HomeMy WebLinkAbout2007-066-07/17/2007-CONCERNING IMPLEMENTATION OF STANDARDS CREATED BY AMENDMENTS TO THE PUBLIC UTILITY REGULATORY POLICI RESOLUTION 2007-066
OF THE COUNCIL OF THE CITY OF FORT COLLINS
CONCERNING IMPLEMENTATION OF STANDARDS CREATED BY
AMENDMENTS TO THE PUBLIC UTILITY REGULATORY POLICIES
ACT OF 1978 BY THE UTILITY
WHEREAS, the City's electric utility enterprise, Fort Collins Utilities (the "Utility"), is
subject to the Public Utility Regulatory Policies Act of 1978 ("PURPA") found at 16 United
States Code §2601, et. seq.; and
WHEREAS, the purposes of PURPA are to encourage the conservation of energy
supplied by electric utilities, to optimize the efficiency of use of facilities and resources by
electric utilities, and to ensure equitable rates to electric customers; and
WHEREAS, in 1992 Congress amended PURPA by enacting the Comprehensive
National Energy Policy Act of 1992 (the "1992 Act"); and
WHEREAS, the 1992 Act required the Utility to consider adoption of a new energy
standard, the Integrated Resource Planning ("IRP") Standard, after providing public notice and
in a public hearing, and to make a determination whether to implement the IRP Standard; and
WHEREAS, pursuant to the 1992 Act, City Council conducted a public hearing on
October 19, 1993, at which it considered the IRP Standard and adopted such standard through
the approval of Resolution 1993-150; and
WHEREAS, in 2005, PURPA was further amended by the enactment of the Energy
Policy Act of 2005 ("the 2005 Act") which added five new standards that address the following
topics: net metering, fuel sources, fossil fuel efficiency, time-based metering and
interconnection; and
WHEREAS, the 2005 Act requires regulatory authorities and utilities to consider the
standards, after notice and public hearing, and to make a determination in writing whether or not
to implement such standards; and
WHEREAS, if a utility determines that it is not appropriate to implement a particular
standard, it may do so as long as it sets forth its reasons in writing; and
WHEREAS, the process of reviewing and considering the new standards was initiated by
the Utility by virtue of a memorandum dated June 14, 2006, from the Utilities General Manager
to the Mayor and City Council, a copy of which memorandum is attached hereto and
incorporated herein by this reference as Exhibit"A"; and
WHEREAS, City staff has reviewed each of the five federal standards established by the
2005 Act, considered and made determinations regarding each standard, and made
recommendations to City Council with regard to each of the standards in a Staff Report that is
marked as Exhibit`B", attached hereto and incorporated herein by this reference; and
WHEREAS, at its regular meeting on May 16, 2007, the Electric Board considered a
draft of the Staff Report prepared by Utility staff and voted unanimously to recommend that the
City Council approve the report; and
WHEREAS, in accordance with the procedural requirements for consideration and
determination of certain ratemaking standards contained in PURPA, public notice of City
Council's consideration of the PURPA standards was published on Sunday, July 1, 2007; and
WHEREAS, the written determinations made herein by the City Council are based upon
findings included in the Staff Report and upon evidence presented at the hearing, and will
hereafter be available to the public in the office of the City Clerk.
NOW, THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY OF
FORT COLLINS as follows:
Section 1. Upon review and consideration of each of the federal standards and as
outlined by staff in Exhibit B, the Council hereby finds that it is in the best interests of the City
of Fort Collins to adopt the determinations made by staff in the Staff Report
Section 2. That this review of the standards of PURPA, consideration of each
standard, public notice of hearing and public hearing, and the passage of this Resolution
complete the consideration and determination process required by PURPA.
Passed and adopted at a regular meeting of the it of the City of Fort ollins this
17th day of July, A.D. 2007.
Mayo
ATTEST:
City Clerk
-2-
EXHIBIT A
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e=ectric - stourtwater • wastewater - water
Citv of Fort Collins
MEMORANDUM
Date: June 14, 2006
To: Mayor and City Council Members
Thru: Darin Atteberry, City Manager
From: Michael Smith, Utilities General Manager M%
Re: PURPA Provisions Contained in the Energy Policy Act of 2005 (P.L. 109-58)
In August 2005, the United States Congress adopted the federal Energy Policy Act of
2005 (P.L. 109-58), which amends the Public Utility Regulatory Policies Act of 1978
(PURPA) to require state regulatory authorities and certain nonregulated utilities to
conduct assessments regarding the implementation of federal standards relating to net
metering, smart metering and interconnections. Because the City of Fort Collins
Electric Utility has retail sales in excess of 500 million kWh, it is subject to these PURPA
provisions. PURPA, as amended, requires that the City take formal action to consider
the following standards for electric service (but does not require the adoption of any of
these standards):
• Within two years of enactment (August 8, 2007), affected parties are required to
have commenced consideration of net metering standards or have set a hearing
date for such consideration. This process must be completed within three years
of enactment (August 8, 2008.)
• Within one year of enactment (August 8, 2006), affected parties are required to
have commenced consideration of smart metering standards or have set a
hearing date for such consideration. This consideration and determination must
be completed within two years of enactment (August 8, 2007.)
• Within one year of enactment (August 8, 2006), affected parties are required to
have commenced consideration of interconnection standards or have set a
hearing date for such consideration. This consideration and determination must
be completed within two years of enactment (August 8, 2007.)
The City's Electric Utility has considered these issues in earlier policy planning and has
already begun implementation of some related programs. However, under PURPA the
City will be required to review these considerations during the timeframes noted. This
memorandum is intended to advise the City Council and to document for the public
record that City staff has commenced working to evaluate the feasibility of modifying or
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EXHIBIT A
adopting new metering/interconnection standards in accordance with PURPA
requirements with the assistance of Platte River Power Authority staff. A formal City
Council hearing to consider the matters listed above will be required after completion of
this staff review. It is the intention of staff to provide the Mayor and City Council with
recommendations to be scheduled for the required public hearing prior to August 8,
2007.
