i>Various drivers are pushing distributed generation forward, but users must do some comparison shopping between DG and central station generation to ensure their decisions are properly informed.
By Will McNamara, Contributing Editor
Large, central station power plants-often located hundreds of miles from the load they serve-have long been the foundation of the nation’s energy supply. However, over the last decade, a number of factors have coalesced to push forward the market for distributed generation (DG) alternatives and prompt generators, electric utilities, and end-use customers to contemplate on-site power options.
While the market for DG may be growing, it remains heterogeneous. The broad definition of DG includes a number of different systems composed of various generation sources that are located near the energy consumer’s site, which may be highly integrated with or isolated from the electric grid. These technologies can include internal combustion engine/generators (gensets), microturbines, photovoltaics, wind turbines, external combustion engines, and fuel cells. Put simply, however, DG is any small-scale power generation technology that provides electric power or thermal energy where it is needed or, at the very least, at a site closer to the load source than a central generating station.
As the market for DG alternatives continues to grow, virtually every entity involved in power generation will be faced with the choice of adopting a DG alternative to one extent or another. This article will explore the considerations that various entities typically vet when “comparison shopping” for a DG solution as an alternative to central station generation.
Since the early 1990s, a number of forces have fundamentally changed the electric power business and pushed forward a burgeoning market for DG:
• Demand for power has increased dramatically due to economic expansion and growth in computer data systems and other technology sectors. The North American Electric Reliability Council estimates that peak power demand will grow by 2 percent per year through 2010.
• Along with this growth, an increasing part of the economy requires high quality, uninterrupted power.
• The monopoly system characterized by government-regulated utilities has been deregulated in some areas. With the dismantling of this system, smaller players have been able to enter the market with DG offerings.
• Environmental concerns and air quality regulations have increased reliance on natural gas and renewable sources.
• New small-scale generating technologies have emerged and existing technologies have improved, helping DG to become more cost-competitive with central station generation.
The ways in which DG is presently being used-and by whom-is also evolving. Cogeneration plants at industrial and commercial facilities account for the largest portion of customer-owned DG power production in the United States. These cogeneration plants typically range in size from 1 to 500 MW. Back-up units operated only in emergencies account for the second-most DG capacity. Such back-up generators, typically used by hospitals and large commercial buildings, range in size from a few to several hundred kilowatts. DG can also be used as a primary source of electricity, essentially reducing or even eliminating reliance on the utility for electric service.
Most DG systems today are being installed by a fragmented industry comprised of small engineering firms and consulting companies responding to end-user needs. Generally, most regulated utilities are taking a “wait and see” approach to DG while monitoring technology developments and conducting pilot demonstration projects to become more familiar with the risk and business case.
Current estimates suggest that grid-connected DG capacity accounts for only 3 percent of total U.S. capacity. According to energy educator Enerdynamics, about 550,000 small DG units now exist in the United States. Of those, roughly 25,000 are operational all the time. By 2020, the American Gas Association forecasts that such facilities will account for 20 percent of all new capacity in this country, or 5 percent of all electricity generated.
A late 2004 study prepared for the Federal Energy Regulatory Commission (FERC) projects that the market for gas-fired DG could rise by some 28 GW this year, adding 1.4 quadrillion Btu of new gas demand in the United States. Resource Dynamics Corp., which provides DG solutions to an array of customers, projects that some 49,500 new DG units-mostly of the combined heat and power variety-could be added to the country’s existing base of 29,000 units in the 2004-2005 timeframe. Those units, with a capacity of 60 MW or less, are typically installed on or near a customer’s home or business.
To assess the cost/benefit analysis of DG compared to central station generation, Power Engineering spoke with three companies actively engaged in the DG market: a utility that wants to supplement its central station power plants (Detroit Edison); a manufacturer of DG power solutions (RealEnergy); and a power marketer that is actively marketing DG solutions (Pepco Energy Services).
Detroit Edison, a principal operating subsidiary of DTE Energy, has used DG as a distribution solution since 2002. In addition to more than 11,000 MW of power generation (primarily coal-fired), Detroit Edison has installed 7 MW of direct grid connected DG for distribution support and 10 MW of premium power generation (customer locations) that can be used for distribution support.
Hi-tech companies like SAP rely on emergency gen-sets to provide reliable power. Photo courtesy of MTU.
Yountville, Calif.-based RealEnergy develops distributed generation/combined heat and power (CHP) systems. The average size of the unit that RealEnergy sells is just under 1.4 MW, although larger units operating in the range of 4.5 MW could apply to larger loads. RealEnergy’s major customers include CALPERS, the State of California, and Marriott Hotels.
Pepco Energy Services provides energy suppliers and large energy users an array of energy management services, including risk management and acquisition and management of power generation assets. Pepco Energy Services does not manufacture DG units; it provides its customers with standby power solutions.
The three companies share a common viewpoint that the most appealing DG units are cogeneration systems (capable of producing both electricity and steam for on-site use) and emergency back-up generators. Not surprisingly, together those two sources account for more than 95 percent of the customer-owned generation capacity in the United States.
