Get documents about "AK policy grid
Document Sample
Guide to the Grid
Navigation Policy Change Indicator:
The grid is designed to give users a broad overview of current utility energy efficiency policies in U.S. states. Each cell will be color-coded to indicate policy areas where change has occurred recently or may occur soon. Colors
Begin your navigation with the "Grid" worksheet by clicking on the "Grid" tab at the bottom of the screen. range from blue (no change is likely) to violet (change is imminent).
This worksheet contains a summary overview for all states of all the information in the document. Policy stable, complete, and functioning (for 24 months or more)
Within the "Grid" worksheet, policies are organized into 5 broad recommendations that follow the National Policy stable, but some elements missing or implementation incomplete
Action Plan and 2 other policy areas of interest. Within each recommendation are many policy options. Policy is new (put into place during previous 24 months)
Click on the black +/- signs to the left of the screen to expand and collapse the policy lists. Policy may change (informal discussion of policy changes, or proposed statute)
Individual worksheets for each state describe individual states' policies in greater detail. Worksheets are Action likely soon (docket has been opened or a Commission has expressed intent)
labeled by state abbreviations at the bottom of the screen. New policy required by statute or order; details in development
Within the "Grid" worksheet, some policies are hyperlinked to the corresponding state page policy. For Cross-hatching indicates that two or more of the above apply. For example:
these, you may click on the Y/N designation to quickly navigate to the corresponding policy on that
state's page. From the state page, you may click on the Y/N to go back to the "Grid" page. Blue/Yellow: Indicates that a major change has recently been made to a pre-existing policy
Acronyms used are listed at the bottom of each worksheet. Yellow/Purple: Indicates that a new policy exists, AND an additional policy is in development
Y Blue/Purple: Indicates that a new policy is in development, in addition to preexisting policy
Explanation of Grid Symbology
Policy Origin:
A letter next to each policy
explanation (on the state pages)
indicates the policy's origin as follows:
S Statutory policy
R Regulatory policy resulting from a decision, order, or MOU
A Policy codified in state rules or administrative code
F Federal Policy
EO Executive Order
U Utility-specific policy
Criteria for specific policy options: A designation of "Y" or "N" is generally self-explanatory.
A designation of "C" indicates the state's policy status is complete, regarding certain federal metrics, as described below.
A designation of "P" indicates the state's policy status is partial, regarding certain federal metrics, as described below.
Order = regulatory or Executive orders
Some options are designated with a qualifier (e.g. Y+, Y, or Y-) based on the following policy-specific criteria:
Recommendation 1
1.1 Y+ indicates that EE has greater priority than supply resources, or that all cost-effective energy efficiency should be procured.
Y indicates that efficiency is considered an equivalent resource in statute or order.
Y+ indicates that a robust resource planning process exists and is designed to procure maximum cost-effective EE.
1.2.1 Y indicates that a resource planning process exists and is designed to procure significant EE.
Y- indicates that a resource planning process exists that results in EE savings goals and targets but it is not designed to procure
significant EE.
Y indicates that EE must be procured as a resource for default or standard offer service (restructured states only)
1.2.2 Y- indicates that EE is presently procured as a resource, but is not required to be.
N+ indicates that EE may be procured as a resource, but is not required to be.
Recommendation 2
Y+ indicates that statute requires the procurement of all cost-effective EE.
2.1 Y indicates that statute requires EE as a systematic and required part of electric resource procurement.
Y- indicates that statute is supportive of EE, but falls short of requiring it or is no longer used.
Y+ indicates that TRC and/or SC or similar cost/benefit test is a primary EE program cost-effectiveness test.
Y indicates that TRC and/or SC or similar test are required, but not considered primary.
2.2 Y- indicates that TRC and/or SC or similar test are used, but not required.
N / P indicates that a docket is open to consider TRC and/or SC
N / P may also indicate that TRC and/or SC are allowed but are not used (however, RAP does not have to pro-actively determine this)
Y indicates that established EE programs reach all customer classes, including low-income customers
2.3.2 Y may also indicate that established EE programs reach all customer classes, but allows customers to opt out who participate in self-
directed EE programs
Y+ indicates that goals are designed to capture all cost-effective EE.
2.5.1 Y indicates that goals are designed to be "stretch" goals, or to increase administrators' ability to procure EE.
Y- indicates that goals exist as a by-product of budget constraints.
Y+ indicates that EE is required as part of an RPS or EEPS or other resource standard, and any type of efficiency may be used.
2.5.3 Y indicates that EE may be used to meet resource standard requirements, but is not required, or that only certain types of EE may
qualify for the resource standard.
2.6.1 Y indicates a robust EM&V process is in place including impact, market and process evaluations
2.7.1 Y indicates EE program administration has been clearly established by statute, order or contract
Y+ indicates the same resource planning process referred to in 1.2.1 is regularly updated and that it quantifies and integrates energy
2.8 savings from building codes.
Y indicates that the same resource planning process referred to in 1.2.1 is regularly updated
2.10 Y+ indicates that Commission or other agency has authority to update standards as needed without specific legislative authorization.
Y indicates that standards have been updated recently.
Recommendation 3
Y indicates that all state-approved EE program portfolios include any type of public education programs.
3.1.1
Y- indicates that state-approved EE program portfolios serving at least one-half of the state's customers of regulated utilities include
any type of public education programs.
Y indicates stakeholders were involved in an advisory or collaborative role with program administrators, while developing EE program
3.1.2
plans or determining best use of efficiency or sustainable energy funds.
Recommendation 4
Y indicates that a cost recovery process exists for EE programs offered to all ratepayer classes.
4.1.1 Y- indicates that cost recovery exists for only some programs or some classes of ratepayers, is done on a case-by-case basis, or is
impacted by legislative diversion of SBC funding.
Recommendation 5
Y+ indicates that disincentives are fully addressed for all utilities and disincentives are removed via a regularly updated decoupling
mechanism designed to promote EE.
5.1.1 Y indicates that disincentives are addressed for all utilities via a mechanism other than decoupling (e.g. third party administration, lost
revenue recovery, or bonus rate of return).
Y- indicates that disincentives are addressed, but not for all utilities or not for all rate classes, is rarely used; or the decoupling
mechanism is not designed to promote conservation.
Y+ indicates that a significant incentive mechanism is in place, encouraging implementors to meet "stretch" goals, with clear rules
regarding the incentive process.
5.2.1 Y indicates that an incentive mechanism is in place, but doesn't encourage "stretch" goals or rules are unclear.
Y- indicates that incentives may be available, but a regular, predictable incentive system does not exist.
N / C indicates that a state has considered incentive mechanisms within the last three years, and has ruled them out; this status was
not proactively determined for every state
5.3 Y- indicates a one-time provision; not a regular part of ratesetting activities.
5.3.2 Y- indicates that most, but not all, declining block rate structures have been eliminated.
5.4.1-
5.4.2 Y- indicates that the rate structure or mechanism in question is in place for some, but not all, customers.
Y+ / C indicates one or more utilities have implemented AMI
5.4.3 Y / C indicates one or more utilities have contracted for AMI
Y- / P indicates that AMI is planned or utilities are running pilots
5.4.4 Y indicates specific customer mechanisms are listed on the state page.
7. Distributed Generation Policies
A statewide interconnection policy is in place
Y+ indicates that there is a well-defined interconnection policy in place that has at least one or more beneficial attributes such as
standard forms, a reasonable timeline for application approval, low or no additional insurance requirements, allows for fairly large DG
units to interconnect and may have additional positive attributes.
7.1 Y indicates that there is an interconnection policy, but overall the policy cannot be considered either beneficial or detrimental to DG.
Y- indicates that the policy may be available, but has unfavorable requirements such as only allowing very small units (up to 10 kW
for residential and 100 kW for commercial) to interconnect, having high liability insurance requirements, requiring owners/operators to
pay large interconnect study fees, and may have other burdensome requirements like only allowing systems that qualify under net
metering rules to interconnect.
A statewide net metering policy is in place
Y+ indicates that there is a favorable net metering policy in place, meaning that the limits on overall enrollment are fairly high, a wide
variety of DG systems and sizes are allowed to net meter, the utility compensates the DG owner for net excess generation, and
possibly other beneficial attributes.
Y indicates that there is a net metering policy, but the policy cannot be considered either beneficial or detrimental to DG, there may
7.2
be some portions of the policy that are helpful and some that are not.
Y- indicates that the policy may be available, but it has unfavorable requirements, such as overall enrollment limits are very low, only
non-emitting renewables that are a small size may be allowed to net meter, customers are not compensated for their net excess
generation, and possibly other negative requirements.
A statewide exit fee policy is in place
Y+ indicates that, under the statewide policy, DG owners/operators are not charged an exit fee.
7.3 Y indicates that, under the statewide policy, utilities are not allowed to charge DG owners an explicit exit fee. However, under certain
circumstances, utilities may still be able to recover costs.
Y- indicates that there is a statewide policy in place that allows utilities to charge DG owners an exit fee.
A statewide standby rate policy is in place
U+ Utility policy that is beneficial/positive for DG projects - small or no reservation fee and no demand ratchets.
7.4 U Utility policy that is neither completely positive or negative towards DG - may have several opposing attributes
U - Utility policy that is detrimental/negative for DG projects - high demand reservation fees, high demand ratchets.
Utility DG Policies, state-level pages only
U+ Utility policy that is beneficial/positive for DG projects.
U Utility policy that is neither completely positive or negative towards DG - may have several opposing attributes
U- Utility policy that is detrimental/negative for DG projects.
ALASKA (as of 12/31/08)
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority
resource, equivalent or superior to supply N
1.1 resources
1.2.1 EE is integrated into an active IRP, There is no requirement that utilities
portfolio management, or other planning undertake IRP (the Commission declined to
process require IRPs in Dockets R-96-001 and U-97-
140). However, some utilities have
completed IRPs, including Chugach Electric
Association in 2004. And, a Regional IRP is
N
to be developed for the Railbelt Region in
2009. An AK Rural Energy Plan, which
examined EE for rural areas, was issued in
2004. And, a report titled Alaska Energy
Efficiency Program and Policy
1.2 Recommendations was completed for the
Information Insights, Alaska Energy
Efficiency Program and Policy
Recommendations, June 8, 2008:
http://www.cchrc.org/alaska+energy+efficien
cy+program+and+policy+recommendations.
aspx
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers NA
EE is an alternative to transmission based
on a long-term transparent IRP or N
1.3 transmission system plan
1.4.1 EE is a biddable commodity
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute Alaska Statute states that in the
establishment of electric service rates "the
commission shall promote the conservation
Y-
of resources used in the generation of
2.1 electric energy." Alaska Administrative
Code encourages "conservation of energy
supplied by electric and gas utilities."
2.1
AK Statutes 42.05.141 (c):
S, A
The TRC or Societal Cost Test is used to
evaluate EE programs
2.2
2.3.1 Potential for cost-effective EE has Estimates for potential of some EE
been established through a potential study measures in rural parts of Alaska were
Y- undertaken in the Alaska Rural Energy Plan
released in 2004.
Alaska Rural Energy Plan:
http://www.aidea.org/AEA/publicationAREP.h
2.3 tml
2.3.2 Established EE programs reach all Golden Valley Electric Association has
customer classes some programs for residential and
N commercial customers. Low-income
customers receive weatherization
assistance through the AK Housing and
Finance Corporation.
Funding requirements for all long-term, cost-
effective EE have been established
N
2.4
2.5.1 Quantitative MW and MWh savings Chugach Electric Association set a goal on
goals have been established and are 9/24/08 to reduce energy use among its
producing incremental investment. residential members by 10% below the
N
2008 monthly average by the end of 2010;
and to set new goals every five years.
http://www.chugachelectric.com/news/pr200
8-10-07-2.html
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
d
system; (c) as part of program approval and
2.5 budget-setting process; (d) other
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar N
standard
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been
established
N
2.6.1.1 M&V is adequately funded
2.6.1.2 Energy savings are used to
measure performance
2.6.1.3 M&V is done according to a
2.6 defined schedule
2.6.1.4 M&V is conducted by an
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been EE programs are done at the utilities'
established initiative. The AK Housing and Finance
Corporation undertakes programs to
address EE, and was appropriated $300
million from the Legislature in 2008 for the
following programs: a weatherization
N program that provides free weatherization
assistance to households at 100% of
median income; a home energy rebate
2.7 program, under which homeowners are
rebated a portion of EE improvements; and
a second mortgage program for EE
improvements. The Alaska Energy
AK Energy Authority and AK Center for
Energy and Power, Alaska Energy , January
2.7.2 Delivery is via: (a) utility 2009
administration; (b) third-party administration; a, c
or (c) government agency
Resource plans are regularly updated
N
2.8
2.9.1 Building Energy Codes for residential The Building Energy Efficiency Standards
buildings are in place and regularly updated (BEES), a state-developed code based on
the 2006 IECC with state amendments, is
mandatory for all residential and community-
owned buildings financed with Alaska
Housing Finance Corporation underwriting.
There is no set schedule for code updates,
Y/N
and the most recent update was effective
4/1/07. The Alaska Energy Efficiency
Program and Policy Recommendations , a
report commissioned by the state and
issued 6/08, recommended the Legislature
adopt BEES as the new state residential EE
building code.
dsireusa.org, and Information Insights,
2.9 Alaska Energy Efficiency Program and
Policy Recommendations, June 8, 2008:
http://www.cchrc.org/alaska+energy+efficien
2.9.2 Building Energy Codes for cy+program+and+policy+recommendations.
No statewide commercial code in place.
commercial buildings are in place and The Alaska Energy Efficiency Program and
regularly updated Policy Recommendations , a report
N commissioned by the state and issued 6/08,
recommended that a commercial EE
building code should be developed.
Information Insights, Alaska Energy
Efficiency Program and Policy
Recommendations , June 8, 2008:
http://www.cchrc.org/alaska+energy+efficien
cy+program+and+policy+recommendations.
aspx
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10
updated
Energy efficiency is a high priority in state The Alaska Energy Efficiency Program and
buildings and state funded buildings as Policy Recommendations, a report
evidenced in capital planning and enabling commissioned by the state and issued 6/08,
performance contracts N made a number of recommendations about
2.11 improved EE in state buildings.
Information Insights, Alaska Energy
Efficiency Program and Policy
Recommendation 3: Miscellaneous Policies Recommendations , June 8, 2008:
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) N
3.1
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
N
high-priority resource. (See Guide Tab for
3.1 Y/N criteria.)
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Do not delete this row.
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75% of state access to ENERGY STAR
Y
3.2 New Homes
What proportion is due to regulated utility
program? (who is sponsor) Performance
75% of state access to Home
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists Chugach Electric Association announced a
policy on 9/24/08 to establish EE programs
and consider and implement a funding
mechanism, such as a system benefits
charge. The Alaska Energy Efficiency
Program and Policy Recommendations , a
report commissioned by the state and
issued 6/08, recommended that the
Commission implement a system benefit
charge to support EE, or the state capitalize
an EE endowment to support EE with its
budget surplus.
4.1
Information Insights, Alaska Energy
Efficiency Program and Policy
Recommendations, June 8, 2008:
http://www.cchrc.org/alaska+energy+efficien
cy+program+and+policy+recommendations.
aspx
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is
N
addressed and disincentives are removed
5.1 5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE incentives are
provided
5.2 5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
when designing retail rates
5.3 5.3.2 Declining block rates and fixed
variable rate designs have been eliminated
5.4.1 Time sensitive rates in place
5.4.2 Usage sensitive rates in place
5.4.3 AMI deployment planned The Commission decided not to adopt the
PURPA standard on time-based metering
and communications in a 8/07 order. The
Alaska Energy Efficiency Program and
N Policy Recommendations , a report
commissioned by the state and issued 6/08,
5.4
recommended the Legislature should fund a
pilot smart meter program.
Docket R-06-005, Order 8/8/07:
https://rca.alaska.gov/RCAWeb/ViewFile.asp
R
x?id=65760476-488E-4EF2-8288-
7FD2A2F78770
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
- energy efficient products
Investment Tax Credit for energy efficient
- investments
State supported low cost financing for
energy efficient investments: buildings (x),
equipment (y)
-
New or reorganized energy policy agency
Distributed Generation Policies
A statewide interconnection policy is in place Alaska is considering statewide
interconnection standards, similar or
identical to those outlined in the Energy
N
Policy Act of 2005 (EPAct 2005). An order
inviting public comments on this subject was
issued on 6/8/2007.
7.1
Docket R-06-005, which contains
information on the order inviting public
comment and public hearings related to this
R
topic can be accessed from here,
http://rca.alaska.gov/data/docketDetail.html?
docket=R-06-005.
Homer Electric Association Inc, Cooperative
U- - does not have interconnection standards
in place.
Golden Valley Electric Association Inc,
Cooperative - has interconnection
standards. Power equipment must meet UL
and IEEE standards. There are several
levels of interconnection. Customers must
bear any costs associated with equipment
upgrades necessary for interconnection. A
disconnect device is required, but will be
provided by GVEA. Additionally, customers
must have liability insurance, but no specific
amount is given. GVEA interconnection
specifications can be accessed here,
U http://www.gvea.com/memserv/connect_disc
onnect/producer_interconn_spec_2007.pdf.
There are also separate interconnection
requirements for those systems that qualify
under GVA's Sustainable Natural Alternative
Power Producer's program (SNAP). These
SNAP guidelines are found here,
http://www.gvea.com/alternative-
energy/snap/files/Interconnection_Requirem
ents.pdf.
A statewide net metering policy is in place Alaska does not have statewide net
N
metering standards.
Homer Electric Association does not have
7.2 U
an established net metering policy
Golden Valley Electric Assn does not have a
U
net metering policy
A statewide exit fee policy is in place
7.3
A statewide standby rate policy is in place Alaska does not have a statewide policy on
N
standby rates
Homer Electric Assn Inc - there is no
standard standby rate. Customers seeking
standby service would be charged under the
regular rate that would apply to their facility
U
if they were not generating power. Regular
rates have moderate to high demand and
energy charges. Rate available at:
http://www.homerelectric.com/nbsp/Rates/ta
bid/136/Default.aspx
7.4
Golden Valley Electric Assn Inc - there is a
standby rate applicable to sites that are
below 50 kW in the form of a capacity
payment per kVa. For sites that are above
50 kW there is no standby rate and they
U
would be charged under the regular rate for
their facility size. Regular rates have high
demand and energy charges, with demand
being based on the maximum 15 minute
demand of the month. Rate available at:
http://www.gvea.com/billing/rates.php
As part of resource planning process, CHP Alaska does have a formal Integrated
is reviewed and incorporated where effective Resource Planning (IRP) process.
Currently, a regional integrated resource
N plan (RIRP) is being developed for the
Railbelt Region of Alaska (see link below).
7.5
Alaska is expected to release a state energy
plan in early 2009.
http://www.aidea.org/aea/regionalintegratedr
esourceplan.html
31/08)
Natural Gas
urce.
effective energy efficiency as a resource
Alaska Administrative Code encourages
"conservation of energy supplied by electric and gas
utilities."
N
AK Administrative Code 3.50.100:
A http://touchngo.com/lglcntr/akstats/aac/title03/chapte
r050/section100.htm
deliver energy efficiency where cost-effective.
cost-effective energy efficiency and modify ratemaking
N
ARIZONA
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority Currently, under the Arizona Administrative
resource, equivalent or superior to supply Code, electric and gas utilities must file
resources energy conservation plans that include, as
minimum requirements: (1) customer
education and assistance programs to help
their customers reduce their energy
consumption and costs, and (2) participation
in energy conservation programs sponsored
by governmental agencies. June 2008 the
ACC opened a proceeding. Some of the
Y-
issues to be addressed in the investigation
1.1 are: how adjustment clauses affect utility
incentives, whether regulatory incentives
could be changed to align a utility’s financial
incentives with energy efficient investment,
and the incentives involved incompetitive
bidding and utilities’ buy-or-build decisions.
Docket # E-00000J-08-0314
R www.cc.state.az.us/divisions/administration/
energyefficiency.asp
1.2.1 EE is integrated into an active IRP, Current rules require the submission of
portfolio management, or other planning conservation plans and the inclusion of
N
process DSM in resource plans, but do not require
an active, robust IRP process. See 1.1
above. # E-00000J-08-0314
Docket
www.cc.state.az.us/divisions/administration/
R
energyefficiency.asp
R14-2-213 requires Class A and B utilities
to submit annual conservation plans to the
Commission. Plans must include customer
education programs and cooperation with
A
state, municipal, county, and federal
1.2 efficiency programs.
http://www.azsos.gov/PUBLIC_SERVICES/T
itle_14/14-02.htm
R14-2-703(C)4-5 requires electric utilities to
submit descriptions of included and rejected
DSM programs when filing resource plans.
A
http://www.azsos.gov/PUBLIC_SERVICES/T
itle_14/14-02.htm
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers
EE is an alternative to transmission based
on a long-term transparent IRP or N
1.3 transmission system plan
1.4.1 EE is a biddable commodity Any resource may bid in the procurement
process, but it is unclear whether any
Y-
demand side resources have done this
successfully.
1.4
1.4.2 Bids occur in the following markets:
(a) energy, (b) capacity, or (c) other a
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute N
2.1
Staff recommend use of the TRC test in
The TRC or Societal Cost Test is used to N their report on DSM policy, unclear when/if
2.2 evaluate EE programs this will go into effect.
R
2.3.1 Potential for cost-effective EE has
been established through a potential study N
2.3 2.3.2 Established EE programs reach all Some utilities offer to all customer classes
customer classes N but it is not mandated by the state.
Funding requirements for all long-term, cost-
effective EE have been established
N
2.4
2.5.1 Quantitative MW and MWh savings Proposed DSM rules would require that the
goals have been established and are N Commission establish savings goals. See
producing incremental investment. p.4
Right now there are just spending goals. http://www.azcc.gov/divisions/util/electric/DS
R
M-Exhibit1.pdf
2.5
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
system; (c) as part of program approval and
budget-setting process; (d) other
2.5
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar
standard
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been Proposed DSM rules would require utilities
established to conduct M&V activities. See p.9
N
2.6.1.1 M&V is adequately funded
2.6.1.2 Energy savings are used to
measure performance
2.6.1.3 M&V is done according to a
2.6 defined schedule
2.6.1.4 M&V is conducted by an
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been Currently, energy efficiency programs are
established administered by investor-owned utilities.
The Arizona Corporation Commission
(ACC) retains approval authority for
program funding and spending. Energy
Y efficiency programs in Arizona are funded
through a systems benefits charge,
collected through a non-bypassable
2.7 surcharge on electricity bills, or through an
adjustor mechanism, described below,
depending on the utility.
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated
Y
2.8
2.9.1 Building Energy Codes for residential
buildings are in place and regularly updated N/N 2000 IECC is voluntary; can use REScheck
to show compliance
http://bcap-energy.org/node/54
2.9 2.9.2 Building Energy Codes for
commercial buildings are in place and
regularly updated ASHRAE/IESNA 90.1-1999 mandatory for
Y-/N
state-owned and state funded buildings
only; can use COMcheck to show
compliance.
http://bcap-energy.org/node/54
Appliance and Equipment Efficiency Arizona's Appliance Efficiency
Standards are in place and regularly Regulations were established by ARS
updated §44-1375 in 2005. These regulations
were designed to reduce Arizona's
energy consumption and became
effective on January 1, 2008. The
Arizona law sets energy efficiency
Y standards for 12 appliances and
establishes schedules for the Energy
2.10 Office to review these standards.
Appliance standards also exist in
eleven other states but in several
instances these standards have been
pre-empted by national standards.
http://www.azcommerce.com/Energy/Efficien
cy/AZ+Appliance+Efficiency+Program.htm
Energy efficiency is a high priority in state
buildings and state funded buildings as
Y
evidenced in capital planning and enabling
performance contracts
http://www.swenergy.org/legislative/2003/ariz
2.11 ona/HB2324_bill_text.pdf
http://www.commerce.state.az.us/Energy/
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are N
in place. (See Guide Tab for Y/N criteria.)
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
Y
high-priority resource. (See Guide Tab for
3.1 Y/N criteria.)
Do not delete this row.
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility Tucson Electric Power Company, Arizona
program? (who is sponsor) Public Servoce
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is due to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists Done on a case-by-case basis through DSM
system charges, tariff riders, ratecases, or
Y-
application to the ACC depending on the
utility.
Proposed rules would allow cost recovery
via base rates, tariffs, or an SBC.
Mechanisms would be determined at each
R
utility's next rate case. The Commission
4.1 would have authority to adopt an interim
deferral account.
4.1
R
4.1.2 Recovery occurs via: (a) rider; (b)
a,b,
regular rate case; or (c) system benefits
c
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support N
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is Currently, only an APS shareholder
addressed and disincentives are removed incentive is in place, set at 10% of DSM
program net economic benefits and capped
at 10% of total DSM expenditures. APS
proposed modifying this incentive
mechanism in a new rate case filed in 2008,
requesting recovery of net lost revenues as
N well as removal of the cap on the incentive.
In Decision 58643, the Commission states
that lost revenues should be considered.
5.1 Proposed DSM rules would allow the
Commission to decide if lost revenues
should be recovered. See p.7. Unclear
when/if these rules will go into effect.
http://www.azcc.gov/divisions/utilities/electric
/DSM-Exhibit1.pdf
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE incentives are Arizona Corporation Commission Decision
provided No. 67744, April 2005, states that utilities
will be given performance incentives.
Currently, only an APS shareholder
N
incentive is in place, set at 10% of DSM
program net economic benefits and capped
5.2 at 10% of total DSM expenditures.
U
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration ACC Docket E-01345A-03-0437, Order of
when designing retail rates April 7, 2005, pp21-22. See
Y
http://www.cc.state.az.us/utility/electric/APS-
FinalOrder.pdf
5.3
5.3.2 Declining block rates and fixed Varies among utilities and seasons source:
variable rate designs have been eliminated Y- Energy & Environment Economics
5.4.1 Time sensitive rates in place
5.4.2 Usage sensitive rates in place
5.4.3 AMI deployment planned Over 1 million smart meters have been
5.4 Y
deployed according to EEI
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
N
- energy efficient products
Investment Tax Credit for energy efficient Personal income tax deductions are
investments Y available for the sale of homes meeting
certain energy efficiency requirements.
- http://www.dsireusa.org/incentives/incentive.
cfm?Incentive_Code=AZ17F&re=0&ee=1
State supported low cost financing for
energy efficient investments: buildings (x), N
- equipment (y)
Distributed Generation Policies
A statewide interconnection policy is in place The Arizona Corporation Commission
started a proceeding to establish statewide
interconnection standards in 2005 for DG,
and initiated a rulemaking process in 2007.
The proceeding has not been completed
yet, but until then the ACC recommends
N
using the interconnection document, which
applies to systems up to 10MW, and can be
found here:
http://images.edocket.azcc.gov/docketpdf/00
00074361.pdf
7.1
7.1
Salt River Project (SRP), Public Utility - has
interconnection standards. There are four
different levels of interconnection based on
system size. Systems up to 5 MW are
allowed to interconnect. A manual
U+ disconnect is required. There is a set
procedure and timelines for system
approval. SRP's interconnection standards
can be accessed here,
http://www.srpnet.com/electric/pdfx/gen_guid
elines.pdf
A statewide net metering policy is in place Arizona does not have a statewide net
N
metering policy in place.
Arizona Public Service Co, IOU - APS has
net metering rules. Renewable energy
systems up to 100 kW in capacity are
eligible for net metering - solar, landfill gas,
wind, and biomass generators. A new net
metering rate plan, EPR-5 has been
approved and is being offered starting July
1, 2007. However this rate plan is an
U experimental program that will only be
offered for 3 years. Net excess generation is
carried forward month to month until the end
of a 12-month billing cycle when it is
credited to the utility. More information on
the new net metering program can be found
here,
http://www.aps.com/main/account/orders/EP
7.2
R/FAQ.html?id=.
Salt River Project (SRP), Public Utility -
established a net metering policy for
residential customers in 2004. The program
is available for customers who generate
electricity using PV systems up to 10 KW in
AC peak capacity. The kW delivered to SRP
are subtracted from the kWh delivered from
SRP for each billing cycle. If the customer
U provides more power than it receives, then
SRP will credit the net kWh from the
customer at the average market price minus
$0.00017/kWh. Information on SRP's net
metering standards for PV can be found
here,
http://www.srpnet.com/environment/earthwis
e/solar/default.aspx.
A statewide exit fee policy is in place
There are no exit fees for DG in Arizona.
The Arizona Corporation Commission Rule
Y+ 14-2-1607 governs exit fees and states that
Competitive Transition Charges are not
7.3 imposed on self generation facilities when
the loads were formerly served by the utility.
Rule 14-2-1607 can be accessed from here,
http://www.azsos.gov/public_services/Title_1
A
4/14-02.pdf
A statewide standby rate policy is in place Arizona does not have a statewide policy on
N
standby rates
Arizona Public Service Co - Rate E-56 -
standby service is provided to customers
that contract with the utility for a specific
amount of standby capacity. A relatively
high demand based reservation charge and
a customer charge is assessed every
U
month, with actual usage being billed
through high demand charges and
moderate energy charges. Rate available
7.4 at:
http://www.aps.com/main/services/business/
rates/BusRatePlans_9.html
Salt River Project - Standby Electric Service
Rider - standby service is provided to
customers that have loads of over 3,000
kW. Standby service is based on demand
U and energy charges that are based on daily
electricity prices traded at Palo Verde. Rate
available at:
http://www.srpnet.com/menu/paybillprice.asp
x
As part of resource planning process, CHP Arizona is currently working on substantial
is reviewed and incorporated where effective revisions to their IRP process. Existing IRP
rules have been suspended, and utilities
have only been required to file recently their
historical data. New IRP regulations are
N
being considered under docket no. E-
00000E-05-0431 and also under RE-
00000A-09-0249. These rules are expected
to be completed sometime in 2009.
7.5 http://www.cc.state.az.us/divisions/utilities/el
ectric/rp.asp
7.5
Arizona Public Service Company has the
following Alternative Resource Plan, which
highlights the benefits and need for energy
efficiency programs, but does not call out
U
CHP specifically,
http://www.aps.com/_files/various/Resource
Alt/APS_Resource_Alternative_Report_0107
08.pdf
U Salt River Project does not have a IRP
Natural Gas
urce.
Currently, under the Arizona Administrative Code,
electric and gas utilities must file energy
conservation plans that include, as minimum
requirements: (1) customer education and
assistance programs to help their customers
reduce their energy consumption and costs, and
(2) participation in energy conservation programs
sponsored by governmental agencies.
Utilities participate in conservation planning, as
required by R14-2-313. The question of IRP
N
requirements for natural gas utilities will be taken
up in the resource planning docket.
R14-2-313 requires Class A and B utilities to
submit annual conservation plans to the
A
Commission. Plans must include customer
education programs and cooperation with state,
municipal, county, and federal efficiency
effective energy efficiency as a resource
N
Proposed DSM rules would require that the
N Commission establish savings goals. See p.4
R
http://www.azcc.gov/divisions/util/electric/DSM-Exhibit1.pdf
N
deliver energy efficiency where cost-effective.
SW Gas and UNS Gas have adjustor
mechanisms for DSM costs.
Y-
The UNS gas proposal is under consideration in
its rate case in Docket g-04204A-06-0463. The
docket can be accessed via search mechanism at
R
http://edocket.azcc.gov/.
https://edocket.azcc.gov/
cost-effective energy efficiency and modify ratemaking
Currently, only an APS shareholder incentive is in
place, set at 10% of DSM program net economic
benefits and capped at 10% of total DSM
expenditures. APS proposed modifying this
incentive mechanism in a new rate case filed in
2008, requesting recovery of net lost revenues as
well as removal of the cap on the incentive.
