HomeMy WebLinkAboutagenda.council.worksession.20130122
CITY COUNCIL WORK SESSION
January 22, 2013
4:00 PM, City Council Chambers
MEETING AGENDA
I. Renewable Energy Options
MEMORANDUM
TO: Mayor and City Council
FROM: Will Dolan, Project Coordinator
THRU: David Hornbacher, Director of Utilities & Environmental
Initiatives
DATE OF MEMO: January 17th, 2013
MEETING DATE: January 22nd, 2013
RE: Renewable Energy Alternatives Work Session I
REQUEST OF COUNCIL: This meeting represents the first work session discussing Aspen’s
renewable energy future. During this initial session, staff will present City Council with a broad
overview of Aspen’s current progress towards the 100% renewable energy commitment, and
provide preliminary concepts to fully reach the goal. The overall objective of this work session
will be to provide Council with the knowledge to make an informed decision in selecting a
focused “short list” of alternatives for detailed analysis by staff.
At a subsequent Council work session, staff will present the in-depth results of the “short list”
analysis, and seek council’s direction and support to pursue renewable energy alternatives
selected to fulfill the goal of a 100% renewable City of Aspen Electric Utility. .
PREVIOUS COUNCIL ACTION: In 2005, the City adopted the innovative Canary Initiative,
identifying Aspen and other mountain communities as the “canaries in the coal mine”,
representing our heightened sensitivity to the deleterious effects of global warming. The overall
goal of the Canary Initiative is to aggressively reduce Aspen’s carbon footprint and contribution
to global warming pollution.
In May 2007, City Council adopted the Climate Action Plan. A central component of the
Climate Action Plan is to “Meet all growth in electricity demand since 2004 with new, zero-
carbon dioxide sources of electricity with an end goal of 100% renewable energy by 2015.”1
In November of 2007, the community authorized municipal bonding for the purposes of
completing the Castle Creek Energy Center (CCEC), a local hydroelectric project which would
add approximately 8% to Aspen’s renewable energy portfolio.
In August of 2012, Council approved the purchase of around 9.8 million kWh/yr. of new
renewable energy from the forthcoming Ridgway hydroelectric power plant, bringing the City’s
electric utility to 89% renewable by late 2013.
1 City of Aspen Canary Initiative, Climate Action Plan, 2007, Introduction (p. 28)
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In October of 2012, Council approved final ballot language for the advisory ballot question
asking residents whether they approve or disapprove of continuing the ongoing Castle Creek
Energy Center (CCEC) project. On November 6th, 2012, 1956 residents voted ‘yes’, and 2063
voted ‘no’ to completion of the CCEC.
BACKGROUND: Since the early 1970s, City leadership has emphasized the development of
local renewable energy. Since then, myriad feasibility studies have been commissioned,
resulting in several completed renewable energy projects—most notably, hydroelectricity plants
at Ruedi Reservoir, Ridgway Reservoir, and Maroon Creek, and solar PV at the water plant. In
addition, the City has increased its purchases of renewable energy (both hydro and wind) through
its energy provider, MEAN. Collectively, these actions have made Aspen’s electric utility a
leader in integrating renewable energy into its electric portfolio.
In addition, the City has invested approximately $7 million developing the CCEC and related
infrastructure,2 with a remaining investment of about $3.5 million to bring the plant online.3 The
CCEC would add an estimated 5.5 million kWh/yr. of new renewable energy—bringing Aspen’s
electric utility to approximately 97% renewable.
DISCUSSION: Quantitatively, Aspen’s electric utility must still replace about 8.5 million
kWh/yr. of fossil-fuel energy with new renewable energy in the next 2 years in order to meet its
Canary Action Plan commitment.4
One of the primary means by which to meet our goal is the continuation of existing conservation
and efficiency programs, as well as the creation of new, more impactful policies and programs to
2 This figure includes the completed cost of the dual-purpose drain line from Thomas Reservoir
3 This includes completion of the drainline’s outfall, which must be built to make the emergency drainline fully
functional as a safety component for Thomas Reservoir.
4 This number is based on 2015 consumption projections, and includes the ~9.8 million kWh/yr. of Ridgway energy
that will come online around January, 2014. It does not include the ~5.5 million kWh/yr. that would be provided
by the CCEC.
0
10,000,000
20,000,000
30,000,000
40,000,000
50,000,000
60,000,000
70,000,000
80,000,000
Renewables, Consumption and Emissions
Renewables (kWh) Consumption (kWh) CO2 Emissions (lbs)
[~8,500,000 kWh/yr]
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bolster their effectiveness. Conservation and efficiency are not specifically discussed in this
memo seeing as they are not technically “new renewable energy resources”, but they remain key
components in achieving our future energy goals.
MEAN Contract
The wholesale electric energy contract with MEAN specifies the options available for the City to
increase its renewable energy portfolio. Specifically, the contract allows for a total of
approximately 8.2 million kWh/yr. of renewable energy not purchased directly through MEAN.
Of this total, 6.7 million kWh/yr. must be hydroelectric, and about 1.5 million kWh/yr. can come
from other “behind the meter” renewable energy sources (i.e., solar, geothermal, biomass, etc.).5
“Other” technologies will play important, but ancillary roles, in the fulfillment of the
community’s 100% renewable energy goal.
Even if Aspen were successful in fully developing all of the contract’s renewable energy
allowances (~8.2 million kWh/yr.), the City would still face a shortfall (based on total remaining
fossil-fuel power of ~8.5 million kWh/yr.), which would need to be satisfied with additional
purchases through MEAN.6 Through natural growth of the customer base and use over time, the
shortfall could continue to grow, ad infinitum. More aggressive efficiency and conservation
measures—including supportive regulation and policies—may need to be developed to manage
or reduce future electric load growth.
The following is a brief overview of renewable energy technologies and their general potential to
get us to 100%:
Hydro
As a result of the CCEC project, the City owns valuable hydroelectric equipment—a turbine,
generator, and related controls. Purchased for about $1.6 million, this equipment could be used
locally or in a new hydro partnership. Or, alternatively, it could be sold (preliminary estimates
show a sales price of about 35% of the original purchase price). Several opportunities exist for
new hydro partnerships in other parts of the state, but it remains to be seen how feasible any of
these alternatives are—both from a cost standpoint, and a power provider standpoint (i.e.,
amenable to MEAN). There is also a possibility that the City would be able to purchase some or
all of the summer Ridgway output from Tri-State, but there have been no discussions to confirm
this.
In addition to the traditional high-head penstock model, there is also potential for local low-head
and run-of-river hydro. However, while these methods produce reliable power and protect water
rights, their aggregated potential capacity is too small to make a sizeable dent in the remaining
11% renewable energy shortfall. In addition, these models are very expensive from a $/kWh
perspective, and do not provide attractive payback periods.
Wind
There is no contractual limit on the amount of wind the City of Aspen can purchase from
MEAN. As such, the City can meet all its new renewable energy needs through additional wind
5 This “other” allowance is based on 2% of Aspen’s total demand
6 This shortfall would continue to grow, based on the projected consumption growth rate of ~1%/yr; it could be
filled by wind, or possibly landfill gas, depending on availability.
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purchases from MEAN, but at a significant added cost. Any additional wind purchases from
MEAN will result in monthly excesses, of which MEAN will charge us $0.10/kWh (represented
by the grey portions of the bar graph below). These penalty charges alone could add up to $
millions/yr., not including the cost of the wind energy that Aspen can actually use. The
following graph shows what this option would look like:
It should also be noted that future O&M and replacement costs, as well as the elimination of
wind attributes’ availability, will drive the cost of wind energy higher into the future.
