HomeMy WebLinkAboutagenda.council.worksession.20110718 Aspen Lights
Presented by the CCLC
The CCLC
The mission of Commercial Core & Lodging Commission (CCLC) is to improve business in the
downtown core.
Over the years, the CCLC has spent time:
- Reviewing and suggesting changes to existing regulations.
- Expanding the outdoor summer dinning experience.
- Creating and /or expanding specific events.
An example would be the Saturday Farmers Market, which 12 years ago consisted of 14
farmers utilizing less than 2/3 of Hopkins, but today covers 3 blocks, has over 90 vendors,
generates significant tax revenue, and is attended by over 50,000 people.
The Big Idea
Over the last few years, the CCLC has focused on coming up with a big idea. While the bike
race may be the "big idea" for the summer, the CCLC believes ASPEN LIGHTS, (working title)
is the big idea for the winter, specifically focusing on the three weeks before Christmas, a lean
period for lodging, restaurants, and retail sales, and running until the mountain closes.
The Goal
To generate heads and beds, and ancillary revenue for the three plus weeks before the
Christmas /New Years rush by promoting the ASPEN LIGHTS, locally, statewide, nationally, and
internationally.
What is the ASPEN LIGHTS?
In the tradition of the great international lighting festivals, the CCLC is proposing funding from
City Council to develop and stage ASPEN LIGHTS, which would be the first of its kind set in a
mountain resort in the world. The CCLC proposal for this December is to enhance the Cooper
and Hyman malls and their connecting walkways.
The Presentation
For the last three months, the CCLC has been worked with Lacroux Streeb Lighting Design,
(who have volunteered their time and expertise to date), to develop this idea. They will make
a short video presentation illustrating types of lighting, and opportunities.
1. Strand Lighting
2. Up Lighting
3. Digital Projection
In addition, CCLC has a breakdown of potential costs to cover design, hard goods,
and installation management for the Cooper and Hyman Malls and their connecting
walking areas this December, plus some ballpark cost for single buildings, and the
digital projection concept.
Q &A
The CCLC, and Lacroux Streeb Lighting Design will answers questions.
THE CITY OF ASPEN
MEMORANDUM
TO: Mayor and City Council
FROM: Chris Everson, Affordable Housing Project Manager
THRU: Barry Crook, Assistant City Manager
DATE OF MEMO: July 15, 2011
MEETING DATE: July 18, 2011
RE: Burlingame Phase II Update on IPD, Presales and Financing
REQUEST OF COUNCIL: Direction requested.
PREVIOUS COUNCIL ACTION: At the budget work session on October 20, 2009,
Council directed staff to proceed with the Burlingame Phase II Integrated Project Delivery (IPD)
design effort. On July 12, 2010, Aspen City Council granted conceptual approval to the
Burlingame Phase 11 concept master plan. On March 22, 2011, staff was instructed by City
Council to submit the Burlingame Phase II land use application. Also on March 22, 2011,
Council directed staff to proceed with the Reservation List phase of the presales program.
BACKGROUND: After the IPD team was selected through a competitive bid process, a
team of design professionals were contracted, and staff kicked off the IPD design project on
March 25, 2010. Based on the contracts and schedule that were approved by City Council, the
original completion date was scheduled for December 3, 2010 with "completion" defined as
including land use approval and implementation documents (the IPD term for construction
drawings). The IPD team embarked on rigorous, transparent and inclusive public outreach
program and provided updates to Council as follows:
April 5, 2010 IPD Schedule Update
May 4, 2010 Conceptualization Update #1
May 17, 2010 Conceptualization Update #2
June 7, 2010 Concept Master Plan Public Hearing #1
June 28, 2010 Concept Master Plan Public Hearing #2
July 12, 2010 Concept Master Plan Public Hearing #3
August 17, 2010 50% Detail Design Update
September 7, 2010 Update on Phasing and Demand
November 23, 2010 Detail Design and GMP Update
January 3, 2011 Presales RFP Update
March 22, 2011 Update on Proposed Presales Program and Single Family Home Designs
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THE CITY OF ASPEN
DISCUSSION:
IPD Design Update:
At the July 12, City Council meeting, homeowner interviews were added to the scope of the
public outreach effort at Council's request. At the August 17, 2010 Council update, Council
suggested that the effort be "slowed down ". At the September 7, 2010 Council update, the notion
of utilizing presales was conceived, and on November 23, 2010, staff was instructed to design a
presales program and issue an RFP for presales. At the January 3, 2011 Council update, Council
approved the presales RFP. At the March 22, 2011 Council update, Council added presales to the
scope of work.
Due to the scope modifications described above, the projected timeline of the effort has
expanded, and completion of the IPD design effort is currently projected to be November I,
2011. Despite these scope modifications, the effort remains on budget as follows:
Original 2010+2011 Budget: $3,950,000
Expenditures to Date 2010 +2011: $2,150,000
Projected Additional Expenditures to Reach Completion in 2011 $1,150,000
Projected Total if Completion is reached in 2011 $3,300,000
Contingency for carry -over to 2012 if needed: $650,000
Total $3,950,000
If the IPD design effort is not completed in 2011, then any remaining portion of the "Projected
Additional Expenditures to Reach Completion in 2011" as well as the "Contingency for carry-
over to 2012" would need to be carried over to the 2012 budget for completion of the work. In
this case, the City would also risk additional costs for the IPD team design professionals who
would more than likely seek additional compensation for the further- expanded timeline.
Alternatively, if the IPD design effort is completed in 2011, and if the presales effort continues
into 2012, then carrying over contingency to 2012 would be necessary to continue with presales.
Staff does not believe that the investment to date in the IPD design effort necessitates a decision
to immediately go forward with construction, but staff does believe that the investment to date in
the IPD design effort is good reason for completing the IPD design effort in 2011 so that the City
may control costs, accomplish one of City Council's top 10 goals, and hold the entitlements and
the construction drawings in hand — thus allowing the City to be fully prepared to move forward
with bidding and construction at a time when Council deems it appropriate to do so.
Per Council's direction on March 22, 2011, the Burlingame Phase I1 land use application was
formally submitted to the City of Aspen Community Development department on March 31,
2011. Community Development's proposed land use schedule is as follows:
Monday, July 25: Regular City Council meeting: First Reading
Monday, August 1: Open House for P &Z plus City board & commission members
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THE CITY OF ASPEN
Tuesday, August 2: Special City Council Meeting: Second Reading #1, Public hearing
at Burlingame Commons Building
Monday, August 22: Regular City Council Meeting: Second Reading #2, Public Hearing
in Council Chambers
August 29, September 6: Special City Council Meetings: Contingency dates if Council does
not take action on August 22 and wants to before September 12
September 12: Regular City Council Meeting: Contingency date if Council does
not take action at prior meetings
Completion of the construction drawings cannot be undertaken without first completing the land
use process since the designs cannot be fully documented until Council approves the application,
otherwise there is a very high risk of significant additional costs due the potential need to modify
the construction drawings — which would be a massive undertaking due to the excessive amount
of detailing that would need to be re -done by the team's design professionals in what will be an
incredibly large package of drawings and specifications.
Presales Update:
On March 22, 2011, staff proposed a multi -part plan for presales, which is summarized below:
PART 1: RESERVATION LIST
✓ Buyer signs up on reservation list
✓ Buyer gets APCHA qualified, $40 fee
PART 2: RESERVATION AGREEMENT
✓ Buyer gets prequalification from bank
✓ Buyer pays $500 refundable deposit
✓ Buyer signs reservation agreement
PART 3: PRESALES AGREEMENT
✓ Buyer re- verifies loan prequalification
✓ Buyer pays $1,500 non - refundable deposit
✓ Buyer signs presales agreement, selects unit
At that time, Council directed staff to go forward with Reservation List part of the plan only,
take a "bare bones" approach, and minimize costs in doing so.
Advertising for presales was kicked off by staff on April 20, 2011 and expenditures to date total
approximately $18,000. Staff created the marketing collateral materials and the presales website
in -house and thus limited expenditures to almost entirely to advertising.
Asset staff and Aspen / Pitkin County Housing Authority staff have been working very closely
on the presales effort, but the majority of the effort has fallen on Teresa Pollock at the Housing
Office who should be commended for her intense effort to garner applicants and shepherd them
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THE CITY OF ASPEN
through the APCHA qualification process while at the same time fulfilling her other
responsibilities in her role at the Housing Office.
Below is a summary list of presales results as of July 13, 2011 followed by a more detailed table:
Summary of results to date:
✓ 167 total applicants
• 58 of 167 total applicants have become APCHA qualified thus far
✓ 11 of the 58 APCHA qualified applicants currently own deed restricted housing
✓ 47 of the 58 APCHA qualified applicants do not currently own deed restricted housing
✓ 33 of 167 total applicants currently own deed - restricted housing
✓ 134 of 167 total applicants currently do not own deed - restricted housing
✓ 101 of 167 total applicants currently rent housing
✓ 133 of 167 total applicants currently have housing in Aspen, SMV or Woody Creek
d ✓ 32 of 167 total applicants currently have housing down valley (mostly Basalt, Carbondale)
✓ 83% of all applicants have a 4+ year work history in Pitkin County
✓ The applicant unit mix is favorable compared to the unit mix proposed for Phase II
✓ The applicant category 2, 3, 4 mix is favorable compared to the proposed category mix
✓ Difficulty with higher categories as APCHA staff had predicted
✓ Includes 8 category 1 applicants who may not be able to afford category 2 purchases
As of 7/13/11 Notes
Total N of Applicants 167 Total applicants
Total N of APCHA qualified applicants thus far 58 58 of 167 applicants have been APCHA qualified thus far
*of APCHA qualified applicants who currently own deed restricted housing 11 19% of APCHA qualified applicants
N of APCHA qualified applicants who do not currently own deed restricted 47 81% of APCHA qualified applicants
N of total applicants who currently own deed restricted housing 33 19.8% of total applicants, Aspen =29, Woody Creek =l, SMV-2, Ctther =1
N of total applicants who currently do not own deed restricted housing 134 77.8% of total applicants
N of total applicants who currently rent deed restricted housing 56 33.5% of total applicants currently rent deed restricted housing
N of total applicants who currently own free market housing 23 13.8% of total applicants, AABC =3, Basalt =8, Carbondale =9, SMV =1, Unknown =2
N of total applicants who currently rent free market housing 45 26.9% of total applicants currently rent free market housing
N of total applkants who currently rent housing 101 60.5% of total applicants currently rent housing
*of total applicants from the up valley area 133 79.6% of total applicants are from Aspen, Snowmass Village and Woody Creek
*of total applicants from the down valley area 32 19.2% of total applicants from further down valley
*of applicants with 4+ year work history in Pitkin County 139 83.2% of total applicants have a 4- year work history in Pitkin County
*of total applicants who want a 1 bedroom multifamily unit 42 25.1% of total applicants want a 18R. 30% currently proposed.
N of total applicants who want a 2 bedroom multifamily unit 50 29.9% of total applicants want a 268. 30% currently proposed.
*of total applkants who want a 3 bedroom multifamily unit 61 36.5% of total applicants wants 3BR. 40% currently proposed.
N of total applicants who want an single family home
29 Some overlap with 3BR condo applicants but few will be able to afford these
*of APCHA qualified applicants in each category:
Category 1
Category 2
Category 3
Category 4
Category 5
8 =13.8% compared to currently proposed 0.0%
14 =24.1% compared to currently proposed 24.2%
20 =34.5% compared to currently proposed 32.3%
14 =24.1% compared to currently proposed 20.5%
0
1
0
0.0% compared to currently proposed 10.6%
Category 6 =1.7% compared to currently proposed 7.S%
Category 7 0.0% compared to currently proposed 5.0%
Category RO 1
=1.7% compared to currently proposed 3.6%
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•
THE CITY OF ASPEN
What's Next ?: Should Council want to proceed to another level of buyer commitment, we
would like Council to determine what kind of commitment is appropriate and provide some
further commitment to the potential buyer community from the City Council. Any increase in
commitment level whereby a potential buyer would be asked to provide a deposit or commit to
some level of obligation — we believe — requires a commensurate commitment from the City
Council as to what its approach to funding and construction is, including some understanding
about timing.
