ENERGY EFFICIENCY POLICY MANUAL

Version 6

April 2020

Applicable to post-2018 Energy Efficiency Programs

Table of Contents

(Click on each heading to access that part of the document)

i. Introduction

ii. How to Use this Document

iii. Common Terms and Definitions

I. Energy Efficiency Policy Objectives

1. Energy Efficiency as a Procurement Resource

2. Energy Savings Goals

3. Implementation of California Energy Efficiency Strategic Plan

4. Energy Efficiency Program Design

5. Program Portfolio Development, Balance and Management

6. Integrated Demand Side Management

7. Emerging Technologies

8. Codes and Standards

9. Marketing, Outreach and Education

10. Competitive Bidding for Third Party Programs

11. Local Government and Institutional Partnerships

12. Pilot Programs

II. Funding Guidelines for IOUs

1. Energy Efficiency Funds from Procurement and Gas Surcharge

2. Cost Caps and Targets

3. Fund Shifting Rules (See Appendix A)

4. Funding Business Plans

 
 
 
 
 Shared Funding and Funding for Evaluation, Measurement, & Valuation 
(EM&V) 
        Treatment of Unspent Funds from Prior Portfolio Cycles 
 Program Cancellation 
III.  Regional Energy Networks & Community Choice Aggregators 
 Regional Energy Networks 
 Community Aggregators 
 Business Plans 
 Implementation Oversight and Reporting Requirements 
 Threshold of Review 
 Program Cost-Effectiveness Threshold 
 Community Choice Aggregator (CCA) and Regional Energy Network (REN) 
Funding  
 Evaluation, Measurement and Verification Requirements 
IV.  Cost-Effectiveness 
 Standard Practice Manual (SPM) 
 Total Resource Cost Test (TRC) 
 Program Administrator Cost Test (PAC) 
 Application of the TRC and the PAC, the Dual-Test 
 Overall Cost-Effectiveness of Investor Owned Utilities (IOU), REN, and CCA 
Portfolios 
 Avoided Costs and Other Inputs 
 Cost-Effectiveness Adjustments for Free-Ridership & Market Effects 
 Portfolio Filing of Prospective Cost Effectiveness 
 Common Sector Level Metrics  
 Cost Sharing & Cost-Effectiveness Across Utility Service Territories 
 Cost Effectiveness Requirements for Fuel Substitution Programs 

 
 
 
 
 Mid-Cycle Funding Augmentations  
 References 
V.  Implementation Oversight and Reporting Requirements 
 Program Reporting Requirements 
 Business Plans and Annual Budget Advice Letters  
 Counting of Savings 
VI.  Ex Ante Savings and Review 
 CPUC Oversight of Ex Ante Values 
 Database of Energy Efficiency Resources (DEER) and Non-DEER Measures 
and Workpapers 
 Freezing of Ex Ante Values 
 Mid-year updates of Ex Ante Values  
 Ex Ante Review of Non-DEER Measures 
 Installation Rate for DEER and non-DEER Measures 
 Establishment of Baseline for use in Establishing TRC Savings and Costs. 
 Custom Projects 
 Heating Ventilation and Air Conditioning (HVAC) Interactive Effects 
 Persistence of Savings 
 Gross Realization Rate 
 Statewide Workpapers 
VII.  Evaluation, Measurement and Verification (EM&V) 
  Purpose of EM&V   
  IOU and Energy Division (ED) Collaboration on EM&V Plan   
  Energy Division Role in EM&V Administration   
  IOU Role in EM&V Administration   
  ED Role in IOU-led Studies   

6. IOU Role in ED-led Studies

7. Dispute Resolutions

8. Public Vetting Process

9. EM&V in the Rolling Portfolio

VIII. Shareholder Incentive Mechanism

1. Incentive Mechanism Criteria.

2. Energy Savings and Performance Incentive (ESPI) Categories

3. Scaling Incentive Earnings Potential for Resource Savings

4. Ex Ante Review Performance Scoring

5. Uncertain Measures

6. Calculating Resource Savings Incentive Awards

7. Verification of Expenditure and Claims Data

8. Resource Savings Claim and Expenditure Eligibility

9. Approval of Incentive Claims

10. Dispute Resolution of Ex Post Evaluations

11. References

IX. Third Party Solicitation Process

1. The Two Stage Solicitation Process

2. Scoring Solicitations

3. Solicitation Schedule

4. Energy Division Review of Solicitations

5. Independent Evaluator’s Role in Solicitation Process

6. Workforce Standards

X. Advisory Groups

1. California Energy Efficiency (EE) Advisory Coordinating Committer (CAEECC)

2. Procurement Review Groups (PRGs)

XI. Affiliate & Disclosure Rules

1. Transactions with IOU Affiliate

2. Treatment of Energy Efficiency Service Providers

3. Conflict of Interest

XII. Process & Procedural Issues

1. Energy Efficiency Policy Manual Disclaimer

2. Modifications to Rules or Existing Policy

3. Complaints and Dispute Resolution

APPENDIX A: Adopted Fund Shifting Rules

APPENDIX B: Glossary

APPENDIX C: Cost Categories, Related Cap, and Targets

APPENDIX D: Phase 2 Workpaper Review

ENERGY EFFICIENCY POLICY MANUAL Version 6.0

FOR POST-2018 PROGRAMS

Introduction

This document presents the California Public Utilities Commission’s (CPUC’s) policy rules and

related reference documents for the administration, oversight, and evaluation of energy

efficiency (EE) programs funded by ratepayers in California. The purpose of the Energy

