HomeMy WebLinkAboutCOUNCIL - AGENDA ITEM - 12/13/2011 - 2012 LARGE COMMERCIAL AND INDUSTRIAL ELECTRIC RATEDATE: December 13, 2011
STAFF: Brian Janonis, Steve
Catanach, Lance Smith, Bill
Switzer, Ellen Switzer
Pre-taped staff presentation: available
at fcgov.com/clerk/agendas.php
WORK SESSION ITEM
FORT COLLINS CITY COUNCIL
SUBJECT FOR DISCUSSION
2012 Large Commercial and Industrial Electric Rates.
SUBJECT FOR DISCUSSION
Ordinance No. 142, 2011 passed by City Council on November 1, 2011, adopted commercial and
industrial electric rates effective for billings with meter readings on or after January 1, 2012. The
adopted rates pass through increases in Platte River Power Authority’s wholesale rates and align
with Platte River’s new seasonal rate structure. The adopted rates also pass through the cost of
service change made by Platte River to shift a greater portion of the wholesale power cost from the
monthly peak demand charge to the energy component of the wholesale rate. In addition to the
purchase power increases, there was also a small rate increase in order to slow the reduction of Light
and Power reserves. These changes resulted in larger 2012 electric rate increases for the large
commercial and industrial customer classes than the system average, but reflect the accurate costs
of providing electric service to these classes.
Since the adoption of Ordinance No. 142, 2011, several large customers have asked the City Council
to reconsider the rate increases. These customers have stated the increases will negatively impact
their business and perhaps delay or eliminate any company expansion plans. In recognition of these
concerns, Council requested a work session for additional review of the impacts of the rate increases
on large commercial customers. As part of this review, staff has prepared additional options for
implementing the electric rate increases for these large customers.
The 2012 rates adopted by Ordinance No. 142, 2011, will remain in effect until changed by
ordinance. If Council chooses to formally consider a change, an ordinance revising the commercial
and industrial rates could be effective prior to the higher summer season rates during June, July and
August.
GENERAL DIRECTION SOUGHT AND SPECIFIC QUESTIONS TO BE ANSWERED
1. Are there options that staff has not presented that should be explored?
2. Of the options presented, which option is preferable?
3. Should staff prepare an ordinance to revise the commercial and industrial rates for 2012?
December 13, 2011 Page 2
BACKGROUND / DISCUSSION
Impacts to Commercial and Industrial Customers
As shown on Attachment 3, Fort Collins commercial and industrial rates are among the lowest in
the state and country and are projected to remain among the lowest in 2012. Platte River Power
Authority is in large part responsible for the City’s ability to maintain low electric rates. However,
Platte River’s costs are increasing and will continue to increase in the future.
In 2012, the City’s purchase power rates are increasing an average of 6.4%. The new rates have a
seasonal price signal with larger increases in the three summer months of June, July and August.
In addition, the purchase power rates will begin to recover more costs from the energy component
of the rate and less through the monthly coincident peak demand component. As a result, the
wholesale energy costs increased 47% and the wholesale coincident peak demand component
decreased 33%. This cost structure impacts large industrial and commercial customers more than
smaller users.
Since 1997, Fort Collins Light and Power’s large commercial and industrial customer rates have
been unbundled to show separate rate components for purchase power energy (kwh), purchase
power demand (coincident peak measured in kW), customer billing and distribution facilities
charges. The two purchase power components directly tie to the monthly cost of power purchased
from Platte River to serve the individual customer and the customer billing and distribution facilities
charges reflect the Utilities cost for operating and maintaining the distribution facilities to serve the
customer. These customers have advanced meters and their contribution to Platte River’s four-city
coincident peak is measured each month. The exact cost of purchase power (adjusted for losses) is
directly passed on to each of these large customers. Platte River posts its projected hourly demands
on a website available to GS50 and GS750 customers and customers may monitor the peaks to
reduce their coincident monthly demand. This enables customers to save on their monthly bills for
the purchase power coincident demand component. While the incentive to do this will remain, it
will be somewhat lessened by the cost shift from demand to energy.
The 2010 Cost of Service Study showed that Utilities also required a rate increase to fully fund
capital improvements. For the last few years, revenues have not covered the cost of capital
improvements and the difference has been drawn from reserves. While this was an intentional
strategy, it is not a sustainable one as reserves will drop below policy levels and be totally depleted
if this is not reversed. To slow the draw down of reserves, the 2012 rates also included an average
increase of 3.5% to the distribution facilities demand charge with the GS50 class seeing a 3.1%
increase and the GS750 class a 1.7% increase. See Attachment 1 for Light and Power’s working
capital reserve balances.
The following two tables show the average impacts of Platte River’s rate changes on the large
commercial and industrial customers. The percentage increases shown below are averages for the
rate classes. Individual customers may see increases greater or less than the average. For example,
the industrial customers increase between 15% and 23% in the summer and increase from 4% to
13% in the non-summer months. Individual customers may see increases that are larger or smaller
than the class averages due to differences in each customers seasonal load profile and ratio of energy
to demand (load factor).
December 13, 2011 Page 3
Table 1: Average Purchase Power and Distribution Cost Components of 2012 Large
Commercial and Industrial Rate Increases
Number of
Customers
Projected
2011
Revenues
Projected 2012
Revenues
Increase
Revenue
Proportion
of
Increase
Large Commercial
General Service 50
Purchase Power $14,607,324 $15,652,767 $1,045,443 65%
Distribution $3,931,085 $4,501,954 $570,869 35%
Total 470 $18,538,409 $20,154,721 $1,616,312 100%
Percent Increase 8.7%
Industrial
General Service 750
Purchase Power $15,258,751 $16,875,908 $1,617,157 85%
Distribution $1,996,178 2,284,899 $288,721 15%
Total 15 $17,254,929 $19,160,807 $1,905,878 100%
Percent Increase 11.0%
Table 2: Average Seasonal Impacts on Large Commercial and Industrial Rates
Summer Non-Summer Average
Large Commercial
General Service 50 20.0% 4.7% 8.7%
Industrial
General Service 750 20.7% 7.6% 11.0%
Platte River Power Authority Rates
Since the largest portion of the rate increase for these customer classes is related to purchase power,
Platte River Power Authority has provided a detailed explanation of the 2012 purchase power rate
changes and planned increases for the next few years (Attachment 4).
Accuracy of Cost of Service and Rate Design
Staff has reviewed the cost of service used to develop the rates contained in Ordinance No. 142,
2011. In staff’s opinion, the adopted rates accurately pass through the increased rates and
realignment of the purchase power for each customer rate class. The rates also reflect the costs of
billing and the operation and maintenance of the Utilities’ distribution facilities. The methodology
used by staff in developing the cost of service allocations is standard to the electric industry. An
December 13, 2011 Page 4
independent review of the cost of service was included in the scope of service for the SAIC
consultants when they were hired in early 2011. This review is expected to be completed shortly.
Any reduction to the cost of service based rates for large commercial and industrial customers would
require additional increases for the other customer classes or further draw-down of the Light and
Power Reserve Fund. Staff would not recommend further depleting reserves to accomplish a
temporary rate reduction for these classes.
Future Rate Impacts
As explained in Attachment 4, Platte River currently estimates an additional 9.4 % increase to the
wholesale purchase power cost in 2013. This will impact each customer differently, with most
commercial and industrial customers seeing an overall increase of 7-11% attributable to higher
wholesale purchase power costs. Also, as noted, the continued draw-down of reserves is not
sustainable and it is necessary for the rates to be increased gradually over the next few years to fully
cover the costs of capital improvements.