Housing Fund Financial Capacity:
In addition to the question of demand for housing at Burlingame Phase II there is also a question
regarding how much capacity the 150 Housing Development Fund has to fund development of
Burlingame Phase II either via debt or cash.
On November 23, 2010, staff presented the 100% Detail Design plans and GMP proposals to
construct either 167, 82 or 52 units at Burlingame Phase II. Those three proformas were based on
phasing scenarios where Burlingame Phase II might be constructed via 1, 2 or 3 mobilizations.
The IPD team has created detailed construction schedules for those scenarios and has used the
work effort described in those schedules to create detailed cash -flow models generally termed
`167x1', `80x2' and `55x3'. Staff is aware that Council is not interested in considering the 167x1
scenario and has thus focused effort on analyzing funding options related to the 80x2 and 55x3
scenarios.
For the past 18 months, the real estate transfer tax (RETT) has outperformed the City's
compared to the
In 2010 actual RETT revenues were $6.3 million com
conservative budget estimates. P
2010 budget of $4.8 million. The City's adopted 2011 budget estimated RETT revenues at $4.9
million, and while actual 2011 RETT revenues are on pace to outperform 2010, the City is
currently projecting $5.5 million in RETT revenues for 2011. At one time, it was estimated that
the City would need to issue $50 million in debt to finance the development of Burlingame Phase
II, but because of the RETT's recent resiliency, staff sees the opportunity to significantly lower
or eliminate the use of debt financing.
The City's Finance department has developed long range plans (LRPs) to accommodate both the
80x2 and the 55x3 development scenarios both with low -debt and no debt options for each.
These LRPs were created using an initial conservative approach as well as a "worst case"
conservative approach as a stress test for each scenario. This approach results in a total of eight
different potential funding models as follows:
❖ 80x2 Phasing
1. Low debt, Revenues On -Time (conservative, containing 10% contingency)
2. Low debt, Revenues Delayed (worst case variation of #1)
3. No debt, Revenues On -Time (conservative, containing 1 0% contingency)
4. No debt, Revenues Delayed (worst case variation of #3)
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I*
THE CITY OF ASPEN
❖ 55x3 Phasing
5. Low debt, Revenues On -Time (conservative, containing 10% contingency)
6. Low debt, Revenues Delayed (worst case variation of #5)
7. No debt, Revenues On -Time (conservative, containing 10% contingency)
8. No debt, Revenues Delayed (worst case variation of #7) .
f
The term "low debt" is used in comparison to prior estimates of $50 million in debt financing.
Nonetheless, there are financial and community impacts related each of these potential funding
models that should be considered as shown in the table below:
Phasing & Financial Factors Community Factors
Construction Unit Sales Subsidy per Subsidy per Interfurtd Neighborhood lob Creation Housing Goals Public Vote
Scenario 8 Scenario Phasing Debt issued
Years Revenues Unit FIE Loan Impacts Begins Realized Required
80a2 debt revenues 2012 -2013 2013
1 on time 80x2 2019 -2020 2020 340,000 150,000 8,000,000 Medium 2012 maD Yes
80x2 debt revenues 2012 -2013 2014 2014
340000 150000 8,000,000 13,000,000 Medium 2012
2 80x2 Yes
late 2019 -2020 2021 2021
80x2 no debt 2013 -2014 2014 2014
3 revenues on time 80x2 2020-2021 2021 320,000 140,000 None Medium 2013 2021 No
4 80x2 no debt 80x2 2014 -2016 2017 2017
320,000 140,000 None High 2014 No
revenues late 2021 -2022 2023 2023
2012 -2013 2013 2013
55x3 debt revenues
5 55x3 2015 -2016 2016 350,000 150,000 3,000,000 Very High 2012 2016 Yes
on time
2018-2019 2019 2019
2012 -2013 2014 2014
6 55x3 debt revenues 55x3 2015 -2016 2017 350,000 150,000 3,000,000 9,500,000 Very High 2012 2017 Yes
late 2018 -2019 2020 2020
2013 -2014 2013 2013
7 55x3 no debt 55x3 2016-2017 2016 340,000 150,000 None Very High 2012 2016 No
revenues on time 2019 -2020 2019 2019
SSx3 no debt 2013-2014 2015 2015
8 55x3 2016-2017 2018 Vary High 2013 2010
revenues late 2019 2020 2021
Scenario #1 suggests that an 80x2 phasing approach could be utilized if the City were to pursue a
November 2011 ballot question which would authorize $8 million in debt financing to begin
construction in 2012. Scenario #2, which is a stress test to scenario #1, suggests that an inter -
fund loan might, in the worst case, be needed to sustain the fund if unit sales revenues are
delayed from 2013 to 2014.
Scenario #3 suggests that an 80x2 phasing approach could be utilized with no debt if
construction were to begin in 2013. Scenario #4, which is a stress test to scenario #3, suggests
that delayed sales revenues could cause a construction delay which could increase the
neighborhood impacts by stretching the construction timeline.
Scenario #5 suggests that a 55x3 phasing approach could be utilized if the City were to pursue a
November 2011 ballot question which would authorize $3 million in debt financing to begin
construction in 2012. Scenario #6, which is a stress test to scenario #5, suggests that an inter-
I fund loan might, in the worst case, be needed to sustain the fund if unit sales revenues are
Page 6 of 7
THE CITY OF ASPEN
delayed from 2013 to 2014. A 55x3 phasing approach would increase neighborhood impacts by
stretching the construction timeline as compared to an 80x2 phasing approach.
Scenario #7 suggests that a 55x3 phasing approach could be utilized with no debt if construction
were to begin in 2013. Scenario #8, which is a stress test to scenario #7, suggests that delayed
sales revenues may allow the fund to sustain sufficient cash flows, but would also increase
neighborhood impacts by stretching the construction timeline as compared to an 80x2 phasing
approach.
In weighing these phasing /funding possibilities, Council may want to consider impacts such as
debt, subsidies, risk, public approval, neighborhood impacts, realization of housing goals and
other community concerns.
STAFF RECOMMENDATIONS:
IPD Design: Staff recommends completion of the land use process and the design effort on the
proposed 2011 schedule so that the City may control costs, accomplish one of City Council's top
10 goals, and hold the entitlements and the construction drawings in hand, thus allowing the City
to be fully prepared to move forward with bidding and construction at a time when Council
deems it appropriate to do so.
Presales: Staff recommends that the presales effort continue to the extent that Council desires,
however staff additionally recommends that City Council establish benchmarks for success
criteria that would allow the opportunity for presales applicants to understand how many presales
would be required for Council to consider moving forward with construction on either an 80x2
or a 55x3 phasing scenario. Success criteria should include not only the number of APCHA
qualified applicants but should also include the level to which Council would require applicant
commitment and mortgage qualification.
Housing Fund Financial Capacity: Staff recommends that Council forego a November 2011
public vote on debt financing and utilize a presales program to make future decisions on whether
or not construction might be pursued with no debt via an 80x2 or a 55x3 phasing plan. This
approach would postpone construction start, and thus the realization of housing goals, by an
additional year.
ALTERNATIVES: Council could choose to accomplish housing goals and create local jobs
sooner by considering a November 2011 public vote on debt financing given that the amount of
debt required for a 2012 construction start has been significantly lowered from $50 million down
to either $8 million (80x2) or $3 million (55x3).
CITY MANAGER COMMENTS:
Page 7 of 7
MEMORANDUM
TO: Mayor and City Council
FROM: David Hornbacher, Director of Utilities and Environmental Initiatives
THRU: Randy Ready, Assistant City Manager
Don Taylor, Finance/Administrative Services Director
DATE OF MEMO: July 14, 2011
MEETING DATE: July 18, 2011
RE: Electric Rate Study — Phase II
The City of Aspen electric's rates have not been adjusted since April 1, 2009, remaining stable
during the challenging past two- and - one -half year economic period. However, wholesale electric
rates have risen during this period increasing the cost of business.
This memorandum is presented to assist council in its review of the appended Phase 11 - Electric
Rate Study and to provide council with background information and staff recommendation for
proposed changes to the rate schedule for City of Aspen electric customers. In 2010, staff was
instructed to conduct an Electric Utility Rate Study in two phases. Phase I was designed to: (1)
determine the effectiveness of existing rates; and, (2) determine 2011 required revenue. Phase II
was requested by Council to: (1) determine the cost of providing electric service to each
customer class for years 2012 through 2015; and, (2) prepare electric rate alternatives that
produce sufficient revenue to meet annual revenue requirements for years 2012 through 2015.
Staff is seeking guidance from City Council on which of two rate structure alternatives to pursue
in any future proposed rate increase ordinance. The two alternatives seek to recover the full cost
to the City of providing electric services, but the two alternatives offer a different method for
recovering the total costs between the different classes of electric customers. (The four classes of
electric customers are: Residential, Small Commercial, Large Commercial, and City Facilities).
The two alternatives being presented in the Electric Rate Study Phase II Worksession are:
1. Alternative 1 - Cost of Service Transition — Recovers from each class of customer the full
cost of providing services to each class of customer. In order to minimize the initial
burden of the change in the proposed rates, the alternative is to transition to a full cost
recovery by class of customer over a period of six years. Only the first four years of the
transition periods are shown in the study.
Page 1 of 6
2. Alternative 2 - Uniform Adjustment. - Recovers the full cost to the City of providing
electric services to all customers by increasing rates uniformly to all customer classes. To
minimize the initial burden of the change in the proposed rates, the alternative proposes
to raise rates over a four -year period.
Revenue Adjustments 4 Year Summary
Des tt 2012 2013 2014 2015 Total Average
Alternative 1 - Coat of Service Transition
Residential 4.90% 5.00% 3.00% 2.50% 16.10% 4.00%
Small Commercial 4.40% 0.00% 0.00% 0.00% 4.40% 1.10%
Large Commercial 4.90% 1.50% 1.00% 0.50% 7.90% 2.00%
City Facilities 4.90% 4.50% 2.00% 1.50% 13.60% 3.40%
Alternative 2 - Uniform Adjustment
Residential 4.60% 2.00 %0 1.00% 1.00%0 8.60% 2.20%
Small Commercial 4.60% 2.00% 1.00% 1.00% 8.60% 2.20%
Large Commercial 4.60% 2.00% 1.00% 1.00% 8.60% 2.20%
City Facilities 4.60% 2.00% 1.00% 1.00% 8.60% 2.20%
Note: Totals on above Table do not equal due to difference in weighting percentage of each
customer class as shown in Table 3 -1; and, also due to Alternative 1 reflecting a higher initial
increase in 2012 and 2013 as compared to recommendations under Alternative 2.
REQUEST OF COUNCIL: Phase 11 of the Electric Rate Study contains two alternatives for
new rates with a proposed effective date of November 1, 2011. City staff is requesting City
Council select one of these two alternatives, which will move forward to the required public
hearing including further presentation to Council and community this summer. Electric Utility
Rate Study Phase II Draft Report dated July 8, 2011 by Red Oak Consulting is attached as
Exhibit "A ".
Additionally, staff requests City Council approval of the following supporting revisions and
updates:
• An ordinance which will establish formal policies used in instances where either under -
or over- billing occur. This proposed policy, in the form of an ordinance, is attached as
Exhibit `B ".
• Adding a 4 electric rate class specifically for electric service to city -owned facilities.
