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Prepared for renew wisconsin January 28, 2003 by steven nelson |
toward a sustainable energy future for madison
is mge’s west campus cogeneration facility on the right track?
toward a sustainable energy future for madison
is mge’s west campus cogeneration facility on the right track?
The request to build a power plant of this magnitude within Madison’s city limits brings with it some real concerns. It is truly being built in our own backyard. That fact alone is reason for pause; it is no longer, “out of sight, out of mind.” While it is reasonable to couple the realities of supplying power to the community consuming the energy, it is questionable to promote and pursue only one solution – increasing electric supply.
We recognize that a growing economy and commercial development will need power and energy to sustain its health. And energy supply companies seem all to eager to plan and market such a commodity. As ratepayers we ask for more prudence, especially in the current events surrounding the energy market. Is it prudent to plan a facility that is so large that it will take 20 years to even approach its forecast or return on investment? Most “cogeneration” projects realize paybacks in one to five years. On the surface it appears that just such a short-term strategy is more prudent and possible. But with the West Campus Cogeneration Facility plan, that is not the case.
There are other alternatives to be presented and promoted, or at least given the same attention and spin as the proposed plan. That is the purpose of this report. The present quality of our neighborhoods is at stake, and the residents and the public should have more than the usual courtesy as to what gets built or how future energy concerns are met.
In February 2000, UW received a study that looked into its future energy needs (i.e. heating and cooling) brought on by planned expansion, and how to best prepare for those needs. The preliminary results of the study were that the UW should build and operate its own cogeneration facility. The subsequent design recommendations were based upon available mechanical technology and related sensitivity factors like the price of natural gas.
One of two chosen design recommendations was a combustion turbine facility with a heat recovery steam generator for process steam. The second cogeneration recommendation for $20 million less was a high-pressure boiler to drive condensing/extracting steam turbines connected to electric generators. The extracted steam would be dedicated to campus heating. The choice was found to be very sensitive to the price of natural gas.
The findings were not unexpected. Cogeneration is a commonly applied technology for many campus type settings. Such settings have desirable electric and steam loads that are sufficiently large and coincident – having high operating hours. The study further recommended electrical capacities from 19 MW to 45 Megawatt (MW) and steam capacity of 500,000 lb/hr that were based upon the anticipated needs for the UW. Adjunct to the electric generators would be 50,000 tons of cooling from steam turbine driven centrifugal chillers. It was also found that best economics were for the UW to own and operate the facility.
Madison Gas and Electric (MGE) company now proposes to build a facility on the western end of the University of Wisconsin – Madison (UW) campus. The facility is sited adjacent to the existing UW Walnut Street steam plant. This location provides convenient access to the campus distribution systems for steam, chilled water and electrical. The project is currently in the application process before the Public Service Commission as required by Wisconsin statute.
The MGE plan that is referred to as the West Campus Cogeneration Facility (WCCF) is to provide a nominal 150 MW of electric generation capacity and process steam to 500,000 lb/hr. The capacity is believed necessary to meet MGE customers’ need for electricity including the UW campus. And MGE believes that the capacity can also meet the future space heating and cooling requirements resulting from planned UW expansion. The space heating will come from process steam fed directly into the UW steam distribution system. Cooling requirements are to result from new electric chillers that will subsequently feed the chilled water distribution system. The electric chillers will add to the UW summer demand an estimated 20 MW with the possibility of expanding up to 50,000 tons (50 MW).
The MGE plan specifies a combined cycle facility. A combined cycle facility utilizes two turbine technologies, that of gas (i.e. combustion) and steam. The gas turbine technology is similar to that which is employed in today’s jet engine. Natural gas is combusted within and then expands through a turbine to create shaft power for an electric generator, and extremely hot exhaust gases. The excessive heat from the hot exhaust is then recovered in a steam boiler known as a heat recovery steam generator (HRSG), which in turn, pressurizes more steam to drive a secondary turbine. This secondary turbine also drives an electric generator.