Efficiency Policy Manual is to provide the most up to date list of the rules established by

Commission Decisions and Resolutions that govern the administration of energy efficiency

programs. This manual enumerates standing Commission rules that continue to apply to the

current portfolio even as subsequent decisions supersede past rules. Version 6.0 shall apply to

all energy efficiency activities commencing in program year (PY) 2018 and beyond. The policy

rules, terms and definitions contained herein pertain to efficiency activities funded through the

following mechanisms:

• The gas public purpose program (PPP) surcharges, as authorized by §890- 900.

• Electric procurement rates, as authorized by the Commission.

The rules in this policy manual, unless specifically indicated, apply to all the following entities

that are funded through the mechanisms above and include the four large investor-owned

utilities (and their third party implementers and administrators), including:

o Pacific Gas and Electric Company (PG&E),

o Southern California Edison Company (SCE),

o San Diego Gas & Electric Company (SDG&E) and

o Southern California Gas Company (SoCalGas);

o Community Choice Aggregators (CCA), and

o Regional Energy Networks (RENs)

Chapter III focuses more specifically on the CCA and RENs:

More information on CCAs can be found here:

o https://www.cpuc.ca.gov/general.aspx?id=2567

More information on Regional Energy Networks can be found here (among other EE program

administrator information):

o https://www.cpuc.ca.gov/General.aspx?id=4460

This manual does not address the following programs:

• Energy Savings Assistance Programs for low income customers,

• California Alternative Rates for Energy (CARE) for low-income customers,

• Interruptible rate or load management programs,

• Self-generation and demand-response programs developed in response to Assembly Bill (AB)

970 (§ 399.15(b)), or

• Small and/or Multijurisdictional Utilities (SMJUs).

This document, which supersedes all previous versions of the Energy Efficiency Policy Manual,

provides may of the CPUC’s policy rules (“Rules”) stipulated in CPUC decisions and resolutions that

apply on an ongoing basis to current (circa 2018) and future energy efficiency portfolios. This manual

is compiled by staff and is not formally adopted by the CPUC. As such, it is intended to be a handy

reference for many of the significant and/or more commonly applied efficiency portfolio Rules, but it

is not an exhaustive compilation of all rules developed in CPUC decisions and resolutions that apply

to the energy efficiency portfolios. In addition, while much of the CPUC’s guidance referenced in this

document applies specifically to IOUs who implement and administer EE programs, all program

implementers (including third-party, CCA’s, etc.) should seek to adhere to them as well, unless clearly

exempt, and should confer with the IOU program administrators, who oversee the EE portfolio and

all EE programs, for clarification as needed.

i. How to Use this Document

This document is intended to provide a high-level overview of the significant policies that impact

energy efficiency programs in the State of California as determined by the California Public Utilities

Commission. It does not provide in-depth detail about each policy area but provides a summary and

links to the various regulatory documents that do. The purpose of this document is to provide a

birds-eye view of the relevant policy rules that all energy efficiency program implementers should

know while also providing them the tools and resources needed to develop more expertise in this area

as they see fit. As previously noted, this document should NOT be considered a completely detailed

source of information, in and of itself, but it does provide comprehensive access to all the relevant

policy documents in the form of references and links. While links to all documents referenced in this

document are provided, these documents can also be found on the Commission’s website by typing in

the document number (all letters capitalized with no dashes) in the search bars located here:

https://www.cpuc.ca.gov/documents/#DocTypeSearches

ii. Common Terms and Definitions

Common terms and definitions will facilitate the administration and evaluation of energy efficiency

activities. In particular, program definitions should be designed to facilitate to the extent possible: (1)

the identification of energy efficiency activities by end-use savings potential, (2) the evaluation,

measurement and verification (EM&V) of those activities based on Commission-adopted EM&V

protocols, and (3) the coordination of program administration and evaluation with resource planning

and procurement needs. To this end, all entities subject to these rules and all program implementers

should use the definitions included in Appendix B when characterizing any proposed program activity.

The burden is on them to justify any departure from those definitions.

I. Energy Efficiency Policy Objectives

1. Energy Efficiency as a Procurement Resource. CPUC and State energy policy, as

expressed in the original 2005 Energy Action Plan (EAP) and reaffirmed in Decision (D).04-

12-048, strives to make energy efficiency and demand response the IOUs’ highest priority

procurement resources. The 2008 EAP promotes ongoing support for the loading order and

identifies energy efficiency and demand response as the State’s preferred means of meeting

growing energy needs. After cost-effective energy efficiency and demand response resources,

we rely on renewable sources for power and distributed generation.

