executive summary of uvm comprehensive campus renewable energy feasibility study

UVM Campus Renewable Energy Feasibility Study

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EXECUTIVE SUMMARY

From the RFP: “The University of Vermont requested consultant services to develop a

comprehensive plan to recommend installation locations of renewable energy technologies on

both its main and south campuses. Technologies included Solar PV, Combined Heat & Power,

Solar Thermal, Geothermal, Fuel Cells, Anaerobic Digestion, Biomass, and Wind energy.

The CHA findings indicate a multitude of good opportunities to economically install

renewable energy on campus. The following report highlights initial conclusions. Detailed

analyses are provided in the attached comprehensive report and appendices.

1. SOLAR PHOTOVOLTAIC

The investigation of solar photovoltaic (solar PV) opportunities at the University of

Vermont focused on three main topics: current technology & installation best practices,

locations for installation, and costs & incentives. CHA found many good candidate sites,

researched state and utility incentive programs, analyzed decreasing market costs, and

reviewed numerous opportunities for the University to implement solar PV successfully.

Three (3) categories of solar PV installations were considered: building/roof mounted,

ground-mount, and parking lot carports. A total of 66 buildings, 3 ground mount sites, and 29

parking lots were identified as good candidate sites for solar PV installations. The chart below

summarizes the opportunities that were identified.

Aggregate Summary of UVM Solar PV Opportunities

Total Installable Capacity (kW) 6,525

Total Annual Output (MWh) 7,861

2011 Campus Electrical Usage (MWh) 63,809

Percent Offset 12.04 %


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Full detailed descriptions, including cost estimates of each proposed solar PV system,

can be found in the Solar PV section and appendix.

Ground-mount sites were limited to the UVM Miller Research Farm (MRF) and Bio

Research Facility sites based on space requirements and land use considerations (both current

and planned). Two ground-mount sites are identified for the Miller Farm, and one site is

identified at the Bio Research Facility.

Buildings were considered based on a number of conditions, including roof

characteristics, historical significance, building orientation, shading, and building size. The top

three building sites based on potential generation capability are the Patrick-Forbush-Gutterson

Complex (1.07MW), the Living/Learning Complex (427kW) and the Bailey-Howe Library

(256kW).

Parking lots were considered based on proximity to existing buildings, shading,

available space, and current and planned usage. The top three parking lot sites ranked by

generation capability are Athletic Complex Parking (497kW), the Harris-Millis east parking lot

(124kW), and the parking lot at Waterman (115kW).

The State of Vermont and local utilities offer a number of financial incentives for solar

PV installations for residential and commercial scale installations. The State program, the

Vermont Small-Scale Renewable Energy Incentive Program, funds a maximum of 60 kW of a

given PV installation. Larger projects can still be eligible for funding, but only 60 kW of the

installation would be incentivized. For UVM, the maximum incentive through this program

would be $97,500 or up to 50% of the project costs, whichever is lower.

The Burlington Electric Department (BED), which services all UVM facilities within the

city limits of Burlington, has a newly implemented program that offers the outright purchase of

PV generated power that is fed directly into the grid at a rate of $0.20/kW-hour. On average,

UVM pays at a rate of $0.137/kW-hour so this incentive offers a significant improvement over


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current electric costs. With the exception of the Athletic Complex parking lot (due to size), all

projects recommended could take advantage of this program. Certain permitting provisions

apply to this program, the details of which are provided in the Solar PV report.

While BED serves the majority of campus, there are extensive areas of the southeastern

portion of University property, including parts of the athletic complex, the Miller Research

Farm, and the Bioresearch Complex, that are in Green Mountain Power (GMP) domain. Under

GMP’s program, solar energy systems are connected directly to buildings’ electrical systems

and are ‘net metered,’ which provides the opportunity to sell excess generation (if any) back to

the utility company. GMP’s incentive is $0.06 /kW-hour in addition to the avoided-cost value

from solar-generated electricity consumed on site. The maximum size for this incentive

program is 500kW or 100% of the building’s annual electricity usage.