• An ordinance revising the definition of the qualifications for the Large Commercial
customer class rate from the minimum monthly demand measurement of 30 kW to 50
kW. This change will be phased in over a 2 -year period. This proposed ordinance revision
is attached as Exhibit "C ".
Page 2 of 6
PREVIOUS COUNCIL ACTION: The existing rates went into effect in April 2009, with the
intent of encouraging energy conservation and efficiency. The existing rates were also designed
to provide additional revenue to purchase increased renewable energy to continue towards the
goal of providing 100 percent renewable power to City electric customers.
The City electric utility currently has three customer classes— Residential; Small Commercial;
and, Large Commercial. Both Residential and Small Commercial rate classes have a four -tier
inverted block rate structure. The Large Commercial rate class has a kW (peak demand) charge
as well as a uniform kWh (total energy consumption) charge. The existing large commercial rate
encourages those users to shift their energy use to off -peak hours, but does not provide an
incentive to reduce the overall usage of power. No consistent integrated policy has been set to
address rate recovery from the growing number of system connections by City owned facilities.
Currently, a variety of different billing mechanisms are used depending on the characteristics of
each account.
BACKGROUND: In the fall of 2009, during Council's review of the 2010 budget, staff
requested a 4 percent rate increase to electric rates to become effective January 2010, to offset the
5.8 percent purchase power increase that was implemented by MEAN at the beginning of 2009.
In the summer of 2010, staff returned to City Council, requesting an electric rate increase during
Phase I of the Electric Rate Study to offset both the 2009 and 2010 MEAN purchase power
increase. Please review Exhibit "D" for further details on the July 2010, Phase I Electric Rate
Study work session with Council. Staff has been requesting that City Council consider electric
rate adjustments for the last three years to reflect an announced increase in wholesale electric
rates that were expected to significantly affect the cost of power purchased from the Municipal
Energy Agency of Nebraska (MEAN) for the years 2009, 2010, 2011 and 2012. City Council
elected to defer consideration of any rate adjustments at that time because of the prevailing
economic conditions in the community at the time of the wholesale rate increases. Energy
purchases from MEAN constitute the largest cost of operation of the electric utility. Wholesale
rates for purchased power have now been raised an average of 7.5 percent in each of the last three
years, contributing to a decline in the required Electric Fund reserve over that time period.
DISCUSSION: During discussions leading up to the adoption of the 2009 inverted block rates
for the Electric Utility, a number of consensus viewpoints were identified. Council's decision
and consensus points from these previous discussions were as follows:
1) Increasingly higher electric usage is subject to higher rates. A four -tier block rate
structure is preferred. The maximum usage for each class is set through identifying use
patterns of comparable users (i.e. larger amperage electric service given higher use
allowance, which is similar to water rates).
2) Rate schedules should provide energy conservation incentives. Those that use less than
average users will pay less than average cost.
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3) The additional revenues collected from higher electrical users should support the
initial/increased cost of running conservation programs and for adding renewable energy
to purchase power mix.
4) It is recognized that large commercial customers have more uniform electric demands
over time. Since wholesale rates are based on this factor, cost savings in wholesale prices
should be reflected through preferred rates for large commercial customers.
5) The allocation of electric cost currently favors residential users over commercial users
(i.e. cost of service for residential use not fully recovered with the difference made up by
commercial charges). Note that with Alternative #1, this preference for residential
customers would gradually be phased out.
6) Service charges should reflect pro -rated fixed expenses, (i.e. Billing; Meter Reading with
AMR component; and, Cost of Lost Energy —i.e. transformer/line losses).
7) A rate increase during the peak of the recession was unacceptable even though
wholesale rates for energy were going up rapidly and drawing down reserves and cutting
back on/delaying capital projects was preferred.
8) The City's energy conservation efforts over the past several years reflect one of our best
investments in managing energy costs for City of Aspen electric utility customers.
Results from the January 2011, CAMU rate survey lists the City of Aspen as having the
6th lowest residential rate out of the 26 Colorado municipal utilities surveyed, 14th
lowest small commercial rate of 26 Colorado municipal utilities, and 9th lowest large
commercial rate of 26 Colorado municipal utilities.
Note: Adoption of Altemative 1 or Alternative 2 would shift the City's rankings within the
26 Colorado Municipal Utilities. However, this comparison does not reflect rate changes that
may have been implemented by other utilities during 6 months period since the survey. For
example, Holy Cross Energy recently implemented an electric rates increase rating from 5.5%
to 6.8 %.
Residential will move to 8`h (rather than 6` out of 50 Colorado electric utilities.
Small Commercial will move to 20th (rather than 17` out of 50 Colorado electric utilities.
Large Commercial will move to 29` (rather than 10 out of 50 Colorado electric utilities.
9) City of Aspen policies direct staff to pursue utilizing 100 percent renewable energy by
2015. City staff has made significant progress on this goal achieving 75 percent with an
additional project under review.
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During the July 2010, Electric Utility Rate Study Phase I work session, Council identified a
number of objectives to be incorporated in Phase II of this study. Specifically requested was
determining the cost of providing electric service to each customer class for years 2012 through
2015 in order to produce sufficient revenue to meet annual Electric Fund requirements for each
of those years.
Currently there is not a separate rate class for City Facilities. New facilities that will be
connecting to the system, (ARC, Water Plant site, Golf and Parks sites) increase energy sales
with corresponding additional wholesale costs for the electric utility. Phase II alternatives
include specific rates for a new City Facilities customer rate class, which considers electric utility
costs appropriate to this new class.
City staff proposes to change the energy capacity (kW) definition for Large Commercial
customer class accounts from the existing 30 kW level to a 40 kW level in November 2011 and a
50 kW level in November 2012. This would have the overall effect of lowering the number of
Large Commercial accounts from 29 to 15. The 14 accounts that would no longer qualify would
be changed to the Small Commercial customer class rate over the course of the next two years.
See Exhibit "E" for further financial details. This proposed change would also be consistent with
the rate definitions of 50 kW minimum used by Holy Cross Energy and which enhances the
consistency in energy charges among the electric energy providers in Aspen.
FACTORS AFFECTING STAFF RECOMMENDATIONS: Prior direction of Council and
current staff recommendations are based on the following key points:
1) Recommendation to move towards a rate system that is based more closely on what it costs to
deliver power to specific customer groups instead of retaining the current system that puts more
of the burden on small commercial and less on large commercial customers.
2) A cost of service approach that should be phased in over a number of years rather than
immediately implemented.
3) If cost of service approach is no longer desired, increased costs should be passed on to
customers based on a uniform percentage adjustment based on existing systems.
4) Costs of providing power to City owned or operated facilities at multiple locations should be
developed on an aggregated basis — i.e. treated as a single customer rather than individual
customers.
5) Large commercial customers and city facilities should have a tiered structure to further
encourage conservation, in addition to the demand charge, which encourages a shift in the peak
energy usage.
6) The cost of community benefits (e.g. the costs of running the street lighting program, etc.)
should not be included in City facilities rate structure and should only be allocated to customer
classes that benefit from these programs?
Page 5 of 6
FINANCIAL/BUDGET IMPACTS: The financial implications of the proposed rates for the
two Alternatives are detailed in the attached Long Range Plans (LRPs) for the Electric Fund
(Exhibit "F') and Renewable Fund (Exhibit "G ") as part of this 2011 Rate Study. Projected
revenue from existing rates is estimated to total approximately $7.03 million in 2012. A
financial comparison of the existing electric rate revenue with those proposed to be in effect by
2015 is attached and labeled Exhibit "H ".
ENVIRONMENTAL IMPACTS: The objective of Aspen Electric is to provide 100 percent
renewable energy by 2015 in conjunction with the goals for emissions reductions set out in the
Climate Action Plan of the City of Aspen's Canary Initiative, which was adopted in 2007. The
Climate Action Plan calls for a reduction in greenhouse gas emissions of 30 percent by 2020 and
80 percent by 2050 using 2004 levels as a comparative base.
RECOMMENDED ACTION: Staff can fully implement Alternative 1 or Alternative 2, both
consistent with Council's direction from the Phase I presentation of the Electric Rate Study in
July of 2010. Either Alternatives will produce sufficient revenue to meet annual financial
requirements identified in the City's Long Range Plan for years 2012 through 2015, with an
implementation date of November 2011.
ALTERNATIVES: Develop a rate adjustment not included in the alternatives presented at this
work session.
Exhibit A: Electric Utility Rate Study Phase 11 Draft Report dated June 8, 2011
Exhibit B: Under /Over Billing new ordinance recommendation
Exhibit C: Large Commercial Electric Rate ordinance revision recommendation
Exhibit D: Phase I Electric Rate Study
Exhibit E: Financial Comparison of Large Commercial change - -30 kW to 50 kW
Exhibit F: Electric Fund Long Range Plan
Exhibit G: Renewable Energy Fund Long Range Plan
Exhibit H: Comparison of existing Electric Rates with proposed
Page 6 of 6
City of Aspen, Colorado
Electric Utili
Rate Study Phase 11
Draft Report
July 13, 2011
•
Report Prepared By:
• • . RED ,: t.
CONSULTING
100 Fillmore Street, Suite 200
Denver, CO 80206
303.316.6500
1
Table of Contents
Contents
1. Executive Summary 1 -1
1.1. Introduction 1 -1
1.2. Definitions 1 -1
1.3. Assumptions 1 -1
1.4. Findings 1 -2
2. Cost of Service 2 -1
3. Rate Design 3 -1
3.1. Existing Rates 3 -1
3.2. Revenue from Existing Rates 3 -1
3.3. Proposed Rates 3 -1
3.3.1. Alternative 1 — Transition to Cost of Service 3 -3
3.3.2. Alternative 2 — Uniform Adjustment 3 -5
3.4. Monthly Bill Impacts 3 -7
List of Tables
Table 1 -1: Summary of Revenue Adjustments Produced by Proposed Rate
Alternatives 1 -2
Table 2 -1: Projected Revenue Requirements 2 -1
Table 2 -2: Comparison of Estimated Class Units of Service Test Year 2012 2 -2
Table 2 -3: Comparison of Class Cost of Service with Revenue under Existing Rates
Test Year 2012 2 -2
Table 3 -1: Projected 2012 Revenue from Existing Rates 3 -1
Table 3 -2: Proposed Monthly Energy Charge Blocks 3 -2
Table 3 -3: Existing and Proposed Alternative 1 Monthly Availability Charges
(Alternative 1— Transition to Cost of Service) 3 -3
Table 3-4: Existing and Proposed Alternative 1 Energy Charges (Alternative 1 —
Transition to Cost of Service) 3-4
Table 3 -5: Existing and Proposed Alternative 1 Large Commercial Demand Charges
(Alternative 1— Transition to Cost of Service) 3-4
Table 3 -6: Existing and Proposed Alternative 2 Monthly Availability Charges
(Alternative 2 — Uniform Adjustment) 3 -5
Table 3 -7: Existing and Proposed Alternative 2 Energy Charges (Alternative 2 —
Uniform Adjustment) 3 -6
Table 3 -8: Existing and Proposed Alternative 2 Large Commercial Demand Charges
(Alternative 2 — Uniform Adjustment) 3 -6
Table 3 -9: 2012 Monthly Electric Bill for Residential Customer with 200 -amp Service
Under Existing and Proposed Alternative Rates 3 -7
Table 3 -10: 2013 -2015 Monthly Electric Bill for Residential Customer with 200 -amp
Service Under Existing and Proposed Alternative 1 Rates 3 -8
Table 3 -11: 2013 -2015 Monthly Electric Bill for Residential Customer with 200 -amp
Service Under Existing and Proposed Alternative 2 Rates 3 -9
ItELa City of Aspen, CO
CONSULTING Electric Utility Rate Study Phase II
Draft Report
1. Executive Summary
1.1. Introduction
The City of Aspen, Colorado (City) provides utility services to approximately 3,000
electric customers. The City's electric operations are self - supporting with funding for
capital and operating requirements derived primarily from electric rate revenue.