CALIFORNIA
Electric
Natural Gas
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority CPUC and CEC Energy Action Plan 2008
resource, equivalent or superior to supply Update issued in Feb 2008 reaffirmed the
resources commitment to EE and demand response as
first priority in energy resources. Separately, the
CPUC's EE proceeding adopted the EE
"Strategic Plan" and EM&V policies and
protocols. Separately, EE risk/reward incentive
Y+ Y+
program adopted policy-- filed and earned
payments for (2006-09). Elaborate EMV
framework and ED audits the performance--
currently relooking at risk/reward mechanism.
EE Strategic Plan in 2008 identified what
1.1 stakeholders need to be involved and key
areas/goals.
CA ranked #1 in ACEEE's 2008 EE scorecard
exercise:
http://aceee.org/pubs/e086.pdf?CFID=3737816&
CFTOKEN=70562179 CA Energy Action Plan
2008 Update:
R R
www.energy.ca.gov/2008publications/CEC-100-
2008-001/CEC-100-2008-001.PDF The CPUC
adopted Strategic Plan:
http://docs.cpuc.ca.gov/published/FINAL_DECISI
ON/91068.htm
1.2.1 EE is integrated into an active IRP, D.04-01-050 required CA utilities to prepare
portfolio management, or other planning Long-Term Procurement Plans that incorporate
process EE plans and targets. For PY2009-2020 utilities
must include a single coordinated Strategic Plan
that includes comprehensive EE and Demand
Y+ Response targets. D.07-10-032. LT Y+
procurement plans are submitted by the IOUs
every 2 years that look out over a 10 year
period. The next submittals are scheduled to
occur in 2010, so IOUs should present drafts in
Oct 2009.
http://www.cpuc.ca.gov/Published/Final_decision/
R R
33625.htm
1.2.2 Efficiency is procured as a resource Efficiency is a priority resource in the EAP (see
1.2
for default service/standard offer customers Section 1.1). Decision 04-09-060 translated the
EAP goals into specific annual MWh and therm
savings goals for each major IOU, through 2013
Y Y
as part of the Strategic Plan. Goals updated last
year updated goals through 2020, see D.08-07-
047. Current EE program cycle is 2009-2011.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC R
ISION/40212.htm#TopOfPage D.08-07-047:
http://docs.cpuc.ca.gov/cyberdocs/Libraries/WEB
R PUB/Common/searchResultsdsp.asp?pagenumb
er=1&FT=false&fromQSearch=yes&desc=Detaile
d+Search
EE is an alternative to transmission based EE is included as a resource for procurement
on a long-term transparent IRP or and transmission needs as part of the LT
1.3
transmission system plan planning process as described in Section 1.2.1
R R
1.4.1 EE is a biddable commodity N N
1.4.2 Bids occur in the following markets:
1.4
(a) energy, (b) capacity, or (c) other N/A N/A
State Implementation Plans (SIPs) include
N N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency as a resource
Efficiency commitment is in statute PUC Code 701 states that utilities should seek
to exploit all practical and cost-effective
Y efficiency. Sections 454.5 (for IOUs) and 9615 Y
(for POUs)require unmet resource needs to be
first met through all cost-effective EE
701: http://www.leginfo.ca.gov/cgi-
bin/displaycode?section=puc&group=00001-
2.1
01000&file=701-709.7 454.5:
http://www.leginfo.ca.gov/cgi-
S bin/waisgate?WAISdocID=5144802949+0+0+0& S
WAISaction=retrieve 9615:
http://www.leginfo.ca.gov/cgi-
bin/waisgate?WAISdocID=5146004343+0+0+0&
WAISaction=retrieve
TRC and PAC are used in CA for both electric
and NG, and TRC is the primary test. This is
most recently reiterated in the CPUC EE Policy
Manual v.4.0 adopted in Aug 2008; “This
Commission relies on the Total Resource Cost
Test (TRC) as the primary indicator of energy
efficiency program cost effectiveness, consistent
with our view that ratepayer-funded energy
Y Y
efficiency should focus on programs that serve
2.2 as resource alternatives to supply-side options.”
CPUC Decision 05-04-051 requires EE portfolios
have to pass the “dual test,” in which the entire
EE portfolios of each utility has to pass both the
TRC and PAC cost-effectiveness tests.
The TRC or Societal Cost Test is used to
evaluate EE programs
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
R R
ISION/45783-03.htm#TopOfPage
2.3.1 Potential for cost-effective EE has
been established through a potential study On Sept. 18, 2008, the CPUC adopted
California’s first Long Term Energy Efficiency
Strategic Plan, presenting a single roadmap to
achieve maximum energy savings across all
major groups and sectors in California. This
comprehensive Plan for 2009 to 2020 is the
state’s first integrated framework of goals and
Y strategies for saving energy, covering
Y
government, utility, and private sector actions,
and holds energy efficiency to its role as the
highest priority resource in meeting California’s
2.3
energy needs. EE potential studies have been
performed in 2002, 2006, and 2008. The
CPUC’s long-term EE goal-setting has been
based on potential found in these studies.
www.californiaenergyefficiency.com/docs/EEStrat
egicPlan.pdf
R R
2.3.2 Established EE programs reach all PGC-funded programs must be available to all
customer classes Y classes of ratepayers. Procurement-funded Y
programs may be designed to capture the
gratest amount of potential efficiency.
S,R S,R
Funding requirements for all long-term, The CPUC set energy savings goals for IOUs for
cost-effective EE have been established 2004-2013 (D.04-09-060), which are expected to
save approx 1% of total electricity forecast sales
per year. In 2013, total savings goals are 23183
GWh and 4885 MW peak. In setting these
goals, the IOUs are directed to meet these goals
Y Y
through their procurement plans. Also see
2.4 comments on section 1.2.2. The state’s PGC
helps provide funding, and utilities are required
to draw from procurement funds to supplement
PGC funding to caption all cost-effective EE;
see comments on 2.1.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
S,R S,R
ISION/40214.htm
2.5.1 Quantitative MW and MWh savings The EAP goal of procuring 90% of maximum
goals have been established and are achievable energy efficiency potential has been
producing incremental investment. quantified into annual MW and MWh savings
Y Y
goals for each IOU through 2013. The EE
Strategic Plan has updated goals from 2009-
2020. See 1.2.2 for add'l detail.
through 2013: R
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DE
CISION/85995.htm. An updated decision in July
R
2008 includes goals for 2012-2020:
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DE
CISION/85995.htm
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
system; (c) as part of program approval a,b a,b
and budget-setting process; (d) other
2.5 EE savings goals are required to be included in
the IOU LT procurement plans.
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DE
R R
CISION/85995.htm
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar N N
standard
2.5.4 Expected Capacity Savings 2008 Savings goals for 2006-2013 were established in
535 N/A
(Annual MW) D. 04-09-060.
R R
2.5.5 Energy Savings Goals 2008 (Annual Expected savings for 2006. Savings are based
MWh or MTherms) on programs approved in IOU's 2006-2008
2,504,000 efficiency plans in Decision 05-09-043. Tables 44400
can be found in Attachment 4 to the decision, p.
39 of the PDF file.
http://www.cpuc.ca.gov/PUBLISHED/Graphics/49
R R
863.PDF
2.6.1 A robust M&V process has been Protocols developed by the CPUC and
established stakeholders were published in 2006 and will be
Y updated as necessary. Y
The protocols and other documents are
available at
R R
http://www.cpuc.ca.gov/static/energy/electric/ene
rgy+efficiency/em+and+v/index.htm
2.6.1.1 M&V is adequately funded most recent EM&V funding decision for 2006-08
Y cycle was D.05-11-011; this is to be done for Y
each three-year program cycle.
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DE
R R
CISION/51420.htm
2.6.1.2 Energy savings are used to
Y Y
measure performance
2.6 R R
2.6.1.3 M&V is done according to a
Y Y
defined schedule
R R
2.6
2.6.1.4 M&V is conducted by an
Y Y
independent party
R R
2.6.1.5 Review of M&V is done in a
Y Y
transparent process
R R
2.6.2 M&V is done using: (a) deemed Annual assessments are done on a deemed
savings; (b) actual savings; (c) other savings basis. Final evaluations (typically done
a,b every 3 years) are done on actual savings for a, b
the highest grossing savings programs.
R R
2.7.1 EE delivery structure has been Historically utilities have administered efficiency
established programs. Decision 05-01-055, issued in 2005,
Y affirmed that IOUs would continue to administer Y
EE portfolios in the post-restructuring energy
sector.
2.7 http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
R R
ISION/43628.htm#TopOfPage
2.7.2 Delivery is via: (a) utility
administration; (b) third-party a a
administration; or (c) government agency
R R
Resource plans are regularly updated Long Term Procurement plans are submitted
every two years that look out over a 10 year
Y period. Y
2.8
R R
2.9.1 Building Energy Codes for Statewide mandatory standards exceed 2003
residential buildings are in place and Y/Y IECC. Y/Y
regularly updated
http://bcap-energy.org/node/56
R R
2.9 2.9.2 Building Energy Codes for Statewide mandatory standards exceed 2006
commercial buildings are in place and ASHRAE.
regularly updated
Y/Y Y/Y
R http://bcap-energy.org/node/56 R
Appliance and Equipment Efficiency Standards are in place for a wide range of
Standards are in place and regularly Y+ products. Y+
2.10 updated
http://www.energy.ca.gov/appliances/index.html
R R
Energy efficiency is a high priority in state CA Executive Order S-20-04, issued in Dec.
buildings and state funded buildings as 2004, requires state agencies and departments
Y Y
evidenced in capital planning and enabling to reduce their energy consumption by 20% from
2.11 performance contracts 2003 levels by 2015. The order also directs the
Division of the State Architect to develop new
http://www.energy.ca.gov/greenbuilding/
EO EO
documents/executive_order_s-20-04.html
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE
are in place. (See Guide Tab for Y/N Y Y
criteria.)
R R
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
Y Y
high-priority resource. (See Guide Tab for
3.1 Y/N criteria.)
R R
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility PG&E, SDG&E, SCE, Southern California Gas
program? (who is sponsor) Company
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is due to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency where cost-effective.
4.1.1 Cost recovery process exists A public goods charge (PGC) provides baseline
funding. Additional funding needed to meet
savings goals comes from utility procurement
Y budgets. The amount of procurement funding is Y
due to increase incrementally through 2013 to
meet aggressive savings goals.
Assembly Bill 1890 (1996 Legislative Session)
established the initial PGC. See p. 43.
S,R http://www.leginfo.ca.gov/pub/95- S,R
96/bill/asm/ab_1851-
4.1 1900/ab_1890_bill_960924_chaptered.pdf
Decision 0312060, issued December 18, 2003,
authorizes the use of procurement funds for
energy efficiency programs.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/32828.htm
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits b, c b, c
charge
S,R S,R
4.1.3 Funding is for multi-year periods Y Y
R R
A base energy efficiency spending level PGC budget is established in statute, IOU LT
exists, with opportunity to justify higher level utility procurement plans must meet adopted EE
savings goals, and utilities may request
Y Y
4.2 additional funding for EE or demand response
programs in order to meet unanticipated
demand for approved programs.
S,R S,R
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program Unknown. The CA Air Resources Board is
support EE currently considering options for a carbon
trading program as part of implementation of
AB32's GHG emission reduction goals. In
addition, CA is part of the Western Climate
Initiative which is also developing a
recommendation for the region. These efforts
are being closely coordinated. The CPUC
recommended that • "All auction revenues
N should be used for purposes related to AB 32, N
4.4 and all revenue from the auction of allowances
allocated to the electricity sector should be used
for the benefit of the electricity sector, including
the support of investments in renewables,
energy efficiency, new energy technology,
infrastructure, customer bill relief (possibly
through rebates), and other similar programs."
as part of their final decision of
recommendations for a cap program.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy efficiency and modify ratemaking prac
5.1.1 Utility throughput incentive is All major investor-owned utilities are decoupled.
addressed and disincentives are removed A 2001 statute provided the basis for
decoupling. Mechanisms for individual utilities
have been approved on a case by case basis
between 2002 and 2006. For all utilities, initial
test year revenue requirements were determined
during a rate case, and balancing accounts were
established to true-up revenue requirements
Y annually. Between rate cases, revenue Y
requirements are adjusted annually for inflation,
using utility-specific mechanisms. Mechanisms
may include factors to account for customer
growth, or factors to limit escalation of the
revenue requirement. Separate balancing
accounts may be used for tracking and
reconciling generation and distribution revenues.
Public Utilities Code 739.10 states “The
commission shall ensure that errors in estimates
of demand elasticity or sales do not result in
material over or undercollections of the electrical
S S
corporations.” See http://leginfo.ca.gov/cgi-
bin/displaycode?section=puc&group=00001-
01000&file=727-755
SCE: Distribution revenue was decoupled in
Decision 04-07-022. See
http://www.cpuc.ca.gov/Published/Final_decision/
5.1
38235.htm#P2659_467920. A description of
SCE's Base Revenue Requirement Balancing
Account is at
http://www.sce.com/NR/sc3/tm2/pdf/ce266.pdf.
SDGE: Distribution revenue was decoupled in
Decision 05-03-023. See
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/44820-05.htm#P186_26137. For the
indexing tariff, see:
http://www.sdge.com/tm2/pdf/EPBR.pdf.
PGE: Distribution and generation revenues were
decoupled in Decision 04-05-055. See
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/37086-06.htm#P300_37806. PG&E uses
separate balancing accounts for distribution and
generation revenues; for a description of the
Distribution Revenue Adjustment Mechanism,
see http://www.pge.com/tariffs/pdf/EPSCZ.pdf;
for a description of the Utility Generation
Balancing Account, see
http://www.pge.com/tariffs/pdf/EPSCG.pdf.
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility a
implementaion of EE
5.2.1 Utility/shareholder EE incentives are The Energy Action Plan states that investments
provided in efficiency should be as profitable to utilities as
investments in supply. The Commission has
stated its intention to adopt incentives numerous
times. This issue will be examined in proceeding
06-04-010; Decision 07-09-043 was issued in
Y this proceeding in September 2007; see Y
decision for details. Implementation of the
existing incentive mechanism has proven
controversial and problemmative. In Jan 2009,
a new proceeding R.09-01-019 to review and
potentially propose new policies.
5.2
Documents related to Proceeding 06-04-010 are
available at
http://www.cpuc.ca.gov/proceedings/R0604010.h
tm#documents. Decision 07-09-043:
R http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISI R
ON/73172.pdf The new rulemaking is posted at:
http://docs.cpuc.ca.gov/Published/proceedings/R
0901019.htm
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration SB1388, passed in 2000, required the CPUC to
when designing retail rates Y investigate various approaches to rate design Y
California Public Utilities Code Section 393. See
http://www.leginfo.ca.gov/cgi-
S S
bin/displaycode?section=puc&group=00001-
5.3
01000&file=391-393
5.3.2 Declining block rates and fixed
variable rate designs have been eliminated Y Y
Info on tariffs and rates can be found at:
R R
www.cpuc.ca.gov/PUC/energy/Electric+Rates/
5.4.1 Time sensitive rates in place PG&E received approval in July 2008 to explore
dynamic pricing rates as part of their GRC.
Y-
Previously, voluntary pilot programs for all IOUs
as part of R.02-06-001.
www.oe.energy.gov/DocumentsandMedia/NCEP
_Demand_Response_1208.pdf. For earlier
R CPUC proceeding documents see:
http://docs.cpuc.ca.gov/proceedings/R0206001.h
tm
PG&E rate case:
http://docs.cpuc.ca.gov/published/proceedings/A
0603005.htm
5.4.2 Usage sensitive rates in place Baseline set and increasing block rates in place
Y Y
5.4
Info on tariffs and rates can be found at:
R R
www.cpuc.ca.gov/PUC/energy/Electric+Rates/
5.4.3 AMI deployment planned All IOUs have advanced meters in place. AMI
5.4 and other strategic demand response policies
were further addressed in the CPUC EE
"strategic plan" proceeding R.08-70-011. The
Y+
IOUs are now responsible for filing plans
annually and coordinating across demand
response programs. See Section 1.2.1 for more
information about the strategic plan.
For 2008 and 2009 approved AMI deployment
info as part of the IOU rate cases , see:
R
www.cpuc.ca.gov/PUC/energy/Demand+Respon
se/R0206001.htm
5.4.4 Other mechanisms exist (e.g., on- SCE offers some customers an on-bill finance
Y
bill financing, benefit sharing) program.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/49859-03.htm#P281_36343 and
R,U www.dsireusa.org/incentives/index.cfm?state=CA
&searchtype=Loan&implementingsector=U&EE=
1&RE=0
State Fiscal Policy
Sales Tax reduction or exemption for
N
- energy efficient products
Investment Tax Credit for energy efficient
N
- investments
State supported low cost financing for Several municipal utilities and one IOU
energy efficient investments: buildings (x), Y (SDG&E/SoCalGas) offer financing for EE:
equipment (y)
R,U www.dsireusa.org/incentives/index.cfm?state=CA
&searchtype=Loan&implementingsector=U&EE=
1&RE=0
-
Low-interest loans are available for efficiency
improvements in state-owned buildings and
schools.
http://www.energy.ca.gov/efficiency/financing/ind
ex.html
Distributed Generation Policies
A statewide interconnection policy is in California has statewide interconnection
place standards, Rule 21, that apply to DG systems up
to 10 MW in capacity. There are simplified rules
for systems under 10 kW and Rule 21 includes
model tariff language. If a customer applies for
interconnection an Initial Review Process (IRP)
is required. If the proposed project passes all
requirements in the IRP then it is eligible for a
simplified interconnection procedure. If a system
does not pass the IRP then it must undergo a
Y+ Supplemental Review Process (SRP). DG
systems have to follow technical requirements in
7.1 IEEE 1547. There is a standard interconnection
agreement, no additional insurance
requirements, and an external disconnect is
required for systems greater than 1 kW. Net-
metered systems up to 1 MW are exempt from
paying costs associated with the interconnection
studies, distribution system modifications or
application review fees
Rule 21 and other interconnection information
can be accessed from here,
R
http://www.energy.ca.gov/distgen/interconnection
/california_requirements.html
A statewide net metering policy is in place California has a net metering law created by Cal
Pub Util Code § 2827, which has been revised
numerous times. CA's law requires all utilities to
offer net metering to all customers that have
solar and wind systems up to 1 MW. IOUs must
also offer net metering to biogas-electric
systems and fuel cells. Also, three large biogas
digesters more than 1 MW but no more than 10
MW are allowed to net meter. There are a
Y+
couple of different limits on overall enrollment of
net-metered systems - there is a limit of 2.5% of
7.2
a utility's peak demand; and a statewide limit of
50 MW for biogas digesters. Net excess
generation (NEG) is carried forward to a
customer's next bill for up to 12 months. Any
NEG remaining at the end of a 12-months is
granted to the utility.
Cal Pub Util Code § 2827 is located here,
http://www.energy.ca.gov/distgen/notices/2002-
S
11-18_forum/PUC_CODE_SECTION_2827.PDF
There are three different kinds of exit fees often
A statewide exit fee policy is in place called "cost responsibility surcharges" (CRCs) in
California that apply to DG and were
implemented with R.02-01-011. These CRCs are
as follows - "tail" competition transition charges
pursuant to Public Utilities Code Section 367 (a);
costs associated with the historic procurement
charge "HPC" applicable to SCE service territory
only; and costs associated with the procurement
of power by the CA Water Resources (DWR),
which are divided into two charges - historic
shortfalls financed through a bond charge and
forward costs associated with ongoing power
Y- charges. Systems that meet certain criteria are
exempt from exit fees. DG systems that are
7.3 eligible for net metering are exempt from exit
fees. Ultra clean and low emission systems 1
MW or greater that meet SB 1038 requirements
to comply with CARB 2007 emisison standards
will have to pay 100% of the bond charge, but
no future DWR charges or utility undercollection
surcharges. All other customers will have to pay
all parts of the CRC except the DWR ongoing
power charges. When the combined total of
installed generation reaches 3000 MW (1500
designated for renewables), any additional
Information on California exit fees can be found
here,
R
http://www.energy.ca.gov/distgen/policy/regulator
y_activity.html.
A statewide standby rate policy is in place There is a statewide policy concerning standby
rates in California. According to Decision 01-07-
027
(http://www.cpuc.ca.gov/word_pdf/FINAL_DECISI
ON%5C/8823.doc) standby rates must 1)
provide for fair cost allocation among customers;
Y 2) allow the utility adequate cost recovery while
minimizing costs to customers; 3) facilitate
customer-side distributed generation
deployment; and 4) send proper price signals to
prospective purchasers of distributed generation.
7.4
Southern California Edison Co - Schedule S -
standby service is provided to customers that
contract with the utility for a specific amount of
7.4
standby capacity. A moderate demand based
reservation charge is assessed every month.
U
Actual usage is billed through a high demand
charge and a moderate energy charge. Billing
demand is based on the maximum 15 minute
demand of the month. Rate available at:
http://www.sce.com/AboutSCE/Regulatory/tariffb
ooks/ratespricing/
Pacific Gas & Electric Co - Schedule S - standby
service is provided to customers that contract
with the utility for a specific amount of standby
capacity. A moderate demand based
U reservation charge and a customer charge is
assessed every month. Actual usage is billed
through a high energy charge. Rate available
at: http://www.pge.com/tariffs/ERS.SHTML#ERS
As part of resource planning process, CHP California utilities must prepare Long-Term
is reviewed and incorporated where Procurement Plans (LTPPs) with a specific
effective Distributed Generation (DG) forecast that is
based on the a forecast of DG operating on the
Y+
customer-side of the meter. IOUs must also
evaluate DG as an alternative to distribution
system upgrades. See information on D.04-01-
7.5
050, below.
http://docs.cpuc.ca.gov/published/Comment_decision/41385
U+ Southern California Edison Co
http://docs.cpuc.ca.gov/published/FINAL_DECISION/76979.
U+ Pacific Gas & Electric Co
http://docs.cpuc.ca.gov/published/FINAL_DECISION/76979.htm
Natural Gas
CPUC and CEC Energy Action Plan 2008
Update issued in Feb 2008 reaffirmed the
commitment to EE and demand response as first
priority in energy resources. Separately, the
CPUC's EE proceeding adopted an EE
"Strategic Plan" and EM&V policies and
protocols. Separately, EE risk/reward incentive
program adopted policy-- filed and earned
payments for (2006-09). Elaborate EMV
framework and ED audits the performance--
currently relooking at risk/reward mechanism.
EE Strategic Plan in 2008 identified what
stakeholders need to be involved and key
areas/goals.
CA ranked #1 in ACEEE's 2008 EE scorecard
exercise:
http://aceee.org/pubs/e086.pdf?CFID=3737816&
CFTOKEN=70562179 CA Energy Action Plan
2008 Update:
www.energy.ca.gov/2008publications/CEC-100-
2008-001/CEC-100-2008-001.PDF The CPUC
adopted Strategic Plan:
http://docs.cpuc.ca.gov/published/FINAL_DECISI
ON/91068.htm
Efficiency is a priority resource in the EAP (see
Section 1.1). Decision 04-09-060 translated the
EAP goals into specific annual MWh and therm
savings goals for each major IOU, through 2013
as part of the Strategic Plan. Goals updated last
year updated goals through 2020, see D.08-07-
047. Current EE program cycle is 2009-2011.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/40212.htm#TopOfPage D.08-07-047:
http://docs.cpuc.ca.gov/cyberdocs/Libraries/WEB
PUB/Common/searchResultsdsp.asp?pagenumb
er=1&FT=false&fromQSearch=yes&desc=Detaile
d+Search
EE is included as a resource for procurement
and transmission needs as part of the LT
planning process as described in Section 1.2.1
rgy efficiency as a resource
PUC Code 701 states that utilities should seek to
exploit all practical and cost-effective efficiency.
Section 454.56 require unmet resource needs to
be first met through all cost-effective EE
701: http://www.leginfo.ca.gov/cgi-
bin/displaycode?section=puc&group=00001-
01000&file=701-709.7 454.56:
http://www.leginfo.ca.gov/cgi-
bin/waisgate?WAISdocID=5144802949+0+0+0&
WAISaction=retrieve
TRC and PAC are used in CA for both electric
and NG, and TRC is the primary test. This is
most recently reiterated in the CPUC EE Policy
Manual v.4.0 adopted in Aug 2008; “This
Commission relies on the Total Resource Cost
Test (TRC) as the primary indicator of energy
efficiency program cost effectiveness, consistent
with our view that ratepayer-funded energy
efficiency should focus on programs that serve
as resource alternatives to supply-side options.”
CPUC Decision 05-04-051 requires EE portfolios
have to pass the “dual test,” in which the entire
EE portfolios of each utility has to pass both the
TRC and PAC cost-effectiveness tests.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/45783-03.htm#TopOfPage
On Sept. 18, 2008, the CPUC adopted
California’s first Long Term Energy Efficiency
Strategic Plan, presenting a single roadmap to
achieve maximum energy savings across all
major groups and sectors in California. This
comprehensive Plan for 2009 to 2020 is the
state’s first integrated framework of goals and
strategies for saving energy, covering
government, utility, and private sector actions,
and holds energy efficiency to its role as the
highest priority resource in meeting California’s
energy needs. EE potential studies have been
performed in 2002, 2006, and 2008. The
CPUC’s long-term EE goal-setting has been
based on potential found in these studies.
www.californiaenergyefficiency.com/docs/EEStrat
egicPlan.pdf
PGC-funded programs must be available to all
classes of ratepayers. Procurement-funded
programs may be designed to capture the
gratest amount of potential efficiency.
The CPUC set energy savings goals for IOUs for
2004-2013 (D.04-09-060), which are expected to
save approx 1% of total electricity forecast sales
per year. In 2013, total savings goals are 23183
GWh and 4885 MW peak. In setting these
goals, the IOUs are directed to meet these goals
through their procurement plans. Also see
comments on section 1.2.2. The state’s PGC
helps provide funding, and utilities are required
to draw from procurement funds to supplement
PGC funding to caption all cost-effective EE; see
comments on 2.1.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/40214.htm
The EAP goal of procuring 90% of maximum
achievable energy efficiency potential has been
quantified into annual MW and MWh savings
goals for each IOU through 2013. The EE
Strategic Plan has updated goals from 2009-
2020. See 1.2.2 for add'l detail.
through 2013:
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/85995.htm. An updated decision in July
2008 includes goals for 2012-2020:
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/85995.htm
EE savings goals are required to be included in
the IOU LT procurement plans.
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/85995.htm
Savings goals for 2006-2013 were established in
D. 04-09-060.
Expected savings for 2006. Savings are based
on programs approved in IOU's 2006-2008
efficiency plans in Decision 05-06-043. Tables
can be found in Attachment 4 to the decision, p.
39 of the PDF file.
http://www.cpuc.ca.gov/PUBLISHED/Graphics/49
863.PDF
Protocols developed by the CPUC and
stakeholders were published in 2006 and will be
updated as necessary.
The protocols and other documents are available
at
http://www.cpuc.ca.gov/static/energy/electric/ener
gy+efficiency/em+and+v/index.htm
most recent EM&V funding decision for 2006-08
cycle was D.05-11-011; this is to be done for
each three-year program cycle.
http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/51420.htm
Annual assessments are done on a deemed
savings basis. Final evaluations (typically done
every 3 years) are done on actual savings for the
highest grossing savings programs.
Historically utilities have administered efficiency
programs. Decision 05-01-055, issued in 2005,
affirmed that IOUs would continue to administer
EE portfolios in the post-restructuring energy
sector.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/43628.htm#TopOfPage
Long Term Procurement plans are submitted
every two years that look out over a 10 year
period. Next utility applications are planned to
be adopted in 2010, with IOU filings anticipated
by end of 2009.
Statewide mandatory standards exceed 2003
IECC.
http://bcap-energy.org/node/56
Statewide mandatory standards exceed 2006
ASHRAE.
http://bcap-energy.org/node/56
Standards are in place for a wide range of
products.
http://www.energy.ca.gov/appliances/index.html
CA Executive Order S-20-04, issued in Dec.
2004, requires state agencies and departments
to reduce their energy consumption by 20% from
2003 levels by 2015. The order also directs the
Division of the State Architect to develop new
http://www.energy.ca.gov/greenbuilding/
documents/executive_order_s-20-04.html
gy efficiency where cost-effective.
A public goods charge (PGC) provides baseline
funding. Additional funding needed to meet
savings goals comes from utility procurement
budgets. The amount of procurement funding is
due to increase incrementally through 2013 to
meet aggressive savings goals.
Assembly Bill 1890 (1996 Legislative Session)
established the initial PGC. See p. 43.
http://www.leginfo.ca.gov/pub/95-
96/bill/asm/ab_1851-
1900/ab_1890_bill_960924_chaptered.pdf
Decision 0312060, issued December 18, 2003,
authorizes the use of procurement funds for
energy efficiency programs.
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ISION/32828.htm
PGC budget is established in statute, IOU LT
utility procurement plans must meet adopted EE
savings goals, and utilities may request
additional funding for EE or demand response
programs in order to meet unanticipated demand
for approved programs.
Unknown. The CA Air Resources Board is
currently considering options for a carbon trading
program as part of implementation of AB32's
GHG emission reduction goals. In addition, CA
is part of the Western Climate Initiative which is
also developing a recommendation for the
region. These efforts are being closely
coordinated. The CPUC recommended that •
"All auction revenues should be used for
purposes related to AB 32, and all revenue from
the auction of allowances allocated to the
electricity sector should be used for the benefit
of the electricity sector, including the support of
investments in renewables, energy efficiency,
new energy technology, infrastructure, customer
bill relief (possibly through rebates), and other
similar programs." as part of
http://www.cpuc.ca.gov/PUBLISHED/FINAL_DEC
ve energy efficiency and modify ratemaking practices
All major investor-owned utilities are decoupled.
A 2001 statute provided the basis for decoupling.
Mechanisms for individual utilities have been
approved on a case by case basis between 2002
and 2006. For all utilities, initial test year revenue
requirements were determined during a rate
case, and balancing accounts were established
to true-up revenue requirements annually.
Between rate cases, revenue requirements are
adjusted annually for inflation, using utility-
specific mechanisms. Mechanisms may include
factors to account for customer growth, or
factors to limit escalation of the revenue
requirement. Separate balancing accounts may
be used for tracking and reconciling generation
and distribution revenues.
Public Utilities Code 739.10 states “The
commission shall ensure that errors in estimates
of demand elasticity or sales do not result in
material over or undercollections of the electrical
corporations.” See http://leginfo.ca.gov/cgi-
bin/displaycode?section=puc&group=00001-
01000&file=727-755
Southern California Gas and SDGE:
Distribution revenue was decoupled in Decision
05-03-023. See
http://docs.cpuc.ca.gov/published/FINAL_DECISI
ON/44820.htm.
PGE: Has been decoupled since 1978. An
annual atrition mechanism adjusts for customer
growth, inflation, and replacement of aging
infrastructure facilities.
Soutwest Gas: Has had some form of
decoupling since the 1970s. Decoupling was
expanded to all customer classes in 2004
through the use of a revenue cap and balancing
account.
The Energy Action Plan states that investments
in efficiency should be as profitable to utilities as
investments in supply. The Commission has
stated its intention to adopt incentives numerous
times. This issue will be examined in proceeding
06-04-010; Decision 07-09-043 was issued in
this proceeding in September 2007; see decision
for details. Implementation of the existing
incentive mechanism has proven controversial
and problemmative. In Jan 2009, a new
proceeding R.09-01-019 to review and potentially
propose new policies.