Solar
The two primary barriers to additional solar installations in Aspen are: 1) the high cost of the
technology; and 2) the high cost of land in the upper Roaring Fork Valley (solar arrays require a
lot of space). Accordingly, the most attractive prospective projects are those using City-owned
property (land or rooftop). However, even with land cost stripped out, solar is still expensive
relative to other renewable technologies.7
However, pursuing additional solar installations in Aspen remains attractive for a variety of
reasons, among them:
• Offers local renewable energy production
• Variety of financing and operations models
• The City of Aspen has experience with construction and operations of Solar installations
7 The City’s 92kW solar array at the water plant cost $451,653 to build, which equates to an installed cost of
$4909/kW.
-4,000,000 kWh
-3,000,000 kWh
-2,000,000 kWh
-1,000,000 kWh
0 kWh
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6,000,000 kWh
7,000,000 kWh
8,000,000 kWh
9,000,000 kWh All Wind (2015)
WAPA RUEDI MAROON CR WIND RIDGWAY NEW WIND EXCESS WIND
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Additional solar installations on City rooftops is feasible, but their aggregated production
potential is very limited (<280kW).8 Non City-owned sites, such as Obermeyer Place, have been
studied as well; however, they require leasing of the roof space at a high cost, which makes these
projects non-starters.
Thus, to make utility-scale solar tenable in Aspen, it would require the use, acquisition, or lease,
of vacant land for free or at a very low cost. It is likely that most of the good sites would require
us to wheel the power briefly through Holy Cross’s distribution system to get it onto Aspen’s
grid, adding slightly to the unit cost of the energy, and potentially disqualifying these projects
due to MEAN’s “behind the meter” requirement. Partnerships with area landowners are a
possibility, whereby the City finances 100% of the installation of the system on non-City land (in
lieu of lease payments), and the landowner gets credited for a portion of the power created at the
solar installation.9
Lastly, the community garden solar model—such as installed at the Garfield County Airport—
might provide local renewable energy opportunities, but again at a small scale, with the benefits
and disadvantages provided by a lease model.
Biomass 10
Biomass energy generation consists of several different technologies, applications, and fuel
sources. Wood and landfill waste are the primary biomass fuel sources available to us in
Aspen—the former because wood waste products are abundant in this region of Colorado, and
the latter because of MEAN’s existing investments in landfill gas energy.
Today, much woody biomass waste is disposed of either by burning or by allowing it to
decompose. Either way, its stored carbon is released into the atmosphere. Using biomass for
energy doesn’t prevent this emission, but it does enable the production of energy that can offset
carbon emissions from fossil fuel sources elsewhere.
Given the relatively small wood biomass supply [available in the Valley], the most successful
local project(s) would likely be for the production of heat, not electricity. However, the potential
exists for landfill gas biomass purchases through MEAN in the future, but that project is not yet
on-line, and it is uncertain whether or not MEAN will offer this energy on a per-subscriber basis.
Geothermal
Like biomass, the potential for geothermal technology in Aspen is primarily for heating purposes
(i.e., it would offset natural gas use, not electricity use). Unless the City is prepared to drill to
sufficient depths (~4km) in order to reach sufficient ground temperatures (provided they even
exist locally), geothermal electricity production is not a likely energy source in Aspen. The City
has drilled a test well to 1000ft, but has not yet reached sufficient temperatures for either. It
remains to be seen what geothermal potential exists underneath Aspen. Moreover, a geothermal
power plant in the heart of Aspen would likely frustrate many in the community.
8 Sites include: Red and Yellow Brick buildings (45kW each), the Golf Course cart shack (25kW), City Hall (6kW), and
Burlingame Phase II (134 kW).
9 The Aspen Sanitation District has voiced interest in installing a PV array on their campus, but the energy was to
be used for powering the wastewater treatment plant (which is on the Holy Cross grid).
10 The majority of this section is excerpted from the Roaring Fork Biomass Consortium’s 2011 “Biomass Feasibility
Study for the Roaring Fork Valley”
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Again, staff believes that any of these alternatives must be pursued concurrent with more
aggressive, policy-based (including regulatory) approaches to energy conservation and
efficiency.
FINANCIAL/BUDGET IMPACTS: Each alternative technology listed above has a different
financial impact. Until further direction is given, staff will refrain from expending the resources
necessary to derive fine-tuned costs associated with specific applications of these technologies
(i.e., conduct formal feasibility studies). However, national averages give some preliminary
basis for comparison (see Table 1, attached).
ENVIRONMENTAL IMPACTS: Achieving Aspen’s renewable energy goals will make
Aspen’s electrical utility carbon neutral, and make the City an environmental leader. Moreover,
it will significantly reduce our contribution to GHG emissions, as well as provide an example for
other cities to follow.
RECOMMENDED ACTION: Staff is requesting Council’s direction to further analyze new
renewable alternatives, with the goal of presenting them to Council at a later date. Ideally,
specific direction will be given to staff with regard to which projects and alternatives are to be
pursued.
ALTERNATIVES:
1. Continue with existing contracts and project commitments and fall short of our renewable
goals (~89% renewable with Ridgway on line in 2014);
2. Redefine the Canary Action Plan timeline, pushing our renewable energy deadline back
by several years (e.g., from 2015 to 2020).
CITY MANAGER COMMENTS:
ATTACHMENTS: Estimated Levelized Cost of New Generation Resources
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Table 1. Estimated Levelized Cost of New Generation Resources
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2013
Analysis of Renewable Energy Alternatives - Overview
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Table of Contents
I. INTRODUCTION ......................................................................................................................................... 5
A. PURPOSE AND INTENT ................................................................................................................. 5
B. BACKGROUND .............................................................................................................................. 5
i. Overview of Past Studies ................................................................................................. 7
ii. Canary Initiative Goals .................................................................................................... 8
C. PAST AND CURRENT ACTIONS ..................................................................................................... 9
i. Demand-side Management ........................................................................................... 10
ii. Supply-side Management ............................................................................................. 11
D. CONTRACTUAL CONSTRAINTS (MEAN PPA) .............................................................................. 11
II. ALTERNATIVE ENERGY SOURCES .......................................................................................................... 14
A. HYDROPOWER ........................................................................................................................... 14
i. Conventional Hydro ....................................................................................................... 15
b. New Partnership(s) ......................................................................................... 15
a. Ridgway ............................................................................................................ 16
ii. Micro Hydro ................................................................................................................. 17
a. Run-of-River (ROR) Model ............................................................................... 17
b. Low Head ......................................................................................................... 19
c. Inline ................................................................................................................. 21
iii. Improvements to Existing Hydro Facilities ................................................................... 22
B. WIND ......................................................................................................................................... 25
i. Additional MEAN Purchases .......................................................................................... 25
C. SOLAR ......................................................................................................................................... 26
i. Ownership Model........................................................................................................... 27
iii. “Solar Garden” Model .................................................................................................. 28
D. GEOTHERMAL ............................................................................................................................ 29
i. Ground Source Heating and Cooling .............................................................................. 29
E. BIOMASS .................................................................................................................................... 30
i. Wood .............................................................................................................................. 30
ii. Landfill Gas (MEAN) ...................................................................................................... 31
III. RENEWABLE ENERGY CERTIFICATES (RECs) .......................................................................................... 31
A. CONFORMANCE TO CANARY GOALS ......................................................................................... 32
V. GENERIC COST COMPARISON ................................................................................................................ 32
VI. CONCLUSION ......................................................................................................................................... 33
A. DIRECTION AND NEXT STEPS ..................................................................................................... 33
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I. INTRODUCTION
A. PURPOSE AND ASSUMPTIONS
The purpose of this overview is to outline the various renewable energy technologies available to the
City of Aspen, as well as to provide staff’s preliminary take on the potential of each. Accordingly, the
intention here is to provide Council with the knowledge necessary to continue to move us towards the
City of Aspen’s Canary Initiative goal of 100% renewable energy by 2015.