The MGE plan portrays and relies on a 20-30 year forecast of fuel stability. But knowing how volatile the energy market has become in recent years, this misleads the public. The current market is evidence to the fact that the availability of natural gas is a moving target and under constant speculation. While we all like to plan for the future and invest for the long haul, a long-term investment dependent upon natural gas may not be the best strategy at this time. And natural gas certainly shouldn’t be the only supply side strategy for bolstering electrical service in MGE’s territory. The instability in the present energy market and propensity for change cannot be reliably predicted as in past decades.
In today’s market, there are obvious risks to any facility dependent on natural gas. First, price volatility is clearly a risk, as was experienced during the winter of 2000-2001. Exactly what caused it is up for debate. But to name one, there are the miles of pipeline – a source of supply constraint and various failures that range from physical limitation to management. It doesn’t really matter if the reasons are real or perceived. The effect on price of natural gas is the same. It goes up.
Second, the demand for natural gas has grown exponentially in the past decade. The growth has occurred in a business climate with limited, if not absent, regulation. The lack of regulation means that there is no reliable window into the supply and demand portfolio. A market like natural gas is subject to the laws of supply and demand, and the need for a clear look into the market is critical for market stability. Do we truly know how much demand is amassing at the end of the pipeline between peaking plants, fertilizer production, and space heating? For peaking plants alone, the 2003 forecasts range from 85 to 300,000 MW – depending upon the source. The only sure thing in these circumstances seems to be uncertainty.
As stated above, natural gas supply activities such as exploration and drilling are not regulated in any responsible manner. The only regulation comes indirectly in the form of monitoring by the market. With no structured regulation, natural gas has become a magnet for speculation by traders and drillers. Forecasters are currently predicting a wintertime spike of $6-8 per million Btu. Others are promising that this initial spike will then level off at $5-6 per million Btu. This type of swing in the market will bring with it a great deal of speculation on the supply-side, leaving captive consumers vulnerable to price spikes. Natural gas is a long way from being a stable industry. More thought must be given to tempering our exposure to price increases and market instability.
Fuel switching offers a hedge. Conceptually, fuel switching may be full or partial – 100 percent switchover verses supplemental supply. In switchover, the facility design must often make substantial investments in fuel handling equipment and/or burn technology. But it is justified by lowering the risk associated with supply of the primary fuel. In the supplemental, a facility design considers a mixing or fractional use of alternate fuels. For example, a sustainable fuel might be considered for the duct or supplementary heater at the HRSG stage. Or, a mix of natural gas and a sustainable fuel such as biogas might be sought for the combustion turbine.
It is clear in the MGE plan that the commitment to natural gas is very high, and any buffering by fuel switching is not being considered. Even if it is considered, it may not be possible given constraints due to large size of the facility and its intimate location. In general, the MGE plan is overly optimistic given the current status of fossil fuels like natural gas.
The overriding criterion for cogeneration is to design its outputs – electric and steam – such that they match existing loads, and preferably, loads with high operating hours. The MGE plan specifies electric capacity of 150 MW. The UW summer peak demand is currently about 50-55 MW. This capacity is clearly in excess of what the UW campus requires. Even with the inclusion of electric chillers, the demand falls short of the 150 MW. This mismatch begs the question why WCCF is being promoted as cogeneration when the base criterion for cogeneration is absent.
The excess electric capacity is partly mitigated with the inclusion of electric chillers. This operational strategy of using electric chillers must first generate electricity, and then subsequently consume electricity. It also creates a consequential and significantly large electrical demand, and better match between electric output and existing (potential) load. This combination of excess capacity and installation of electric chillers makes sense only if your economic advantage is to come from selling electricity. It is not conventional cogeneration to expand the electric side of the output equation.
The base criterion would imply that the design seeks to increase the existing steam load. For example, chilled water can result directly from using steam through the secondary turbine. It directly drives a centrifugal chiller (as done in the Charter Street facility), thus eliminating additional steps in energy conversion. Multiple conversions of energy induce extra losses into the cycle and increase the consumption of primary fuel. This approach grows the steam side of the design equation by adding steam load. But the proposed plan doesn’t take that approach. It calls for more electricity rather than designing balance into the steam side. The MGE plan will greatly increase the energy cost to the UW for chilled water.