The City authorized Red Oak Consulting to complete an electric utility rate study in two
phases. Phase I of the rate study determined the effectiveness of existing rates to change
customer energy use patterns and produce adequate revenue and determined the
sufficiency of revenue from existing rates and other sources to meet 2011 revenue
requirements. The Red Oak Electric Utility Rate Study Phase 1 Draft Report dated July
16, 2010 summarized Phase I study findings.
Phase II of the rate study includes the following tasks:
• Determination of cost of providing electric service to each customer class for each
year, 2012 through 2015.
• Preparation of electric rate alternatives that produce sufficient revenue to meet annual
revenue requirements each year, 2012 through 2015.
This report summarizes Phase II findings and recommendations.
1.2. Definitions
The following terms are used throughout the report and are defined in this section.
• Cost of service means the annual expense determined through a detailed analysis of
revenue requirements and utility billing resulting in the cost of providing electric
service to each customer class.
• Community benefit class includes electric functions provided that are of benefit to the
community. These functions include street lighting, and are not specifically charged.
• Existing rates mean electric rates in effect April 2009.
1.3. Assumptions
This rate study is based on numerous assumptions. Changes in these assumptions could
have a material effect on study findings. Red Oak incorporated the following key
assumptions into the study:
City of Aspen, CO
I ; ' ' Electric Utility Rate Study Phase II 1 -1
Draft Report
Section 1
Executive Summary
• The City Long Range Plan provides annual revenue requirements for 2012 through
2015.
• Energy usage per account will decrease by 1.0% per year.
• Growth in electric accounts is 1.0% per year.
• The Large Commercial class consists of customers who meet the City's proposed
instantaneous demand criteria of 50 kW.
1.4. Findings
Principal findings of the electric rate study are as follows:
• Red Oak conducted a comprehensive electric utility cost of service analysis in
accordance with industry standard methods.
• Red Oak designed proposed rates to produce sufficient revenue to meet annual revenue
requirements identified in the City's long range plan. Two rate alternatives are
proposed:
• Alternative 1 (Cost of Service Transition) - Provides initial transition to class
cost of service rates over four -year period.
• Alternative 2 (Uniform Adjustment) - Increases rates by uniform percentage
amount.
• Table 1 -1 compares the revenue increases produced by the proposed alternatives rate
adjustments for each customer class. Each alternative is designed to recovery a similar
revenue amount to stabilize the long range plan.
Table 1 - 1:
Summary of Revenue Adjustments Produced
by Proposed Rate Alternatives
Revenue Adjustments 4 Year Summary
Description 2012 2013 2014 2015 Total Average
Alternative 1 - Cost of Service
Transition
Residential 4.9% 5.0% 3.0% 2.5% 16.1% 4.0%
Small Commercial 4.4% 0.0% 0.0% 0.0% 4.4% 1.1%
Large Commercial 4.9% 1.5% 1.0% 0.5% 7.9% 2.0%
City Facilities 4.9% 4.5% 2.0% 1.5% 13.6% 3.4%
Alternative 2 - Uniform Adjustment
Residential 4.6% 2.0% 1.0% 1.0% 8.6% 2.2%
Small Commercial 4.6% 2.0% 1.0% 1.0% 8.6% 2.2%
Large Commercial 4.6% 2.0% 1.0% 1.0% 8.6% 2.2%
City Facilities 4.6% 2.0% 1.0% 1.0% 8.6% 2.2%
City of Aspen, CO
Electric Utility Rate Study Phase II 1 -2
1 Draft Report
2. Cost of Service
Red Oak analyzed the cost of providing electric service to each customer class for each
year, 2012 — 2015. The electric utility customer class includes residential, small
commercial, large commercial, City facilities, and community benefit.
Red Oak Class determined class cost of service in accordance with industry standards
through a two -step process:
• Step 1 - Allocate annual revenue requirements to functional cost components of energy,
demand, and customer. Table 2 -1 summarizes annual revenue requirements shown in
the City's Long Range Plan.
Table 2 -1:
Projected Revenue Requirements
Revenue Requirement 2012 2013 2014 2015
Operating Expenditures
Wholesale Power $2,570,948 $2,686,641 $2,283,630 $2,325,745
Wind Power Purchase 1,031,971 1,042,290 1,052,713 1,063,240
Renewable Energy 508,012 525,458 972,626 988,916
Other 1,085, 932 1,120,487 1,157,055 1,197,898
Total Operating Expenditures $5,196,863 $5,374,876 $5,466,024 $5,575,799
AMP Expenditures 1,585,995 562,075 1,129,825 464,825
Franchise Fee 279,455 285,044 287,894 450,000
Transfers To Other Funds 637,846 665,075 676,716 688,748
Subtotal $7,700,159 $6,887,070 $7,560,459 $7,179,372
Less: Other Current Revenue (38,831) (35,363) (54,796) (56,860)
Changes in Fund Balance (306,313) 646,721 67,749 526,635
Total Revenue Requirements $7,355,014 $7,498,428 $7,573,413 $7,649,147
City of Aspen, CO
• .:: RFC Electric Draft Report Utility Rate Study Phase 11 2 -1
CC-N1Sl IITIf\('
Section 2
Cost of Service
• Step 2 - Allocate functionalized costs to customer classes in proportion to class units of
service (energy, demand, and equivalent 100 -amp services). Table 2 -2 summarizes
estimated 2012 class units of service.
Table 2 -2:
Comparison of Estimated Class Units of Service
Test Year 2012
Equivalent
Energy Demand 100 -amp
Class (kWh) (kW) Accounts Services
Residential 20,974,988 78,052 1,927 3,895
Small Commercial 33,460,191 95,303 1,022 2,537
Large Commercial 7,578,948 18,340 15 231
City Facilities 4,178,977 11,170 26 121
Community Benefit 702,214 2,836 5 10
Total 66,415,189 205,701 2,995 6,794
Table 2 -3 summarizes the findings of the cost of service analysis by comparing class cost
of service with revenue under existing rates. Community benefit costs are reallocated to
small and large commercial customer classes proportional to their cost of service.
Table 2 -3:
Comparison of Class Cost of Service with Revenue under Existing Rates
Test Year 2012
Revenue
Under Community Adjusted Indicated
Existing Cost of Benefit Cost of Percent
Class Rates Service Reallocation Service Adjustment
Residential $2,213,472 $2,665,926 $ 0 $2,665,926 20.4%
Small Commercial 3,768,566 3,433,755 140,073 3,573,828 (5.2 %)
Large Commercial 691,045 693,203 28,278 721,480 4.4%
City Facilities 357,336 393,780 0 393,780 10.2%
Community Benefit 0 168,351 (168,351) 0 0.0%
Total $7,030,420 $7,355,014 $ 0 $7,355,014 4.6%
City of Aspen, CO
Electric Utility Rate Study Phase II 2 -2
Draft Report
3.1. Existing Rates 3. Rate Design
Existing rates have been in effect since April 2009. The rates include availability, energy
and demand charges. The existing availability charge varies by service size and applies to
all classes. Energy charges for residential and small commercial customers use a four -
block increasing rate structure. Energy charges for large commercial customers use a
single tier rate structure. Large commercial customers have instantaneous demands of 30
kW. The demand charge is applicable to large commercial customers only.
3.2. Revenue from Existing Rates
Projected revenue from existing rates will total approximately $7.03 million in 2012.
Table 3 -1 summarizes projected 2012 availability, energy and demand charge revenue
from existing rates for each customer class.
Table 3 -1:
Projected 2012 Revenue from Existing Rates
Availability Energy Demand Percent of
Class Charge Charge Charge Total Total
Residential $237,297 $1,976,175 $0 $2,213,472 31.5%
Small Commercial 146,969 3,621,598 0 3,768,566 53.6%
Large Commercial 5,007 576,000 110,038 691,045 9.8%
City Facilities 6,302 351,034 0 357,336 5.1%
Total $395,576 $6,524,807 $110,038 $7,030,420 100.0%
3.3. Proposed Rates
Red Oak designed proposed rates to produce sufficient revenue to meet annual revenue
requirements. Two rate alternatives are proposed:
• Alternative 1 (Cost of Service Transition) - Provides initial transition to class cost of
service rates over four -year period.
• Alternative 2 (Uniform Adjustment) - Increases rates by uniform percentage amount.
City of Aspen, CO
Electric Utility Rate Study Phase II 3 -1
Draft Report
1
Section 3
Rate Design
Proposed energy charges for residential and small commercial customers use the existing
four -block increasing rate structure. Proposed energy charges for large commercial
customers use a revised two -block increasing rate structure. Proposed energy charges for
city facilities customers use a single tier rate structure. Table 3 -2 shows the proposed
energy blocks for each customer class and service size.
Residential customers are primarily 100 and 200 amp customers, with 13.9% at 100 amp
service and 80.6% at 200 amps. Small commercial customers are also primarily 100 and
200 amp customers, with 19.7% at 100 amp service and 68.7% at 200 amps.
Table 3 -2:
Proposed Monthly Energy Charge Blocks
Rate Service Size (amps)
Block 100 200 300 400 600 800 1200 1600 1800 2000+
Residential (kWh) - Same as Existing
Block 1 500 650 2,000 2,000 3,500 3,500 3,500 3,500 3,500 3,500
Block 2 850 1,050 2,500 2,500 3,300 3,300 3,300 3,300 3,300 3,300
Block 3 1,050 1,800 3,200 3,200 4,200 4,200 4,200 4,200 4,200 4,200
Block 4 >2,400 >3,500 >7,700 >7,700 >11,000 >11,000 >11,000 >11,000 >11,000 >11,000
Small Commercial (kWh) - Same as Existing
Block 1 1,100 1,600 4,200 4,200 8,200 14,000 17,000 17,000 17,000 17,000
Block 2 1,800 2,300 4,700 4,700 8,300 37,500 18,000 18,000 18,000 18,000
Block 3 3,100 3,300 6,400 6,400 6,500 48,500 21,000 21,000 21,000 21,000
Block 4 >6,000 >7,200 >15,300 >15,300 >23,000 >100,000 >56,000 >56,000 >56,000 >56,000
Large Commercial (kWh) - Proposed Revision
Block 1 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 63,000
Block 2 >29,000 >29,000 >29,000 >29,000 >29,000 >29,000 >29,000 >29,000 >29,000 >63,000
City Facilities (kWh) - Proposed Revision
Block 1 All All All All All All All All All All
City of Aspen, CO
Electric Utility Rate Study Phase II 3 -2
Draft Report
• Section 3
• Rate Design
3.3.1. Alternative 1 - Transition to Cost of Service
It is common practice for utilities to transition to cost of service rates over a multi -year
period to mitigate customer bill impacts. Alternative 1 rates will increase revenues to
meet the City's long term plan revenue requirements for years 2012 through 2015 and
improve the equitability of the rates. For example, residential customers recover 83.0%
of their cost of service under existing rates in 2012. Their recovery of cost of service
improves to 92.0% under proposed Alternative 1 rates in 2015. Small Commercial
recovery is 105.9% by 2015, and Large Commercial and City Facilities is 100 %. Under
alternative 1 rates it is projected that class cost of service will be met in 2017.
Alternative 1 rates are comprised of availability, energy and demand charges. Table 3 -3
compares existing and proposed Alternative 1 monthly availability charges.
