By Bhavesh S. Patel,
ASCO Power Solutions, Florham Park, NJ, USA
Figure 1. Two sides of the same coin: DG will have different costs and benefits for utilities and customers
Evaluating distributed generation (DG) as an economic option for utilities to meet load growth and relieve transmission constraints is a decision comprising many shades of grey. What makes economic sense for some will not be justifiable for others. An array of factors, ranging from a utility’s own situation to a host of market, technological, regulatory, competitive and other pressures will colour a given utility’s evaluation of distributed generation as a cost efficient option.
DG systems small electrical generating units that are located near the site of consumption on either the utility’s or customer’s side of the meter can be an economic and integral part of a utility’s overall strategy for satisfying demand while operating within a deregulated environment. DG installed on the utility side of the meter can enhance existing distribution systems. DG system configurations that blend capacity, technologies and fuel sources can be tailored to suit a variety of power demands in commercial, industrial, institutional and other applications.
DG installed on the customer side of the meter is another matter entirely and essentially removes some of the
utility’s control over how power demand is satisfied. Indeed, a case can be made that proactively installing DG may be an effective approach for a utility to control its own destiny and maintain the integrity of the system that it stewards.
In true economics parlance, utilities must weigh the opportunity costs of investing its available and finite resources (financial, human and hardware capital) in DG, compared to other solutions for managing supply and demand for its product.
A utility’s supply options may be considered three-fold: to build base load generation, import power, or supplement existing base load capacity with smaller power generation sources. On the other hand, demand management options without regard to political consequences could include curtailment and incentives to save energy.
For many utilities in the USA, building base load plants is not a realistic option in the short term given the long lead times, huge investment and siting and permitting challenges of these facilities, plus the uncertainty of the evolving competitive scenario in a deregulated environment. Importing power may be even less economically attractive.
Supplementing base load capacity with smaller generation units that can be located near end users can be a supply/demand solution for utilities. Commonwealth Edison in Chicago, Illinois, facilitates installation of these units near customer facilities. The utility pays for and installs the equipment on the utility side of the meter and end users maintain it. The utility activates the systems as needed to ensure that it can satisfy overall demand.
Jim Lefeld, Manager of Distributed Generation for Cinergy in Cincinnati, Ohio, USA, reported as part of a roundtable on distributed generation that “the prospects for DG in the next two to five years look good as an alternative energy source. With traditional natural gas reciprocating engines, microturbines and fuel cells, the products to fit different applications will be there.”
Curtailment, while an effective strategy to balance demand with supply, is not a palatable long-term solution to maintain a reliable power supply for public safety and commerce. Some curtailment strategies promoted by utilities for their side of the meter spark customers to look at DG systems for their side of the meter to compensate for the ‘lost’ power.
So what criteria help determine whether DG makes economic sense for a given utility? The utility’s structure for one: ‘know thyself’ is good advice and the utilities that have investigated DG know that their own structure and characteristics are powerful determinants in deciding how much economic sense DG makes for them. Regulation, legislation and the location of DG on the power grid also affect DG’s economic contribution to a utility.
Assessing DG as a cost-effective solution for a variety of utility situations produces interesting results. The following examples are based on a DG system generating electricity for $0.07-0.15/kWh. This range represents capital and operating costs for a large, natural gas-fired reciprocating engine, substation upgrades and new construction.
A utility in the enviable position of having no constraints (i.e., a comfortable margin in terms of generation, transmission and distribution capacity) will incur only marginal costs ($0.02-0.04/kWh) in using more available installed capacity to meet additional demand, so DG would be hard-pressed to prove itself an economic solution. A comfort margin, or lack of it, is perhaps the most powerful economic determinant in how a utility evaluates the economic benefits of DG.
If a utility has a shortfall in generation capacity only, DG also will find it difficult to compete with the $0.04-0.07 range per kWh cost of adding new generation. This assumes of course that a utility has the financial and political capability to successfully add new base load generation in today’s market scenario. If it does not, it may have to purchase high-priced power that then could make DG economic indeed.
If a utility lacks transmission and distribution capacity, it is a closer contest. A utility would have the option of installing new capacity for $0.07-0.18 per kWh or DG systems for $0.07-0.15/kWh.
Figure 2. Comparing costs of DG to other options for meeting new demand
Lacking a comfort margin in generation, transmission and distribution in one or more areas of its system, a utility faces the prospect of a large and probably politically encumbered base load capital investment with a per-kWh cost of $0.09-0.22, which represents capital and operating costs for a combined cycle gas turbine, capital construction and operating costs for new transmission and capital construction and operating costs for new distribution. The decision could be economically straightforward as Figure 2 shows.
All the per-kWh cost ranges are based on studies of industry data. These cost ranges notwithstanding, it can be difficult to assess the attractiveness of DG to regulated utilities, since true costs are determined by type of load, utility system characteristics, geography, where the DG would be located within the system and the regulatory climate. This last factor deserves special mention.
Cost-of-service regulation that guarantees a rate of return on utility investments favours higher capital cost options. Selecting DG would not optimize total dollar return, as would more expensive transmission/distribution additions, which represent greater profits in the long term.