Several PURPA related documents have been posted on APPA's website as part of a
new webpage devoted to the Energy Policy Act of 2005. These materials may be
accessed at http://www.appanet.org/legislative/index.cfm?ltemNumber=13734
cc: Diane Jones, Deputy City Manager
Carrie Daggett, Sr. Assistant City Attorney
EXHIBIT "B"
Exhibit B ("Staff Report")
Fact Sheets Regarding Consideration of the
Public Utility Regulatory Policies Act(PURPA) of 1978
As Amended by the Energy Policy Act of 2005
Fort Collins City Council—Regular Meeting
July 17, 2007
In August 2005, the United States Congress adopted the federal Energy Policy Act of 2005 (P.L.
109-58), which amends the Public Utility Regulatory Policies Act of 1978 (PURPA)to require
state regulatory authorities and certain nonregulated utilities to conduct assessments regarding
the implementation of federal standards relating to net metering, smart metering and
interconnections. Because the City of Fort Collins Electric Utility has retail sales in excess of
500 million kWh, it is subject to these PURPA provisions. PURPA as amended requires that
regulatory authorities and utilities consider the standards after notice and public hearing and to
make a determination in writing whether or not to implement such standards. A regulatory
agency or utility may determine that it is not appropriate to adopt a particular standard and may
decline to do so as long as it sets forth its reasons in writing. The Utility is not in violation of
the law where it cannot meet a standard contained in PURPA.
Page 2 of 22
FACTSHEET
Legislation: Energy Policy Act of 2005 —PURPA Amendments
Requirement: Consideration of PURPA Standards (Appendix A)
Standard: Net Metering, (Section 1251 (a) (11))
"Each electric utility shall make available upon request net metering service to
any electric consumer that the electric utility serves."
Goal: Equitable rates to electric consumers
Definition: Service to an electric consumer under which electric energy generated by that
electric consumer from an eligible on-site generating facility and delivered to the
local distribution facilities may be used to offset electric energy provided by the
electric utility to the electric consumer during the applicable billing period.
Status: The Code, regulations, policies and practices of the City's Utility meet this
standard.
Key Points:
4 The Utility allows for net metering under the"special services"provision of the current
electric rate schedules.
4, Customer-owned electric generation in excess of monthly consumption is credited at the
C g y p
appropriate avoided cost of purchased power in accordance with applicable Platte River
Power Authority(PRPA) tariffs.
Net metering is currently available to both commercial and residential customers. Net
metering for residential customers is made available under the demand(RD) rate or at the
standard residential rate (R) through participation in a five-year parallel generation pilot
program (Jan. 2005 - Dec. 2009). Staff will be using data collected during the pilot
program to develop a separate residential parallel generation rate that includes a net
metering provision similar to that of non-residential rates.
Page 3 of 22
FACT SHEET
Legislation: Energy Policy Act of 2005 —PURPA Amendments
Requirement: Consideration of PURPA Standards
Standard: Fuel Sources Standard, (Section 1251 (a) (12))
"Each electric utility shall develop a plan to minimize dependence on one fuel
source and to ensure that the electric energy it sells to consumers is generated
using a diverse range offuels and technologies including renewable
technologies. "
Goal: Promotion of renewable energy generation
Status: The Code, regulations, policies and practices of the City's Utility meet this
standard to the extent possible through its membership and participation in Platte
River Power Authority("PRPA").
Key Points:
*1. The City owns PRPA jointly with Loveland, Longmont and Estes Park. This standard
does not apply directly to the Utility as the Utility does not own or operate any electric
generation facilities. Through its participation in PRPA's governance, the Utility acts to
develop a plan to minimize dependence on one fuel source and to ensure that the electric
energy it sells to consumers is generated using a diverse range of fuels and technologies,
including renewable technologies. PRPA uses multiple resources (fossil fuel, wind,
hydro, purchased power) to meet the needs of the four member cities. Resources used to
serve the municipalities in 2006 included 74.8% coal, 18.7% hydro, 3.8% purchases,
1.6% renewable and 1.1% natural gas.
4 PRPA reviews its future fuel needs on a regular basis, with several factors impacting
these requirements. The fuel mix can be impacted by factors such as availability of
hydropower or wind resources, scheduled maintenance of generation units, fuel price, and
wholesale market prices.
4k PRPA maintains an Integrated Resource Plan(IRP) that describes future capacity and
energy supply resources, as well as renewable energy and energy efficiency options. The
IRP provides information associated with the planning of resource acquisitions to meet
customers' future electrical energy needs, including capacity and energy supply
resources, renewable energy and energy efficiency options. All resource plans and
budgets are approved by the eight-member PRPA Board of Directors. The IRP is
updated annually, with a formal revision every five years. The IRP and associated budget
is approved by the eight members of the PRPA board of directors. The City of Fort
Collins is currently represented on the board by the Mayor and Utilities General
Manager.
Page 4 of 22
4- When Council adopted the Energy Supply Policy in March 2003, the Council established
specific renewable energy goals including the goal of a 15% renewable portfolio by 2017.
These goals are regularly communicated to PRPA and reflected in planning efforts.
Page 5 of 22
FACTSHEET
Legislation: Energy Policy Act of 2005 — PURPA Amendments
Requirement: Consideration of PURPA Standards
Standard: Fossil Fuel Generation Efficiency Standard, (Section 1251 (a) (13))
"Each electric utility shall develop and implement a 10 year plan to increase the
efficiency of its fossil fuel generation."
Goal: Efficient use of electric utility resources
Status: The Code, regulations, policies and practices of the City's Utility meet this
standard to the extent possible through its membership and participation in
PRPA.
Key Points:
pit. The City owns PRPA jointly with Loveland, Longmont and Estes Park. This standard
does not apply directly to the City of Fort Collins as the City does not own or operate any
electric generation facilities. Through its participation in PRPA's governance, the Utility
acts to develop a plan to increase the efficiency of PRPA's fossil fuel generation.