Besides the preference for generating and consuming electricity in the summer, the plan has a preference for generating electric in the winter as well. Steam derived from the HRSG and expanded through the secondary steam turbine can provide shaft power to an electric generator or centrifugal chiller. Or, the steam can be extracted for space heating. There is a choice to be made at the secondary level, whether to use steam for shaft power (i.e. electricity) or process (i.e. space heating). In their case, using steam for space heating is only on an occasional basis. The MGE plan again shows a preference to generate electricity.
The proposed plan as present warrants using the term cogeneration with an asterisk. The plan enlists a design commonly used by power developers and utilities for peaking plants, and is not necessarily conventional cogeneration. This plant design is currently popular because of its use of natural gas as a primary fuel, which overcomes many of the environmental concerns associated with traditional coal burning technologies such as being a cleaner burning fossil fuel. Thus the plan only appears to come across as well thought out relative to air quality. However, the MGE plan leaves many prudent questions unanswered.
Supply-side refers to capacity additions for increasing the quantity of energy. In contrast, demand-side covers measures for reducing or regulating energy intake, and focuses on such end-uses as air conditioning, motors, lights, etc. Cogeneration is considered a supply-side strategy. Its main selling point to industry and society is supplying electricity and steam (thermal energy) at a greatly reduced cost because less fuel is purchased. Cogeneration is often applied, in lieu of supplying electricity and steam independently, when prominent electric and thermal loads are located in near proximity to each other.
Why cogeneration? First, the amount of fuel necessary to provide electricity and steam simultaneously can potentially be much less than the amount of fuel consumed when produced independently. Most electric-only generation facilities realize a 20-30 percent fuel utilization factor. The percent varies with varying thermal and transmission losses. This fuel utilization percentage represents the conversion efficiency of the energy contained within the primary fuel to the actual energy consumed by an end-use. For comparison, a true cogeneration facility can realize a fuel utilization of 70-80 percent or more.
Second, accepted practice in electric generation dumps massive amounts of thermal energy into the environment in the form of condensate and exhaust. This is in an effort to maximize the shaft output that corresponds to kilowatt-hours. The practice results in more fuel being consumed and subsequently more heat and pollutants being released into the environment. By contrast, cogeneration seeks a balance between electric and thermal outputs that potentially maximizes fuel use over electric output.
Along with less primary fuel being used to meet the same level of end-use requirements, there is also the benefit of less fuel having to be transported. That benefits Wisconsin. And is a major consideration in regions where natural gas pipelines are nearing capacity. Natural gas is almost exclusively used for space heating in Wisconsin so pipeline capacity is likely to become critical first during the heating season. However, summertime is not immune from limited capacity due to the expanding number of gas peaking plants such as the WCCF. Also not to be overlooked, there is a large demand for natural gas in the production of fertilizers. To reemphasize, fuel utilization becomes critical when you consider the sheer volume of natural gas being transported. Such excessive volume requirements will prematurely stress our transportation network, since two to three times more of fuel is transported, in order to yield an equivalent amount of useable energy.
In the present market, cogeneration must have a short-term payback. Planning and forecasting that is too far out into the future in today’s business climate will have long-term repercussions. It should be done with a great deal of caution and reluctance. Normally, cogeneration projects have short paybacks but not the MGE plan. Its magnitude immediately hinders any short-term potential. Such overbuilding of capacity is likely to leave ratepayers paying for years to come on speculations and guarantees that should not have been made.
What would make cogeneration feasible? There must be a reasonable electric and thermal load ratio. While there are various design configurations employed in cogeneration, each configuration sets forth a respective and plausible ratio for thermal and electric outputs. For steam turbines, the ratio would be 3-20 (average lb/hr x 1,000 Btu /lb)/(average kW x 3,412 Btu/kWh). And for gas turbines, the ratio is slightly lower at 1-10. This balance or ratio between thermal and electric output is the starting point for any economic justification of cogeneration.