This is also consistent

with Pub. Util. Code § 454.5(b)(9)(C),

which requires IOUs to first meet their “unmet energy

resource needs through all available energy efficiency and demand reduction resources that are

cost effective, reliable, and feasible.” In order to promote the resource procurement policies

articulated in the Energy Action Plan and by this CPUC, demand-side energy efficiency

activities funded by ratepayers should offer programs that serve as alternatives to supply-side

resource options (demand-side energy resource programs). By keeping energy resource

procurement costs as low as possible through the deployment of a cost-effective portfolio of

resource programs, over time all customers will share in the resource savings from energy

efficiency. An additional type of EE program are non-resource demand-side programs

http://docs.cpuc.ca.gov/word_pdf/REPORT/51604.pdf

Hereafter all references to code sections are to the Public Utilities Code unless otherwise noted.

designed to promote market sector specific approaches that indirectly reduce energy usage (ex:

marketing, education, and outreach programs)

2. Energy Savings Goals. One of the CPUC’s objectives is to pursue all cost-effective energy

efficiency opportunities over both the short and long term. The CPUC established electricity

and natural gas savings goals, pursuant to Pub. Util. Code § 454.55 and 454.56. In D.04-09-

060, the CPUC first provided numerical goals for electricity and natural gas savings by utility

service territory. The CPUC-adopted energy savings goals are expressed in terms of Gigawatt

hours, million-therms, and peak Megawatt load reductions. These goals are informed by

periodic Energy Efficiency Potential and Goals Studies, and historically were updated in D.08-

07-047, D.09-05-037, D.09-09-047, D.12-05-015, D.12-11-015,and D.17-09-025. Thee most

recent goals decision; D.19-08-034 established goals for 2020 – 2030. Energy Efficiency goals

shall continue to be updated periodically by the CPUC. The IOUs should develop their

energy efficiency program portfolios so that they will meet or exceed these savings goals. The

CPUC’s intent is for goals to:

(1) be appropriately aggressive;

(2) support long-term procurement planning;

(3) encourage a focus on long-term savings;

and

(4) be based on the best available information.

In D.17-09-025, The Decision Adopting Energy Efficiency Goals for 2018 – 2030, the CPUC

adopted energy savings goals for ratepayer-funded energy efficiency program portfolios for

2018 and beyond based on an assessment of economic potential using the Total Resource

Cost test, the 2016 update to the Avoided Cost Calculator, and a greenhouse gas adder that

reflects the California Air Resources Board Cap-and-Trade Allowance Price Containment

Reserve Price. The CPUC also deferred the adoption of cumulative goals until the California

Energy CPUC develops a method for calculating savings persistence and CPUC staff assesses

the viability of that method for the purpose of EE goals.

D.04-09-060 at 3

D.04-09-060 at 35

D.07-10-032 at 5

D.08-07-047 at 18-19

Goals for the 2018 - 2030 portfolio cycle will be applied on the following basis:

a. Energy savings goals are based on achieving 100 percent of incremental market

potential identified in the most recent Potential Study for both gas and electric

savings.

b. Separate energy savings goals were adopted for IOU Codes and Standards (C&S)

advocacy. The C&S advocacy category represents the estimated energy savings

forecasted for the Title 20 and 24 updates and federal appliance standards that

can be attributed to the IOUs’

C&S advocacy program (D.12-11-015, pp. 56-58).

c. Energy savings goals are set on a “net basis.” (D.16-08-019, p. 19).

d. The CPUC intends to develop a better understanding of the sustained impact of

the utility programs (including decay and market transformative effects) to

encourage programs that will have lasting impacts and to hold IOUs accountable

for long-term savings in future portfolios. (D.12-05-015 at 95.)

3. Implementation of the California Long-Term Energy Efficiency Strategic Plan. D.07-

10-032 established a broader framework for statewide coordination on energy efficiency

program design, in order to overcome market barriers to more widespread adoption of energy

efficiency and to capture longer-term savings. The decision directed the IOUs to work with

CPUC staff and market participants to prepare the California Long-Term Energy Efficiency

Strategic Plan (Strategic Plan). Adopted in D.08-09-040, the Strategic Plan set forth a roadmap

for energy efficiency in California through 2020 and beyond, by articulating a long-term vision

and goals for each market sector and identifying specific near-term, mid-term and long-term

strategies to achieve the goals. (The Strategic Plan can be viewed at

http://www.cpuc.ca.gov/NR/rdonlyres/D4321448-208C-48F9-9F62-

1BBB14A8D717/0/EEStrategicPlan.pdf

The Potential Study can be viewed at http://www.cpuc.ca.gov/PUC/energy/Energy+Efficiency/Energy+Efficiency+Goals+and+

Potential+Studies.htm

D.08-09-040 and the subsequent October 30, 2008 Ruling in A.08-07-021 directed the IOUs

to align their programs with Strategic Plan goals by clearly identifying utility actions for all

Strategic Plan near-term strategies and action steps, where a utility role is important, and to

provide programs that reflect the Strategic Plan short-term steps and milestones. (D.08-09-

040, ordering paragraph 2.)

i. Among the market strategies identified as necessary to achieve market

transformation, the Strategic Plan established three long-term goals for

energy efficiency:

• All new residential construction in California will be zero net energy by

2020;

• All new commercial construction in California will be zero net energy

by 2030; and

• The Heating, Ventilation, and Air Conditioning (HVAC) industry will

be reshaped to ensure optimal equipment performance

ii. The Strategic Plan expanded the CPUC’s objectives for the energy

efficiency portfolios to also pursue market transformation, which was

defined as “long-lasting sustainable changes in the structure or

functioning of a market achieved by reducing barriers to the adoption of

energy efficiency measures to the point where continuation of the same

publicly-funded intervention is no longer appropriate in that specific

market. Market transformation includes promoting one set of efficient

technologies until they are adopted into codes and standards (or

otherwise adopted by the market), while also moving forward to bring

the next generation of even more efficient technologies to the market.”

(D.09-09-047 at 354.)

4. Energy Efficiency Program Design. D.15-10-028 established a “Rolling Portfolio”

process for regularly reviewing and revising portfolios. Central to the rolling portfolio cycle

framework is the rolling portfolio schedule. This schedule is described in Attachment 5 and 6

in D.15-10-028.

IOUs, CCAs, and RENS must use the same process for program design.

For example

program related business plans must be submitted

for CPUC review and

approval and revised if prompted by certain triggers as described in D.15-10-028. p. 56-57.

Existing plans (prior to the adoption of D.15-10-028) do not need a new application until they

have one year of funding left for the corresponding program. The IOUs should implement

statewide programs in order to achieve economies of scale and employ industry best

practices.

5. Program Portfolio Development, Balance and Management. The most appropriate

program design and balance of program funding across market sectors (e.g., residential,

industrial, commercial) should be based on maximizing cost-effective long-term savings. D.07-

10-032 directed the IOUs to work with stakeholders, including the CPUC and the California

Energy Commission (CEC) staff as well as market participants, to encourage the application of

best practices, portfolio diversity and innovation.

IOUs are expected to coordinate to develop

and manage statewide programs, in order to avoid duplications of efforts and promote

innovation and good program management. IOUs should also include a selection of non-

resource programs such as statewide marketing and outreach programs, information and

education programs, workforce education and training, emerging technologies programs and

other activities in their proposed portfolios that support the CPUC’s short-term and long-

term energy savings goals. Non-resource programs also help in achieving Strategic Plan

objectives. Lastly, the IOUs have been directed by the CPUC to utilize a percentage of their

program funding for third party designed and implemented programs. D.18-01-004, modified

by D.18-05-041 requires the IOUs to use at least 25 percent of their program funding for third

parties by PY 2020, 4 percent by PY 2021, and 6 percent by 2023.

6. Integrated Demand Side Management. In order to achieve maximum savings while

avoiding duplication of efforts, reducing transaction costs, and diminishing customer

confusion, the IOUs are required to integrate customer demand side programs, such as energy

efficiency, self-generation, advanced metering, and demand response in a coherent and

efficient manner. Integrated demand side management (IDSM) is identified in the Strategic

Plan as an overarching strategy to promote customer-side energy management and

achievement of zero net energy goals.

In Ordering Paragraph (OP) 10 of D.18-05-041, the

CPUC directed that a set amount of the IOUs’ IDSM budget shall focus on the integration

between energy efficiency and demand response. The CPUC also has related work on

2013-14 Portfolio cycle program guidance provided in D.12-05-15 and D.12-11-015 for RENs, and D.14-01-033

for CCAs

In D.07-10-032 at 31

D.09-09-047, p. 214

Integrated Distributed Energy Resources (IDER) with more information available at

https://www.cpuc.ca.gov/IDER.

7. The Emerging Technologies Program (ETP). ETP supports EE program uptake of cost-

effective new and underutilized commercial technologies. In order to filter this uptake, ETP is

primarily engaged in technology evaluation with a focus on achieved savings and cost-

effectiveness via the ETP Technology Assessment subprogram. In this capacity, ETP both

identifies suitable technologies for program inclusion and eliminates unsuitable technologies

from consideration. Technologies with positive evaluation results are then recommended for

inclusion into the portfolio and passed off to EE resource programs for workpaper

development. To support the technology intake process, the ETP Technology Development

Support subprogram works with technology development actors to support their engagement

with ETP and IOU programs and gather information about current and upcoming technology

innovations. ETP also holds annual or semi-annual ET Summits to encourage discussion and

knowledge sharing. The Technology Introduction Support subprogram engages in work

intended to smooth the transition of technologies into EE programs and subsequently into the

market. D.18-05-041, Attachment A, requires the IOUs to initiate Technology-focused Pilots,

which will be ETP’s first efforts at accelerating high-priority technologies into the market by

identifying technology-specific market barriers and initiating market barrier breakdown

activities. Along with this expanded scope, ETP is expanding its role as a technology

communications hub spanning from R&D to C&S in California with several tools, including

the Technology Priority Maps and an updated dissemination website (https://www.etcc-

ca.com/).