*4 As part of its annual operating goals, PRPA seeks continued improvement in plant
efficiency at the Rawhide facility. These improvements are reflected in the PRPA
Integrated Resource Plan.
-1. PRPA regularly makes modifications to the Rawhide electric generation plant to improve
efficiency. These include, but are not limited to: improvements to the boiler control
system; turbine upgrades; pump motor upgrades; the addition of efficient lighting;
emission control; and upgrades to the fuel ignition system.
As a part owner of the Craig electric generation facility, PRPA has participated in
evaluation and approval of similar improvements by way of management and oversight
committees.
44 All plant efficiency improvements are approved by the PRPA Board of Directors, either
on an individual project basis or as part of the overall budgeting review process.
Page`, bf 22
FACT SHEET
Legislation: Energy Policy Act of 2005 —PURPA Amendments
Requirement: Consideration of PURPA Standards
Standard: Smart Metering (with Time-Based Schedules), (Section 1252 (a) (14))
"Each electric utility shall offer each of its customer classes, and provide
individual customers upon customer request, a time-based rate schedule under
which the rate charged by the electric utility varies during different time periods
and reflects the variance, if any, in the utility's costs ofgenerating and
purchasing electricity at the wholesale level. The time-based rate schedule shall
enable the electric consumer to manage energy use and cost through advanced
metering and communications technology. "
Goal: Equitable rates to electric consumers - With appropriate rate incentives, utilities
with energy and demand components in wholesale rate structure can seek to shift
consumer use and consequently improve the load factor.
Status: The Utility employs a modified approach to this standard.
Key Points:
4 The City owns PRPA jointly with Loveland, Longmont and Estes Park. PRPA generates
electricity for the Utility and sells the electricity to the Utility at wholesale rates. The
Utility then sells the electricity it distributes to its customers at retail rates that correspond
with PRPA's wholesale tariffs. These retail rates reflect Utility operating costs while also
directly passing on wholesale charges to the customer.
46 PRPA does not currently offer a wholesale rate that includes a time-based component.
4 Prohibitively high costs are currently associated with the Utility providing technology to
its customers to measure time-based use.
4l Time-based rates are electricity rates that vary with time and with the price of product.
Time-based rates may be structured in a number of different ways. The most common
types of time-based rates and those identified in PURPA may be referenced in Appendix
A to this Report, Section 1252(a)(14)(B).
Page 7 of 22
Background:
The City of Fort Collins Electric Utility's cost structure can be broken down into three
components.
1. Distribution Utility costs
These are the costs to cover the metering, billing, operation and maintenance of the electric
system from the distribution substation transformers to the individual customer. These
costs are managed through the budget process and are generally sensitive to the number of
customers and insensitive to the amount of electricity delivered through the distribution
system. They are considered fixed costs and make up approximately 1/3 of the budget.
2. Purchase Power costs
These costs make up 2/3 of the Electric Utility Budget and are evenly split between an
energy component($ per kilowatt hour) which is constant for all use and not time sensitive
and a demand component($ per monthly peak kilowatt) which is time sensitive to a one-
hour period each month. The time of the one-hour period is not known until the end of the
monthly billing period when it is determined when the highest hourly use of electricity can
be calculated. These costs are considered variable costs.
3. Demand costs
The demand component of the purchase power costs are not time-sensitive in the
traditional sense where they vary over determined periods of time and season. Thus the
Utility cannot pass along these time varying costs to its customers. However, given
current metering technology, the Utility has some options to pass along the coincident
peak price signal, particularly to the larger commercial customers.
Residential Customers
Residential customers have historically had uniform or homogeneous load characteristics
among the many users and, as a result, there was not sufficient differentiation to justify
time of use ("TOU") rates to support cost based pricing.
Commercial/Industrial Customers
When advanced metering and communication technology entered the commercial market,
the Utility established a coincident peak rate for larger commercial and industrial (GS-750
and GS-50) customers (slightly less than 500 count). With this rate, the Utility accurately
passes along the customer's contribution to the Utility's monthly wholesale purchase
power bill. Several advantages have followed the implementation of this rate. These
customers have an appropriate price signal to justify demand reduction measures if they
choose to reduce their energy bill. Although the Utility cannot predict exactly the day and
hour of the coming peak there are reasonably defined time periods in which they occur
(Typically from 1:00— 5:00 p.m. on summer weekdays and 5:00—8:00 p.m. on winter
weekdays.). The transition periods such as April, early May and late September are
somewhat more elusive. Customer response to this rate has been similar to that of a
traditional TOU rate. One additional benefit of the coincident peak rate is that the Utility
Page 8 of 22
records 15 minute interval load history and make this information available to the
customers for their own internal analysis.
Things to consider regarding time-based rates:
• Currently, there is no price variation in wholesale purchased power (kilowatt-hours)that
varies with the time of day that can be passed on to customers via a time-based rate
(fundamental goal of the PURPA standard).
• A price signal does exist in the form of a coincident demand component that is based on
the PRPA one-hour system peak each month.
• This coincident demand element is directly passed on to Fort Collins commercial and
industrial customers in their respective rates as a"coincident demand" charge.
• Coincident demand provides customers an incentive to modify use patterns to reduce
energy bills and optimize operations (the intent of the PURPA standard). Several
commercial customers presently monitor the PRPA website for projected electrical load to
predict the best time to alter use patterns, avoid the system peak and reduce energy costs.
• The coincident demand period is relatively predictable, but it is not a strictly defined time
period as it would be under a traditional TOU rate.
• The coincident demand component is currently blended for residential customers, who are
for planning purposes, viewed as a homogeneous load.
• Discussions continue with PRPA to determine if the member cities would be better served
with a time-based wholesale rate and how PRPA might implement this type of tariff.
Potential Benefits:
In general, TOU pricing has the potential to achieve two things.
• Fair(cost based)pricing - If there is significant diversity among the users within a rate
class regarding their electric load patterns and times of peak use, then TOU rates may
more accurately allocate wholesale costs to these customers thus minimizing inevitable
cross subsidies that would occur without this differentiation. Additionally, the more
accurate allocation of such costs would allow the higher cost customers to be effectively
targeted for proactive conservation or DSM measures.
