What's in NERC's new Reliability Standard for Frequency Response?

FERC has issued a Notice for Proposed Rulemaking (NOPR), agreeing with NERC's proposed change of reliability standard for Frequency Response from standard BAL-003-01.b to BAL-003-1. This article is an effort trying to understand the difference between the two. I can't say that I have complete understanding of Frequency Response, hence an effort, instead of an analysis.

How is Frequency Response/Frequency Bias determined for each Balancing Authority (BA)?
BAL-003-01.b (the Old Rule) gives each BA the freedom to decide what their Frequency Bias Setting should be. BAL-003-1 (the New Rule) mandates how each BA should calculate Frequency Response and in turn decide what the Frequency Bias Setting should be.

NERC's filing explains the how to go from Frequency Response to Frequency Bias Setting very well. Picture a balanced grid suddenly lose one generator,

1. The grid is now unbalanced, there's a tendency to extract the kinetic energy stored in the rotating turbines to make up for the loss of generation. The turbines slow down; the frequency of the grid decreases.  
2. The Governor Control of the turbine senses this decrease in frequency. It opens the valves to let in more fuel, or mechanical input power, to generate more energy. The collective action of all the Governor Controls is the Interconnection's Frequency Response Characteristics. In other words, when a loss of generation happens, to what degree does it affect the frequency and how long does it take the Interconnection to stabilize, or capture the frequency drop. (see following illustration from NERC filing, Exhibit D, p.41)
   
   
   
3. What' more interesting is what happens next. After the Governor Control kicks in to capture the frequency drop, the Secondary Response, Automatic Generation Control (AGC) would then try to restore the frequency back to its desired setting. AGC is based on Area Control Error (ACE).

$ACE = [NI_{A} - NI_{S}] - [10B(f_{A}-f_{S})]$

The first bracket is the difference between the actual and scheduled power flows on the tie lines between each BA. If the lost generator is not in the BA (non-contingent BA), from the steps described above, the generators would start to output more energy to counteract the frequency drop, and the actual power flow on the tie lines would be higher than that scheduled. If ACE is only composed of the tie-line exchanges, the first bracket is positive, and the ACE-directed AGC would start to counteract the generators generating more energy.
Hence the second bracket. If B (Frequency Bias Setting) is commensurate with the BA's share of Frequency Response Characteristics, the first and the second brackets would cancel each other out so that the AGC doesn't counteract the generators' Governor Control. Based on the frequency drop profile, I would think that second bracket has to be slightly larger than the first so that the generators not only capture the frequency drop, but also restore the frequency to its original setting. Need to dig in more on this.

In summary, Frequency Response is a primary control parameter that the generators react on their own depending on the Interconnection's frequency. Frequency Bias Setting is closely related to Frequency Response, but is a parameter in secondary control. Keep in mind that the difference between primary and secondary control is the time to reaction based on existing (out-dated) capabilities of the generating fleet. New renewable generation and fast-reacting devices may change this scheme completely.

Back to where we started, the loss of generation events that are large enough to observe the Frequency Response Characteristics do not happen very often (good news!). The New Rule defines the qualifications of events to be used to calculate the Frequency Response Characteristics and proposes using medium, instead of mean, of the calculated Frequency Response of each event to be the annual Frequency Response.

So exactly how does the New Rule affect each BA? I think each BA now has to meet a higher standard of Frequency Response. Where would they get this Frequency Response? Exhibit F of the NERC filing documented a survey of how the Governor Control is implemented for different types of generation resources and ERCOT's experiment decreasing the deadband and eliminating step change of Frequency Response. The BAs would have to ask each generator to come up with an improved Governor Control or tap into other types of frequency-responsive resources.

California Public Utility Commission's Storage Rulemaking: the Targets

Use case category, by utility	2014	2016	2018	2020	Total
SCE
Transmission	50	65	85	110	310
Distribution	30	40	50	65	185
Customer	10	15	25	35	85
Subtotal SCE	90	120	160	210	580
PG&E
Transmission	50	65	85	110	310
Distribution	30	40	50	65	185
Customer	10	15	25	35	85
Subtotal PG&E	90	120	160	210	580
SDG&E
Transmission	10	15	22	33	80
Distribution	7	10	15	23	55
Customer	3	5	8	14	30
Subtotal SDG&E	20	30	45	70	165
Total	200	270	365	490	1,325

 

California Public Utility Commission (CPUC) has recently put out the Proposed Decision for Energy Storage Rulemaking (R. 10-12-007) with the above Procurement Targets for each Investor-owned Utility (IOU) in California. In responding to stakeholder's concerns that there's no demonstrated need for additional resources, CPUC stated that,

"In other policy areas promoting preferred resources, such as renewables, the California Solar Initiative and demand response, the Commission has not set targets based on a system need determination, but rather administratively determined procurement requirements to meet public policy objectives. To the extent that energy storage is treated akin to a “preferred resource,” as it has been designated in D.13-02-015, the Commission has clear precedent to administratively establish storage procurement targets without a system needs determination." (from sec. 4.4.3).

As a renewable energy/energy storage enthusiast, it's quite difficult to take a stand on such statement. It is a chicken and egg problem. The market does not procure energy storage because it is still too expensive; energy storage technologies cannot become cheaper by economies of scale if there isn't a big enough market. CPUC is trying to create the market with the procurement target. But stating that it's not necessary to figure out the system needs because that's the way we have been doing things is hardly convincing.

In this case, CPUC is concerned with treating all Preferred Resources equally: if renewables and Demand Response (DR) had administratively determined procurement targets, Energy Storage shouldn't have to go through the system needs evaluation but should have an administrative target as well. We all know the consequences of setting targets without knowing the actual need: we either end up building too much or realizing that the target is not enough. Such administratively determined procurement target gives room for stakeholders to argue both ways: the target can be too low for some and too high for others.

To be fair, CPUC did ask the IOUs to include in the bi-annual solicitation application,

Reference to 1) needs study by the California Independent System Operator for the IOU’s system, local, and flexible needs, if available, or 2) upgrade needs identified in the IOU’s transmission or distribution planning studies; 

CPUC does believe in making a decision based on analysis, but probably is very afraid of paralysis by analysis. That being said, the lack of scientific reasoning (system need) or economic reasoning (how big the market needs to be for Energy Storage to become cost-effective) behind the arbitrary numbers is worrisome. It makes you wonder: how did CPUC come up with the targets for renewables and DR?