PJM Interconnection: Model of a Smooth Operator

POWER & ENERGY

During the summer of 1999, searing heat waves across the United States set air conditioners roaring and brownouts rolling through the grid--that network of substations, transformers, cables, and towers that conducts the flow of electricity from supply center to demand point. While local utilities faced outages at the distribution level in the mid-Atlantic states, grid operator PJM Interconnection LLC, of Norristown, Pa., kept its transmission network humming, though not without some difficulty and what the company calls "learning experiences."

PJM is an independent system operator, that is, an independent organization coordinating the movement of power through the transmission network across and within its region. Transmission networks, like the one PJM manages, operate at 230 kV and higher, channeling electricity into and out of utility-controlled lower voltage subtransmission and distribution networks [see "How the grid really works"].

As part of its services, PJM ensures that the grid remains stable, regardless of power flow, and that the right parties receive and pay for the energy moved through its system. It does its job well--or so the Federal Energy Regulatory Commission (FERC), in Washington D.C., seems to think. When the commission issued Order No. 2000 in December 1999 calling for the establishment of regional transmission organizations (RTOs) or coordinating bodies, it cited PJM repeatedly, in footnotes, as a good example to follow [see "The FERC vision of an RTO"].

PJM has coordinated the transmission grid across most of the Mid-Atlantic states ever since 1927, when it began as a power pool. Formed of a group of power systems, it operated as an interconnected system sharing resources in Pennsylvania, New Jersey, Maryland, Delaware, Virginia, and the District of Columbia. (Back then, PJM stood for the first three of those states, but today it serves simply as a reminder of its origins.) The current company established itself as a separate entity from its original pool members in 1993, receiving FERC approval in 1997 to become an independent system operator. In January 1998, it became fully functional, complying as well with FERC Order No. 888, which required it to offer all comers open and equal access to the transmission network it operated [Tables 1and 2].

Having expanded from a pool of seven members into a grid operator with over 170 participants nationwide, PJM now controls over 12 870 km of bulk-power transmission line and dispatches (or orders to run or not) 540 generating units. By all accounts, PJM gets high marks for the work it does. But even a smooth grid operator like PJM has what it sees as one cloud on the horizon--proposed legislation that would give enforcement power to what is now a voluntary body charged with overseeing grid reliability across North America.

On the high wires

Because there is never a time when electricity is not in demand, and because the storage of electricity on a large scale is impractical, PJM is constantly doing something of a high-wire act. It oversees the market for electricity in its region, simultaneously handling the logistics for its transfer from power producers (either directly or through a third party) to utilities and large power consumers. Specifically, the company balances demand, including load and line losses, with supply--that is, power generated for its territory (known as network generation whether generated within its territory or not). At the same time, it must account for the power just moving through its grid enroute to another territory (so-called interchange power).

The nucleus of this operation is just five people and five workstations in an underground bomb-proof control room, in a nondescript building, in an industrial complex near Valley Forge, Pa. Of course, more controllers are on duty if it is a period of high demand, as in the summer, or if an event, say a hurricane, is likely. Behind the scenes, however, are hundreds of employees who handle metering, accounting, market development, customer relations, engineering, member and employee training, and other business operations necessary to manage the flow of electricity.

The five control room operators each sit at an expansive workstation fitted with computers and telephones. Two things strike the first-time visitor: how few people are in the large room and the magnitude of the schematic of the transmission network occupying its entire front wall. The drawing is 6 meters high. Despite the serious nature of the job and the unremitting pressure to be on the alert for any anomaly or alarm, the setting looks a picture of calm from the viewing gallery on the floor above. (Almost never is a visitor allowed on the control room floor.)

Control room operators are trained extensively in all aspects of the job, learning the responsibilities of each of the five stations over time. Every workstation has its own computers to handle its particular function and area of responsibility, though all are networked. At the back of the room sit the market transaction and scheduling coordinators, who handle the generating capacity market [see Fig. 1]. Their job is to evaluate bids for power generation as they come in, and schedule the appropriate resources--generation and transmission.

At the front left corner of the room (in front of the market coordinator's workstation) is the generation coordinator, who is responsible for balancing demand and generation, dispatching additional units as demand spikes. This coordinator faces both the transmission map and a bank of monitors on the left wall that display data from generating units at a glance.

