        *order on reh'g,*
                         Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), 
                        *order on reh'g,*
                         Order No. 719-B, 129 FERC ¶ 61,252 (2009). 
                        *See also*18 CFR 35.28(g)(3)(iii)(B) (2015). Back to Citation
 5.
    
                         Pursuant to 18 CFR 35.28(g)(3)(iii)(B), either the internal or external market monitor can “provide the inputs required to conduct prospective mitigation . . . including, but not limited to reference levels, identification of system constraints, and cost calculations.” 18 CFR 35.28(g)(3)(iii)(B) (2015). However, prospective mitigation may only be carried out by an internal market monitor if the RTO/ISO has a hybrid Market Monitoring Unit structure. 18 CFR 35.28(g)(3)(iii)(D) (2015). Back to Citation
 6.
    
                         
                        *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). Back to Citation
 7.
    
                         
                        *Id.*
                         at 1, 3-4. Back to Citation
 8.
    
                         
                        *See*
                         Supplemental Notice of Workshop on Price Formation: Scarcity and Shortage Pricing, Offer 
                        
                        Mitigation, and Offer Caps in RTO and ISO Markets, Docket No. AD14-14-000 (Oct. 10, 2014). Back to Citation
 9.
    
                         Price Formation Notice at 2. Back to Citation
 10.
    
                         
                        *See Price Formation in Energy and Ancillary Servs. Mkts. Operated by Reg'l Transmission Orgs. & Indep. Sys. Operators,*
                         153 FERC ¶ 61,221, at P 2 (2015); 
                        *see also*
                         Price Formation Notice at 2. Back to Citation
 11.
    
                         RTOs/ISOs typically restrict incremental energy supply curves to ten price and quantity pairs (
                        *i.e.,*
                         ($/MWh, MW)). Back to Citation
 12.
    
                         
                        *See*
                         Federal Energy Regulatory Commission, Division of Energy Market Oversight Office of Enforcement, 
                        *Energy Primer,*
                         at 60 (Nov. 2015), 
                        *http://www.ferc.gov/​market-oversight/​guide/​energy-primer.pdf.* Back to Citation
 13.
    
                         
                        *See, e.g.,*
                         California Independent System Operator Corporation (CAISO), eTariff, 39.6.1.1 (11.0.0); ISO New England Inc. (ISO-NE), Transmission, Markets and Services Tariff, Market Rule 1, III.1.10.1A(d)(ix), III,1.10.IA(c)(iv), III.2.6(b)(i), and III.A.15.1(b) (27.0.0); Midcontinent Independent System Operator, Inc. (MISO), FERC Electric Tariff, 39.2.5 (35.0.0), 39.2.5A (34.0.0), 39.2.5B (34.0.0), 40.2.5 (35.0.0), 40.2.6 (35.0.0) and 40.2.7 (33.0.0); New York Independent System Operator, Inc. (NYISO), NYISO Tariffs, NYISO Markets and Services Tariff, 21.4 and 21.5.1 (7.0.0); PJM Interconnection, L.L.C. (PJM), Intra-PJM Tariffs, OATT, Tariff Operating Agreement, Attachment K, Appendix, 1.10.1A(d) (24.0.0); Southwest Power Pool, Inc. (SPP), OATT, Sixth Revised Volume No. 1, Attachment AE, Section 4.1.1 (2.0.0). Back to Citation
 14.
    
                         
                        *PJM Interconnection L.L.C.,*
                         153 FERC ¶ 61,289, at P 25 (2015) (PJM 2015/16 Offer Cap Order). The tariff provisions related to the offer cap do not have a sunset date. Back to Citation
 15.
    
                         
                        *See*18 CFR 35.28(g)(3)(iii)(B)-(D) (2015). Back to Citation
 16.
    
                         The RTOs/ISOs use different terms for a mitigated offer. ISO-NE., MISO, and NYISO mitigate supply offers to a “Reference Level.” 
                        *See*
                         ISO-NE., Transmission Markets and Services Tariff, Market Rule 1, III.A.7.2; MISO FERC Electric Tariff, 64.1.4 (30.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, 23.3.1.4 (11.0.0). CAISO mitigates supply offers to “Default Energy Bids.” 
                        *See*
                         CAISO, eTariff, 39.7.1 (11.0.0). PJM mitigates supply offers to a “cost-based offer.” 
                        *See*
                         PJM Operating Agreement, Schedule 1, 1.10.1A (24.0.0) and 6.4.1 (7.0.0). SPP mitigates supply offers to a “Mitigated Energy Bid.” 
                        *See*
                         SPP OATT, Sixth Revised Volume No. 1, Attachment AF, 3.2 (7.0.0). For purposes of this NOPR, the offers RTOs/ISOs use for purposes of mitigation will be referred to as “cost-based offers.” Back to Citation
 17.
    