Another approach, performance-based ratemaking, has been tried in the USA and elsewhere. This approach caps utility prices or revenues and so provides incentives to reduce costs to optimize profits. DG under this approach would likely become a favoured option in instances where it represents the more cost effective solution and requires lower capital investment.
A customer perspective
The decision to use DG is not the utility’s alone. An increasing number of utility customers and even energy services companies are evaluating the system’s ability to generate economic power in a range of applications.
Comparing the cost of utility-delivered power to the capital and operating costs of a DG system determine whether it is an economic alternative at a basic level. Obviously, other factors, such as siting, environmental compliance, technical requirements for interconnection and utility charges for providing on-demand power should be included in a thorough evaluation of DG. These factors are highly location-, utility- and application-specific.
In most situations, DG realistically would not totally replace utility power because it could not compete with the efficiencies of base plant generation. Complementing base plant efficiencies by helping manage peak load demand and its associated higher costs can make economic sense, however.
In a real-world example, a commercial utility customer experiencing peak load demand of 96 kW considers installing a 50 kW microturbine with a generation efficiency of 31.5 per cent (LHV) to reduce and level load to 46 kW. The reduction in the customer’s bill would be $28 600 a year, which represents two-thirds of their energy expense.
Here is how the numbers developed. Peak demand varies by month at 75-96 kW, carrying a demand charge of $13 700. Total energy equals 439 000 kWh and costs $29 600, so demand and energy charges total $43 300 for the year.
With a 50 kW microturbine, peak demand provided by the utility would fall to 25-46 kW, dropping demand charges to $5000. Energy for utility-delivered power would total 125 000 kWh and cost $9700. Demand and energy charges in this instance would total $14 700. The $8700 savings in demand charges and the $19 900 savings in energy charges produce the $28 600 total savings.
Is DG an economic alternative power source in this instance? It depends.
Figure 3. Determining annual savings for DG based on variable operating costs and fuel prices
Fuel costs to fire the microturbine play a significant role in determining economic justification. In this instance, a $5/MMBtu cost would combine with operating and maintenance costs of $0.75/kWh to total $21 100/year, for a $7500 savings. Figure 3 shows the extent to which fuel costs affect DG economics. Even at $8/MMBtu, the customer still would save money on their utility bill.
Dividing a yearly savings of $7500 into the installed cost, in this case $30 000 or $600/kW, produces a four-year payback. Whether the project moves forward depends on the customer’s return on investment criteria.
Figure 4. Payback analysis for DG in the USA: 3, 5, and 7 year scenarios
Plotting this simple payback analysis using typical fuel and electricity costs in each of the 50 states in the USA produces the spread shown in Figure 4. The three lines represent paybacks of three, five and seven years respectively.
DG is most economic in states such as California, Illinois and New York where electricity rates are high and fuel prices are low. At the other end of the spectrum are states such as Florida, where electricity rates are low and fuel prices high. The economic argument for DG is then difficult to support, but the situation can change because of market volatility.
Life is rarely that simple, however. Real-world analyses also must include site-specific benefits and costs for both the utility and the customer.
For customers, benefits include the increased power reliability and quality as well as reduced costs for thermal energy loads, less exposure to electric price volatility and revenue from selling excess power. If the example mentioned above was a commercial bank authorizing credit card purchases, the financial benefits from ensuring power reliability alone could pay back the cost of the DG system in less than a year.
At the same time, utilities could enjoy a long list of benefits. Avoiding system capacity increases, reducing transmission and distribution (T&D) electric losses, deferring T&D upgrades, capitalizing on VAR support since some DG technologies can provide reactive power that can help utilities maintain system voltage, and relieving transmission congestion are examples.
The other side of the DG coin for customers includes costs that would be borne by customers and be paid to utilities. Standby charges, competitive transition charges, exit fees and additional incremental capital costs for interconnection and permitting would benefit utilities, while making DG more difficult to justify for customers.
The problem with some of these benefits and costs, however, is quantifying them so they can be objectively entered into the economic equation for DG. A multitude of studies conducted by the Electric Power Research Institute, Edison Electric Institute, National Electric Reliability Council, Pacific Gas & Electric and others piece together a quantifiable foundation that indicates a measure of monetary value.
Reducing costs for energy thermal loads, decreasing exposure to electric price volatility and increasing power reliability could translate into a $0.037 savings per kWh for customers, based on a 60 per cent capacity factor. For utilities, avoiding system capacity increases, reducing T&D losses, deferring T&D upgrades and capitalizing on VAR support could mean a $0.032 benefit per kWh. The extra costs to a customer for standby charges and competitive transition charges would total $0.027/kWh.
Figure 5 shows how customer benefits improve the economic justification to include all 50 states. The chart also shows how extra costs lengthen payback, making DG unattractive in all but a few states.
Clearly, evaluating DG as an alternative power source from both the utility’s and customer’s perspectives requires discerning many shades of grey. It is not a universal solution because an array of factors, ranging from a utility’s own situation to a host of market, technological, regulatory, competitive and other pressures, will colour the decision. Each utility and their customer needs to factor in the benefits and costs that are most important to them, then determine whether DG is the appropriate solution.