To the right of the generation coordinator's workstation is the transmission grid coordinator, whose job is to handle real-time operation of the grid, ensuring that lines are never overloaded anywhere. This workstation sits directly in front of the huge transmission network map, showing substations and power plants, digital voltage readouts, and flashing alarms to indicate the location of any problem. Proximity to the map lets the grid operator keep an eye on it, as well as on the data on the computer displays at the transmission workstation.

At a fifth workstation in the right rear corner of the room is the shift supervisor who is charged with assisting any coordinator at any of the other workstations when needed.

As might be expected, all this coordination requires state-of-the-art computer systems, especially in the software used to run them. Even the energy management system, an off-the-shelf system, is highly customized for PJM's needs, noted Bob Reed, manager of the company's operations planning group. Tracking the information used by the coordinators to make decisions and by the billing department to charge for services rendered requires highly sophisticated software, much of which is proprietary. Crucial details that are tracked include what the price is to move energy across any given transmission lines, who has transmission rights during times of constraint (a constrained line is one very near or just over its electricity-carrying capacity), how much power is financially hedged, what generation is available at what cost, who is moving power through PJM to a neighboring control area, and who is importing power to PJM territory.

Key to the requisite software are complex algorithms that have been developed over many years to analyze supply and demand scenarios. Every 2 seconds, for instance, dispatch signals are calculated and sent to local control centers. And every 2 minutes, 800 thermal and voltage contingencies (spikes, sags, and other sudden-event possibilities) are assessed, resulting in a contingency analysis report of all PJM monitored facilities. The volumes of data involved are massive: 5300 telemetered values from around the region are read every 2 seconds; another 6000 values for generating units are available every 14 seconds; and 18 000 available transmission capacity values must be updated daily.

The software and other intellectual property embodied in these algorithms was developed by PJM power pool members before PJM became an independent entity. Now in the process of purchasing the software from those members, PJM has an eye toward possibly marketing it to other grid operators in the future.

Pricing for the market

As an independent system operator (ISO), PJM coordinates multiple markets, including those for long- and short-term generating capacity and energy (transmission), an auction for transmission rights, and a regulation market. This last governs ancillary services provided by units that can be started or stopped by PJM nearly instantaneously in response to grid stability issues.

The capacity markets enable PJM to add or to recall capacity by requesting that certain generating units start up or shut down to maintain grid reliability--the outage-free grid operation maintained by the smooth, synchronous running of the generators supplying it with current. If the current furnished by a generator exceeds the limit of its protective relay setting, the unit will disconnect from the grid, affecting the current supply of the still-connected generators. If the situation persists, more generators will disconnect from the grid until a blackout or unstable condition occurs.

"Reliability is the single biggest issue [PJM] handles" as a regional grid operator, Richard A. Drom, PJM vice president and general counsel, emphasized to IEEE Spectrum.

Generally, the grid and generation coordinators look at what generators must run to ensure a stable grid, which provide the cheapest power, and where power enters and leaves the grid. Pricing is fairly straightforward. A power purchaser--a utility, say--contracts to take X kilowatt-hours on a specific day and time at a cost of so much each. The marginal power price is the cost of the X+1 kilowatt-hour, whether that is the same cost for, or higher than, the Xth kilowatt-hour. During an emergency, any generator could suddenly become a must-run unit to ensure grid stability, however high the price set for its generated power. PJM dynamically determines must-run units in such a situation. Bids for power produced by these units are capped to certain levels to avoid price-gouging by generators.

Within PJM's transmission or energy market, three options are available. Utilities can self-schedule their own resources to meet local needs, transfer power among themselves (bilateral transactions), or buy and sell power (and thus its transfer, too) on the spot market. Self-scheduling merely means meeting local demand, though power must flow through PJM-controlled lines on its way from utility plants to utility customers. Bilateral transfers are power transfers between two utilities, at least one of which is within the PJM control area.

The spot market is the real-time, bid-based energy market where power can be bought and sold on an hourly basis by PJM's 170 members. Bids and offers for energy are accepted on a daily basis. A day-ahead market--buying power on the day previous to the day the power is received--is scheduled to begin operating in June 2000 (market trials were under way at press time).