                         There are exceptions to this eligibility, for instance, when a resource is committed outside of the market clearing process. Back to Citation
 18.
    
                         
                        *See supra*
                         n.16. Back to Citation
 19.
    
                         PJM resources develop cost-based offers pursuant to PJM Manual 15: Cost Development Guidelines. SPP resources develop Mitigated Energy Bids pursuant to SPP's Mitigated Offer Guidelines in the SPP Market Protocols. Back to Citation
 20.
    
                         
                        *See*
                         Docket Nos. OA97-261-000 and ER97-1082-000 (Apr. 1, 1997); 
                        *Pennsylvania-New Jersey-Maryland Interconnection,*
                         81 FERC ¶ 61,257 (1997). Back to Citation
 21.
    
                         Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 209:18-22 (Oct. 28, 2014). Back to Citation
 22.
    
                         PJM Comments at 2. All comments cited herein were submitted in Docket No. AD14-14-000 on or about March 6, 2015. Back to Citation
 23.
    
                         
                        *See, e.g.,*
                         FERC Staff, 
                        *Commission and Industry Actions Relevant to Winter 2013-14 Weather Events*
                         (Oct. 16, 2014), 
                        *https://www.ferc.gov/​media/​news-releases/​2014/​2014-4/​10-16-14-A-4-presentation.pdf.* Back to Citation
 24.
    
                         
                        *PJM Interconnection, L.L.C.,*
                         146 FERC ¶ 61,041, at P 2, 
                        *order on reh'g,*
                         149 FERC ¶ 61,059 (2014). For example, a natural gas resource with a heat rate of 8,350 Btu/kWh could have short-run marginal fuel costs above $1,000/MWh if the natural gas price exceeds $120/MMBtu. Back to Citation
 25.
    
                         
                        *Id.*
                         P 1. Back to Citation
 26.
    
                         
                        *PJM Interconnection, L.L.C.,*
                         146 FERC ¶ 61,078, at PP 3-4 (2014). Back to Citation
 27.
    
                         
                        *N.Y. Indep. Sys. Operator, Inc.,*
                         146 FERC ¶ 61,061, at PP 2-4 (2014). Back to Citation
 28.
    
                         
                        *Id.*
                         P 24. Back to Citation
 29.
    
                         
                        *PJM Interconnection L.L.C.,*
                         150 FERC ¶ 61,020, at P 5 (2015) (PJM 2014/15 Offer Cap Order). Back to Citation
 30.
    
                         
                        *Midcontinent Indep. Sys. Operator, Inc.,*
                         150 FERC ¶ 61,083, at P 3 (2015) (MISO 2014/15 Offer Cap Order). Back to Citation
 31.
    
                         PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020. Back to Citation
 32.
    
                         MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083. Back to Citation
 33.
    
                         
                        *See*
                         PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 34; MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 17. Back to Citation
 34.
    
                         PJM, Proposed Tariff Revisions, Docket No. ER16-76-000 (filed Oct. 14, 2015). Back to Citation
 35.
    
                         MISO, Request for Waiver, Docket No. ER16-248-000 (filed Nov. 2, 2015). Back to Citation
 36.
    
                         PJM 2015/16 Offer Cap Order, 153 FERC ¶ 61,289 at P 25. The tariff provisions related to the offer cap do not have a sunset date. Back to Citation
 37.
    
                         
                        *Id.*
                         PP 25-26. Resources can submit cost-based offers above $2,000/MWh and PJM will use such offers for merit order dispatch, but incremental energy offers used for purposes of calculating LMP are capped at $2,000/MWh. Back to Citation
 38.
    
                         
                        *Midcontinent Indep. Sys. Operator, Inc.,*
                         154 FERC ¶ 61,006 (2015) (MISO 2015/16 Offer Cap Order). Back to Citation
 39.
    
                         
                        *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 2-3    (Jan. 16, 2015). A list of commenters and the abbreviated names the Commission will use for them in this document appears in Appendix A. Back to Citation
 40.
    