8. Codes and Standards (C&S). In order to ensure that energy efficiency programs support the

adoption of higher efficiency standards rather than compete with them, the IOUs shall

implement programs to advocate for the adoption of higher codes and standards. D.12-05-015

established separate goals for codes and standards and affirmed that 100 percent of verified

net savings shall count toward meeting these goals. The baseline for gross savings should be

the previous standard or the prevailing market practice. The purpose of Codes and Standards

goals is to give the IOUs credit for their specific contributions to new energy savings via their

Codes and Standards advocacy work, which should not include naturally occurring savings or

the advocacy work of other entities.

9. Marketing Outreach and Education (ME&O). In the CPUC’s Proceeding A.12-08-007

directs the IOUs to implement the statewide Marketing, Education, and Outreach program

called “Energy Upgrade California”, which encourages Californians to save energy, and

informs them about time-of-use rates. For more information go to

https://www.energyupgradeca.org/ .

10. Competitive Bidding for Third Party (3P) Programs. Competitive solicitations help to

identify innovative approaches or technologies for meeting savings goals with improved

performance that might not otherwise be identified during the program planning process, and

can take advantage of the unique strengths that third parties bring to the table. The IOUs shall

propose a portfolio of programs that reflects the continuation of successful IOU and non-

IOU designed and implemented programs. As part of that process, the IOUs will solicit

competitive bids from third parties for the purpose of soliciting innovative ideas and proposals

for improved portfolio performance. Please see section IX for a more detailed description of

the CPUC adopted rules associated with IOU third party solicitations.

11. Local Government and Institutional Partnerships. Local Government Partnerships

(LGPs) are partnerships between an IOU and a Lead Local Partner (LLP), which could be a

city, county or region for the purpose of engaging local governments to promote demand side

management (DSM) activities. Specifically, LGPs are designed to generate energy and demand

savings within their own facilities and in their communities through joint utility-local

government program designs that incorporate utility offerings and local government

leadership, take actions that support the California Energy Efficiency Strategic Plan, leverage

their local government role/authority, and provide DSM outreach in the community. Pursuant

to D.12-05-015, beginning in the 2013-2014 cycle, new candidate partners must also adhere to

deep retrofit criteria, as defined in the IOUs' program implementation plans.

12. Pilot Programs. Pilot programs should be designed to create the measures and program

delivery mechanisms of the future, enabling EE programs to achieve deeper savings and

market transformation. The pilots should be limited in scope and duration so that results are

available in a specified time frame and limited in budget so that unsuccessful programs have a

minimal impact on the overall portfolio. All results of pilot programs must be shared widely

with the other program implementers and with the stakeholders in the sector impacted by the

pilot. There should be a specific plan and timeframe to move successful pilot programs into

statewide use (if applicable), or other more significant program efforts.

Each proposed pilot should contain the following elements

D.09-09-047 at 48-49

i. A specific statement of the concern, gap, or problem that the pilot seeks

to address and the likelihood that the issue can be addressed cost-

effectively through utility programs;

ii. Whether and how the pilot will address a Strategic Plan goal or strategy and

market transformation;

iii. Specific goals, objectives and end points for the project;

iv. New and innovative design, partnerships, concepts or measure mixes that

have not yet been tested or employed;

v. A clear budget and timeframe to complete the project and obtain results

within a portfolio cycle - pilot projects should not be continuations of

programs from previous portfolios;

vi. Information on relevant baselines metrics or a plan to develop baseline

information against which the project outcomes can be measured;

vii. Program performance metrics (see Section 4.6.3);

viii. Methodologies to test the cost-effectiveness of the project;

ix. A proposed EM&V plan; and

x. A concrete strategy to identify and disseminate best practices and lessons

learned from the pilot to all California IOUs and to transfer those practices to

resource programs, as well as a schedule and plan to expand the pilot to utility

and hopefully statewide usage.

II. Funding Guidelines for IOUs

These guidelines provide the IOUs with ways to be compensated for their energy efficiency programs.

1. Energy Efficiency Funds from Electric Procurement Rates and Gas Public Purpose

Program (PPP) Surcharges. Pursuant to § 381, 381.1, 399 and 890-900, gas PPP surcharge

and/or electric procurement funds must be spent to deliver energy efficiency benefits to

ratepayers in the IOU service territory from which the funds were collected. Gas PPP surcharge

and/or electric procurement collections must fund energy efficiency programs that benefit gas

and/or electric customers within an IOU's service territory, as adopted by the CPUC. However,

nothing in these Rules is intended to prohibit or limit the ability of the CPUC to direct the

IOUs to jointly fund selected measurement studies, statewide marketing and outreach programs,

or other EE programs and activities that reach across service territory boundaries that serve

statewide energy efficiency efforts.

2. Cost Caps and Targets. All IOUs shall reflect all costs associated with the delivery of their

energy efficiency programs in their submissions in the EE portfolio annual budget advice letters

(ABAL) as stated in D.18-05-041 and shall note, where applicable, when the costs are recovered

in other proceeding. Costs shall reflect the caps and targets defined in D.09-09-047 and clarified

in D.12-11-015 (D.09-09-047, pg. 49).