That said, the MGE design ratio is well below “1”. In fact it approaches “0” for much of the year. Falling so far below the range, the MGE plan would be disqualified as a cogeneration project. Not being a conventional cogeneration design shifts the economics. Electricity sales now become critical to the economic model. Therefore the inclusion of electric chillers into the design is necessitated in order to make economic sense to said developer.
Beyond the thermal to electric ratio, several other factors are considered before a project is feasible for cogeneration. These factors include
· Cost of electricity
· Cost of primary fuel
· Operating hours in which capacity matches existing load
· Size of team and electrical output(s) – economies-of-scale
· Both boiler operating and process pressure, and
· Installed cost.
Experts in the cogeneration field have over time established acceptable or “favorable” range for each of these factors. When a factor is outside its respective range, then a project is likely to be questioned.
In no particular order, the average cost of electricity is desirably above $0.06 per kWh. Second, most cogeneration experts want to see the cost for primary fuel below $3 per million Btu. In industry, primary fuel is frequently “free” as found in the wood processing industry where sawdust or chips are readily available. But in some cases, the fuel cost is overruled where reliability is more of a concern.
Third, operating hours or base load to be served should be greater than 6,000 hours per year. This is not the case with the MGE plan, which is anticipated to be well below 6,000 hours. The operating or demand threshold applies equally to electricity and steam. For the purposes of this evaluation factor, the demand for steam by the electric generators is not considered a steam load. The economic model weakens as either of the operating hours decrease. However, should that happen, other factors have to overcompensate. For example, low hours of operation would mean that the price for electricity would need to be higher or maybe the cost of primary fuel would have to drop. Again since excess steam capacity already exists at the UW Charter Street plant, and MGE has more of an incentive to generate electricity than steam, it is likely to be cogenerating for only a minimal number of hours per year.
Other factors relating to economies-of-scale are steam capacity and electric capacity. Steam capacities greater than 50,000 lb/hr, and electric capacities greater than 1 MW are desirable. These reflect economies-of-scale that a developer would like to see in order to warrant the necessary level of planning and investment. Looking at steam properties is also important; boiler pressures should be greater than 250 psig and process pressures less than 50 psig. The MGE plan is within these ranges.
Lastly, developers would like to see installed costs below $450 per kW for steam turbine installations and under $1,000 for gas turbines. The MGE plan’s installed cost of around $1,170 per kW is above the amount that is seen in the market. Plus it is not known if the installed cost includes system upgrades that are necessitated by the implementation of electric chillers
Considering the above feasibility factors, the MGE plan is very questionable as a cogeneration project. Foremost are that the electricity costs are at the very low end. But in this case, the volume of electricity sales to the UW might compensate. Increasing the volume makes up the margin. Second, the market price for primary fuel is already at the high end of the favorable range and expecting to go higher. Predictions are for $6-8 per million Btu sometime in the coming year, and likely leveling off around $5 per million Btu for the next 3-5 years. Further, the cost of fuel is increased by the facility’s requirement for approximately 50 percent firm capacity instead of fully interruptible. Per this level one test, the MGE plan as presented in the application is not a feasible cogeneration project
Photovoltaic (PV) installations can provide a unique solution to our need for power in Dane County. The electrical output from PV installations is highest during sunny days. During sunny days is the time when Dane County is experiencing its highest demands for electric power. This coincidence is the main reason for promoting PV as a viable solution. The MGE plan is predominantly driven by the requirement to meet summer peaking demands. Since solar-induced loads such as air conditioning significantly contribute to our demand in Dane County and on the UW campus, PV is a plausible strategy.
PV is modeled by MGE but the model does not exploit the coincident aspect. Their calculated cost of $0.30 per kWh is high in terms of base energy costs. However it is the going rate when considering the price for energy at peak times. PV’s value to Wisconsin is being a peaking capacity resource, not in being an energy source or meeting base load requirements. And that is the standard to which it should be measured. In addition, the installed costs that MGE used in its model have notably fallen by 10-15 percent or more in the last year, from $7,500 to $6,500 per kW, as found in a recent local installation. Second, the costs used for modeling by MGE are derived from small demonstration scale pricing, not commercial scale installations. Installed costs are likely to be even lower as a service infrastructure begins to grow.
