FERC risks going overboard in easing penalties for generation imbalances.
Bruce W. Radford is editor-in-chief for Public Utilities Fortnightly.
Take an actual wind farm, this one with a capacity of 102 megawatts (MW), developed and brought on line by FPL Energy. Now consider what happened next with the Oklahoma Municipal Power Authority (OMPA), which owned a 50 percent share in the facility during its first full year of operation, beginning Sept. 29, 2003.
According to records assembled and analyzed by the Transmission Access Policy Study Group (TAPS), an association of municipal and other transmission-dependent utilities (TDUs), the wind farm did just about as good a job of incurring penalties for imbalances as producing profits from actual power sales.
Over the first 12 months, from October 2003 through September 2004, OMPA's share of the wind farm produced more than 154,000 MWh, at an average unit cost of $16.33/MWh. So far so good.
But wind is fickle. Wind turbine output often failed to match the schedules that OMPA would have filed with the control area operator (now also known as the balancing authority). In fact, over the full year, OMPA recorded some 14,000 MWh of excess power deliveries. Shortfalls ran higher—at 40,688 MWh—and that's the problem of most interest here.
These shortfalls, under typical transmission owner tariffs governing generation imbalances, and permitted by the Federal Energy Regulatory Commission (FERC), likely would have given rise to more than $3.4 million in imbalance penalties. That’s $22.10 per MWh—a third higher than the production cost. These harsh charges would have come from FERC’s so-called $100 “death penalty” ($100/MWh, or 10 cents per kilowatt-hour), which is calculated on all generator imbalances that exceed a dead-band of the greater of 2 MW, or plus or minus 1.5 percent of the plant’s schedule. (Energy imbalances, which occur when customer demand runs higher or lower than promised by load-serving entities, also trigger an identical $100 penalty, outside of an identical dead-band.) These penalties are sanctioned by FERC Order No. 888, which allowed transmission providers to build them into their generation interconnection agreements, for generation imbalances, and their pro forma open access transmission tariffs (OATT), for energy imbalances.
To be accurate, the TAPS analysis assumes that OMPA would have avoided its $16.33/MWh production cost on the under-deliveries, so that the net penalty would have come in a bit less than $100/MWh. And, to be conservative, TAPS recognizes that some economists might instead credit OMPA with a higher avoided production cost of $50. That would be the cost of production of a gas-fired turbine burning fuel at prices of $5/MMBtu, at a heat rate of 10,000 Btu/kWh-the theory being that a wind farm might actually turn to purchased power on margin in the short term to meet all its delivery obligations. Yet, even in this most conservative case, OMPA's wind-farm investment would have racked up more than $2 million in penalties for generator imbalances, worth $13.20/MWh, or nearly as high as the $16.33 cost of the power itself. (See FERC Docket No. AD04-13, Post-Technical Conference Comments, pp. 4-8, filed Nov. 1, 2004.)
How could regulators let this happen?
Alas, in the real world, control area operators must keep generation constantly in balance with load over small time intervals, to regulate voltage and cycle frequency on the grid. Thus, as instructed by the North American Electric Reliability Council (NERC), grid operators must maintain an average ACE (area control error) within a specific limit for at least 90 percent of the 10-minute intervals that occur in a given calendar month. This activity is known as the ancillary service of "regulation," and it can be costly to provide, perhaps even requiring a second set of generation resources to offset the volatility in output of the wind turbines. To minimize this need, FERC prescribed the 3 percent dead-band and $100 penalty in Order No. 888 as a matter of "good utility practice."
Of course, Order No. 888 and the pro forma tariff assumed that all generation was dispatchable—that generators could forecast and control their output in real time. The $100 penalty seemed reasonable to guarantee a smooth-running grid, for scheduling plant deliveries, as well as for promising ratepayer load at the receiving end.
But what good is a penalty that does nothing to deter the crime? For wind turbines, generation imbalances are caused primarily by variations in weather. Even if these imbalances are indeed a bad thing, no $100 penalty will make them go away.
