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May 13, 2016
Order on Rehearing on PJM Capacity Performance Product

FERC issued an Order on Rehearing regarding PJM's Capacity Performance Product. In a prior Order FERC had approved, subject to certain conditions, PJM's proposal to establish enhanced capacity resource performance requirements, a Non-Performance Charge, an Performance Bonus Payment, a must-offer requirement applicable to capacity performance resources and a transition mechanism through May 31, 2020. In response to multiple petitions for rehearing, FERC issued a Rehearing Order in which it, "affirm[ed] the Commission’s finding in the Capacity Performance Order that PJM’s proposal represents a just and reasonable improvement to PJM’s capacity market design. PJM has presented compelling evidence in this proceeding that capacity resource performance has deteriorated significantly since PJM implemented its Reliability Pricing Model (RPM) to ensure resource adequacy in the PJM region. The Polar Vortex events of the winter of 2013-14, when 22 percent of the generation in the PJM region failed to respond on the peak winter day, illustrated the severity of this performance deterioration." FERC also found that the, "Non-Performance Charge rate, which not only establishes the rate at which capacity resources will be penalized for under-performance, but is also a determinant of each market seller’s offer cap applicable when PJM determines the seller may have market power. . . is just and reasonable."

Chairman Bay issued a lengthy dissent to the Rehearing Order. He noted his dissent to the original Capacity Performance Order on the grounds that, "the Commission failed to adequately consider the costs of the proposed changes or to compare those costs with the potential benefits. Indeed, the record to date suggests that the multi-billion dollar cost to consumers exceeds the benefits. Furthermore, and equally important, the market design itself is flawed. Compensation for capacity resources is so generous, and the penalties for non-performance are so weak, that resources can profit even if they are unable to perform when they are most needed, thereby undercutting the very purpose of the program." Bay said the Rehearing Order failed to correct either error. With regard to costs, Bay noted that, "Since issuance of the Capacity Performance Order, PJM has run three capacity performance auctions. We now know that the costs are in the billions. The first auction occurred in August 2015 for the 2018-19 delivery year. This auction procured 80 percent capacity performance and 20 percent base capacity. The price tag for capacity performance was $9.34 billion; capacity performance cleared at $179.60/MW-day or .60 of Net CONE. PJM next held two transition auctions in which base capacity was replaced with capacity performance: 60 percent for the 2016-17 delivery year and 70 percent for 2017-18. This gave resources that had received a base capacity award – and were already obligated to provide capacity in the delivery year – the opportunity to re-offer the capacity as capacity performance. This added $2.30 billion in incremental costs for the 2016-17 delivery year. Capacity performance cleared at $134/MW-day or .41 of Net CONE. The 2017-18 transition auction added costs of $1.63 billion. Capacity performance cleared at $151.50/MWday or .43 of Net CONE." Bay concluded by stating, "Reliable operation of the electric grid is a central goal of the Commission, PJM, and the participants in our markets. When designed appropriately, capacity markets can help ensure that resources are properly compensated for delivering reliable power to consumers at just and reasonable rates. Nevertheless, the majority fails to adequately consider the design of the market, the costs of capacity performance, or the balance of those costs against the potential benefits. As a result, we do not know whether consumers pay a just and reasonable rate for capacity, and we do not know whether they will receive the service they are purchasing. Such an outcome cannot be the product of reasoned decision making."

The full texts of the Order and Dissent are available on the NEM Website.

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Investigation on WGL Billing System and Impact on Competition

The Commission opened an investigation into WGL's implementation of a new billing system and, "its impact on customers, on the approval process for natural gas suppliers, and on competition in the natural gas retail market in the District of Columbia." WGL will launch a new billing system in the fourth quarter of 2016. The Commission noted that a new billing system can offer increased functionalities and billing options as well as the incorporation of suppliers onto the system in a more timely fashion. However, "the initial testing and implementation process can also adversely impact a company’s ability to timely and accurately distribute customers’ bills," in the required format.