Table 3 -3:
Existing and Proposed Alternative 1
Monthly Availability Charges
(Alternative 1- Transition to Cost of Service)
Proposed Transition to Cost of Service Rates
Service Size Existing
Rates 2012 2013 2014 2015
(amps) (per bill) (per bill) (per bill) (per bill) (per bill)
100 $ 5.20 $ 6.25 $ 7.50 $ 9.00 $ 10.80
200 10.40 12.50 15.00 18.00 21.60
300 15.60 23.44 28.13 33.75 40.50
400 20.80 31.25 37.50 45.00 54.00
600 31.20 46.88 56.25 67.50 81.00
800 41.60 62.50 75.00 90.00 108.00
1000 52.00 78.13 93.75 112.50 135.00
1200 62.40 93.75 112.50 135.00 162.00
1600 83.20 125.00 150.00 180.00 216.00
1800 93.60 140.63 168.75 202.50 243.00
2000 104.00 156.25 187.50 225.00 270.00
Energy charges use the energy charge structure shown in Table 3 -2 and recover energy
I related costs. Table 3 -4 compares existing and proposed Alternative 1 energy charges.
The size of each block varies with the amperage size and is shown in Table 3 -2.
City of Aspen, CO
i:I l Electric Utility Rate Study Phase II 3 -3
Draft Report
Section 3
Rate Design
Table 3 -4:
Existing and Proposed Alternative 1 Energy Charges
(Alternative 1- Transition to Cost of Service)
Existing Proposed Transition to Cost of Service Rates
Rate Block Rates
2012 2013 2014 2015
(per kWh) (per kWh) (per kWh) (per kWh) (per kWh)
Residential
First Block $0.0660 $0.0678 $0.0697 $0.0693 $0.0678
Second Block 0.0957 0.0983 0.1011 0.1005 0.0983
Third Block 0.1436 0.1475 0.1517 0.1508 0.1475
Fourth Block 0.2153 0.2213 0.2276 0.2262 0.2213
Small Commercial
First Block $0.0840 $0.0871 $0.0862 $0.0846 $0.0828
Second Block 0.1008 0.1045 0.1034 0.1015 0.0994
Third Block 0.1512 0.1568 0.1551 0.1523 0.1491
Fourth Block 0.2268 0.2352 0.2327 0.2285 0.2237
Large Commercial
First Block $0.0760 $0.0728 $0.0713 $0.0687 $0.0662
Second Block 0.0760 0.0910 0.0891 0.0859 0.0828
City Facilities
All Energy $0.0840 $0.0876 $0.0912 $0.0920 $0.0924
Demand charges are assessed to commercial customers with instantaneous demands of at
least 50 kW. Table 3 -5 compares existing and proposed Alternative 1 demand charges.
Table 3 -5:
Existing and Proposed Alternative 1
Large Commercial Demand Charges
(Alternative 1- Transition to Cost of Service)
Large Existing Proposed Transition to Cost of Service Rates
Commercial Rates 2012 2013 2014 2015
(per kW) (per kW) (per kW) (per kW) (per kW)
All Demand $6.00 $7.00 $8.00 $9.00 $9.70
City of Aspen, CO
Electric Utility Rate Study Phase II 3-4
Draft Report
Section 3
Rate Design
3.3.2. Alternative 2 - Uniform Adjustment
Uniform rates reflect consistent percentage adjustments to each class' rates. These rates
will generate sufficient revenue to meet the City's long range plan revenue requirements
for years 2012 through 2015. Tables 3 -6, 3 -7 and 3 -8 compare existing and proposed
Alternative 2 availability, energy and demand charges, respectively.
Table 3 -6:
Existing and Proposed Alternative 2
Monthly Availability Charges
(Alternative 2 - Uniform Adjustment)
Service Size Existing 2012 2013 2014 2015
Rates
(amps) (per bill) (per bill) (per bill) (per bill) (per bill)
100 $ 5.20 $ 5.45 $ 5.55 $ 5.57 $ 5.60
200 10.40 10.90 11.10 11.14 11.20
300 15.60 16.35 16.65 16.71 16.80
400 20.80 21.80 22.20 22.28 22.40
600 31.20 32.70 33.30 33.42 33.60
800 41.60 43.60 44.40 44.56 44.80
1000 52.00 54.50 55.50 55.70 56.00
1200 62.40 65.40 66.60 66.84 67.20
1600 83.20 87.20 88.80 89.12 89.60
1800 93.60 98.10 99.90 100.26 100.80
2000 104.00 109.00 111.00 111.40 112.00
City of Aspen, CO
Electric Utility Rate Study Phase II 3 -5
Draft Report
Section 3
Rate Design
Table 3 -7:
Existing and Proposed Alternative 2 Energy Charges
(Alternative 2 - Uniform Adjustment)
Rate Block Existing 2012 2013 2014 2015
Rates
(per kWh) (per kWh) (per kWh) (per kWh) (per kWh)
Residential
First Block $0.0660 $0.0690 $0.0703 $0.0707 $0.0710
Second Block 0.0957 0.1001 0.1020 0.1025 0.1030
Third Block 0.1436 0.1502 0.1530 0.1538 0.1545
Fourth Block 0.2153 0.2253 0.2295 0.2307 0.2318
Small Commercial
First Block $0.0840 $0.0879 $0.0895 $0.0900 $0.0904
Second Block 0.1008 0.1055 0.1074 0.1079 0.1084
Third Block 0.1512 0.1583 0.1611 0.1619 0.1626
Fourth Block 0.2268 0.2375 0.2417 0.2429 0.2439
Large Commercial
First Block $0.0760 $0.0745 $0.0758 $0.0761 $0.0764
Second Block 0.0760 0.0931 0.0948 0.0951 0.0955
City Facilities
First Block $0.0840 $0.0876 $0.0893 $0.0898 $0.0901
Table 3 -8:
Existing and Proposed Alternative 2
Large Commercial Demand Charges
(Alternative 2- Uniform Adjustment)
Large Existing 2012 2013 2014 2015
Commercial Rates
(per kW) (per kW) (per kW) (per kW) (per kW)
All Demand $6.00 $6.28 $6.40 $6.43 $6.46
City of Aspen, CO
Electric Utility Rate Study Phase II 3 -6
Draft Report
Section 3
Rate Design
3.4. Monthly Bill Impacts
Table 3 -9 compares typical monthly residential electric bills under existing and proposed
alternative 2012 rates. The average residential customer has an amperage size of 200
amps and uses 700 kWh monthly.
Table 3 -9:
2012 Monthly Electric Bill for Residential Customer with 200 -amp Service
Under Existing and Proposed Alternative Rates
Alternative 1 Rates
Transition to Cost Alternative 2 Rates
Billable of Service Uniform Adjustment
Monthly Existing 2012 2012
Usage Rates Amount Change Amount Change
(kWh) $ $ $ $ $
0 10.40 12.50 2.10 10.90 0.50
100 17.00 19.28 2.28 17.80 0.80
200 23.60 26.06 2.46 24.71 1.11
300 30.20 32.84 2.64 31.61 1.41
400 36.80 39.62 2.82 38.52 1.72
500 43.40 46.40 3.00 45.42 2.02
600 50.00 53.18 3.18 52.33 2.33
700 58.09 61.49 3.40 60.79 2.70
800 67.66 71.32 3.66 70.80 3.14
900 77.23 81.15 3.92 80.81 3.58
1,000 86.80 90.98 4.18 90.82 4.02
1,100 96.37 100.81 4.44 100.83 4.46
1,200 105.94 110.64 4.70 110.84 4.90
1,300 115.51 120.47 4.96 120.85 5.34
1,400 125.08 130.30 5.22 130.86 5.78
1,500 134.65 140.13 5.48 140.87 6.22
1,600 144.22 149.96 5.74 150.88 6.66
1,700 153.79 159.79 6.00 160.89 7.10
1,800 168.14 174.54 6.39 175.91 7.77
1,900 182.50 189.29 6.79 190.93 8.43
2,000 196.85 204.04 7.18 205.95 9.10
City of Aspen, CO
• REts)' ', N. Electric Utility Rate Study Phase II 3 -7
• • . coNSIJLI'IN. Draft Report
Section 3
Rate Design
Table 3 -10 compares typical monthly residential electric bills under existing and
proposed alternative 1 rates for 2013 through 2015.
Table 3 -10:
2013 -2015 Monthly Electric Bill for Residential Customer with 200 -amp
Service Under Existing and Proposed Alternative 1 Rates
Billable Alternative 1 Rates Transition to Cost of Service
Monthly Existing 2013 2014 2015
Usage Rates Amount Change Amount Change Amount Change
(kWh) $ $ $ $ $ $ $
0 10.40 15.00 4.60 18.00 7.60 21.60 11.20
100 17.00 21.97 4.97 24.93 7.93 28.38 11.38
200 23.60 28.94 5.34 31.86 8.26 35.16 11.56
300 30.20 35.91 5.71 38.79 8.59 41.94 11.74
400 36.80 42.88 6.08 45.72 8.92 48.72 11.92
500 43.40 49.85 6.45 52.65 9.25 55.50 12.10
600 50.00 56.82 6.82 59.58 9.58 62.28 12.28
700 58.09 65.36 7.28 68.07 9.98 70.59 12.50
800 67.66 75.47 7.82 78.12 10.47 80.42 12.76
900 77.23 85.58 8.35 88.17 10.95 90.25 13.02
1,000 86.80 95.69 8.89 98.22 11.43 100.08 13.28
1,100 96.37 105.80 9.43 108.27 11.91 109.91 13.54
1,200 105.94 115.91 9.97 118.32 12.39 119.74 13.80
1,300 115.51 126.02 10.52 128.37 12.87 129.57 14.06
1,400 125.08 136.13 11.06 138.42 13.35 139.40 14.32
1,500 134.65 146.24 11.60 148.47 13.83 149.23 14.58
1,600 144.22 156.35 12.14 158.52 14.31 159.06 14.84
1,700 153.79 166.46 12.68 168.57 14.79 168.89 15.10
1,800 168.14 181.63 13.49 183.65 15.51 183.64 15.50
1,900 182.50 196.80 14.31 198.73 16.24 198.39 15.89
2,000 196.85 211.97 15.12 213.81 16.96 213.14 16.29
City of Aspen, CO
RED Electric Report Ut ilit y Rate Study Phase 11 3 -8
• - CC)NSU LTI Draft Nv
Section 3
Rate Desig n
Table 3 -11 compares typical monthly residential electric bills under existing and
proposed alternative 2 rates for 2013 through 2015.
Table 3 -11:
2013 -2015 Monthly Electric Bill for Residential Customer with 200 -amp
Service Under Existing and Proposed Alternative 2 Rates
Billable Alternative 2 Rates Uniform Adjustment
Monthly Existing 2013 2014 2015
Usage Rates Amount Change Amount Change Amount Change
(kWh) $ $ $ $ $ $ $
0 10.40 11.10 0.70 11.14 0.74 11.20 0.80
100 17.00 18.13 1.13 18.21 1.21 18.30 1.30
200 23.60 25.17 1.57 25.28 1.68 25.40 1.80
300 30.20 32.20 2.00 32.34 2.14 32.50 2.30
400 36.80 39.24 2.44 39.41 2.61 39.60 2.80
500 43.40 46.27 2.87 46.48 3.08 46.70 3.30
600 50.00 53.31 3.31 53.55 3.55 53.80 3.80
700 58.09 61.93 3.84 62.21 4.12 62.50 4.42
800 67.66 72.13 4.47 72.46 4.80 72.80 5.15
900 77.23 82.33 5.10 82.71 5.48 83.10 5.88
1,000 86.80 92.53 5.73 92.96 6.16 93.40 6.61
1,100 96.37 102.73 6.36 103.21 6.84 103.70 7.34
1,200 105.94 112.93 6.99 113.46 7.52 114.00 8.07
1,300 115.51 123.13 7.62 123.71 8.20 124.30 8.80
1,400 125.08 133.33 8.25 133.96 8.88 134.60 9.53
1,500 134.65 143.53 8.88 144.21 9.56 144.90 10.26
1,600 144.22 153.73 9.51 154.46 10.24 155.20 10.99
1,700 153.79 163.93 10.14 164.71 10.92 165.50 11.72
1,800 168.14 179.23 11.09 180.09 11.95 180.95 12.81
1,900 182.50 194.53 12.03 195.47 12.97 196.40 13.91
2,000 196.85 209.83 12.98 210.85 14.00 211.85 15.00
City of Aspen, CO
Electric Utility Rate Study Phase II 3 -9
Draft Report
Exhibit B — Under /Over Billing — New Ordinance Recommendation
Proposed Municipal Code for Electric and Water Departments
Sec. 25.04.130 (Electric) Sec. 25.16.100 (Water)
(a) When an error has been made in a utility account, the following shall apply:
Each utility customer is responsible for using reasonable diligence to review
billing statements and for immediately notifying the utility of a billing error.