Documents related to Proceeding 06-04-010 are
available at
http://www.cpuc.ca.gov/proceedings/R0604010.ht
m#documents. Decision 07-09-043:
http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISI
ON/73172.pdf The new rulemaking is posted at:
http://docs.cpuc.ca.gov/Published/proceedings/R
0901019.htm
SB1388, passed in 2000, required the CPUC to
investigate various approaches to rate design
California Public Utilities Code Section 393. See
http://www.leginfo.ca.gov/cgi-
bin/displaycode?section=puc&group=00001-
01000&file=391-393
Info on tariffs and rates can be found at:
www.cpuc.ca.gov/PUC/energy/Electric+Rates/
Baseline set and increasing block rates in place
Info on tariffs and rates can be found at:
www.cpuc.ca.gov/PUC/energy/Electric+Rates/
COLORADO
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority HB 1037, passed in 2007, requires utilities
resource, equivalent or superior to supply to establish electric and gas savings goals
resources that support the minimization of revenue
requirements. As a result, in a 2008 PUC
decision, Xcel Energy/PSCo’s goals were
set, which call for the utility to help its
customers reduce their electricity use in
Y
2020 by about 11.5%, saving 3,669 GWh,
from energy efficiency programs
implemented during 2009-2020. Same
goals in percentage terms were also
adopted for Black Hills Energy, the other
1.1 IOU in Colorado
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/cs
S l.nsf/fsbillcont3/5EA2048E8A50B212872572
51007B8474?open&file=1037_enr.pdf
The Decision approving the resource plan
can be found at
R http://www.dora.state.co.us/puc/DocketsDeci
sions/decisions/2008/C08-0929_07A-
447E.pdf
1.2.1 EE is integrated into an active IRP, Current least cost planning rules require
portfolio management, or other planning minimal consideration of efficiency. HB
process 1037 creates statute 40-2.2-104, which
Y
states that the goal of resource planning is
to minimize the present value of revenue
requirements. See 1.1 above.
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/cs
S
l.nsf/fsbillcont3/5EA2048E8A50B212872572
51007B8474?open&file=1037_enr.pdf
Current least cost planning rules are
available at
http://www.sos.state.co.us/CCR/Rule.do?de
ptID=18&deptName=700%20Department%2
0of%20Regulatory%20Agencies&agencyID=
96&agencyName=723%20Public%20Utilities
S
1.2 %20Commission&ccrDocID=2259&ccrDocN
ame=4%20CCR%20723-
3%20RULES%20REGULATING%20ELECT
RIC%20UTILITIES&subDocID=31404&subD
ocName=LEAST-
COST%20PLANNING&version=2
1.2
Consideration of Public Service Co.'s DSM
and IRP activities will be done in DOCKET
NO. 07A-447E Link to summary of Sept
2008 IRP Decision and Decision document:
R
www.dora.state.co.us/PUC/publications/New
sReleases/09-19-08NR_DecisionPSCoERP-
PhaseI.htm
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers
EE is an alternative to transmission based
on a long-term transparent IRP or N
1.3 transmission system plan
1.4.1 EE is a biddable commodity N
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute HB 1037, passed in 2007, requires utilities
to establish savings goals that support the
Y minimization of revenue requirements.
2.1
The RIM test had been the primary cost-
benefit test, prior to 2004. The 2004 Excel
settlement required the TRC test. HB 1037,
Y passed in 2007, amends statute 40-1-102 to
require the use of a cost-benefit test that
The TRC or Societal Cost Test is used to included avoided costs and non-energy
2.2 evaluate EE programs benefits.
The 2004 Xcel DSM settlement is available
at
U
http://www.swenergy.org/news/XCEL_Energ
y_Settlement_DSM_Language.pdf
S HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/cs
2.3.1 Potential for cost-effective EE has A 2004 Xcel DSM settlement required Xcel
been established through a potential study Y to conduct a potential study.
The 2004 Xcel DSM settlement is available
at
R
2.3 http://www.swenergy.org/news/XCEL_Energ
y_Settlement_DSM_Language.pdf
2.3
2.3.2 Established EE programs reach all HB 1037 requires utilities to offer programs
customer classes Y to all customer classes.
S
Funding requirements for all long-term, cost-
N
2.4 effective EE have been established
2.5.1 Quantitative MW and MWh savings HB 1037 directs the Commission to
goals have been established and are establish savings goals based on potential,
producing incremental investment. demand, and other factors. Goals are to
increase to 5% of 2006 sales and 5% of
Y 2006 peak demand by 2018. Interim goals
are to be established at the Commission's
discretion. The PUC established higher
goals for Xcel Energy in Docket 07A-420E.
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/cs
S l.nsf/fsbillcont3/5EA2048E8A50B212872572
51007B8474?open&file=1037_enr.pdf
The Aug 2008 Decision Calls for energy
savings of at least 1,744 GWh (energy) and
421 MW (demand) by 2015, via demand-
side management (DSM) programs, the
R equivalent of two medium sized power
plants. Docket 07A-420E:
2.5 http://www.dora.state.co.us/PUC/DocketsDe
cisions/HighprofileDockets/07A-420E.htm
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
a
system; (c) as part of program approval and
budget-setting process; (d) other
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar N
standard
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been A 2004 Xcel DSM settlement required Xcel
Y
established to conduct M&V activities.
The 2004 Xcel DSM settlement is available
at
R
http://www.swenergy.org/news/XCEL_Energ
y_Settlement_DSM_Language.pdf
2.6.1.1 M&V is adequately funded
2.6.1.2 Energy savings are used to
measure performance The PUC implemented a performance-
based incentive, enabling PSCo to earn a
profit on its DSM expenditures as long as it
achieves at least 80% of its energy savings
goal in any one year, in addition to
Y
recovering the costs for its DSM programs.
The incentive is tied to energy savings
achieved and the net economic benefits of
2.6 the programs, and is capped at 20% of the
utility’s DSM expenditures. Same incentives
also adopted for Black Hills Energy.
R
2.6.1.3 M&V is done according to a Xcel does M&V on an ongoing basis.
defined schedule
2.6.1.4 M&V is conducted by an
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been PSCo’s programs are administered by the
established Y company after approval from the Colorado
PUC.
R
2.7 2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated Y
2.8
2.9.1 Building Energy Codes for residential Legislation passed in 2007 (HB 1146)
buildings are in place and regularly updated requires all cities and counties with building
codes to adopt and enforce a relatively up-
to-date building energy code, according to
SWEEP. Cities and counties without
Y- building codes are not affected. 2003 IECC
or any successor edition is the minimum
energy code for any jurisdiction that has
adopted a building code; can use REScheck
to show compliance.
http://bcap-energy.org/node/57
S
2.9 2.9.2 Building Energy Codes for Legislation passed in 2007 (HB 1146)
commercial buildings are in place and requires all cities and counties with building
regularly updated codes to adopt and enforce a relatively up-
to-date building energy code, according to
SWEEP. Cities and counties without
building codes are not affected. 2003 IECC
or any successor edition is the minimum
Y-
energy code for any jurisdiction that has
adopted a building code; can use
COMcheck to show compliance. In any area
that does not adopt or enforce local codes,
the 1993 MEC is mandatory for hotels,
motels, and multifamily dwellings.
S http://bcap-energy.org/node/57
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10
updated
Energy efficiency is a high priority in state Executive Order D 014 03 established
buildings and state funded buildings as energy performance contracting for state
Y
evidenced in capital planning and enabling facilities. Executive Order D 005 05 requires
performance contracts managers of state facilities to develop
http://www.state.co.us/gov_dir/govnr_dir/exe
EO
2.11 c_orders/d01403.pdf
http://www.dsireusa.org/incentives/incentive.
cfm?Incentive_Code=CO35R&re=0&ee=1
http://www.colorado.gov/energy/index.php?/g
reening/energy
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.)
3.1
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
Y
3.1 high-priority resource. (See Guide Tab for
Y/N criteria.)
Do not delete this row.
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility Colorado Springs Utilities, Governor's
program? (who is sponsor) Energy Office, Xcel Energy
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists Cost recovery has historically been done
through tariff riders. HB 1037, passed in
2007, does not change the cost recovery
Y
mechanism, but establishes that cost-
recovery mechanisms for DSM are in the
public interest.
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/cs
S l.nsf/fsbillcont3/5EA2048E8A50B212872572
4.1
51007B8474?open&file=1037_enr.pdf
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits a
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level HB 1037 states "The Commission shall
exists, with opportunity to justify higher level permit electric utilities to implement cost-
effective electricity DSM programs to reduce
Y
the need for additional resource that would
otherwise be met through a competitive
4.2 acquisition process."
4.2
Aug 2008 Phase I Decision sets targets
beyond HB 1037. Phase II anticipated in
R May 2009 will adopt final procurement
targets for all resources. See 1.2.1 above.
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support N
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is HB 1037 directs the Commission to offer
addressed and disincentives are removed utilities an opportunity to make DSM
Y investments more profitable than other
investments through measures it deems
appropriate.
Currently being addressed in Docket 07A-
5.1 R, U
447E
http://www.dora.state.co.us/puc/electricmain.
htm
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility b
implementaion of EE
5.2.1 Utility/shareholder EE incentives are Incentives may be developed by the
provided Commission, as directed by HB 1037 (see
N above).
5.2
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
N
when designing retail rates
5.3 5.3.2 Declining block rates and fixed according to energy&environment
variable rate designs have been eliminated N economics document
5.4.1 Time sensitive rates in place
5.4.2 Usage sensitive rates in place N
5.4
5.4.3 AMI deployment planned In March 2008, the Colorado Public Utilities
Commission decided not to adopt PURPA
Standard 14 (“Time-Based Metering and
Communications”) as enacted in EPACT
2005. The Commission stated that its
decision is based in part on the fact that the
5.4 Y-
Public Service Company of Colorado is
building (with Xcel Energy) the Smart Grid
City in Boulder, CO, and that Aquila
Networks intends to deploy AMI in the City
of Pueblo.
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
N
- energy efficient products
Investment Tax Credit for energy efficient
N
- investments
State supported low cost financing for
energy efficient investments: buildings (x), N
- equipment (y)
Distributed Generation Policies
A statewide interconnection policy is in place Colorado has statewide standards for net-
metering and interconnection, established
by Amendment 37. Systems up to 10 MW
are allowed to interconnect and there is a
standard interconnection agreement.
External disconnects are not addressed.
There are three levels of interconnection.
Systems up to 2 MW have to comply with
IEEE 1547 and UL 1741 standards. Liability
insurance of $300,000 is required for
systems up to 10 kW and $2 million in
insurance is required for systems up to 2
MW. For larger systems those < 2MW up to
Y- 10 MW insurance requirements will be
determined on a case-by-case basis. The
7.1
PUC standards generally apply to utilities
with 40,000 or more customers and all
cooperative utilities. H.B. 1160, enacted in
2008, requires municipal utilities with 5,000
customers or more to adopt interconnection
rules that are functionally similar to the
PUC's rules. Systems up to two megawatts
(MW) in capacity that generate electricity
using qualifying renewable-energy
resources are eligible for net metering.
Amendment 37 can be accessed here:
S http://www.dora.state.co.us/puc/rules/723-
3.pdf
A statewide net metering policy is in place CO adopted net metering standards along
with interconnection standards in
Amendment 37. The standards apply to
electric utilities that serve 40,000 or more
customers. Systems up to 2 MW in capacity
that generate electricity using qualifying
renewable energy resources (anaerobic
digestion, small hydroelectric, fuel cells
using renewable fuels) are eligible to net
Y+
meter. Net excess generation (NEG) is
applied as a credit towards the next month.
7.2 If a generation exceeds consumption then
the utility must reimburse the customers for
the excess generation at the utility's
average hourly incremental cost for the prior
12-month period. There is no limit on overall
enrollment of net metered systems.
Amendment 37 can be accessed from here,
http://www.dsireusa.org/library/includes/ince
S ntive2.cfm?Incentive_Code=CA21R&state=
CA&CurrentPageID=1&RE=1&EE=1.
A statewide exit fee policy is in place
Colorado does not have a statewide policy
N
7.3 on exit fees, DG system owners/operators
will not be charged such fees.
A statewide standby rate policy is in place Colorado does not have a statewide policy
N
on standby rates
Public Service Co of Colorado (Xcel Energy)
- Schedule PST - standby service is
provided to customers that contract with the
utility for a specific amount of standby
capacity. A moderate demand based
reservation charge and a customer charge
7.4 is assessed every month. Actual usage is
U
charged through high demand and
moderate energy charges. Billing demand
is based on the maximum demand of the
month. Rate available at:
http://www.xcelenergy.com/Company/About_
Energy_and_Rates/Energy%20Prices%20(R
ates%20and%20Tariffs)/Pages/COEnergy_
Rates.aspx
As part of resource planning process, CHP
is reviewed and incorporated where effective CO recently revised their resource planning
regulations, making permanent the
emergency rules adopted in Decision No.
C07-8029 with the later Decision No. C07-
1101 in December 2007. More specifically,
least cost planning provisions were changed
so that the benefits of "new clean energy"
and "energy efficient technologies" are
N
considered in addition to their costs.
Additionally new clean energy and energy
efficient technologies must be addressed in
the resource planning process, this
resource category is now referred to as
"Section 123 Resources," which are
7.5 identified in §40-2-123(1). CHP is not
specifically mentioned in resource planning
requirements.
http://www.dora.state.co.us/puc/rules/723-
A
3.pdf
http://www.dora.state.co.us/PUC/DocketsDecision
7.5
Public Service Co of Colorado (Xcel Energy)
filed a 2007 electric resource plan with the
U+ PSC, which has a section on CO2 reduction
options and lists CHP technologies such as
gas-fired combined cycle systems. This
plan was approved in 2008.
http://www.dora.state.co.us/PUC/DocketsDecision
Natural Gas
urce.
HB 1037, passed in 2007, requires utilities to
establish electric and gas savings goals that
support the minimization of revenue
requirements. All investor-owned gas utilities in
the state now have gas savings goals and
programs.
Y
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/csl.nsf/f
S sbillcont3/5EA2048E8A50B21287257251007B847
4?open&file=1037_enr.pdf
The Decision approving the resource plan can be
found at
R http://www.dora.state.co.us/puc/DocketsDecisions/
decisions/2008/C08-0929_07A-447E.pdf
Current least cost planning rules require minimal
consideration of efficiency. HB 1037 creates
statute 40-2.2-104, which states that the goal of
resource planning is to minimize the present
value of revenue requirements. See 1.1 above.
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/csl.nsf/f
sbillcont3/5EA2048E8A50B21287257251007B847
4?open&file=1037_enr.pdf
S
R
effective energy efficiency as a resource
40-3.2-101, created in 2007 by HB 1037, requires
gas utilities to develop and implement
Y conservation programs. The statute also provides
guidance on savings goals, cost recovery, and
incentives; see sections below.
HB 1037, passed in 2007, amends statute 40-1-
102 to require the use of a cost-benefit test that
included avoided costs and non-energy benefits.
Y
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/csl.nsf/f
S
sbillcont3/5EA2048E8A50B21287257251007B847
4?open&file=1037_enr.pdf
HB 1037 requires utilities to offer programs to all
Y customer classes.
S
N
HB 1037 directs the Commission to establish
natural gas savings goals commensurate with
conservation budgets and plans.Savings goals
now in place for all gas utilities.
Y
HB 1037 is available at
http://www.leg.state.co.us/clics/clics2007a/csl.nsf/f
S sbillcont3/5EA2048E8A50B21287257251007B847
4?open&file=1037_enr.pdf
R
c
N
a
deliver energy efficiency where cost-effective.
HB 1037 directs the Commission to establish a
cost recovery mechanism for gas utilities. Utilities
are to have the option to expense or amortize
N
DSM expenditures. Cost recovery mechanism
was in place as of 2009.
HB 1037, passed in 2007 and creating statute 40-
3.2-103, is available at
S http://www.leg.state.co.us/clics/clics2007a/csl.nsf/f
sbillcont3/5EA2048E8A50B21287257251007B847
4?open&file=1037_enr.pdf.
HB 1037 directs the Commission to open a
proceeding that will establish expenditure targets
0.50% equal to at least 0.5% of utility revenues.
S HB 1037, passed in 2007 and creating statute 40-
cost-effective energy efficiency and modify ratemaking
HB 1037 directs the Commission to establish
incentives, based on utility performance in
N meeting savings goals, up to 25% of expenditures
or 20% of net economic benefits, whicher is lower.
HB 1037, passed in 2007 and creating statute 40-
3.2-103, is available at
http://www.leg.state.co.us/clics/clics2007a/csl.nsf/f
HAWAII
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority SUMMARY: HECO completed its 4th IRP
resource, equivalent or superior to supply process in September 2008. In November
resources and December 2008, the Commission
closed the IRP dockets for HECO, HELCO
& MECO to allow companies to divert
resources to the development of a Clean
Energy Scenario Planning framework, which
will lead to a new amended IRP Framework
as part of Hawaii's Clean Energy Initiative.
As of the end of 2008, CESP Framework
was not yet completed and the new IRP
amendments has not yet been proposed. All
activities pursuant to the IRP Framework
had been suspended. The former IRP
Y Framework had prioritized energy efficiency.
It stated in its governing principles (principle
#7): "existing disincentives should be
1.1 removed and, as appropriate, incentives
should be established to encourage and
reward aggressive utility pursuit of demand-
side management programs. Incentive
mechanisms should be structured so that
investments in suitable and effective
demand-side management programs are at
least as attractive to the utility as
investments in supply-side options."
IRP Framework (PUC Decision and Order
No. 11630, Docket No. 6617) May 1992,
available at:
http://www.renewablehawaii.com/vcmcontent
/FileScan/PDFConvert/HECO_IRP3_App_C
_Final.pdf
1.2.1 EE is integrated into an active IRP, SUMMARY: HECO completed its 4th IRP
portfolio management, or other planning process in September 2008. In November
process and December 2008, the Commission
closed the IRP dockets for HECO, HELCO
& MECO to allow companies to dedicate
resources to the development of a new
Clean Energy Scenario Planning
framework, which will lead to a new revised
IRP Framework. The IRP Framework used
previously, including for 2008 planning, was
developed in 1992 in Order 11630. Under
the IRP Framework, costs and benefits
must be analyzed for all available and
Y
feasible supply and demand side options.
The Framework states in its governing
principles (principle #7): "existing
disincentives should be removed and, as
appropriate, incentives should be
established to encourage and reward
1.2 aggressive utility pursuit of demand-side
management programs. Incentive
mechanisms should be structured so that
investments in suitable and effective
demand-side management programs are at
least as attractive to the utility as
investments in supply-side options."
IRP Framework available at
http://www.renewablehawaii.com/vcmcontent
/FileScan/PDFConvert/HECO_IRP3_App_C
_Final.pdf; HECO IRP, Sept 2008, available
at
http://www.heco.com/vcmcontent/Integrated
Resource/IRP/PDF/HECO_IRP4_Plan2009_
2028_Final_Report.pdf
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers
EE is an alternative to transmission based HECO's 2005 IRP 3 Appendix Q on
on a long-term transparent IRP or Transmission Planning Consideration
transmission system plan recognizes the least cost, best performance
transmission scenarios occur under plans
Y
for enhanced DSM and CHP. HECO's 2008
IRP considers distributed generation as an
alternative to transmission/distribution, but
not EE.
1.3
1.3 HECO IRP 3, 2005 available at
http://www.renewablehawaii.com/vcmcontent
/FileScan/PDFConvert/HECO_IRP3_App_Q
_Final.pdf; Sept 2008 IRP 4, p. 5-16,
available at
http://www.heco.com/vcmcontent/Integrated
Resource/IRP/PDF/HECO_IRP4_Plan2009_
2028_Final_Report.pdf
1.4.1 EE is a biddable commodity N
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute The RPS law (sections 269-91 to 269-95)
as amended by Act 162 (2006) sets 10%
RPS for utilities by 2010; 15% by 2015; 20%
by 2020. Energy savings through energy
Y- efficiency qualify as renewable electrical
2.1 energy. Under the October 2008
Agreement, energy efficiency will not count
toward the RPS after 2014.
2008 Agreement available at
http://www.heco.com/vcmcontent/StaticFiles/
pdf/HCEI.pdf
The TRC or Societal Cost Test is used to All five tests are used.
Y-
2.2 evaluate EE programs
2.3.1 Potential for cost-effective EE has EE potential study was undertaken for
been established through a potential study HECO 2008 IRP by Global Energy Partners
in September 2008. Energy Efficiency
Y
potential study was done for the Kauai
Island Utility Cooperative in April 26, 2005.
HECO available at
http://www.heco.com/vcmcontent/Integrated
Resource/IRP/PDF/AppendixN_HECO_IRP4
_Final_GEP_DSM.pdf; Energy Efficiency
Potential Study, Prepared for the Kauai
Island Utility Cooperative, April 26, 2005
available at
http://www.kiuc.coop/pdf/Kauai%20EE%20R
eport%20Final.pdf.
2.3
2.3.2 Established EE programs reach all HECO utility programs target commercial,
customer classes industrial, residential and low-income
residential customers. HECO first
2.3 introduced an EE program targeting low-
Y income users in its 2005 IRP. October 2008
agreement states that stakeholders will
design and deliver program specifically
targeted to benefit low income electric and
gas users.
See July 7, 2008 Order Regarding Demand-
Side Management Programs' Goals and
Budgets, Public Utilities Commission,
Docket No. 2007-0341 available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
8/; 2008 Agreement available at
http://www.heco.com/vcmcontent/StaticFiles/
pdf/HCEI.pdf; HECO 2005 IRP available at
http://www.heco.com/vcmcontent/FileScan/P
DFConvert/HECO_IRP3_Final_ExecSumma
ry.pdf.
Funding requirements for all long-term, cost-
effective EE have been established
2.4
2.5.1 Quantitative MW and MWh savings Docket No. 05-0069, Order 23258, issued
goals have been established and are February 13, 2007 established ee goals for
producing incremental investment. HECO utilities according to the estimated
Y savings of the utility programs. The 2008
requested approval for programs additions
and expansions.
See p. 30 of Docket No. 05-0069, Order
23258, issued February 13, 2007 is
available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
7/.
2.5.2 Goals are established: (a) (a) Docket No. 05-0069, Order 23258,
connection with IRP or other planning issued February 13, 2007 established ee
process; (b) as part of an EEPS or similar goals and requires the goals be revised
system; (c) as part of program approval and through the IRP process. (b) As part of the
budget-setting process; (d) other Hawaii Clean Energy Initiative, an October
a, b, 2008 compact between the state and the
electric utilities stated all parties would
support the development of an energy
efficiency portfolio standard in state statute
through 2009 session of the legislature.
2.5
(a)Docket No. 05-0069 Order 23258, issued
February 13, 2007 is available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
7/; (b) October 2008 agreement available at:
http://www.heco.com/vcmcontent/StaticFiles/
2.5 pdf/HCEI.pdf
2.5.3 Energy Efficiency can be used to The RPS law (sections 269-91 to 269-95)
fulfill requirements of an RPS or similar as amended by Act 162 (2006) allows
standard energy efficiency to qualify as renewable
electrical energy. It sets a 10% RPS for
utilities by 2010; 15% by 2015; 20% by
2020. An October 2008 agreement
between the state and utilities articulates a
commitment to enacting an EEPS through
the legislature. As of the end of 2008 it was
Y
not in place. Under the 2008 Agreement,
energy efficiency will not count toward
utilities' RPS goals after 2014. However,
energy efficiency is incorporated into the
Hawaii Clean Energy Initiative goal under
which HECO has agreed to meet 70% of
electricity and transportation needs with
clean sources by 2030.
October 2008 Agreement:
http://www.heco.com/vcmcontent/StaticFiles/
pdf/HCEI.pdf
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been November 30, 2007 PUC Docket No. 2007-
established 0341, 23861, requires periodic DSM
evaluation reports, as well as requests for
program modification, to be filed by HECO
under this docket. HECO produces Annual
Program Accomplishments and Surcharge
Report (“A&S Report”).
11/30/2007 Public Utilities Commission,
Docket No. 2007-0341, Order 23861
available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
7/.
2.6.1.1 M&V is adequately funded
2.6
2.6 2.6.1.2 Energy savings are used to
measure performance
2.6.1.3 M&V is done according to a
defined schedule
2.6.1.4 M&V is conducted by an
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been A 2007 Order approved an independent
established energy efficiency administrator, to be
funded by a statewide PBF. See Order
Y 23258, issued 2/13/2007. The third-party
administrator is charged with assuming
responsibility of utility program by mid-2009.
http://hawaii.gov/budget/puc/dockets/05-
S
0069_dno23258_2007-02-13.pdf;
2.7 2.7.2 Delivery is via: (a) utility http://www.hawaii.gov/budget/puc/pr/NR-
July 2008 Order, Docket No. 2007-0323,
administration; (b) third-party administration; established a 6 month transition period from
or (c) government agency a, b January to June 2009 for EE programs to
shift from utilities to the third-party
administrator.
July 2, 2008 Docket No. 2007-0323
available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
8/
Resource plans are regularly updated IRPs undergo major review every three
Y
years.
IRP Framework (PUC Decision and Order
No. 11630, Docket No. 6617) May 1992,
2.8
available at:
http://www.renewablehawaii.com/vcmcontent
/FileScan/PDFConvert/HECO_IRP3_App_C
_Final.pdf
2.9.1 Building Energy Codes for residential State code based on 1995 MEC is voluntary
buildings are in place and regularly updated N/N statewide and mandatory for counties of
Honolulu and Maui.
http://bcap-
energy.org/state_status.php?state_ab=HI
2.9
2.9
2.9.2 Building Energy Codes for No statewide standards. Some counties
commercial buildings are in place and N/N have established their own codes, based on
regularly updated pre-2000 ASHRAE.
http://bcap-
energy.org/state_status.php?state_ab=HI
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10 updated
Energy efficiency is a high priority in state Hawaii's "Lead by Example" program
buildings and state funded buildings as includes a wide range of programs and
Y
evidenced in capital planning and enabling standards for state facilities.
2.11 performance contracts
http://www.hawaii.gov/dbedt/info/energy/effici
ency/state/
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
Y-
in place. (See Guide Tab for Y/N criteria.)
3.1.2 Process is in place, such as a state Third Party Administrator will work with
or regional collaborative, to pursue EE as a utilities and stakeholders.
Y
high-priority resource. (See Guide Tab for
3.1 Y/N criteria.)
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility Hawaii Electric Light Co., Maui Electric
program? (who is sponsor) Company, Hawaiian Electric Company
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists July 2008 PUC Order Docket No. 2007-
0323 initiated the collection of the PBF for
the third-party administrator to begin July
2008, initially to finance startup costs.
Previously, in 2007, the PUC created a
statewide PBF to fund a third-party PBF
administrator. HRS 269-121 allows the PUC
to establish a "public benefits fund", funded
by all or a portion of current DSM fees, to be
used to support PUC-reviewed DSM and EE
Y programs. Previously, utilities collected
"DSM fees" and used the funds to
administer their own programs. The IRP
framework states that costs of implementing
the IRP are recoverable through a number
of possible methods. The transfer of energy
efficiency programs from the utilities to the
PBF was scheduled to occur between
January-July 2009.
4.1
Docket No. 2007-0323 available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
8/. Information about the 2007 PBF
R approval is available at
http://puc.hawaii.gov/PressReleases/2007/N
R-
Energy_Efficiency_Public_Benefits_Fund.PD
Statutory cost recovery provisions are
S available at
http://capitol.hawaii.gov/hrscurrent/Vol05_Ch
0261-0319/HRS0269/HRS_0269-0121.HTM
4.1.2 Recovery occurs via: (a) rider; (b) PBF to fund the third-party administrator
regular rate case; or (c) system benefits c was initiated on July 1, 2008.
charge
http://puc.hawaii.gov/PressReleases/2007/N
4.1.3 Funding is for multi-year periods R-
A base energy efficiency spending level
exists, with opportunity to justify higher level
4.2
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
EE n/a
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is The IRP Framework addresses
addressed and disincentives are removed disincentives by authorizing the Commission
to establish lost revenue recovery. The
Y
legislature has also granted the PUC
authority to establish a third party
administrator.
Hawaii 2006 Legislature, Senate Bill 3185
amends Chapter 269 of the Hawaii Code to
allow the Commission to authorize an
Energy Efficiency Utility.
http://capitol.hawaii.gov/hrscurrent/Vol05_Ch
0261-0319/HRS0269/HRS_0269-0122.HTM
The IRP Framework states that
disincentives should be removed and
incentives developed to make demand side
options at least as attractive to utilities as
supply side options. The Framework further
authorizes the Commission to establish lost
revenue recovery and/or incentive
mechanisms as necessary.
5.1.2 Method used is: (a) decoupling; (b) (a) October 24, 2008, the PUC opened
lost revenue recovery; or (c) non-utility Docket No. 2008-0274 to initiate proceeding
implementation of EE on decoupling for Hawaiian utilities. This
5.1 was driven by the October 2008 agreement
between the state and the utilities which
announced the intention of the parties to
adopt decoupling, to be initiated with the
a,b,
2009 HEC rate case. (b) The 1992 IRP
c
Framework allows use of cost recovery
mechanisms for DSM programs. (c) A third
party administrator will assume
responsibility for all utility energy efficiency
programs starting in the first half of 2009.
October 24, 2008 Docket No. 2008-0274 on
decoupling available at
http://hawaii.gov/budget/puc/PUC%20Annou
ncements/PUC%20opens%20proceeding%2
0relating%20to%20Decoupling.PDF/view;
IRP Framework (see item F) available at
http://www.renewablehawaii.com/vcmcontent
/FileScan/PDFConvert/HECO_IRP3_App_C
_Final.pdf; October 2008 agreement
available at:
http://www.heco.com/vcmcontent/StaticFiles/
pdf/HCEI.pdf
5.2.1 Utility/shareholder EE incentives are A shared savings, positive-only incentive
provided mechanism is in place, based on a
percentage of net benefits attributable to
demand side management programs. The
incentive is structured such that if 100% of
Y
energy efficiency goals are met, the utility
will receive 1% of net system benefits; it
increases incrementally to a maximum of
5% of the net system benefits if goals are
5.2 exceeded by 10%.
Feb 13, 2007, PUC Docket No. 05-0069,
Order 23258, "DSM Utility Incentive
Schedule", p. 104, available at
http://hawaii.gov/dcca/areas/dca/dno/dno200
7/.
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
when designing retail rates
5.3 5.3.2 Declining block rates and fixed
variable rate designs have been eliminated
5.4.1 Time sensitive rates in place The October 2008 Agreement stated that
Hawaiian Electric would request expedited
approval to fully implement interim time-of-
use rates for those customers.
5.4.2 Usage sensitive rates in place
5.4.3 AMI deployment planned HECO applied to the commission for
approval for advance metering project on
December 1, 2008; commission opened
5.4 document number 2008-0303 to investigate.
N The October 2008 Agreement stated that
Hawaiian Electric would apply to the
Commission for immediate approval to
begin installing advanced meters for all
customers who request them; by December
Docket No. 2008-0303 available at
http://dms.puc.hawaii.gov/dms/OpenDocSer
vlet?RT=&document_id=91+3+ICM4+LSDB
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
- energy efficient products
Investment Tax Credit for energy efficient
- investments
State supported low cost financing for
energy efficient investments: buildings (x),
- equipment (y)
Distributed Generation Policies
A statewide interconnection policy is in place Hawaii has simplified interconnection rules
for renewables, and all other DG. There are
some differences between the rules for
Kauai (which has an electric cooperative)
and all other islands. For systems up to 10
kilowatts (kW) with an inverter (and inverter-
based DG under 250 kW on islands other
than Kauai), there is a simple application
process for interconnection. For other
smaller systems, there are simplified
interconnection procedures for net metering
for solar, wind, biomass and hydroelectric
systems up to 50 kW in capacity on Kauai
Y and 100 kW in capacity on the other islands.