Administrative cost definitions are further delineated in

Appendix C of this manual.

i. Administration – Administrative costs for utility EE programs

(excluding non-IOU third party and/or government partnership

budgets) are limited to 10 percent of total EE budgets. These costs

shall be inclusive of any energy efficiency-related costs authorized and

collected in other proceedings. These costs should also reflect the fully-

loaded personnel costs of delivering EE programs and shall also note

where the costs have been or will be recovered elsewhere to avoid

double counting of costs. Administrative costs shall be consistent

across IOUs and can only be shifted into other cost categories subject

to the fund shifting rules as described in D.15-10-028. The IOUs shall

not reduce the non-utility portions of government partnership and

third-party implementer administrative costs without following

authorized fund shifting guidelines subject to the fund shifting

guidelines in Appendix A. (D.09-09-047, pg.369.)

ii. Marketing, Education, & Outreach (ME&O) – ME&O cost

targets for energy efficiency are set at 6 percent of total adopted EE

budgets, subject to the fund-shifting rules in Rule II.3 and Appendix A.

iii. Direct Implementation Non-Incentive (DINI) -- DINI costs are

defined in Appendix C as resource program delivery support costs and

shall have a target value set at 20 percent of the total adopted energy

efficiency budgets.

The IOUs are required to minimize their non-

incentive budgets as much as possible to achieve savings targets (D.12-

This target was adopted for 2010-12 cycle in D.09-09-047 at 6, at 74, and OP 13c and re-iterated for the 2013-14

cycle. D.12-11-015 at 98 states “This provision of D.09-09-047 is still in effect and has not been superseded,

though the target is also not met by the proposed portfolios. We find that such a target is still reasonable for 2013-

2014.”

11-015, pg. 101).

iv. Local Government Partnerships and Third Party Programs – The

utilities will seek to limit administrative costs of third party and local

government partnership direct costs to 10 percent, striving for an

entire cost cap of 10 percent. This amount is separate from utility costs

to administer these programs (D.09-09-047, pg. 63).

v. The utility PAs shall ensure that their EE portfolios contain third party

designed and implemented programs funded as a percentage of each IOU’s

overall EE budget utilizing the following schedule and budget amount by the

end of each given year: 25 percet by 2019, 40 percent by 2020, and 60 percent

by 2022. These PAs shall file a Tier 2 advice letter for each third party contract,

or a batch of third party contracts, that is valued at $5 million or more and/or

with a term of longer than three years for Commission review (D.18-01-004,

pg.61, and D.18-05-041).

3. Fund Shifting Rules. D.15-10-028 modifies prior fund-shifting rules established in D.12-11-

015, the December 22, 2011 Assigned Commissioner’s Ruling (ACR) in R.09-11-014, D.09-09-

047, D.09-05- 037, D.07-10-032, D.06-12-013, and D.05-09-043 to apply to the current

funding cycle. Each energy efficiency program administrator (PA) must file a Tier 2 advice letter

highlighting the next calendar year’s budget, all fund shifting activity, annual spending, and cost-

effectiveness statements (D.15-10-028,p.123).

In D.15-10-028, the CPUC also eliminated prior requirements that EE PAs must file advice

letters to obtain authorization to shift funds among EE programs. However, if CPUC Staff or

stakeholders identify fund-shifting activities that substantially depart from CPUC policy

direction or, in the opinion of CPUC Staff or stakeholders, are not in the best interest of

ratepayers and/or the efficiency portfolios, they may raise their concerns in a protest to the PA

(D.15-10-028, pg.127).

4. Funding Business Plans. Each PA will file an initial business plan for new programs as an

application to receive EE funding. Business plans will explain at a relatively high level how PAs

will effectuate the strategic plan and correspond with their more detailed implementation plans.

PAs will organize business plans into market sectors and subsectors as discussed below. After

the initial filing, PAs must file revised business plans only when a “trigger” event happens; PAs

may also file revised business plans whenever they choose to do so. Business plan filings will

generally be untethered to the calendar except that PAs will need to apply for an extension of

funding – that is, a restarting of the ten-year clock -- no less than one year before funding is set

to end. (D.15-10-028, pg. 123).

Business plans will be considered as part of a stakeholder process and shall contain the

following:

a) Portfolio summary and description of applicable intervention strategies;

b) A chapter for each of six sectors (residential, commercial, industrial, agriculture, public,

cross-cutting) providing;

a. A description of each PA’s overarching goals, strategies and approaches; near-,

mid- and long-term strategic initiatives;

b. Sector-specific intervention strategies;

c. Descriptions of how each sector approach advances the goals, strategies and

objectives of the strategic plan;

d. Descriptions of which and how strategies are coordinated statewide and

regionally among PAs and/or with other demand-side options;

e. Descriptions of how cross-cutting “sectors” are addressed;

f. Descriptions of leveraging of cross-cutting activities for success for particular

customer groups;

g. Descriptions of work to minimize redundancy;

h. Descriptions of efforts voiding working at cross purposes with other PAs;

i. A description of any pilots contemplated or underway for the sector.

j. A chapter for each of six sectors (residential, commercial, industrial, agriculture,

public, cross-cutting) providing a statement of evaluation.