This report assumes that a continued emphasis on energy conservation and efficiency programs is
essential to reaching this goal. The fact that this report focuses on “new renewable energy sources” in
no way implies that efficiency and conservation measures are less important or impactful. To the
contrary, if buttressed by a supportive policy framework, conservation and efficiency can go a long way
towards closing our remaining fossil-fuel energy gap. Reaching our renewable energy goal will require
both new renewable sources and new conservation and efficiency gains.
Lastly, this report makes no assumptions regarding Council’s future decisions on the fate of the Castle
Creek Energy Center (CCEC). Due to ballot initiative 2C’s advisory status, Council alone reserves the
right to make those decisions—whatever they may be.
B. BACKGROUND
Aspen Electric is a municipally owned electric utility serving 991 commercial and 1,899 residential
accounts in a four-square-mile service area.
Figure 1: Aspen Electric’s Service Territory1
Aspen Electric generates electricity through two municipally-owned hydroelectric power plants—one at
Reudi Reservoir and one on Maroon Creek—as well as a 92kW solar array at the water plant. The utility
purchases the balance of its power wholesale from the Municipal Energy Association of Nebraska
(MEAN), along with a small amount of hydropower purchased from the Western Area Power
Administration (WAPA).
Figure 2: Aspen’s 2014 Energy Portfolio by Source2
1 The Aspen Recreation Center (ARC) and the Burlingame affordable housing development are also covered by
Aspen Electric, despite not being on this map. The water plant is also scheduled to be added within the year.
2 Actual wind percentage is higher, due to the 4% wind component of “MEAN”
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The orange “MEAN” and turquoise “Support” slices are dominantly (>87%) carbon-based, and are thus
the sources we aim to replace with renewable energy.3 The following pie chart is a breakdown of the
orange “MEAN” slice:
Figure 3: Current MEAN Resource Mix
MEAN’s resource mix does change from year to year, but the proportion of renewable energy does not
fluctuate greatly.4
The total power consumption for Aspen Electric grew from 63,663,922 kWh in 2001 to 71,704,818 kWh
in 2011. This represents annualized consumption growth of around 1.1%/yr. Over the same period, the
total greenhouse gas emissions (GHGs) attributable to Aspen Electric fell from 59,918,005 lbs to
3“Support” energy is nearly 100% fossil-fuel based.
4 Nuclear is not considered a renewable resource due to the finite nature of radioactive fuel sources
Ruedi
26%
Maroon
Creek
3%
Wind
29%
WAPA
10% Support
3%
MEAN
15%
Ridgway
14%
Aspen Energy Mix (2014)
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34,834,403 lbs, or about -4.7%/yr. These inverse trends are due to the marked reduction Aspen
Electric’s carbon factor during this time—from 0.94 lbs CO2/kWh to 0.47 lbs CO2/kWh—which was
caused by marginal increases in hydro production and purchases,5 as well as dramatic increases in wind
energy purchases between 2001 to 2011.6 Over the past decade, renewable energy has grown at a
~3.6% annualized rate.
Figure 4: Tracking the 10-Year Trends in Consumption, Renewables, and GHG Emissions
i. Overview of Past Studies
Since 1974, the City of Aspen has been actively researching and pursuing renewable alternatives
to reduce the proportion of fossil fuels in Aspen Electric’s energy portfolio, increase energy
security, and stabilize electricity rates. The following is a list of renewable energy studies
commissioned and/or used by the City:
Figure 5: Past Renewable Energy Feasibility Studies
Year Consulting Party Renewable Energy Type
1974 Merrick & Co. Hydroelectric
1974 Rea, Cassens & Assoc. Hydroelectric
1984 MEAN 7 Hydroelectric
1995 CORE 8 Hydroelectric
1995 Enartech, Inc. Hydroelectric
1996 Fuller Consulting Hydroelectric
1997 RWAPA9 Hydroelectric
1997-98 NCWCD10 Hydroelectric
1998 CORE Wind
5 Ruedi production increased by ~2.8 million kWh/yr., and WAPA purchases increased by ~2 million kWh/yr.
compared to 2001.
6 Wind purchases increased from ~2.0 million kWh/yr. in 2001 to ~20.3 million kWh/yr. in 2011
7 Municipal Energy Association of Nebraska
8 Community Office for Resource Efficiency
9 Ruedi Water And Power Authority
10 Northern Colorado Water Conservation District
0
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Renewables, Consumption and Emissions
Renewables (kWh) Consumption (kWh) CO2 Emissions (lbs)
[~8,500,000 kWh/yr]
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2002-03 MEAN Hydroelectric
2004-05 CRWCD 11 Hydroelectric
2007 Canyon Engineering, Inc. Hydroelectric
2007 Integra Engineering Efficiency
2007-09 McLaughlin Water Engineers,
Ltd.
Micro-Hydro
2008 SAIC 12 Geothermal
2009 Sopris Engineering, LLC Micro-Hydro
2010 CEC 13 Solar
2001-11 TCWCD 14 Hydroelectric
2011 RFBC 15 Biomass
2012 Zancanella & Associates Hydroelectric
During this decades-long process, there has been an overarching goal to prioritize local,
ownership-model renewable energy development over non-local, leased/purchased energy.
The advantages of locally owned renewable energy projects are manifold, the obvious two being
long-term rate stability and enhanced long-term energy security. The prevalence of
hydroelectric studies is a product of Aspen’s comparative advantages when it comes to
hydropower (i.e., topography, hydrology, etc.). In other words, it has proven to be Aspen’s most
reliable and available source of local renewable energy.
ii. Canary Initiative Goals
“In 2005, the City adopted the ambitious Canary Initiative that identifies Aspen and other
mountain communities as the canary in the coal mine for global warming. The goal is to
aggressively reduce Aspen’s carbon footprint…and to contribute to global reduction of global
warming pollution.” 16 In May 2007, Aspen’s City Council adopted the Climate Action Plan, which
calls for a reduction in community-wide greenhouse gas emissions of 30% by 2020 and 80% by
2050, below the 2004 community-wide baseline.
A central component of the Climate Action Plan is to “Meet all growth in electricity demand
since 2004 with new, zero-carbon dioxide sources of electricity with an end goal of 100%
renewable energy by 2015.”17
Quantitatively, this means that Aspen’s electric utility must replace ~8.5 million kWh of fossil-
fuel energy with new renewable energy in the next 2 years.18 This number will increase (or
possibly decrease) based on the future growth rate (or rate of decline) in consumption.
C. PAST/CURRENT ACTIONS
Aspen Electric has adopted a two-pronged approach to achieving 100% renewable energy by 2015:
1) Demand-side management: efficiency and conservation approaches; and
11 Colorado River Water Conservation District
12 Science Application International Corporation
13 Community Energy Collective
14 Tri-County Water Conservancy District
15 The Roaring Fork Biomass Consortium
16 City of Aspen Canary Initiative, Climate Action Plan, 2007, Introduction
17 Id., p. 28
18 This number is based on 2012 consumption, and includes the ~9.8 million kWh/yr. of Ridgway energy that will
come online at the end of 2013; it does not include the ~5.5 million kWh/yr. that would be provided by the CCEC.
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2) Supply-side management: increasing renewable energy through increased local generation
and wholesale electricity purchases.