                         ANGA Comments at 2; Brookfield Comments at 7; EPSA Comments at 24; Entergy Nuclear Power Marketing Comments at 11-12; Exelon Comments at 10-11; PJM Comments at 2-3; PJM Power Providers Comments at 2-4; SPP Comments at 1; Western Power Trading Forum Comments at 5-6. Back to Citation
 41.
    
                         EPSA Comments at 21-24; Exelon Comments at 10-12; OMS Comments at 2; PJM Comments at 2-3; PJM Power Providers Comments at 2. Back to Citation
 42.
    
                         OMS Comments at 2. Back to Citation
 43.
    
                         PJM Utilities Coalition Comments at 3-4; Western Power Trading Forum Comments at 5. Back to Citation
 44.
    
                         Direct Energy Comments at 2; EPSA Comments at 21. Back to Citation
 45.
    
                         ANGA Comments at 2-3; Xcel Comments at 2. Back to Citation
 46.
    
                         ANGA Comments at 2; Brookfield Comments at 7; Entergy Nuclear Power Marketing Comments at 11-12; ISO-NE Comments at 5; IRC Comments at 2-3; MISO Comments at 4; PJM Comments at 2; PJM Power Providers Group Comments at 2-4; Potomac Economics Comments at 3; Powerex Comments at 29-30; PSEG Companies Comments at 5-6; Western Power Trading Forum Comments at 5-6. Back to Citation
 47.
    
                         EPSA Comments at 21-22. Back to Citation
 48.
    
                         MISO Comments at 4. Back to Citation
 49.
    
                         
                        *Id.;*
                         PJM Comments at 2. Back to Citation
 50.
    
                         SPP Comments at 1; Western Power Trading Forum Comments at 5-6. Back to Citation
 51.
    
                         APPA and NRECA Comments at 30; CAISO Comments at 3; ELCON Comments at 6. Back to Citation
 52.
    
                         CAISO Comments at 3; ISO-NE Comments at 3 & n.2; NYISO Comments at 4. Back to Citation
 53.
    
                         CAISO Comments at 3. Back to Citation
 54.
    
                         NCPA Comments at 2; PG&E Comments at 3; SCE Comments at 3; 
                        *see also*
                         California State Water Project Comments at 2; New York Transmission Owners Comments at 2. Back to Citation
 55.
    
                         NCPA Comments at 2-3; SCE Comments at 2. Back to Citation
 56.
    
                         SCE Comments at 2. According to SCE, the $390/MWh figure assumes a heat rate of 17,000 Btu/kWh, slightly higher than the least efficient unit in CAISO, and a natural gas price of $23/MMBtu. Back to Citation
 57.
    
                         APPA and NRECA Comments at 32. Back to Citation
 58.
    
                         Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 205:6-15 (Oct. 28, 2014). Back to Citation
 59.
    
                         
                        *Id.*
                         at 206:24-207:7. Back to Citation
 60.
    
                         
                        *Id.*
                         at 210:14-23. Back to Citation
 61.
    
                         
                        *Id.*
                         at 211:25-212:14. Back to Citation
 62.
    
                         ANGA Comments at 2-3; Entergy Nuclear Power Marketing Comments at 11; EPSA Comments at 22-23; Exelon Comments at 11-12; Wisconsin Electric Comments at 2-3; Xcel Comments at 2. Back to Citation
 63.
    
                         Wisconsin Electric Comments at 2. Back to Citation
 64.
    
                         Direct Energy Comments at 2. Back to Citation
 65.
    
                         GDF SUEZ Comments at 3. Back to Citation
 66.
    
                         ISO-NE Comments at 4; MISO Comments at 5-6; New York Transmission Owners Comments at 2-3; NYISO Comments at 3; TAPS Comments at 10-11; California State Water Project Comments at 2-3. Back to Citation
 67.
    
                         Direct Energy Comments at 2; MISO Comments at 9; NCPA Comments at 3; New York Transmission Owners Comments at 4; Wisconsin Electric Comments at 2-3. Back to Citation
 68.
    
                         ISO-NE Comments at 4. Back to Citation
 69.
    
                         OMS Comments at 2. Back to Citation
 70.
    
                         Potomac Economics Comments at 3-4. Back to Citation
 71.
    
                         ELCON Comments at 6; TAPS Comments at 10-11. Back to Citation
 72.
    
                         TAPS Comments at 12-13 (citing Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 217:17-21 (Oct. 28, 2014)). Back to Citation
 73.
    
