The Economics of Photovoltaics
by Monica A. Mallini, P.E., Chair, Industry Applications Society
The IEEE members who attended a tour of the BP Solar plant in Frederick, Maryland learned about the state of the solar energy industry, including current and future photovoltaic (PV) technology, from BP Solar hosts Bill Poulin and Jean Posbic. An article in the May-June Scanner presented an overview of the subject and delved into Mr. Posbic’s solar PV primer. This article focuses on solar PV economics.
Why solar PV? The benefits include peak load reduction, which offsets the need for utilities to run expensive gas-fired peaking units. Reduced grid congestion is particularly important in large metropolitan areas, like Washington and Northern Virginia, where locating additional transmission and distribution resources is both expensive and either very difficult or impossible. Other benefits to owners and society include reduced energy price volatility, enhanced security and reliability (especially on the consumer side), increased protection of critical infrastructure, and improved air quality. The limiting factor of the technology is its high initial cost, as compared to conventional energy sources.
Photovoltaic systems can be designed for a variety of applications, and a well-designed system has a long service life with relatively low maintenance requirements. As a general rule, each kilowatt of peak installed capacity requires a surface area of 8 to 12 square meters, a considerable amount of rooftop real estate. A 3 kW roof array can easily cost $24,000 and it generates about 4.5 MWh per year, a third of the annual electricity consumption of a typical single family household. When this cost is amortized over 15 years (at 5 percent interest), the PV energy produced averages 30 cents per kWh over a 25-year life.
A solar PV module, consisting of a sealed package of individual quality-matched solar cells electrically configured to reach desired voltage and current, can achieve practical efficiency up to about 15 percent, with a theoretical maximum of 30 percent. Efficiency dictates performance of the system and helps determine whether the investment is attractive. An efficiency improvement from 15 percent to 16 percent, due to advances in the technology, will reduce the average lifetime cost of energy for our hypothetical system from 30 cents to 28 cents per kWh. These modules are the building blocks of a complete PV power system, which may also include a DC-AC inverter, batteries, system controllers, power conditioning equipment, and balance of system wiring and hardware.
The exact configuration depends on the specific requirements of an installation. The simplest configuration, a direct-coupled system, supplies a load that operates only during sunlight hours, such as circulation pumps for a solar thermal heating system. In this case, there is no need for energy storage or DC-AC inversion, and system design is focused on impedance matching. A grid-independent standalone system depends on a properly sized battery bank as a critical component and must manage system loads carefully. A PV system that sells power back to the utility may omit batteries and use the interconnected power grid to replace energy storage and supply backup power needs.
Many states encourage or require utilities to implement “net metering,” the single-meter tracking of electricity sales between a customer and the utility. The meter can spin in either direction, and the customer is billed only for net electricity consumed. This is advantageous to the customer because it guarantees that excess energy can be sold to the utility for the full retail price.
Some states and countries are willing to encourage PV adoption with incentives. California, New Jersey and New York are leaders in incentive programs in the United States. New Jersey offers a rebate of $5.30 per watt of installed capacity. With this incentive, the same hypothetical 3 kW system will produce energy for the owner at a cost of only 10 cents per kWh. Japan, with 1 GW of grid connected solar PV, has provided an incentive for rooftop PV installations for several years with a 20 percent rebate. Germany takes a different approach. An earlier program of interest-free loans has been sweetened with more substantial payments for energy produced. German PV owners may sell all the PV energy produced for 20 years for 60 cents (and up) per kWh. German installations use two kilowatt-hour meters, one to record the owner’s electricity consumption, and a separate meter to track PV energy sold back to the grid. As a result of its incentive program, Germany has catapulted to first place in worldwide installed PV capacity. A 60-cent purchase incentive will roughly pay for the amortized cost of the 3 kW example system and the energy to replace what is sold back to the grid for 15 years, resulting in a zero net cost of the system and the energy it produces. After the 15-year loan is paid off, the owner will make a profit of more than $2,000 per year until the incentive ends.
A second type of phenomenon also contributes to PV adoption. Half of the states have adopted renewable portfolio standards (RPS), flexible, market-driven policies designed to encourage the use of renewable energy. Typically, electricity retailers are required to demonstrate that they have provided or sponsored an amount of renewable energy generation equivalent to some percentage of their sales. California’s aggressive RPS mandates 20 percent renewable energy by 2017. Compliance is proven through the ownership of renewable energy credits, tradable certificates of proof that are a separate commodity from the energy itself. An electricity retailer or generator may invest in renewable energy projects, and these projects will generate credits that can satisfy that generator’s compliance or be traded on the renewable energy credits market. Alternatively, the retailer may choose to purchase some or all of the necessary credits from projects that it does not own. Individual PV owners may sell their credits individually or enroll as members of a PV registry, aggregating their credits with other PV owners. The going rate for PV credits is dictated by the market, but a typical price may be around $100 per MWh, a nice bonus for residential PV owners. If the PV market eventually becomes saturated, the market price of credits will naturally fall toward zero, and RPS programs will have satisfied their objectives.
Green pricing programs have also driven increased demand for PV energy. When given a choice to pay a premium price for electricity that includes a stated percentage of renewable energy in the mix of resources, many residential and corporate customers will opt to use “green energy” as a marketing strategy, or simply because it’s the right thing to do. It has been demonstrated that enough people are willing to pay premium prices for green energy to make it profitable for power companies to buy kilowatt-hours from rooftop and commercial PV owners for attractive prices.
With efficiency improvements at the module level, ramp-up of polycrystalline silicon production capacity, planned development-scale PV system installations, and growth of state incentive programs, PV will make sense for more homeowners and businesses. When “grid parity” is eventually achieved, forecast growth in the U.S. solar industry is estimated to exceed $6 billion per year.
According to Mr. Posbic, one of the most commonly asked questions about photovoltaic technology is why it makes sense to lose money by paying more for PV energy than the retail cost of electricity. To answer, he offered three observations. First, the 10 cents per kWh that we see on our electric bills is not an accurate reflection of the cost of energy. Next, all energy costs are not equal. PV is not in competition with base loaded units; PV displaces gas fired peaking units, which are expensive to build and expensive to operate. Finally, the utility stands to save money by avoiding the capital cost of expansion when it can purchase electricity from the consumer, even above retail electricity rates.
The BP Solar tour was sponsored by the Washington and Northern Virginia chapter of the Nuclear and Plasma Sciences Society.
Read Part 1 of this story.
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Updated 6/30/06
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