Solar PV systems can either be UVM-owned or financed via a power purchase

agreement (PPA). These are just two common options for purchasing a solar PV system; there

are many variations and nuances to PPAs, including lease options, fixed term PPAs and buyout

provisions. Under an ownership arrangement, UVM would purchase the PV system and be

responsible for operations and maintenance. Cost estimates and financial analysis can be found

in the appendix. Payback terms in the report have been calculated based on current market

conditions, and vary from 15 to 20 years, based on site conditions, incentives, and system size.

Under a PPA scenario, a third-party developer would own, operate, and maintain the system,

and UVM would agree to install the system on its roof or property. Through this financial

arrangement, UVM could receive more stable and lower cost electricity, while the solar service

provider or financer acquires financial benefits such as tax credits and depreciation, which

would be passed on to the University via lower electricity rates. The PPA scenario has the

advantage of requiring little to no up-front capital investment, and is often cash-flow positive in

year one.


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CHA recommends implementation of solar PV systems across UVM’s campus.

Opportunities to take advantage of PPA options should be considered as projects develop.

Many candidate locations have been identified for further consideration. The most appealing

projects in terms of cost and payback would be the larger rooftop sites on campus, provided the

roof and understructure are suitable.

2. ANAEROBIC DIGESTION

It is currently estimated that approximately 1,000 tons of degradable organic wastes are

generated at UVM each year. These wastes include food waste and landscaping wastes from

campus operations and mixed manures from farm operations at the MRF site. Due to this large

quantity of decomposable materials, anaerobic digestion could be a helpful tool to recycle and

reuse the otherwise discarded debris.

The decomposition of organic matter in an anaerobic environment produces methane, a

valuable fuel gas. The potential to treat UVM’s organic wastes in an anaerobic digester and

produce electric energy for grid sale by combusting the methane produced by digestion in

engine-generators was studied in 2010 by Forcier, Aldrich & Associates. That study was based

upon a larger farm herd than exists today, but it concluded that anaerobic waste digestion with

grid electric sale would only produce a return on investment if external sources of waste were

found to help source the digester and increase gas generation.

In this report, CHA examined anaerobic digestion of UVM’s organic wastes, but at a

smaller scale proportional to the now reduced farm herd. However, instead of using the excess

methane for electric generation (as previously studied), this report considered the conversion of

the excess methane into a Renewable Natural Gas (RNG) fuel for vehicle use. This use has both

environmental and economic benefits, and it would allow UVM to capture the full avoided cost

of fuel purchases for every equivalent gallon of gasoline or diesel produced.

On a simple economic basis, the cost of installing a process to anaerobically digest the

campus and MRF organic wastes and converting the resulting excess biogas to RNG is difficult


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to justify. The digester needed to produce biogas for RNG production would cost

approximately $820,000, and fuel preparation, storage, and dispensing facilities would cost

another $800,000 ($1.62 million in total excluding vehicle conversion costs.) Calculations

indicate annual savings derived from using RNG versus gasoline or diesel would

approximately equal the annual costs for system operation, and thus there would be little

chance for return on the initial capital investment.

In a broader context, digestion of the campus and farm organic wastes, and the

production of RNG for use as a fuel in UVM fleet vehicles, would produce both economic and

environmental benefits that are difficult to quantify at this point in time. An anaerobic digestion

project for campus and farm organic wastes would yield measurable positive economic and

environmental benefits if the negative externalities of fossil fuel production and environmental

harm caused by GHG emissions could be better quantified.

3. BIOMASS ENERGY

Biomass energy is the utilization of a renewable fuel source (e.g. wood chips,

agricultural waste, yard clippings, municipal solid wastes, etc.) for the production of thermal

energy or the production of both electricity and thermal energy (i.e. CHP/cogeneration).