                         TAPS Comments at 11 (citing Written Statement of Patrick T. Connors on Behalf of WPPI Energy and the Transmission Access Policy Study Group Regarding Impacts of Offer Caps and Market Power Mitigation, at 5 (Dec. 3, 2014)). Back to Citation
 74.
    
                         APPA and NRECA Comments at 31-32. Back to Citation
 75.
    
                         
                        *Id.*
                         at 29-31; California State Water Project Comments at 2-3; New York Transmission Owners Comments at 2-3. Back to Citation
 76.
    
                         APPA and NRECA Comments at 31. Back to Citation
 77.
    
                         
                        *Id.*
                         at 31. Back to Citation
 78.
    
                         
                        *Id.*
                         at 31-32. Back to Citation
 79.
    
                         PG&E Comments at 3-4; SCE Comments at 3. Back to Citation
 80.
    
                         Calpine Comments at 4-6. Back to Citation
 81.
    
                         
                        *Id.*
                         at 21. Back to Citation
 82.
    
                         Powerex Comments at 30. Back to Citation
 83.
    
                         SPP Comments at 1. Back to Citation
 84.
    
                         OMS Comments at 3. Back to Citation
 85.
    
                         ISO-NE Comments at 4-6; MISO Comments at 5-7. Back to Citation
 86.
    
                         ISO-NE Comments at 6. Back to Citation
 87.
    
                         MISO Comments at 5-6. Back to Citation
 88.
    
                         ISO-NE Comments at 6-7. Back to Citation
 89.
    
                         ANGA Comments at 3. Back to Citation
 90.
    
                         Exelon Comments at 12. Back to Citation
 91.
    
                         ISO-NE Comments at 6. Back to Citation
 92.
    
                         
                        *Id.*
                         at 3-4. Back to Citation
 93.
    
                         MISO Comments at 4-5. Back to Citation
 94.
    
                         
                        *Id.*
                         at 5. Back to Citation
 95.
    
                         TAPS Comments at 13. Back to Citation
 96.
    
                         APPA and NRECA Comments at 30-31. Back to Citation
 97.
    
                         
                        *Id.*
                         at 30-31. Back to Citation
 98.
    
                         Direct Energy Comments at 2; Exelon Comments at 12; PJM Comments at 3; PJM Power Providers Comments at 3-4; PSEG Companies Comments at 5. Back to Citation
 99.
    
                         PJM Comments at 2-3. Back to Citation
 100.
    
                         
                        *Id.*
                         at 4. Back to Citation
 101.
    
                         PJM Power Providers Comments at 4; PSEG Companies Comments at 6. Back to Citation
 102.
    
                         APPA and NRECA Comments at 30-32. Back to Citation
 103.
    
                         TAPS Comments at 13-14. Back to Citation
 104.
    
                         APPA and NRECA Comments at 32; CAISO Comments at 6-7, NCPA Comments at 2. Back to Citation
 105.
    
                         CAISO Comments at 4-6. Back to Citation
 106.
    
                         
                        *Id.*
                         at 6. Back to Citation
 107.
    
                         TAPS Comments at 14-15. Back to Citation
 108.
    
                         Direct Energy Comments at 3-4. Back to Citation
 109.
    
                         Brookfield Comments at 8; Calpine Comments at 5; EEI Comments at 9; EPSA Comments at 21; Exelon Comments at 13-14; IRC Comments at 2; ISO-NE Comments at 6-7; MISO Comments at 8; New York Transmission Owners Comments at 3-4; NYISO Comments at 4; PJM Comments at 4; PJM Power Providers Comments at 5-6; PJM Utilities Coalition Comments at 6; PSEG Companies Comments at 6-7; Potomac Economics Comments at 5; Western Power Trading Forum Comments at 6; Wisconsin Electric Comments at 4. Back to Citation
 110.
    
                         IRC Comments at 2; PJM Comments at 4; PSEG Companies Comments at 6-7. Back to Citation
 111.
    
                         ISO-NE Comments at 7; NYISO Comments at 5. Back to Citation
 112.
    
                         NYISO Comments at 4-5. Back to Citation
 113.
    
                         MISO Comments at 8. Back to Citation
 114.
    
                         APPA and NRECA Comments at 29-30; NCPA Comments at 3. Back to Citation
 115.
    
                         APPA and NRECA Comments at 32. Back to Citation
 116.
    