(1) When the utility determines that a utility customer has overpaid for utility service
and the overpayment occurred no more than twenty -four (24) months before the
date the error is made know to the utility, the utility will issue to the customer a
credit to the Customer's account without interest, as reimbursement for the
overpayment.
Previous Customer accounts at same service location will be reviewed to
determine if they were affected by the overbilling. If it is determined that an
overbilling affected a previous Customer with the twenty -four month period as
described herein, reasonable efforts will be made to locate the Customer and
refund any amounts owed due to the overbilling.
Any refund check mailed to the last known address of the Customer and returned
unpaid to the City or not cashed by the Customer within two (2) years of either
the date of delivery or mailing of the check, will be retained by the City and will
be credited as miscellaneous revenue for the utility service which was overpaid.
Prior to final determination of an overbilling refund credit or refund, each of the
following conditions must be met:
a. the customer could not have discovered the error with reasonable inquiry
prior to the date of discovery;
b. documentation evidencing the overpayment is available in utility records
or has been provided to the utility; and
c. The utility confirms the accuracy and sufficiency of the documentation
based on utility records.
d. The overbilling is not the result of changes, modifications, updates, or
alterations by the Customer or its agent that affects the metering accuracy,
multiplier, or other metering components without evidence of prior
notification to and approval of the Utility.
(2) When the Utility determines that a current utility customer has been undercharged
and has underpaid for utility service, the customer shall be billed for the correct
amount unless the undercharges occurred more than six (6) months before the
date the error is discovered and the following conditions are met:
a. The customer could not have discovered the error with reasonable inquiry.
b. Each utility customer is responsible for using reasonable diligence to
review billing statements and for immediately notifying the utility of a
billing error.
c. Bills for corrected usage and other utility rate code charges shall be due
and payable in the same manner as regular bills for service.
In the event of an inaccurate billing due to the diversion or theft of utility service,
the City retains the right to back bill for the entire period of occurrence.
(3) Any attempt or action by a utility customer to mislead the utility with regard to a
billing error shall be a violation of code, punishable by fine as provided for
wherein. Each day upon which any violation shall continue shall constitute a
separate offense, punishable as such. Additionally, the Utility reserves the right to
pursue other compensation or charges to the fullest extent of the law.
EXHIBIT C - ELECTRIC RATE STUDY PHASE II
LARGE COMMERCIAL ELECTRIC RATE ORDINANCE REVISION
RECOMMENDATION
CURRENT ORDINANCE
Sec. 25.04.040. Electric service rates.
(xv) The retail service rate for large commercial customers, with operable demand metering
systems in place and measured usage of thirty (30) kW and greater, shall be $0.0760 per kWh for
metered usage plus a demand charge of $6.00 per kW of metered peak usage for that meter
reading cycle.
PROPOSED ORDINANCE
Sec. 25.04.040. Electric service rates.
(xv) Effective November 2011, the retail service rate for large commercial customers, with operable
demand metering sytems in place and measured annual average monthly usage of forty (40) kW
and greater, shall be $0.0752 for the first block of metered usage and $0.0940 for the second block
of metered usage plus a demand charge of $7.00 per kW of metered peak usage for that meter
reading cycle. Effective November 2012, the retail service rate for large commercial customers,
with operable demand metering systems in place and measured annual average monthly usage of
fifty (50) kW and greater, shall be $0.0742 for the first block of metered usage and $0.0928 for the
second block of metered usage plus a demand charge of $8.00 per kW of metered peak usage for
that meter reading cycle.
City of Aspen, Colorado
Electric Utility
Rate Stud y Phase 1
Draft Report
July 16, 2010
Report Prepared By
y CONSULTING
A O:VISION OF MALCOLM PI4N1[
100 Fillmore Street
Suite 200
Denver, CO 80206
5557004 (303)316 -6500
Table of Contents
Contents
1. Rate Study Phase 1 1 -1
1.1. Introduction 1 -1
1.2. Existing Rates 1 -1
1.2.1. Availability Charges 1 -2
1.2.2. Energy Charges 1 -2
1.2.3. Demand Charge 1 -2
1.3. Customer Class Service Characteristics 1 -3
1.3.1. Customer Accounts 1 -3
1.3.2. Energy 1 -3
1.3.3. Load Factors 1-4
1.4. Residential and Small Commercial Energy Use Analysis 1-4
1.5. 2009 Rate Revenue Comparison 1 -5
1.6. 2011 Revenue Requirements 1 -5
1.7. 2011 Revenue from Existing Rates 1 -6
1.8. 2011 Additional Revenue Needed 1 -7
1.9. Rate Adjustment Considerations 1 -7
1.10. Phase II Services 1 -8
List of Tables
Table 1 -1. Existing Monthly Availability Charges 1 -2
Table 1 -2. Existing Energy Charges (per kWh) 1 -2
Table 1 -3. Historical Number of Customer Accounts 1 -3
Table 1-4. Historical Energy Use (kWh) 1 -3
Table 1 -5. Customer Class 2009 Load Factors 1-4
Table 1 -6. Comparison of 200 -Amp Residential Energy Use for 2008 and 2009 1-4
Table 1 -7. Comparison of 200 -Amp Small Commercial Energy Use for 2008 and 2009 1 -5
Table 1 -8. Projected 2011 Revenue Requirements 1 -6
Table 1 -9. Projected 2011 Revenue from Existing Rates 1 -6
Table 1 -10. Additional 2011 Revenue Needed 1 -7
Appendices
A. Revenue Requirements and Bill Frequency Analysis
A -1. Revenue Requirements
A -2. Revenue Requirements Summary
A -3. Small Commercial Bill Frequency Analysis
A-4. Residential Bill Frequency Analysis
A -5. 2009 Revenue Comparison by Customer Class
::• REI3DAK City of Aspen, Colorado
• • •• CONSULTING Electric Utility Rate Study Phase I
•
1. Rate Study Phase 1
1.1. Introduction
The City of Aspen, Colorado provides utility services to approximately 2,900 electric
customers. The City's electric operations are self - supporting with funding for capital and
operating requirements derived primarily from rates.
The City authorized Red Oak Consulting to complete Phase I of the rate study to:
• Determine the effectiveness of existing rates to change customer energy use
patterns and produce adequate revenue.
• Determine if revenue from existing rates (effective April 2009) and other sources
is sufficient to meet 2011 revenue requirements.
This report summarizes Phase I findings and recommendations.
1.2. Existing Rates
Existing rates went into effect in April 2009. The rates include availability, energy and
demand charges and contained several structure changes designed to encourage energy
conservation:
• Availability charge structure changed from a charge that varied by customer class
to a charge that varied by transformer size.
• Residential energy charge structure changed from three -block to four -block
increasing energy charge and the block sizes vary by transformer size.
• Small commercial energy charge structure changed from uniform charge to four -
block increasing energy charge and the block sizes vary by transformer size.
Section 1.4 of this report describes changes in residential and small commercial energy
use since existing rates became effective. These customers are generally using less
energy. This is causing a gradual shift in energy use to the lower - priced rate blocks.
• • • ; REBDA K City of Aspen, Colorado
• CONSULTING Electric Utility Rate Study Phase I 1 -1
.,..,., .,„....,.,, Draft Report
Section 1 .
Rate Study Phase 1
1.2.1. Availability Charges
The existing availability charge varies by transformer size and applies to all classes.
Table 1 -1 shows existing monthly availability charges.
Table 1 - 1.
Existing Monthly Availability Charges
Transformer Size
(amps) Amount
100 $ 5.20
200 10.40
300 15.60
400 20.80
600 31.20
800 41.60
1000 52.00
1200 62.40
1600 83.20
1.2.2. Energy Charges
Existing energy charges for residential and small commercial customers use a four -block
increasing rate structure. The size of each block is specific to the transformer size.
Energy charges for large commercial and City electric customers use a uniform rate
structure. Table 1 -2 summarizes existing energy charges.
Table 1 -2.
Existing Energy Charges (per kWh)
Rate Small Large
Block Residential Commercial Commercial City Electric
1 $0.0660 $0.0840 $0.0760 $0.0840
2 0.0957 0.1008 0.0760 0.0840
3 0.1436 0.1512 0.0760 0.0840
4 0.2153 0.2268 0.0760 0.0840
1.2.3. Demand Charge
The existing demand charge is assessed to large commercial customers that meet or
exceed 30 kW instantaneous demand. The existing demand charge is $6.00 per kW of
metered peak usage.
• • •' REBDA K City of Aspen, Colorado • • 4. CONSULTING Electric Utility Rate Study Phase I 1 -2
4,.,4,04 y. .,.<G., aR.,( Draft Report
Section 1
Rate Study Phase 1
1.3. Customer Class Service Characteristics
Red Oak analyzed customer billing data for each customer class. This analysis was used
to forecast revenue under existing rates and determine the following class electric service
characteristics:
EI Number of accounts by transformer size
Energy usage by rate block
Demand load factors
1.3.1. Customer Accounts
Table 1 -3 summarizes the historical number of customer accounts served in each class
during 2007 through 2009. Ninety new residential and small commercial accounts were
added in 2008 and 2009. Residential customers represent about two- thirds of the total
number of electric customers.
Table 1 - 3.
Historical Number of Customer Accounts
Class 2007 2008 2009 2009
Residential 1,800 1,837 1,870 64.6%
Small Commercial 948 957 967 33.4%
Large Commercial 42 42 42 1.5%
City Electric 12 12 12 0.5%
Total 2,802 2,848 2,892 100.0%
1.3.2. Energy
Table 1 -4 summarizes the historical amount of energy used by each class during 2007
through 2009. The 2009 energy use was the lowest of the three years. Small commercial
class customers used nearly half of the total annual energy.
Table 1
Historical Energy Use (kWh)
Class 2007 2008 2009 2009
Residential 20,029,008 21,872,769 21,193,214 33.7%
Small Commercial 30,834,185 32,020,283 30,657,135 48.8%
Large Commercial 11,249,929 11,187,187 9,846,611 15.7%
City Electric 1,343,887 1,411.482 1,163,853 1.8%
Total 63,457,009 66,491,721 62,860,813 100.0%
•' .: ; REII AK City of Aspen, Colorado
• • • CONSULTING Electric Utility Rate Study Phase I 1 -3
.,.,,............... Draft Report
Section 1
Rate Study Phase I
1.3.3. Load Factors
The load factor is the quotient of the class average month demand divided by peak month
demand. Load factors close to 1.0 represent consistent energy demands throughout the
year. Load factors well below 1.0 represent varying energy demands throughout the year.
Table 1 -5 compares 2009 class load factors.
Table 1 - 5.
Customer Class 2009 Load Factors
Class Load Factor
Residential 0.61
Small Commercial 0.76
Large Commercial 0.80
City Electric 0.72
Total System 0.70
1.4. Residential and Small Commercial Energy Use Analysis
Red Oak completed a bill frequency analysis of 2009 residential and small commercial
bills for each transformer size. This analysis shows the number of monthly bills at
various levels of energy usage. Tables A -3 and A -4 in Appendix A show the 2009 bill
frequency analysis for the small commercial and residential classes, respectively.