Although reliability and environmental benefits are strong factors, the potential for cost savings stands out as the primary consideration among entities considering a DG alternative. The capital cost of building or acquiring a generating facility represents a significant financial investment. Costs obviously vary depending on the size of the plant and the region, and for traditional power generation can range anywhere from less than $1,000/kW to possibly more than $4,000/kW (Table 1).
Over the next decade, the cost structure of the traditional generation sector could increase considerably due to rising fuel costs, environmental regulations, and energy security concerns. In addition, substantial new investments in electric T&D system infrastructure are needed to address load growth and increase reliability. These key industry uncertainties continue to drive interest in the role of distributed power, particularly in its opportunity to meet peak demand and use precious natural gas resources more efficiently.
Among small-capacity technologies, internal combustion engines (fueled by diesel and gas) have the lowest capital costs and highest operating costs (Table 1). The capital costs of many DG technologies have fallen significantly in recent years and can be expected to continue to do so. In the case of photovoltaics, the cost per delivered kWh in sustainable applications has plummeted by almost 70 percent since 1980, and is projected to decline by another 70 percent from current levels by 2020.
Installation costs for microturbines and fuel cells are relatively high and unpredictable compared to more mature DG systems such as internal combustion engines and combustion turbines. However, as microturbines and fuel cells approach full-scale commercialization, it is expected that these costs will decline and become more consistent.
Similarly, developers forecast that fuel cells will improve in performance and decline in cost over the next several years to the point that they will soon be suitable for widespread use in DG. A recent study by Lawrence Berkeley National Laboratory projected that the installed cost per kilowatt for a 200 kW fuel cell would drop from $3,500 in 2000 to $1,300 (in 2000 dollars) by 2010.
From the perspective of a manufacturer that sells DG solutions, RealEnergy believes the primary attraction for end users is that it is cheaper. “Customers who lease DG plants from us believe they have more control over the cost and, in many cases, they do,” said Kevin Best, CEO. “It is attractive for a customer to buy a system that is commissioned, running and operational for a set period of time. Customers all want cheaper power and they do not want to own the plants. Standby power is an option for them because they have it on-site and they don’t have to pay for it as a capital expense.”
RealEnergy’s experience has been that the investment cost of the wires is rising rapidly, currently averaging almost $1,500 per kW at today’s prices for transmission, distribution and substations. According to Best, “While end users may be able to install a $50 million plant cheaper, they also have to add in the wire costs and the generation costs and take away the fuel hedge that the cogeneration plant offers.”
According to David Weiss, group president and COO of Pepco Energy Services, “The installation costs for DG may be slightly higher, but when coupled with combined heat and power it is far more efficient and draws the operating costs down. So it becomes more cost efficient over time. When the technology provides a combined heating technology, that is the real benefit.”
In some instances, DG offers an appropriately sized solution to a problem. “We can’t afford to solve every 1 MVA problem with a traditional T&D 30 MVA solution,” said Hawk Asgeirsson, supervising engineer, distributed resource planning at Detroit Edison. “There are many problems that may only exist for a few hours per year. Installing [central-station] capacity that may not be fully utilized for several years is simply not cost effective. DG is one way of delivering just-in-time and right-sized capacity to resolve smaller shortfalls while minimizing the initial capital outlay.”
Along with the actual cost differences, Detroit Edison found an added advantage in its DG units. “With our microturbine, we were able to defer costs that we would not have been able to defer if we had gone the route of a substation,” said Asgeirsson. “With a 2 MW or less shortfall, there is the opportunity for cost savings with DG. While $4 to $6 million may not be a lot to spend on a substation, it you are looking to meet only a 2 MW shortfall, it is an exorbitant expense. DG can be a less expensive alternative.”
Fuel & Other Costs
Natural gas prices are a critical input variable for evaluating DG because many DG technologies use natural gas as a fuel. For example, if gas prices rise between 4.9 percent and 22.4 percent, some 32 percent of the DG market potential would be lost. But if gas prices were to fall to historic 1990s levels, then the DG market could increase as much as 92 percent, according to the Energy Information Administration.
Companies considering a DG option versus central station generation also need to carefully consider operation and maintenance (O&M) expenses. These include labor and overhead (e.g. medical and pension benefits), expendable materials, and local property taxes (which vary from state to state). See Table 2 for a detailed comparison of the O&M costs of traditional power sources and DG technologies.
In summary, O&M costs for DG options are slightly lower than central station generation. O&M costs for a 30 kW to 6+MW reciprocating engine running on diesel would be about $0.005 to $0.015/kWh. The range for a fuel cell in the range of 100 to 3,000 kW would be somewhere between $0.0019 and $0.0153/kWh.
When evaluating costs, companies may compare technologies on the basis of total capital and operating costs incurred over a 10 to 20 year time period. A technology with comparatively high capital costs but comparatively low operating costs (primarily fuel costs) may be the appropriate choice if the unit is expected to operate continuously. However, a plant with high operating costs but low capital costs may be a more appropriate selection to serve peak load.