• Load shifting- If there is significant price differentiation between time periods the
customer may have sufficient incentive to change their electric use behavior and reduce
energy bills.
Concerns:
• Many consumers are not willing to commit to appreciable changes in energy use patterns,
and as such, voluntary participation in TOU programs is very limited. "Participation in
TOU rates and other types of residential DR (demand response)programs is generally
low, usually ranging from almost zero to 3%of eligible customers."�"
• One unintended consequence of using residential TOU rates to reduce peak can be a
reduction of revenue without a proportional reduction in system peak. The results of an
Arizona Public Service TOU rate study revealed that, although customers shifted energy
l Randy Gunn,North American Utdiry Demand Response Survey Resultr,Summit Blue Consulting; 150 North Michigan Avenue,Suite 2700,
Chicago,IL,March 7,2007.
gage 9 Of 22
use from higher priced on-peak time periods to lower priced off-peak time periods to save
money, there was little impact of these customers on the system demand peak. The reason
was that for most of the moderately hot days the customers would reduce the use of their
air-conditioning but for the hottest days they were willing to pay that day's increased costs
for air-conditioning comfort. Thus, they achieved cost savings in their monthly bill but
there was not a proportional reduction in system peak savings or the utility's cost of
service.
• If a traditional TOU rate were established, the defined peak period would likely be longer
than the control period currently used by those who actively seek to avoid the monthly
coincident peak period, thus sacrificing some flexibility for predictability.
• Hardware/Communication/Programming Costs.
- The cost of a residential TOU meter is approximately$50 higher than that of a
standard kwh meter. This increase is slightly less for commercial applications.
- Adding communication hardware to a metering location ranges from$60-120 per
residential installation and $200-400 for each commercial/industrial installation(not
including monthly access changes for cell phone based installations).
- While the actual number of customers who would migrate toward a time-based rate
is uncertain, the potential exists to modify more than 60,000 installations.
- Any increased hardware costs would likely be passed on to the customer in the form
of fixed charges. These charges would offset some of the customer savings realized
from altered use patterns under a time-based rate.
- Any changes to pricing periods or seasons would require each meter to be
reprogrammed. There also exists the issue with battery maintenance and
replacement for TOU meters.
Potential Residential Applications:
With the recent growth in whole house air-conditioned homes it has become evident that
there is a difference in costs per kilowatt-hour for these homes as opposed to the older,
non-air-conditioned homes. The more recent whole house air-conditioned homes have a
higher coincidence with the system peak and, as a result, should have a higher cost per
kilowatt hour than the blended class as a whole. TOU pricing could be used for more
fairly differentiating the costs between air-conditioned residential homes and non-air-
conditioned homes but there are factors that make it presently impractical:
• If the rate were voluntary, the current residential rate would be cheaper for an air-
conditioned customer than the optional TOU rate unless that customer significantly
altered their use patterns. This would make the TOU option less appealing.
• If the rate were mandatory for whole house air-conditioned customers we would be in
the difficult position of identifying these customers and then forcing them on the TOU
rate.
• If the rate were mandatory for all customers we would have the staggering task of
purchasing, installing and reading TOU meters for more than 52,000 customers.
Staff has installed load survey meters on more than 33 residential services with air
conditioning(AC) loads. This data is being analyzed to determine the impact of AC on
system peak and whether a time-based rate would better address the cost-of-service for
Page 10 of 22
customers with AC. Data will be used to determine how to apply the coincident demand
component at the residential level including the possibility of a time-based rate. Staff will
continue to monitor and evaluate the cost of metering hardware and communication
options to identify a point at which routine deployment of this equipment is cost-effective.
Page 1 i of22
FACT SHEET
Energy Y
—P P Amendments
Legislation: Ener Policy Act of 2005 UR A
g
Requirement: Consideration of PURPA Standards
Standard: Interconnection, (Section 1254 (a) (15))
"Each electric utility shall make available, upon request, interconnection
service to any electric consumer that the electric utility serves ...
Interconnection services shall be offered based upon the standards developed by
the Institute of Electrical and Electronics Engineers: IEEE Standard 154 7 for
Interconnecting Distributed Resources with Electric Power Systems ...
... services offered shall promote current best practices of interconnection for
distributed generation ...
All such agreements and procedures shall be just and reasonable, and not
unduly discriminatory or preferential. "
Goal: Efficient use of electric utility resources & equitable rates to electric consumers
Status: The Code, regulations, policies and practices of the Utility meet this standard.
Key Points:
Residential interconnection is allowed by the Utility under the demand rate ("RD") or
with approval from the Utilities General Manager.
b Parallel generation for all other rate classes is permitted under the"special provisions"
section of each rate schedule. The details for interconnection are described in the
"Electric Service Rules & Regulations."
For residential customers:
N In an effort to streamline residential interconnection and collect cost-of-service data,
Utilities established a residential pilot parallel generation program in 2004. This five-
year program allows for the first 25 customers who participate to earn credit at the full
retail rate for any electric generation (kilowatt-hours) in excess of their monthly
consumption.
N Energy use data collected from the pilot program will be used to establish a residential
parallel generation rate. This rate is planned for implementation in 2008.
N There are approximately 12 residential PV installations connected to the distribution grid.
Page 12 of 22
For commercial customers:
i✓ A formal application process was developed in 2004
There are 4 large scale commercial distributed generation installations connected to the
distribution system.
Page 13 of 22
Appendix A—Excerpts of the Energy Policy Act of 2005
Subtitle E—Amendments to PURPA
SEC. 1251. NET METERING AND ADDITIONAL STANDARDS.
(a)ADOPTION OF STANDARDS-Section 111(d) of the Public Utility Regulatory
Policies Act of 1978 (16 USC. 2621(d)) is amended by adding at the end the following:
'(11)NET METERING-Each electric utility shall make available upon request
net metering service to any electric consumer that the electric utility serves. For
purposes of this paragraph, the term 'net metering service'means service to an
electric consumer under which electric energy generated by that electric
consumer from an eligible on-site generating facility and delivered to the local
distribution facilities may be used to offset electric energy provided by the electric
utility to the electric consumer during the applicable billing period.