Additional Options for Implementation of Commercial Rate Increases
While the City’s electric rates will still remain low in comparison to other electric utilities, several
large customers have voiced both questions and concerns related to the magnitude of the increases.
Also, changes to the rate structure were not anticipated by these customers, causing budgeting
problems for some large customers and potential changes in operations and capital expansion plans.
The following table shows several additional options for implementing the 2012 cost increases for
the large commercial and industrial customers. Because purchase power and operating costs of the
Utility must be paid in 2012, the reduction in revenue from any changes to the large commercial and
industrial classes would have to be drawn from reserves (which are already projected to be further
depleted in 2012), or through additional 2012 rate increases to other customer classes. Deferring
the increases to these classes would compound the planned rate increases for these large customers
in the future.
December 13, 2011 Page 5
Staff Recommendation:
Staff recommends Option 1.
Other Related Issues
Issue 1
One large customer is served by a wholesale contract rate based on agreement with the City and
Platte River and will not be impacted by any change in Ordinance No. 142, 2011. The contractual
rate for this customer is specified in the Amended Master Agreement. Annual rate changes for this
customer are based solely on Platte River’s Tariff 1 (Firm Resale Power Service) as applied to the
December 13, 2011 Page 6
customer’s historic load factor. The average 2012 rate increase for this one contractual customer
is 11.3% and will vary by season.
Issue 2
A new rate class was created by Ordinance No. 142, 2011, for medium sized commercial customers.
The rate increases for these customers average 27% in the summer and 10.9% in the non-summer.
These 500 customers include sandwich shops, coffee shops, some retail, restaurants, churches,
preschools and some smaller schools. Prior to the change, all commercial customers with demands
of less than 50 kW were grouped into a single rate class and their costs of service were averaged
over both customer groups. This historical grouping resulted in lower rates for the 500 customers
with demands between 25 and 50 kW and higher rates for the 3500 customers with demands less
than 25 kW. The Utilities rate consultant, SAIC, recommended that this class be divided to better
reflect the cost to serve the diverse small/medium commercial customers. Ordinance No. 142, 2011
created the new GS25 rate and eliminated the cross subsidy between the two groups of customers.
The adopted change resulted in the largest percentage increase for the group of 500 business
customers with demands between 25 and 50 kW. These customers generally have smaller utility
budgets than those for the larger commercial and industrial customers. Additional outreach for these
customers is planned, to provide more information about the impacts of the change on their typical
charges, as well as help in reducing bills through energy efficiency and conservation measures.
NEXT STEPS
Ordinance No. 142, 2011 will become effective for commercial billings for all meter readings on
or after January 1, 2012. Should Council’s response to the questions posed indicate a desire to
change the adopted ordinance, required notice will be sent and a revised ordinance will be prepared
for Council consideration in early 2012. The new ordinance would be implemented prior to the
summer season.
Regardless of Council’s direction to staff, all large commercial and industrial customers are
encouraged to send representatives to the Utilities Key Account Meeting to learn more about the rate
increases and efficiency programs.
ATTACHMENTS
1. Light and Power Fund Reserve Balances
2. Light and Power 2012 Rate Increase by Class and Season
3. Colorado Association of Municipal Utilities Comparison Graphs for Large Commercial and
Industrial
4. National Rate Comparison Graphs
5. Platte River Rate Explanation Memo
6. Excerpt from the Agenda Item Summary for Ordinance No. 142, 2011
7. Memo from Josh Birks, City Economic Advisor, re: Economic Health Incentives - Offsetting
Commercial Utility Rate Increases
8. Ordinance No. 142, 2011
9. Powerpoint presentation
10. Platte River Power Authority Powerpoint presentation
Attachment 1 – Light and Power Fund Reserve Balances and Intended Use of Reserves
2007 2008 2009 2010 2011 2012
CAFR CAFR CAFR CAFR Estimated Reserves Estimated Reserves
Current Assets $ 66,217,267 $ 82,861,465 $ 70,640,231 $ 57,192,926
Current Liablilities $ 6,779,144 $ 24,273,012 $ 23,021,404 $ 12,056,242
Working Capital Reserves $ 59,438,123 $ 58,588,453 $ 47,618,827 $ 45,136,684 $ 44,499,684 $ 39,406,383
Note: Not all working capital reserves are cash. The balance includes inventory, accounts receivable, and accounts payable.
Cash and investments totalled $37.86 million of which $16.5 million is from the AMI bond issue.
Intended Use of Reserves
Required Reserves per Financial Policy
Reserve for Art in Public Places $ 716,700
Reserve for Operations (8% of O&M Expense less Purchase Power) $ 2,817,380
Capital Improvements (1/5th of the 5-year capital plan less capital outlay reserve) $ 10,429,159
Capital Outlay Reserve $ 797,927
Total Reserves per Financial Policy $ 14,761,166
Reserve for Encumbrances (committed by 2010 purchase order for expenditure in 2011) $ 2,303,541
Bond Proceeds Committed to AMI Grant Match $ 16,500,000
Reserves Needed to Fund Prior Year Unexpended Captial Project Appropriations $ 10,171,697
Committed and Required Reserves $ 43,736,404 $ 43,736,404 $ 43,736,404
Excess Reserves YE (estimated 2011 and 2012) $ 1,400,280 $ 763,280 $ (4,330,021)
2012 Budget $ 112,752,791
2012 Revenues $ 107,659,490
Use of Reserves in 2012 - Excludes AMI revenues and expenditures $ 5,093,301
Attachment 2 – Light and Power 2012 Rate Increase Charts
2012 RATE INCREASE
17%
20%
18%
27%
20%
21%
2%
15%
11%
5%
8%
6%
16%
4%
16%
9%
11%
19.2%
-2%
4.4%
8.3%
-5%
0%
5%
10%
15%
20%
25%
30%
RES RES DEM GS GS25 GS50 GS750 SYSTEM
Summer
Non-summer
Average
2012 Rate Class Increase Detail
-13%
-15%
-6%
-13%
16%
22%
2%
6%
16% 16%
11%
-13% -13% -12.4%
18% 18%
14%
15%
17.2%
5% 4%
14%
4% 3%
3.5%
9%
4%
8.3%
-20%
-15%
Attachment 3 – Colorado Rate Comparison
Colorado Association of Municipal Utilities Large Commercial Rate Survey
January 2011 --- Cost for 45,000 kWh and 130 KW per month
$3,423
$3,048
GUNNISON
LONGMONT 2011
FORT COLLINS 2011
LOVELAND 2011
LONGMONT 2012
ESTES PARK
COLORADO SPRINGS
FLEMING
LOVELAND 2012 - Average
FT COLLINS 2012 - Average
XCEL ENERGY
UNITED POWER
BLACK HILLS ENERGY
POUDRE VALLEY EA
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
FORT COLLINS LOVELAND LONGMONT INVESTOR OWNED MUNICIPAL/REA
Colorado Association of Municipal Utilities Industrial Rate Survey
January 2011 --- Cost for 1,900,000 kWh and 3000 KW per month
$90,827
$104,260
$0
$25,000
$50,000
$75,000
$100,000
$125,000
$150,000
$175,000
$200,000
$225,000
FORT COLLINS 2011
TRI-COUNTY
LONGMONT 2011
LOVELAND 2011
COLORADO SPRINGS
LONGMONT 2012
FT COLLINS 2012 - Average
LOVELAND 2012 - Average
XCEL ENERGY
UNITED POWER
BLACK HILLS ENERGY
POUDRE VALLEY EA
FORT COLLINS LOVELAND LONGMONT INVESTOR OWNED MUNICIPAL/REA
Attachment 4 – National Rate Comparison
Cost of Electricity Commercial
Source: Energy Information Administration
0
2
4
6
8
10
12
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
YTD
Customer cost in cents per kWh
National Average Fort Collins Colorado Average
Cost of Electricity Industrial
Source: Energy Information Administration
0
1
2
3
4
5
6
7
8
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
YTD
2012
Est
Customer cost in cents per kWh
National Average Fort Collins Colorado Average
ATTACHMENT 5
Ip PLATTE RIVER
POWER AUTHORITY
MEMORANDUM
November 30, 2011
To: Darin Atteberry, Fort Collins City Manager
Brian Janonis, Fort Collins Utilities Director
From: Brian Moeck, General
Subject: Attachment for December 13 Work Session Agenda Item Summary
2012 Large Coinmejuii I and Industrial Electric Rates
Working with staff from Fort Collins Utilities, Platte River developed the attached summary to
support discussion of electric rates at the City Council work session on December 13.
