When FERC decided in February, in Order 890, to lift the price cap for electric-transmission customers seeking to resell their grid capacity rights in the secondary market, it cautioned against...
Yet Another Subsidy For Wind?
FERC risks going overboard in easing penalties for generation imbalances.
California Independent System Operator (Cal-ISO) already nets positive and negative wind-turbine schedule deviations over a full month, causing them to largely vanish. Not only that, but, according to the engineering firm Babcock & Brown (B&B), Cal-ISO calls on an independent third party to prepare the schedules for wind plants, based on state-of-the-art software and wind forecasting technology. The monthly net deviation is driven as close to zero as possible, says B&B, and Cal-ISO’s use of a weighted-average price for imbalances lowers risk even further.
In New York, where Gov. George Pataki has committed the state to greatly expand its reliance on wind power, the ISO says it has relieved existing intermittent resources (as well as the next 500 MW of new IRs coming on line) of the obligation to balance actual outputs against scheduled outputs. Wind generators that execute a service agreement under the ISO's market tariff see their imbalances prices at real-time locational marginal prices, without an additional penalty multiplier.
PJM explains that it "does not assess imbalance penalties on any generators, let alone intermittent generators." Instead, virtually all market participants and generators choose to reserve network transmission rights, rather than point-to-point service. Thus, all imbalances are resolved financially using the real-time energy market, as a dollar settlement differential between the day-ahead market (DAM) and the final real-time position, based on the need created for operating reserves (as distinguished from ancillary services).
As PJM explains further, these settlement costs have tended to average just under $1.50/MW over the past several years. Yet PJM notes that wind generators, if they so chose, could lower the differential even further by taking better advantage of the day-ahead market (DAM). As PJM notes, so far the wind players "generally have not yet made the investments that would allow them to better predict their next-day output," and tended instead to forgo the day-ahead market and incur the relatively modest PJM cost already noted.
In New England, where intermittent resources represent about 2.55 percent of all generation, the RTO explains that IRs enjoy an exemption from participating in the DAM. They simply do not incur a DAM monetary position, and hence are not subject to RTO's regime of charges and credits for real-time deviations.
Then there is the Bonneville Power Administration (BPA), which has embraced a rather progressive policy.
As BPA explains, it has exempted wind generators from FERC's $100 death penalty and instead has substituted a regime with three separate dead bands, with deviations priced on a sliding scale:
- Band 1. Deviation of greater of 2 MW or plus or minus 1.5 percent of schedule, trued up monthly, priced without penalty at the Dow Jones Mid-C energy index;
- Band 2. Between 1.5 and 7.5 percent of schedule (and at least 10 MW), settled with a penalty charge of 10 percent of incremental or decremental cost;
- Band 3. Deviations greater than 10 MW or 7.5 percent of schedule, settled at a penalty of 25 percent.
BPA's sliding scale has attracted a fair degree of praise in the comments filed at FERC.
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