This overview offers as a basic premise that the best way to reach 100% is through a simultaneous
pursuit of both demand- and supply-side approaches. When achieved, this goal is only sustainable if
long-term demand growth is managed concurrently. As of 2012, Aspen Electric generated or purchased
about 75% of its power from renewable, non-carbon sources. However, there’s more to it than just
adding more kWhs of renewable energy. Any tenable solution to this challenge must also conform to
the consumption curve, shown here:
Figure 6: Aspen Monthly Consumption Curve (2015)
As you can see, peak load occurs in January, whereas lowest load is during the month of May. Any new
sources added to Aspen Electric’s existing portfolio should conform to this general pattern, lest the
City—and its ratepayers—foot the bill for unusable, excess energy.
Non-base load sources of energy, such as wind and solar, often do not conform to this demand curve
because their production can fluctuate so dramatically. For example, since wind energy is purchased in
blocks and spread across each month of the year, additional wind purchases would result in excess,
unusable energy during most months of the year.
i. Demand-S ide Management
Aspen Electric is undertaking a host of measures to reduce consumer demand including:
• Economic disincentives applied via expanded tiered electric rates, ensuring that the
consumers who use the most electricity pay the highest marginal rates per kilowatt hour;
• Rebates for free energy audits when the customer undertakes residential energy efficiency
improvements;19
• Affordable housing retrofits and efficiency programs;20
19 Including lighting, air-sealing and insulation, HVAC, controls, smart technology, pumps and motors.
0 kWh
1,000,000 kWh
2,000,000 kWh
3,000,000 kWh
4,000,000 kWh
5,000,000 kWh
6,000,000 kWh
7,000,000 kWh
8,000,000 kWh
9,000,000 kWh
Aspen Energy Consumption (2015)
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• Hotel efficiency competition;
• Free CFL light bulb giveaways;
• Rebates and incentives for energy efficient appliances;
• Solar thermal and PV incentives
• Equipment rental program for energy audits
• Collaborative partnership with CORE, Energy Smart Colorado, HCE, and SourceGas
As you can see from the below graphic, education and conservation/efficiency measures offer
the highest return on investment in the energy realm. This “low hanging fruit” is the target of
demand-side management:
Figure 7: ROI Pyramid
In November, 2000, the Aspen and Pitkin County Building Departments worked with Aspen City
Council to create REMP (Renewable Energy Mitigation Program). The REMP program gives
owners of new homes over 5,000 square feet the following choice: either the home must
include a renewable energy system (solar thermal or electric) or the owner must pay a
mitigation fee that increases based on the number of energy-using amenities. That money goes
into a fund that pays for rebates and incentives for other customers to install solar or make
efficiency improvements. In 2011, REMP gave 467 rebates, totaling $64,940. These rebates
reduced consumption by 205,240 kWh/yr and reduced CO2e emissions by 337,698 lbs/yr.
In 2009, the City Council adopted a REMP program for commercial buildings, and also adopted
the 2009 IECC.21 That same year, The City of Aspen’s City Council approved the program of
tiered electrical rates which by design encourage energy efficiency.
ii. Supply-S ide Management
20 A complete portfolio of residential and commercial energy and water efficiency (EE) programs and projects from
professional energy assessments to EE upgrades and retro fits.
21 IECC stands for the International Energy Conservation Code. The City is currently considering adoption of the
updated 2012 IECC and complimentary 2012 IgCC “green” building codes, which purport to increase new building
efficiency by 15%.
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Aspen Electric is adding renewable energy generation on both sides of the meter,22 with the
following programs and projects:
• 92 kW PV array to power water treatment plant
• 5.4 MW of locally owned and operated hydroelectric production (Ruedi and Maroon Creek)
• 4.5 MW Ridgway hydroelectric contract (beginning January, 2014)
• Rebates for installation of customer-sited solar photovoltaics (PV)
• Rebates for customer-sited ground-source heat pumps
• Research into community solar garden
• Feasibility studies of micro hydro
• Working with MEAN to increase non-carbon electricity generation
D. CONTRACTUAL CONS TRAINTS (MEAN PPA)
The City’s contract with its wholesale power provider, MEAN, only allows Aspen’s utility to produce ~8.2
million kWh/yr. in new renewable energy not purchased through MEAN. The allowance is designed as
follows:
• 6.7 million kWh/yr. for new hydro;23 and
• 1.5 million kWh/yr. (or 2% of annual consumption) in other “behind the meter”
sources.
TOTAL: 8.2 million kWh/yr.24
As such, even if the City is to fully take advantage of this allowance, it will still face a renewable energy
shortfall, and come just short of meeting the Canary Goals. Supplemental purchases of renewable
energy through MEAN will remain a necessity regardless. Moreover, this shortfall will continue to grow
unless consumption growth is neutralized or made negative.
Below is the operative exhibit of the City’s current contract, showing all future hydroelectric energy
allowances:
Figure 8: Exhibit B of Second Supplemental Agreement to the MEAN PPA
22 Basically, “behind the meter” refers to power sources on the Aspen-side of the AABC substation, whereas “in
front of the meter” refers to all power sources that are wheeled to us from the down valley-side of the substation.
For example, Maroon Creek hydro is “behind the meter” source, while Ridgway is “in front of the meter”.
23 This allowance is for sources on both sides of the meter, providing they are amenable to MEAN
24 Based on projected 2015 demand
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Historically, MEAN has been extremely accommodating to the City of Aspen. Of their 60+ municipal
subscribers, MEAN granted Aspen the sole exception to their traditional “All Requirements” power
purchase agreement (PPA), meaning that we are the only participating municipality allowed to develop
or participate in renewable energy resources outside of MEAN’s resource pool (see “Exhibit B”, below).
Over time, this has allowed the City of Aspen to complete the Maroon Creek and Ruedi hydroelectric
plants, the Ridgway hydro PPA, as well as pursue the CCEC.
That said, many have suggested that Aspen abandon its contract with MEAN. This would be
disadvantageous for a number of reasons:
• The City is effectively a cooperative owner of MEAN, and would thus lose its existing
investment in the net asset value of MEAN’s energy portfolio (the City’s interest constitutes
roughly 3.5% or MEAN’s $58 Million in net assets);
• Aspen would continue to have financial liability (through access to its tax base) on projects
already financed under the agreement until all such debt is retired;
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• Dispatching and scheduling and transmission services offered by MEAN provide much higher
efficiencies and access to the utility grid not available to Aspen for instance, 24-7
dispatching would require more than a doubling of Aspens’ electric staff);
• MEAN’s contract with Aspen is very flexible in allowing the City to achieve its renewable
energy goals, whereas the previous agreement with Excel Energy (in effect for 20 years from
1963-1983) allowed no such flexibility;
• MEAN expanded its choice of energy sources to include greatly expanded access to wind
resources at the request of Aspen and others allowing Aspen to be a nati9onal leader in
purchases of wind energy on a percentage basis;
• Leaving MEAN would eliminate access to the existing wind contracts (as well as firming
services) that allowed Aspen to reach nearly a third of its energy through wind;
• Excel and MEAN are the only 2 entities providing all requirements energy service statewide
in Colorado; and
Summarily, leaving MEAN would make our 2015 renewable energy goals virtually unattainable. In light
of that, the City has three general options going forward:
OPTION 1: Develop 8.2 million kWh/yr. of new renewable energy not purchased through MEAN, limited
to:
• 6.7 million kWh of new hydro energy (either locally, with micro and conventional hydro, or non-
locally through a Ridgway-like partnership); and
• ~1.5 million kWh “behind the meter” new renewable energy (solar, biomass, etc.)25
Total: 8.2 million kWh
Any resulting shortfall would need to be met with more supplemental purchases of renewable energy
from MEAN.
OPTION 2: Purchase all additional renewable energy through MEAN, but at a significant added cost (see
Figure 6, above).
OPTION 3: Pursue a combination of the two—partially using the contractual allowance, and
supplementing with MEAN purchases.