Residential customers with 200 -amp meters represent 80% of residential accounts and
purchase 72% of residential energy. Red Oak did a separate bill frequency comparison of
these accounts for 2008 to identify changes in customer usage patterns. Table 1 -6
summarizes this information and shows that annual energy use decreased by 3.1%.
Coincidentally, the percent of total energy decreased in Blocks 3 and 4 and increased in
Blocks 1 and 2. Red Oak recommends the City annually update this analysis to monitor
usage patterns.
Table 1 - 6.
Comparison of 200 -Amp Residential Energy Use for 2008 and 2009
Rate Energy Use (kWh) Percent of Total kWh
Block 2008 2009 Variance 2008 2009
1 7,649,209 7,731,487 48.7% 50.8%
2 4,542,344 4,470,322 28.9% 29.4%
3 2,383,661 2,173,594 15.2% 14.3%
4 1,126,694 844,244 7.2% 5.5%
Total 15,701,908 15,219,647 (3.1 %) 100.0% 100.0%
•' :: • REIIDA K City of Aspen, Colorado
• CONSULTING Electric Utility Rate Study Phase I 1-4
Section 1
Rate Study Phase 1
Small commercial customers with 200 -amp meters represent 71% of small commercial
accounts and purchase 46% of small commercial energy. Red Oak did a separate bill
frequency comparison of these accounts for 2008 to identify changes in customer usage
patterns. Table 1 -7 summarizes this information and shows that annual energy use
decreased by 10.5 %. Coincidentally, the percent of total energy decreased in Blocks 3
and 4 and increased in Blocks 1 and 2. Red Oak recommends the City annually update
this analysis to monitor usage patterns.
Table 1 - 7.
Comparison of 200 -Amp Small Commercial Energy Use for 2008 and 2009
Rate Energy Use (kWH) Percent of Total kWh
Block 2008 2009 Variance 2008 2009
1 7,829,282 7,489,490 50.0% 53.5%
2 4,440,307 4,021,497 28.4% 28.7%
3 2,279,403 1,799,569 14.6% 12.8%
4 1.100,156 699.853 7.0% 5.0%
Total 15,649,148 14,010,409 (10.5 %) 100.0% 100.0%
1.5. 2009 Rate Revenue Comparison
During its previous electric rate study, Red Oak projected that 2009 revenue would total
$6,670,880 assuming these rates were fully effective the entire year. Using actual 2009
billing units, revenue from existing electric rates totaled $6,788,064 assuming these rates
were fully effective the entire year. The adjusted actual 2009 revenues were about
$117,000 greater than projected 2009 revenues. Table A -5 in Appendix A compares
projected and adjusted actual 2009 revenues by customer class.
1.6. 2011 Revenue Requirements
Per the City's long range plan, electric utility 2011 revenue requirements total $7,717,690
and include operating expenditures, asset management plan (AMP), franchise fees, and
transfers to other City funds. Table 1 -8 summarizes 2011 revenue requirements. Table A-
1 in Appendix A shows a more detailed list of 2011 revenue requirements.
•
.• • • CONSULT! K ElectncU Aspen, Colorado
Rate Study Phase I 1 -5
• • • CONSULTING Draft Report
Section 1
Rate Study Phase I
Table 1-8.
Projected 2011 Revenue Requirements
Item Annual Cost
Operating Expenditures
Wholesale Power $1,715,647
Wind Power Purchase 1,021,754
Renewable Energy Program 561,297
Other 1.077,435
Total Operating Expenditures $4,376,133
AMP Expenditures 2,127,500
Franchise Fee 460,054
Transfers To Other Funds 754.003
Total 2011 Revenue Requirements $7,717,690
1.7. 2011 Revenue from Existing Rates
Projected 2011 revenue from existing rates totals $6,986,513 and includes availability,
energy and demand charge revenue from each customer class. Small commercial
customers are expected to generate over half of the revenue. Table 1 -9 summarizes
projected 2011 electric revenue by class.
Revenue from existing rates is the product of existing rates and 2011 projected billing
units. Existing rates are described in Section 1.6 of the report. The 2011 projected billing
units are based on 2009 actual billing units adjusted for assumed annual growth in the
number of customer accounts of 2% and assumed annual reduction in energy use per
account of 1 %.
Table 1 - 9.
Projected 2011 Revenue from Existing Rates
Availability Energy Demand
Class Charge Charge Charge Total
Residential $239,623 $2,023,217 $ 0 $2,262,840
Small Commercial 137,697 3,436,374 0 3,574,071
Large Commercial 23,307 755,676 154,490 933,473
City Electric 3.506 212.623 0 216.129
Total $404,133 $6,427,890 $154,490 $6,986,513
RE13DA K City of Aspen, Colorado
• :' CONSULTING Electric Utility Rate Study Phase I 1 -6
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Section 1
Rate Study Phase 1
1.8. 2011 Additional Revenue Needed
Per the City's long range plan, projected 2011 revenue requirements will be met from
electric rate revenue, other current revenue and the fund balance. Table 1 -10 shows that
these revenue sources are insufficient to meet projected revenue requirements without an
increase in electric rates. This rate adjustment should increase annual electric rate
revenue by about $320,000.
Table 1 - 10.
Additional 2011 Revenue Needed
Item Amount
Revenue Requirements $7,717,690
Existing Revenue Sources
Existing Electric Rates $6,986,513
Other Current Revenue 57,353
Fund Balance 354.006
Total Existing Revenue Sources $7,306,331
Additional Revenue Needed from
Rate Adjustment $319,818
1.9. Rate Adjustment Considerations
In Phase I of this study, Red Oak determined the need for an annual revenue increase of
$320,000 to meet 2011 user charge revenue requirements. This increase will be produced
by an adjustment to rates.
There are several rate adjustment options to consider:
1. Status Quo. This option would not increase rates. This implies that the City would
reduce the 2011 revenue requirements by at least $320,000 through downsizing or
eliminating optional programs such as renewable energy and energy efficiency
programs.
2. Equal percentage increases. This option would increase each rate by 4.6 %. While
this option would equally affect all customers, it may not equitably recover cost of
providing electric service from each customer class.
3. Cost of service. This option would equitably recover class cost of service but may
result in uneven interclass rate adjustments.
4. Transition to cost of service. This option would transition existing rates to cost of
service rates over a multi -year period.
The City has taken the initial step toward cost of service rates through its adoption of
existing rates in April 2009. These rates provided intra -class equity through availability
and energy charge structures that vary by transformer size. If Phase II of this study is
authorized, Red Oak would determine class cost of service rates that would also create
RE1IDA K City of Aspen, Colorado
• • CONSULTING Electric Utility Rate Study Phase I 1 -7
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Section 1
Rate Study Phase 1
inter -class equity. This would allow consideration of the third and fourth rate adjustment
options.
1.10. Phase 11 Services
In Phase II of this study, Red Oak will determine the cost of providing electric service to
each customer class and design electric rates that equitably recover class cost of service.
The cost of service analysis will recognize differing service characteristics of each
customer class such as peak demand, average demand, transformer size and utility billing
requirements.
At a minimum, the cost of service analysis will be done for 2011 and may be done for a
multi -year period. It is common for utilities to transition to cost of service over a multi-
year period to mitigate rate impacts. For the multi -year option, the rates will increase
revenues to meet the long term plan revenue requirements for the years, 2011 through
2015, and will equitably recover class cost of service in 2015.
REUDAK City of Aspen, Colorado
• • •• • ' CONSULTI NG Electric Utility Rate Study Phase I 1 -8
City of Aspen Table A -1
Electric Utility
Revenue Requirements
FY2011
OPERATING EXPENDITURES
80000 - Labor 560,094
80076 - Health Insurance 67,292
81000 - Travel and Training 13,770
82340 - Wholesale Power Purchase 1,715,647
Renewable Energy Fund - Reudi 426,644
Renewable Energy Fund - Maroon 134,653
Renewable Energy - Castle 0
82370 - Windpower Purchase 1,021,754
82000 - Other Contractual Services 81,090
83000 - Equipt Maint/Supplies 100,552
80800 - Allocated Services (Overhead) 254,637
TOTAL OPERATING EXPENDITURES 4,376,133
CAPITAL EXPENDITURES
86000 - AMP Expenditure - 431 -94 2,127,500
86000 - Reappropriated Capital Projects - 2007 0
86000 - New Capital Projects 0
TOTAL CAPITAL EXPENDITURES 2,127,500
TRANSFERS OUT
Transfer to Water Fund - UB Services 307,445
Transfer to Other Funds 0
Transfer to Water Fund -1/3 of Global Warming 117,046
Transfer to Renewable Energy Fund (Capital Projects) 0
Transfer to Hydro/Renewables 444;Carbon Emission Reduction Tags 312,000
City Employee Housing Fund 17,512
One time transfer to 471 - Water Reclaimation 0
One time transfer to 340 - Water Reclaimation 0
Franchise Fee (xfer to General Fund) 460,054
TOTAL TRANSFERS OUT 1,214,057
OTHER CURRENT REVENUE
Refund of Expenditure Wind & Other 0
Sale of Cannary Tags 0
Transformer Sales 5,171
Finance Charges Electric 5,304
Inter Dept. Service 0
Connect and Disconnnect Charges 1,683
Lease Revenue 0
Investment Interest 30,079
Sale of AABC/Puppy Smith / mist revenue in Eden 0
Other Miscellaneous Revenue 4,508
Vendor's Fees 10,608
Sale of fixed assets 0
TOTAL OTHER CURRENT REVENUE 57,353
ADDITION TO FUND BALANCE (354,006)
TOTAL RATE REVENUE REQUIREMENTS 7,306,331
Draft - For Discussion Purposes Only
City of Aspen Table A -2
Electric Utility
Revenue Requirements Summary
FY2011
OPERATING EXPENDITURES
ANNUAL O &M 3,814,836
RENEWABLE ENERGY PROGRAM 561,297
CAPITAL EXPENDITURES 2,127,500
Plus: TRANSFERS OUT 1,214,057
TOTAL 7,717,690
Less: OTHER CURRENT REVENUE (57,353)
USE OF FUND BALANCE (354,006)
TOTAL ADJUSTMENTS (411,359)
TOTAL O &M AND CAPITAL RATE REVENUE REQUIREMENTS 7,306,331
2011 Projected Revenue Under Existing Rates 6,986,513
Rate Adjustment 319,818
Percent Overall Rate Adjustment 4.6%
Draft - For Discussion Purposes Only
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EXHIBIT H -- ELECTRIC RATE STUDY PHASE 11
COMPARISON OF EXISTING ELECTRIC RATES WITH PROPOSED
Table 3 - 3, 3-4, 3 -5:
Existing and Proposed Alternative 1
Monthly Demand, Availability, and Energy Charges
(Alternative 1- Transition to Cost of Service)
Existing Proposed Transition to Cost of Service Rates
Service Size Rates 2012 I 2013 I 2014 I 2015
(amps)
Demand Charge (per kW) (per kW) (per k149 (per kW) (per kW)
All $6.00 $7.00 $8.00 $9.00 $9.70
Availability Charge (per bill) (per bill) (per bill) (per bill) (per bill)
100 $5.20 $6.25 $7.50 $9.00 $10.80
200 10.40 12.50 15.00 18.00 21.60
300 15.60 23.44 28.13 33.75 40.50
400 20.80 31.25 37.50 45.00 54.00
600 31.20 46.88 56.25 67.50 81.00
800 41.60 62.50 75.00 90.00 108.00
1000 52.00 78.13 93.75 112.50 135.00
1200 62.40 93.75 112.50 135.00 162.00
1600 83.20 125.00 150.00 180.00 216.00
1800 93.60 140.63 168.75 202.50 243.00
2000 104.00 156.25 187.50 225.00 270.00
Energy Charge (per kWh) (per kWh) (per kWh) (per kWh) (per kWh)
Residential
First Block $0.0660 $0.0678 $0.0697 $0.0693 $0.0678
Second Block 0.0957 0.0983 0.1011 0.1005 0.0983
Third Block 0.1436 0.1475 0.1517 0.1508 0.1475
Fourth Block 0.2153 0.2213 0.2276 0.2262 0.2213
Small Commercial
First Block $0.0840 $0.0871 $0.0862 $0.0846 $0.0828
Second Block 0.1008 0.1045 0.1034 0.1015 0.0994
Third Block 0.1512 0.1568 0.1551 0.1523 0.1491
Fourth Block 0.2268 0.2352 0.2327 0.2285 0.2237
Large Commercial
First Block $0.0760 $0.0728 $0.0713 $0.0687 $0.0662
Second Block 0.0760 0.0910 0.0891 0.0859 0.0828
City Electric
First Block $0.0840 $0.0876 $0.0912 $0.0920 $0.0924
MEMORANDUM
TO: Mayor and City Council
FROM: Don Taylor, Director of Finance
THRU: Steve Barwick, City Manager
DATE OF MEMO: July 15th, 2011
MEETING DATE: July 18 2011
RE: Refunding 2003 General Obligation Bonds
REQUEST OF COUNCIL: This is for the City Council to consider issuance of bonds in order
to refund (pay off) bonds that were issued in 2003. The bonds issued would bear a lower interest
rate than currently paid on the outstanding 2003 bonds and therefore save the city money.