Two dockets were opened in 2006 to
streamline interconnection procedures: (1)
PUC Docket No. 2006-0497 (Hawaiian
7.1 Electric Co., Inc. (HECO); Hawaii Electric
Light Co., Inc.; and Maui Electric Co., Ltd.);
and (2) PUC Docket No. 2006-0498 (KIUC).
The PUC issued a decision and order in
April and May 2008 that created a more
streamlined procedure for interconnection to
HECO, Hawaii Electric Light Co., and Maui
Electric Co. KIUC provides small generating
facilities under two megawatts (MW) a fast-
track process, while larger systems must
PUC Order No. 19773 can be accessed
from here,
R
http://www.dsireusa.org/documents/Incentive
s/HI01Rc.pdf
Decisions and dockets 2006-0497 and 2006-
0498 can be found here:
R
http://hawaii.gov/dcca/areas/dca/dno/dno200
8/
A statewide net metering policy is in place Hawaii has net metering rules in place
established with HRS § 269-101 et seq. All
utilities must offer net metering to residential
and "small commercial" customers with
solar, wind, biomass or hydroelectric
systems up to 50 kW in size (an increase is
possible). Utilities offer net metering until
total net-metered capacity equals 0.5% of
each utility's peak demand. Net excess
generation is carried forward in the form of
a kWh credit that is applied to the next
month's bill. At the end of a 12-month period
NEG will be granted to the utility without any
compensation to the customer unless the
Y+ customer enters into a purchase
agreement. In December 2008, the
7.2 Commission approved in part and denied in
part, stipulations filed by HELCO & MECO
on 12/3/08. In particular, the Commission
approved the system cap from 1.0% to
3.0% of system peak demand for HELCO
and MECO. 40% of the 3.0% system peak
demand would be reserved for small
systems (10kw or less). HELCO and
MECO will increase system cap from 3.0%
to 4.0% of system peak demand when NEM
applications equal or exceed 75% of then
existing 3.0% system peak demand cap for
either less than or equal to 10kw systems or
HRS § 269-101 et seq can be accessed
from here,
S
http://www.dsireusa.org/documents/Incentive
s/HI04R.htm
A statewide exit fee policy is in place Hawaii does not have a statewide policy on
N exit fees. DG units do not have to pay exit
7.3
fees.
A statewide standby rate policy is in place The Hawaii PUC issued an order in 2008
making standby rates optional for 10 years
for consumers who install CHP or other
forms of power generation on their own
properties (applies to customers of the
following utilities: Hawaiian Electric
Company, Maui Electric Company, and
Y Hawaii Electric Light Company). DG
customers have the option to take standby
service or remain on the otherwise
applicable rate schedule. See Order No.
2006-0497, issued on May 15, 2008, for
more information.
http://hawaii.gov/dcca/areas/dca/dno/dno200
8
Hawaiian Electric Company (HECO) -
Schedule SS - Customers may choose to
receive standby service under the
provisions of their current commercial rate,
or the standby rate. A specific value of
standby capacity is contracted for with the
utility. Standby service is provided for fairly
7.4 U- high demand and energy charges. The
billing demand is based on the maximum
demand of the month with a partial ratchet
covering the previous 11 months. Rate
available at:
http://www.heco.com/vcmcontent/FileScan/P
DF/EnergyServices/Tarrifs/HECO/HECORat
esSchSS.pdf
Hawaii Electric Light Company (HELCO) -
Schedule SS - Customers may choose to
receive standby service under the
provisions of their current commercial rate,
or the standby rate. A specific value of
standby capacity is contracted for with the
utility. Standby service is provided for fairly
U- high demand and energy charges. The
billing demand is based on the maximum
demand of the month with a partial ratchet
covering the previous 11 months. Rate
available at:
http://www.heco.com/vcmcontent/FileScan/P
DF/EnergyServices/Tarrifs/HELCO/HELCOR
atesSchSS.pdf
As part of resource planning process, CHP
is reviewed and incorporated where effective As part of the Hawaii Clean Energy Initiative
(HCEI), the state has decided to replace its
current IRP process with a new Clean
N
Energy Scenario Planning (CESP) Process.
The PUC closed existing IRP dockets in late
2008, and is working on developing the new
CESP approach.
http://www.renewablehawaii.org/portal/site/h
eco/menuitem.508576f78baa14340b4c0610
7.5 c510b1ca/?vgnextoid=63ada76154960210V
gnVCM1000005c011bacRCRD&vgnextfmt=
default&cpsextcurrchannel=1
Hawaiian Electric Company released their
U+ most recent IRP in 2007. This IRP lists DG
and CHP as future supply side resource
options and sets a CHP MW targets.
http://www.heco.com/vcmcontent/HELCO/Renewa
Natural Gas
urce.
effective energy efficiency as a resource
October 2008 agreement states that stakeholders
will design and deliver program specifically
targeted to benefit low income electric and gas
users.
N
deliver energy efficiency where cost-effective.
cost-effective energy efficiency and modify ratemaking
IDAHO
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority Order 22299 from Case # U-1500-165,
resource, equivalent or superior to supply issued in 1989, establishes that
resources conservation resources should be given
consideration equivalent to generation
resources, and that utilities should procure
Y all cost-effective efficiency. The 2007 Idaho
Energy Plan, prepared by the Idaho
1.1 Legislative Council Interim Committee on
Energy, Environment and Technology,
recommended that when acquiring
resources, Idaho should give priority to
Order 22299 can be looked up from
http://www.puc.state.id.us/search/orders/dts
R earch.html; Idaho Energy Plan:
http://www.puc.state.id.us/hot/2007%20Ener
gy%20Plan.pdf
1.2.1 EE is integrated into an active IRP, IRP was established in Order 25260 from
portfolio management, or other planning Y Case #GNR-E-93-3, issued in 1993.
process
Order 25260 can be looked up from
R http://www.puc.state.id.us/search/orders/dts
1.2 earch.html
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers N/A
EE is an alternative to transmission based
on a long-term transparent IRP or
1.3 transmission system plan
1.4.1 EE is a biddable commodity
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute N
2.1
The TRC or Societal Cost Test is used to No specific cost effectiveness test is
evaluate EE programs required, although in practice utilities may
use a variety of tests. Order 22299, issued
in 1989, rejected exclusive use of the "no
losers" test. The 2007 Idaho Energy Plan,
N prepared by the Idaho Legislative Council
Interim Committee on Energy, Environment
2.2
and Technology, recommendeds that the
TRC test is the appropriate test of the cost-
effectiveness of DSM measures.
Order 22299 can be looked up from
R http://www.puc.state.id.us/search/orders/dts
earch.html; Idaho Energy Plan:
2.3.1 Potential for cost-effective EE has http://www.puc.state.id.us/hot/2007%20Ener
Order 22299 from Case # U-1500-165,
been established through a potential study issued in 1989, required utilities to submit
Y annual Conservation Analysis Plans, which
2.3 would assess potential within each utility's
own jurisdiction.
2.3.2 Established EE programs reach all Each utility has a program for all classes.
Y
customer classes
Funding requirements for all long-term, cost-
N
2.4 effective EE have been established
2.5.1 Quantitative MW and MWh savings Specific numeric goals are not established,
goals have been established and are but the Commission expects utilities to
producing incremental investment. procure all cost-effective efficiency. The
2007 Idaho Energy Plan, prepared by the
Idaho Legislative Council Interim Committee
N
on Energy, Environment and Technology,
recommends the PUC establish targets for
conservation achievement for IOUs based
on estimates of available cost-effective EE.
Idaho Energy Plan:
http://www.puc.state.id.us/hot/2007%20Ener
gy%20Plan.pdf
2.5.2 Goals are established: (a)
connection with IRP or other planning
2.5 process; (b) as part of an EEPS or similar
system; (c) as part of program approval and
budget-setting process; (d) other
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar
standard
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been Programs are reviewed periodically by
established Commission staff, but there is no formal
N M&V process. Specific M&V criteria are
expected to be developed in Case No. IPC-
E-09-09.
2.6.1.1 M&V is adequately funded
2.6.1.2 Energy savings are used to
measure performance
2.6.1.3 M&V is done according to a
2.6 defined schedule
2.6.1.4 M&V is conducted by an
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been The ID PUC requires utilities to file and
established implement DSM plans. Programs are
Y funded by utilities, who recover costs
through riders, rate cases, rate design, etc.
2.7
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated Order 25260 from Case #GNR-E-93-3,
issued in 1993, establishes that IRPs should
Y
2.8 be updated at least every 2 years.
2.9.1 Building Energy Codes for residential 2006 IECC standards mandatory statewide.
buildings are in place and regularly updated Y/Y Codes are reviewed every three years, and
the last code change was in 2007.
http://bcap-
energy.org/state_status.php?state_ab=ID
2.9
2.9.2 Building Energy Codes for 2006 IECC standards mandatory statewide.
commercial buildings are in place and Y/Y Codes are reviewed every three years, and
regularly updated the last code change was in 2007.
http://bcap-
energy.org/state_status.php?state_ab=ID
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10 updated
Energy efficiency is a high priority in state Executive Order 2005-12, signed July 2005,
buildings and state funded buildings as requires state agencies to implement a
evidenced in capital planning and enabling series of energy conservation measures,
performance contracts where feasible. The measures include
adjusting settings for thermostats, shutting
off lights and computers, and evaluating
HVAC machinery for efficiency. The 2007
xxxxxx had a number of recommendations
related to EE in state govt. In 2008,
legislation passed that requires major state
facility projects (to the extent feasible,
Y practical, and fiscally prudent) to be
2.11 designed, constructed, and certified to meet
a target of at least 10% to 30% better
efficiency than a comparable building on the
same site built to the requirements of the
then current building codes. Major facility
projects are defined as new construction
larger than 5,000 square feet, and
renovations greater than 5,000 square feet
with a project cost greater than 50% of the
assessed value of the existing building.
EO, Executive Order:
S http://gov.idaho.gov/mediacenter/execorders
Recommendation 3: Miscellaneous Policies /eo05/eo_2005-12.htm; HB 422, Idaho
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
Y
3.1 high-priority resource. (See Guide Tab for
Y/N criteria.)
3.1
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Do not delete this row.
Do not delete this row.
Do not delete this row.
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility Idaho Power Company, Intermountain Gas,
program? (who is sponsor) Kootenai Electric Co-Op
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists The three major utilities have tariff riders.
Additional funding may come from rate
Y cases or other sources such as BPA.
4.1 4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits a,b
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently Idaho Power: 2.5% (Case IPC-E-08-03;
used for energy efficiency [no unit = %; m/k Decision on 5/30/08). Rocky Mountain
= mils/kWh] Power: 3.72% (Case PAC-E-08-01;
4.3 Decision on 4/29/08). Avista: 1.9%.
Amounts are subject to change
Funds from carbon trading program support
4.4 EE
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is SUMMARY: Idaho Power was granted a
addressed and disincentives are removed three-year pilot fixed-cost adjustment
decoupling mechanism on 3/12/07 for
residential and small business customers.
The fixed-cost adjustment allows annual
true-up, concurrent with existing power cost
Y adjustment, of collected fixed costs and
amount authorized in most recent rate case.
The Decision requires the utility to expand
DSM programs and support more EE
building energy codes. Lost revenue
recovery may also be available on a case-
by-case basis.
Idaho Power, Order No. 30267, Case No.
IPC-E-04- l5, pp. 13-14:
5.1 R http://www.puc.idaho.gov/internet/cases/elec
/IPC/IPCE0415/ordnotc/20070312FINAL_O
RDER_NO_30267.PDF.
Order 25261 in Case No. GNR-E-93-4
establishes that expenditures on
conservation and efficiency should be
treated at least as profitably as investments
in supply side resources, and allows lost
R
revenue recovery on a case-by-case basis.
Order 25261 may be looked up from
http://www.puc.state.id.us/search/orders/dts
earch.html
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility a,b
implementaion of EE
5.2.1 Utility/shareholder EE incentives are As of the end of 2008, Idaho Power had a
provided three-year pilot incentive for its Energy Star
New homes program. The utility earns an
incentive based on the penetration of
Energy Star new homes in the marketplace.
The 2007 Idaho Energy Plan, prepared by
Y-
the Idaho Legislative Council Interim
Committee on Energy, Environment and
Technology, recommends the PUC should
establish incentives for IOUs that achieve
5.2 conservation targets established by the
PUC.
http://www.puc.idaho.gov/internet/cases/elec
/IPC/IPCE0632/ordnotc/20070312FINAL_O
RDER_NO_30268.PDF; Idaho Energy Plan:
R
http://www.puc.state.id.us/hot/2007%20Ener
gy%20Plan.pdf
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration The 2007 Idaho Energy Plan, prepared by
when designing retail rates the Idaho Legislative Council Interim
Committee on Energy, Environment and
N
Technology, recommends the PUC and
utilities adopt rate designs that encourage
more effeicient use of energy.
5.3 Idaho Energy Plan:
http://www.puc.state.id.us/hot/2007%20Ener
gy%20Plan.pdf
5.3.2 Declining block rates and fixed
variable rate designs have been eliminated Y
5.4.1 Time sensitive rates in place Pacificorp has had TOU rates in place since
Y
the 1980s for all customer classes.
5.4.2 Usage sensitive rates in place
5.4.3 AMI deployment planned Smart metering programs are implemented
for all three utilities. In July 2007, the
Commission approved a two-year pilot
Y/
program for Avista. In 2008, The
5.4 C
Commission approved for an Idaho Power
proposal to install smart meters for every
customer over three years.
Idaho Power Case IPC-E-08-16:
R http://www.puc.state.id.us/search/orders/dts
earch.html
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
- energy efficient products
Investment Tax Credit for energy efficient
- investments
State supported low cost financing for x,y Low-interest loans are available to all
energy efficient investments: buildings (x), sectors for a wide range of conservation
- equipment (y) improvement projects.
http://www.idwr.idaho.gov/energy/loans/default.htm
Distributed Generation Policies
A statewide interconnection policy is in place Idaho does not have statewide
interconnection standards for DG. An order
issued in January 2007 by the ID PUC ruled
that the National Association of Regulatory
Utility Commissioners (NARUC)
interconnection model should be used as a
guideline for interconnection agreements.
N
However, later the Idaho Public Utilities
Commission (PUC) rejected the federal
interconnection and net metering standards
in early 2007, pursuant to EPAct 2005,
stating that the utility tariffs are adequate
(case # GNR-E-06-02).
Avista Corp, IOU - has interconnection
standards for systems that either are net-
metered or are not. For net-metered
systems the capacity limit is 25 kW and the
limit is 10 MW for PURPA qualifying
facilities that are not net-metered. Avista's
interconnection guidelines for net-metered
systems up to 25 kW require an external
disconnect and all equipment must meet
IEEE, UL, NESC, and NEC requirements.
U- Avista has separate interconnection rules
7.1
for DG systems up to 300 kW in capacity.
There is a $100 application fee for these
systems and they have to follow the same
general guidelines as smaller net metered
systems, such as having an external
disconnect and applicable national
standards. The Utility allows for DG systems
up to 10 MW with QF status to connect.
Idaho Power Co, IOU - has an established
interconnection procedure and two levels of
interconnection - one for systems smaller
than 20 MW and the other for systems
larger than this threshold. There are
standard interconnection application and
agreement forms. For systems larger than
U- 20 MW $10,000 must be deposited with the
utility and may be used for interconnection
studies. There are set interconnection
timeframes, but the entire procedure is quite
lengthy. Insurance and technical
requirements are not discussed in detail.
A statewide net metering policy is in place Idaho does not have a statewide net
metering policy, however each of the state's
N three IOUs - Avista Utilities, Idaho Power,
and Rocky Mountain Power - has developed
a net-metering tariff.
Avista Corp offers net metering to
customers that generate electricity using
solar, wind, hydropower, biomass or fuel
cells. Commercial, residential, and
agricultural systems are eligible, but
residential systems are limited to 25 kW in
capacity. Aggregate net-metered capacity is
limited to 0.1% of the utility's retail peak
generation in 2000. Also, any single
U- customer cannot generate more than 20%
of the aggregate capacity of all net-metered
systems. Net excess generation is credited
to the customer's next bill at the utility's
retail rate and at the end of each calendar
year any remaining NEG is granted to the
utility. Avista's net metering tariff can be
found here, http://www.avistautilities.com/
7.2 assets/tariffs/id/ID_063.pdf.
Idaho Power Co, IOU - has the same
general net metering requirements as Avista
Utilities with a couple of exceptions related
to capacity limits and treatment of NEG.
Idaho Power limits large commercial and
agricultural customers to 100 kW in
capacity. Residential and small commercial
customers are limited to 25 kW. NEG for
residential and small commercial customers
is credited at the utility's retail rate and
U- carried forward to the next month. For large
commercial and agricultural customers,
NEG is credited at 85% of the utility's
avoided cost-rate and carried forward to the
next month. Information on Idaho Power's
net metering standards can be found here,
http://www.idahopower.com/
aboutus/regulatoryinfo/tariffPdf.asp?id=198&
.pdf.
A statewide exit fee policy is in place
N Idaho has no statewide policy on exit fees.
7.3
DG units would not be charged such a fee.
A statewide standby rate policy is in place Idaho does not have a statewide policy on
N
standby rates
Avista Corp - there is no standard standby
rate. Customers seeking standby service
would need to contract with the utility to be
charged under a regular tariff. Typical rates
U
have moderate demand and energy
charges. Demand charges are based on
the maximum 15 minute demand of the
month. Rates available at:
http://www.avistautilities.com/services/energ
ypricing/tariffs/id/elect/Pages/default.aspx
7.4
Idaho Power Co - Schedule 45 - standby
service is provided to customers that
contract with the utility for a specific amount
of standby capacity. A moderate demand
based reservation charge is assessed every
month. Actual usage is charged through
U
Schedule 19 along with a standby demand
charge based on the maximum 15 minute
demand of the month. There is a high
penalty for exceeding the contract demand.
Rate available at:
http://www.idahopower.com/aboutus/regulat
oryinfo/tariffs.asp?state=id
As part of resource planning process, CHP IRP was established in Order 25260 from
is reviewed and incorporated where effective Case #GNR-E-93-3, issued in 1993. The ID
N rules do not mention CHP. The Idaho PUC
prepares a statewide energy plan. Biennial
filing of IRPs is required.
http://www.puc.state.id.us/search/orders/dtsearch.
Avista Corp filed its most recent IRP in ID
7.5
U+ and WA on 8/31/2007. Avista modeled the
costs of implementing small CHP projects
and list CHP as a viable resource option.
http://www.avistautilities.com/inside/resources/irp/
U+ Idaho Power Co's most recent IRP update
was issued in 2008, CHP is considered.
http://www.idahopower.com/AboutUs/PlanningForFuture/irp/2006/default.cfm
Natural Gas
urce.
Gas utilities participate in resource planning, but it
N does not always result in the pursuit of meaningful
DSM.
effective energy efficiency as a resource
N
Y
deliver energy efficiency where cost-effective.
Avista has a gas EE cost recovery rider.
Intermountain Gas, the other natural gas utility in
Y- Idaho, does not.
a
Avista gas 0.5%
cost-effective energy efficiency and modify ratemaking
y/loans/default.htm
MONTANA
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority Montana's IRP rules state an objective of
resource, equivalent or superior to supply acquiring all cost-effective energy efficiency.
resources The commission considers EE equivalent
Y to supply side resources in assembling the
least cost, least risk portfolio. Also see 2.1.
1.1
Administrative Rules of Montana 38.5.2001
et seq. See
A
http://www.mtrules.org/gateway/ruleno.asp?
RN=38%2E5%2E2001
1.2.1 EE is integrated into an active IRP, SUMMARY: Montana's two IOUs are
portfolio management, or other planning regulated differently. A traditionally
process Y regulated IOU performs IRP. A restructured
IOU conducts portfolio management.
IRP PROCESS: § 69-3-1201-1206,
Montana Code Annotated requires IRP. See
http://data.opi.state.mt.us/bills/mca_toc/69_3
_12.htm. IRP rules require the integration of
S, R supply and demand side resources into a
least cost plan. Rules are available in
Montana Administrative Code 38.5.2001 et
1.2 seq. See http://arm.sos.state.mt.us/38/38-
698.htm
PORTFOLIO MANAGEMENT FOR
DEFAULT SUPPLY: See entry in Section
1.2.2.
1.2.2 Efficiency is procured as a resource MCA 69-8-419 requires the restructured
for default service/standard offer customers utility to conduct portfolio management for
Y default supply, including the consideration of
a full range of demand-side options.
See
S http://data.opi.state.mt.us/bills/mca/69/8/69-
8-419.htm
Administrative rules regarding the treatment
R of efficiency in portfolio management is
available at MAC 38.5.8218. See
http://161.7.8.61/38/38-6175.htm
EE is an alternative to transmission based Transmission constraints are handled in the
on a long-term transparent IRP or context of the IRP. Targeted DSM has been
Y
1.3 transmission system plan considered as an alternative to transmission
lines in the past.
1.4.1 EE is a biddable commodity All-source RFPs are issued, but as a
Y- practical matter, utilities have not received
DSM bids in these solicitations.
1.4
1.4 1.4.2 Bids occur in the following markets:
(a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute Montana's IRP rules state an objective of
acquiring all cost-effective energy efficiency.
The commission considers EE equivalent
to supply side resources in assembling the
least cost, least risk portfolio. Statute
requires a Universal System Benefit
Program to ensure funding for energy
Y conservation, renewables, and low-income
energy assistance. Utilities are required to
contribute 2.4% of their annual retail sales
2.1 revenue from 1995. The Montana Climate
Change Action Plan, released in 11/07,
recommended that utilities implement a plan
to obtain 100% of the achievable cost-
effective EE by 2025.
MT Code Annotated 69-8-402:
http://data.opi.state.mt.us/bills/mca/69/8/69-
8-402.htm; Climate Change Action Plan:
S, A
http://www.mtclimatechange.us/ewebeditpro/
items/O127F14041.pdf
The TRC or Societal Cost Test is used to The Societal Cost Test and the TRC test
evaluate EE programs are used for the IRP utility. Neither test is
required for the "portfolio management"
Y-
2.2 utility. MAC 38.5.8218 specifies that the RIM
[non-participant] test should not be used in
portfolio management.
See http://161.7.8.61/38/38-6175.htm
2.3.1 Potential for cost-effective EE has The "portfolio management" utility did a
been established through a potential study potential study in 2003 as part of its default
Y- supply plan. An update of the potential
study is expected in Sprint 2009.
2.3 Information about the 2003 study is
available at
http://www.montanaenergyforum.com/pdf/20
05_Plan/2005_v2_CH2.pdf
2.3.2 Established EE programs reach all Electric EE programs reach all customer
Y
customer classes classes, including low-income customers.
Funding requirements for all long-term, cost-
effective EE have been established
2.4
2.5.1 Quantitative MW and MWh savings The "portfolio management utility" has
goals have been established and are Y- established a goal of 5 aMWH/year in its
producing incremental investment. 2005 Default Supply Plan.
http://www.montanaenergyforum.com/pdf/20
05_Plan/2005_v2_CH2.pdf
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
a
system; (c) as part of program approval and
budget-setting process; (d) other
2.5 2.5.3 Energy Efficiency can be used to EE cannot be used to fulfill Montana's
fulfill requirements of an RPS or similar current RPS requirements. The Montana
standard Climate Change Action Plan, released in
N
11/07, recommended that utilities
implement a plan to obtain 100% of the
achievable cost-effective EE by 2025.
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been NorthWestern Energy, the "portfolio
established management" utility, submitted a
comprehensive evaluation of its programs
Y- to the Commission on 8/16/07 as part of the
Commission approval of its lost revenue
recovery mechanism.
http://www.psc.state.mt.us/eDocs/eDocume
nts/pdfFiles/D2004-6-90_6574e.pdf; Docket
D2007.5.46 (evaluation):
http://www.psc.mt.gov/eDocs/eDocuments/g
etDocumentsInfo.asp?docketId=8516&do=fa
lse
2.6.1.1 M&V is adequately funded
2.6 2.6.1.2 Energy savings are used to
Y
measure performance
2.6.1.3 M&V is done according to a
defined schedule
2.6
2.6.1.4 M&V is conducted by an
Y
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been The Universal System Benefits Program
established requires all electric utilities, including coops,
to contribute annually 2.4% of their 1995
revenues to the program, which supports
cost-effective energy conservation,
weatherization renewable projects, R&D
related to EE and renewables, market
transformation, and low-income energy
Y assistance. Utilities may spend the funds
on internal programs or contract to fund
programs externally or turn the funds over
2.7 to state agencies to administer. Large
electricity users may fund their own
programs instead of contributing to the
program. The Commission declined to
require NorthWestern Energy to use a third-
party administrator to conduct its DSM
programs Annotated 69-8-402:
MT Code in 2008.
S
http://data.opi.state.mt.us/bills/mca/69/8/69-
2.7.2 Delivery is via: (a) utility 8-402.htm; Docket D2007.5.46:
Both options are used in practice.
administration; (b) third-party administration; a,c
or (c) government agency
Resource plans are regularly updated IRPs are required to be submitted every two
Y years. See 1.2.1
2.8 Administrative Rules of Montana 38.5.2001
et seq. See
A
http://www.mtrules.org/gateway/ruleno.asp?
RN=38%2E5%2E2001
2.9.1 Building Energy Codes for residential 2003 IECC mandatory statewide. Code is
buildings are in place and regularly updated reviewed every three years and was last
updated in 2004. The Montana Climate
Change Action Plan, released in 2007,
Y/Y recommends Montana increase building
codes so that they are at least 15% higher
by 2010 than current codes, and 30% higher
by 2020. "Beyond code" building design
incentives are also recommended.
http://bcap-
energy.org/state_status.php?state_ab=MT;
Climate Change Action Plan:
2.9.2 Building Energy Codes for 2003 IECC mandatory statewide. Code is
2.9
commercial buildings are in place and reviewed every three years and was last
regularly updated updated in 2004. The Montana Climate
Change Action Plan, released in 2007,
Y/Y recommends Montana increase building
codes so that they are at least 15% higher
by 2010 than current codes, and 30% higher
by 2020. "Beyond code" building design
incentives are also recommended.
http://bcap-
energy.org/state_status.php?state_ab=MT;
Climate Change Action Plan:
http://www.mtclimatechange.us/ewebeditpro/
items/O127F14041.pdf
Appliance and Equipment Efficiency The Montana Climate Change Action Plan,
Standards are in place and regularly resleased in 2007, recommends Montana
N
updated set higher-than-federal EE appliance
2.10 standards where technological advances
allow. Change Action Plan:
Climate
http://www.mtclimatechange.us/ewebeditpro/
items/O127F14041.pdf
Energy efficiency is a high priority in state
buildings and state funded buildings as
N
evidenced in capital planning and enabling
2.11 performance contracts
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y
3.1.2 Process is in place, such as a state NorthWestern Energy has an on-going
or regional collaborative, to pursue EE as a advisory committee related to all aspects of
3.1 Y
high-priority resource. (See Guide Tab for resource planning and acquisition, including
Y/N criteria.) EE.
3.1
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility Montana-Dakota Utilities Company
program? (who is sponsor)
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists Statute requires that the Commission "shall
estalish an electricity cost recovery
mechanism that allows a public utility to fully
recover prudently incurred elctricity supply
costs." Montana's PBF was established in
1998 and has been extended twice by the
Y Legislature. Electric utilities, including
coops, are required to contribute annually
2.4% of their 1995 revenues to the program.
Currently, the program runs through 2009.
Some additional DSM costs are recovered
in base rates.
4.1
MCA 69-8-210 (cost recovery):
http://data.opi.state.mt.us/bills/mca/69/8/69-
8-210.htm; Montana Code Annotated
S
69.8.402 (PBF):
http://data.opi.state.mt.us/bills/mca/69/8/69-
8-402.htm
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits b,c
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is The "portfolio management" utility,
addressed and disincentives are removed NorthWestern Energy, was granted lost
revenue recovery mechanisms in 2004 and
in 2008. In the 2008 Order, the
Commission found that it had inadequate
information on the merits of decoupling, and
Y- thus should continue its lost revenue
recovery practice, but required the utility to
continue considering the throughput
incentive with its advisors. A 2008
Commission Order required Montana-
5.1 Dakota Utilities to consider decoupling in its
2009 cost-of-service / rate design filing.
Docket D2004.6.90 (2004):
http://www.psc.state.mt.us/eDocs/eDocume
nts/pdfFiles/D2004-6-90_6574e.pdf; Docket
D2007.5.46 (2008):
http://www.psc.mt.gov/eDocs/eDocuments/p
dfFiles/D2007-5-46_6836c.pdf
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility b
implementaion of EE
5.2.1 Utility/shareholder EE incentives are Statute allows for a bonus 2% return on
provided DSM investments, but this hasn't been
used. DSM expenses are generally
expenses rather than capitalized. Montana
N
rules allow the Commission to reward the
default supplier for superior performance,
5.2 which can include demand and supply side
procurement.
Montana Administrative Rules 38.5.8227.
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
when designing retail rates
5.3 5.3.2 Declining block rates and fixed The two largest utilities have flat rates for
variable rate designs have been eliminated residential customers.
5.4.1 Time sensitive rates in place In 2006, the Commission deferred a
decision to adopt the PURPA Standard 14,
saying it would consider whether to adopt
the standard for each utility in the next rate
cases. A 2008 Commission Order required
N
Montana-Dakota Utilities to study time-
differentiated rates, and consider smart
metering, inverted block rates in its 2009
cost-of-service / rate design filing.
http://www.psc.mt.gov/eDocs/eDocuments/p
dfFiles/D2007-7-79_6846f.pdf
5.4 5.4.2 Usage sensitive rates in place
5.4.3 AMI deployment planned A 2008 Commission Order required
Montana-Dakota Utilities to study time-
N differentiated rates, and consider smart
metering, inverted block rates in its 2009
cost-of-service / rate design filing.
http://www.psc.mt.gov/eDocs/eDocuments/p
dfFiles/D2007-7-79_6846f.pdf
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
- energy efficient products
Investment Tax Credit for energy efficient Tax incentives are available to customers in
investments Y certain sectors for energy efficiency
improvements.
- http://mt.gov/revenue/forindividuals/individual
income/incentivesiit.asp#conservation
http://mt.gov/revenue/forbusinesses/corporat
ion/corptaxincentives.asp
State supported low cost financing for
energy efficient investments: buildings (x),
- equipment (y)
Distributed Generation Policies
A statewide interconnection policy is in place Montana has interconnection standards only
for net metered systems, and only for
systems generating electricity from solar
photovoltaics, wind, or hydroelectric.
System capacity is limited to 50 kW; there is
not limit on overall enrollment. External
disconnects are not specified, however
Northwestern Energy requires it. All systems
Y- must comply w/ with all national safety,
equipment and power-quality standards as
set by the National Electrical Code (NEC),
Institute of Electrical and Electronic
Engineers (IEEE), National Electrical Safety
Code (NESC) and Underwriters
Laboratories (UL). Additional insurance is
not addressed.
7.1
Northwestern Energy LLC has
interconnection standards and an
interconnection agreement for net metered
systems.Customers must follow all national
safety standards and must have a manual,
lockable, external disconnect. Customers
are not required to purchase additional
U- liability insurance, but customers are
encouraged to verify that they have enough
coverage. The standard interconnection
agreement can be accessed from here,
http://www.northwesternenergy.com/docume
nts/E+Programs/E+NetMeteringAgreement.p
df
A statewide net metering policy is in place Montana has a net metering law,
established with Mont. Code § 69-8-604.