With regard to the City’s existing contract with MEAN, this report assumes no additional flexibility
beyond Exhibit B and the 2% “behind the meter” allowance. Accordingly, several of the alternatives
covered in this report are limited in their implementable size, and therefore disadvantaged from an
economic feasibility perspective.26
II. ALTERNATIVE ENERGY SOURCES
In order to meet the City’saggressive Canary Goals, and in the absence of the CCEC, it is likely that
several of the following alternatives must be used in concert with other categories of renewable energy
(rather than a single “silver bullet” approach). This section will look at each of the five renewable energy
technologies available to Aspen, giving a general overview of the technology and a preliminary
impression of feasibility.
25 This 2% allowance is based on 2011 consumption, and will rise with future consumption growth (presuming it
continues to rise).
26 Most renewable energy technologies benefit from economies of scale, and thus require certain installed
capacities to be economically viable.
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A. HYDROPOWER
All hydropower projects are governed by the same physical equation: P=p*g*H*Q
Where:
P = power;
p = water density;
g = acceleration (from gravity);
H = head; and
Q = flow rate.
Of these factors, H (head) and Q (flow rate) are the only variables which increase P (power) (the others
are constants).27 Accordingly, developers of utility-scale hydropower projects aim to maximize head and
flow rates in order to maximize and stabilize power output. This usually involves using reservoirs and
penstocks, which artificially increase head and enable the control of flow rates, both of which optimize
power production. The following graph shows the universal relationship between power (kW), head
(m), and flow (m3/sec) (plotted logarithmically):
Figure 9: Universal Flow/Head/Power Relationship
i. Conventional Hydro (“High Head”)
Whether or not the CCEC comes to fruition, the City owns valuable hydroelectric equipment—a
turbine, generator, and related controls. Purchased for ~$1.6 million, this equipment could be
used locally or in a new hydro partnership. Or, alternatively, it could be sold (preliminary
estimates show a sales price of about 35% of the original purchase price). Several opportunities
exist for new hydro partnerships in other parts of the state, but it remains to be seen how
feasible any of these alternatives are—both from a cost standpoint, and a power provider
standpoint (i.e., amenable to MEAN). There is also a possibility that the City would be able to
27 The other variable is turbine efficiency, which tends to hover between 88% and 92% for most modern Pelton
designs.
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purchase some or all of the summer Ridgway output from Tri-State, but there have been no
discussions to confirm this.
a . New Partnership(s)
There exists the potential to co-develop a new or nascent hydroelectric project in
another part of the state. Several prospective sites and partners have been identified
for this approach. However, their respective feasibilities are unknown without further
discussions and analysis with potential partners. Ideally, the project site would use an
existing dam and reservoir, require no changes in release flow schedules, be sited near
existing transmission infrastructure,28 and fit the turbine and generator’s technical
specifications in hopes of using the equipment in lieu of up-front capital outlays or,
alternatively, to secure a more desirable long-term rate agreement.
Figure 10: The 1.17MW Turbine and Generator Intended for the CCEC
The existing turbine and generator was built to the CCEC’s specifications, so the goal
would be to find a partnership involving an existing reservoir with comparable effective
head and available flow to that of the CCEC project (325ft and 10-52 cfs, respectively).
Even small discrepancies in design can result in huge long-term losses for the project
owner(s).
a. Ridgway
The City of Aspen has contracted with Tri-County Water Conservation District (TCWCD)
to purchase the winter output (Oct-May) of the new Ridgway hydroelectric plant
(expected to come online in October 2013), or about 9.8 million kWh/yr. The City
contracted for this energy because it was clean, renewable, base-load energy that fit
28 Many reservoirs in the state would be attractive prospective project sites if not for the extremely high
interconnection costs associated with building out the transmission infrastructure.
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Aspen’s winter-peaking consumption curve. The price of energy in the City’s 20-year
PPA with Tri-County is $0.059/kWh, with a 2% annual inflation factor.
The other buyer, Tri-State Generation and Transmission Association, has a 10-year PPA
with TCWCD for the summer output from Ridgway (roughly the same output), at a
significantly lower cost (~$0.039/kWh).
Based on the wide gap between contracted rates, this leaves a lot of room for a win-win
rate negotiation, as well as a significant cost savings over MEAN Schedule M ($0.062/
kWh, including transmission costs).
An “All Ridgway” solution would look something like this:
Figure 11: Fit of “All Ridgway” Scenario
As you can see by from the above graph, this scenario would result in considerable
overages during the summer months. Preliminary discussions with MEAN show a
willingness on their part to apply summer excesses to winter shortfalls (shown as
“swapped energy” in the graph above).
ii. Micro Hydro
For the purposes of this report, “micro hydro” will be used as an umbrella term to describe
hydroelectric projects <100kW installed capacity. Run-of-River (ROR), low head, and inline
turbine projects all fall under this category, and each will be covered in this subsection. Like
conventional hydro, the kinetic energy of the stream is converted to mechanical energy, which
creates electricity. However, unlike conventional hydro—which artificially increases hydraulic
head and allows for controlled flows (via elevated reservoir and penstock)—micro hydro
generally uses the stream/water distribution system’s “natural” hydraulic gradient and flow
regime.
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WAPA RUEDI MAROON CR WIND RIDGWAY EXCESS RIDGWAY SWAPPED ENERGY PURCHASES TO BALANCE
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It is important to emphasize up front that even if the City were to spend millions of dollars
constructing dozens of local micro-hydro installations, the maximum aggregated output of these
facilities would not even begin to approach the output of a single conventional hydro project, as
represented by Ruedi, Maroon Creek, or the proposed CCEC. The primary advantage of micro
hydro technology in Aspen is its potential to protect portions of the City’s senior water rights.
Accordingly, a traditional financial analysis of this technology isn’t all that useful. On its face,
micro hydro appears to be incredibly expensive both on an installed $/kW basis, and a lifecycle
cost basis. However, if one incorporates the value of the water right into the calculation, the
cost/benefit becomes very desirable in most cases.
a. Run-of-River (RoR)
This alternative is defined by its lack of water storage. RoR is “a power station utilizing
the run of the river flows for generation of power [whereby] the normal course of the
river is not materially altered”.29 Due to its lack of storage, head is usually limited, and
so is the power production potential.
Natel Energy, a leading provider of RoR technology and services, is a firm endorsed by
the Low Impact Hydropower Institute and its Chairman, Richard Roos-Collins (also of the
Water and Power Law Group, PC). Natel’s first commercial application of RoR
technology was installed on an irrigation ditch in Arizona in 2009. The installation’s
capacity was <20kW, and it required minimum flows of 22cfs with 12ft of head. Natel’s
largest RoR unit has a capacity of 988kW, and requires 1,106cfs of continuous flow.
In Aspen’s case, RoR would involve the installation of turbines on existing dam spillways
or diversions of water through a very short (<50ft.) penstock. As explained above,
compared to conventional dam-and-penstock hydroelectric developments, this method
produces far less energy due to lack of head.
In 2010, the City of Aspen commissioned a feasibility study from McLaughlin Water
Engineers, Ltd., detailing the potential for RoR using Aspen’s existing infrastructure. The
study proposed using a 12kW vertical-axis turbine and generator at the existing Maroon
Creek diversion facility:
Figure 12: Diagram of RoR Turbine and Generator at Maroon Creek Diversion Site
29http://www.conflicts.indiawaterportal.org/sites/conflicts.indiawaterportal.org/files/Damming%20Northeast%20I
ndia,%20Single%20page%20format.pdf
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While the financials of this project appear extremely unattractive on paper ($29,166/kW installed, with
a 38-year payback), the 12-16 cfs of water rights this installation could preserve—if monetized—would
likely make the cost/benefit analysis highly desirable.
