When renewables drop off the grid, how much should the state pay for replacement electricity? That policy was center stage at a joint Feb. 26 meeting by state regulators and the California Independent System Operator in San Francisco. Regulators, the CAISO, utilities, and generators agreed that a mechanism is needed to narrow the gap between the California Public Utilities Commission\u2019s one-year \u2018\u201dResource Adequacy\u201d requirement, and its 10-year energy planning process for investor-owned utilities in an evolving energy landscape. Resource adequacy is used to meet the state\u2019s 15 percent power generation cushion, which was adopted after the 2000-01crisis to avoid blackouts. At issue this week is the growing gap between 12-month resource adequacy deals, which are too short to incentivize new and cleaner generation, and longer term power agreements in the works to meet projected needs in the decade-long planning process for utilities. That gap is expected to become a chasm with the rise in renewable supplies under the state\u2019s 33 percent green electricity mandate, with much of it intermittent. Also, the future system faces retirements of ocean water-cooled and other aging fossil-fueled plants. \u201cThe problem is right around the corner,\u201d said Mark Ferron, California Public Utilities Commission member. The issue is expected to come to a head in less than three years--by 2015. A possible market to sign up supplies of \u201cflexible capacity\u201d from a wide range of resources --traditional and new--for three to five years is getting considerable attention. The definition of the underlying qualifying capacity, however, is unsettled, but it generally entails megawatts and negawatts (both generation and demand-response) that can quickly address power shortages in locations designated by the grid operator. State agencies are debating how much to pay generators for supplying power or curtailing energy demand. \u201cWe have to think more broadly about this or CAISO is going to stick with gas plants\u201d to fill in power voids, warned Steve Berberich, grid operator chief executive officer. A key matter is that current payments to generators who help balance the grid when supplies ebb and flow are deemed inadequate. Regulators, the grid operator and generators say there\u2019s not enough incentive to keep independent plants on standby or to build new ones that can ramp up on short notice. At the same time, current practice goes against the grain of state policy, which gives top priority to energy efficiency, demand-response to curb peak load, and cleaner sources of energy. The existing payment structure pays the most to aging, inefficient power plant capacity, discouraging upgrades and new plants, according to a CPUC paper issued last week (Current, Feb. 22, 2013). Many advocates of what is known as a multi-year capacity market, which reveals power price tags, argue that all resources bid into that market--fossil or renewable generation, energy efficiency, demand side resources or energy storage--should get the same price. \u201cAll resources should compete on level playing field,\u201d said Johannes Pfeifenberger, Brattle Group principal. Others, including utility representatives, disagree. They don\u2019t want to pay the same price for less-costly demand-response negawatts and higher-cost juice from a new power plant. Also at issue is how to shape this new state market or mechanism in a shifting energy landscape given future load uncertainty. That includes who is using how much and where it\u2019s going on the grid. Other parts of the country have developed a multi-year capacity market, in particular PJM, which could provide California a blueprint. PJM launched a regional capacity market in 2006. Multi-year payments entice the lowest-cost resources, which reduces system costs for customers by creating a transparent market and boosting demand response and energy efficiency, according to Andrew Ott, PJM senior vice president of markets. That included 1,000 (n)MW from efficiency in the last market auction, which \u201cwouldn\u2019t have been seen without the revenue stream from the forward capacity market.\u201d \u201cIt brought in resources we never thought could meet the capacity needs,\u201d Ott said. Like California, PJM\u2019s East Coast region is facing a high level of power plant retirements-- about 20,000 MW of soon to be shuttered coal plants. But the East Coast experience was not all good news. Stakeholders of a West Coast capacity market beware, warned an East Coast consumer advocate. A capacity market could override state policies promoting alternative resources. \u201cThere is an inherent tension between a central capacity market and state policy,\u201d said Stefanie Brand, director of New Jersey\u2019s Division of the Rate Counsel. New Jersey is part of the PJM grid. She said her state\u2019s push for renewable energy was overshadowed by the capacity market and its drive for low prices.