We should also consider transmission and pipeline benefits from PV. These benefits are often overlooked. Power plants and associated assets like transmission are often underutilized for much of the year, being designed for a small fraction of time when system peak might occur. The MGE plan requires further expansion and investment in transmission or distribution assets ($7-10 million). That again would be underutilized much of the year. PV could help alleviate this stress to the distribution system. In contrast to the WCCF, PV would not burden the transmission line during the summer cooling months; rather it would serve to lessen the demand on the lines. The same holds true for the natural gas side of things. Pipeline capacity would be available because less generation would be required to meet the summer loads satisfied by the installed PV systems.
PV can also lessen the need for energy through proper or creative installation. By its nature, the PV panels provide shade. An innovative installer or architect can arrange the panels on a structure to be effectively integrated into a roof or shade fenestrations. The shading greatly reduces the solar load within a building, making PV not only a source of energy but a conservation measure as well. While the economic model credits PV for not creating pollutants such as carbon dioxide, it doesn’t credit it for energy that is potentially conserved. This quality and those mentioned above need some consideration in any modeling attempt.
In conclusion, PV is more than a producer of kWh’s. It is a generation source whose maximum output coincides with peak summertime demand, and can be effectively used to relieve stress on our present distribution system. As a fuel, it is free and nonpolluting – true benefits that can last a lifetime.
Wind varies from PV. It is more competitive as an energy generator but not necessarily coincident with demand. The wind blows as the weather changes and electricity is produced without polluting the air, water or soil. Second, the installed cost per kW is nearing that of fossil fuel installations. This is helping the development of more wind resources and subsequently further lowering the installed cost.
In the past two years, a number of eastern U.S.
colleges and universities, mostly in Pennsylvania, have struck a blow for a
sustainable energy practices, principally through retail purchases of renewable
electricity. Their commitment to buy
higher-cost renewable electricity is impressive; indeed, a significant portion
of Pennsylvania’s wind generation capacity is dedicated to serving the
electrical needs of these educational institutions. The two largest colleges in
that state, University of Pennsylvania and Penn State, have elected to secure
5% of their electricity from wind power sources.
Nearly every college campus in Wisconsin has access
to a premium renewable power program offered by its electricity provider. In
fact, Madison’s Edgewood College has been purchasing wind power from MGE since
the program was started in 1999. .
If the UW decided to pursue a similar path, it
should consider forming a working group consisting of administrators, facility
managers, faculty and students to identify ways to cut back on energy
consumption, and apply those savings to offset the cost of renewable power. In
some cases, the above-market cost of renewable power can be a powerful
inducement to go beyond the usual quick-and-dirty energy-saving measures and
adopt behavior-based approaches for limiting electricity consumption.
The wind resource in Wisconsin is comparable to that
in Pennsylvania. Already 53 MW of wind power capacity has been placed in
service in Wisconsin, and more installations are expected this year and next. A
solicitation recently issued by Milwaukee-based We Energies to acquire 200 MW
of new capacity by 2005 will be the principal driver of new installations in
Wisconsin, and could result in development opportunities for other utilities
like MGE.
Wisconsin technical colleges are beginning to invest in sustainable energy such as PV and wind. The rationale is centered on exposing students and future technicians to the technologies. Doing so supplies the marketplace with the talent to install and maintain said systems. Infrastructure development such as this is critical to making progress towards a sustainable future. The UW and MGE are to be encouraged to do more in this regard. The UW is a leading educational institution well positioned to lead sustainable research as it applies to Wisconsin. MGE is likewise positioned to invest and implement such technology on behalf of its customers.
Sustainable energy is also available in biomass and biogas forms. Wisconsin is no stranger to biomass with its many forests and fields. There is an extensive opportunity here to research both biomass options relative to cogeneration and biomass relative to supplanting the facility with another central plant option. Many developers prefer building central plants nearer the supply. In this case, the location might be in a highly wooded area such as western or northern Wisconsin. To implement biomass at the proposed cogeneration site there would be the need for transportation of the fuel resource so it would most likely necessitate the activation of the rail system. This might also be applicable to the Blount Street plant.