Platte River staff will be available at the work session to answer any questions the City Council may
have regarding wholesale electric rates.
Please let me know if you have any questions before the meeting.
ATTACHMENT
5
PLATTE
RIVER POWER
AUTHORITY
ATTACHMENT
Agenda
Item
Summary
-
2012
Large
Commercial
&
Industrial
Electric
Rates
The
Platte
River
Board
of
Directors
approved
wholesale
electric
rates
for
2012
at
its
meeting
on
October
27,
2011.
The
average rate
increase
at
the
wholesale
level
is
6.1%.
On
average,
this
represents
an
increase
at
the
retail
level
of
about
4.3%
(combined
retail
2012
Wholesale
Rate
Increase
(vs.
2011)
—
Revenue
Requirements
ATTACHMENT
5
The
wholesale
rate
increase
from
2011
to
2012
is
primarily
driven
by
reduced
surplus
sales
revenues,
as
indicated
in
Figure
2.
Reduced
revenues
from
other
sources
must
be
recovered
from
the
Municipalities.
The
next
most significant
factor
is
increased
operation
and
maintenance
(O&M)
costs
—
primarily maintenance
work
at
Rawhide
planned
ATTACHMENT
5
The
average
surplus
sales
price for
2011
(year
to
date)
is
about
$25/MWh.
Surplus
generation
in
the
region,
higher
than
expected
hydropower
levels,
lower
natural
gas
prices
and poor
economic
conditions
all
likely
have
contributed
to
the
lower
prices.
2012
Wholesale
Rate
Structure
Change
For
several
years,
the
owner
Municipalities
have
discussed
potential
new
retail rate
structures
such
as
seasonal
and
ATTACHMENT
5
Summary
of
2012
Wholesale
Rate
(Tariff
1)
Tariff
1
Charges:
Change
Energy:
Jun
-
Aug
$003513/kWh
52.1%
Energy:
Other
Months
$0.03340/kWh
44.6%
Demand:
Jun
-
Aug
$l0.05/kW-mo
-19.1%
Demand:
Other Months
$7.53/kW-mo
-39.4%
Average
$/MWh
Estes
Park
$47.14
8.3%
Fort
Collins
$49.47
6.4%
Longrnont
$50.33
5.7%
Loveland
$50.46
5.5%
Total
$49.81
6.1%
A
summary
of
the
major
changes
to
ATTACHMENT
5
Wholesale
Rate
Projections
Additional
wholesale
rate increases
are
anticipated
in
2013,
driven
primarily
by
anticipated
increases
in
coal
prices
—
and
most
of
this
increase
would
apply
to
the
energy
charge.
Fuel
is
Platte
River’s
largest
expense,
at
about
25%
of
total
cost.
At
this
time,
the
average rate
is
estimated
to
increase
about
9.4%
in
2013.
No
rate
increases
ATTACHMENT
5
Average
monthly
retail
cost
trends
for
residential
customers
in
Colorado
are
summarized
in
Figure
5.
Platte
River’s
owner
Municipalities
all
have relatively
lower
rates
than cooperatives,
investor-owned
utilities and
other
municipalities
in
the
state.
Figure
6
shows
the
trend
for
wholesale
rates
provided
to
cooperatives
in
the
region
(from
Tn-
State)
relative
to
wholesale
rates
to
Platte
River’s
owner
Municipalities.
The
80
ATTACHMENT
5
Figure
6
—
Platte
River
and
Tn-State
‘Wholesale
Rate
Trends
70
60
40
30
20
10
70%
60%
50%
40%
30%
20%
10%
no,
U
/0
-10%
—PRPA
Average
Wholesale
Rate
Tn-State
Average
Wholesale Rate
Figure
7
—
Platte
River
and
National
Electric Rate
Trends
—
PRPA
Average
Wholesale
Rate
—
National
Retail
Rates
-20%
—-----
----------
----
----
ATTACHMENT 6
EXCERPT FROM OCTOBER 18, 2011 AGENDA ITEM SUMMARY
“Items Relating to Utility Rates, Fees and Charges for 2012”
c. Monthly Electric Rates (Ordinance No. 142, 2011, Amending Chapter 26 of the City Code to
Revise Electric Rates, Fees and Charges.)
Based on Council response at the September 13, 2011 Work Session, the electric rate ordinance does not
contain any changes to the RESR, the rate applicable to the majority of residential customers. The changes
to the RESR will be presented in a separate ordinance on November 15, 2011 and will contain several rate
form alternatives. The ordinance for consideration at this meeting pertains only to the Residential Demand,
Commercial (General Service, General Service 25, General Service 50), Industrial (General Service 750) and
Traffic rates.
Fort Collins’ wholesale and retail electric rates are among the lowest in the region and nation. This will
continue to be true following the 8.3% electric rate increase proposed for 2012. The 8.3% increase is the
system average and will not be equally applied to all customer rate classes. Based on a cost-of-service study,
the proposed rates vary by rate class as follows:
Proposed Rate Class Increases for 2012
Individual customers will vary from the class average.
Summer increases (June, July and August) will be greater than average.
RESR – Not included in Ordinance No. 142, 2011 6.0%
Residential Demand Rate 15.9%
1. General Service (small commercial less than 25 kW) 3.9%
1. General Service 25 (small commercial between 25-49 kW) 15.5%
General Service 50 (medium commercial between 50-749 kW) 8.7%
General Service 750 (large com/industrial greater than 749kW) 11.0%
Traffic Signals 11.3%
Floodlights 0.0%
Average System Increase 8.3%
4.8% of the 8.3% system-wide increase is due to a 6.4% increase in Platte River Power Authority’s purchase
power rates. In addition, Platte River’s wholesale rate will be seasonal, with higher rates in June, July and
August. Platte River’s 2012 purchase power rate increase is due to several key factors:
• Reduced surplus sales
• Increased operating and maintenance costs
• Increased financing and depreciation costs as new projects are placed into service
• Reduced interest income – due to low interest rates and lower cash reserves
The remaining 3.5% of the 8.3% is required to reduce the use of Light and Power’s reserves to cover the cost
of system improvements and replacements. While the reduction of reserves has been intentional,
expenditures in the Light and Power Fund have exceeded revenues each year since 2007. Even following
the proposed 3.5% increase, expenditures are projected to exceed revenues for 2012.