'(12) FUEL SOURCES-Each electric utility shall develop a plan to minimize
dependence on I fuel source and to ensure that the electric energy it sells to
consumers is generated using a diverse range of fuels and technologies, including
renewable technologies.
'(13)FOSSIL FUEL GENERATION EFFICIENCY- Each electric utility shall
develop and implement a 10 year plan to increase the efficiency of its fossil fuel
generation.'.
(b) COMPLIANCE-
(1) TIME LIMITATIONS-Section 112(b) of the Public Utility Regulatory Policies
Act of 1978(16 U.S.C. 2622(b)) is amended by adding at the end the following:
'(3)(A) Not later than 2 years after the enactment of this paragraph, each State
regulatory authority (with respect to each electric utility for which it has ratemaking
authority) and each nonregulated electric utility shall commence the consideration
referred to in section I11, or set a hearing date for such consideration, with respect to
each standard established by paragraphs (11) through (13) of section I II(d).
'(B)Not later than 3 years after the date of the enactment of this paragraph, each State
regulatory authority (with respect to each electric utility for which it has ratemaking
authority), and each nonregulated electric utility, shall complete the consideration, and
shall make the determination, referred to in section I11 with respect to each standard
established by paragraphs (11) through (13) ofsection I11(d).'.
(2) FAILURE TO COMPLY- Section 112(c) of the Public Utility Regulatory
Policies Act of 1978 (16 U.S.C. 2622(c)) is amended by adding at the end the
following:
'In the case of each standard established by paragraphs (11) through (13) ofsection
111(d), the reference contained in this subsection to the date of enactment of this Act
shall be deemed to be a reference to the date of enactment of such paragraphs (11)
through (13).'.
(3) PRIOR STATE ACTIONS-
(A)IN GENERAL-Section 112 of the Public Utility Regulatory Policies
Act of 1978 (16 U.S.C. 2622) is amended by adding at the end the
following:
'(d)PRIOR STATE ACTIONS-Subsections (b) and(c) of this section shall not apply to
the standards established by paragraphs (11) through (13) ofsection 111(d) in the case
of any electric utility in a State if, before the enactment of this subsection--
Page 14 of 22'
'(1) the State has implemented for such utility the standard concerned(or a
comparable standard);
'(2) the State regulatory authority for such State or relevant nonregulated electric
utility has conducted a proceeding to consider implementation of the standard
concerned(or a comparable standard)far such utility; or
'(3) the State legislature has voted on the implementation ofsuch standard(or a
comparable standard)for such utility.'.
(B) CROSS REFERENCE-Section 124 of such Act(16 U.S.C. 2634) is
amended by adding the following at the end thereof 'In the case of each
standard established by paragraphs (11) through (13) of section 111(d),
the reference contained in this subsection to the date of enactment of this
Act shall be deemed to be a reference to the date of enactment of such
paragraphs (11) through (13).'.
SEC. 1252. SMART METERING.
(a) IN GENERAL- Section 111(d) of the Public Utilities Regulatory Policies Act of 1978
(16 US.C. 2621(d)) is amended by adding at the end the following:
(14) TIME-BASED METERING AND COMMUNICATIONS-
'(A) Not later than 18 months after the date of enactment of this
paragraph, each electric utility shall offer each of its customer classes,
and provide individual customers upon customer request, a time-based
rate schedule under which the rate charged by the electric utility varies
during different time periods and reflects the variance, if any, in the
utility's costs ofgenerating and purchasing electricity at the wholesale
level. The time-based rate schedule shall enable the electric consumer to
manage energy use and cost through advanced metering and
communications technology.
'(B) The types of time-based rate schedules that may be offered under the
schedule referred to in subparagraph (A) include, among others--
'(i) time-of-use pricing whereby electricity prices are set for a
specific time period on an advance or forward basis, typically not
changing more often than twice a year, based on the utility's cost
ofgenerating and/or purchasing such electricity at the wholesale
level for the benefit of the consumer. Prices paid for energy
consumed during these periods shall be pre-established and known
to consumers in advance of such consumption, allowing them to
vary their demand and usage in response to such prices and
manage their energy costs by shifting usage to a lower cost period
or reducing their consumption overall;
'(ii) critical peak pricing whereby time-of-use prices are in effect
except for certain peak days, when prices may reflect the costs of
generating and/or purchasing electricity at the wholesale level and
when consumers may receive additional discounts for reducing
peak period energy consumption;
'(iii) real-time pricing whereby electricity prices are set for a
specific time period on an advanced or forward basis, reflecting
the utility's cost ofgenerating and/or purchasing electricity at the
wholesale level, and may change as often as hourly; and
Page 15 of 22
'(iv) credits for consumers with large loads who enter into pre-
established peak load reduction agreements that reduce the
planned capacity obligations of a utility.
'(C) Each electric utility subject to subparagraph (A)shall provide each
customer requesting a time-based rate with a time-based meter capable of
enabling the utility and customer to offer and receive such rate,
respectively.
'(D) For purposes of implementing this paragraph, any reference
contained in this section to the date of enactment of the Public Utility
Regulatory Policies Act of 1978 shall be deemed to be a reference to the
date of enactment of this paragraph.
'(E)In a State that permits third party marketers to sell electric energy to
retail electric consumers, such consumers shall be entitled to receive the
same time-based metering and communications device and service as a
retail electric consumer of the electric utility.
'(F)Notwithstanding subsections (b) and(c) of section 112, each State
regulatory authority shall, not later than 18 months after the date of
enactment of this paragraph conduct an investigation in accordance with
section 115(i) and issue a decision whether it is appropriate to implement
the standards set out in subparagraphs (A) and(Q.'.