Biogas is another sustainable resource that is prevalent in Wisconsin. There is an untapped supply when you consider the size and range of the dairy industry in our state. The manure presently represents a problem for farmers and rural communities affecting water resources and land-use. On the other hand, manure also represents an ideal source of biogas that is very similar to natural gas in heat content. There is much to be done to improve and implement this resource. But again, the UW is positioned to research and prepare the technology for the market.
Load management is a crossover between supply and demand-side endeavors. It both affects and is affected by supply and demand. An aggressive load management program is a must for any entity that purchases power. Electric cooperative and municipals that purchase a large share of their requirements have an immediate advantage in the power market. They can shed load in order to sell existing capacity in a high price market, or shed load as a matter of reducing losses in a high price market. As we continue to pursue energy efficiency, we also need to have the knowledge and means to control “when” we use energy. This potential capacity should be fully developed before committing to any forecast or building of capacity.
It is believed that MGE has only 25 MW of load management. Their gross system demand is currently around 720 MW. So the percent of load management potential is only 3.5 percent. This percentage is extremely low and suggests a strategy for delaying premature investing. As discussed earlier, load leveling or lack of, directly impacts ratepayers by not fully maximizing the profit potential in existing assets and results in premature investments.
The volatility of the energy market is equally matched on the demand side. The political pressure on global warming is increasing in the US Senate; denial is no longer a defensible position and voluntary compliance has been ineffective so far. This growing pressure from congress is likely to cause an increase in the implementation of demand-side solutions by businesses in order to balance future energy management.
Demand-side options bring many benefits to market. In contrast to the years of planning and construction for a supply options, it can be quickly implemented. Demand-side solutions often are sold for their many other problem-solving benefits besides energy efficiency. And proper applications usually result in positive cash flow to the consumer. This is in contrast to a supply-side option that invariably burdens the environment; depends on long-term economic forecasts; and universally increases energy rates in order to pay for the often-underutilized assets. Further, the development of a support infrastructure presents our regional economy with an opportunity for both lower cost for efficient products and more jobs to install and service equipment than a lone supply-side project.
Relating to infrastructure, a public-private partnership is needed to promote and eventually install energy efficiency and conservation measures. The good news is that the UW and Johnson Controls, Inc. are actively identifying and developing measures with paybacks of 10 years or less. The importance of this relationship is noteworthy. Most efficiency measures never come to fruition because of deficits in the infrastructure to support the project development of measures. Most businesses are very involved in their day-to-day responsibilities, the UW is no exception, and they lack the time or expertise to develop and implement potential measures. The existence of a partnership concept greatly increases the success of energy efficiency.
The question to ask is, ‘how far along is this endeavor?’ Most energy managers would prefer to implement demand-side solutions before investing in supply-side assets. The logic is simple. Demand-side strategies lower the amount that you need to purchase or invest in terms of supply. It would be important for the UW to evaluate its demand-side potential before making such an important supply-side investment.
Partnerships such as that with Johnson Controls should be aggressively expanded and accelerated. More partnerships will increase the economies of scale making newer and better products available on local shelves, and at lower prices. As an example, magnetic drives for motor control are now available in Madison in lieu of frequency drives. While frequency drives in the past were an efficient motor control strategy, the newer magnetic drives accomplish the same efficiency without overheating (increasing the air conditioning load) and causing power quality concerns. If we aggressively expand the market, then more products like these will be installed and cumulatively begin to benefit Dane County from the customer all the way back to the power plant. To not encourage this synergy and partnering is to leave our regional economy increasingly dependent upon out-of-state energy suppliers.
Buildings need to be modeled for energy use profiles. A building with a flat energy use profile, using energy at a steady rate throughout the day or season, requires less capital investment at the supply end. Large fluctuations in energy use require additional investments in assets that are often underutilized. It should be stressed that load leveling, building-by-building, will pay dividends in terms of asset utilization. The public-private partnership is currently doing this modeling but the process is not complete. And the practice is focused on efficiency measures but should be expanded to consider load-leveling strategies and on-site renewable energy use.