The larger commercial classes are experiencing a greater than average increase due to the shift of purchase
power costs from demand charges to energy charges in Platte River’s new rate form. Those customers with
larger load factors, typically larger commercial and industrial customers and also the traffic signal system, will
1
have larger than average increases in the purchase power components of their rates. (Load factor measures
the consistency of power use over time.)
Although the last cost-of-service study showed that the residential demand (“RD”) rate was 18% under cost-of-
service, all rate classes were limited to a 10% increase in 2011. The 2012 increase brings the RD rate class
up to full cost-of- service. The rate has traditionally been selected by high-use customers such as those who
exclusively heat their homes with electricity. The increase to this rate will make the RESR more economical
for many of the existing RD customers in 2012. Staff is also recommending that the RD rate be available only
to those customers providing documentation that their home is heated entirely with electric energy. These
changes will begin a phase-out of the RD rate.
Electric Rate Form Changes
Changes in the electric rate forms are necessary to align rates in support of the City’s Energy Policy and
Climate Action Plan goals. By adopting rate forms to incentivize customers to conserve and use energy more
efficiently and by providing energy conservation assistance and programs to our customers, the City will more
likely be able to achieve its policy goals. In addition, successful implementation of these tools will delay or
defer the expense of constructing additional generation resources. Rate form changes are also needed to
pass through the seasonal cost differentials that will be charged by Platte River Power Authority beginning
in 2012. All rates will have higher costs in the summer (June, July and August) than during the remaining nine
“non-summer” months. Consistent with Platte River, the recommended rates also shift a greater proportion
of the rate from the demand charges to energy charges.
Rate form options were presented to the Council Finance Committee on August 15, 2011 and to the full
Council at work sessions on September 13, 2011 and October 11, 2011. Based on Council’s responses to
the questions posed at the work sessions, there is a delay in the ordinance making changes to the RESR until
November 15, 2011. Several options for the RESR ordinance will be presented at that time. The changes
recommended for the RD and Commercial/Industrial rates seemed to have wide-spread support at the
September 13 Work Session. The following summarizes changes to the electric rate forms that are included
in the proposed electric rate ordinance.
• Residential Demand: The residential demand rate will be increased to the cost-of-service and
energy charges will reflect the seasonal differential. The rate will be available only to customers who
heat their residences exclusively with electricity.
• Small /Medium Commercial: The General Service rate is currently one rate class serving all
commercial customers with average monthly demands of less than 50 kW. Staff is proposing that it
be split into two rate classes beginning in 2012.
N General Service - energy-only seasonal rate for customers with average monthly demands
of less than 25 kW
N General Service 25 - energy/demand seasonal rate for customers with average monthly
demands of between 25 and 49kW
• Large Commercial / Industrial: The recommended rate form changes for the GS50 and GS750 rate
classes are due to Platte River’s seasonal wholesale rate.
N General Service 50 – add seasonal energy and coincident demand components for
customers with average demands of between 50-749 kW
N General Service 750 – add seasonal energy and coincident demand components for
customers with average demands of 750 kW and greater
Additional Amendments to Electric Article and Rates
• Wholesale Transactions: Staff is recommending the addition of a Code section and definition to
clarify terms of wholesale transactions and to specify that the retail rates, requirements and electric
development fees do not apply to wholesale purchases.
2
• Clarification of Net Metering Credit: Staff is recommending that the rate schedule specify that credits
for net excess generation due to net metering will be based on the summer season retail energy
charge as reflected in the new rate structure.
• Clarification of Parallel Generation Credit: Staff is recommending that the rate tariff schedule specify
that credits for parallel generation delivered to the utility will be based on Platte River Power
Authority’s avoided cost rate.
• Clarification of Distribution Facilities Demand: The proposed change more fully defines distribution
facilities demand for the large commercial and industrial rate classes and permits the Utilities
Executive Director to use an alternative method to recover a customer’s cost-of-service share of
distribution demand if the costs associated with serving a customer are not fully recovered by the
standard rate.
3
ATTACHMENT 7
Economic Health Office
300 LaPorte Avenue
PO Box 580
Fort Collins, CO 80522
970.221.6505
970.224.6107 - fax
fcgov.com
MEMORANDUM
Date: December 6, 2011
To: Mayor, and City Councilmembers
From: Josh Birks, Economic Advisor – City of Fort Collins
Re: Economic Health Incentives – Offsetting Commercial Utility Rate Increases
On November 1, 2011, City Council passed Ordinance No. 142, 2011, adopting commercial and
industrial electric rates effective for billing with meter readings on or after January 1, 2012. The
adopted rates pass through increased in Platte River Power Authority’s wholesale rates and align
with Platte River’s new seasonal rate structure. Since adoption, City Council, the City Manager’s
Office, and the Economic Health Office have received numerous inquiries regarding the
increases. The December 13 City Council Work Session is an opportunity to review the increases
and evaluate alternatives.
City staff will present several alternatives for City Council review. The first and recommended
option is to aggressively market energy conservation programs and evaluate the possibility of
economic incentives for potential commercial or industrial expansions. The City has approved
economic incentives to support commercial or industrial expansions in the past. Most recently,
City Council approved a Business Assistance Package by Resolution 2011-066 on July 19, 2011
for Avago’s expansion of their electronic manufacturing operations.
Overview
This memorandum is intended to provide an overview of the available economic incentives that
could be used to offset the commercial rate increases at the time of commercial or industrial
expansion. However, it must be noted that in order to truly offset the cost any future business
assistance package may have to be more aggressive than previously presented to City Council.
All assistance packages are subject to City Council approval. If City Council instructs staff to
pursue this option, Economic Health Office staff will see it as direction to bring forward more
aggressive assistance packages when the appropriate form of commercial or industrial expansion
is proposed by businesses within the GS50 and GS750 rate classes.
Local Incentives
The following incentives may be available to a commercial or industrial expansion project. The
value of the incentive has been estimated based on a $1.0 million investment in equipment and
building enhancements. In all cases, the funds rebated by these incentives would typically flow
into the General Fund. However, it is important to note that these incentives due not reduce
current tax collections they forgo revenue that is associated with a proposed expansion. If done
right, the incentives are used to support project that would not otherwise occur; therefore, the
forgone revenue would not be realized even if the incentives are not offered to the proposed
commercial or industrial expansion project.
Manufacturing Equipment Use Tax Rebate Program – The City’s Manufacturing
Equipment Use Tax Rebate Program permits local manufactures to request a partial rebate of
the 3.0 percent local use taxes paid on qualifying equipment. Use taxes are used by other
Colorado municipalities and intended to equalize competition between venders located in the
cities who collect local sales tax and those located outside the cities who do not charge local
sales tax. City Council must approve a full rebate of the 3.0 percent use tax rate. Example, if
the client were to invest $1.0 million in manufacturing equipment, this program could
potentially save the company up to $30,000 in use tax.
Personal Property Tax Rebate – The City employs the use of personal property tax rebates
on a discretionary or case-by-case basis. Use of this incentive will require approval of the
City Council. Past agreements with primary employers have included a 10-year rebate for 50
percent of the personal property in the expansion/relocation project. A more aggressive
approach would be to rebate the full personal property tax for a 10-year or longer period.
Example, if the project includes an investment of $1.0 million in building enhancements, this
program could potentially save the company between $1,400 and $2,800 annually depending
on the rebate percentage authorized by City Council.