Figure 13: Financial Summary of Maroon Creek RoR Feasibility Study
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Assuming an identical RoR project would work at the Castle Creek diversion structure,
the City could produce a combined total of ~184,000kWh/yr. at an up-front cost of
~$700,000, potentially protecting 24-32 cfs worth of Aspen’s senior water rights.
b. Low Head
The City has also commissioned a feasibility study examining the possibility of low head,
or “short penstock” micro hydro, on both creeks. This model requires the installation of
new diversion structures (upstream of the existing diversion points), power houses
(downstream of the exiting diversion points), and a 150ft and 300ft penstock at Castle
and Maroon Creeks, respectively. T
he primary reason this option has not been pursued was that it involved a bypass reach,
which—although relatively short—has proven unpalatable to some in the Aspen
community, and would likely be fought in ways similar to the CCEC.
The short penstock micro hydro proposed for Maroon Creek has the following
characteristics:
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The layout of the proposed Maroon Creek installation is shown below:
Figure 14: Proposed Short Penstock Micro Hydro on Maroon Creek
This installation would produce ~124,000 kWh/yr. according to the study, or about 30%
more than the associated RoR installation. The exact costs of this project are unknown
at this time.
The short penstock micro hydro proposed for Castle Creek has the following
characteristics:
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The layout of the proposed Castle Creek installation is shown below:
Figure 15: Proposed Short Penstock Micro Hydro on Castle Creek
The output of this installation is estimated to be ~74,000 kWh/yr. Like the Maroon
project, the exact costs are unknown at this time.
c . Inline Hydro
Inline hydro harnesses the kinetic energy of water running through the City’s existing
distribution system. The most attractive installation site for inline hydro is at the
system’s pressure reduction valves (PRVs). Basically, the inline turbine would perform a
similar function to the PRV, dissipating the energy (pressure) of the water within the
City’s predominantly gravity-fed delivery system, and making it safe for customer use.
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A feasibility study was commissioned in 2007 to study the potential for inline hydro in
the City’s water distribution system. Three of the most attractive PRVs were studied in
greater detail, shown below in Figure 16:
Figure 16: Financial Analysis of Three Inline Hydro Sites
Castle Creek
Bridge
Airport Business
Center
West
Buttermilk Rd.
Total
Capacity (kW)30 2 1.5 0.85 4.35
Output (kWh/yr.) 12,000 8,400 4,800 25,200
Project Cost31 62,445 45,195 26,220 133,860
Revenue ($/yr.)32 720 504 288 1,512
O&M Cost ($/yr.)33 84 59 37 180
Net Income ($/yr.) 636 445 251 1,332
Simple Payback (yrs.) 98 102 105 102 (Avg.)
Based on almost every financial metric, inline hydro makes no sense. Using the 3 “most
desirable sites” analyzed in the feasibility study:
• The average installed cost is $30,772/kW (Aspen’s solar PV at the water plant
was $4,909/kW)
• The aggregated unit cost of the energy is $0.19/kWh
• The average payback time is 102 years—far longer than the expected life of the
equipment
• The total output is 25,200kWh/yr.—about the energy use of 3 average homes
iii. Improvements to Existing Hydro Facilities
At current, the hydro facility at Ruedi is not able to operate at its designed capacity (5.02MW at
300cfs). According to a 2007 study by Canyon Engineering:
“[W]hen the plant was commissioned, it was observed that at flows above
about 250cfs (4.3MW), noise and vibration level increased dramatically. It was
determined that turbulence in the tailwater area directly under the turbine was
affecting free rotation of the impulse turbine runner.”34
The losses associated with this design flaw amount to ~543,470kWh/yr., or
~$20,652/yr.35 Therefore, any cost recovery projections for Ruedi improvements would
be based on this number (e.g., a $500,000 solution would have a payback period of 24
years, based on current uninflated energy costs).
Figure 17: Aerial View of the Ruedi Dam, Hydroelectric Facility, and Exit Channel
30 Based on turbine mechanical efficiency of 70% and generator efficiency of 75%-80%
31 Based on construction cost of $2,300/kW of capacity, as well as 25% contingency and 20% engineering fees
32 Based on $0.06/kWh
33 Based on national average of $0.007/kWh
34 Canyon Engineering, Inc., “Ruedi Hydroelectric Project – Backwater Review” May 29, 2007.
35 The financial loss is calculated by taking the difference between Ruedi and MEAN unit costs ($0.038/kWh) and
multiplying by the loss in energy output.
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Simply put, this loss is caused by two things:
1) The exit channel is not steep enough (or, similarly, the powerhouse floor is
not high enough); and
2) The turbine and powerhouse lack adequate aspiration and ventilation,
respectively.
There are three ways to fix this:
1) Raise the entire power plant by several vertical feet
The most obvious, but least cost effective way would be to raise the whole
powerplant about four vertical feet. Possibly only the turbine and generator
could be raised, but modifications would still need to be made to the building to
change the tailrace outlet. [This] would obviously be quite expensive, especially
since the turbine and generator is essentially cast (in concrete) into its own
reinforced concrete foundation, which is in turn founded on the bedrock under
the site. The upper part of this system would need to be removed and then
reconstructed at a higher level. The building would also have to be modified to
accommodate changes.
2) Lower the water surface elevation in the tailwater pit and exit channel
This would involve dredging up to 8,500 yds3 of streambed material to achieve
streambed elevation profile described by “proposed grade of channel bottom”
in Figure 17, above. The slope from the base of the old cofferdam to the lowest
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part of the concrete USGS weir is 0.0024 vertical foot per horizontal foot, or less
than one quarter of a foot drop in 100 feet of channel. For comparison, the
average drop in the next few miles of river, from the weir to just above the Cap-
K Ranch, is 1.4%, or 1.4 feet of drop in 100 feet of channel. That is nearly six
times steeper.
Figure 18: Profile View of Frying Pan River and Powerhouse with Proposed
Channel Grade
3) Increase the powerhouse ventilation and/or enlarge the turbine aspiration
apparatus
The turbine case could be vented even more to allow the pressure inside the case to
more closely approach atmospheric pressure. [This] option…appears to be the most
likely way to improve power output without expending great amounts of time and
money.36
To summarize: considering the amount of energy and money to be gained, option (1) is
not cost-effective; option (2) is also not cost effective and is also environmentally
hazardous; and option (3) is possibly cost effective, depending on the energy gains it can
achieve. A cost benefit analysis of option (3) needs to be conducted in order to make a
fully informed decision.
B. WIND
36 Excerpts taken from Zancanella & Associates, “Ruedi Hydroelectric Frying Pan River HEC-RAS Analysis”
(November, 2012)
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Aspen Electric already has one of the highest proportions of wind energy in the State of Colorado. As
stated in the Introduction, the dramatic increase in wind purchases between 2001 and present has been
a big driver of our progress towards our renewable energy goals. However, it has come at a cost. In
calendar year 2011, Aspen purchased 20.3million kWh of wind energy (29% of total consumption 37) at
~$0.069/kWh (including all transport and capacity charges), at a total cost of ~$1,620,000.00.
The following is a breakdown of wind costs for 2011:
• Standard wind charges: $1,023,002.00 ($0.051/kWh)
• Wind attribute charges: $44,800.00 ($0.016/kWh)
• Capacity charges: $438,416.00 ($0.019/kWh)
• Transport charges: $115,373.00 ($0.005/kWh)
TOTAL: $1,621,590.00
i. Additional MEAN Purchases
So, why doesn’t the City buy more wind to reach its renewable goals? Every year, the City
purchases a share of MEAN’s annual wind resources’ output. That share is divided into each
month to roughly represent demand for the energy. At current, additional wind purchases
would exceed the demand for the energy in several months during the year. In order to
accommodate more wind in its portfolio, the City would be required to pay ~$0.10/kWh for all
excess wind energy. Add this to the already comparatively expensive unit cost of wind energy,
and wind looks very unattractive from a financial standpoint.