At UVM, several existing and emerging biomass technologies could be employed, including

(but not limited to): biomass combustion to produce hot water; the production of steam for

heating, with potential utilization in a steam turbine generator to make electricity; synthetic gas

production for use in reciprocating engine or gas turbine generators (electricity) with heat

recovery for the production of thermal energy; and stacked technologies including biomass

combustors and an Organic Rankine Cycle (ORC) system producing electricity and thermal

energy.

In this study, two potential biomass plant locations were examined: the Trinity Campus

and the Cage Heat Plant. At Trinity Campus, two cases were considered: an economic update of

a previous UVM Physical Plant intern study that looked at heating only; and a new


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cogeneration scenario that would provide both heating and electricity to buildings that are

currently electrically heated. At the Cage Heating Plant, a biomass cogeneration plant was

examined that would produce electrical power to off-set electricity that UVM purchases, and

that would pre-heat condensate to the existing heating plant deaerator, which would slightly

improve heating plant efficiency.

A simplified economic analysis of the cases, considering a range of future energy prices

(wood/biomass, gas, electricity) reveals that the nominal payback period of the heating-only

biomass plant at Trinity has the best potential payback of cases examined. CHA recommends

that when the opportunity is appropriate, the Trinity biomass heating-only case should be

compared to gas-fired boiler options, geothermal options, and should consider/include the cost

of district-heating system infrastructure and conversion of the Trinity buildings from electric

heat to hot-water heating coils (which is required whether the Trinity district heating system is

gas or biomass fired). The cogeneration cases at Trinity and at the Cage have much longer

payback periods, in comparison to the biomass heating-only case.

4. CHP / COGENERATION

Combined-Heat-and Power / Cogeneration

Combined-Heat-and-Power (CHP) or Cogeneration, is defined as the simultaneous

production of two or more useful forms of energy from a single fuel source, with the resultant

combined energy production accomplished at a high overall efficiency. For the UVM campus,

the energy products from a cogeneration facility would be electricity and steam or hot-water for

heating.

Each potential cogeneration opportunity is unique and may require a different technical

solution, depending on factors including the magnitude and variability of the electrical and

thermal loads that can be serviced; future load growth or even load contraction; physical space

available for a plant; suitable access to an adequate fuel supply, and to electrical and thermal

interconnections; the type and sometimes the age or condition of existing thermal energy and/or


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electrical generating assets (i.e. avoided costs, as applicable); existing infrastructure; and

frequently public perception (e.g. environmental) and/or external stakeholder concerns

(including those of existing gas or electrical utilities).

UVM Energy Information

UVM energy operations staff provided basic campus energy technical information

including recent electrical energy consumption on a monthly-per-building basis; a description

of the annual steam production profile at the existing Cage Heating Plant and an explanation of

the steam distribution system; descriptions and graphical representations of the existing

Burlington Electrical Department (BED) electrical interconnections to UVM buildings; Vermont

Gas natural gas fuel supply information; ongoing energy efficiency and conservation measures;

and a basic tour of the campus and potential locations for a cogeneration facility.

This technical information, plus a copy of a year-2006 Cogeneration Feasibility Study (by WMG

Group) that examined cogeneration opportunities on the campus as it was configured at the

time, were used to examine the opportunity for cogeneration in the near future at UVM.

UVM Cogeneration Locations

Accordingly, based on the information provided, two (2) locations were identified for

further examination in this Renewable Energy Feasibility Study: a) a nominal 3.5 MWE

cogeneration plant at the Cage Heating Plant that would provide electricity to eleven (11) large

electrical-load buildings located relatively near to the Cage, and would provide steam to the

Cage (displacing gas-fired boiler steam); b) a nominal 250 kW cogeneration plant at University

Heights, that would provide electricity and hot-water (displacing Cage steam from the steam

distribution system during winter-heating months).

Cage Cogeneration Plant

Based on the information provided, a Cage Cogeneration Plant would include a nominal

3.5 MWE gas turbine generator (GTG) with a low-emissions combustion system, and a duct-


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fired single-pressure heat recovery steam generator (HRSG) capable of producing about 19,000

lb/hr of steam unfired, and up to about 50,000 lb/hr when duct-fired the HRSG when needed. In

practice, based on the UVM annual steam load profile, the HRSG would be fired year-round.