Utility program administrators shall not opt out of funding statewide programs and must fund

at levels consistent with their proportional share based on load, unless specifically approved by

the CPUC for a deviation by means of a new business plan (D.18-05-041, pg.186). In a rolling

portfolio, where budgets are annualized rather than in a multi-year (portfolio cycle) period, if the

program calendar year ends before disposition of the advice letter with the budget for the next

calendar year, the prior year’s budget shall remain in place until disposition of the pending

advice letter. IOUs shall continue to recover costs, and make transfers to CCAs and RENs,

based on the prior year’s authorized budget (D.15-10-028, OP 5).

5. Shared Funding and Funding for EM&V - The utilities shall file a Tier 1 advice letter to

propose a mechanism for shared funding of statewide programs detailing proportional amounts

and discrepancies or issues (D.18-05-041, pg.187). Energy efficiency PAs shall fund the

coordinating committee (as created via D.15-10-028, p. 70) budget pro-rata based on their share

of the overall authorized annual energy efficiency spending, filed through a Tier 1 advice letter

(D.15-10-028 pg.125-126). Evaluation budgets will remain at four percent of the total portfolio,

with at least 60 – 72.5 percent reserved for CPUC staff evaluation efforts and from 27.5 and up

to 40 percent for program administrators, to be further divided proportionally among utilities,

community choice aggregators, and regional energy networks by appropriate utility service area,

with the exact amounts to be finalized during the collaborative process between program

administrators and CPUC staff. (D.16-08-019, pg. 3.)

6. Treatment of Unspent Funds from Prior Portfolio Cycles. At the beginning of each

portfolio cycle, IOUs should apply prior cycle(s) unspent funds to the new portfolio, including

any associated interest collected, to offset revenue requirements in the new portfolio cycle as

approved by the CPUC through the IOUs’ EE applications (D.12-11-015, pg. 93).

Committed

funds are defined as those associated with individual customer projects and/or are contained

within contracts signed during a previous program cycle and associated with specific activities

under the contract. Committed funds are not considered “unspent funds,” and need not be

spent during that particular program cycle so long as there is an expectation that the activities

will be completed and that the committed funds are spent to complete the activities for which

they were committed. Savings will be counted in the cycle in which the project is completed

(D.12-11-015, pg. 92).

7. Program Cancellation. IOUs shall not eliminate any energy efficiency program or sub-

program except through the energy efficiency portfolio application or an Advice Letter seeking

such a change. (D.12-11-015)

III. Regional Energy Networks & Community Choice Aggregators

This section provides information on the option for local government entities to apply with the

CPUC to directly administer and report of energy efficiency related programs. This section also

includes compliance requirements for Regional Energy Networks (RENs) and Community

Choice Aggregators (CCAs) administering Energy Efficiency programs.

1. Regional Energy Networks. In D.12-11-015, the CPUC authorized the formation of

RENs, to enable local government entities to plan and administer energy efficiency programs

independent from the IOUs. RENs are distinguishable from other local government

partnerships (LGPs) by the fact that they have applied to the CPUC to become a REN vs.

LGPs that propose to and are selected by the IOUs. RENs are intended to be additional to

and not in replacement of design or budget of LGPs contracting to IOUs. The RENs will

have the independent ability, within the confines of CPUC approval, to manage, deliver, and

oversee their own programs independently, without utility interference or direction as it

relates to the design and delivery of their programs. Within California there are three RENs;

1) The Bay Area Regional Energy Network, 2) The Southern California Regional Energy

Network, and 3) The Tri-County Energy Network. The IOUs will serve as fiscal managers

responsible for all usual fiscal and management functions including fiscal oversight and

monitoring,

such as providing the day-to-day contract management functions and

disbursement of ratepayer funds (D.12-11-015, pg. 10). The CPUC retains the authority to

direct changes to the REN energy efficiency portfolio. The RENs and IOUs are required to

submit Joint Cooperation Memorandum advice letters (D. 18-05-041, OPs 38-39). These

memos ensure coordination between the Program Administrators with overlapping service

territory. The memos identify program offerings that are distinct and similar. Where programs

are similar, the RENs and the IOUs state their plan for seamless program offerings and to

avoid customer confusion. Finally, D.16-08-019, page 11 reaffirmed the RENs as “pilots”

and that they should be evaluated on an equal basis as the IOUs and that the RENs should

continue to directly apply to the CPUC for funding.

On December 5, 2019, the CPUC approved D.19-12-021 which adopted Frameworks for

RENs and Market Transformation. The language in this decision authorizes the continued

operation of the RENs and “invites new REN proposals as business plans to be filed with

the Commission” so long as they meet specific criteria laid out in the proposed decision.