Fulfilling Aspen’s energy demand with more wind purchase from MEAN would be extremely
expensive. In addition, upcoming replacement costs will force wind energy prices up going
forward. The following roughly outlines MEAN’s fulfillment of the 100% renewable with more
wind:
Figure 19: 100% Renewable with Wind
37 More, when Schedule M wind is added. This percentage just describes voluntary wind purchases by Aspen.
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C. SOLAR
Solar PV technology is extremely expensive per installed kW, with a relatively short lifespan of ~20-25
years, and steady production decay. What’s more, it has a very low capacity factor seeing as solar
technology can only produce energy during times—and in locations—of adequate sun exposure. Despite
Aspen’s generally sunny climate, Aspen’s steep mountain valleys, heavily treed neighborhoods, and
periodic snowfall lower the community’s overall productive capacity. The national average for capacity
factor is 25%; the PV installation at the water plant has a 19% capacity factor, despite its optimal siting
at that location.38
However, pursuing additional solar installations in Aspen remains attractive for a variety of reasons,
among them:
• Offers local renewable energy production
• Variety of financing and operations models
• The City of Aspen has experience with construction and operations of Solar installations
It’s worth mentioning that customer-sited solar installations (i.e., residential PV) remain a great option
for demand reduction in Aspen.39 CORE offers significant incentives to encourage residential solar
projects--$0.50/kWh for annual production up to $3,000 for customer-owned systems, and $0.25/kWh
for annual production up to $2,000 for leased systems. These incentives make on-site residential solar
much more competitive and attractive for broader adoption.40 Further promotion of these—and other
demand-side—incentives is an important component of achieving the renewable energy goals.
i. Ownership Model
38 “Capacity factor” refers to the percentage of maximum designed output achieved during a given year.
39 CORE also offers solar thermal incentives ($1,500 per panel, up to $6,000), and solar maintenance incentives
(50% of tune-up and repair costs).
40 Average capacity of residential solar is growing every year. As of 2012, it stood at ~6kW (~10,000kWh/yr.,
assuming a 20% capacity factor).
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9,000,000 kWh All Wind (2015)
WAPA RUEDI MAROON CR WIND RIDGWAY NEW WIND EXCESS WIND
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The two primary barriers to utility-scale41 solar projects in Aspen are: 1) the high cost of the
technology; and 2) the high cost of land in the upper Roaring Fork Valley (solar arrays require a
lot of space). Accordingly, the most attractive prospective projects are those using City-owned
property (land or rooftop). However, even with land cost stripped out, solar is still expensive
relative to other renewable technologies—the City’s 92kW solar array at the water plant cost
$451,653 to build, which equates to an installed cost of $4909/kW.42
Additional solar installations on City rooftops are feasible, but their aggregated production
potential is very limited (~300 kW).43 Non City-owned sites, such as Obermeyer Place, have
been studied as well; however, they require leasing of the roof space at a high cost, which
makes these projects non-starters. What’s more, the City does not qualify for one of the
primary solar incentives—the 30% solar capital investment credit from the federal
government—due to the City’s non-profit status.
Thus, to make utility-scale solar tenable in Aspen, it would likely require the use, acquisition, or
lease, of vacant land for free or at a very low cost. It is likely that many of the good sites would
require us to wheel the power briefly through Holy Cross’s distribution system to get it onto
Aspen’s grid, adding slightly to the unit cost of the energy, and potentially disqualifying these
projects due to MEAN’s “behind the meter” requirement. Partnerships with area landowners
are nonetheless a possibility worth considering, whereby the City finances 100% of the
installation of the system on non-City land (in lieu of lease payments), and the landowner gets
credited for a portion of the power created at the solar installation.44
The Burlingame affordable housing development currently has plans to install a two-phase, 134
kW solar system.45 Based on a 25% capacity factor, this installation would provide ~293,000
kWh/yr. Below is a mock-up of the proposed system design:
Figure 20: Burlingame Phase II Carport Solar PV System Illustration
41 “Utility scale” generally refers to projects that produce enough energy to sell to a customer base
42 Compared to $1500-$3000/kW for wind, $1500-$1800 for biomass, and $2000 for hydro. You can see the real-
time output of the water plant array here:
http://view2.fatspaniel.net/PV2Web/merge?&view=PV/standard/HostedDetail&eid=171944
43 Sites include: Red and Yellow Brick buildings (45kW each), the Golf Course cart shack (25kW), City Hall (6kW),
and Burlingame Phase II (134 kW).
44 The Aspen Sanitation District has voiced interest in installing a PV array on their campus, but the energy was to
be used for powering the wastewater treatment plant, which is on the Holy Cross grid.
45 MV Consulting completed a preliminary solar installation design in February, 2011
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i i. Solar Garden Model
The “solar garden” model” is a centralized solar project whereby residents of Aspen would buy
into a share of the project (in lieu of installing a small solar array on their roof, in their yard,
etc.), and receive credit for that energy on their monthly utility bill. The Clean Energy Collective
model is “an agreement that would enable Aspen electric customers who purchase an interest in
the solar panels to receive direct credit on their electric bills for the energy produced through a
“virtual net metering” arrangement.”
This approach has several advantages:
• Increased capacity factor (solar garden projects are intentionally sited to maximize
productivity)
• Economy of scale (lower $/installed kW than multiple small projects)
• Centralized system monitoring (monitoring of one large system as opposed to dozens of
small, scattered ones; also leads to simplified billing)
• Community ownership
• Ongoing facilities maintenance provided
Aspen is in many ways an ideal candidate for this model, due to the strict building codes, heavily
shaded residential neighborhoods, and generally environmentally-minded populace (high
potential uptake). However, the high cost of land is again a serious limitation to the viability of
this model. The most likely participants in a cooperative solar model are upper-tier and eco-
conscious customers. In the case of the former, cannibalization of revenue stream could occur.46
E. GEOTHERMAL
46 The utility relies on these high energy users financially, so their independent energy production potential would
represent a reduction—possibly significant—in department revenues. This would likely put upward pressure on
the current rate structure.
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There are two potential uses of geothermal energy in Aspen—heat exchange, and electricity production.
The former has been studied in Aspen, and is considered the more feasible option. The latter generally
requires drilling to much deeper depths (~4km), at significant added cost, and requires much hotter
ground temperatures (>180 F). While geothermal power plant in Aspen might be possible based on the
geothermal resources in the area (see map below), it would likely come at a very high cost. If test well
results from the current drilling project yield high temperatures, it might nonetheless be worthy of
consideration.47
Figure 21: Geothermal Heat Map of the United States
i. Ground Source Heating and Cooling
Based on current information, the most cost-effective application of geothermal technology in
Aspen is for ground source heating, used to reduce the energy consumption related to the
heating and cooling of commercial buildings in the City’s south core. Most of this heating
energy exists as natural gas, rather than electrical heat (ie., geothermal would not measurably
reduce electricity use, nor would it produce new renewable electricity in this case).
According to a 2008 feasibility study conducted by SAIC, ample geothermal potential might exist
for the installation of a groundwater heat pump system to supply most of the heating needs for
the hotels and lodges in the southern section of the City’s commercial core: ~167 billion of the
~231 billion Btu/yr consumption—the electrical equivalent of ~49 million kWh/yr.