The gas supply to the Cage would require improvements (by Vermont Gas) to ensure

sufficient volumes of natural gas were available to serve the GTG, the HRSG and the existing

Cage boilers. Ideally, the gas supply to the GTG itself would be at as high a supply pressure

possible to minimize cogeneration plant auxiliary power losses associated with the electric-

motor driven natural gas compressor required for supplying fuel to the GTG at high enough

pressure.

The electrical interconnections to the existing 11 buildings would utilize the 13.8 kV

distribution feeders that UVM has recently commenced installing, plus additional UVM-

installed feeders and system upgrades to ensure a robust electrical system. A capacity upgrade

to the existing BED 13.8 kV feeder to the Cage 13.8 kV system will most likely be required, to

ensure that the 11 buildings can continue to be served electrically via BED supply when the

cogeneration plant is shut down for maintenance.

The estimated cost for year-2013 for the above-discussed Cage Cogeneration system and

UVM-internal electrical system upgrades (but not Vermont Gas or BED upgrades) is in the

order of $18.65 million. A new gas-fired boiler system (roughly $2.9 million) is under

consideration in lieu of the cogeneration system. Installing cogeneration would avoid this boiler

upgrade cost, resulting in a net cogeneration plant cost in the order of $15.7 million.

A 1st-year annual-savings / simple-payback analysis similar to that used for the other

renewable energy opportunities in this study was conducted, for a range of fuel gas prices

($5.00, $7.50, $10.00 and $12.85/mmbtu) and electricity prices (12.1 and 15.0 c/kW.hr), as follows.


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1st-Year Annual Savings; Simple Payback Analysis Gas Price $/mmbtu 5.00 5.00 7.50 7.50 10.00 10.00 12.85 12.85 Avoided Electricity Price c/kW.hr 12.1 15.0 12.1 15.0 12.1 15.0 12.1 15.0 Net Installed Cost $mm 15.7 15.7 15.7 15.7 15.7 15.7 15.7 15.7 Savings $mm

Electrical Cost Savings $mm 3.6 4.4 3.6 4.4 3.6 4.4 3.6 4.4 Thermal (Boiler) Fuel

Savings $mm 2.8 2.8 4.1 4.1 5.5 5.5 7.1 7.1

Total Savings $mm 6.3 7.2 7.7 8.6 9.1 10.0 10.7 11.5 Costs $mm

Fuel Cost $mm 3.5 3.5 5.3 5.3 7.0 7.0 9.0 9.0 O&M Cost $mm - GTG/HRSG/GComp $mm 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 - Add'tl Staffing $mm 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 - Consumables $mm 0.13 0.13 0.13 0.13 0.13 0.13 0.13 0.13 BED Standby Charges $mm 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Total Costs $mm 4.2 4.2 5.9 5.9 7.7 7.7 9.7 9.7 Annual Savings $mm 2.2 3.0 1.8 2.7 1.4 2.3 1.0 1.9 Simple Payback Years 7 5 9 6 11 7 15 8

In addition, A 20-year present-worth and break-even point analysis, similar to that

presented in the 2006 WMG study was conducted based on the net cogeneration project cost,

performance and fuel consumption; electrical cost savings; Cage fuel gas savings; and nominal

O&M costs; for the same range of natural gas prices and electricity prices, using the same

discount and escalation factors as that study.

Present-Worth; Break-Even Point Analysis (similar to WMG 2006 Cogeneration Study) Gas Price $/mmbtu 5.00 5.00 7.50 7.50 10.00 10.00 12.85 12.85

Electricity Price c/kW.hr 12.1 15.0 12.1 15.0 12.1 15.0 12.1 15.0

1st-Year Annual Savings $mm 2.18 3.04 1.81 2.67 1.44 2.30 1.02 1.88

20-Year Present Worth $mm 15.5 30.6 9.0 24.1 2.5 17.6 -4.9 10.2

Break-Even Point Years 10 7 13 8 17 9 N/A 12

Either method of economic analysis reveals that despite the smaller cogeneration plant

size (compared to the WMG-2006 study) and despite the increase in costs over the past 7 years,


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the potential payback and present worth of a Cage 3.5 MW cogeneration plant appears to be

favorable for those scenarios where gas prices are in the $5.00 to $10.00/mmbtu range and

where BED electricity prices are near to or higher than current pricing. Further examination of

this cogeneration opportunity may be warranted.