Payment in Lieu of Taxes Rebate – The City could elect on a case-by-case basis to evaluate
rebating a portion of the Payment in Lieu of Taxes (PILOT) associated with the “net new”
energy consumption from a commercial or industrial expansion project. The amount of the
rebate would vary depending on the estimated energy consumption associated with the
project.
1
1
2012 Electric Rate Increase
Impacts to Large Commercial and
Industrial Customers
City Council Work Session
December 13, 2011
2
Agenda
•• 2012 Rate Increase
•• Commercial & Industrial Rates
•• Options for Consideration
•• Questions for Staff
ATTACHMENT 9
2
3
2012 Rate Increase
4
City Council Presentations to Date
Work
Session
Regular
Meeting Subject
10-May-11 Utilities Rate Philosophy
13-Sep-11 Proposed Comm. & Res. Electric Rate Options
11-Oct-11 Residential Electric Rate Options, Efficiency and Conservation
18-Oct-11 First Reading of Ordinance No. 142, 2011 (Comm / Ind & Res Demand)
1-Nov-11 Second Reading of Ordinance No. 142, 2011 (Comm / Ind & Res Demand)
15-Nov-11 First Reading of Ordinance No. 166, 2011 (Res Tiered Rates)
6-Dec-11 Second Reading of Ordinance No. 166, 2011 (Res Tiered Rates)
3
5
City Council Presentations to Date
Council Finance Committee
Meeting Subject
15-Aug-11 Electric Rate Options
17-Oct-11 Recommended Rates and Fees
Electric Board
Meeting Subject
06-Apr-11 Rate Design Philosophy / PRPA Wholesale Rate Discussion
04-May-11 Rate Forms
03-Aug-11 Rate Options
06-Oct-11 Update on Rate Forms from 9/13 Council Work session
06-Oct-11 Rate Recommendations
6
2012 Electric Rate Increases
Rate Class Non-Summer Summer Annual
Residential 2.0% 16.8% 6.0%
Residential Demand 15.1% 19.6% 15.9%
GS Small Commercial -1.6% 18.1% 3.9%
GS25 Medium Commercial 10.9% 27.0% 15.5%
GS50 Large Commercial 4.7% 20.0% 8.7%
GS750 Industrial 7.6% 20.7% 11.0%
System 4.4% 19.2% 8.3%
4
7
GS50 & GS750 Customer Response
•• Following the passage of Ordinance No.
142, 2011 concerns were expressed to
Council and City Staff
•• Several options have been evaluated to
address these concerns
•• Customer outreach and communication
8
Commercial and Industrial Rates
5
9
Rate History
Cost of Electricity Commercial
Source: Energy Information Administration
0
2
4
6
8
10
12
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
YTD
Customer cost in cents per kWh
National Average Fort Collins Colorado Average
10
Rate History
Cost of Electricity Industrial
Source: Energy Information Administration
0
1
2
3
4
5
6
7
8
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
YTD
2012
Est
Customer cost in cents per kWh
National Average Fort Collins Colorado Average
6
11
CO Large Commercial Electric Rates
Colorado Association of Municipal Utilities Large Commercial Rate Survey
January 2011 --- Cost for 45,000 kWh and 130 KW per month
$3,423
$3,048
GUNNISON
LONGMONT 2011
FORT COLLINS 2011
LOVELAND 2011
LONGMONT 2012
ESTES PARK
COLORADO SPRINGS
FLEMING
LOVELAND 2012 - Average
FT COLLINS 2012 - Average
XCEL ENERGY
UNITED POWER
BLACK HILLS ENERGY
POUDRE VALLEY EA
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
FORT COLLINS LOVELAND LONGMONT INVESTOR OWNED MUNICIPAL/REA
12
CO Industrial Electric Rates
Colorado Association of Municipal Utilities Industrial Rate Survey
January 2011 --- Cost for 1,900,000 kWh and 3000 KW per month
$90,827
$104,260
$0
$25,000
$50,000
$75,000
$100,000
$125,000
$150,000
$175,000
$200,000
$225,000
FORT COLLINS 2011
TRI-COUNTY
LONGMONT 2011
LOVELAND 2011
COLORADO SPRINGS
LONGMONT 2012
FT COLLINS 2012 - Average
LOVELAND 2012 - Average
XCEL ENERGY
UNITED POWER
BLACK HILLS ENERGY
POUDRE VALLEY EA
FORT COLLINS LOVELAND LONGMONT INVESTOR OWNED MUNICIPAL/REA
7
13
GS50 and GS750 Rate Structure
•• ““UUnnbbuunnddlleedd”” rates
–– Fixed Charge
–– Distribution Facilities Charge
–– Purchased Power components
•• Energy
•• Coincident Peak Demand
–– PILOT
14
Rate Increase Drivers
•• Platte River Power Authority (PRPA)
–– Commodity costs increasing
•• Coal contracts
–– Cost of Service Study
•• Rate structure adjusted
–– (Please see PRPA presentation)
•• Distribution / Facility Charges
–– Capital additions are not yet fully funded
–– Reserves draw down slowed
8
15
Rate Increase Drivers
-13% -12%
17%
9%
11%
-13%
22%
18%
4%
2%
3%
8%
-15%
-10%
-5%
0%
5%
10%
15%
20%
25%
GS50 GS750 System
PP Demand PP Energy Dist fac Total Increase
16
Components of the Increase
Number Projected Projected Revenue Proportion of
of Customers 2011 Revenues 2012 Revenues Increase 2012 Increase
GS50 Large Commercial
Purchase Power $14,607,324 $15,652,767 $1,045,443 65%
Distribution $3,931,085 $4,501,954 $570,869 35%
Total 470 $18,538,409 $20,154,721 $1,616,312 100%
% Increase 8.7%
GS750 Industrial
Purchase Power $15,258,751 $16,875,908 $1,617,157 85%
Distribution $1,996,178 $2,284,899 $288,721 15%
Total 15 $17,254,929 $19,160,807 $1,905,878 100%
% Increase 11.0%
9
17
Options for Consideration
18
Options for Consideration
•• Option 1 –– Customer Outreach, Education, &
Potential Incentives
•• Option 2 –– Eliminate Distribution Facilities
Charge Increase for GS50 & GS750 only
•• Option 3 –– Decrease PILOT for GS50 & GS750
only
•• Option 4 –– PRPA Reconsideration of Increase
10
19
Option 1 –– Customer Outreach
•• No change to the adopted rate ordinance
•• Aggressively market energy conservation
programs
•• Explore potential economic incentives for
expansion
Pros
•• Sends correct price signal
•• Appropriately allocates costs
across all rate classes
•• Encourages conservation
Cons
•• Requires customer investment
20
Option 2 –– Hold Dist. Facility Charges
•• Adopt new rate ordinance to keep the Distribution
Facilities charge for these two rate classes at
2011 levels
Pros
•• Would reduce overall rate
increase for these two classes
•• GS50 from 8.7% to 5.6%
•• GS750 from 11.0% to 9.4%
Cons
•• Requires modification of approved
rate ordinance
•• Undermines integrity of Cost of
Service Rate Structure
•• Requires subsidization by other
rate classes or further drawdown of
Reserve Fund
11
21
Option 3 –– Decrease PILOT
•• Adopt new rate ordinance to set the Payment in-in -
lieu of taxes charge for these two rate classes at a
lower level than that of the other rate classes
Pros
•• Would reduce overall rate
increase for these two classes
by 1% for each 1% reduction in
PILOTs
•• No cost/revenue impact to
LightPower Light & Power
Cons
•• Requires modification of
approved rate ordinance
•• Reduces General Fund
Revenue by $370K for each 1%
reduction
•• Unfair to other rate classes
22
Option 4 –– PRPA Reconsideration
•• Request that PRPA Board reconsider the 2012
rate increase it unanimously approved 10/27/11
–– Reconsideration of overall rate increase
–– Reconsideration of rate structure change
Pros
•• Potentially reduces costs to
all rate classes temporarily
•• PRPA could use their Rate
Stabilization Fund to soften the
increase for all municipalities
Cons
•• PRPA Board has already
unanimously approved rate increase
•• Maintaining full 6.4% increase but
shifting costs back from energy to
demand would increase rates
inaccurately for other rate classes
12
23
Staff Recommendation
•• Option 1 –– Customer Outreach & Education
–– No change to the adopted rate ordinance
–– Aggressively market energy conservation
programs
–– Explore potential economic incentives
–– Consistent with rate principles
•• Encourages conservation for all rate classes
•• Fairly allocates costs of service to each rate
class
24
Other Considerations
•• PRPA Rate Increase in 2013
•• Other factors
13
25
Questions for City Council
•• Are there other options that staff has not presented
that should be explored?
