Electricity generation must “follow” the load (or demand): as load increases or decreases across the grid, generation for that grid must be increased or decreased to match load (and provide reserve energy) at any given time. Power plant units can be characterized by how they are used to meet this ever-changing demand.
A “baseload” generating unit is run fairly steadily throughout a day and throughout the year. They are dispatchable, which means that they can be controlled to run at specified levels over specified time periods. Together, baseload units can provide a significant portion of overall generating resources on a grid at a given time. They are often steam generators that cannot ramp up or down quickly and that operate most efficiently when run near capacity. Coal, nuclear, geothermal, natural gas, and hydro are all potential baseload resources.
“Cycling” or load following units are dispatchable but are ramped up or down throughout a day to meet changing demand. Hydropower and combined cycle gas plants are commonly utilized as load following resources. “Peaking” units are a type of load following unit that are utilized primarily to meet peak demand on a given day. Although they are less efficient than thermal plants, gas combustion turbines can be started or stopped relatively quickly, can be ramped between load levels quickly, and can operate at a wider range of power outputs than thermal plants. Combustion turbines are therefore most often used as peaking units. To some degree, solar can be used as peaking units in summer when the peak is due to increased demand for air conditioning on sunny days.
Price is a foremost consideration for power providers both when running power plants and when considering what new power plants to build in the future. One simplified way of comparing the costs of different fuel sources is to use a concept called the ‘levelized cost of energy’ (LCOE). LCOE accounts for both the capital expenses to build a new plant and provide transmission as well as the lifetime operating expenses of a new plant. The table below shows the U.S. Energy Information Administration estimate of LCOE in 2020 (not including financial subsidies) as well as select characteristics of different power plants not captured by that concept.
It is important to note that the LCOE of a new power plant must be weighed against both the LCOE of other new plants as well as the cost to operate existing plants. It is also important to note that different technologies affect land and water use in ways that depend on many different variables.
There are three different types of electric utilities in Colorado: investor-owned utilities, municipal utilities, and rural electric associations. Investor-owned utilities are for-profit monopolies that are governed by shareholders and regulated by the Colorado Public Utilities Commission. Xcel and Black Hills Energy are the two IOU electric utilities in the state. These utilities both generate their own power and purchase power from other providers.
Municipal electric utilities are governed by a municipality’s elected officials or appointed utility boards. There are 29 municipal electric utilities in the state, with Colorado Springs Utilities as the largest and the Fleming Electric Light Department as the smallest. Most of these utilities purchase power from public providers such as the Municipal Energy Agency of Nebraska (MEAN), the Arkansas River Power Authority (ARPA), and the Platte River Power Authority (PRPA).
Rural electric associations are governed by their owner-members. There are 26 REAs in Colorado. Most of these utilities purchase power from the Tri-State Generation & Transmission Association or Xcel Energy. According to the Colorado Rural Electric Association, REAs serve an average of 7.9 members per mile, municipal electric utilities serve an average of 48 customers per mile, and Xcel Energy serves an average of 34 customers per mile.
Electric utilities distribute power to customers or members. Power providers generate electricity that they sell to electric utilities. In some cases, “vertically integrated” companies like Xcel Energy both generate and distribute power.
Among power providers, wholesale power providers such as Tri-State Generation & Transmission either generate or purchase power on behalf of their members. Independent power producers sell their power on the market and commonly generate renewable electricity for purchase by electric utilities.
Investor-owned utilities and wholesale power providers typically own and operate transmission lines and infrastructure. Transmission lines carry power to substations, at which point electric utilities own and operate the distribution lines and infrastructure needed to bring power directly to individuals.
Colorado Renewable Energy Policy
In Colorado, different electric utilities are required to generate certain amounts of their electricity from renewable sources by certain dates. Investor-owned utilities such as Xcel are required to generate 30% of their electricity from renewables by 2020. Electric cooperatives serving 100,000 or more meters (Tri-State Generation & Transmission and Intermountain Rural Electric Association) are required to generate 20% of their electricity from renewables by 2020. Electric cooperatives serving less than 100,000 meters and municipal utilities serving more than 40,000 customers are both required to generate 10% of their electricity from renewables by 2020. Renewable technologies include but are not limited to geothermal, solar thermal, solar PV, wind, biomass, hydroelectric, landfill gas, and anaerobic digestion.
In addition, certain portions of electricity sold by electric utilities must come from “distributed generation” (DG). DG refers to smaller power plants, and certain portions of a utility’s DG must come from renewable resources located on the customer side of the meter such as rooftop solar.
Source: Database of State Incentives for Renewables & Efficiency (DSIRE)
Net metering refers to an electric customer’s ability to get credit for renewable electricity generated on his or her side of the meter at the retail rate of electricity. In other words, the meter “spins backwards” when more electricity is generated than used. Excess electricity generated in one billing cycle can be carried over to the following billing cycle. After 12 months, net metered customers in investor-owned utility service territories can choose to either carry over excess electricity into the following year or receive a credit at the utility’s avoided cost of energy. Net metered customers of municipal utilities and electric cooperatives are subject to individual utility policies for excess generation after 12 months.
Investor-owned utility electric customers can offset up to 120% of his or her average annual electricity use through net metering, while municipal utility and electric cooperative customers are subject to system size limitations.
Green Power Purchasing programs like Xcel’s WindSource program can be hard to understand. At a basic level, a utility customer can choose to pay a premium on one’s own energy consumption to support renewable energy. If the number of blocks ( i.e. 100 kilowatt-hours each) purchased through a green power program exceeds the amount of renewable energy the utility generates in a year, the utility will purchase more renewable energy on the market or by installing more renewables.
One key consideration is how much renewable energy a utility already has on its system. For utilities like Xcel that already have a lot of renewable energy, it is likely that green power premiums would be used exclusively to pay down loans on existing renewable energy farms (essentially as a subsidy). For utilities with little renewable energy, a significant influx of green power premiums is more likely to result in the purchase of new renewable energy on the market or by installing more wind or solar farms.