Also, much has changed in the decade since FERC issued Order No. 888. Wind power has made tremendous inroads. Spurred by complaints from the wind power industry, and by technical analysis such as provided by TAPS, FERC has come to believe that the current regime of penalties for generation imbalances amounts to rate discrimination against wind power, discouraging investment in turbines farms. And so FERC now has sought to craft a remedy.
Accordingly, on April 14, FERC proposed a new rule for the pro forma tariff, applicable only to “intermittent resources” (IRs), as defined by the rule. This proposal, designed to put wind power on par with thermal plants, promises to reduce the seemingly harsh penalties for generator imbalances.
First, FERC would kill the $100 death penalty. Second, the commission would create a broader 20 percent dead-band, the greater of 2 MW or plus or minus 10 percent above or below schedule. For deviations within the dead-band, wind turbine owners would make up the difference at cost. They would buy back the imbalance shortfall at the transmission provider's incremental cost, and receive credits for excess deliveries at decremental cost. Only those imbalance amounts exceeding the dead-band would incur a penalty, calculated at only 10 percent. In other words, wind would buy back these outlier deviations at 110 percent of incremental cost for shortfalls, and would "sell" the surplus at 90 percent of decremental cost. (See FERC Docket No. RM05-10, notice of proposed rulemaking filed Apr. 14, 2005, and industry comments filed through July 7, 2005.)
At first blush, FERC's proposal might look like a win-win. In truth, virtually all sides of the power industry appear to be relieved to see the end of the $100 penalty for generator imbalances-even those most skeptical of renewable energy. Yet the proposal still has met with considerable opposition.
Glen Schleede, a former utility executive, and perhaps the most vociferous critic of wind power, calls the proposal "illogical and probably illegal."
On one hand, as he notes, FERC admits that electricity from wind turbines imposes cost requirements on the grid because of its uncontrollable output and thus carries less implicit value. As evidence of that lesser value, some utilities, such as the Western Farmers Electric Co-op., in western Oklahoma, have shown how high local concentrations of wind-turbine capacity may force them to resort to base-load coal-fired plants with slow ramping rates to provide regulation and voltage control. That's far from ideal, as explained in more detail in Figure 1.
Yet, on the other hand, as Schleede adds, FERC concludes that tariffs that recognize this lower intrinsic value for wind turbine output must somehow be unduly discriminatory!
Danger lurks in singling out one particular power plant technology for special treatment. Consider, for example, the comparison between: (a) wind turbine output; and (b) customer load-both which are weather-driven, volatile, and difficult to control or even forecast. Why isn't FERC proposing to kill the $100 penalty for energy imbalances, which occur when consumer load deviates from schedule?
In particular, consider that many electric consumers operate their own distributed generation resources, behind the meter, such as rooftop solar panels or wind turbines for water pumping. Public power lawyers Robert McDiarmid and Cynthia Bogorad add that even FERC's Washington, D.C., headquarters features solar panels that generate power that reduces the building's net retail electric consumption, and that the fluctuations in output are readily visible on a readout in the building's entrance lobby.
This sneaky but apt example shows that, in some cases, volatility in downstream ratepayer load (and hence the energy imbalance) can be attributable to the same variations in weather that drive fluctuations upstream at the generating plant, and yet FERC promises relief for one, but not the other. Imagine this issue up on appeal.
Glenda Lanik, assistant general counsel for Tri-State Generation and Transmission, a "G&T" co-op association serving non-profit member utilities in Colorado, Nebraska, New Mexico, and Wyoming (all prime areas for wind power development, by the way), sums up the problem quite nicely.
"The commission," she notes, "has no legislative mandate to pursue these issues."
This problem, like so many others these days, exists largely for wind-power operators and developers located outside the boundaries of a FERC-sanctioned regional transmission organization (RTO) or independent system operator (ISO). For, as it happens, most RTOs and ISOs seem to have done away with any severe penalties for generator imbalances.
Thus, FERC's proposal appears designed primarily for non-RTO areas, and in fact contains an explicit escape clause (the "independent entity" rule) that allows RTOs to adopt or preserve rules for wind generator imbalances that differ from the FERC scheme.