•• Of the options presented, which option is preferred?
•• Should staff prepare an ordinance to revise the
commercial and industrial rates for 2012?
26
End of Presentation
Attachment 10
1
WHOLESALE RATE REVIEW
PLATTE RIVER POWER AUTHORITY
Fort Collins City Council December 7, 2011
BACKGROUND
2
Attachment 10
2
LOCAL ELECTRIC SYSTEM
Residential
Small
Business
Large
Business
Distri-
bution
Transmission
Generation
Customers
Estes Park
Fort Collins
Longmont
Loveland
Platte River Power Authority
• Sole Electricity Supplier
• Joint Ownership / Equity
• Local Governance
3
LOCAL ELECTRIC COSTS – AVERAGE SPLIT
~ 71% ~ 29%
Generation & Transmission
(Wholesale)
Distribution
(Retail)
4
Attachment 10
3
Rawhide Unit 1 (coal) – 278 MW
Rawhide Units A B C D & F
Natural gas – 388 MW total
Craig Units 1&2 (coal) – 154 MW total
Craig Unit 3 – 100 MW Shaft Sharing
Hydropower – 90 MW Summer (seasonal
variability)
Wind – 20 MW (intermittent)
Total 2011 Load – 640 MW (Peak)
Total 2011 Firm Resources – 910 MW
EXISTING RESOURCES
Municipalities Municipalities and and Surplus Surplus Sales Sales
5
6
Attachment 10
4
HISTORICAL WHOLESALE RATES
Average Wholesale Rate History
Historical Factors:
• Rates 28% above 1982
• Same basic rate structure
• Increases began in 2004:
o Added peaking
o Lower surplus sales
o Fuel cost (coal & gas)
o Hydro changes
o Hydro cost
o New transmission
o Increased O&M
Historical Factors:
• Rates 28% above 1982
• Same basic rate structure
• Increases began in 2004:
o Added peaking
o Lower surplus sales
o Fuel cost (coal & gas)
o Hydro changes
o Hydro cost
o New transmission
o Increased O&M
-
10
20
30
40
50
$ / MWh
7
RATE DRIVERS – 2011 to 2012
8
Attachment 10
5
WHOLESALE SURPLUS SALES TREND
Surplus Sales Prices
$/MWh
9
RATE STRUCTURE CHANGE
10
Attachment 10
6
RATE MAKING PROCESS
Non-Municipal
Revenues
Wholesale Rates
Retail
Customers
(By Class)
Retail (Municipal) Rates
Municipal Rate Designs
(All Different)
12
Set by
Platte River Board Set by each Municipality
RATE STRUCTURE STUDY – TIMELINE
Fall 2009
Initial
Study
Review
(Staff)
Feb 2010
Retained
Consultant
(UFS)
Management
Team
Kick-off
Data
Collection
“Phase I”
Scope
May –
Jun 2010
City Staff
Review
Directors
Meeting
Review
City Staff
Discussions
UFS
Model
Concepts
Initial
Draft
Rates
Meeting
With City
Rate staffs
Review
of
Staff input
Apr 2010
Platte River
Board
Review
Jul 2010
Platte River
Board
Attachment 10
7
WHY CONSIDER A CHANGE ?
Update Cost Allocations
Same basic wholesale rate
design for over 30 years
Changes since initial design:
o Loads and resources
o Seasonal differences
o Credits & other allocations
New models needed for
implementing future wholesale
rates
Rate / Cost Alignment
Improve rate design to better
reflect supply costs
o Overall cost of service
o Costs vs. time (seasonal,
day type, time of day)
o Direct pass-through
(increasing)
o Expanding load control &
other technologies
13
Coal unit fuel 100% energy 100% energy
Coal variable O&M 100% energy 100% energy
Other purchases 100% energy 100% energy
Gas unit fuel 100% energy 100% energy
Gas unit debt 100% demand 100% demand
Transmission 100% demand 100% demand
ALLOCATIONS STAYING THE SAME
COST CATEGORY EXISTING PROPOSED
14
Attachment 10
8
Surplus sales 100% energy (credit) 67% energy
Hydropower 53% energy 74% energy
Coal unit debt 100% demand 24% demand
Coal fixed O&M 100% energy 76% energy
Windy Gap 100% demand 24% demand
Gas O&M 100% energy 20% energy
Ancillary services 100% energy 100% demand
Admin./General 100% energy 67% energy
Interest income 85% energy (credit) 67% energy
ALLOCATION CHANGES
CATEGORY EXISTING PROPOSED
15
KEY CHANGES
Seasonal cost differences added:
New natural gas peaking units & related infrastructure (summer)
Surplus sales credit:
Historically applied 100% to energy charge
Now applied based on overall demand/energy allocation
Hydropower operations:
Constraints have reduced flexibility to meet peak demand
Now operated similar to coal units – base load resources
Base load fixed costs:
Debt and fixed O&M now treated consistently
Less recovered at time of coincident peak
More recovered over all operating periods
16
Attachment 10
9
PEAKING RESOURCE ADDITIONS
1996
Last year of winter peak
All coal & hydro
Avg. monthly peak = 89% of annual
Seasonal difference = 5% or 18 MW
(Winter higher than summer)
Today
Coal, hydro + gas peaking
Avg. monthly peak = 75% of annual
Seasonal difference = 18% or 129 MW
(Summer much higher than winter)
Daily Peaks
17
LOADS, RESOURCES AND COST RECOVERY
MW
Municipal loads (with reserves & losses)
Highest Load
Surplus Sales
(Coal)
Lowest Load
Load
Following portion
Base-load
portion
Peaking Costs
18
Attachment 10
10
DECISION PROCESS (CONTINUED)
Feb 2011
Platte River
Board
Review
Rate
Structure
Decision
Approval to
incorporate new
structure
…
May 2011
Platte River
Board
Review
Final
Rate
Structure
and
Pricing
Tentative Approval
For 1/1/2012 start
Oct 2011
Platte River
Board
Review
2012
Rate
Approvals
… …
19
Season
Energy
(¢/kWh)
Demand
$/kW
All Months 2.310 12.42
Historical
Rate
Structure
New 2012
Seasonal
Demand &
Energy Rate
Reflects seasonal cost differences
Aligns rates with other costs – lower peak demand / higher energy
Relatively simple for metering and billing
Positions for future time-of-day rate making (new models)
Wholesale structure only – retail implementation varies by City
Season
Energy
(¢/kWh)
Demand
$/kW
Summer (Jun – Aug) 3.513 10.05
Spring, Fall & Winter 3.340 7.53
WHOLESALE RATE CHANGES
Attachment 10
11
FUTURE WHOLESALE RATE TRENDS
Multiple Unknowns:
• Surplus sales prices
• Coal prices (and gas)
• Environmental regulations
• Water supply firming