Customers of IOUs are allowed to net meter
systems that generate electricity from the
following renewables - solar, wind, or
hydropower systems up to 50 kW. All
customer classes are eligible and there is
Y-
no limit on overall enrollment or statewide
installed capacity. Systems must comply
7.2
with national standards - IEEE, UL, and
NEC standards. NEG is credited to the
customers next monthly bill. At the
beginning of each calendar year any NEG is
granted to the utility.
Mont. Code § 69-8-604 can be accessed
from here,
S
http://www.dsireusa.org/documents/Incentive
s/MT07R.htm
A statewide exit fee policy is in place Montana does not have a statewide exit fee
N policy. DG unit owners/operators are not
7.3
charged exit fees.
A statewide standby rate policy is in place Montana does not have a statewide policy
N
on standby rates
MDU Resources Group Inc - no standard
standby rate is currently offered, so
customers seeking standby service would
have to enter into an individual contract with
the utility. Utility personnel said that a rate
similar to Rate 30 would be charged with a
U specific reservation fee determined in the
contract. Rate 30 has moderate demand
and energy charges and billing demand is
based on the maximum 15 minute demand
of the month with no ratchet. Rate available
7.4 at: http://www.montana-
dakota.com/Pages/ElectricandNaturalGasRa
tes.aspx?state=Montana
NorthWestern Energy LLC - there is no
standard standby rate. Customers seeking
standby service would need to contract with
the utility to be charged under a regular
tariff. Typical rates have moderate demand
U
and energy charges. Demand charges are
based on the maximum 15 minute demand
of the month. Rate available at:
http://www.northwesternenergy.com/display.
aspx?Page=Montana_Rate_Schedules&Ite
m=117
As part of resource planning process, CHP Montana’s IRP process is outlined in the
is reviewed and incorporated where effective Montana Administrative Rules 38.5.2001-
2012. However, during the restructuring
period Montana’s main electric utility
divested itself of its generation resources
and the PSC adopted another set of
N
Administrative rules to govern the
restructured utility. Those rules were
modeled after the PSC’s IRP rules and are
outlined in the Administrative Rules
38.5.8201-8226.
7.5
http://www.mtrules.org/gateway/ruleno.asp?
RN=38.5.2002 and
http://www.mtrules.org/gateway/RuleNo.asp
?RN=38%2E5%2E8226
MDU Resources Group Inc considers
U+
resources such as CHP in their IRP.
http://www.mduenergycenter.com/forms/2007Main
Northwestern Energy LLC considers CHP
U+
technologies in its IRP.
http://www.northwesternenergy.com/display.aspx?Page=Default_Supply_Electric&Item=1
NA
Natural Gas
urce.
Montana's IRP rules state an objective of acquiring all cost-
effective energy efficiency.
Y
Administrative Rules of Montana 38.5.2001. See
http://arm.sos.state.mt.us/38/38-697.htm
A
Natural gas utilities are required to prepare conservation plans.
See MAC 38.6.201. NorthWestern Energy completed its natural
Y gas biennial procurement plan in 12/08.
http://arm.sos.mt.gov/38/38-7021.htm; NorthWestern plan:
http://www.northwesternenergy.com/display.aspx?Page=Default_S
upply_Gas
S
effective energy efficiency as a resource
Montana's IRP rules state an objective of acquiring all cost-
effective energy efficiency. The Commission considers EE
equivalent to supply side resources in assembling the least cost,
least risk portfolio. Statute requires the Commission to establish a
natural gas Universal System Benefit Program, and starting
1/1/07, there is a minimum annual funding requirement for low-
income weatherization and low-income energy bill assistance at
Y 0.42% of a natural gas utility's annual revenue. The Montana
Climate Change Action Plan, released in 11/07, recommended
that utilities implement a plan to obtain 100% of the achievable
cost-effective EE by 2025.
MT Code Annotated 69-3-1408:
http://data.opi.mt.gov/bills/mca/69/3/69-3-1408.htm
Natural gas EE programs reach all customer classes, including
Y
low-income customers.
Statute requires the Commission to establish a natural gas
Universal System Benefit Program, and starting 1/1/07, there is a
minimum annual funding requirement for low-income
weatherization and low-income energy bill assistance at 0.42% of
a natural gas utility's annual revenue.
Y
MT Code Annotated 69-3-1408:
S
http://data.opi.mt.gov/bills/mca/69/3/69-3-1408.htm
Natural gas conservation plans are required to be submitted every
Y two years.
Y
NorthWestern Energy has an on-going advisory committee related
to all aspects of resource planning and acquisition, including EE.
Y
deliver energy efficiency where cost-effective.
MAC 38.6.201 states that gas utilities shall be authorized to
recover reasonable costs incurred to implement conservation
programs. A gas PBF was established in 1997. Additional DSM
costs are recovered in base rates.
Y
http://arm.sos.mt.gov/38/38-7021.htm; MT Code Annontated
(PBF) 69-3-1408: http://data.opi.mt.gov/bills/mca/69/3/69-3-
1408.htm
b,c
cost-effective energy efficiency and modify ratemaking practices to
Lost revenue recovery was approved for MDU's natural gas
efficiency programs in 2005 in Docket 2005-10-156.
Y-
http://www.psc.state.mt.us/eDocs/eDocuments/pdfFiles/D2005-10-
156_6697c.pdf
b
NEW MEXICO
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority The New Mexico Efficient Use of Energy Act
resource, equivalent or superior to supply requires demand and supply side resources
resources to be evaluated consistently in the IRP
process. The Act also requires the
Commission to ensure that supply and
demand options are financially neutral to
utilities. The 2008 amendments (HB 305) to
the Efficient Use of Energy Act of 2005 to
provide for energy efficiency and load
Y management for public utility customers. HB
305 directs electric and gas utilities to
acquire all cost-effective and achievable
1.1 energy efficiency resources. The 2008
amendments also direct the PRC to provide
utilities an opportunity to earn a profit on
investments in cost-effective energy
efficiency and load management resources.
http://www.nmcpr.state.nm.us/NMAC/_title17
R
/T17C007.htm
HB 305:
S http://ssl.csg.org/dockets/2010cycle/30B/30B
bills/1230b01nmloadmanagement.pdf
1.2.1 EE is integrated into an active IRP, New Mexico Statutes, Chapter 62-17-10
portfolio management, or other planning requires utilities to conduct IRP and
process Y evaulate supply and demand side resources
on a consistent and comparable basis.
IRP statute may be looked up from
S http://www.conwaygreene.com/nmsu/lpext.dl
l?f=templates&fn=main-hit-h.htm&2.0
1.2 The PUC promulgated IRP rules in April
2007. The rules are available at
R
http://www.nmcpr.state.nm.us/NMAC/_title17
/T17C007.htm
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers
EE is an alternative to transmission based
on a long-term transparent IRP or N
1.3 transmission system plan
1.4.1 EE is a biddable commodity N
1.4
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute New Mexico Statutes, Chapter 62-17-2
establishes efficiency as an essential
component of utility resource portfolios.
Utility stakeholders followed up overall
energy use reduction goals established by
Governor Bill Richardson in 2007 with
Y specific requirements for electric utilities.
2.1 Negotiated consensus amendments to the
2005 Efficient Use of Energy Act require
investor-owned utilities to reduce electricity
use by 5% by 2014 and 10% by 2020 as a
result of DSM programs implemented
starting in 2007.
http://www.conwaygreene.com/nmsu/lpext.dl
S
l?f=templates&fn=main-hit-h.htm&2.0
New Mexico Statutes, Chapter 62-17-5
The TRC or Societal Cost Test is used to Y requires use of the TRC test.
2.2 evaluate EE programs
S see 2.1 above
2.3.1 Potential for cost-effective EE has PNM completed a study in 2006.
been established through a potential study Y
http://www.swenergy.org/news/PNM_Electric
_Potential_Study.pdf
2.3 2.3.2 Established EE programs reach all PNM and Xcel's DSM programs include
customer classes programs for residential and commercial
Y customers. Filings for 2009 programs took
place 2008 and were approved by the PRC.
2008 Leg activity (HB 246) attempted to
direct funds to low-income programs. Bill
stalled in committee.
PNM:
http://www.swenergy.org/news/2008/2008-
09-
U PNM_2008_Electricity_DSM_Plan_and_Filin
g.pdf Xcel:
http://www.swenergy.org/news/2008/2008-
11-SPS_2009_DSM_Plan.pdf
Funding requirements for all long-term, cost- The PNM study, conducted by ITRON,
effective EE have been established included a 10-year analysis of costs and
benefits of a "maximum achievable" EE
program. See p. 10 of the report at the link
Y below. HB 305 clarifies that PRC-approved
2.4 energy efficiency programs must be cost
effective, that is,
less expensive than pursuing new sources
of supply;
2.5.1 Quantitative MW and MWh savings The 2008 amendments (HB 305) to the
goals have been established and are Efficient Use of Energy Act of 2005 to
producing incremental investment. provide for energy efficiency and load
management for public utility customers. HB
305 directs electric and gas utilities to
acquire all
cost-effective and achievable energy
efficiency resources. Electric utilities must
N achieve a five
percent energy efficiency savings from 2005
electricity sales by 2014, and 10 percent by
2020.
The Public Regulation Commission (PRC)
can set alternative energy efficiency
requirements if
the electric utility demonstrates it cannot
meet the minimum requirements.
2.5
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
system; (c) as part of program approval and
budget-setting process; (d) other
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar N
standard
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been New Mexico Statutes 62-17-8 requires
established utilities to submit an annual M&V report
prepared by an independent third party and
conforming to any specifications that the
Commission should establish. Additional
guidance is provided in NMAC 17.7.2.12.
Y HB 305 adopted in 2008 strengthens the
energy efficiency
measurement and verification requirement;
and requires a detailed assessment of the
utility’s energy efficiency programs every
three years by an independent program
evaluator.
http://www.nmcpr.state.nm.us/NMAC/parts/ti
S
tle17/17.007.0002.htm
2.6.1.1 M&V is adequately funded Y
2.6.1.2 Energy savings are used to
Y
2.6 measure performance
2.6.1.3 M&V is done according to a HB 305 strengthens the energy
defined schedule efficiencymeasurement and verification
requirement; and requires a detailed
Y
assessment of the utility’s energy efficiency
programs every three years by an
independent program evaluator.
2.6.1.4 M&V is conducted by an
Y
independent party
2.6.1.5 Review of M&V is done in a
Y
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
b
2.7.1 EE delivery structure has been Currently being addressed through utility
established applications. Appears to be primarily utility
administered and implemented. 2008
amendments to the Efficient Use of Energy
Y
Act allows the PRC to require utilities to
solicit
competitive bids from third party contractors
2.7 for energy efficiency services.
U
2.7
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration;
or (c) government agency
Resource plans are regularly updated
Y NMAC 17.7.3.9 requires utilities to file IRPs
2.8 every 3 years.
R http://www.nmcpr.state.nm.us/NMAC/parts/ti
2.9.1 Building Energy Codes for residential 2006 IECC mandatory statewide. REScheck
buildings are in place and regularly updated can be used to show compliance. Typically
Y/Y
updated every 3 years. Last updated as of
7/1/08.
http://bcap-energy.org/node/85
2.9 2.9.2 Building Energy Codes for ASHRAE 90.1-2004 mandatory statewide.
commercial buildings are in place and COMcheck can be used to show
regularly updated compliance. Typically updated every 3
Y/Y
years. Last updated as of 7/1/08.
http://bcap-energy.org/node/85
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10 updated
Energy efficiency is a high priority in state However, unclear how many buildings have
buildings and state funded buildings as complied with the EO.
Y
evidenced in capital planning and enabling
2.11 performance contracts
http://www.governor.state.nm.us/orders/200
EO
6/EO_2006_001.pdf
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y-
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
Y
3.1 high-priority resource. (See Guide Tab for
Y/N criteria.)
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75% of state access to ENERGY STAR
Y
3.2 New Homes
What proportion is due to regulated utility Public Service Company of New Mexico
program? (who is sponsor) Performance
75% of state access to Home (PNM), Texas New Mexico Power Company
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists New Mexico Statutes, Chapter 62-17-6.
establishes that expenses for cost-effective
efficiency programs should be recovered via
a rider. The initial rider was capped at 1.5%
unless certain conditions were met. 2007
amendment have removed the 1.5% cap
Y
and now allow the Commission to establish
the rider. The actual amount of efficiency
spending is determined via annual DSM
plans submitted by the utilities and
approved by the PRC.
http://www.conwaygreene.com/nmsu/lpext.dl
l?f=templates&fn=main-hit-h.htm&2.0
NMAC 17.7.2.12 requires utilities to propose
4.1 tariff riders to fund efficiency activities
requires by the Efficient Use of Energy Act
http://www.nmcpr.state.nm.us/NMAC/_title17
/T17C007.htm
The amendment to the Act (SB 418 of the
2007 session) is available at
http://legis.state.nm.us/Sessions/07%20Reg
ular/final/SB0418.pdf
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits a
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently See 4.1.1 above
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support N
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is New Mexico Statutes, Chapter 62-17-5
addressed and disincentives are removed requires the Commission to identify and
remove any finanical barriers to energy
efficiency procurement by utilities.
Rulemaking in Case No 08-24-UT will
consider the changes required by passage
of HB305 in 2007. HB305 adopted in 2008
N requires the commission to “provide public
utilities an opportunity to earn a profit on
cost-effective energy efficiency and load
management resource development that,
with satisfactory program performance, is
financially more attractive to the utility than
supply-side resources."
NMAC 17.7.2.9 requires utilities to identify
5.1 any barriers or disincentives and propose
mechanisms to eliminate any
disincentives.http://www.nmcpr.state.nm.us/
NMAC/parts/title17/17.007.0002.htm
New Mexico Statutes 62-17-7 allow the use
of an alternative efficiency provider. NMAC
17.7.2.15 allows the use of a third party
administrator to assume a utility or utilities'
obligation to provide efficiency. Such an
arrangement would be done with the
consent of all involved utilities and by
Commission approval.
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE incentives are Amendments to the 2005 Efficient Use of
provided Energy Act allows the Commission to to
N provide financial incentives to make utility
procurement of energy efficiency profitable
for utilities.
5.2 http://legis.state.nm.us/Sessions/07%20Reg
ular/final/SB0418.pdf
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
N
when designing retail rates
5.3 5.3.2 Declining block rates and fixed One utility has inclining rates, the others
variable rate designs have been eliminated N have flat rates
U according to EEI
5.4.1 Time sensitive rates in place Some IOUs have TOU rates in place but the
Y-
program varies based upon utility
5.4
U according to EEI
5.4.2 Usage sensitive rates in place One utility has inclining rates, the others
Y-
have flat rates
5.4 U according to EEI
5.4.3 AMI deployment planned N
according to FERC filings
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for SB 35 would have provided an income tax
energy efficient products credit for the purchase of certain energy-
N
- efficient appliances and HVAC systems.
The bill stalled in committee.
Investment Tax Credit for energy efficient
investments SB 463, enacted in April 2007, established a
personal tax credit and a corporate tax
credit for sustainable buildings in New
Mexico. The tax credits apply to both
commercial and residential buildings.
Commercial buildings which have been
registered and certified by the US Green
Y
Building Council at LEED* Silver or higher
for new construction (NC), existing buildings
(EB), core and shell (CS), or commercial
- interiors (CI) are eligible for a tax credit. The
amount of the credit varies according to the
square footage of the building and the level
of certification achieved, as indicated on the
following chart:
See statute 7-2A-21
http://www.conwaygreene.com/nmsu/lpext.dl
S
l/nmsa1978/9a3/493d/501a/5119?fn=docum
ent-frame.htm&f=templates&2.0
http://www.dsireusa.org/incentives/incentive.
cfm?Incentive_Code=NM16F&re=0&ee=1
State supported low cost financing for
energy efficient investments: buildings (x), New Mexico's Energy Efficiency and
equipment (y) Renewable Energy Bonding Act, which
became law in April 2005, authorizes up to
$20 million in bonds to finance energy
efficiency and renewable energy
improvements in state government and
school district buildings. At the request of a
state agency or school district, the New
Mexico Energy, Minerals and Natural
Resources Department will conduct an
energy assessment of a building to
determine specific efficiency measures
Y which will result in energy and cost savings.
x,y A state agency or school district may install
or enter into contracts for the installation of
energy efficiency measures on the building
identified in the assessment. An installation
- contract may be entered into for a term of
up to 10 years. The bonds are exempt from
taxation by the state, and any type of
renewable energy system and most energy
efficiency measures, including energy
recovery and combined heat and power
(CHP) systems, are eligible for funding.
Projects financed with the bonds will be paid
back to the bonding authority using the
savings on energy bills.
See Article 21D
http://www.conwaygreene.com/nmsu/lpext.dl
S
l/nmsa1978/9a3/3c10/44f7?fn=document-
frame.htm&f=templates&2.0
http://www.dsireusa.org/incentives/incentive.
cfm?Incentive_Code=NM07F&re=0&ee=1
New or reorganized energy policy agency
Distributed Generation Policies
A statewide interconnection policy is in place In July 2008 the New Mexico Public
Regulation Commission adopted Rule 568
and Rule 569 which govern
interconnection. Rule 569 applies to all
qualifying facilities (QFs) under PURPA,
which generally includes all renewable-
energy systems and combined-heat-and-
power (CHP) systems from 10 megawatts
(MW) up to 80 MW in capacity. Rule 568
applies to renewable-energy systems and
CHP systems up to 10 MW in capacity.
There are four levels of review. Systems up
to 10 kilowatts (kW) in capacity are eligible
for the "Simplified Interconnection Process,"
Y+ which includes simplified applications.
Systems greater than 10 kW and up to 2
MW are eligible for the "Fast Track
7.1 Process," which might include supplemental
review. Systems greater than 2 MW and up
to 10 MW must follow the "Full
Interconnection Study Process." Systems
greater than 10 MW must follow the "Case
Specific Study Process." The application
fees vary according to size. Systems up to
10 kW must pay $50; systems greater than
10 kW and up to 100 kW must pay $100;
and systems greater 100 kW must pay $100
plus $1 per kW. In addition to these fees, a
small utility with fewer than 50,000
Rule 568 can be accessed here:
http://www.dsireusa.org/documents/Incentive
s/NM16Ra.htm and Rule 569 is located
A
here:
http://www.dsireusa.org/documents/Incentive
s/NM16Rb.htm
A statewide net metering policy is in place New Mexico has a statewide net metering
policy available to systems up to 80 MW in
capacity. All utilities regulated by the PRC
must offer net metering. Net metering is
available to all PURPA QF, which includes
renewables and CHP systems. NEG is
credited or paid to customers at the utility's
avoided cost rate. There is no limit on
Y
overall enrollment of net metered systems.
If a customer has NEG worth less than $50
7.2 during a monthly billing period, then the
excess will be carried forward to the next
month, otherwise if NEG exceeds $50 then
the utility will pay the customer during the
next billing month.
7.2
The most recent rules related to net
metering, 17.9.570 NMAC, can be accessed
A from here,
http://www.nmcpr.state.nm.us/NMAC/parts/ti
tle17/17.009.0570.htm.
A statewide exit fee policy is in place
7.3
A statewide standby rate policy is in place New Mexico does not have a statewide
N
policy on standby rates
Public Service Co of NM - Rate 12 - standby
service is available to QFs that contract for
a specified amount of standby capacity.
There is a high customer charge assessed
every month. Actual usage is charged
through a high demand charge and
U- moderate energy charges. Billing demand
is based on the higher of the maximum on-
peak demand of the month or 50% of the
maximum from the previous 11 months.
Rate available at:
http://www.pnm.com/regulatory/electricity_le
gacy.htm
7.4
Southwestern Public Service Co (Xcel
Energy) - standby service is available to
QFs that contract for a specified amount of
standby capacity. There is a high customer
charge and a moderate demand based
reservation fee that are assessed every
month. Actual usage is charged through a
U- moderate demand and energy rate. Billing
demand is based on the higher of the
maximum 30 minute demand of the month
or 60% of the maximum from the previous
11 months. Rate available at:
http://www.xcelenergy.com/Company/About_
Energy_and_Rates/Energy%20Prices%20(R
ates%20and%20Tariffs)/Pages/NMEnergy_
Rates.aspx
As part of resource planning process, CHP New Mexico's IRP rules are outlined in
is reviewed and incorporated where effective Chapter 62-17-10 of the state statutes.
Y
Utilities must assess distributed generation.
Chapter 62-17-10 can be looked up at
http://www.conwaygreene.com/nmsu/lpext.dl
l?f=templates&fn=main-hit-h.htm&2.0
7.5
Public Service Co of NM issued an IRP in
7.5 September 2008 for the 2008-2017 period.
U+
CHP technologies are not specifically
identified as a resource option in the IRP,
but may be assessed in future IRPs.
http://www.pnm.com/regulatory/irp_electric.htm
Southwestern Public Service Co (Xcel
Energy) considers CHP technologies in its
U+ IRP. The next IRP will be submitted to the
New Mexico Public Regulation Commission
by Mid-July 2009.
http://www.xcelenergy.com/Company/About_Energy_and_Rates/Resource%20and%20Renewable%20Energy%20Plans/Pages/New_
Natural Gas
urce.
The New Mexico Efficient Use of Energy Act
requires demand and supply side resources to be
evaluated consistently in the IRP process. The
Act also requires the Commission to ensure that
supply and demand options are financially neutral
to utilities. The 2008 amendments also direct the
PRC to provide utilities an opportunity to earn a
profit on investments in cost-effective energy
efficiency and load management resources.
Y
R
S
New Mexico Statutes, Chapter 62-17-10 requires
utilities to conduct IRP and evaulate supply and
Y demand side resources on a consistent and
comparable basis.
IRP statute may be looked up from
S http://www.conwaygreene.com/nmsu/lpext.dll?f=te
mplates&fn=main-hit-h.htm&2.0
The PUC promulgated IRP rules in April 2007.
The rules are available at
R
http://www.nmcpr.state.nm.us/NMAC/_title17/T17
C007.htm
effective energy efficiency as a resource
New Mexico Statutes, Chapter 62-17-2
establishes efficiency as an essential component
of utility resource portfolios.
Y
http://www.conwaygreene.com/nmsu/lpext.dll?f=te
S
mplates&fn=main-hit-h.htm&2.0
New Mexico Statutes, Chapter 62-17-5 requires
Y use of the TRC test.
S see 2.1 above
Y
New Mexico Statutes 62-17-8 requires utilities to
submit an annual M&V report prepared by an
independent third party and conforming to any
specifications that the Commission should
establish.
Y
http://www.nmcpr.state.nm.us/NMAC/parts/title17/
S
17.007.0002.htm
Y NMAC 17.7.4.9 requires gas utilities to file IRPs
every 4 years.
R http://www.nmcpr.state.nm.us/NMAC/parts/title17/
Y-
deliver energy efficiency where cost-effective.
New Mexico Statutes, Chapter 62-17-6.
establishes that expenses for cost-effective
efficiency programs should be recovered via a
rider. The initial rider was capped at 1.5% unless
certain conditions were met. 2007 amendment
have removed the 1.5% cap and now allow the
Y
Commission to establish the rider. The actual
amount of efficiency spending is likely to depend
on the results of the IRP analysis and approval
process.
http://www.conwaygreene.com/nmsu/lpext.dll?f=te
mplates&fn=main-hit-h.htm&2.0
http://www.nmcpr.state.nm.us/NMAC/_title17/T17
C007.htm
cost-effective energy efficiency and modify ratemaking
PNM filed for a gas decoupling mechanism in
Case 06-00210-UT. The Commission rejected the
decoupling mechanism in June 2007 but stated
that PNM would be encouraged to request a
better-designed decoupling proposal in the future.
New Mexico Statutes, Chapter 62-17-5 applies to
gas as well as electric utilities; Rulemaking in
N Case No. 08-24-UT also applies to gas; see
entries under electric.
http://www.pnmresources.com/press/docs/2007/0
702_prc_order_pnm_gas.pdf
Amendments to the 2005 Efficienct Use of Energy
Act allows the Commission to use incentives to
N make utility procurement of energy efficiency
financially neutral.
http://legis.state.nm.us/Sessions/07%20Regular/fi
nal/SB0418.pdf
NEVADA
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority EE is included in IRP planning but is not
resource, equivalent or superior to supply N equivalent or superior to supply resources.
1.1 resources
1.2.1 EE is integrated into an active IRP, Nevada Revised Statutes 704.741 require
portfolio management, or other planning an IRP process. Rules regarding DSM are
Y-
process detailed in Nevada's administrative code.
See http://www.leg.state.nv.us/NRS/NRS-
704.html#NRS704Sec741at
NRS 704.741 is available
S http://www.leg.state.nv.us/NRS/NRS-
704.html#NRS704Sec741
1.2 Nevada Administrative Code 704.934
contains specific requirements for DSM
R
analysis in the IRP. See
http://www.leg.state.nv.us/NAC/NAC-
704.html#NAC704Sec9523
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers N
EE is an alternative to transmission based
on a long-term transparent IRP or N
1.3 transmission system plan
1.4.1 EE is a biddable commodity N
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides see 2009 notes
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute NRS 702 codified the universal service
Y charge which calls for some portion to be
spent towards EE.
2.1
http://www.leg.state.nv.us/71st/bills/AB/AB66
S 1_EN.html or
http://leg.state.nv.us/NRS/NRS-702.html
Supply and demand resource analyses for
utility resource plans must include present
worth of societal costs and future revenue
Y requirements (utility cost) as well as net
The TRC or Societal Cost Test is used to economic benefits and envirnomental costs
evaluate EE programs to the State.
2.2
2.2
Nevada Administrative Code 704.934
through 704.937 contains specific
R
requirements for DSM analysis in the IRP.
See http://www.leg.state.nv.us/NAC/NAC-
704.html#NAC704Sec934 et seq.
2.3.1 Potential for cost-effective EE has
been established through a potential study N
2.3.2 Established EE programs reach all NAC 704.800 specifies that utilities are
2.3 customer classes required to annually inform customers (via
Y announcements in bills) about available
energy savings programs and the costs and
procedures involved.
http://www.leg.state.nv.us/NAC/NAC-
R
704.html#NAC704Sec800
Funding requirements for all long-term, cost-
N
2.4 effective EE have been established
2.5.1 Quantitative MW and MWh savings
goals have been established and are N
producing incremental investment.
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
b
system; (c) as part of program approval and
budget-setting process; (d) other
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar Nevada Revised Statutes, 704.7803-
standard 704.78215 allows efficiency to supply up to
2.5 25% of the re-named clean energy portfolio
standard. The clean energy portfolio
Y
standard is equal to 9% of electricity supply
in 2007-08, increasing to 20% in 2015. At
least half of the energy savings credits must
come from electricity savings in the
residential sector.
http://www.leg.state.nv.us/NRS/NRS-
S
704.html#NRS704Sec701
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been Electric IRPs are filed every 3 years.
established Further, the utility required to file an annual
DSM status report every August. Further, if
participating in energy efficiency programs
Y natural gas energy efficiency and
conservation plan are required to be filed
every three years with a annual update.
(LCB File Number R095-08)
Sierra Pacific Docket no. 06-04018, and
Nevada Power docket no. 06-03038.
U
NOTE: nothing filed in 2008 for either utility
http://leg.state.nv.us/register/2008Register/R
R
095-08I.pdf
2.6.1.1 M&V is adequately funded Y Funded as part of the IRP process
2.6.1.2 Energy savings are used to one of the measures
Y
2.6 measure performance
2.6.1.3 M&V is done according to a
defined schedule
2.6.1.4 M&V is conducted by an
Y
independent party
2.6.1.5 Review of M&V is done in a NAC 704.9522 requires the electric utility to
transparent process comply with the recent M&V protocol
Y
approved by the Commission at the time the
EE measure is implemented.
http://leg.state.nv.us/NAC/NAC-
S
704.html#NAC704Sec9522
2.6.2 M&V is done using: (a) deemed unique protocol for each measure
savings; (b) actual savings; (c) other
a,b,c
2.7.1 EE delivery structure has been
established The utility companies collect a EE system
benefits charge and administer the
programs with oversight by the PUCN. The
companies propose a budget and program
Y plan to the PUCN as part of energy
efficiency and conservation plan
requirements. The utilities must have their
2.7 program plans and budgets approved by the
PUCN prior to implementation. (LCB File
Number R095-08)
http://leg.state.nv.us/register/2008Register/R
S
095-08I.pdf
2.7
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated See 1.2.1 above
Y
2.8
2.9.1 Building Energy Codes for residential 2003 IECC code mandatory where local
buildings are in place and regularly updated code does not exist. Jurisdictions in
Southern Nevada have adopted the 2006
Y/Y Southern Nevada Energy Code, which is
based on the 2006 IECC with amendments.
Jurisdictions in Northern Nevada have
adopted the 2006 IECC.
http://bcap-energy.org/node/81
U
2.9 2.9.2 Building Energy Codes for
commercial buildings are in place and 2003 IECC mandatory for all jurisdictions
regularly updated that have not adopted an energy code; can
use COMcheck to show compliance.
Y/Y Jurisdictions in southern Nevada have
adopted the 2006 Southern Nevada Energy
Code, which is based on the 2006 IECC
with amendments. Jurisdictions in Northern
Nevada have adopted the 2006 IECC.
U http://bcap-energy.org/node/81
Appliance and Equipment Efficiency Legislation passed in 2007 (Assembly bill
Standards are in place and regularly 178) effectively bans incandescent lights,
Y
2.10 updated starting in 2012. No regulations in effect.
Energy efficiency is a high priority in state
buildings and state funded buildings as NRS Title 58, Chapter 701 directs the
evidenced in capital planning and enabling Director of the Office of Energy to develop a
performance contracts state energy reduction plan requiring state
agencies to reduce grid-based energy
purchases for state-owned buildings by 20%
by 2015. It also requires the Director to
Y-
adopt guidelines establishing a Green
2.11 Building Standards for all occupied public
buildings whose construction will be
sponsored or financed by the State or a
local government. Note that a Bill to require
green bldg standards for some state bldgs
was repealed in 2007.
http://leg.state.nv.us/nrs/NRS-
S
701.html#NRS701Sec200
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y-
see utility resource plans 2.6.1
3.1.2 Process is in place, such as a state DSM statewide collaborative process in
or regional collaborative, to pursue EE as a place for regulated utilities
Y
high-priority resource. (See Guide Tab for
3.1 Y/N criteria.)
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75% of state access to ENERGY STAR
Y
3.2 New Homes
What proportion is due to regulated utility State of Nevada, Housing Division
program? (who is sponsor) Performance
75% of state access to Home
with ENERGY STAR? Y
What proportion is due to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists
NRS 704.751 states that all reasonable and
Y
prudent expenditures in carrying out a
utility's IRP shall be recovered from
ratepayers.
S
http://www.leg.state.nv.us/NRS/NRS-
704.html#NRS704Sec741
4.1 Utility can capitalize DSM expenses???
R
4.1.2 Recovery occurs via: (a) rider; (b) EE costs are recovered through regular rate
regular rate case; or (c) system benefits b case
charge
4.1.3 Funding is for multi-year periods Programs are approved with estimated
budget but utilities must justify all costs in
N
rate cases in order to receive approval for
funds previously spent.
A base energy efficiency spending level
exists, with opportunity to justify higher level Y
4.2
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is Currently, NAC 704.9523 allows the utility to
addressed and disincentives are removed earn a 5% equity adder on EE investment.
Y
5.1
NAC 704.9523 3(e)(4):
R
http://www.leg.state.nv.us/register/2007Regi
ster/R162-07RP1.pdf
5.1.2 Method used is: (a) decoupling; (b) see 5.1.1 above
lost revenue recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE incentives are Nevada allows a bonus rate of return for
provided DSM investments 5% higher than
authorized rates of return on equity for
Y
supply investments, designed to make up
for lost revenues. Decoupling NOT in place
or under consideration.