University Heights Cogeneration

The 250 kW University Heights electrical load is quite modest compared to the above

Cage cogeneration configuration, however it appears to be relatively steady year-round.

Installing a complex and expensive steam plant based on heat recovery from a 250 kW electrical

generator at this location is impractical, so hot-water heating was selected as the thermal energy

output, recognizing that it would only be needed for about 50% of the year.

Several equipment configurations were examined, including 65 and 200 kW gas-fired

Capstone microturbine generators with hot-water heat recovery; a 250 kW gas reciprocating

engine generator with hot-water heat recovery; and for interest and comparisons sake, a 400 kW

(too big) UTC 400 Fuel Cell system with hot-water heat recovery and Bloom Energy 100 kW and

200 kW fuel cell systems without heat recovery. Capital cost estimates range from about $0.43

million for the smallest Capstone C65 system to $2.0 million for the UTC 400 fuel cell system.

A simple economic analysis (payback period) was conducted based on the equipment

cost, performance and fuel consumption; electrical cost savings; thermal fuel savings (i.e. fuel

saved at the Cage plant); and nominal O&M costs, for a range of fuel gas prices and electricity

prices.

The general conclusions of the University Heights preliminary cogeneration plant analysis

indicate that only for the scenario with a low gas price and high avoided electricity cost:

• Small microturbines (65 or 200 kW) with heat recovery are a good candidate (nominal 8

year payback) to offset the electrical loads and a good portion of the hot-water heating


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loads during the heating season.

• On paper, the Bloom Energy 100 or 200 kW fuel cells are reasonable candidates (9~13

year payback), but they cannot provide hot-water (heat recovery) and thus are not really

cogeneration units and do not offset Cage fuel costs. On paper, the 400 kW UTC fuel

cells with hot-water heat recovery have a better payback, but in reality they are too big

for the University Heights electrical load.

• A reciprocating engine generator with hot-water heat recovery is a good candidate

(nominal 6 year payback) but it would be much larger and nosier than the small

microturbine installations.

For the high-gas price / current electricity price cost scenario, none of the above-discussed

University Heights cogeneration and alternate configurations indicate a good payback potential

(i.e. dozens of years).

5. FUEL CELLS

CHA investigated the potential installation and utilization of fuel cells around the UVM

campus. The study looked at two different types of fuel cells: solid-oxide fuel cells (SOFC) and

proton exchange membrane (PEM) fuel cells. Detailed descriptions of these cell types, and the

specific units that were examined, can be found in the Fuel Cell section of the report. After a

simplified economic analysis, CHA concluded that on the UVM campus there is not a beneficial

opportunity for fuel cell installation.

Out of the two fuel cell types, CHA found that, theoretically, the UTC 400 model would

be more beneficial for UVM. Its lower installed cost and combined heat and power (CHP)

benefits are appealing. Under ideal economic conditions (5.00 gas and 15.0 c/kW.hr), the UTC

400 Fuel Cell cogeneration (with CHP) unit would be reasonable. However, since the heating

plant already produces and distributes steam to provide heat, there is no need for CHP,

rendering the cells’ heat-recovering ability nearly financially neutral at most high electrical load


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sites. Therefore, the payback period would be longer without the recovery of the heat

byproduct of the fuel cell unit.

In conclusion, CHA found that, unless under ideal conditions, including future grants

and funding, installing either type of fuel cell is not a viable option at the present time. Since

there are currently no grants available to fund fuel cell installation costs, the payback period is

too long to make utilizing fuel cells financially reasonable. However, if there were funding

available, UVM would be a great candidate to participate in a fuel cell pilot program.