• New capacity resources
• Renewable energy
• Other capital projects
• Future O&M
• Climate change
Multiple Unknowns:
• Surplus sales prices
• Coal prices (and gas)
• Environmental regulations
• Water supply firming
• New capacity resources
• Renewable energy
• Other capital projects
• Future O&M
• Climate change
Average Wholesale Rate Increases
21
RATE COMPARISONS
22
Attachment 10
12
COLORADO WHOLESALE RATES
Platte River Tri-State Xcel ARPA
Wholesale Rate ($/MWh)
49.81
68.80
98.00
88.85
23
$40
$45
$50
$55
$60
$65
$70
$75
$80
$85
$90
Jan 06 Jul 06 Jan 07 Jul 07 Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11
Average Monthly Bill
Other
Municipalities
Investor Owned
Cooperative
Estes Park
Fort Collins
Loveland
Longmont
COLORADO RETAIL RATES – RESIDENTIAL
24
Attachment 10
13
RURAL COOPERATIVE SUPPLIER VS. PLATTE RIVER
-
10
20
30
40
50
60
70
80
$/MWH
PRPA Average Wholesale Rate Tri-State Average Wholesale Rate
25
NATIONAL RATES VS. PLATTE RIVER
-20%
-10%
0%
10%
20%
30%
40%
50%
60%
70%
PRPA Average Wholesale Rate National Retail Rates
26
Attachment 10
14
CONSUMER PRICE INDEX COMPARISON
27
20
Review
Detailed
Review
of UFS
Model &
Suggestions
City Staff
Discussions
(with UFS)
Aug 2010
Platte River
Board
Review
Board
Direction
To
Develop
Detailed
Model &
Draft Rate
Options
“Phase II”
Dec 2010
Platte River
Board
Review
Sep –
Nov 2010
Rate
Options
Development
Integration
of UFS
Suggestions
to In-House
Model
UFS
Support
Management
Team
Review
In-house
Rate
Model
Complete
Draft
Options
Presented
Dec 2010 –
Feb 2011
City Staff
Review
Meetings
With City
Rate staffs
UFS
Support
Feb 2011
Platte River
Board
Review
Final
Rate
Structure
Proposal
11
7
cooperatives
often
share
borders
with
the
Municipalities’
city
limits
and
are
also
not-for-profit
retail electric
suppliers.
About
10
years
ago,
wholesale
rates
to
these
cooperatives
were
about
the
same
as
those
to
Platte
River’s
Municipalities.
Now
these
rates
are
about
38%
higher
than
Platte
River
rates.
Figure
7
shows
a
comparison
of
Platte
River
rate
changes relative
to
changes
in
the
national
average
for
retail
electric
rates.
Since
1982,
Platte
River’s
rates
have
increased
about
20%
while
national
retail
rates
have increased
over
60%.
Though
rates
will
increase
for
2012
and
2013,
Platte
River’s
wholesale
rates
are
the
lowest
in
the
state
and
have
increased
less
than
other
utilities
in
the
region
and
the
nation.
Customers
served
by the
owner
Municipalities
pay
less
for
electricity
than
they
would
if
located
elsewhere.
Figure
5 —
Trends
for
Residential
Electric
Cost
in
Colorado
$90
$85
$80
$75
-
$70
4-.
$65
$60
clj
>
$55
$50
$45
$40
Jan06
Jul06
Jan07
Jul07
Jan08
Jul08
Jan09
Jul09
Jan
10
Jul
10
ian
11
6
are
currently anticipated
in
2014
or
2015
and
an
increase
of
about
3%
is
anticipated
in
2016.
Future
rates
are
difficult
to
predict
due
to
significant
uncertainty
regarding
coal
prices,
surplus
sales
market
prices,
impacts
of
proposed
environmental
regulations,
the
need
for
firming
of
future
water
supply, timing
of
a
new resource
and
transmission
for
the
new
resource, changes
to
capital
project
plans,
addition
of
renewable
energy
sources,
potential
climate
change
regulations and
other
factors.
Each
of
these
factors
would
impact
the
demand
and energy rates
differently.
For
example,
climate
change
regulations
would
increase
energy
charges while
new
gas-peaking
generation
costs
would
increase
demand
charges.
Wholesale
Rate
Comparisons
Platte
River’s
rates
are
increasing.
However,
the
wholesale
rates
from
Platte
River
to
its
owner
Municipalities
remain
relatively
low.
Figure
4
shows
the
rates
for
the
four wholesale
power
suppliers
in Colorado.
Tn-State
serves
rural
electric
cooperatives,
ARPA
(Arkansas
River
Power
Authority)
serves
municipalities
in
southern
Colorado
and
Xcel
Energy
(via
Public
Service
Company
of
Colorado)
serves
wholesale
purchasers
as
well
as
a
large
portion
of
the
retail
customers
in the
state.
Figure
4
—
Wholesale
Rates
in
Colorado
Platte
River
Tn-State
ARPA
Xcel
7-
5
the
wholesale
rate
structure
is
provided
below.
•
Summer
cost
increases
—
Costs
to
provide
electricity
to
the
Municipalities
is
higher
in
the
summer than
in
other months
and therefore rates
are
higher
in
the
summer.
Municipal
loads peaked
in the
winter
until
the
early
1990’s;
1996
was
the
last
year
that
winter
peak
exceeded
summer
peak.
Platte
River
added
gas-fired
combustion turbine units
in
2002,
2004
and
2008
to
help meet
the
Municipalities’
growing
summer
peak
demand.
These
units
added
capital
and operating
costs,
as
well
as
fuel
costs,
which
increase
wholesale
costs in
the
summer
season.
In
2011,
the
summer
peak
was
21%
higher
than
the
winter
peak and
summer
peak
is
expected
to
significantly
exceed
winter
peak
into
the
foreseeable
future.
•
Credit
for
suiplus
sales
—
Historically,
all
revenues
from
surplus
sales
were
credited
to
energy.
This
held
energy
rates
lower
than
they
would
otherwise
have
been.
In
the
new
rate,
surplus
sales
are
credited
on
a
prorated
basis
to
both
demand and
energy
charges.
This
reduces
the
variability
of
energy
and
demand
allocations
associated
with
surplus
sales
(volume
and
market
prices).
•
Coal
units
—
Historically,
100%
of
debt
was allocated
to
demand
charges
and
100%
of
fixed
operating
and maintenance
cost
was
allocated
to
energy
charges. Going
forward,
the
allocation
for
coal
unit
fixed costs
is
about
75%
to
energy
charges
and
25%
to
demand
charges.
This
allocation
is
based
on
charging
the
average
loading
on
the
baseload
resources
to
energy
(average load
is 75%
of
maximum)
and charging
the
difference
between
maximum loading
and
average
loading
to
demand
(maximum
less
average
is
25%
of
maximum).