For example, under a program known as PIRP (Participating Intermittent Resource Program), approved in 2002 (98 FERC ¶61,327), the 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.
The Big Picture
Viewed from 40,000 feet (putting aside for the moment the matter of whether FERC ought to subsidize a specific energy technology) the issue tends to boil down to several micro squabbles, plus one really big question that will force the power industry to take a good look at itself.
First, FERC has proposed to define intermittent resources eligible to the new rule rather loosely: any electric generator "that is not dispatchable and cannot store its fuel source and therefore cannot respond to changes in system demand or respond to transmission security constraints."
Yet wind turbine blades already can be "feathered" to control output. Also, with today's software, a wind farm operator ought to be able to employ SCADA systems to manage a cluster of turbines to control output to some degree. Many parties have warned FERC instead to define the rule in terms of "weather-driven" resources, so as not to get tripped up down the road when this or that technology takes an unexpected turn.
Second, FERC specifies the new 10 percent penalty for deviations outside the dead-band in terms of incremental and decremental cost, as defined in a 1999 case (87 FERC ¶61,170) as a function of cost of fuel, unit heat rate, start-up cost, operation and maintenance, taxes, and purchase interchange power. The proposal makes no mention of capacity costs, nor does it attempt to use real-time market prices to calculate the new imbalance penalty. That means, as many have pointed out, that if transmission providers in areas with a high degree of wind-turbine penetration find it necessary to construct power plants to provide ancillary services to back up the wind power, that the capacity costs will fall through the cracks, with utility ratepayers left paying the bill.
Many also warn of arbitrage: that when real-time market prices deviate significantly from the fuel-based incremental and decremental cost calculation, any savvy wind farm operator would gladly pay the 10 percent penalty for a real-time over-delivery that could be sold at market for much more. They have urged FERC to use some form of a market price indicator to calculate the imbalance penalty, rather than a static cost-based benchmark.
Nevertheless, the real question is more challenging. Are imbalances the enemy, or should the electric industry instead think about reorganizing itself to adapt to the coming age of wind power?
The record in the FERC case is flush with complaints from small-scale utilities (many are co-ops) operating in rural areas, where wind power potential is greatest. They say they cannot deal with high concentrations of turbines, due to the costs of forecasting, regulation and voltage control, and integrating a new and strange animal into the resource mix. Yet the answer may lie in still heavier investment in wind (lowering unit costs for these services), and operating control areas and bulk power systems at much larger scales.
Consider, for example, the recently concluded landmark study on wind energy development potential conducted by GE Energy, TrueWind Solutions, AWS Scientific Inc. and others, for the New York ISO, and the New York State Energy Research and Development Authority. (See, Effects of Integrating Wind Power on Transmission System Planning, Reliability, and Operations-Phase 2 Report on System Performance Evaluation," March 4, 2005, posted at www.uwig.org/operatingimpacts.html.)
According to the Utility Wind Interest Group, this study (and another notable study conducted in Minnesota for Xcel Energy), shows that by far, there is less cost impact in the timeframe of hour-ahead wind forecasting, or near-real-time scheduling of wind turbines, designed to assist the real-time control room operator than the day-ahead energy market.
In other words, programs such as Cal-ISO's PIRP, which focus solely on netting out the short-term imbalances, are "probably not optimal," as UWIG explains, from the point of view of "minimizing the all-in cost impacts at the system level."
"Costs in the regulation and load-following time frame," UWIG continues, "are measured in the 10s of cents per MWh, while the costs in the unit commitment time frame are measured in dollars per MWh.
"Studies done to date have analyzed wind scenarios using a generation portfolio that is not necessarily optimal for large quantities of wind," adds the group.
"A different mix of conventional units with shorter start times and more ramping capability will increase the limits of wind penetration in a given control area, and should be considered in future planning scenarios."
If these comments are valid, then the NYSERDA study implies that tomorrow's generating mix ought to look very different, and that thinking outside the box might be the best way to put the imbalance problem to bed.