6. GEOTHERMAL

CHA research on the addition of geothermal energy to UVM’s campus identified a

number of good opportunities to implement ground source heat pumps to augment heating

and cooling of UVM buildings. Due to the lack of available data on site specific heating and

cooling infrastructure, conclusions and economic feasibility were limited to a conceptual level.

Feasibility study analysis for geothermal energy focused on hybrid ground-source heat pumps

with vertical wells augmenting natural gas hydronic heating systems with cooling. This was for

two primary reasons: this is generally the most cost-effective way to add geothermal to a

building, and for the UVM sites considered, it required less modification to existing building

systems.

Sites were considered based on their existing heating and cooling setup, and available

space for geothermal wells. First, sites within the central heating & cooling system were

eliminated. Secondly, a survey was completed for area suitable for wells. Prior to project

development, test wells should be drilled and analyzed to ensure proper geothermal design.

The survey yielded the following sites as good candidates:

On Trinity Campus: the “Back Five” residence halls, Mercy Hall, McAuley Hall, and

Mann Hall. Additionally, the Blundell House, 284 East Avenue (UVM Rescue/Police

Services/Physical Plant), and Waterman Building. Of the eleven sites evaluated, the “Back Five”,


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Mercy Hall, and McAuley Hall were the most appealing due to their impending HVAC

upgrade/replacement needs. The “Back Five” are currently served by electric baseboard heat,

which is inefficient and now a much more expensive method for space heating. Mercy Hall and

McAuley Hall are heated by two hydronic natural gas boilers which are slated for replacement

in the near future.

The recommended geothermal setup for each site is a high efficiency hydronic natural

gas boiler, augmented by geothermal ground-source heat pumps and ground source cooling.

Conceptual estimates put installed costs for geothermal heating and cooling at $10-$15/sq.ft.

more than traditional heating and cooling for large residential buildings. Savings are typically

in the 10-30% range with paybacks often being achieved in the 15 to 20 year range.

In conclusion, CHA recommends further investigation into geothermal heating and

cooling at the eleven sites mentioned above. In particular, we identify the “Back Five” as an

excellent candidate. Greater savings and shorter payback terms are realized with the “Back

Five” since they currently utilize electric heat.

7. SOLAR THERMAL

Solar thermal feasibility investigation for UVM focused on opportunities to add solar

heating to domestic hot water systems on campus. CHA found excellent state incentive

programs, a handful of good candidate sites, and a number of challenges to overcome when

developing solar thermal on campus.

For the purposes of this study, CHA focused on buildings that have demand for hot-

water year round. These buildings were then cross referenced with the solar PV sites to ensure

solar potential and roof space. Those identified to be best candidates were Marsh, Austin, and

Tupper Halls, Living/Learning D, University Heights, and both the Harris/Millis Commons and

Simpson Hall dining facilities. Of those buildings, the University Heights residential complex is

one of the most favorable given the overall size of the facility and its comparatively large energy


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consumption. Additional information is needed on each building’s existing hot water setup in

order to confirm cost estimates and savings.

Two technologies for solar thermal collectors are common for domestic hot water

applications, evacuated tubes and flat plate collectors. An evaluation of each technology

yielded flat plate collectors as the better choice for domestic water heating in Vermont. Flat

plate collectors are less expensive and more durable and on average perform better than

evacuated tubes at lower average ambient temperatures (such as Vermont’s climate.)

The State of Vermont offers a number of incentive programs for solar thermal hot water

installations. The ‘Vermont Small-Scale Renewable Energy Incentive Program’ funds a

maximum of $45,000 or 50% of the total project costs, whichever is less. The state offers a

number of other incentives for solar water projects, however these are generally geared towards

residential installations via tax incentives and are therefore not likely applicable to the

University, unless the savings are passed along through a local vendor who is eligible to receive

the credits.

