Defining important, frequently misunderstood energy terms: Part 2

On an MBR, do HDDs signal the chance for DR, and will my REC purchase affect my UCAP requirement? You’re probably asking yourself, “What are you talking about?” In today’s article, we continue a previous discussion and present our second lesson in learning EIL (Electric Industry Language) by defining a few more terms that are commonly used, but sometimes misunderstood.

HDD/CDD = Heating Degree Day/Cooling Degree Day
HDD is a measurement designed to reflect the demand for energy needed to heat a building or facility. The heating requirements for a given structure at a specific location are considered to be directly proportional to the number of HDDs at that location. A similar measurement, CDD, reflects the amount of energy used to cool a building.

HDDs are defined relative to a base temperature, which is the outside temperature above which a building needs no heating. HDDs can be calculated in several different ways, depending on the accuracy desired, but one of the simplest and most common uses 65° F as a base temperature, and is calculated as follows:

Take the average temperature on any given day, and subtract it from the base temperature. If the value is less than or equal to zero, that day has zero HDDs. But if the value is positive, that number represents the number of HDDs on that day. Other calculation methods improve accuracy by taking into account such things as the type of building and how well it’s insulated, any heat-generating occupants or equipment, the time of day when heating is required, or the cumulative effect of residual heat.

Why does this matter? Because HDDs are typical indicators of energy consumption for space heating, they can be used to monitor the heating costs for climate-controlled buildings, to forecast heating demand, or for estimating future heating demand costs.

MBR = Market Based Rate
MBR has different meanings, depending on context. In one instance, MBRs are rates for power or electric service that are established in an unregulated, competitive market. These rates can be established through competitive bidding or through negotiations between the buyer and seller, rather than set by a regulator. The Federal Energy Regulatory Commission grants market-based rate authorization for wholesale sales of electric energy, capacity, and ancillary services by sellers that can demonstrate that they and their affiliates lack or have adequately mitigated market power.

MBR may also refer to a customer default rate used in lieu of a fixed contract rate. In this instance, the cost of energy fluctuates with current market prices. A customer would pay their energy provider a varying rate based on market conditions at any given point in time. This is usually considered risk-prone because future prices are unknown.

Why does this matter? As portions of the electric industry become less regulated, market prices are increasingly important for making business decisions. With the first definition, MBRs may afford a customer to buy power below the local regulated utility’s price with the possibility of realizing substantial savings in their energy costs. With the second definition, MBRs create uncertainty and present considerable risk, as projecting future energy costs becomes near impossible, given the unpredictability of energy market prices.

DR (EDRP/DADRP) = Demand Response (Emergency Demand Response Program/Day-Ahead Demand Response Program)
DR (also known as load response) is the action taken by end-use customers in reducing their electricity consumption in response to power grid needs, economic signals from a competitive wholesale market, or special retail rates. A customer enrolled in a DR program receives incentive payments to lower their electric use at times of high wholesale market prices or when system reliability is jeopardized. Demand response can involve actually curtailing power being used, or by starting on-site generation, which displaces some or all of the electricity being supplied by an energy provider.

Under conditions of tight electricity supply, DR can significantly decrease the peak price and, in general, electricity price volatility. DR programs are designed to be, both, fiscally and environmentally responsible ways to respond to occasional and temporary peak demand periods. The programs offer incentives to businesses that volunteer and participate by temporarily reducing their electricity use when demand could outpace supply.

Why does this matter? Price-based DR gives customers time-varying rates that reflect the cost of electricity in different time periods. Armed with this information, customers tend to use less electricity at times when electricity prices are high.  Incentive-based DR programs pay participating customers to reduce their loads at times requested by the program sponsor, triggered by either a grid reliability problem or high electric prices. Both types of DR provide a customer with a method to reduce their energy costs.

ICAP/UCAP = Installed Capacity/Unforced Capacity
Installed Capacity (ICAP) refers to the maximum amount of electricity a generator is designed to produce, or what is sometimes referred to as the boilerplate (or nameplate) rating, and is usually expressed in megawatts (MW). However, despite this rating, power plants are usually not able to produce this maximum output 100% of the time. Unforced Capacity (UCAP) refers to the average amount of electricity that is actually available at any given time after discounting the time that the facility is unavailable due to outages or deratings. For example, if a generating facility has an ICAP rating of 100 MWs, but ambient conditions only allow the generator to produce 90 MW, the UCAP rating would be 90 MW. Likewise, if the same generator with an ICAP rating of 100 MW can actually produce 100 MW of electrical output, but is shut down 10% of the time due to repairs, its UCAP rating would also be 90 MWs. Power plants that generate an amount of electricity close to their ICAP rating are said to have a high capacity factor.

Regional regulatory authorities determine how much total capacity is needed for system reliability purposes. The total amount of capacity required is allotted among customers based on their individual peak demands, which gives each individual customer a specific capacity requirement.

Why does this matter? The cost of capacity is ultimately born by the customer, and becomes a component of their electric rate. A customer’s capacity requirement is based on their PLC (see previous blog), so by managing their energy use during periods of peak demand, a customer can, to some degree, control their capacity cost, and, in turn, their overall rate.

REC/SREC = Renewable Energy Credit/Solar Renewable Energy Credit
A Renewable Energy Credit (REC) is a non-tangible energy commodity that represents proof that one megawatt-hour (MWh) of electricity was generated from an eligible renewable energy source. A REC is sometimes referred to as a Green Tag or a Renewable Energy Certificate. Solar Renewable Energy Credits (SRECs) are RECs that are specifically generated by solar energy. A renewable, or “green”, energy source, such as a wind farm, is credited with one REC for every one MWh of electricity it produces. RECs represent the environmental attributes of the power produced from a green energy source and are sold separately from the electricity commodity. The actual electricity is fed into the electrical grid, and the accompanying REC can then be sold or traded on the open market. The owner of the REC can claim to have purchased green power.

Why does this matter? More and more states are passing legislation requiring that a certain amount of the electricity produced be from renewable sources, such as solar, wind, hydro (water), or biomass. RECs are used to keep track of the amount of renewable energy being produced, and to track who is using or buying it.

Posted: May 08, 2014

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