Interventions are due ten days from the date of the Order. The full text of the Order is available on the NEM Website.

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Department Opens Investigation on Revisions to Net Metering Regulations

A law passed this spring, An Act Relative to Solar Energy, requires the Department to revise its rules regarding net metering. The Department issued an Order adopting emergency regulations to implement the Act. Prior to the Act becoming effective, the net metering limits for public and private projects, referred to as public and private caps, had been or were nearing being met by the utilities. The Act increased the public and private caps, and the Department ordered those new caps become effective as of the date of the Order. The private cap is raised to seven percent of each utility's historical peak load, and the public cap is raised to eight percent of each utility's historical peak load. The emergency regulations include a process for utilities to seek a "monthly minimum reliability contribution" on electric bills for customers receiving Net Metering Credits.

The Department is requesting comments on the emergency net metering regulations, including the following topics:
"1. The process for Distribution Companies to calculate Net Metering Credits for Solar Net Metering Facilities that are interconnected prior to the Notification Date and seek to expand such facilities after the Notification Date;
2. Whether the Act permits Distribution Companies to provide payment to Class III Solar Net Metering Facilities receiving Market Net Metering Credits in lieu of a Net Metering Credit on an electric bill;
3. Whether the term “government entity” as used in the Act, Section 3, which states that “credits shall only be allocated to an account of a municipality or government entity,” should be interpreted to have the same meaning as “other
governmental entity” as used in G.L. c. 164, § 139;
4. Whether including in the definitions of Class I Net Metering Facility and Class I Solar Net Metering Facility the phrase “is not a transmission facility” is appropriate; and if so, whether the definitions of Class II Net Metering Facility, Class II Solar Net Metering Facility, Class III Net Metering Facility, and Class III Solar Net Metering Facility also should reference that the facility is not a transmission facility;
5. At what time and under what circumstances the Department may consider proposals for a monthly minimum reliability contribution;
6. What process should the Department use to consider the monthly minimum reliability contribution;
7. Whether the Department should exempt or modify a monthly minimum reliability contribution for low-income ratepayers;
8. Whether the Department should exempt any class or sub-class of net metering facilities that were in service before December 31, 2016;
9. What would be a reasonable amount of time between (a) the Department of Energy Resource’s (“DOER”) determination that the aggregate nameplate capacity of Solar Net Metering Facilities qualified under G.L. c. 25A, § 11F(g), is equal to or greater than 1,600 MW direct current and (b) the Notification Date to be established pursuant to Department Order following receipt of the DOER’s determination; and
10. In defining the process for calculating Net Metering Credits in 220 C.M.R. § 18.04, should the term 'Basic Service' be used rather than the term 'Default Service.'"

Comments are due June 15, 2016, and reply comments are due June 20, 2016. The full text of the Order is available on the NEM Website.

New Jersey
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Board Proposes Readoption of TPS Marketing Standards

The Board is proposing the readoption of Third Party Supplier (TPS) advertising and marketing regulations adopted to implement statutory requirements enacted through P.L. 2013, c. 263. The regulations proposed to be readopted prohibit, "electric power suppliers, gas suppliers, brokers, energy agents, marketers, private aggregators, sales representatives, and telemarketers," from making false or misleading advertising and marketing claims to potential residential customers. The regulations also prohibit those entities from contacting a potential residential customer by telephone for the purpose of making an unsolicited advertisement or marketing of their services if the entities do not have a preexisting business relationship with the customer and the customer's phone number appears on the "no telemarketing" list maintained by the Division of Consumer Affairs or the FTC's national "do not call" registry. If an entity violates these provisions it must pay to the residential customer, "an amount equal to all charges paid by the residential customer after such violation occurs." Violations of these requirements will also subject these entities to liability for a civil penalty. The Board also has authority to revoke an entity's license for violation of these provisions. Comments on the rule readoption are due by July 1, 2016. The full text of the Proposed Rule Readoption is available on the NEM Website.

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