PREVIOUS COUNCIL ACTION: In 1993 the City issued General Obligation Bonds to
finance the construction of the Marolt housing project. The City subsequently issued refunding
bonds in 2003 in order to pay off the 1993 bonds and lower its interest costs. There is currently
$2,750,000 outstanding on the 2003 issue.
BACKGROUND: When the City finances a project it will issue bonds to do so. Each Bond,
usually in 5,000 denominations, has its own specific interest rate and maturity date. As you
would expect, the longer term bonds usually carry a higher interest rate. The stated interest rate
on the outstanding 2003 bonds ranges from 3.3% to 3.9 %. The City could issue bonds today that
would bear interest rates that would range from .25% to 1.90% for the same maturities as the
outstanding 2003 bonds. This would dramatically lower our interest cost.
DISCUSSION: This is the first opportunity that the City could refund these bonds as the bonds
carry a provision that they may be called in December 2011. This allows the city to pay off those
bonds early by issuing new bonds at a lower interest cost. The City would issue the bonds
through the investment banking firm of Stifel Nicolaus. Attached are financial pro - formas that
show the structure of the proposed refunding deal.
City Council, if they give the okay to move forward, would formally approve the issuance of the
bonds at a meeting sometime in August.
FINANCIAL/BUDGET IMPACTS: The City would save approximately $150,000 by
undertaking this refunding. The savings would be realized in the Marolt housing fund which is
expected to encounter difficult cash flow issues in the coming years. This would help deal with
Page 1 of 2
that issue, but not solve it. The exact amount of savings will not be known until the refunding
bonds are issued and the exact interest cost determined.
RECOMMENDED ACTION: Staff recommends moving forward with the refunding issue.
ALTERNATIVES: The other alternative would be to not refund the 2003 bonds and pay them
off through 2018. This would bear a higher cost.
PROPOSED MOTION: City Council directs staff to proceed with the work necessary to issue
bonds to refund the 2003 General Obligation Bonds.
CITY MANAGER COMMENTS:
ATTACHMENTS:
Page 2 of 2
•
SOURCES AND USES OF FUNDS
City of Aspen
General Obligation Refunding Bonds, Series 2011
Dated Date 09/06/2011
Delivery Date 09/06/2011
Sources:
Bond Proceeds:
Par Amount 2,420,000.00
Premium 81,121.25
2,501,121.25
Uses:
Refunding Escrow Deposits:
Cash Deposit 2,453,268.13
Delivery Date Expenses:
Cost of Issuance 31,500.00
Underwriter's Discount 15,730.00
47,230.00
Other Uses of Funds:
Additional Proceeds 623.12
2,501,121.25
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011G0,2011G0) Page 1
BOND DEBT SERVICE
City of Aspen
General Obligation Refunding Bonds, Series 2011
Dated Date 09/06/2011
Delivery Date 09/06/2011
Period Annual
Ending Principal Coupon Interest Debt Service Debt Service
12/01/2011 30,000 2.000% 12,144.97 42,144.97 42,144.97
06/01/2012 25,418.75 25,418.75
12/01/2012 385,000 2.000% 25,418.75 410,418.75 435,837.50
06/01/2013 21,568.75 21,568.75
12/01/2013 390,000 2.000% 21,568.75 411,568.75 433,137.50
06/01/2014 17,668.75 17,668.75
12/01/2014 395,000 2.000% 17,668.75 412,668.75 430,337.50
06/01/2015 13,718.75 13,718.75
12/01/2015 405,000 2.000% 13,718.75 418,718.75 432,437.50
06/01/2016 9,668.75 9,668.75
12/01/2016 415,000 2.250% 9,668.75 424,668.75 434,337.50
06/01/2017 5,000.00 5,000.00
12/01/2017 400,000 2.500% 5,000.00 405,000.00 410,000.00
2,420,000 198,232.47 2,618,232.47 2,618,232.47
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011G0,201 IGO) Page 2
BOND PRICING
City of Aspen
General Obligation Refunding Bonds, Series 2011
Maturity Premium
Bond Component Date Amount Rate Yield Price (- Discount)
Serial Bonds:
12/01/2011 30,000 2.000% 0.250% 100.412 123.60
12/01/2012 385,000 2.000% 0.340% 102.045 7,873.25
12/01/2013 390,000 2.000% 0.550% 103.217 12,546.30
12/01/2014 395,000 2.000% 0.820% 103.760 14,852.00
12/01/2015 405,000 2.000% 1.130% 103.588 14,531.40
12/01/2016 415,000 2.250% 1.450% 104.018 16,674.70
12/01/2017 400,000 2.500% 1.880% 103.630 14,520.00
2,420,000 81,121.25
Dated Date 09/06/2011
Delivery Date 09/06/2011
First Coupon 12/01/2011
Par Amount 2,420,000.00
Premium 81,121.25
Production 2,501,121.25 103.352118%
Underwriter's Discount - 15,730.00 - 0.650000%
Purchase Price 2,485,391.25 102.702118%
Accrued Interest
Net Proceeds 2,485,391.25
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011GO) Page 3
SAVINGS
City of Aspen
General Obligation Refunding Bonds, Series 2011
Present Value
Prior Refunding Annual to 09/06/2011
Date Debt Service Debt Service Savings Savings @ L2684498%
12/01/2011 43,268.13 42,144.97 1,123.16 1,123.16 1,119.81
06/01/2012 43,268.13 25,418.75 17,849.38 17,684.01
12/01/2012 393,268.13 410,418.75 - 17,150.62 698.76 - 16,884.64
06/01/2013 37,493.13 21,568.75 15,924.38 15,578.61
12/01/2013 397,493.13 411,568.75 - 14,075.62 1,848.76 - 13,683.21
06/01/2014 31,373.13 17,668.75 13,704.38 13,238.36
12/01/2014 401,373.13 412,668.75 - 11,295.62 2,408.76 - 10,842.75
06/01/2015 24,898.13 13,718.75 11,179.38 10,663.53
12/01/2015 409,898.13 418,718.75 - 8,820.62 2,358.76 - 8,360.59
06/01/2016 17,920.00 9,668.75 8,251.25 7,771.62
12/01/2016 417,920.00 424,668.75 - 6,748.75 1,502.50 - 6,316.40
06/01/2017 10,420.00 5,000.00 5,420.00 5,040.81
12/01/2017 425,420.00 405,000.00 20,420.00 25,840.00 18,871.69
06/01/2018 2,535.00 2,535.00 2,328.02
12/01/2018 132,535.00 132,535.00 135,070.00 120,946.73
2,789,083.17 2,618,232.47 170,850.70 170,850.70 157,155.61
Savings Summary
PV of savings from cash flow 157,155.61
Plus: Refunding funds on hand 623.12
Net PV Savings 157,778.73
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011 G0) Page 4
SUMMARY OF REFUNDING RESULTS
City of Aspen
General Obligation Refunding Bonds, Series 2011
Dated Date 09/06/2011
Delivery Date 09/06/2011
Arbitrage yield 1.268450%
Escrow yield
Bond Par Amount 2,420,000.00
True Interest Cost 1.445042%
Net Interest Cost 1.473331%
Average Coupon 2.198579%
Average Life 3.726
Par amount of refunded bonds 2,410,000.00
Average coupon of refunded bonds 3.676810%
Average Life of refunded bonds 4.020
PV of prior debt to 09/06/2011 @ 1.268450% 2,658,276.86
Net PV Savings 157,778.73
Percentage savings of refunded bonds 6.546835%
Percentage savings of refunding bonds 6.519782%
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011GO) Page 5
SUMMARY OF BONDS REFUNDED
City of Aspen
General Obligation Refunding Bonds, Series 2011
Maturity Interest Par Call Call
Bond Date Rate Amount Date Price
General Obligation Refunding Bonds, Series 2003, 2003GOR:
SERIALS 12/01/2012 3.300% 350,000.00 12/01/2011 100.000
12/01/2013 3.400% 360,000.00 12/01/2011 100.000
12/01/2014 3.500% 370,000.00 12/01/2011 100.000
12/01/2015 3.625% 385,000.00 12/01/2011 100.000
12/01/2016 3.750% 400,000.00 12/01/2011 100.000
12/01/2017 3.800% 415,000.00 12/01/2011 100.000
12/01/2018 3.900% 130,000.00 12/01/2011 100.000
2,410,000.00
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011GO) Page 6
PRIOR BOND DEBT SERVICE
City of Aspen
General Obligation Refunding Bonds, Series 2011
Period Annual
Ending Principal Coupon Interest Debt Service Debt Service
12/01/2011 43,268.13 43,268.13 43,268.13
06/01/2012 43,268.13 43,268.13
12/01/2012 350,000 3.300% 43,268.13 393,268.13 436,536.26
06/01/2013 37,493.13 37,493.13
12/01/2013 360,000 3.400% 37,493.13 397,493.13 434,986.26
06/01/2014 31,373.13 31,373.13
12/01/2014 370,000 3.500% 31,373.13 401,373.13 432,746.26
06/01/2015 24,898.13 24,898.13
12/01/2015 385,000 3.625% 24,898.13 409,898.13 434,796.26
06/01/2016 17,920.00 17,920.00
12/01/2016 400,000 3.750% 17,920.00 417,920.00 435,840.00
06/01/2017 10,420.00 10,420.00
12/01/2017 415,000 3.800% 10,420.00 425,420.00 435,840.00
06/01/2018 2,535.00 2,535.00
12/01/2018 130,000 3.900% 2,535.00 132,535.00 135,070.00
2,410,000 379,083.17 2,789,083.17 2,789,083.17
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011GO) Page 7
ESCROW REQUIREMENTS
City of Aspen
General Obligation Refunding Bonds, Series 2011
Period Principal
Ending Interest Redeemed Total
12/01/2011 43,268.13 2,410,000.00 2,453,268.13
43,268.13 2,410,000.00 2,453,268.13
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011GO) Page 8
UNREFUNDED BOND DEBT SERVICE
City of Aspen
General Obligation Refunding Bonds, Series 2011
Annual
Period Debt Debt
Ending Principal Coupon Interest Service Service
12/01/2011 340,000 3.500% 5,950 345,950 345,950
340,000 5,950 345,950 345,950
Jul 7, 2011 1:14 pm Prepared by Stifel Nicolaus & Company (Finance 6.020 SWESTCO:ASPEN- 2011GO,2011GO) Page 9