According to SAIC:
“The yield of the bedrock aquifer system beneath Aspen is not precisely known
and needs to be determined. The bedrock aquifer system may be capable of
yielding 1,000 to 5,000 gpm of warm ground water through one or more high-
capacity wells constructed to a depth ranging from 2,500 to 3,500 feet. Provided
47 The prospect of having a geothermal power plant in the middle of Aspen will most likely be controversial from
an aesthetic standpoint.
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access is available, the ground water temperature is sufficiently high (about
100º F), and the yield is adequate (at least 1,000 gallons per minute (gpm)).”48
In addition, widespread buy-in and investment from south core businesses will be
required to finance the build-out of a district heat exchange system. Further analysis of
geothermal resources is required.
F. BIOMASS
Biomass energy generation consists of several different technologies, applications, and fuel sources. For
this report, we’ll focus on wood and landfill waste as the primary biomass fuel sources49-- the former
because wood products are abundant in this region of Colorado, and the latter because of MEAN’s
existing investments in landfill gas energy.
i. Wood 50
Today, much woody biomass waste is disposed of either by burning or by allowing it to
decompose. Either way, its stored carbon is released into the atmosphere. Using biomass for
energy doesn’t prevent this emission, but it does enable the production of energy that can
offset carbon emissions from fossil fuel sources elsewhere.
Some advantages of biomass energy, if it is planned carefully:
• Reduced fossil fuel use
• Reduced carbon emissions
• A step toward energy independence for the nation
• Local economic benefits
• Financial support for forest health and restoration efforts
Careful planning includes ensuring that the biomass supply is sustainable and that – after fuel
transportation and other operating requirements – a biomass energy project both produces
more energy than it consumes and offers net negative CO2 emissions. The biggest challenge to
biomass energy in the U.S. is low energy prices. In areas where energy costs more, such as
Europe, biomass energy is often commonplace.
This [Roaring Fork Valley] supply analysis was geared toward relatively small community-scale
biomass energy production. It looked at the existing supply today and did not take into account
the significant amount of additional woody biomass that would become available if a market
existed for wood from forest management projects. If such a market existed, the Forest Service
would be able to undertake a variety of forest restoration projects that are precluded today by a
lack of funding.
Approximately 6,000 tons/year (bone dry) are available today from the following sources:
• USFS timber harvest residuals 1,600 tons/yr
• USFS fuel reduction projects 750
• Wildlife Habitat Improvement Projects 535
• Private forest management projects 200
• Urban wood waste (construction debris, etc.) 2,600
• Utility line maintenance 175
48 SAIC Technical Memorandum: “Reconnaissance Study of Aspen Geothermal Resources” (2008)
49 Other biomass fuel sources include agricultural products such as: corn stover, sugarcane, and hemp, among
others.
50 This subsection is excerpted entirely from the Roaring Fork Biomass Consortium’s 2011 “Biomass Feasibility
Study for the Roaring Fork Valley”
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TOTAL: 5,860 tons/yr
Approximately 50% of the above 5,860 tons comes from USFS lands. (This is equivalent to
around 200 wooded acres/year.) No new logging or roads would be necessary. Urban wood
waste is likely to increase if the U.S. housing market recovers in future years.
Given the relatively small wood biomass supply assumed for this study, the most successful local
project(s) would likely for the production of heat, not electricity. According to the Technology
Review, if several small direct combustion or gasification heat-only facilities were built with no
long-term debt, the projected simple payback for each would be 8.8 or 7.2 years, respectively.
This is based on biomass facilities with a 1 million BTU/hour heat load, approximately the annual
average heating needs of the Glenwood Springs Community Center.
The “sweet spot” in community-scale biomass energy:
• A heat-only (gasification or direct combustion) facility
• Using a ~3 million BTU/hour wood chip boiler
• Heating around 100,000 square feet of building space
ii. Landfill Gas
MEAN has a landfill gas power plant in the pipeline, set for production in the 2014-2015
timeframe. At this point, it is unclear whether or not they will offer this energy source a la
carte, on a per-subscriber basis, or if it will be incorporated into their broader energy portfolio
and sold to all subscribers. It is possible that if Aspen commits to a large enough portion of the
plant’s output, then MEAN will offer it to us as a separate renewable energy source.
III. RENEWABLE ENERGY CERTIFICATES (RECs)
According to the EPA, “A REC represents the property rights to the environmental, social, and other non-
power qualities of renewable electricity generation. A REC, and its associated attributes and benefits,
can be sold separately from the underlying physical electricity associated with a renewable-based
generation source.” There is currently no national oversight or regulation of the REC market. Thus, it
currently relies upon self-reporting and accounting of buyers and sellers of the product. However, REC
tracking and market standardization is maturing in the Unites States, with several regional groups
issuing unique ID numbers to RECs in order to prevent double counting.
The City of Aspen’s general policy is to keep all the RECs associated with its renewable energy. Often
times, utilities will buy the RECs from a renewable project in order to meet state energy standards,
without buying the associated energy. The seller of those RECs must ensure that the receiver of the
associated energy does not count it as renewable. In addition, there are occasions where REC
multipliers are offered (e.g., Ridgway), where the buyer of the energy receives bonus RECs (e.g., 1.5:1
ratio of RECs to energy). In these cases, Aspen does not market or sell the extra RECs.
A . CONFORMANCE TO CANARY GOALS
The following statement represents Canary Initiative’s position on REC use and accounting:
“The Canary Initiative supports Aspen Electric’s commitment to meet its 100%
renewable energy goal through the purchase and production of actual renewable
energy. While Canary staff recognizes that Renewable Energy Credits (RECs) may
provide some benefits, we do not believe RECs should be used to reach the utility’s
100% renewable goal. In instances where Aspen Electric is awarded RECs that exceed
the actual energy purchased (such as the 1.5 to 1 incentive through the Ridgeway
project), Canary staff thinks these promotional REC units should neither be counted
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toward the renewable goal, nor sold. Similarly, if the RECs from one of Aspen’s future
renewable projects are sold for any reason, the City should be disallowed from counting
that energy as renewable.
Per the ICLEI U.S. Community-wide Inventory Protocol (see below), RECs will not reduce
the Aspen Electric carbon factor nor will they be applied to Aspen’s community-wide
greenhouse gas emission reductions. Canary values the integrity of Aspen Electric’s
renewable energy efforts thus far and believes direct purchase of renewable energy and
investment in tangible renewable projects are the most appropriate and credible ways
to reach the 100% goal.”
In a word, purchased RECs cannot be used to advance the City towards its renewable energy goals
unless it also receives the associated renewable energy (at a 1:1 ratio), despite its “legality” and despite
other communities and utilities willingness to do so.
V. Generic Cost Comparison
This overview report will not go into project-specific cost analyses. With Council’s direction based on
this report, staff will spend the time and resources necessary to offer feasibility studies of specific
projects, and their related financial impacts. For the purposes of this report, the table below shows
average levelized cost to bring the various energy sources online:51
Figure 22: Levelized Cost Estimates for New Generation Sources ($/MWh)52
51According to NREL, “Levelized Cost…compares the combination of capital costs, operations and maintenance
(O&M), performance, and fuel costs. Note that this does not include financing issues, discount issues, future
replacement, or degradation costs. Each of these would need to be included for a thorough analysis.”
52Source: Energy Information Administration (EIA) – Levelized Costs AEO 2012. This table does not include
targeted subsidies available for many of the renewables listed here.
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VI. CONCLUSION
A. DIRECTION AND NEXT STEPS
Staff is requesting Council’s direction to further analyze new renewable alternatives, with the goal of
presenting them to Council at a later date. Ideally, specific direction will be given to staff with regard to
which projects and alternatives are to be pursued. A more in-depth follow-up report will be presented
to Council at a later date.
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