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Electric rates, once relatively stable, have in many areas become more volatile than stocks on Wall Street. Deregulation at the wholesale and retail levels, and increased exposure to fluctuating natural gas pricing, are producing monthly electric rates that differ widely depending on the time of use and a facility’s location.
Due to the rising cost of power, even Uncle Sam is pushing fluctuating rates, mainly through the federal Energy Policy Act of 2005 (EPAct). For facility executives, the changing rate structures can have a significant impact on the cost effectiveness of some energy upgrades. If energy savings estimated for a lighting upgrade, for example, use average utility costs instead of factoring in peak demand charges, project savings almost surely won’t match expectations. The bottom line: facility executives considering energy efficiency upgrades should understand their rate structure to ensure that projects deliver the expected return on investment.
For the decades when electric rates were regulated by state Public Utility Commissions (PUC), the general standard for ratemaking was “cost plus,” meaning that utilities would determine their total cost to generate, transmit, and distribute power and then add a regulated profit margin. The end result was the total cost to be charged to all customers. Industrial, commercial, and residential customers vary in how they use and take power from the utility, so rates reflected the differing costs each type of customer imposes on the system.
Commercial and industrial customers are often charged based on both how much electricity (kilowatt-hours, or kWh) they consume, and the fastest rate they use it (kilowatts, or kW) during a billing period, called peak demand. By separately adjusting rates for consumption and demand, a utility may better allocate its fixed and variable costs. Residential customers typically pay flat rates per kWh. Most states also allow an additional fuel adjustment charge so utilities can pass their varying costs for fuel to run generators directly through to ratepayers.
A mix of energy sources is used to generate electricity, the costs of which may vary greatly during the year and even at different times of the day. The cost to build power plants varies, with the cost per kW of some units being several times that of others. Coal, for example, is much cheaper than natural gas. Adding even more complexity, wholesale prices may vary seasonally and even daily. Heat rates — the efficiency with which power is created — differ among fossil-fueled generators, making some much more expensive to run than others. All those generators feed into power grids where the choice among fuel sources at any given time is a function of unit price and maintaining reliability. When a power line goes down or becomes fully loaded, for example, more expensive units may need to be brought online based solely on their grid location.
The advent of wholesale power markets resembling stock market trading floors has opened the door to greater price volatility.
Up to about 1992, most utilities satisfied their loads with their own generation, or else informally swapped power with nearby utilities to avoid building new generation that would be needed only a few hours a year. Thereafter, federal law allowed non-utility power suppliers to sell wholesale power generated in private plants to utilities and to brokers that would “trade” it like stock. The pricing of wholesale power now floats with supply and demand, just like the pricing of other commodities. When the supply-demand margin is wide, competition among such parties drives wholesale pricing down, benefiting utilities and their customers. When that margin narrows, prices rise to “whatever the market will bear” up to very high regulated caps, such as $1.00 per kWh.
Fast forward 15 years, and retail deregulation lets wholesale pricing variations filter down to end users. Many utilities are now “wire and pipe” companies with little generation, focusing instead on transmitting and delivering power. Such utilities simply pass along the wholesale costs they incur, just as they did previously with fuel costs. Electric rates are gradually moving toward a two-component system: regulated power delivery cost plus wholesale power cost.
To see how much wholesale generation pricing may vary, see the chart on page 63, “Wholesale Power Pricing: Peaks and Valleys,” which shows the hourly wholesale price being charged in New York City every hour during 2003. While the price stays in the green range more than 90 percent of the time, it occasionally jumps sharply to reflect high demands on the system, typically caused by very hot days or the loss of a generator or transmission line that forces use of a more expensive power resource.
Besides time-based variations, geographic variations further differentiate pricing. In most grids where deregulation has occurred, zones have been created based on local transmission capabilities. Some older cities, for example, lack sufficient transmission to always bring in the cheapest power. Customers may then see higher prices based on the mini-market of local generation that must be used when power lines are congested.
Such areas are sometimes called “load pockets” and may see even higher peak pricing than adjacent zones having better transmission or lower cost local generation. Among those locations are Boston, New York City, Chicago, and San Diego. To varying degrees, new transmission lines may ameliorate this problem, but such improvements to the grid don’t happen overnight.
For facility executives, the complexity of new rate structures can cause real headaches when it comes to planning energy-efficiency projects. Such rates may alter the cost-effectiveness of energy upgrades, improving some while diminishing others. The problem is that many energy service firms, consultants, product vendors, and building professionals still use average kWh per dollar rates to calculate costs and savings. Under time-sensitive rates, however, that method may not properly reflect the true price of power.