Nevada Administrative Code 704.9523. See
5.2 S http://www.leg.state.nv.us/NAC/NAC-
704.html#NAC704Sec9523
NAC 704.9484, available at
S http://www.leg.state.nv.us/NAC/NAC-
704.html#NAC704Sec9484
5.2.2 Incentives exceed amount of lost Incentives amount independent of lost
revenues revenue amount.
5.3.1 Impact on EE is a consideration
N
when designing retail rates
5.3 5.3.2 Declining block rates and fixed fixed rate regardless of amount of
variable rate designs have been eliminated N consumption
5.4.1 Time sensitive rates in place Y-
5.4
residential:
www.nvenergy.com/home/paymentbilling/tim
R eofuse.cfm business:
www.nvenergy.com/business/paymentbilling/
timeofuse.cfm
5.4 5.4.2 Usage sensitive rates in place N
5.4.3 AMI deployment planned Y+
R
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
N
- energy efficient products
Investment Tax Credit for energy efficient AB 621 requires a property tax abatement
investments Y for bldgs that are LEED silver certified or
better.
-
S http://www.dsireusa.org/incentives/incentive.
cfm?Incentive_Code=NV10F&re=0&ee=1
State supported low cost financing for
energy efficient investments: buildings (x), N
equipment (y)
-
New or reorganized energy policy agency N
Distributed Generation Policies
A statewide interconnection policy is in place The NV PUC adopted interconnection
standards for customers of Nevada Power
and Sierra Power in 2003. On-site
generators using solar thermal electric,
photovoltaics, wind, biomass, and
geothermal energy, generating up to 20 MW
in capacity are eligible to interconnect. NV's
Y+
7.1 standards are similar to IEEE 1547
standards, CA's interconnection Rule 21
and the model interconnection rule
established by NARUC. Additional
insurance requirements are not specified
and an external disconnect is not required.
A statewide net metering policy is in place Nevada has a net metering law enacted in
1997 and amended in 2001, 2003, 2005
and 2007. Systems up to 1 MW in capacity
that generate electricity using solar, wind,
geothermal, biomass and certain types of
hydropower are generally eligible. However,
systems greater than 100 kW may be
subject to extra costs. Each IOU must offer
net metering until the aggregate capacity of
Y all net-metered systems in its service
territory equals 1% of the utility's peak
7.2 capacity. NWG is carried forward to over to
the next month as a kWh credit, without any
expiration date. Legislation passed in 2007,
A.B. 178, requires the Nevada Public
Utilities Commission (PUC) to adopt
regulations that outline a standard contract
for net metering along with a net-metering
tariff.
NAC 704.8901 et seq. can be accessed
from here,
A
http://www.leg.state.nv.us/nac/NAC-
704.html#NAC704Sec8901
A statewide exit fee policy is in place The NV PUC does allow for DG systems to
7.3 Y-
be charged an exit fee.
A statewide standby rate policy is in place Nevada does not have a statewide policy on
N
standby rates
Sierra Pacific Power Co - standby service is
provided to customers that contract for a
specified amount of standby capacity. A
moderate customer charge and high
- demand based reservation charge is
U assessed every month. Actual usage is
charged through high energy charges. Rate
available at:
http://www.sierrapacific.com/rates/nv/electric
/schedules/
7.4
Nevada Power Company - Schedule LSR -
standby service is provided to customers
that contract for a specified amount of
standby capacity. A moderate customer
charge and moderate demand based
reservation charge are assessed every
U
month. Actual usage is charged through a
moderate demand charge and moderate
energy charges. Billing demand is based on
the maximum demand of the month. Rate
avaialable at:
http://www.nevadapower.com/rates/tariffs/sc
hedules/
As part of resource planning process, CHP Details regarding resource plan
is reviewed and incorporated where effective requirements can be found in the NV
administrative code, 704.925. Utilities must
forecast energy consumption and peak
demand. The regulations state that "The
utility shall consider the impact of distributed
generation and customers who acquire
energy" from either - 1) those that sell
electricity who are not subject to the
Y
jurisdiction of the Public Utilities
Commission of Nevada, tariff for distribution
service (i.e., Colorado River Commission of
Nevada)(see NRS 704.787); or 2) who are
considered to be new providers of electric
services (see chapter 704B). Currently
docket # 08-02037 is open to consider
7.5 revisions to the resource planning process.
http://www.leg.state.nv.us/NAC/NAC-
S
704.html#NAC704Sec925
Sierra Pacific Power Co uses the same
general IRP requirements as Nevada Power
U (see below). Nevada Power and Sierra
Pacific Power are owned by Sierra Pacific
Resource Company.
Nevada Power Co is a Sierra Pacific
Resources Company. Nevada Power
addresses energy efficiency (EE) in its IRP
U
and has numerous EE incentive programs,
but does not specifically address CHP.
http://www.swenergy.org/news/2008-03-NPC_DSM_Amendments.pdf
Natural Gas
urce.
No IRP planning required
N
NRS 704.991 requires an informal resource
planning process, but the statute does not specify
N
any consideration of DSM.
http://www.leg.state.nv.us/NRS/NRS-
704.html#NRS704Sec991
NAC 704.9655 addresses the role of DSM in gas
utility resource plans. Effects of DSM must be
included in demand forecasts, and potential
R
programs analyzed.
http://www.leg.state.nv.us/NAC/NAC-
704.html#NAC704Sec9655
effective energy efficiency as a resource
NRS 702 codified the universal service charge
Y which calls for some portion to be spent towards
EE.
http://www.leg.state.nv.us/71st/bills/AB/AB661_EN
.html or http://leg.state.nv.us/NRS/NRS-702.html
Supply and demand resource analyses for utility
resource plans must include present worth of
societal costs and future revenue requirements
Y (utility cost) as well as net economic benefits and
envirnomental costs to the State.
R
same as decoupling reg???
N
NAC 704.800 specifies that utilities are required
to annually inform customers (via announcements
Y in bills) about available energy savings programs
and the costs and procedures involved.
http://www.leg.state.nv.us/NAC/NAC-
R
704.html#NAC704Sec800
N
N
deliver energy efficiency where cost-effective.
LCB File Nos. R095-08 and T004-08 allow the
natural gas utility to recover all reasonable and
prudent costs in carrying our a energy efficiency
Y
and conservation plan. Decoupling is an option to
remove financial disincentives for encouraging
conservation.
http://leg.state.nv.us/register/2008Register/R095-
08I.pdf and
S
http://leg.state.nv.us/register/2008TempRegister/T
004-08RP.pdf
EE costs are recovered through a regular rate
b case. If decoupling is authorized, revenue
reductions are recovered as a rider.
LCB File No. R095-08 allows the gas utility to
propose an amendment to its tri-annual plan in
the annual report process.
cost-effective energy efficiency and modify ratemaking
LCB File Nos. R095-08 allows a natural gas utility
to earn a 5% equity adder on its EE investment
and T004-08 allow the natural gas to request
decoupling rather than the 5% incentive.4. In
2007, the legislature passed SB437 requiring the
PUCN to decouple profits from sales for natural
Y
gas utilities, codified as NRS 704.992. The
PUCN subsequently adopted regulations in 2008
implementing that law. The regulations require
that a DSM plan must be submitted and approved
before decoupling can be authorized in a rate
case.
http://leg.state.nv.us/register/2008Register/R095-
08I.pdf and
http://leg.state.nv.us/register/2008TempRegister/T
004-08RP.pdf
see 5.1.1 above
Legislation passed in 2007 (SB 437) requires the
PUC to adopt regulations removing the financial
disincentives to EE for natural gas utilities.
see 5.1.1 above
If utilities choose decoupling it includes lost
revenues.
N
OREGON
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority
resource, equivalent or superior to Y+
1.1 supply resources
1.2.1 EE is integrated into an active
IRP, portfolio management, or other
Y+
planning process
1.2
1.2.2 Efficiency is procured as a
resource for default service/standard
offer customers
N
EE is an alternative to transmission
based on a long-term transparent
IRP or transmission system plan N
1.3
1.4.1 EE is a biddable commodity
Y-
1.4
1.4.2 Bids occur in the following
markets: (a) energy, (b) capacity, or
(c) other
State Implementation Plans (SIPs)
N
1.5 include EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute
2.1 Y
The TRC or Societal Cost Test is
2.2 used to evaluate EE programs Y+
2.3.1 Potential for cost-effective EE
has been established through a Y
potential study
2.3
2.3.2 Established EE programs
reach all customer classes Y-
Funding requirements for all long-
term, cost-effective EE have been
established
Y
2.4
2.5.1 Quantitative MW and MWh
savings goals have been established
and are producing incremental
investment.
Y+
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or
a,c,d
similar system; (c) as part of program
approval and budget-setting process;
(d) other
2.5 2.5.3 Energy Efficiency can be used
to fulfill requirements of an RPS or
similar standard
Y
2.5.4 Expected Capacity Savings
(Annual MW)
2.5.5 Energy Savings Goals (Annual
MWh or MTherms)
281,371
2.6.1 A robust M&V process has
been established
Y
2.6.1.1 M&V is adequately funded Y
2.6.1.2 Energy savings are used to
Y
measure performance
2.6.1.3 M&V is done according to a
Y
defined schedule
2.6.1.4 M&V is conducted by an
2.6 independent party
Y
2.6.1.5 Review of M&V is done in a
Y
transparent process
2.6.2 M&V is done using: (a)
deemed savings; (b) actual savings;
a,b
(c) other
2.7.1 EE delivery structure has been
established
Y
2.7
2.7
2.7.2 Delivery is via: (a) utility
administration; (b) third-party a,b
administration; or (c) government
agency
Resource plans are regularly updated
2.8 Y
2.9.1 Building Energy Codes for
residential buildings are in place and Y
regularly updated
2.9 2.9.2 Building Energy Codes for
commercial buildings are in place
and regularly updated
Y
Appliance and Equipment Efficiency
Standards are in place and regularly
Y
2.10 updated
Energy efficiency is a high priority in
state buildings and state funded
buildings as evidenced in capital
2.11 planning and enabling performance Y
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on Y-
EE are in place. (See Guide Tab for
3.1.2 Process is in place, such as a
state or regional collaborative, to
pursue EE as a high-priority
resource. (See Guide Tab for Y/N
criteria.)
Y
3.1
3.1
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Do not delete this row.
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75% of state access to ENERGY
Y
3.2 STAR New Homes
What proportion is due to regulated
utilityof state access to Home
75% program? (who is sponsor)
Performance with ENERGY STAR? N
What proportion is ue to regulated
utility program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists
Y
4.1
4.1
4.1.2 Recovery occurs via: (a) rider;
(b) regular rate case; or (c) system a,c
benefits charge
4.1.3 Funding is for multi-year
Y
periods
A base energy efficiency spending Y
4.2 level exists, with opportunity to justify
% of net (retail) utility revenue
presently used for energy efficiency Changed
[no unit = %; m/k = mils/kWh] in 2008
4.3
Funds from carbon trading program N/A
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is
addressed and disincentives are
removed
Y
5.1
5.1
5.1.2 Method used is: (a)
decoupling; (b) lost revenue
b,c
recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE
incentives are provided
N
5.2
5.2.2 Incentives exceed amount of
lost revenues
5.3.1 Impact on EE is a
consideration when designing retail
rates Y
5.3
5.3
5.3.2 Declining block rates and fixed
variable rate designs have been Y
eliminated
5.4.1 Time sensitive rates in place
Y
5.4.2 Usage sensitive rates in place
Y
5.4.3 AMI deployment planned
5.4
Y
5.4.4 Other mechanisms exist (e.g.,
on-bill financing, benefit sharing) N
State Fiscal Policy
Sales Tax reduction or exemption for N/A
- energy efficient products
Investment Tax Credit for energy
efficient investments
Y
-
-
State supported low cost financing x, y
for energy efficient investments:
buildings (x), equipment (y)
-
Distributed Generation Policies
A statewide interconnection policy is
in place
Y+
7.1
S
A
A statewide net metering policy is in
place
Y+
7.2
A
A statewide exit fee policy is in place
N
7.3
A statewide standby rate policy is in
N
place
U
7.4
U+
As part of resource planning process,
CHP is reviewed and incorporated
where effective
Y+
7.5
U
http://www.pacificorp.com/Navigation/Navigation23807.html
U+
http://www.portlandgeneral.com/about_pge/current_issues/energy_strategy/2007_irp.aspx
OREGON
Electric Natural Gas
y efficiency as a high priority energy resource.
Federal Northwest Power Act requires
conservation first (10% cost-effectiveness adder). Y+
In 1989, the Oregon Commission required
regulated required under PUC Orderand demand
IRPs first utilities to evaluate supply 89-507.
IRP has been required since 1989. Updated IRP
guidelines were issued in 2007. Utilities must
Y+
evaluate all known demand-side resources as part
of the planning process.
http://apps.puc.state.or.us/orders/2007ords/07-
002.pdf (corrected by Order 07-047:
http://apps.puc.state.or.us/orders/2007ords/07-
047.pdf)
Updated IRP guidelines state the utility should not
plan for loads "effectively committed to service" by
an alternative electricity supplier. However, the
customer is considered to be effectively committed
to such service only during the term of the option
(e.g., one year or three years).
The Commission has identified transmission as a
priority issue and has previously expressed
interest in developing rules guiding the use of non-
wires solutions to address distribution and
transmission system constraints.
Utilities may issue all-source or resource (including
DSM)-specific RFPs, although in practice DSM
resources are identified in the IRP process and by
the Energy Trust of Oregon and are procured
separately from supply. The Energy Trust issues
RFPs for its programs.
ng-term commitment to implement cost-effective energy efficiency as a resource
ORS 757.056: All public utilities . . . shall establish
energy conservation services.
http://www.leg.state.or.us/ors/757.html
The Energy Trust uses the Utility System Test and
the Societal Cost Test to evaluate programs.
Y+
http://www.energytrust.org/meetings/board/2008/08
0213/06b_CostEff.pdf (Quick links to all Energy
Updated IRP guidelines (2007) require utilities to
ensure a potential study is conducted periodically. Y
(Utility or Energy Trust may conduct it.)
http://apps.puc.state.or.us/orders/2007ords/07-
002.pdf
Large customers can opt out of Energy Trust
programs and self-direct a portion of the Y-
conservation funds to on-site efficiency projects, if
the project is approved by the Oregon Department
Oregon statute established a public purpose
charge and allows, but does not require, funding
for all incremental cost-effective conservation.
Customers over 1 MWa are exempt from paying
incremental EE charges and from receiving
Y
benefits from incremental funding. Commission
IRP policy requires utilities to include in their IRP
action plans all best cost/risk portfolio conservation
resources for meeting
projected resource needs, specifying annual
savings targets.
The Energy Trust proposes annual performance
benchmarks for the Commission's approval and
sets long-term energy-savings goals. Under SB
838 (RPS bill passed in 2007), PGE and Pacific
Y+
Power can file (and have filed) tariffs to include in
rates funding for cost-effective efficiency
incremental to what can be achieved through the
public purpose charge.
http://apps.puc.state.or.us/orders/2008ords/08-
529.pdf
The utility IRP process, Energy Trust planning and
budget-setting processes, and utility tariff filings for
incremental efficiency funding (beyond the public
a,c
purpose charge) set energy savings goals
Alternative Compliance Payments (ACP) by
utilities can go to end-use efficiency, power plant
efficiency upgrades or eligible renewable energy
resources; ACP payments by alternative electricity
service suppliers fund conservation for their direct
access customers.
The Energy Trust of Oregon does not estimate
capacity savings. However, the utilities do in their
IRPs.
2006 = 25.5 average MW, or about 223,380
MWh; 2008 = 32.12 average megawatts, or about 2.6
281,371 MWh (Energy Trust goals for PacifiCorp million
and PGE)
http://www.energytrust.org/library/reports/2006_Ann
ual_Report.pdf;
http://www.energytrust.org/library/reports/2008_Ann
Statute requires independent review of the PPC to
develop recommendations for the legislature. A
report was released in 2006 that recommended
developing more consistent M&V procedures for Y
PPC funds. M&V is done by the ETO. The ETO
http://www.puc.state.or.us/PUC/electric_restruc/pur
pose/013007PPCModificationsFinal.pdf
Energy Trust conducts numerous M&V studies Y
http://www.energytrust.org/library/reports/db/report_
Y
Y
Most evaluations are conducted by third party
contractors. The Trust does some assembly and
cleaning of data sets in-house; contracting that out
has not been effective. The Trust evaluates some Y
pilot programs in-house because small-scale work
is too expensive to contract out. The Trust also
does some simple analysis in-house as a check on
consultant work.
The Trust's board evaluation committee reviews
Y
draft evaluations. The committee includes outside
Prescriptive measures have “deemed” estimates
and quality control and assurance to make sure
a,b
the correct equipment was installed properly.
Large complex mechanical projects have a
commissioning option, where the ETO pays part of
1999 restructuring act (SB 1149) established the
Energy Trust of Oregon, a third party non-profit
entity to deliver energy efficiency programs. The
ETO delivers programs on behalf of most of Y
Oregon's electric utilities. Idaho Power administers
Energy Trust delivers programs for PGE and
Pacific Power customers; Idaho Power delivers b
programs for its customers.
New IRPs must be filed within 2 years of
Commission acknowledgment of an IRP unless
Y
Commission grants waiver
Residential code is mandatory and updated every
3 years. Efficiency requirements in 2008 update Y
are as stringent as 2006 IECC and 15% more
http://bcap-energy.org/node/90
Non-residential code is mandatory and reviewed
every three years. 2007 code exceeds ASHRAE
2004.
Y
http://bcap-energy.org/node/90
Many of the appliance standards adopted in 2005
exceed federal standards. Standards phased in
from Jan. 1, 2007, to Jan. 1, 2009. See ORS
http://www.dsireusa.org/library/includes/incentive2.
cfm?Incentive_Code=OR19R&state=OR&CurrentP
ageID=1&RE=1&EE=1
HB 2620 (2007 Session) requires at least 1.5% of
contract price for public building construction or
major renovation to go toward solar water heating,
passive solar or PV. Executive Order No. 06-02
http://egov.oregon.gov/ENERGY/CONS/SEED/SEE
Dhome.shtml
licies
Y-
A Conservation Advisory Council advises the
Energy Trust of Oregon on electric and natural gas
programs. Oregon ratepayers also fund the
Northwest Energy Efficiency Alliance, a regional
group funding electric market transformation.
NEEA also has a broad advisory group. A
Northwest Energy Efficiency Taskforce was Y
recently formed to recommend actions to advance
energy efficiency in the region. The group
completed its draft report in December 2008. See
http://www.nwcouncil.org/energy/neet/Default.asp
Energy Trust of Oregon, Pacific Power
t, timely, and stable program funding to deliver energy efficiency where cost-effective.
SB 1149 (restructuring bill, 1999 Session)
instituted a 3% public purpose charge on utility
revenues, with about half the funds used for EE.
However, the bill also served as a cap on
efficiency expenditures. SB 838 (RPS bill, 2007
Session) allowed utilities to file tariffs for funding
additional cost-effective EE in base rates. The
Commission approved tariffs for both Pacific Y
Power (Advice No. 07-022, Schedule 297) and
PGE (Advice No. 07-25, Schedule 109) in 2008.
See
http://apps.puc.state.or.us/edockets/docket.asp?Do
cketID=14416 and
http://apps.puc.state.or.us/edockets/docket.asp?Do
cketID=14402
SB 838 is available at
http://www.leg.state.or.us/07reg/measpdf/sb0800.di
r/sb0838.en.pdf, with EE provisions beginning at p.
13.
SB 1149 is available at
http://www.energytrust.org/library/policies/sb1149.p
df
Statute requires the independent review of the
PPC to develop recommendations for the
Legislature. A report was released in 2006,
recommending the PPC be increased from 3% to
5%, recognizing that there are cost-effective EE
opportunities available beyond what the PPC can
fund. The report also recommended that the PPC
be reviewed every 5 years and adjusted as
necessary -- timed to coincide with utility IRP and
cost-effective potential assessments. See p. 5 at
http://www.puc.state.or.us/PUC/electric_restruc/pur
pose/013007PPCModificationsFinal.pdf
Rider for incremental funding; system benefit
charge for base funding a
Y
Y
Public purpose charge is 3% of revenues for PGE
and PacifiCorp. About 57% of the charge is used
for efficiency, or 1.7% of the bill. Tariffs for
incremental EE funding approved in 2008 for both
utilities amount to an additional 1% of revenues
SB 838 said no increasing PPC. But utilities can
file tariffs to include more funding in base rates.
align utility incentives with the delivery of cost-effective energy efficiency and modify ratemaking
SUMMARY: 1999 statute established a 3% public
purpose charge and authorized the creation of a
third party to administer efficiency programs. The
PUC helped establish the Energy Trust of Oregon
and executed a grant agreement in 2001 for
program administration. Lost revenue recovery is
Y+
allowed for Idaho Power.
1999 Oregon Legislative Session SB 1149
authorized the creation of a third party entity to
administer efficiency programs. See
http://www.energytrust.org/library/policies/sb1149.p
df
ORS 757.262: the Commission may establish
policies to protect utilities from short-term earnings
reductions due to DSM.
http://www.leg.state.or.us/ors/757.html
OAR 860-027-0310: Acquisition of least-cost
resources should be the energy utility's most
profitable course of action.
http://arcweb.sos.state.or.us/rules/OARS_800/OAR
_860/860_027.html
a,c
OAR 860-027-0310 allows utilities to request
approval of incentive programs. Enactment of a
public purpose charge in 1999 (effective March
2002) muted this issue. However, the 2007 RPS
law (SB 838) allows utilities to file tariffs to include
in rates funding for incremental energy efficiency.
The Commission opened a proceeding in 2002 to
address utilities' bias toward owning generating
facilities rather than buying power (Docket UM
N
1276). In Jan. 2008, staff filed a proposal for a pilot
incentive program for power purchase
agreements. The case does not address energy
efficiency incentives but if the Commission
approves the pilot proposal, it could inform such a
mechanism. Case documents at:
http://apps.puc.state.or.us/edockets/docket.asp?Do
cketID=13600
http://arcweb.sos.state.or.us/rules/OARS_800/OAR
_860/860_027.html
Inclining block rates are in place for the major
electric utilities in the state.
All customers of PGE and Pacific Power have a
time-varying rate option. Residential and small
nonresidential customers have a conventional time
of use rate option; all nonresidential customers
have a daily market pricing option. See ORS
757.601 and 757.603
(http://www.leg.state.or.us/ors/757.html). PGE
offers its largest customers a two-part real-time
pricing option.
Inclining block rates are in place for the major
electric utilities in the state.
The Commission approved full roll-out of
Advanced Metering Infrastructure (AMI) for
Portland General Electric. Includes customer
access to hourly usage information (on a daily
basis), a proposed critical peak pricing pilot for
residential customers, and proposed new demand
response programs for large customers. The
Commission also approved Idaho Power's request
for accelerated writeoff of equipment to be
replaced pursuant to its AMI project.
Order for PGE in Docket UE 189 (No. 08-245):
http://apps.puc.state.or.us/orders/2008ords/08-
245.pdf. Order for Idaho Power in UE 202 (008-
614):
http://apps.puc.state.or.us/orders/2008ords/08-
614.pdf.
N
Y
Oregon does not have a sales tax.
Tax credits are available to residents and
businesses for installing eligible efficiency
measures and renewable energy systems.
http://www.dsireusa.org/library/includes/incentive2.
cfm?Incentive_Code=OR17F&state=OR&CurrentP
ageID=1&RE=1&EE=1
Residential tax credits:
http://www.oregon.gov/ENERGY/CONS/RES/RET
C.shtml; business tax credits:
http://www.oregon.gov/ENERGY/CONS/BUS/BETC
.shtml
The State Energy Loan Program was enacted by
voters (in the Constitution) in 1980. It provides
fixed-rate, long-term loans for efficiency measures,
renewable energy systems, using alternative fuels
and using recycled materials to make new
products. The loans are available to any individual
or entity in the state.
http://www.oregon.gov/ENERGY/LOANS/selphm.s
html
The state’s net metering law, ORS 757.300,
requires all utilities in the state to interconnect
eligible net-metered systems up to 25 kW for all
types of customers. (This excludes Idaho Power,
which is required to offer net metering under
requirements promulgated in Idaho.) Eligible
system types are solar, wind, hydropower, fuel
cells and certain types of biomass resources. A
utility may not limit the cumulative capacity of net-
metered systems until they have reached 0.5% of
the utility’s historic single-hour peak load. The
Oregon Public Utility Commission can increase the
size limits and establish other rules for its primary
IOUs (PGE and PacifiCorp). In July 2007, the
Oregon PUC adopted interconnection standards
as part of a broader net metering rulemaking, OR
Admin. R. 860-039. Nonresidential customers of
the IOUs may interconnect net-metered systems
up to 2 MW. The rules did not revise the statutory
size limit on interconnection of net-metered
systems by residential customers (25 kW). The
ORS 757.300 is available here:
http://landru.leg.state.or.us/ors/757.html
Or. Admin. R. 860-039 can be accessed here:
http://arcweb.sos.state.or.us/rules/OARS_800/OAR
_860/860_039.html.
Oregon's net metering law (ORS 757.300) applies
to all electric utilities in the state. Residential
customers up to 25 kW and non-residential
customers up to 2 MW may net meter. The OPUC
can increase size limits for the two largest IOUs --
PGE and Pacific Power. Eligible resources are
wind, solar, hydro, biomass and fuel cell systems.
The utility can credit net excess generation (NEG)
in a billing month at its avoided cost rate or carry
forward the kWh credit to the customer's
subsequent bills in the annual billing cycle. Any
remaining NEG at the end of the annual billing
cycle may be treated in the following manner, as
determined by the Commission (for IOUs) or board
(for COUs): 1) credit the customer at the utility's
avoided cost rate; 2) grant the credit to the utility's
low-income assistance program; or 3) dedicate the
credit for another use as determined by the
Commission or board. For PGE and Pacific Power,
the Commission grants any remaining NEG at the
end of the annual billing cycle to low-income
assistance. A utility may limit aggregated capacity
of all net metered systems to 0.5% of its historic
single-hour peak load. However, PGE and Pacific
OR's net metering law (ORS 757.300) is at:
http://landru.leg.state.or.us/ors/757.html. OR's net
metering rules (OAR 860-039) are located here:
http://arcweb.sos.state.or.us/rules/OARS_800/OAR
_860/860_039.html
Oregon has no statewide policy on exit fees.
Utilities are not charging such fees to DG
owners/operators.
Oregon does not have a statewide policy on
standby rates.
PacifiCorp - Customers with self-generation under
1 MW receive standby service under standard rate
schedules. Customers whose generator has a
nameplate capacity of 1 MW or greater receive
basic partial requirements service under
Schedules 47 (delivery) and 247 (supply). The
monthly basic charge and energy charges are the
same as for full requirements customers. The
customer contract sets baseline demand and other
terms and conditions. Distribution and reserves
charges (to serve the customer's load when the
generator is not operating) are based on the
average of the two greatest demands of the
previous 12 months, but not less than the baseline
demand. The customer can self-supply reserves to
avoid reserve charges or demonstrate
instantaneous load reduction capability to reduce
reserved capacity needs. Thirty-day advance
notice is required for scheduled maintenance
energy, priced at the applicable standard rate
schedule. Unscheduled energy is priced at an
hourly firm market rate index (plus a small risk
adder). The customer also can sign up for
Schedule 276R to buy energy from PacifiCorp to
replace some or all of the customer’s on-site
Portland General Electric - Customers with self-
generation under 2 MW receive service under
standard rate schedules. Customers whose
generator has a nameplate capacity of 2 MW or
greater receive basic partial requirements service
under Schedule 75. The monthly basic charge and
energy charges are the same as for full
requirements customers. The customer contract
sets baseline demand as well as reserved capacity
to serve the customer's load when the generator is
not operating. Reserved capacity is the lesser of
the nameplate rating of the generator or maximum
kW of customer load supplied by the generator.
The customer can self-supply reserves to avoid
reserve charges or demonstrate instantaneous
load reduction capability to reduce reserved
capacity needs. Distribution charges are based on
the average of the two greatest demands of the
previous 12 months, but not less than the baseline
demand. The customer can choose fixed or daily
pricing for scheduled maintenance. Unscheduled
energy is priced at an hourly firm market rate
index (plus a small risk adder). The customer also
can sign up for Schedule 76R to buy energy from
PGE
to replace some or all of the customer’s on-site
Updated IRP requirements were released in 2007.
OR's current IRP guidelines require the evaluation
of distributed generation technologies "on par with
other supply-side resources," and should consider
the benefits of DG. IRPs must be filed at least
every two years from the date of acknowledgment
of the prior IRP.
http://apps.puc.state.or.us/orders/2007ords/07-
PacifiCorp addresses CHP in its 2007 IRP,
including in portfolio studies. CHP is included in
PacifiCorp's 2007 IRP Preferred Portfolio.
http://www.pacificorp.com/Navigation/Navigation23807.html
Portland General Electric addresses CHP in its
2007 IRP, assessing the market potential for CHP
and ways to improve policies related to CHP.
.portlandgeneral.com/about_pge/current_issues/energy_strategy/2007_irp.aspx
Natural Gas
Utility IRPs must evaluate supply and demand
side resources on a consistent and comparable
basis. Guidelines updated in 2007 require utilities
to include in IRP action plans all best cost/risk
IRP has been required since 1989. Updated IRP
guidelines were released in 2007. Utilities must
evaluate all known demand-side resources as
part of the planning process.
nergy efficiency as a resource
The Utility System Test and the Societal Cost
Test are used by the ETO to evaluate programs.
http://www.energytrust.org/meetings/board/2008/0
80213/06b_CostEff.pdf
Updated IRP guidelines (2007) require utilities to
ensure a potential study is conducted periodically.
(Utility or Energy Trust may conduct it.)
http://apps.puc.state.or.us/orders/2007ords/07-
002.pdf
Efficiency programs exclude distribution-only
customers.
Gas utilities agreed to a Commission-approved
public purpose charge. Commission IRP policy
requires utilities to include in their IRP action
plans all best cost/risk portfolio conservation
resources for meeting
projected resource needs, specifying annual
savings targets.
The Energy Trust proposes annual performance
benchmarks for the Commission's approval and
sets long-term energy-savings goals.
http://apps.puc.state.or.us/orders/2008ords/08-
529.pdf
The utility IRP process and Energy Trust planning
and budget-setting processes set energy savings
goals
2006 = 2.3 million therms; 2008 = 2.6 million
therms (Energy Trust goals for NW Natural and
Cascade)
http://www.energytrust.org/library/reports/2006_An
nual_Report.pdf;
http://www.energytrust.org/library/reports/2008_An
Statute requires independent review of the PPC to
develop recommendations for the legislature. A
report was released in 2006 that recommended
developing more consistent M&V procedures for
PPC funds. M&V is done by the ETO. The ETO
http://www.puc.state.or.us/PUC/electric_restruc/pu
rpose/013007PPCModificationsFinal.pdf
Energy Trust conducts numerous M&V studies
http://www.energytrust.org/library/reports/db/report_list.php
Most evaluations are conducted by third party
contractors. The Trust does some assembly and
cleaning of data sets in-house; contracting that
out has not been effective. The Trust evaluates
some pilot programs in-house because small-
scale work is too expensive to contract out. The
Trust also does some simple analysis in-house as
a check on consultant work.
The Trust's board evaluation committee reviews
draft evaluations. The committee includes outside
Prescriptive measures have “deemed” estimates
and quality control and assurance to make sure
the correct equipment was installed properly.