Customers outside the PJM control area must schedule their expected use of the spot market. All generation nominated as installed capacity is required to bid into the market and may be scheduled as must-run units by PJM to fend off instability. Units not nominated for installed capacity may bid voluntarily on a day-to-day basis. All bids are final as to price by noon of the day preceding the date of use.

While transmission pricing is fixed by tariffs filed by PJM with FERC, the overall cost of moving a block of power from point to point may not be fixed. When demand is high, power lines become congested or constrained (operating at or above capacity), and costs for their use are higher. (Capacity can be affected by humidity and temperature, and a line that exceeds its capacity could drop out of service, causing problems throughout the grid.)

To allow for these problems, PJM has a related market power mitigation procedure. When transmission constraints occur, PJM may price-cap generating resources needed to relieve congestion. This procedure, was approved by FERC, effective 1 April 1999, within PJM's control area, explained Lesley Collons, a PJM engineer in the customer relations and training department.

In dealing with congestion, PJM employs locational marginal pricing (LMP). Also known as nodal pricing, LMP is the cost of supplying the next 1000 kW of load at a specific location, figuring in generation marginal cost and the cost of transmission congestion. As a result, this pricing is one value for all locations when the transmission system is unconstrained, and varies by location when the system is constrained.

LMP, Collons said, "bases prices on how energy actually flows, not a contract path." The latter is literally a flow path for transmission specified in a contract and generally does not reflect the physical flow of electricity from point to point. When system constraints occur, PJM controllers can curtail transmission by starting and stopping specific units, so as to reconfigure the system and alleviate the problem.

If PJM must redispatch generation, the delivery limitations of certain transmission lines may rule out use of the least expensive generator available. In that instance, PJM may call on a high-cost generator nearer to the load instead of the lower-cost generator. When it bills a member for the service rendered in this case, the higher-cost generation is listed as the "security constrained redispatch cost," Collons told Spectrum.

As a hedge of sorts against locational marginal pricing, PJM uses fixed transmission rights so that market participants may manage congestion risk. These rights are a financial contract that entitles their holder to a revenue stream, based on hourly energy price differences across the transmission path. Although the rights can be traded separately from transmission service, they permit their holder to have some price certainty during anticipated times of system constraint.

Reliability key to stability

Lying entirely within the Eastern Interconnection, one of four synchronous ac systems in North America, is PJM. In each system, all the generators operate in phase with one another. PJM monitors tie lines across four interfaces connecting it to its neighbors: the New York ISO, Allegheny Power, FirstEnergy, and Virginia Power. A problem with any tie line can create a problem for PJM. Should voltage sag, for example, PJM control-room coordinators would contact local control centers operated by the utilities within its control area, notifying them of the problem and implementing emergency procedures as necessary.

The entire North American grid operates at a nominal 60 Hz on four big circuits (one per interconnection) linked by high-voltage dc tie lines. As part of this grid, PJM also must maintain 60 Hz. If a load suddenly draws more current, then a drop in voltage and frequency will occur across the grid, affecting the speed (frequency) of the generators supplying current to the load.

If the generators no longer operate synchronously, the one least affected by the sudden change will attempt to supply additional current, establishing a give-and-take relationship between generators as they speed up and slow down in an attempt to reestablish synchronicity. If the problem with the line is eliminated in time, the generators will regain synchronous operation. If not, the give-and-take will escalate beyond protective limits until a generator disconnects from the grid, causing an outage. This failure could cascade, disconnecting several generators from the grid.

The power outages in the scalding 1999 summer were largely local in scope. They did not wipe out an entire interconnection or even an entire region [see "Restructuring the thin-stretched grid"]. While the PJM transmission grid did not undergo an outage, some utilities in the PJM control area did have distribution-level outages. What PJM encountered were steep voltage declines on the transmission system during load conditions that set a new record peak. In response, operators instituted emergency procedures on two separate days.

On the first day, voltages remained low for several hours. On the second day of voltage sags, voltages were restored rapidly, thanks to the emergency procedures set up. Generators were redispatched, some transmission was curtailed, and capacitor banks were activated. These last are designed to provide voltage support to the grid in the event such an emergency arises. Grid reliability was maintained, but the incidents served as a wake-up call to PJM and its members, who took a fresh look at processes, procedures, and tools available to remedy the situation.