Load leveling opportunities vary from building mass ratios to lighting controls to cool storage. Cool storage is possible on a central or distributed basis. And depending upon the application, can greatly impact the performance and available capacity in both the central plant and distribution systems. The possibilities will be as unique as each asset’s function. The architect should be challenged to flatten the diurnal and seasonal fluctuations. Again, the benefits will be felt all the way back to the central plant. Such strategies may even supplant some of the forecasted or projected capacity by capping the present demand, coordinating all of the buildings such that as a group they have a level energy profile.
In addition, energy profiling of buildings should be implemented comparatively and competitively. Many institutions and managers compare facilities and compete with each other on various levels regarding energy consumption. Wisconsin technical colleges regularly compare consumption levels in order to improve building performance and lower energy costs.
The aforementioned partnership is in the process of replacing all steam traps. This measure cannot be emphasized enough. Steam is a high form of energy where conservation measures like replacing leaky traps or insulation need to be policy. The reasons are two fold, and the first is obvious. The energy density of steam is so much greater than, let’s say, a cubic foot of conditioned air, that a small leak or lack of insulation in a steam system might be equivalent to a whole story of leaky windows. Thus the return on investment is always much better. The second reason is the direct impact that steam losses have on the available steam capacity. For example, a cluster of leaky steam traps means that the central plant is being robbed of capacity to serve legitimate loads.
Motors are the predominant end-use on campus – an estimated 57 percent of the electric load. The Division of Facility Development has promoted motor replacement from standard to high efficiency or premium motors. While this is good policy, it is the systems that the motors energize that offer the greatest potential for savings. A premium efficient motor energizing a system that is poorly designed or adjusted is analogous to driving an expensive fuel-efficient automobile with the emergency brake on. Significant return on investment is missed by not addressing this system efficiency. The aforementioned magnetic drives are an attempt to address system efficiency but only the beginning. For comparison, motor efficiency alone might improve by 2-4 percent from standard to high (1-3 from high to premium) while motor driven systems often see efficiency improvements of 10-40 percent. There is a tenfold difference in magnitude of the savings.
What does all of that mean? Simply put, efficiency improvements reduce the amount of MW capacity that is required by the campus. To quantify the potential, a 55 MW peak load for the UW calculates to about 31 MW in motor loads. If one half of the motorized systems could be improved by 20 percent it would reduce the UW demand by approximately 3 MW. Using the MGE growth projection of 3.2 percent per year, that equates to two years of forecasted growth – forestalling the campus need for more capacity by two years. Such solutions can be implemented immediately, and for less money. This approach doesn’t mean that capacity should never be considered or planned. Rather that money and capacity concerns can be managed in smaller increments.
The motors and motor systems within the existing central plants should also be scrutinized. These systems represent extremely large and concentrated savings. Central plants are often well maintained and efficiently operated but not often upgraded as engineering and technology make advances. This tendency leads to dismissing the central plant from “efficiency” scrutiny because of the perceived level of attention. As a result, a large quantity of potential energy savings can be overlooked. The auxiliary load such as these motor systems can easily be 10-30 percent of the plant capacity.
Applying heat pumps is an aggressive and efficient strategy for recovering or transferring low-grade heat. Low-grade heat is understood as heat or temperatures that otherwise may not be of any usable or process benefit. One such application is to recover space heat from an exhaust air stream. The heat pump in this case uses standard refrigeration technology. It pulls (recover) heat out of the exhaust air stream and transfers the heat to a “heat sink”. That heat sink could be another air stream or possibly a water loop such as in a perimeter heating zone system – a wintertime strategy. The same system design can also benefit by operating in reverse – a summertime strategy. In the later case, heat can be drawn from the room as in cooling, and be transferred (reject) into the exhaust air stream or chilled water return.