Large complex mechanical projects have a
commissioning option, where the ETO pays part
1999 restructuring act (SB 1149) established the
Energy Trust of Oregon, a third party non-profit
entity to deliver energy efficiency programs. The
ETO delivers programs on behalf of most of
Oregon's electric utilities. Idaho Power
Energy Trust delivers programs for NW Natural
and Cascade Natural Gas. Avista delivers
programs for its natural gas customers in Oregon.
New IRPs must be filed within 2 years of
Commission acknowledgment of an IRP unless
Commission grants waiver
A Conservation Advisory Council advises the
Energy Trust of Oregon on electric and natural
gas programs.
ergy efficiency where cost-effective.
Decoupling orders for natural gas utilities included
funding of EE programs administered by the
Energy Trust of Oregon.
For the largest gas utility, NW Natural, Schedule
301. For Cascade Natural Gas, Schedule No. 31.
NW Natural - 1.25%; Cascade - 0.75%
ctive energy efficiency and modify ratemaking
NW Natural Gas: The Oregon Public Utility
Commission decoupled NW Natural Gas’
revenues from sales in 2002 (Order 02-634). At
the same time, a public purpose funding
mechanism was created that set aside 0.9% of
revenues for EE programs (administered by the
Energy Trust of Oregon) and low-income
weatherization, plus a $0.25 per month charge for
low-income bill payment assistance. In 2005, the
mechanism was modified slightly and extended,
along with the public purpose charge, for four
more years (Order 05-934).
Docket UG-143, Order 02-634, p. 3:
http://apps.puc.state.or.us/orders/2002ords/02-
634.pdf. Extended in Docket UG-163, Order No.
05-934. An evaluation of the mechanism is at:
http://www.raponline.org/showpdf.asp?PDF_URL=
%22Pubs/General/OregonPaper.pdf%22.
Cascade Natural Gas: In 2006, the PUC
decoupled Cascade Natural Gas and established
a set-aside fund for EE programs to be
administered by the Energy Trust of Oregon and
community groups.
Docket UG-167, Order No. 06-191;
http://apps.puc.state.or.us/orders/2006ords/06-
191.pdf.
Energy Trust offers incentives for renewable and fossil CHP for Oregon electric IOUs
CHP for Oregon electric IOUs
TEXAS
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority Legislation passed in 2007 increased
resource, equivalent or superior to supply Texas' EEPS to 15% of annual growth in
resources Y demand from residential and commercial
1.1 customers by 2008, and 20% by 2009.
HB 3693:
S http://www.capitol.state.tx.us/tlodocs/80R/bill
text/html/HB03693F.HTM
1.2.1 EE is integrated into an active IRP, Electric utilities must submit annual energy
portfolio management, or other planning efficiency plans that show how savings
N
process goals will be met.
See p. 8-9 at
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
1.2
1.2.2 Efficiency is procured as a resource Under Texas Administrative Rules, standard
for default service/standard offer customers offer programs must be implemented
Y
consistent with the Rules governing EE and
the EEPS.
Texas Administrative Rules §25.181:
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
EE is an alternative to transmission based
on a long-term transparent IRP or
1.3 transmission system plan
1.4.1 EE is a biddable commodity
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute Texas utilities code 39.905 establishes
savings goals and requires utilities to offer
Y efficiency incentive programs to meet those
2.1 goals. Goals were last updated in 2007.
http://www.capitol.state.tx.us/tlodocs/80R/bill
text/html/HB03693F.HTM
The TRC or Societal Cost Test is used to Rules on the TX Energy Efficiency Goal
evaluate EE programs state that an EE program is deemed to be
cost-effective if the costs (including
incentives, M&V, R&D, and administrative
costs) to the utility are lower than the
N benefits (including the value of the demand
reductions and energy savings, measured in
2.2 accordance with the avoided costs given in
the Rules). Thus, the PACT test, not the
TRC test, is followed.
Texas Administrative Rules §25.181:
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
2.3.1 Potential for cost-effective EE has 2007 legislation required the Commission to
been established through a potential study fund a potential study by 2009. The PUC
Y commissioned a potential study for the
largest 9 IOUs, which was completed on
12/23/08.
HB 3693:
http://www.capitol.state.tx.us/tlodocs/80R/bill
text/html/HB03693F.HTM; Potential study:
S http://www.puc.state.tx.us/electric/reports/mi
sc/Electricity_Saving_2009-
2018_122308.pdf
2.3 2.3.2 Established EE programs reach all TX Rules require that all customers in
customer classes residential and commercial classes have
access to efficiency programs, including low-
income customers. Industrial customers
must have access to programs that were
Y developed and implemented prior to 5/1/07,
to the extent that such customers meet the
criteria for participation in load management
standard offer programs; in addition, such
programs must be completed by 12/31/08.
Texas administrative rules §25.181:
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
Funding requirements for all long-term, cost-
effective EE have been established
N
2.4
2.5.1 Quantitative MW and MWh savings 2007 legislation required utilities to meet
goals have been established and are 10% of their annual load growth in demand
producing incremental investment. of residential and commercial customers
through EE by 2007; 15% by 2008; and 20%
by 2009. The Commission set rules related
to this standard on 4/14/08. The legislation
also required the Commission to examine
the potential to increase the goal to 50% of
Y
annual load growth. The potential study
described in 2.3.1 examined whether each
utility could feasibly achieve 30% of annual
growth through EE by 2010 and 50% by
2015. The study concluded that the 50%
goal may be achievable for some of the
utilities, but not others.
HB 3693 (2007):
http://www.capitol.state.tx.us/tlodocs/80R/bill
S text/html/HB03693F.HTM; Commission
rules (Project 33487), Order 4/14/08
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
b
system; (c) as part of program approval and
budget-setting process; (d) other
2.5
2.5.3 Energy Efficiency can be used to 2007 legislation required utilities to meet
fulfill requirements of an RPS or similar 10% of their annual load growth in demand
standard of residential and commercial customers
through EE by 2007; 15% by 2008; and 20%
by 2009. The Commission set rules related
to this standard on 4/14/08. The legislation
also required the Commission to examine
the potential to increase the goal to 50% of
Y
annual load growth. The potential study
described in 2.3.1 examined whether each
utility could feasibly achieve 30% of annual
growth through EE by 2010 and 50% by
2015. The study concluded that the 50%
goal may be achievable for some of the
utilities, but not others.
HB 3693 (2007):
http://www.capitol.state.tx.us/tlodocs/80R/bill
text/html/HB03693F.HTM; Commission
rules (Project 33487), Order 4/14/08
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been M&V procedures are guided by Texas
established Administrative Rules. Utilities are
Y responsible for conducting M&V according
to Commission-established methods.
Texas Administrative Rules §25.181 (o):
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
2.6.1.1 M&V is adequately funded
2.6.1.2 Energy savings are used to
Y
measure performance
2.6.1.3 M&V is done according to a EE service providers shall not receive final
defined schedule compensation until the M&V processes are
Y-
complete, according to the Rules.
2.6
Texas Administrative Rules §25.181 (o):
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
2.6.1.4 M&V is conducted by an A third party may be used, according to the
independent party Rules.
A Texas Administrative Rules §25.181 (o):
2.6.1.5 Review of M&V is done in a http://www.puc.state.tx.us/rules/subrules/ele
transparent process
2.6.2 M&V is done using: (a) deemed Deemed savings and statistically significant
savings; (b) actual savings; (c) other samples may be used, according to the
a,c
Rules.
Texas Administrative Rules §25.181 (o):
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
2.7.1 EE delivery structure has been Texas administrative rules §25.181
established establish that utilities will administer
Y efficiency programs.
http://www.puc.state.tx.us/rules/subrules/ele
2.7 ctric/25.181/25.181.pdf
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated Resource plans are not required. The plans
N described under 1.2.1 must be updated
annually.
2.8
Texas Administrative Rules §25.181:
A http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
2.9.1 Building Energy Codes for residential 2000 IECC with 2001 supplement is
buildings are in place and regularly updated mandatory statewide; many local
Y/N jurisdictions have adopted a more stringent
code. The state is authorized to adopt the
most recent IECC standards, and the most
recent update was effective in 2005.
http://bcap-energy.org/node/96
2.9 2.9.2 Building Energy Codes for 2000 IECC with 2001 supplement, with
commercial buildings are in place and reference to ASHRAE 90.1-2001 is
regularly updated mandatory statewide; many local
jurisdictions have adopted a more stringent
Y/N code. ASHRAE 90.1-2007 is mandatory for
state-funded buildings. The state is
authorized to adopt the most recent IECC
standards, and the most recent update was
effective in 2005.
dsireusa.org
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10
updated
Energy efficiency is a high priority in state Legislation passed in 2007 that renewed
buildings and state funded buildings as 2001 legislation, and directed political
evidenced in capital planning and enabling subdivisions (including state agencies) to
performance contracts reduce their energy use by 5% annually for
six years beginning 9/1/07. The legislation
also requires that state-owned or leased
buildings must purchase Energy Star
appliances and equipment, and specified
other standards for certain equipment. In
Y
addition, statute requires government
2.11 bodies responsible for new and
reconstructed state buildings (and repair or
construction of certain systems and
equipment) to conduct an economic
analysis of EE and renewable energy
options, and if these options are cost-
effective over the life of the building, they
must be undertaken.
SB 12:
http://www.legis.state.tx.us/tlodocs/80R/billte
Recommendation 3: Miscellaneous Policies xt/pdf/SB00012F.pdf; HB 3693:
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
3.1 high-priority resource. (See Guide Tab for
Y/N criteria.)
Do not delete this row.
Do not delete this row.
Do not delete this row.
Do not delete this row.
Do not delete this row.
75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility CenterPoint Energy, Entergy Texas, Oncor
program? (who is sponsor) Electric Delivery, TXU Energy, Texas New
75% of state access to Home Performance Mexico Power Company, AEP Texas,
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists TX Rules states that an Energy Efficiency
Cost Recovery Factor will be included in
Y utilities' rates to recover costs of EE, and
will be tracked annually.
Texas administrative rules §25.181:
http://www.puc.state.tx.us/rules/subrules/ele
4.1 ctric/25.181/25.181.pdf
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits b
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is
N
addressed and disincentives are removed
5.1 5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE incentives are Legislation passed in 2007 required the
provided Commission to establish incentives to
reward utilities for exceeding the EEPS
goals. TX Rules were revised in 2008,
providing for EE performance bonuses, as
follows. A utility that exceeds its demand
reduction goal at a cost that does not
exceed the cost limits established in the
rules, will receive a performance bonus
based on the utility's EE achievements
during the previous year. The bonus
Y entitles the utility to receive a share of the
net benefits; a utility that exceeds 100% of
its demand reduction goal, will receive 1%
of the net benefits for every 2% that the
demand reduction goal has been exceeded,
5.2
with a maximum of 20% of the utility's
program costs. A utility that meets at least
120% of its demand reduction goal with at
least 10% of its savings achieved through
Hard-to-Reach programs will receive an
additional bonus of 10% of the bonus
calculated above.
HB 3693:
http://www.capitol.state.tx.us/tlodocs/80R/bill
text/html/HB03693F.HTM; Texas
S, A
administrative rules §25.181:
http://www.puc.state.tx.us/rules/subrules/ele
ctric/25.181/25.181.pdf
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
when designing retail rates
5.3 5.3.2 Declining block rates and fixed Residential rates of the largest two utilities
variable rate designs have been eliminated are flat rates.
5.4.1 Time sensitive rates in place
5.4.2 Usage sensitive rates in place
5.4.3 AMI deployment planned A number of utilities have AMI pilots or full
deployment underway. Legislation passed
in 2006 allows the Commission to establish
a nonbypassable surcharge to cover the
Y+/
cost of advanced meter deployment. The
C
cost recovery mechanism and guidelines
regarding meter deployment were approved
5.4 and established on 5/10/07.
HB 2129:
http://www.puc.state.tx.us/rules/rulemake/31
418/HB02129F.pdf; AMI Rules, Project No.
31418:
http://www.puc.state.tx.us/rules/rulemake/31
418/31418adt.pdf
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for There was a sales tax holiday on Energy
energy efficient products
Y Star appliances in May 2008 and 2009.
http://www.ens-
- newswire.com/ens/mar2008/2008-03-26-
095.asp;
http://www.window.state.tx.us/taxinfo/taxpub
s/tx96_1331/
Investment Tax Credit for energy efficient
- investments
State supported low cost financing for There is a revolving loan fund for EE
energy efficient investments: buildings (x), improvements to public buildings called
equipment (y) Y LoanStar. As of 11/07, the program had
- funded loans totaling more than $240 million
dollars.
http://www.seco.cpa.state.tx.us/ls/
Distributed Generation Policies
A statewide interconnection policy is in place
The Public Utility Commission of Texas
(PUCT) first adopted statewide
interconnection standards with Substantive
Rules §25.211 and §25.212. The rules apply
to electrical generating systems up to 10
MW and connected at a voltage less than
60 kV. Systems must meet all applicable
national, state, and local construction and
safety codes. No pre-interconnection study
7.1 Y+ fees are required for units up to 500 kW and
study fees are limited for larger systems.
There are set timeframes for approval or
rejection (4-6 weeks). There are pre-
certification provisions allowing for a fast-
track procedure. An external disconnect is
required for all systems. There are brief
standard forms and agreements. No
additional insurance is required and liability
insurance is limited. An external disconnect
is required.
HB 3693 can be accessed here,
http://www.capitol.state.tx.us/tlodocs/80R/bill
S text/pdf/HB03693F.pdf.
A statewide net metering policy is in place Texas has limited net metering rules. Under
PUCT Substantive Rule § 25.242(h), net
metering only applies to integrated IOUs
that have not unbundled in accordance to
PURPA § 39.05 that have QF of 100 kW or
less that use non-renewable resources and
Y QF 50 kW or less that use renewable
energy resources. For eligible facilities,
7.2 there is no limit on overall enrollment of net-
metered systems. Net excess generation is
purchased by the utility for a given billing
period at the avoided-cost rate.
16 TAC § 25.242(h)(4) can be found here,
http://info.sos.state.tx.us/pls/pub/readtac$ext
R
.ViewTAC?tac_view=5&ti=16&pt=2&ch=25&
sch=J&div=1&rl=Y
A statewide exit fee policy is in place There is a statewide exit fee policy in place
that does not allow utilities to collect fees
from DG applications smaller than 10 MW.
The state's Restructuring Act did allow for
Y+ utilities to recoup stranded costs from DG
7.3
systems greater than 10 MW. However, in
2003, the PUCT decided that utilities have
already recovered their stranded costs.
A statewide standby rate policy is in place Texas does not have a statewide policy on
N
standby rates
TXU Energy Retail Co LP - there is no
standard standby rate. Customers seeking
standby service would need to contract with
U the utility to be charged under a regular
tariff. Typical rates are based on both
demand and energy charges. There may
7.4 be a demand ratchet depending on the
contract with the utility.
Reliant Energy Retail Services - there is no
standard standby rate. Customers seeking
standby service would need to contract with
U
the utility to be charged under a regular
tariff. Typical rates are based on both
demand and energy charges. There would
be no demand ratchet.
As part of resource planning process, CHP
is reviewed and incorporated where effective TX does not have an IRP planning process,
this was deleted with the passage of SB 7 in
1999. The state does have energy efficiency
goal requirements. Utilities must submit
energy efficiency plans outlining how
N
savings goals will be met. For standard offer
and market transformation program
requirements, regulations state that utilities
7.5 "may permit the use of renewable DSM and
combined heat and power technologies,
involving installations of 10 MW or less."
http://www.puc.state.tx.us/rules/subrules/electric/2
TXU Energy Retail Co LP's 2006 annual
U
report does not mention CHP.
http://www.txucorp.com/pdf/txu2006ar.pdf
Reliant Energy Retail Service's Energy &
U
Environment policy does not list CHP.
http://www.reliant.com/PublicLinkAction.do?i_chronicle_id=09017522801502c5&language_code=en_US&
Natural Gas
urce.
effective energy efficiency as a resource
deliver energy efficiency where cost-effective.
cost-effective energy efficiency and modify ratemaking
UTAH (as of 12/31/08)
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority IRP rules require the comparison of supply
resource, equivalent or superior to supply and demand side resources on a consistent
resources and comparable basis. See Feb. 1992
Order in Docket 90-235-01.
Y
1.1
http://www.psc.state.ut.us/elec/02orders/Feb
/98203505ro.htm
1.2.1 EE is integrated into an active IRP, Pacificorp (Rocky Mtn Power) must prepare
portfolio management, or other planning an IRP that compares supply and demand
process side resources on a consistent and
comparable basis. See Feb. 1992 Order in
Y Docket 90-235-01.
1.2
http://www.psc.state.ut.us/elec/02orders/Feb
/98203505ro.htm
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers
EE is an alternative to transmission based The IRP compares all resources across
on a long-term transparent IRP or Y time and accounts for transmission
1.3 transmission system plan costs/bottle necks.
1.4.1 EE is a biddable commodity
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute The Governor issued an Executive Order in
2006 that called for increasing energy
Y efficiency statewide 20% by 2015, for all
2.1 forms of energy use in the state. IRP Rules
also exist, as described under 1.1 and 1.2.
EO
The TRC or Societal Cost Test is used to DSM programs must meet the TRC and the
evaluate EE programs utility cost tests. Other tests may be
considered. (from RAP IRP survey). The
Y+ 1992 rules state that the TRC be used as
the primary test for determining if DSM
2.2 programs are cost-effective, according to
SWEEP.
http://www.raponline.org/showpdf.asp?PDF_
URL=%22Pubs/IRPsurvey/IRPUT2.pdf%22
2.3.1 Potential for cost-effective EE has Pacificorp (Rocky Mountain Power)
been established through a potential study commissioned a DSM potential study in
Y 2007, and the study was the subject of an
on-going proceeding as of the end of 2008.
Pacificorp 2007 study:
http://www.le.utah.gov/UtahCode/getCodeSe
ction?code=54-7-12.8; also see Docket 08-
2.3
035-56:
http://www.psc.utah.gov/utilities/electric/eleci
ndx/0803556indx.html
2.3.2 Established EE programs reach all Pacificorp has programs that reach all
customer classes Y customer classes.
Funding requirements for all long-term, cost-
effective EE have been established
2.4
2.5.1 Quantitative MW and MWh savings IRPs establish savings goals. The Utah
goals have been established and are Energy Efficiency Strategy, written in 10/07
producing incremental investment. in response to the Governor's 2006 goal of
increasing EE 20% by 2015, recommends
Y Utah adopt energy savings standards or
targets for electric DSM programs.
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
2.5
2.5.2 Goals are established: (a)
connection with IRP or other planning
process; (b) as part of an EEPS or similar
a
system; (c) as part of program approval and
budget-setting process; (d) other
2.5
2.5.3 Energy Efficiency can be used to The Utah Energy Efficiency Strategy, written
fulfill requirements of an RPS or similar in 10/07 in response to the Governor's 2006
standard goal of increasing EE 20% by 2015,
N recommends Utah adopt energy savings
standards or targets for electric DSM
programs.
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
2.5.4 Expected Capacity Savings 2006 About 100 MW peak reduction in 2008 or
(Annual MW) 2009.
2.5.5 Energy Savings Goals 2006 (Annual Rocky Mountain Power: 120 GWh per year
MWh or MTherms) from measures installed in 2006
2.6.1 A robust M&V process has been
established
2.6.1.1 M&V is adequately funded
2.6.1.2 Energy savings are used to
measure performance
2.6 2.6.1.3 M&V is done according to a
N
defined schedule
2.6.1.4 M&V is conducted by an
independent party
2.6.1.5 Review of M&V is done in a
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
a, b
2.7.1 EE delivery structure has been Utilities are required to file IRPs and
established undertake DSM programs.
Y
2.7
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated Utilities file biennial IRPs.
Y
2.8
2.9.1 Building Energy Codes for residential 2006 IECC mandatory statewide; code
buildings are in place and regularly updated changes ongoing. The most recent update
was in 2007. The Utah Energy Efficiency
Strategy, written in 10/07 in response to the
Y/Y Governor's 2006 goal of increasing EE 20%
by 2015, recommends Utah upgrade
building energy codes every three years,
and provide funding for training and
enforcement.
http://bcap-
energy.org/state_status.php?state_ab=UT;
Utah Energy Efficiency Strategy:
2.9.2 Building Energy Codes for 2006 IECC mandatory statewide; code
2.9 commercial buildings are in place and changes ongoing. The most recent update
regularly updated was in 2007. The Utah Energy Efficiency
Strategy, written in 10/07 in response to the
Y/Y Governor's 2006 goal of increasing EE 20%
by 2015, recommends Utah upgrade
building energy codes every three years,
and provide funding for training and
enforcement.
http://bcap-
energy.org/state_status.php?state_ab=UT;
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
Appliance and Equipment Efficiency The Utah Energy Efficiency Strategy, written
Standards are in place and regularly in 10/07 in response to the Governor's 2006
updated goal of increasing EE 20% by 2015,
N recommends Utah adopt appliance
2.10 efficiency standards for products not
covered by federal standards.
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
Energy efficiency is a high priority in state A 2006 statute established the State
buildings and state funded buildings as Building Energy Efficiency Program, which
evidenced in capital planning and enabling requires the Division of Facilities
performance contracts Construction and Management to develop
guidelines, incentives, and procedures for
EE and reduction of energy costs in state
buildings, and to assist state entities in
implementing the procedures. A
subsequent statute in 2008 establishes a
revolving loan fund for state agencies to
finance EE measures. Salt Lake City has
Y
established a requirement that all city-
2.11 owned building projects greater than 10,000
square feet, as well as major renovations of
city buildings and private buildings that
receive city funds, must be LEED certified at
the Silver Level. The Utah Energy
Efficiency Strategy, written in 10/07 in
response to the Governor's 2006 goal of
increasing EE 20% by 2015, recommends
Utah adopt energy savings requirements for
state agencies, in order to reduce energy
HB 80 (2006):
S
http://www.le.state.ut.us/~2006/bills/hbillenr/
Recommendation 3: Miscellaneous Policies hb0080.pdf; also see HB 198 (2008) and
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
Y
high-priority resource. (See Guide Tab for
3.1 Y/N criteria.)
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75% of state access to ENERGY STAR
Y
3.2 New Homes
What proportion is due to regulated utility Rocky Mountain Power, Questar Gas
program? (who is sponsor) Performance
75% of state access to Home
with ENERGY STAR?
What proportion is ue to regulated utility
N
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists Funding for EE programs is provided by a
tariff rider on customer bills. Legislation
passed in 2002 allowed for a tariff rider. An
Y Order and settlement agreement in 2003
established the details of the tariff rider for
Rocky Mountain Power.
Utah Code 54-7-12.8:
http://www.le.utah.gov/UtahCode/getCodeSe
4.1 ction?code=54-7-12.8; Docket 02-035-T12,
S, R
Order 10/3/03:
http://www.psc.state.ut.us/utilities/electric/03
orders/Oct/02035T12roc.htm
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits a
charge
4.1.3 Funding is for multi-year periods
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is The Utah Energy Efficiency Strategy, written
addressed and disincentives are removed in 10/07 in response to the Governor's 2006
goal of increasing EE 20% by 2015,
recommends Utah adopt decoupling or
N shareholder incentives.
5.1
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility
implementaion of EE
5.2.1 Utility/shareholder EE incentives are The Utah Energy Efficiency Strategy, written
provided in 10/07 in response to the Governor's 2006
goal of increasing EE 20% by 2015,
N
recommends Utah adopt decoupling or
shareholder incentives.
5.2 Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
Y
when designing retail rates
5.3 5.3.2 Declining block rates and fixed The residential tariffs of the two largest
variable rate designs have been eliminated Y utilities do not have declining block rates.
5.4.1 Time sensitive rates in place In 2/07, the Commission decided not to
adopt PURPA standard 14 regarding time-
based metering and communications.
However, Rocky Mountain Power offers
TOU rates, seasonal rates, and a peak-load
reduction program. The Utah Energy
Y
Efficiency Strategy, written in 10/07 in
response to the Governor's 2006 goal of
increasing EE 20% by 2015, recommends
Utah adopt real-time pricing or critical peak
pricing for certain residential customers.
5.4 Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_e
fficiency_strategy.html
5.4.2 Usage sensitive rates in place Y
5.4.3 AMI deployment planned In 2/07, the Commission decided not to
N adopt PURPA standard 14 regarding time-
based metering and communications.
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
N
- energy efficient products
Investment Tax Credit for energy efficient
- investments
State supported low cost financing for
energy efficient investments: buildings (x),
equipment (y)
-
New or reorganized energy policy agency Y
Distributed Generation Policies
A statewide interconnection policy is in place Utah has interconnection guidelines outlined
in their net metering law -Utah Code § 54-
15-1-1 et seq. Utah requires the state's only
investor-owned utility, Rocky Mountain
Power (RMP), and most electric
cooperatives to offer net metering to
customers who generate electricity using
solar energy, wind energy, hydropower,
hydrogen, biomass, landfill gas or
geothermal energy. Net metering is
available for residential systems up to 25
Y- kilowatts (kW) in capacity and non-
residential systems up to two megawatts
7.1 (MW) in capacity. Net-metered customers
must comply with local and national
standards established by the National
Electrical Code (NEC), National Electrical
Safety Code (NESC), Institute of Electrical
and Electronic Engineers (IEEE), and
Underwriters Laboratories (UL). Utilities
may enforce additional requirements -- if
approved by the Utah Public Service
Commission (PSC) or an electric
Utah Code § 54-15-1-1 et seq can be
A accessed here:
http://le.utah.gov/~code/TITLE54/54_15.htm
A statewide net metering policy is in place Utah has a net metering policy -Utah Code
§ 54-15-1-1 et seq. that applies to all IOUs
and cooperative utilities. Eligible systems
are fuel cells, solar, wind and hydropower
systems up to 25 kW. Net metering is also
limited to 0.1% of the cumulative generating
Y- capacity of each utility's peak demand in
2001. NEG must be credited at a rate equal
7.2 to the utility's avoided cost or higher. NEG is
carried over to the customer's next bill and
is granted to the utility at the end of a
calendar year.
7.2
Utah Code § 54-15-1-1 et seq. can be
accessed here,
A
http://le.utah.gov/~code/TITLE54/54_11.htm
A statewide exit fee policy is in place N
7.3
A statewide standby rate policy is in place Utah does not have a statewide policy on
N
standby rates
PacifiCorp - Schedule 31 - standby power is
provided through a contract with the utility
that is not to exceed 10 MW. A moderate
customer charge and demand based
reservation charge is assessed every
month. Actual usage is billed through
7.4
U- moderate energy and high demand charges
based on the maximum 15 minute demand
of the month. There is a very high penalty
for exceeding the contract demand. Rate
available at:
http://www.rockymtnpower.net/Article/Article
2599.html
As part of resource planning process, CHP Utah Docket 90-2035-01 established IRP
is reviewed and incorporated where effective requirements in 1992 (only Pacificorp is
required to binennially file an IRP), stating
that supply and demand side resources
must be considered on a consistent basis.
The IRP does not mention CHP.
N
7.5
http://www.airquality.utah.gov/Public-
U+ Pacificorp: Rocky Mountain Power's 2008
IRP assesses CHP in its planning process.
http://www.pacificorp.com/Navigation/Navigation2
08)
Natural Gas
urce.
A 1994 Order on Standards and Guidelines
established IRP guidelines for natural gas that
required an evaluation of supply-side and
demand-side resources on a consistent and
Y
comparable basis. In 2008, a new proceeding
was initiated to consider revisions to these
guidelines; the Docket was still in process as of
the end of 2008.
Docket No. 08-057-02 (2008):
R http://www.psc.utah.gov/utilities/gas/gasindx/docu
ments/0805702ROosagfqgc.pdf
A 1994 Order on Standards and Guidelines
established IRP guidelines for natural gas that
required an evaluation of supply-side and
demand-side resources on a consistent and
Y comparable basis. In 2008, a new proceeding
was initiated to consider revisions to these
guidelines; the Docket was still in process as of
the end of 2008.
Docket 91-057-09, Order 9/26/94; Docket No. 08-
057-02 (2008):
R
http://www.psc.utah.gov/utilities/gas/gasindx/docu
ments/0805702ROosagfqgc.pdf
effective energy efficiency as a resource
The Governor issued an Executive Order in 2006
that called for increasing energy efficiency
Y statewide 20% by 2015, for all forms of energy
use in the state. IRP Rules also exist, as
described under 1.1 and 1.2.
EO
A 1994 Order on Standards and Guidelines that
established IRP guidelines for natural gas states
that supply-side and demand-side resources
Y should be compared on a total resource cost
basis.
Docket 91-057-09, Order 9/26/94
Established EE programs are only available to
N residential and small commercial GS rate classes.
N
Questar's IRP incorporates savings goals. The
Utah Energy Efficiency Strategy, written in 10/07
in response to the Governor's 2006 goal of
increasing EE 20% by 2015, recommends Utah
Y expand natural gas DSM programs and establish
energy savings targets for these programs in
order to cut gas sales 5% by 2015 and almost 9%
by 2020.
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_efficien
cy_strategy.html
a
The Utah Energy Efficiency Strategy, written in
10/07 in response to the Governor's 2006 goal of
increasing EE 20% by 2015, recommends Utah
N expand natural gas DSM programs and establish
energy savings targets for these programs in
order to cut gas sales 5% by 2015 and almost 9%
by 2020.
Utah Energy Efficiency Strategy:
http://energy.utah.gov/energy/utah_energy_efficien
cy_strategy.html
A DSM Evaluation Plan was approved for the
three-year Questar Gas DSM pilot program in
Y 11/07.
Docket 07-057-05, Order on 11/20/07:
http://www.psc.utah.gov/utilities/gas/gasindx/0705
705indx.html
DSM balancing account will cover these costs.
Once the impact evaluation is completed this will
N
be the case.
Y
Y
This will change in the future.
a
Utilities are required to file IRPs and undertake
DSM programs.
Y
a
Utilities are required to file biennial IRPs in the
1994 Order on Standards and Guidelines that
Y established IRP guidelines for natural gas.
Docket 91-057-09, Order 9/26/94
Y
deliver energy efficiency where cost-effective.
Cost recovery occurs in rate cases.
Y
b
cost-effective energy efficiency and modify ratemaking
A 2006 Utah PSC decision approved a stipulated
settlement with Questar, creating a three-year
pilot DSM program accompanied by a rate
mechanism that separates recovery of fixed costs
Y- from sales (Conservation Enabling Tariff or
CET).The decoupling mechanism will be reviewed
and subject to change during the three year-long
Pilot Program. Questar Gas committed to
implement DSM programs as part of the
settlement.
Utah Public Service Commission DOCKET NO.
05-057-T01, Order of 10/5/06. See
http://www.psc.utah.gov/utilities/gas/06orders/Oct/
05057t01oass.pdf
b
Y
Y
Y
WASHINGTON
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority Initiative 937, passed by voters in 2006,
resource, equivalent or superior to supply amends Title 19 RCW to require utilities to
resources pursue all cost-effective conservation.
Y+
1.1
http://apps.leg.wa.gov/RCW/default.aspx?cit
S
e=19.285
1.2.1 EE is integrated into an active IRP, Washington Administrative Code 480-100-
portfolio management, or other planning 238 requires electric utilities to file IRPs and
process establishes IRP requirements. IRPs must
include an assessment of commercially
Y+ available DSM.
S http://apps.leg.wa.gov/RCW/default.aspx?cit
1.2 IRP rules are available at WAC 480-100-
238. See
A
http://apps.leg.wa.gov/WAC/default.aspx?cit
e=480-100-238
http://www.wutc.wa.gov/rms2.nsf/208e3d50f
ad2b39d88256a77006f9105/e091202136c2
9a8b88256feb0061419c!OpenDocument
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers
EE is an alternative to transmission based Cost of transmission must be considered
on a long-term transparent IRP or Y when evaluating EE.