                         Direct Energy Comments at 4; PJM Utilities Coalition Comments at 6. Back to Citation
 117.
    
                         SCE Comments at 2. Back to Citation
 118.
    
                         CAISO Comments at 5. Back to Citation
 119.
    
                         MISO Comments at 5. Back to Citation
 120.
    
                         IRC Comments at 3; New York Transmission Owners Comments at 5. Back to Citation
 121.
    
                         New York Transmission Owners Comments at 5. Back to Citation
 122.
    
                         IRC Comments at 3. Back to Citation
 123.
    
                         
                        *See supra*
                         P 10. Back to Citation
 124.
    
                         
                        *See supra*
                         P 17. Back to Citation
 125.
    
                         
                        *See, e.g., Midwest Indep. Transmission Sys. Operator, Inc.,*
                         108 FERC ¶ 61,163, at PP 380-381, 
                        *order on reh'g,*
                         109 FERC ¶ 61,157 (2004), 
                        *order on clarification,*
                         111 FERC ¶ 61,367 (2005); 
                        *N.Y. Indep. Sys. Operator, Inc.,*
                         97 FERC ¶ 61,095, at 61,496-97 (2001); 
                        *ISO New England, Inc.,*
                         97 FERC ¶ 61,090, at 61,471. Back to Citation
 126.
    
                         
                        *See supra*
                         PP 23-26. Back to Citation
 127.
    
                         PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 2. Back to Citation
 128.
    
                         MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 2. Back to Citation
 129.
    
                         MISO Comments at 4; PJM Comments at 2. Back to Citation
 130.
    
                         
                        *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 2 (Jan. 16, 2015). Back to Citation
 131.
    
                         16 U.S.C. 824e(b). Back to Citation
 132.
    
                         
                        *Wholesale Competition in Regions with Organized Electric Markets,*
                         Order No. 719, FERC Stats. & Regs. ¶ 31,281, at PP 370-375 (2008), 
                        *order on reh'g,*
                         Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), 
                        *order on reh'g,*
                         Order No. 719-B, 129 FERC ¶ 61,252 (2009). Back to Citation
 133.
    
                         PJM 2015/16 Offer Cap Order, 153 FERC ¶ 61,289, at PP 2-3 (2015); MISO, Transmittal at 4, Docket No. ER16-248-000 (filed Nov. 2, 2015); MISO 2015/16 Offer Cap Order, 154 FERC ¶ 61,006. Back to Citation
 134.
    
                         Scarcity and Shortage Pricing, Offer Mitigation and Offer Price Caps Workshop, Docket No. AD14-14-000, Tr. 205:11-19, 206:24-207:7, 210:14-211:8, 212:12-213:3 (Oct. 28, 2015). Back to Citation
 135.
    
                         
                        *See supra*
                         PP 25-26. Back to Citation
 136.
    
                         ISO-NE Comments at 4. Back to Citation
 137.
    
                         CAISO Comments at 3; ISO-NE Comments at 3; NYISO Comments at 4. Back to Citation
 138.
    
                         
                        *See supra*
                         n.36. Back to Citation
 139.
    
                         
                        *See supra*
                         n.16. Back to Citation
 140.
    
                         
                        *Id.* Back to Citation
 141.
    
                         ISO-NE, Markets and Services Tariff, Market Rule 1, III.A.3.1 (43.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, 23.3.1.4.6.7 (11.0.0). Resources in SPP may also contact the Market Monitoring Unit during the operating day and request a mitigation exception pursuant to SPP, OATT, Sixth Revised Volume No. 1, Attachment AF, 3.8 (7.0.0). Additionally, in MISO resources may consult with the Market Monitoring Unit to change reference levels as soon as practicable. MISO, FERC Electric Tariff, 64.1.4.h (30.0.0). Back to Citation
 142.
    
                         For example, CAISO and PJM mitigate resources to cost-based offers that include a ten percent adder, while the standard cost-based offers in MISO, ISO-NE, and NYISO do not include an adder above cost. Back to Citation
 143.
    
                         
                        *See supra*
                         n.16 Back to Citation
 144.
    
                         Any proposal to develop cost-based incremental energy offers for external transactions could address external resources generically or address certain scheduling practices (
                        *e.g.,*
                         dynamic or pseudo tie schedules). Back to Citation
 145.
    
                         To the extent they currently exist, this proposal would not affect existing RTO/ISO tariff provisions that permit virtual transactions to exceed $1,000/MWh. Back to Citation
 146.
    