The system conditions of July 1999 were unprecedented but afforded PJM a "learning opportunity," to quote the company's root cause analysis report. According to the report: "Reactive demand was exceedingly high because of record electricity consumption resulting from high temperatures, high humidity, a strong economy, and from increased transmission system losses created by high transfer levels across the system. Reactive supply was insufficient to meet the demand because some generators were unavailable or unable to meet their rated reactive capacity because of ambient conditions and some capacitors were not in service."

In short, the low voltage on the two days was due to reactive demand exceeding reactive supply. (In an ac circuit, the current generally leads or lags the voltage. The current consists of an active component in phase with the voltage and an out-of-phase or reactive component.)

Economics vs. reliability

Today, not only is PJM in charge of reliability and grid security and stability for its area of operation, but it is also the security coordinator for that area under the North American Electric Reliability Council (NERC), Princeton, N.J. Security coordinators ensure outage-free grid operation across a NERC region. Each of the 10 regions has at least one security coordinator, but can have any number of control areas. For example, the Florida Reliability Coordinating Council has 14 control areas though only one security coordinator. Coincidentally the territory covered by the Mid-Atlantic Area Council (MAAC), is virtually the same as PJM's control area. PJM relishes its dual role and the authority given it as security coordinator, but its pride in the role has sparked some disagreement with NERC over pending legislation designed to give NERC enforceable oversight.

The legislation would transform NERC from its present voluntary state into a quasi-regulatory body. In its new form, to be called the North American Electric Reliability Organization (Naero), the entity would acquire some authority to enforce its reliability standards.

Currently four bills relating to NERC's transformation are in various stages of debate in the U.S. House of Representatives and the Senate. Senate bill 2098, sponsored by Senator Frank Murkowski (Rep.-Alaska), is the furthest along in the legislative process: hearings were held in April by the Senate Committee on Energy and Natural Resources, chaired by Murkowski.

PJM's Drom questions what improvements to reliability would result from the legislation. "Operators [like PJM] have extensive emergency powers to respond to situations. Operational problems usually have to be addressed in seconds in order to keep the grid lit," he said. Under the legislation as now written, system operators would be forced to comply with Naero rules and variances. "Situations could arise where a system operator would need a variance in order to balance the grid," he said, "but instead of being able to respond to the situation immediately, an operator would have to contact Naero for a variance, explain it, get approval, and then implement the solution. In an emergency situation, that can take more time than is available to prevent a cascading failure."

NERC staff bristle at this characterization of the legislation's provisions. Dave Nevius, NERC vice president, told Spectrum that "PJM seems to be alone in objecting to the NERC consensus legislative language on reliability that appears in every major restructuring bill in Congress. Simply stated, all systems operators, including ISOs and RTOs, would be expected to follow a common set of grid operating reliability rules to ensure that the actions of one do not adversely affect another." As he explained, "The variances would be predetermined and preapproved by both FERC and Naero. Once approved, they become the rules by which the system is operated."

Drom's concern is that legislation may put economics ahead of reliability. If the regulations Congress is considering are written to favor economics (low-cost generators must be dispatched over higher cost ones) rather than reliability (dispatch those generators required to maintain grid stability, regardless of the cost of generation), reliability will suffer. Stressed Drom, "Reliability must take precedence in the legislation just as it does in the dispatch center." In a conversation with Spectrum, Nevius retorted: "That is exactly what the legislation does."

Next in PJM's future

Once approved as an RTO by FERC, PJM's next step is to look beyond its own territory. Right now, Van Billet, PJM's chief financial officer, told Spectrum, "despite the fact that PJM and its members depend on real-time information 24/7, it isn't practical to trade that sort of data across regions." The methodologies of the neighboring ISOs and utilities are not consistent across boundaries. "We all use different computer systems, present information differently--it can be confusing for customers [ISO users] to go back and forth," Billet acknowledged. "My vision is a consistent 'virtual ISO' across regions whose boundaries are invisible" to users but an entity that would have several RTOs and ISOs behind it. "That's the efficiency of the virtual marketplace. The sky's the limit on customer-oriented innovation," he said.

Drom concurs, but sees such a vision unfolding over time in carefully thought-out steps. "Once PJM receives RTO approval, then the next step is greater interregional coordination," he stated. He would like to see PJM build on the memorandum of understanding it has with ISOs to the north: New York, New England, and Ontario's Independent Market Operator. "There are opportunities for greater coordination with neighbors to the south and west," he said.