1.3 transmission system plan
WAC 480-100-238(3)(d)
1.4.1 EE is a biddable commodity WAC 480-107-015 establishes the RFP
process utilities must use and states that
any provider of energy savings may submit
N
bids in this process (effective 4/28/06). But
no bidding occurs for a forward capacity
1.4 market.
http://apps.leg.wa.gov/WAC/default.aspx?cit
1.4.2 Bids occur in the following markets:
(a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute RCW 19.285.040: Each qualifying utility
shall pursue all available conservation that
Y+ is cost-effective, reliable, and feasible
2.1 (approved November 2006).
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=19.285.040
Avista Corp. staff memo UG-090052
The TRC or Societal Cost Test is used to Y
2.2 evaluate EE programs
http://www.wutc.wa.gov/rms2.nsf/177d98baa
5918c7388256a550064a61e/f3bda44463ed
2.3.1 Potential for cost-effective EE has Initiative 937 requires each utility to conduct
been established through a potential study an assessment of cost-effective energy
efficiency potential through 2019, beginning
in 2010 and updated every 2 years
Y
thereafter. Assessments are based on the
methodologies established by the Northwest
Power and Conservation Planning Council.
RCW 19.285.040 "Energy Conservation and
Renewable Energy Targets" is available at
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=19.285.040.
2.3
2.3.2 Established EE programs reach all UE-082180 PacifiCorp Low Income DSM
customer classes Program increases
Y
http://www.wutc.wa.gov/rms2.nsf/177d98baa
5918c7388256a550064a61e/45814298f39f9
390882575190060833a!OpenDocument
Funding requirements for all long-term, cost- Funding requirements are developed on a
effective EE have been established utility-by-utility basis.
N
2.4
2.5.1 Quantitative MW and MWh savings IRP and utility requests for energy efficiency
goals have been established and are tariff riders include targets. Beginning in
producing incremental investment. 2010, utilities will be required to establish
biennial acquisition targets, based on each
utility's cost-effective potential. "At a
minimum, each biennial target must be no
lower than the qualifying utility's pro rata
Y share for that two-year period of its cost-
effective conservation potential for the
subsequent ten-year period," according to
RCW 19.285.040. See also WAC 480-109
http://www.secstate.wa.gov/elections/initiativ
es/text/I937.pdf;
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=19.285.040; Seattle City Light 2008 IRP
see Table 7-1, available at
http://www.seattle.gov/light/news/issues/irp/d
ocs/2008IRPfinal.pdf.
2.5
2.5.2 Goals are established: (a) RCW 19.285.040 gives the commission
connection with IRP or other planning permission to review and approve investor-
process; (b) as part of an EEPS or similar a, c owned utility conservation targets through
system; (c) as part of program approval and its standard processes.
budget-setting process; (d) other
http://apps.leg.wa.gov/RCW/default.aspx?cit
2.5.3 Energy Efficiency can be used to RCW 19.285.040 requires utilities to pursue
fulfill requirements of an RPS or similar all cost effective energy efficiency and
standard N establishes an RPS of 15% renewables by
2020. Energy efficiency is not eligible in the
RPS.
http://apps.leg.wa.gov/RCW/default.aspx?cit
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been Utility-by-utility.
established
N
2.6.1.1 M&V is adequately funded N Utility-by-utility.
2.6.1.2 Energy savings are used to UE-060266 Puget Conservation Incentive
measure performance Program. UE-060266 (2006) initiated a 3
Y year pilot performance incentive program by
which financial incentives are set to MW
savings targets.
http://wutc.wa.gov/rms2.nsf/vw2005OpenDo
2.6 2.6.1.3 M&V is done according to a
N
defined schedule
2.6.1.4 M&V is conducted by an Utility-by-utility.
N
independent party
2.6.1.5 Review of M&V is done in a Puget Sound Energy required by settlement
N
transparent process to share EE processes including M&V
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
a
2.7.1 EE delivery structure has been Customers are served by a variety of utilities
established and programs through public and private
Y utilities and advanced by strong regional
organizations.
2.7
2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a
or (c) government agency
Resource plans are regularly updated Least-cost plans are filed every two years.
Y
2.8
2.9.1 Building Energy Codes for residential Mandatory state code exceeds 2006 IECC.
buildings are in place and regularly updated Y/Y Code is reviewed every three years.
http://bcap-
energy.org/state_status.php?state_ab=WA
2.9.2 Building Energy Codes for State-adopted code exceeds 2004
2.9 commercial buildings are in place and ASHRAE. Code is reviewed every three
regularly updated years.
Y/Y
2.9
http://bcap-
energy.org/state_status.php?state_ab=WA
Appliance and Equipment Efficiency Washington adopted appliance efficiency
Standards are in place and regularly Y standards through legislation in 2005.
updated
2.10 See RCW § 19.260.010, et seq., available
at
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=19.260
Energy efficiency is a high priority in state Executive order 05-01 (1/5/05) requires a
buildings and state funded buildings as reduction in state agency energy use by
evidenced in capital planning and enabling 10% by Sept. 1, 2009 using FY 2003
performance contracts baseline, and also major state construction
projects (over 25,000 sq ft) to be designed
and built according to LEED Silver
standards. WA Statute (RCW 39.35D)
Y requires that all major facility projects of
public agencies receiving any funding in a
2.11 state capital budget must be designed,
constructed, and certified to at least the
LEED-Silver standard and must include
building commissioning as a component of
the design process.
http://www.governor.wa.gov/actions/orders/e
oarchive/eo05-01.htm
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=39.35D.030
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.)
Y
3.1
3.1.2 Process is in place, such as a state Washington is a member of the regional
or regional collaborative, to pursue EE as a energy planning organization, the Northwest
high-priority resource. (See Guide Tab for Power and Conservation Council, which
Y/N criteria.) actively supports energy efficiency as the
least cost, most readily available energy
resource for meeting load growth.
Washington customers are also reached by
the energy efficiency programs of the
Northwest Energy Efficiency Alliance and
the Bonneville Power Authority. In April
2008, Pacific Power, the Northwest Power
and Conservation Council and the
Bonneville Power Administration
3.1 Y announced a regional effort to improve ee.
The effort will be lead by a volunteer
organization of regional leaders of electric
utilities, businesses, government, NGOs
and energy efficiency organizations.
Information about the task force is available
at:
http://eastsidebusinessjournal.com/Wine/ind
ex.php?option=com_content&task=view&id=
1571&Itemid=2; see the current Fifth
Northwest Power Plan (2004), available at
http://www.nwcouncil.org/energy/default.htm.
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75% of state access to ENERGY STAR
Y
New Homes
3.2 What proportion is due to regulated utility Puget Sound Energy; Avista; PacifiCorp
program? (who is sponsor)
75% of state access to Home Performance
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists RCW 80.28.303 allows the Commission to
approve tariffs to recover utility conservation
expenses. Initiative Measure No. 937
Y
authorizes utilities to recover from its
customers all costs prudently incurred to
comply with the measure.
RCW 80.28.303 is available at
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=80.28.303; see commission website at
http://www.wutc.wa.gov/webimage.nsf/8d712
cfdd4796c8888256aaa007e94b4/0b2e39343
c0be04a88256a3b007449fe!OpenDocument
.
4.1.2 Recovery occurs via: (a) rider; (b) Investor owned utilities regulated by the
regular rate case; or (c) system benefits commission recover costs through tariff
4.1 charge riders. Since 2000, Pacific Power has used
a System Benefits Charge (SBC) to fund
a, c their conservation programs in Washington;
Since 1997, Puget Sound Energy has
included a surcharge for energy efficiency
on customer bills.
RCW 80.28.303 is available at
http://apps.leg.wa.gov/RCW/default.aspx?cit
e=80.28.303; see commission website at
http://www.wutc.wa.gov/webimage.nsf/8d712
cfdd4796c8888256aaa007e94b4/0b2e39343
c0be04a88256a3b007449fe!OpenDocument
.
4.1.3 Funding is for multi-year periods N
A base energy efficiency spending level N
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently Energy efficiency program spending in 2006
used for energy efficiency [no unit = %; m/k was $113.3 million, 2.2% of total utility
= mils/kWh] 2.2% revenues statewide, according to ACEEE.
4.3
EE IOU Program Spending in 2008 was $69
million, 2.6% of IOU electric revenue.
Funds from carbon trading program support N
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is
N
addressed and disincentives are removed
5.1.2 Method used is: (a) decoupling; (b) Note that on July 14, 2006 the commission
lost revenue recovery; or (c) non-utility rejected a proposal by Pacific Power & Light
implementation of EE for cost adjustment/decoupling on the basis
that the proposal was weak, but the
commission came out in support of cost
adjustment mechanisms generally.
5.1
5.1
See Docket #050684 Order #4 available at
http://www.wutc.wa.gov/rms2.nsf/vw2005Op
enDocket/482BB934770E106F88257153005
84C2B
5.2.1 Utility/shareholder EE incentives are UE-060266 Puget Conservation Incentive
provided Program. Docket 060266 (2006)
established a 3 year pilot for a performance
incentive program, to run Jan 2007 - Dec
Y+ 2009. The mechanism provides an incentive
for all MWh saved if the target is achieved
5.2 and incentives for higher levels of
performance based on the incremental
savings above the target.
http://wutc.wa.gov/rms2.nsf/vw2005OpenDo
5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration It is a consideration on a case by case basis
Y
when designing retail rates through the cost recovery process.
5.3 5.3.2 Declining block rates and fixed Of Washington's two largest utilities, one
variable rate designs have been eliminated has inclining rates, one has flat rates.
5.4.1 Time sensitive rates in place N Some utilities offer time-of-use rates,
5.4.2 Usage sensitive rates in place Y
5.4 5.4.3 AMI deployment planned N
5.4.4 Other mechanisms exist (e.g., on-bill
N
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
- energy efficient products
Investment Tax Credit for energy efficient Y
- investments
State supported low cost financing for Y
energy efficient investments: buildings (x),
equipment (y)
-
New or reorganized energy policy agency
-
Distributed Generation Policies
A statewide interconnection policy is in place WA adopted new interconnection standards
in September 2007, which apply to all DG
systems up to 20 MW. There are two levels
of interconnection, one for systems up to
300 kW in size, and the other for systems
greater than 300 kW but not greater than 20
MW (FERC interconnection stds were
adopted for larger systems) . There is no
Y+ standard interconnection agreement, but
each utility is required to have one. An
7.1 external disconnect is required, but this may
be waived at the utility's discretion. Utilities
may only require additional insurance for
systems eligible for net metering. There are
set interconnection application fees.
Amended Chapter 480-108 WAC can be
accessed from here,
A
http://www.wutc.wa.gov/webimage.nsf/0/511
22508732C88F08825718D007AB322
A statewide net metering policy is in place WA net metering law applies to systems up
to 100 kW in capacity that generate
electricity using solar, wind, hydro, biogas
from animal waste, or CHP technologies.
The law was first enacted with Rev. Code
Wash. § 80.60 and then recently revised
with Substitute HB 2352 of 2006. All
customer classes are eligible and all utilities
must offer net metering. Net metering is
Y+ available until the cumulative generating
capacity of net metered systems equals
0.25% of a utility's peak demand during
1996. The limit will increase to 0.5% on
7.2
January 1, 2014. NEG is credited to the
customer's next bill at the utility's retail rate.
However, on April 30 of each calendar year
any NEG remaining is granted to the utility.
Rev. Code Wash. § 80.60 can be accessed
here,
http://www.dsireusa.org/documents/Incentive
S s/WA01R.htm and HB 2352 can be found
here,
http://www.dsireusa.org/documents/Incentive
s/WA01Rb.pdf
A statewide exit fee policy is in place
WA does not have a statewide policy on exit
fees, but. DG unit owners are typically not
charged an exit fee. However, many of the
N
7.3 large industrial DG owners have their own
special contracts with the utility and in the
contract terms the DG owner may be
charged some sort of fee.
A statewide standby rate policy is in place Washington does not have a statewide
N
policy on standby rates
PacifiCorp - Schedule 47 T - standby
service is provided through a contract with
the utility. A high customer charge and
moderate reservation charge is assessed
every month based on contract demand.
Actual usage is based on moderate energy
U- charges and a high demand charge based
on the maximum 15 minute demand of the
month. There is a high penalty for
exceeding the contract demand. Rate
available at:
http://www.rockymtnpower.net/New_Auto_In
7.4
dex/New_Auto_Index2564.html
Puget Sound Energy Inc - Schedule 458 -
standby delivery service is provided through
a contract with the utility. A customer
charge and a moderate demand based
charge is assessed every month. The
U demand charge is based on the maximum
demand of the month. Actual usage would
consist of energy charges that must be
contracted for through a separate provider.
Rate available at:
http://www.pse.com/InsidePSE/RatesElecTa
riffsRules.aspx
As part of resource planning process, CHP Chapter 48-100-238 WAC establishes basic
is reviewed and incorporated where effective IRP requirements for IOUs. The
requirements state that utilities must
N "assess commercially available
conservation" and "a wide range of
conventional and commercially available
unconventional generating technologies."
7.5
http://apps.leg.wa.gov/WAC/default.aspx?cite=480-
PacifiCorp's IRP assesses the potential for
U+
CHP where effective
http://wutc.wa.gov/webimage.nsf/00000000000000
Puget Sound Energy Inc's IRP addresses
U+
CHP
http://www.pse.com/energyEnvironment/energysupply/Pages/pse2007irpView.aspx
Natural Gas
urce.
Washington Administrative Code 480-100-238
requires electric utilities to file IRPs and
establishes IRP requirements. IRPs must include
an assessment of commercially available DSM.
WAC 480-90-238 requires integrated resource
planning for gas utilities to determine the least-
cost mix of supply and demand side resources.
Y+
IRP rules for gas utilities are here.
http://apps.leg.wa.gov/WAC/default.aspx?cite=480
A
-90-238
ffective energy efficiency as a resource
N
Avista Corp. staff memo UG-090052
Y
http://www.wutc.wa.gov/rms2.nsf/177d98baa5918
c7388256a550064a61e/f3bda44463ed617a88257
WAC 480-90-238 (3)(b) requires integrated
resource planning for gas utilities to assess
conservation potential.
Y
Cascade Natural Gas 2008-2010 Conservation
and Low-income Weatherization Plan includes
detailed description of low-income programs and
goals, available at
Y http://wutc.wa.gov/rms2.nsf/177d98baa5918c7388
256a550064a61e/6c09629d4be2f5ce882572d500
60bae5!OpenDocument
Funding requirements are developed on a utility-
by-utility basis.
N
As required by Docket No. UG-060256, Cascade
Natural Gas 2008-2010 Conservation and Low-
income Weatherization Plan includes description
of low-income programs and goals: 2008
Targeted Annual therm savings range between
285,500 to 385,750.
Y
Cascade's conservation plan including goals is
available at
http://wutc.wa.gov/rms2.nsf/177d98baa5918c7388
256a550064a61e/6c09629d4be2f5ce882572d500
60bae5!OpenDocument; 19.285 RCW "Energy
Independence Act" is available at
http://apps.leg.wa.gov/RCW/default.aspx?cite=19.
285; Docket No. UG-060256, available at
available at
http://www.wutc.wa.gov/rms2.nsf/035319dd75df58
ee8825706c0082540d/c7d3541678a5fa5d882571
150082fa7a!OpenDocument-
Decoupling pilot project authorized in 2007 for
Cascade requires conservation targets and sets
a, c,
penalties based on performance.
d
Cascade Natural Gas 2008-2010 goals, available
Cascade 2008 Targeted Annual therm savings
range between 285,500 to 385,750
Cascade Natural Gas 2008-2010 goals, available
Utility-by-utility.
N
N Utility-by-utility.
UG-060256 Cascade and UG-060518 Avista
Y
N
Utility-by-utility.
N
N
a
Y
a, b
Y
Northwest Energy Efficiency Taskforce and
Northwest Energy Efficiency Alliance
Y
Y
Cascade; Avista; Puget Sound Energy; Northwest
Natural Gas
N
eliver energy efficiency where cost-effective.
RCW 80.28.303 allows electrical, gas, or water
company to file a conservation service tariff with
the commission to recoup costs.
Y
RCW 80.28.303 is available at
http://apps.leg.wa.gov/RCW/default.aspx?cite=80.
28.303; see commission website at
http://www.wutc.wa.gov/webimage.nsf/8d712cfdd4
796c8888256aaa007e94b4/0b2e39343c0be04a88
256a3b007449fe!OpenDocument.
Avista uses a tariff rider. For Cascade Natural Gas
and Northwest Natural Gas, recovery occurs through
annual Purchase Gas Adjustment filings.
a, b
RCW 80.28.303 is available at
http://apps.leg.wa.gov/RCW/default.aspx?cite=80.
28.303; see commission website at
http://www.wutc.wa.gov/webimage.nsf/8d712cfdd4
796c8888256aaa007e94b4/0b2e39343c0be04a88
256a3b007449fe!OpenDocument.
N
N
EE program spending in 2008 was $18.9 million,
0.9% of IOU natural gas revenue.
1%
N
cost-effective energy efficiency and modify ratemaking
Avista (Docket No. UG-060518) and Cascade
Y
(Docket No. UG-060256)
In 2007, the Commission authorized Cascade
Natural Gas and Avista to implement partial
decoupling through designated pilot programs.
a Docket No. UG-060518 refers to Avista case;
Docket No. UG-060256 refers to Cascade Natural
Gas' rate case.
Avista, Docket No. UG-060518, available at
http://www.wutc.wa.gov/rms2.nsf/frm2005VwFiling
Web?OpenForm&vw2005L4FilingID=060518&NA
V=0204060000CatL206CatL30605CatL4CatL5Cat
L6CatL7; Cascade, Docket UG-060256, available
at
http://www.wutc.wa.gov/rms2.nsf/035319dd75df58
ee8825706c0082540d/c7d3541678a5fa5d882571
150082fa7a!OpenDocument-
Avista (Docket UG-060518) and Cascade (Docket
UG-051651) decoupling pilots
Y
Avista Docket UG-060518:
Y
Y
N
N
WYOMING
Electric
Recommendation 1: Recognize energy efficiency as a high priority energy resource.
EE is established as a high priority Utilities offer some EE programs, but EE is
resource, equivalent or superior to supply N not required in statute or order.
1.1 resources
1.2.1 EE is integrated into an active IRP, Many utilities do IRP, but there is no formal
portfolio management, or other planning requirement. Degrees of EE integration into
process IRPs vary by utility. The WY PSC will
Y- consider a rule requiring electric and gas
utilities to undertake IRP in 2009.
1.2
1.2.2 Efficiency is procured as a resource
for default service/standard offer customers N
EE is an alternative to transmission based
on a long-term transparent IRP or N
1.3 transmission system plan
1.4.1 EE is a biddable commodity N
1.4.2 Bids occur in the following markets:
1.4 (a) energy, (b) capacity, or (c) other
State Implementation Plans (SIPs) include
N
1.5 EE set-asides
Recommendation 2: Make a strong, long-term commitment to implement cost-effective energy efficiency
Efficiency commitment is in statute N
2.1
The Commission has previously accepted
all of the standard tests, including TRC. No
specific test is required. The TRC test was
Y-
used in the DSM programs approved for
2.2 The TRC or Societal Cost Test is used to Rocky Mountain Power on 10/2/08.
evaluate EE programs
Docket 20000-264-EA-06, Final Order,
10/2/08:
http://psc.state.wy.us/htdocs/orders/20000-
2.3.1 Potential for cost-effective EE has Utilities are required to provide the expected
been established through a potential study program benefits and the evidence and
reasons for the expectations when they
N submit proposed DSM programs to the
Commission. However, a statewide
potential study of all cost-effective EE has
2.3 not been done.
2.3.2 Established EE programs reach all Several utilities offer programs for
customer classes residential, commercial, and industrial
N customers. Rocky Mountain Power's DSM
programs approved on 10/2/08 will reach
those customer classes, as well as low-
income customers.
Funding requirements for all long-term, cost-
effective EE have been established
N
2.4
2.5.1 Quantitative MW and MWh savings The DSM plans approved for Rocky
goals have been established and are Mountain Power on 10/2/08 state that the
producing incremental investment. utility will seek to meet or exceed the energy
N savings forecasted in the application, but
that the programs will continue regardless of
the energy savings achieved, as long as
they continue to be cost-effective.
Docket 20000-264-EA-06, Final Order, and
Stipulation, 10/2/08:
http://psc.state.wy.us/htdocs/orders/20000-
R
264-18102.htm;
http://psc.state.wy.us/htdocs/orders/20000-
264-18102.pdf
2.5.2 Goals are established: (a)
2.5 connection with IRP or other planning
process; (b) as part of an EEPS or similar
system; (c) as part of program approval and
budget-setting process; (d) other
2.5.3 Energy Efficiency can be used to
fulfill requirements of an RPS or similar N
standard
2.5.4 Expected Capacity Savings 2006
(Annual MW)
2.5.5 Energy Savings Goals 2006 (Annual
MWh or MTherms)
2.6.1 A robust M&V process has been M&V is dealt with on a case-by-case basis
established during each utilities' DSM filings. Rocky
Mountain Power's approved DSM plan
requires yearly evaluations conducted by an
N independent third party; the evaluations
must include the kWh saved, the kW saved,
the participation rate, the take rates, all with
sufficient detail to show each program's
cost-effectiveness.
Docket 20000-264-EA-06, Final Order, and
Stipulation, 10/2/08:
http://psc.state.wy.us/htdocs/orders/20000-
264-18102.htm;
http://psc.state.wy.us/htdocs/orders/20000-
264-18102.pdf
2.6.1.1 M&V is adequately funded
2.6
2.6.1.2 Energy savings are used to
Y
measure performance
2.6.1.3 M&V is done according to a
Y
defined schedule
2.6.1.4 M&V is conducted by an
Y
independent party
2.6.1.5 Review of M&V is done in a
Y
transparent process
2.6.2 M&V is done using: (a) deemed
savings; (b) actual savings; (c) other
2.7.1 EE delivery structure has been Delivery structure has not been established
established N by statute or order, but some utilities
undertake DSM programs.
2.7 2.7.2 Delivery is via: (a) utility
administration; (b) third-party administration; a, b
or (c) government agency
Resource plans are regularly updated There is no requirement for all utilities to
produce resource plans or regularly update
N
2.8 them. However, the PSC will consider a
rule regarding IRPs in 2009.
2.9.1 Building Energy Codes for residential 1989 MEC may be adopted and enforced by
buildings are in place and regularly updated N/N local jurisdictions.
2.9
http://bcap-
energy.org/state_status.php?state_ab=WY
2.9
2.9.2 Building Energy Codes for 1989 MEC may be adopted and enforced by
commercial buildings are in place and N/N local jurisdictions.
regularly updated
http://bcap-
energy.org/state_status.php?state_ab=WY
Appliance and Equipment Efficiency
Standards are in place and regularly N
2.10
updated
Energy efficiency is a high priority in state There are communities in Wyoming that
buildings and state funded buildings as have adopted energy efficiency action plans
N
evidenced in capital planning and enabling where goals have been established to
2.11 performance contracts improve energy efficiency in buildings and
Recommendation 3: Miscellaneous Policies
3.1.1 Public education programs on EE are
in place. (See Guide Tab for Y/N criteria.) Y
3.1.2 Process is in place, such as a state
or regional collaborative, to pursue EE as a
N
3.1 high-priority resource. (See Guide Tab for
Y/N criteria.)
Do not delete this row.
Do not delete this row.
Do not delete this row.
Do not delete this row.
Do not delete this row.
75% of state access to ENERGY STAR
Y
3.2 New Homes
What proportion is due to regulated utility
program? (who is sponsor) Performance
75% of state access to Home
with ENERGY STAR? N
What proportion is ue to regulated utility
program? (who is sponsor)
Recommendation 4: Promote sufficient, timely, and stable program funding to deliver energy efficiency w
4.1.1 Cost recovery process exists Cost recovery is done on a case-by-case
basis. Montana-Dakota Utilities has a
conservation tracking adjustment approved
in 2006. DSM programs were approved for
Rocky Mountain Power on 10/2/08; the
costs will be recovered through a rate
surcharge that will be set separately for
residential, small commercial, and large
Y-
industrial groups. No customer may opt out.
Each year, the programs' cost-
effectiveness will be reassessed, changes
to the programs may take place, and the
surcharge may be adjusted for the future
year's programs, as well as to account for
over- or under-collected amounts.
Rocky Mountain Power: Docket 20000-264-
EA-06, Final Order, and Stipulation, 10/2/08:
http://psc.state.wy.us/htdocs/orders/20000-
4.1 R 264-18102.htm;
http://psc.state.wy.us/htdocs/orders/20000-
264-18102.pdf
4.1.2 Recovery occurs via: (a) rider; (b)
regular rate case; or (c) system benefits a
charge
4.1.3 Funding is for multi-year periods Rocky Mountain Power's DSM programs,
approved on 10/2/08, provide for funding of
Y about $25 million from 10/1/08 to 7/1/2012,
as long as the programs remain cost-
effective.
Rocky Mountain Power: Docket 20000-264-
EA-06, Final Order, and Stipulation, 10/2/08:
http://psc.state.wy.us/htdocs/orders/20000-
264-18102.htm;
http://psc.state.wy.us/htdocs/orders/20000-
264-18102.pdf
A base energy efficiency spending level
4.2 exists, with opportunity to justify higher level
% of net (retail) utility revenue presently
used for energy efficiency [no unit = %; m/k
4.3 = mils/kWh]
Funds from carbon trading program support
4.4
Recommendation 5: Modify policies to align utility incentives with the delivery of cost-effective energy effi
5.1.1 Utility throughput incentive is The Commission has generally allowed
addressed and disincentives are removed provisions for recovery of lost revenues as
part of the cost recovery process. Actual
Y- mechanisms vary by utility. See Section 4.1.
5.1
5.1.2 Method used is: (a) decoupling; (b)
lost revenue recovery; or (c) non-utility b
implementaion of EE
5.2.1 Utility/shareholder EE incentives are
N
provided
5.2 5.2.2 Incentives exceed amount of lost
revenues
5.3.1 Impact on EE is a consideration
N
when designing retail rates
5.3 5.3.2 Declining block rates and fixed Declining block rate structures have been
variable rate designs have been eliminated N addressed in some, but not all electric
utilities.
5.4.1 Time sensitive rates in place Some utilities have TOU rates in place for
Y
some customers.
5.4.2 Usage sensitive rates in place Y
5.4 5.4.3 AMI deployment planned N
5.4.4 Other mechanisms exist (e.g., on-bill
financing, benefit sharing)
State Fiscal Policy
Sales Tax reduction or exemption for
N
- energy efficient products
Investment Tax Credit for energy efficient
N
- investments
State supported low cost financing for
energy efficient investments: buildings (x), N
- equipment (y)
Distributed Generation Policies
A statewide interconnection policy is in place WY has interconnection requirements in
their net metering law - Wyo. Stat. § 37-16-
101 et seq. Systems up to 25 kW that
generate electricity using solar, wind
hydropower or biomass resources are
eligible to interconnect. Systems must
comply with NEC, IEEE, and UL standards.
Y-
Customers must install an external
disconnect switch. Additional liability
insurance is not required. All utilities in the
state have their own interconnection
7.1 agreement forms modeled after the one
developed by Rocky Mountain Power.
Wyo. Stat. § 37-16-101 et seq. can be
accessed here,
http://legisweb.state.wy.us/statutes/statutes.
aspx?file=titles/Title37/T37CH16.htm and
S Rocky Mountain Power's interconnection
agreement can be found here,
http://www.rockymountainpower.net/File/File
78687.pdf
A statewide net metering policy is in place WY's net metering law - Wyo. Stat. § 37-16-
101 et seq, applies to IOUs and electric
cooperatives. Eligible technologies under
the legislation are solar, wind, hydropower
and biomass systems up to 25 kW. There is
Y no limit on overall enrollment of net metered
systems. NEG is credited to the next month.
7.2 At the end of an annual period, a utility will
purchase unused credits at the utility's
avoided cost rate.
Wyo. Stat. § 37-16-101 et seq. can be
accessed here,
S
http://www.dsireusa.org/documents/Incentive
s/WY02R1.htm
A statewide exit fee policy is in place
7.3
A statewide standby rate policy is in place Wyoming does not have a statewide policy
N
on standby rates
7.4
PacifiCorp - Schedule 33 - standby service
is provided through a contract with the
utility. A high customer charge and a
relatively high reservation charge is
assessed every month based on the
contract demand. Actual usage is based on
7.4 very low energy charges and a moderate
U- demand charge that is based on the two
maximum demand of the month with a 12
month ratchet. There is a very high penalty
for exceeding the contract demand. Rate
available at:
http://www.rockymtnpower.net/Article/Article
1997.html
As part of resource planning process, CHP WY does not currently have a formal IRP
is reviewed and incorporated where effective N process.
Pacificorp's IRP for WA state was also filed
7.5
U+ with the WY PSC, it does assess CHP and
incorporates it where effective.
http://psc.state.wy.us/htdocs/dwnload/irp/2007Paci
Natural Gas
urce.
Utilities offer some EE programs, but EE is not
N required in statute or order.
Questar Gas Company files an IRP in WY. The
WY PSC will consider a rule requiring electric and
gas utilities to undertake IRP in 2009.
Y-
N
N
N
N
effective energy efficiency as a resource
N
The Commission has previously accepted all of
the standard tests, including TRC. No specific test
is required. The TRC test was used in the DSM
Y-
programs approved for Questar Gas Company,
effective July 1, 2009.
Docket No. 30010-94-GR-08, Final Order June
R 17, 2009.
http://psc.state.wy.us/htdocs/orders/30010-94-
Utilities are required to provide the expected
program benefits and the evidence and reasons
for the expectations when they submit proposed
N DSM programs to the Commission. However, a
statewide potential study of all cost-effective EE
has not been done.
Some utilities offer programs for residential,
commercial, and industrial customers, but not low-
N income customers (Questar Gas Company's
DSM programs effective July 1, 2009; Montana
Dakota Utilities' programs effective August 28,
2006).
N
N
M&V is dealt with on a case-by-case basis during
each utilities' DSM filings. Questar Gas
Company's approved DSM plan requires the
company to report semi-annually. Montana
N Dakota Utilities is required to report annually. The
reports must include the Dth savings, the take
rates, etc, all with sufficient detail to show each
program's cost-effectiveness.
Docket No. 30010-94-GR-08
http://psc.state.wy.us/htdocs/orders/30010-94-
18687.htm Docket
No. 30013-166-GT-05
http://psc.state.wy.us/htdocs/orders/30013-166-
16278.htm
Y
Y
Y
Y
Delivery structure has not been established by
N statute or order, but some utilities undertake DSM
programs.
a, b
There is no requirement for all utilities to produce
resource plans or regularly update them.
N
However, the PSC will consider a rule regarding
IRPs in 2009.
There are communities in Wyoming that have
adopted energy efficiency action plans where
N
goals have been established to improve energy
efficiency in buildings and facilities in the
Y-
N
deliver energy efficiency where cost-effective.
A 2006 Order in Docket No. 30013-166-GT-05
approved cost recovery for Montana Dakota
Utilities gas conservation programs via a tariff
rider. http://psc.state.wy.us/htdocs/orders/30013-
166-16278.htm. Questar Gas will begin DSM
programs on 7/1/09.
Y-
a
Questar Gas Company's DSM programs have an
annual budget.
N
No. 30010-94-GR-08 Questar Gas Company.
http://psc.state.wy.us/htdocs/orders/30010-94-
18687.htm
cost-effective energy efficiency and modify ratemaking
In Docket No. 30013-166-GT-05, MDU had
requested lost revenue recovery for natural gas
distribution sales lost to conservation programs.
N The request was later revised and the lost
revenue request was dropped.
N
N
N
N
N
N
N