                         The Commission found it just and reasonable for virtual increment offers and decrement bids in PJM to clear up to $2,700/MWh, equal to the newly established energy and reserve market aggregate price cap. 
                        *PJM Interconnection, L.L.C.,*
                         139 FERC ¶ 61,057, at PP 123-143 (2012). Back to Citation
 147.
    
                         Under this proposal, any make-whole payments associated with such an after-the-fact cost verification would not be duplicative or overcompensate a resource for the costs included in its energy supply offer. Back to Citation
 148.
    
                         Several RTOs/ISOs also rely on procedures to temporarily strip resources of the opportunity to make fuel price related adjustments to their reference levels in the event after-the-fact verification processes fail to confirm the need for the reference level update. 
                        *See*
                         ISO-NE., Transmission Markets and Services Tariff, Market Rule 1, III.A.3.4(c) (43.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, 23.3.1.4.6.8 (11.0.0). Back to Citation
 149.
    
                         18 CFR 35.41(b) (2015). Back to Citation
 150.
    
                         18 CFR 1c.2(a)(2) (2015). Back to Citation
 151.
    
                         CAISO Comments at 6-7. Back to Citation
 152.
    
                         PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 39. Back to Citation
 153.
    
                         
                        *See*
                         MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 16; PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 39; PJM 2015/16 Offer Cap Order, 153 FERC ¶ 61,289; MISO 2015/16 Offer Cap Order, 154 FERC ¶ 61,006. Back to Citation
 154.
    
                         NYISO Comments at 4-5. Back to Citation
 155.
    
                         ISO-NE Comments at 7; NYISO Comments at 5. Back to Citation
 156.
    
                         
                        *See*
                         PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 42; MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 19. Back to Citation
 157.
    
                         CAISO Comments at 8. Back to Citation
 158.
    
                         44 U.S.C. 3501-3520. Back to Citation
 159.
    
                         5 CFR 1320 (2015). Back to Citation
 160.
    
                         44 U.S.C. 3507(d). Back to Citation
 161.
    
                         The RTOs and ISOs (CAISO, ISO-NE., MISO, NYISO, PJM, and SPP) are required to comply with the reforms proposed in this NOPR. Back to Citation
 162.
    
                         The Commission expects that the validation of cost-based incremental energy offers above $1,000/MWh would be an infrequent occurrence. To the extent that the Market Monitoring Unit or the RTO/ISO spends time validating these offers, the Commission estimates such time to be de minimis. Back to Citation
 163.
    
                         The estimated hourly cost (salary plus benefits) provided in this section are based on the salary figures for May 2014 posted by the Bureau of Labor Statistics for the Utilities sector (
                        *available at http://www.bls.gov/​oes/​current/​naics2_​22.htm#13-0000*) and scaled to reflect benefits using the relative importance of employer costs in employee compensation from March 2015 (
                        *available at http://www.bls.gov/​news.release/​ecec.nr0.htm*). The hourly estimates for salary plus benefits are: Legal (code 23-0000), $129.87
                    Computer and mathematical (code 15-0000), $58.25
                    Information systems manager (code 11-3021), $94.55
                    IT security analyst (code 15-1122), $63.55
                    Auditing and accounting (code 13-2011), $51.11
                    Information and record clerk (code 43-4199), $37.50
                    Electrical Engineer (code 17-2071), $66.45
                    Economist (code 19-3011), $73.04
                    Management (code 11-0000), $78.04 The average hourly cost (salary plus benefits), weighting all of these skill sets evenly, is $72.48. The Commission rounds it to $72 per hour. Back to Citation
 164.
    
                         5 U.S.C. 601-12. Back to Citation
 165.
    
                         This estimate does not include costs for software or increased time spent validating cost-based incremental energy offers, for which the Commission requests comment. As stated above, the Commission expects that the validation of cost-based incremental energy offers above $1,000/MWh would be an infrequent occurrence. To the extent that the Market Monitoring Unit or the RTO/ISO spends time validating these offers, the Commission expects such time to be de minimis. Back to Citation
 166.
    
                         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. Back to Citation
 167.
    
                         
                        *Regulations Implementing the National Environmental Policy Act of 1989,*
                         Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). Back to Citation
 168.
    
                         18 CFR 380.4(a)(15) (2015). Back to Citation


[FR Doc. 2016-01813 Filed 2-3-16; 8:45 am] BILLING CODE 6717-01-P