(b) STATE INVESTIGATION OF DEMAND RESPONSE AND TIME-BASED
METERING-Section 115 of the Public Utilities Regulatory Policies Act of 1978(16
U.S.C. 2625) is amended as follows:
(1) By inserting in subsection (b) after the phrase 'the standard for time-of-day
rates established by section 111(d)(3)'the following: 'and the standard for time-
based metering and communications established by section 111(d)(14)'.
(2) By inserting in subsection (b) after the phrase 'are likely to exceed the
metering'the following.• 'and communications'.
(3) By adding at the end the following:
'(i) TIME-BASED METERING AND COMMUNICATIONS-In making a determination
with respect to the standard established by section 111(d)(14), the investigation
requirement of section 111(d)(14)(F)shall be as follows: Each State regulatory authority
shall conduct an investigation and issue a decision whether or not it is appropriate for
electric utilities to provide and install time-based meters and communications devices for
each of their customers which enable such customers to participate in time-based pricing
rate schedules and other demand response programs.'.
(c) FEDERAL ASSISTANCE ONDEMAND RESPONSE- Section 132(a) of the Public
Utility Regulatory Policies Act of 1978 (16 U.S.C. 2642(a)) is amended by striking 'and'
at the end of paragraph (3), striking the period at the end of paragraph (4) and inserting
and, and by adding the following at the end thereof:
'(5) technologies, techniques, and rate-making methods related to advanced
metering and communications and the use of these technologies, techniques and
methods in demand response programs.'.
(d) FEDERAL GUIDANCE- Section 132 of the Public Utility Regulatory Policies Act of
1978 (16 U.S.C. 2642) is amended by adding the following at the end thereof
'(d) DEMAND RESPONSE- The Secretary shall be responsible for--
'(]) educating consumers on the availability, advantages, and benefits of
advanced metering and communications technologies, including the funding of
demonstration or pilot projects;
_;
Paga 1f 4,22
'(2) working with States, utilities, other energy providers and advanced metering
and communications experts to identify and address barriers to the adoption of
demand response programs; and
'(3) not later than 180 days after the date of enactment of the Energy Policy Act
of 2005,providing Congress with a report that identifies and quantifies the
national benefits of demand response and makes a recommendation on achieving
specific levels of such benefits by January 1, 2007.'.
(e) DEMAND RESPONSE AND REGIONAL COORDINATION-
(1) IN GENERAL-It is the policy of the United States to encourage States to
coordinate, on a regional basis, State energy policies to provide reliable and
affordable demand response services to the public.
(2) TECHNICAL ASSISTANCE- The Secretary shall provide technical assistance
to States and regional organizations formed by 2 or more States to assist them in-
(A) identifying the areas with the greatest demand response potential;
(B) identifying and resolving problems in transmission and distribution
networks, including through the use of demand response;
(C) developing plans and programs to use demand response to respond to
peak demand or emergency needs; and
(D) identifying specific measures consumers can take to participate in
these demand response programs.
(3) REPORT-Not later than 1 year after the date of enactment of this Act, the
Commission shall prepare and publish an annual report, by appropriate region,
that assesses demand response resources, including those available from all
consumer classes, and which identifies and reviews--
(A)saturation and penetration rate of advanced meters and
communications technologies, devices and systems;
(B) existing demand response programs and time-based rate programs;
(C) the annual resource contribution of demand resources;
(D) the potential for demand response as a quantifiable, reliable resource
for regional planning purposes;
(E) steps taken to ensure that, in regional transmission planning and
operations, demand resources are provided equitable treatment as a
quantifiable, reliable resource relative to the resource obligations of any
load-serving entity, transmission provider, or transmitting party; and
(F) regulatory barriers to improved customer participation in demand
response,peak reduction, and critical period pricing programs.
69 FEDERAL ENCOURAGEMENT OF DEMAND RESPONSE DEVICES-It is the
policy of the United States that time-based pricing and other forms of demand response,
whereby electricity customers are provided with electricity price signals and the ability to
benefit by responding to them, shall be encouraged, and the deployment of such
technology and devices that enable electricity customers to participate in such pricing
and demand response systems shall be facilitated, and unnecessary barriers to demand
response participation in energy, capacity, and ancillary service markets shall be
eliminated. It is further the policy of the United States that the benefits ofsuch demand
response that accrue to those not deploying such technology and devices, but who are
part of the same regional electricity entity, shall be recognized.
(g) TIME LIMITATIONS- Section 112(b) of the Public Utility Regulatory Policies Act of
1978 (16 U.S.C. 2622(b)) is amended by adding at the end the following:
Page 17,of22'
'(4)(A)Not later than I year after the enactment of this paragraph, each State
regulatory authority (with respect to each electric utility for which it has
ratemaking authority) and each nonregulated electric utility shall commence the
consideration referred to in section 111, or set a hearing date for such
consideration, with respect to the standard established by paragraph (14) of
section I I I(d).
'(B) Not later than 2 years after the date of the enactment of this paragraph, each
State regulatory authority (with respect to each electric utility for which it has
ratemaking authority), and each nonregulated electric utility, shall complete the
consideration, and shall make the determination, referred to in section III with
respect to the standard established by paragraph (14) of section I I I(d).'.
(h) FAILURE TO COMPLY- Section 112(c) of the Public Utility Regulatory Policies Act
of 1978 (16 U.S.C. 2622(c)) is amended by adding at the end the following:
'In the case of the standard established by paragraph (14) ofsection 111(d), the
reference contained in this subsection to the date of enactment of this Act shall be
deemed to be a reference to the date of enactment ofsuch paragraph (14).'.
(i)PRIOR STATE ACTIONS REGARDING SMART METERING STANDARDS-
(1) IN GENERAL- Section 112 of the Public Utility Regulatory Policies Act of
1978 (16 U.S.C. 2622) is amended by adding at the end the following:
'(e) PRIOR STATE ACTIONS- Subsections (b) and(c) of this section shall not apply to
the standard established by paragraph (14) of section I I l(d) in the case of any electric
utility in a State if, before the enactment of this subsection--
'(]) the State has implemented for such utility the standard concerned(or a
comparable standard);
'(2) the State regulatory authority for such State or relevant nonregulated electric
utility has conducted a proceeding to consider implementation of the standard
concerned(or a comparable standard)for such utility within the previous 3
years; or
'(3) the State legislature has voted on the implementation of such standard(or a
comparable standard)for such utility within the previous 3 years.'.