It is shortsighted to think of heat pumps as an all or nothing strategy. We must recognize that the central plant technology in place on the UW campus is already an efficient choice for providing comprehensive space heating and air conditioning. Heat pumps however could be implemented to supplement distributed cooling (and heating) capacity that could greatly forestall investments in cooling water distribution (and steam assets). This hybrid approach wouldn’t require ground loops nor a complete shift in building technology for the architect and building operator. By contrast, ignoring heat pumps as a strategy is to perpetuate the wasting of the steam and chilled water capacity.
Again, heat pumps are an innovative means for transferring low-grade heat. The architect or mechanical contractor responsible for developing the zoning requirements is often the best person to approach the application design. It is not uncommon in commercial structures to find internal zones with very high heat gains from lighting systems and office equipment. This is a natural fit for heat pump technology. Heat pumps can transfer the excess heat from the internal zone to an exhaust air stream or a perimeter-heating loop (in the summertime heat gain can be rejected into the chilled water return.) Just as zoning requirements in a building vary from internal to external; they can vary from top to bottom. Each application reduces the volume of steam and chilled water that needs to be generated and distributed throughout the campus.
Heat pump technology is more efficient than conventional heating and cooling systems. This is largely due to the fact that the technology takes advantage of energy that is free or otherwise lost. No more primary fuel has to be combusted or burned to create heat. The heat is already present and needs only to be concentrated and transferred to the demand. The “free” heat displaces fuel that would ordinarily have to be combusted in conventional systems by three to four times. That is to say, the electric energy to operate the heat pump is about one third of the energy that would be consumed by conventional systems to supply the same thermal benefit. Each cubic foot per minute (cfm) of exhaust from a conditioned building represents about $1.50 per year in energy costs. In buildings where there are high volumes of exhausted air, there are clear savings.
Lighting design is improving lighting efficacy beyond lamp replacement. While lamp and ballast replacement accomplishes notable energy savings, it usually perpetuates poor lighting design and efficacy. Knowing that light energy diminishes by the square root of the distance over which it must travel, lighting that is installed at the ceiling is at an extreme, if not exponential disadvantage from an energy standpoint as soon as the lights come on. It is not uncommon to reduce lighting demand by 4 or 8 times when implementing task lighting, wall washing, floor egress lighting, etc. Such savings far exceeds what can be accomplished with simple lamp replacement.
Daylighting is still a long way from realizing its full potential. Every time one has to draw the blinds it is a sign that daylighting is most likely misapplied. Thinking through this strategy requires a bit more creativity and project coordination. Plus daylighting is a strong source of light; commonly found to be 10 to 100 times more intense than artificial lighting systems within the same space that has windows. One effective strategy to mute its strength is to reflect the daylight off of the ceiling but this is more applicable to new designs rather than a retrofit. Nonetheless, the potential may still occur in existing facilities. (The square root law also applies to daylighting.) The savings result from both turning off overhead lights and reducing respective heat gain. The latter is valid only in the summer.
In new buildings, there are a host of new innovations. Light corridors and pipes are creative opportunities to bring daylight into the center of buildings. These pathways bring high solar light densities into internal spaces in lieu of other strategies such as higher ceilings. Central lighting systems, either daylight or artificial, should also be considered. These technologies have great potential for savings and can also mitigate high-risk maintenance situations.
While many options have been covered, it is evident that much still needs to be done. The energy strategies that are available are diverse and interrelated. To simply conclude that a power plant needs to be built does not paint a complete picture. Existing assets must first be maximized for profit and evaluated for how to best serve the ratepayers. That includes supply-side strategies like cogeneration with increased fuel utilization, and management strategies that link supply and demand such as load management.
Second, ratepayers use energy. It is important to fully educate and implement the many options that are available to more efficiently use that energy. The UW is taking steps in this direction but to what extent? The potential on the demand-side is something that needs more quantification because of its direct impact on how much supply is actually needed, and to avert overbuilding and over investing.
Finally, sustainable energy is no longer a pipe dream. It has become an economic reality. It is time for those involved in energy and community development to fully research and implement sustainable practices. The day is here when we must decide whether to continue and solely invest in fossil fuel, or to begin the transformation into more sustainable practices.