Some efficiency upgrades, such as T8 lamps and electronic ballasts, save power whenever lights are on, which is generally most days of the year, while others, such as occupancy sensors, may cut power use mainly when rooms are empty for extended periods, usually at nights and on the weekends. When calculating the true dollar savings of such options, a good analysis takes into account the true cost of power when savings will take place.
Where electric rates charge separately for consumption and peak demand, it is important to determine whether savings will take place at the time peak demand occurs, typically early afternoon, though this may vary based on facility use and operation. If savings don’t occur during peak demand, only consumption savings may be realized. Where peak demand charges are a significant portion of the total bill — in some areas it can amount to 30 percent — using an average power price that includes peak demand charges will underestimate savings from options that cut peak demand, and overestimate savings from those that don’t.
In the case of occupancy sensors, some may shut off lights in conference rooms when unoccupied during the peak demand period but have no impact on areas that are occupied during the peak elsewhere in the building, such as open offices and corridors. Assuming that each sensor will yield peak demand savings is likely unjustified.
The same may be true for variable speed drives running motors that are sized properly for peak flow needs (e.g., fans and pumps). During peak time, they will need to run those motors at full speed, so no peak demand savings will appear. Significant consumption savings will occur at most other times, however, and the value of such savings at those times must be known to properly determine the real dollar savings.
On the other hand, running an on-site generator, or an automated demand response system that dims non-essential lighting or slows motor speed, could reduce load seen at the meter, significantly cutting cost during known high-priced periods.
Where simple time-of-use rates prevail, the time-block nature of pricing may create greater error regarding when savings occur. (See “Time to Look at Your Time-of-Use” on page 64 for a definition of various pricing structures.) If an off-peak block runs from 6 p.m. to 8 a.m., for example, it makes no difference if the savings occurred between 6 p.m. and 10 p.m. or midnight to 4 a.m. The dollar savings will be the same. If, however, a customer is being billed under a real-time pricing (RTP) rate that takes into account actual usage during each hour, the 6 p.m. to 10 p.m. time period may still contain an hour or two at a higher price than would be seen between midnight and 4 a.m.
Under real-time pricing, there is no demand charge. Instead, it is built into the hourly price, which, as seen in the chart on page 63, may vary considerably and inconsistently. Upgrades that cut peak monthly demand may therefore not consistently cut cost in proportion to demand reductions under RTP. Measures that cut only consumption may, at certain times, save a great deal and other times save very little since the unit cost of consumption may at times vary widely.
Where critical peak pricing (CPP) is in effect, the ability to quickly respond to wide price swings may net savings, but an automated response process may yield the most consistent results. Trying to find ways to cut loads on the fly, such as by shutting off too many elevators at one time, is unlikely to provide good results and could instead make spaces uncomfortable or create inconvenience for occupants and unforeseen headaches for facility executives.
First, find out if and how rates could be changing in your area. Your utility account rep or energy consultant should be able to outline the status of relevant changes to you, especially how your rates may begin to reflect wholesale power pricing.
If your electricity accounts could be affected by such changes, a better understanding of how your loads vary with time may be in order. Talk to the same people, and those who operate your building’s energy management system, about what it would take for you to see hourly load profiles at various times of the year. Doing so may involve upgrading electric meters and finding ways to communicate with them in near real time.
To get a handle on how wholesale prices are varying in your area, ask your utility rep or energy consultant to show you where such pricing may be found on the Internet. Some utilities provide their larger customers with access to such pricing, and most Web sites for the Independent System Operators (ISOs) that run wholesale grids also offer it. For example, the chart on page 63 is based on information provided by the New York ISO for its Zone J, which is New York City.
When contracting for basic energy upgrades, use lighting/occupancy loggers to determine when rooms are actually occupied and lights are on, instead of winging it with general assumptions. Similar arrangements may be made to determine when fan and motor speeds may be adjusted with variable speed drives.
When considering more advanced upgrade options such as thermal storage, demand response systems or distributed generation, request that a computer model be used instead of simple assumptions to estimate when and how much load may be shifted or eliminated. Have it examined by an independent consultant to ensure that the numbers have not been cooked in a way that may overstate savings.
When it comes to calculating savings, realize that this new world of energy costing involves more probabilities and ranges in pricing, and not the regulated rates of the past. A more conservative approach toward savings may be necessary, along with some education of the bean counters, to ensure that final results live up to expectations.
Lindsay Audin is president of EnergyWiz, an energy consulting firm based in Croton, N.Y. He is a contributing editor for Building Operating Management.