More
coal
generation
is
used
to
serve
the
Municipalities
during
peak periods
than
at
other
times,
but
a
large
portion
of
this
generation
is
needed
at
all
times.
The
bulk
of
these
costs
are
allocated
to
energy,
since
most
of
the
generation
capability
is
needed
to
serve
load
during
all
hours
of
the
year.
•
Hydropower
purchases
—
En
the
past,
hydropower
could
be
operated
with
more
flexibility
to
meet
changing
Municipal
loads.
Due
to
operational
restrictions
imposed
on
federal
hydropower
units,
hydropower
now
operates
like
a
haseload
resource,
similar
to
the
coal
units.
Costs
for
hydropower
are
now
allocated
to
demand
and
energy charges
using
the
same
approach
as
that
for
allocating
coal
plant
fixed
costs.
4
time-of-use rates
(among
other
options).
The
same
basic
wholesale
rate
structure
has been
in
place
for
over
30
years,
although
much
has
changed
since
the
original
rate
was
designed. Changes
include
higher
increases
in
some
cost
categories
relative
to
others,
reduced
flexibility
of
hydropower
operations
over
time,
addition
of
new
gas-fired
combustion
turbines
at the
Rawhide
site,
upgraded
and
expanded
transmission
infrastructure and
falling
surplus
sales
market
prices.
In
addition
to
these factors,
new
technologies
for
controlling
and/or
displacing
electric
loads
at
time
of
peak
have
expanded
considerably.
Platte
River
and
the
Municipalities
began
evaluating
potential
new wholesale
rate
structures
in
the
fall
of
2009.
This
effort
was
driven
by the
fundamental
goal
of
aligning rate
charges
with
current
costs
—
particularly
as
these
costs
change
with
time (seasonally,
time-of-day,
etc.).
A
team
of
staff
from
the
Municipalities
and Platte
River
worked
together
with
a
rates
consultant
(Utility
Financial Solutions)
to
develop options
for
consideration
by the
Platte
River Board
of
Directors.
Historical
cost
allocations
were
updated
and
detailed
rate
models
were
developed
to
evaluate
changes.
An
initial
draft
set
of
rate options
was
reviewed
with
the
Plate
River
Board
in
April
2010
and evaluation
of
options
continued
through
February
2011.
Five
rate
options were considered:
(1)
single
demand
and
single
energy
charge
—similar
to
the
current
structure,
but with
updated
cost
allocations,
(2)
single
demand
rate
with
on-peak and
off-peak
energy
charges,
(3)
seasonal
rates
with
a
single
demand
and
energy rate
for
each
of
two
seasons
—
summer and
other
months,
(4)
seasonal rates
with
two
peak
demand
charges
—
one
for
summer and
one
for
other
months,
with
on-peak
and
off-peak
energy
charges
for
each season,
and
(5)
seasonal time-of-use
energy
rates
with
no
demand
charge. At
their
February
2011
meeting,
the Board
directed
staff
to
proceed
in
finalizing
a
simple
seasonal
demand/energy
rate
(option
3)
for
implementation
beginning
January
2012.
This
rate
was
reviewed
in
detail
with
staff
from
the
Municipalities
during
2011
and
presented
to
the
Fort
Collins
Electric
Board
in
April
2011.
The
Platte
River
Board
gave
preliminary
approval
to
the
new
rate
structure
in
May
2011
and
final
approval
was
given
at
the
October
27
Board
meeting.
The
table
below
summarizes
the
2012
wholesale rate
(Tariff
1)
and
the projected
impacts
to
each
of
the Municipalities.
As
indicated
in
the
table,
wholesale energy
costs
increased
while
peak
demand
charges
decreased
—
relative
to
the
historical
rate
structure.
Also,
charges
are
higher
in
the
summer
months
than
in
the
winter. Note
that
the
values
in
the
table are
wholesale
rates.
approved
for
sales
to
the
Municipalities
in
2012.
The
Platte
River
Board
approved
these
wholesale
charges,
recognizing that
each
Municipality
allocates
wholesale
costs
and
other
expenses
to
their
customers
as
they
see
fit.
Individual
allocations
are
made
by
each
Municipality
based
on
their
particular
approach
to
retail
rate design.
Decisions
regarding
timing
for
implementation
of
rate changes
at
the
retail
level
are
also
made
by
each
individual
Municipality.
3
for
2012.
Increased
interest
payments
on
debt
for
new
transmission
facilities
and
reduced
interest
income
(net
interest
cost)
are
also
significant,
as
are
increased
depreciation
expenses.
The
remaining
portion
of
the
increase
is
due
to
rising
fuel
costs
and
other
minor
expense
changes.
Figure
2
—
Reasons for
2011
to
2012
Rate
Increase
Other
Factors
Depreciation
5%
Net
Interest
Cost
9
0/
/0
The
price received
for
surplus
sales
is
based
on the
regional
electricity
market, which continues
to
soften.
Figure
3
shows
the
decline
in
monthly average
wholesale prices
since
2008.
Figure
3 —
Wholesale
Surplus
Sales
Prices
, ,
$/MWh
60
55
50
45
40
35
30
25
20
.r___
I
2
sales
in
the
Municipalities
are
70.5%
of
wholesale
sales).
Individual
Municipalities
will
see
wholesale
rate
increases
from
5.5%
to
8.3%;
thu
increase
in Fort
Collins
is
6.4%.
Individual
homes
and
businesses
in
the
Municipalities
will
see
a
range
of
increases,
depending
on
how
(and
when)
the
Municipalities pass
through
the
new
wholesale
rates
to
their
retail
customers.
The
wholesale rate
change
in
2012
is
made
up
of
two
components:
(1)
additional revenue
requirements
to
cover
an overall increase
in
costs
for
providing
electricity
to
the
Municipalities,
and
(2)
changes
to
the
structure
of
the
wholesale
rate.
Additional
background
on
these
changes
is
provided
below.
Wholesale
Rate
Trends
Platte
River
is
a
not-for-profit
entity. Revenues collected from the
Municipalities
are
used
to
cover
wholesale
costs
and
rates
are
based
on
cost
of
electric
service
to
the
Municipalities.
Wholesale
rates
were
relatively
flat
between
1982
and
2003,
as
shown
in
Figure
1.
During
this
period,
no
new
generation
was
built
by
Platte
River,
debt financing
rates
were
generally
declining
and
surplus
sales
revenues
were
a
large
portion
of
total
sales.
“Surplus
sales”
revenues
come
from
electricity
sales
made
to
other
wholesale
purchasers
in
the
region
(beyond
sales
made
to
the
four
owner
Municipalities).
These
additional
sales
reduce
the
need
for
revenues
from the
Municipalities and therefore
reduce
wholesale
rates.
Figure
1 —
Wholesale
Rate
History
Beginning
in
2004,
rates
began
to
increase
due
to
several
factors.
These
included
the
addition
of
new generation
(five
new
natural
gas-fired
combustion turbine
units
at Rawhide
with
a
new
gas
pipeline
and
other
infrastructure),
reduced
surplus
sales
(both
volume
and
price),
increased
fuel
costs
(coal
and
natural
gas),
changes
in
hydropower
operations,
increased
hydropower
purchase
costs,
capital
costs
for
upgrading
transmission
system
reliability and
increased
operation
and
maintenance
costs
for
the
power plants.
50
-
40
30
20
10
-10%
-5%
0%
5%
10%
15%
20%
25%
R RD GS GS25 GS50 GS750 System
Rate Class
% of total increase
PP Demand PP Energy Dist fac Total Increase