(2) CROSS REFERENCE- Section 124 ofsuch Act (16 US.C. 2634) is amended
by adding the following at the end thereof. 'In the case of the standard
established by paragraph (14) of section I I1(d), the reference contained in this
subsection to the date of enactment of this Act shall be deemed to be a reference
to the date of enactment ofsuch paragraph (14).'.
SEC. 1253. COGENERATIONAND SMALL POWER PRODUCTION PURCHASE AND SALE
REQUIREMENTS.
(a) TERMINATION OF MANDATORY PURCHASE AND SALE REQUIREMENTS-
Section 210 of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 824a-3) is
amended by adding at the end the following:
'(m) TERMINA TION OF MANDA TOR Y PUR CHASE AND SALE REQUIREMENTS-
'(1) OBLIGATION TO PURCHASE-After the date of enactment of this
subsection, no electric utility shall be required to enter into a new contract or
obligation to purchase electric energy from a qualifying cogeneration facility or a
qualifying small power production facility under this section if the Commission
finds that the qualifying cogeneration facility or qualifying small power
production facility has nondiscriminatory access to--
Page 18 of 22
'(A)(i) independently administered, auction-based day ahead and real
time wholesale markets for the sale of electric energy; and(ii) wholesale
markets for long-term sales of capacity and electric energy; or
'(B)(i) transmission and interconnection services that are provided by a
Commission-approved regional transmission entity and administered
pursuant to an open access transmission tariff that affords
nondiscriminatory treatment to all customers; and(ii) competitive
wholesale markets that provide a meaningful opportunity to sell capacity,
including long-term and short-term sales, and electric energy, including
long-term, short-term and real-time sales, to buyers other than the utility
to which the qualifying facility is interconnected. In determining whether a
meaningful opportunity to sell exists, the Commission shall consider,
among other factors, evidence of transactions within the relevant market;
or
'(C) wholesale markets for the sale of capacity and electric energy that
are, at a minimum, of comparable competitive quality as markets
described in subparagraphs (A) and(B).
'(2) REVISED PURCHASE AND SALE OBLIGATION FOR NEW FACILITIES-
(A)After the date of enactment of this subsection, no electric utility shall be
required pursuant to this section to enter into a new contract or obligation to
purchase from or sell electric energy to a facility that is not an existing qualifying
cogeneration facility unless the facility meets the criteria for qualifying
cogeneration facilities established by the Commission pursuant to the rulemaking
required by subsection (n).
'(B) For the purposes of this paragraph, the term 'existing qualifying
cogeneration facility'means a facility that--
'(i) was a qualifying cogeneration facility on the date of enactment of
subsection (m); or
'(ii) had filed with the Commission a notice ofself-certification, self
recertification or an application for Commission certification under 18
C.F.R. 292.207 prior to the date on which the Commission issues the final
rule required by subsection (n).
'(3) COMMISSION RE VIEW-Any electric utility mayfile an application with the
Commission for relieffrom the mandatory purchase obligation pursuant to this
subsection on a service territory-wide basis. Such application shall set forth the
factual basis upon which relief is requested and describe why the conditions set
forth in subparagraphs (A), (B) or (C) of paragraph (1) of this subsection have
been met. After notice, including sufficient notice to potentially affected qualifying
cogeneration facilities and qualifying small power production facilities, and an
opportunity for comment, the Commission shall make a final determination within
90 days of such application regarding whether the conditions set forth in
subparagraphs (A), (B) or(C) of paragraph (1) have been met.
'(4) REINSTATEMENT OF OBLIGATION TO PURCHASE-At any time after the
Commission makes a finding under paragraph (3) relieving an electric utility of
its obligation to purchase electric energy, a qualifying cogeneration facility, a
qualifying small power production facility, a State agency, or any other affected
person may apply to the Commission for an order reinstating the electric utility's
obligation to purchase electric energy under this section. Such application shall
set forth the factual basis upon which the application is based and describe why
the conditions set forth in subparagraphs (A), (B) or(C) of paragraph (1) of this
Pag��t9'of,22
subsection are no longer met. After notice, including sufficient notice to
potentially affected utilities, and opportunity for comment, the Commission shall
issue an order within 90 days of such application reinstating the electric utility's
obligation to purchase electric energy under this section if the Commission finds
that the conditions set forth in subparagraphs (A), (B) or (C) of paragraph (1)
which relieved the obligation to purchase, are no longer met.
'(5) OBLIGATION TO SELL-After the date of enactment of this subsection, no
electric utility shall be required to enter into a new contract or obligation to sell
electric energy to a qualifying cogeneration facility or a qualifying small power
production facility under this section if the Commission finds that--
'(A) competing retail electric suppliers are willing and able to sell and
deliver electric energy to the qualifying cogeneration facility or qualifying
small power production facility; and
'(B) the electric utility is not required by State law to sell electric energy
in its service territory.
'(6)NO EFFECT ON EXISTING RIGHTS AND REMEDIES-Nothing in this
subsection affects the rights or remedies of any party under any contract or
obligation, in effect or pending approval before the appropriate State regulatory
authority or non-regulated electric utility on the date of enactment of this
subsection, to purchase electric energy or capacity from or to sell electric energy
or capacity to a qualifying cogeneration facility or qualifying small power
production facility under this Act(including the right to recover costs of
purchasing electric energy or capacity).
'(7) RECOVERY OF COSTS- (A) The Commission shall issue and enforce such
regulations as are necessary to ensure that an electric utility that purchases
electric energy or capacity from a qualifying cogeneration facility or qualifying
small power production facility in accordance with any legally enforceable
obligation entered into or imposed under this section recovers all prudently
incurred costs associated with the purchase.