Efficiency & Reliability
Efficiency and reliability have long been concerns at central power stations. Central power plants struggle to achieve a 50 percent delivered fuel efficiency for the power they generate. In fact, most reports indicate that central station power plants average approximately 30 percent in overall efficiency. This means that half the potential energy in a cubic foot of natural gas (or ton of coal) actually reaches the wall socket of the consumer in the form of usable energy. The rest of the energy either goes up the stack at the central generating station in the form of waste heat or is lost in the transmission process as line losses and transformer losses.
Not only do DG resources put the power where it is needed, but they also provide enhanced energy efficiency. Modern gas turbines, for example, can achieve 35 to 45 percent efficiency when generating electricity, and in cogeneration applications recovering waste heat, overall efficiencies can rise to the range of 80 to 90 percent efficiencies.
With respect to reliability issues, DG proponents generally believe that, for companies that require premium, uninterruptible power, DG systems are the only guaranteed solution. DG resources have the potential to enhance grid-connected applications by improving transmission and distribution reliability while meeting baseload energy, peak shaving, back-up power, remote power and cooling, heating and power requirements.
DG can also protect against service interruptions or variations in voltage or frequency that can harm equipment. The majority of those interruptions are due to equipment failures or power line breaks close to customers’ premises.
The value of improved reliability is hard to quantify. It depends largely on the reliability of the regular electricity supply. “We found that the portable generator used in place of the substation had improved reliability,” said Asgeirsson.
“Central power plants are getting more efficient, but the more important comparison relates to the power that DG offsets,” said RealEnergy’s Best. “Lines losses are a barrier to get the power to the load from central power stations. The power that DG units displace is where the real issue is.”
Weiss of Pepco Energy Services concurred: “Often there is a need to stay powered up without interruption, so even though the economics would not stand on its own, the benefits of reliability and not going down make it a worthwhile investment for the customer. Four to six hours to restart the assembly line and that is money that goes down the drain.”
Neither central station nor DG escapes regulatory challenges. Almost all states, counties, and cities regulate the installation and operation of electricity generators. Those regulations are often enforced by multiple and sometimes overlapping jurisdictions. Large power facilities have become politically more difficult to site and permit. Community, neighborhood, and activist groups frequently oppose new power plants and transmission projects, claiming they would cause environmental damage, noise and declines in property value. Organized opposition has stopped numerous projects and delayed others for years.
The problems associated with siting central station power plants remains a primary driver behind Detroit Edison’s move toward DG . “The regulatory issues we had with community siting of substations were extremely problematic,” said Asgeirsson. “It was vastly easier to get a portable generator approved. Even though it’s an essential service, regulators seemed more willing to approve it if they thought in temporary terms. We couldn’t get the job done [with a substation]. The NIMBY coalitions just made building a substation extremely difficult, so DG was the option.”
At the same time, incentives provided in some regulatory jurisdictions can be a real boost for DG options. For example, Oregon utilities would be able to bring some 1,831 MW of new DG into their electric system over 20 years with incentives, according to an Oregon Public Utilities Commission report. But without the incentives, only 384 MW will likely be developed. Some 500 MW are currently in operation in Oregon, the PUC said, as it outlined ways to develop the mini power plants at homes and factories. Among recommendations, the Oregon regulators said utilities should follow new uniform rules for interconnecting generators. The PUC said it should approve standard purchase agreements for plants and review how small generators could sell power to other retail customers over a utility’s distribution system.
The Pennsylvania PUC also wants more DG in its state, and it plans to encourage development by standardizing interconnection requirements among different utilities. In late 2004, it issued a request for comment on which issues to address and which practices to adopt. The PUC has said that DG can improve grid reliability by locating power sources closer to loads, and by reducing peak power demand.
Regulatory subsidies have actually made the growth of RealEnergy’s business possible. “We couldn’t have done anything without regulatory incentives,” said Best. “In California, New York and New Hampshire, representing about 25 percent of the money available, the incentive programs have been essential for us to get our products on the market. We have been sustained by public goods charges (subsidies built into utility power rates). In the 1 MW range, we can’t even do it without subsidies.”
DG growth will vary among the various entities involved in the market. From a utility perspective, DG will remain one of the tools used to manage generation load. “DG can’t effectively be used for circuit loading,” said Asgeirsson. “It’s not a solution for everything. It’s maybe a 3-percent solution, to manage distribution system technology.”
Over the next 10 years, rising generation expenses associated with high fuel costs and environmental and security costs will further drive the market for DG alternatives. The utility market’s reliance on central power station ownership will likely remain largely intact, but the DG model will help utilities meet future peak power needs and avoid costly T&D investment in certain instances.
Implementation of DG will likely be slow over the next 10 years. Full-blown commercialization will take time. Some DG applications make sense, especially for certain customers who need higher quality and higher reliability power.
For DG to meet its growth projections, technologies must improve and costs need to come down. p