The domestic water heating for many of the buildings at UVM is provided by a central

steam plant. A hybrid domestic water heating system which combines the available steam with

the renewable aspect of solar collectors is mechanically possible but economically less

appealing. With a steam/solar hybrid system, this water heating setup will consume less steam

from the central plan than an all-steam system. This amount of steam can be estimated, and it

would likely result in very small decrease in overall amount of steam produced by the central

plant. Compared to a solar thermal setup where solar is augmented by a natural gas or electrical

water heater, the steam/solar hybrid system is around 25% more expensive due to the

additional costs of the storage tank, heat exchangers and controls required and the resulting

increased labor and engineering costs. Furthermore, the cost of producing hot water via the

central steam system is less expensive than heating hot water via gas or electricity. So in

conclusion, the system would be more costly and result in lower bottom line savings and


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increase payback term. We would recommend focusing any solar thermal projects to buildings

that do not get their hot water via central steam system.

Implementing solar thermal for domestic water heating is a worthwhile pursuit for

UVM, provided the following are considered. It is essential that projects be selected at sites that

have hot water demand in the summer. We have identified buildings that in 2012 have summer

hot water demand, but future demand could change and should be re-evaluated prior to

developing a project. Furthermore, projects which add solar thermal to buildings which do not

get their hot water from the central steam system will present more appealing project

economics.

8. WIND ENERGY

CHA researched the installation of wind turbine generators (WTG) on UVM campus.

The study focused on two types of WTG: “small” and “micro” wind turbines. The sites

considered were fields surrounding the MRF and Bio-Research Complexes, the area west of

Living and Learning, west of Bailey-Howe and in Centennial Woods Nature Area. Our research

identified small wind turbines to be feasible in a few locations, but concluded that micro

turbines were not feasible.

For small turbines, the basis of this study was the 100 kW Northwind 100 Turbine

manufactured by Northern Power Systems in Vermont. The turbine stands approximately 130’

tall at hub height with a rotor of 75’. For micro turbines, a number of models were compared in

order to select the best of technologies. While some of the turbines were promising, the project

payback of micro turbines was found to be excessive. The payback periods for micro turbines

are rarely less than 20 years in class 2 and 3 wind speeds (higher than those at UVM).

Installation of micro turbines on buildings was considered not feasible based on structural

concerns in addition to long payback periods.

Sites for small turbines were selected based on open space. In order to take into

consideration the proper precautions, all WTG’s should be sited so that in the event of a tower


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fall there would be no buildings or critical infrastructure damaged. Potential sites were

identified around MRF and the Bio Research Complexes and in Centennial Woods Natural

Area. For micro turbines, any open space on campus was considered, and would be narrowed

down after completion of wind mapping. Wind reports were run at nine locations around

campus to account for any potential wind differences between locations.

Nine locations were mapped for wind speed. All nine locations were found to be

category 1 wind at 30m height. In category 1, the average wind speed is below 11.6 mph. The

location south of the Miller Farm had the highest average wind speed of 10.9 mph and

Centennial Woods had the lowest at 9.8 mph. Low average wind speeds would result in energy

output of the turbine being very low and the project economics being unfavorable.

There are several incentives for installing small wind turbines in the State of Vermont.

The Small Scale Renewable Energy Incentive Program grants $1.20 per kWh produced by the

wind turbine with a maximum incentive of $455,000. Under this program, a Northwind 100

Turbine would be feasible to install near the Miller Farm. Based on CHA experience designing

projects with this turbine, an economic analysis was performed. The overall project cost would

be around $640,000 with a payback period of around 18 years. The turbine would be

interconnected and net metered at the Farm’s main service and offset 25-35% of the site’s power

needs.

CONCLUSIONS

In summary, CHA identified a number of good opportunities for renewable

energy development on UVM campus. Some technologies exhibited better feasibility conditions

than others due to siting conditions, economies of scale, incentives, commodity prices, and

other factors. Detailed analyses and recommendations are provided in the attached

comprehensive report and appendices.

executive summary of uvm comprehensive campus renewable energy feasibility study

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