A re-defined capacity product, revised parameters for generator performance, and a new role for demand response.
PJM would minimize risk, but so did regulation.
If PJM markets should lose demand response as a capacity resource.
Mississippi draws a line in the sand.
PJM and MISO ran from the altar once before. Now there’s talk of a shotgun wedding.
Does the lack of long-term pricing undermine the financing of new power plants?
The PJM Interconnect’s Reliability Pricing Model generally has succeeded in attracting and retaining low-cost generation and demand resources to maintain resource adequacy. But sluggish demand and low prices have weakened the market for long-term capacity contracts. Suppliers aren’t willing to lock in current low prices, and buyers don’t want to pay more for future certainty. Is the market dysfunctional, as some state lawmakers suggest, or does the lack of long-term contracts indicate a rational balance of supply and demand?
2011 Groundbreaking Law & Lawyers Survey and Report
With a flurry of major new environmental regulations, the Environmental Protection Agency (EPA) is altering the power generation landscape. But will the new federal rules survive court challenges—to say nothing of next year’s national elections? Fortnightly's Michael T. Burr considers the controversy over new environmental standards. PLUS: Top Utility Lawyers of 2011.
1. ‘Policy’ Guides the Grid; 2. Carbon Not a Nuisance (Yet); 3. Gigabucks for Negawatts; 4. A MOPR, Not a NOPR; 5. Ramp Up the Frequency; 6. Cap-and-Trade Still Lives; 7. Cyber Insecurity; 8. Korridor Killer; 9. The Burden Not Shared; 10. Ozone Can Wait.
When you sell demand response back to the grid, how much capacity are you now not buying?
When customers sell demand response into a regional capacity market (such as PJM’s Reliability Pricing Model, known as the RPM), how much credit should they earn for agreeing to curtail demand and alleviating stress on the grid — that is, for reducing the market’s need for generating capability and capacity reserve margin? And further, should the amount of credit depend on whether the customer works with market aggregators, known both as CSPs (“Curtailment Service Providers”) or ARCs (“Aggregators of Retail Customers”)? One view would pay customers for the full extent of their curtailment of demand — known as its “Guaranteed Load Drop” (GLD). The other would limit capacity credit to the customer’s prior load history — “Peak Load Contribution,” or PLC. The answer may well dictate whether regulators continue to treat “energy” and “capacity” as two distinct concepts.
Out of market means out of luck—even for self-supply.
When the U.S. Federal Energy Regulatory Commission issued its so-called ”MOPR“ decision in April 2011, approving a minimum offer price rule (or bid floor) for PJM RPM capacity market — and then on the very next day did much the same for New England’s FCM capacity market — FERC did more than just prop up prices. Instead, it created a nightmare scenario for utilities that still own their own generation. These utilities, who choose to “self-supply” with their own plants, rather than buy capacity from either the RPM or FCM, adequacy rules, could now be forced to pay twice for capacity — if their own plants are deemed inefficient or uneconomic.