'(B)A regulation under subparagraph (A) shall be enforceable in accordance
with the provisions of law applicable to enforcement of regulations under the
Federal Power Act (16 U.S.C. 791 a et seq.).
'(n) RULEMAKING FOR NEWQUALIFYING FACILITIES- (1)(A) Not later than 180
days after the date of enactment of this section, the Commission shall issue a rule
revising the criteria in 18 C.F.R. 292.205 for new qualifying cogeneration facilities
seeking to sell electric energy pursuant to section 210 of this Act to ensure--
`(i) that the thermal energy output of a new qualifying cogeneration facility is
used in a productive and beneficial manner;
Page 20 of 22
'(ii) the electrical, thermal, and chemical output of the cogeneration facility is
used fundamentally for industrial, commercial, or institutional purposes and is
not intended fundamentally for sale to an electric utility, taking into account
technological, efficiency, economic, and variable thermal energy requirements, as
well as State laws applicable to sales of electric energy from a qualifying facility
to its host facility; and
'(iii) continuing progress in the development of efficient electric energy
generating technology.
'(B) The rule issued pursuant to section (n)(1)(A)shall be applicable only to facilities
that seek to sell electric energy pursuant to section 210 of this Act. For all other
purposes, except as specifically provided in section (m)(2)(A), qualifying facility status
shall be determined in accordance with the rules and regulations of this Act.
'(2)Notwithstanding rule revisions under paragraph (1), the Commission's criteria for
qualifying cogeneration facilities in effect prior to the date on which the Commission
issues the final rule required by paragraph (1)shall continue to apply to any
cogeneration facility that--
'(A) was a qualifying cogeneration facility on the date of enactment of subsection
(m), or
'(B) had filed with the Commission a notice of self-certification, self-
recertification or an application for Commission certification under 18 C.F.R.
292.207 prior to the date on which the Commission issues the final rule required
b '
Yparagraph 1( )• •
(b) ELIMINATION OF OWNERSHIP LIMITATIONS-
(1) QUALIFYING SMALL POWER PRODUCTION FACILITY- Section 3(17)(C)
of the Federal Power Act(16 U.S.C. 796(17)(C)) is amended to read as follows:
'(C) 'qualifying small power production facility'means a small power
production facility that the Commission determines, by rule, meets such
requirements (including requirements respecting fuel use,fuel efficiency,
and reliability) as the Commission may, by rule, prescribe;'.
(2) QUALIFYING COGENERATIONFACILITY-Section 3(18)(B) of the Federal
Power Act(16 U.S.C. 796(18)(B)) is amended to read as follows:
'(B) 'qualifying cogeneration facility'means a cogeneration facility that
the Commission determines, by rule, meets such requirements (including
requirements respecting minimum size,fuel use, and fuel efficiency) as the
Commission may, by rule,prescribe;'.
SEC. 1254. INTER CONNECTION.
(a) ADOPTION OF STANDARDS-Section 111(d) of the Public Utility Regulatory
Policies Act of 1978 (16 U.S.C. 2621(d)) (as amended by section 1252(a)) is amended by
adding at the end the following:
'(15)INTERCONNECTION- (A)In this paragraph, the term 'interconnection
service'means service to an electric consumer by which an on-site generating
facility on the premises of the electric consumer is connected to the local
distribution facilities.
'(B)(i)Each electric utility shall make available, on request, interconnection
service to any electric consumer that the electric utility serves.
'(ii)Interconnection services shall be made available under clause (i) based on
the standards developed by the Institute of Electrical and Electronics Engineers,
entitled 'IEEE Standard 154 7 for Interconnecting Distributed Resources with
Electric Power Systems'(or successor standards).
Page 21 of 22
'(C)(i) Electric utilities shall establish agreements and procedures providing that
the interconnection services made available under subparagraph (B)promote
current best practices of interconnection for distributed generation, including
practices stipulated in model codes adopted by associations of State regulatory
agencies.
'(ii)Any agreements and procedures established under clause (i)shall be just and
reasonable and not unduly discriminatory or preferential.'.
(b) COMPLIANCE-
(1) TIME LIMITATIONS- Section 112(b) of the Public Utility Regulatory Policies
Act of 1978 (16 U.S.C. 2622(b)) (as amended by section 1252(g)) is amended by
adding at the end the following:
'(5)(A) Not later than 1 year after the date of enactment of this paragraph, each
State regulatory authority (with respect to each electric utility for which the State
regulatory authority has ratemaking authority) and each nonregulated utility
shall, with respect to the standard established by section 111(d)(15)--
'(i) commence the consideration under section 111(a); or
'(ii)set a hearing date for the consideration.
'(B) Not later than 2 years after the date of enactment of this paragraph, each
State regulatory authority (with respect to each electric utility for which the State
regulatory authority has ratemaking authority) and each nonregulated electric
utility shall, with respect to the standard established by section 111(d)(15),
complete the consideration and make the determination under section 111(a).'.
(2) FAILURE TO COMPLY- Section 112(c) of the Public Utility Regulatory
Policies Act of 1978 (16 U.S.C. 2622(c)) (as amended by section 1252(h)) is
amended by adding at the end the following: 'In the case of the standard
established by paragraph (15), the reference contained in this subsection to the
date of enactment of this Act shall be considered to be a reference to the date of
enactment ofparagraph (15).'.
(3) PRIOR STATE ACTIONS-
(A) IN GENERAL-Section 112(e) of the Public Utility Regulatory Policies
Act of 1978 (as added by section 1252(i)(1)) is amended by striking
paragraph 14'and inserting paragraph (14) or(15)'.
(B) CONFORMING AMENDMENT- Section 124 of the Public Utility
Regulatory Policies Act of 1978(16 U.S.C. 2634) (as amended by section
1252(i)(2)) is amended by adding at the end the following: 'In the case of
each standard established by section 111(d)(15), the reference contained
in this section to the date of enactment of the Act shall be considered to be
a reference to the date of enactment of paragraph (15).'.
Page 22 of 22