Reiterates that the RENs have no cost-effectiveness threshold given that they exist to fill

gaps in California’s energy efficiency portfolio of programs and serve hard-to-reach (HTR)

customers. Allows some geographic overlap among more than one REN and other program

The new criteria for RENs in D.19-12-021 include that they must represent more than local

government entity (pg 22); coordinate with existing program administrators in their geographic area

prior to filing a business plan (pg 22); vet their proposal with stakeholders through the California

Energy Efficiency Coordinating Committee (CAEECC) (OP 2); explain their governance structure in

the business plan filing (OP 2); A description of its new and unique value to contribute to

California’s energy, climate, and/or equity goals (OP 2); and a proposed set of metrics and savings

targets (OP 2).

administrators, with appropriate coordination and requires that all PAs file JCMs to avoid

duplication (D.19-12-021, pgs 25-26). Finally, the decision re-designates the RENs as

program administrators instead of pilots, requires that the RENs business plans demonstrate

a value add, in addition to filling gaps and serving HTR customers, and does not limit them

to any specific sector or program area (D.19-12-021).

2. Community Choice Aggregator (CCA). Community Choice Aggregators (CCAs), are an

alternative to the investor owned utility energy supply system in which local entities in

California can aggregate the buying power of individual customers within a defined

jurisdiction in order to secure alternative energy supply contracts. In 2010 the first CCA,

Marin Clean Energy (MCE) launched. The passage of AB 117 (Midgen, 2002) which allowed

formation of CCAs as an alternate load serving entity also created the option for CCAs to

administer EE programs under Public Utility Code (PUC) § 381.1 by allowing a CCA to

“apply to administer” ratepayer funded EE programs. This act was later modified by Senate

Bill (SB) 790 (Stats. 2011, Ch.599, Leno) which allowed another route for CCA’s to offer

ratepayer funded EE programs through “electing to administer” and D.14-01-033 provided

further clarity for CCAs choosing either approach. CCAs “applying to administer” EE

programs must file an application with their Business Plan which must comply with the

CPUC’s prior decisions and resolutions per PUC § 381.1(a-d). Additionally, CCAs shall

submit their plans factoring in cost effectiveness approved by their governing board, then the

CPUC. CCAs “electing to administer” programs can only offer only EE services to their own

customers pursuant to Section 381.1(e-f). A formula that sets the maximum funding the

electing CCA can request (D.14-01-033, pg. 22). CCAs elect to administer through filing a

proposed plan via a Tier 3 advice letter (D.14-01-033, pg. 54).

Compliance Requirements for Regional Energy Networks and Community Choice Aggregators:

3. Business Plans. CCAs were encouraged apply to be non-IOU program administrators of

energy efficiency programs and local governments were allowed to submit regional pilots for

the CPUC to review in D.12-05-015, COL 50 and the applications of BayREN, MCE and

SoCalREN were later approved in D.12-11-015, OPs (8-11). RENs and MCE submitted their

applications, which were proposed in Business Plans, to the CPUC in January of 2017. Each

year, after approval of the overall business plans, MCE and RENs’ annual budget advice

letters are to be shared with stakeholders by leveraging the California Energy Efficiency

Coordinating Council (CAEECC) prior to submission to CPUC, a process endorsed in D.15-

10-028 (16-08-019, OP 1 and OP 2). All EE PAs, including the RENs and MCE are subject

to the triggers for refiling their business plans per OP 2 of D.15-10-028.

However, RENs

are not required to meet a cost-effectiveness threshold and do not have assigned savings

targets through the ED led Potential and Goals Study.

MCE is required to meet the same

cost-effective threshold as the IOUs, but also do not have assigned savings targets through

the ED led Potential and Goals Study).

To ensure that MCE and the RENs are more

accountable to meeting a saving threshold, D.18-05-041 stated that RENs and MCE

forecasted energy savings goals must meet or exceed the annual energy savings targets

included in their business plan as a criteria for approval of their ABALs.

However, MCE

and the RENs each submitted budget and savings true-up tables in their PY 2019 ABALs.

These true-up tables reflected more accurate and updated planning assumptions and

forecasts, for each program year through 2025, than their business plans. Thus, D.19-08-034

stated that for each year MCE and the RENs request energy efficiency funding authorization

via an ABAL, they shall meet or exceed the annual savings forecasts presented in their true-up

tables as submitted in their prior year’s ABALs.

4. Implementation Oversight and Reporting Requirements. The RENs and CCA’s who

implement EE programs are subject to the same periodic reporting requirements to the

CPUC as the IOUs are required to submit. The IOUs will receive attribution toward their

portfolio goals for REN and CCA energy savings (D.12-11-015, pg. 11). Additionally, RENs

and CCAs will submit monthly narrative reports, which enable CPUC staff to track and

perform approved EE activities. These reports are found on the CEDARs

(https://cedars.sound-data.com/). The CCAs and RENs shall conduct financial and

management audits of its energy efficiency programs and provide a copy of the audits to the

CPUC (D.12-11-015, pg.10).

Each energy efficiency program administrator must file an application with a revised business plan when a “trigger” event happens. Triggers

are:

1. A Program Administrator (PA) is unable to adjust its portfolio in response to goal, parameter, or other updates to:

a. meet savings goals,

b. stay within the budget parameters of the last-approved business plan, or

c. meet the Commission-established cost effectiveness (excluding Codes and Standards and spillover adjustments)

2. The Commission calls for a new application as a result of a decision in the policy track of the proceeding (or for any other reason);

D.19-08-034, pg 28.

Ibid

D.18-05-041, pg. 134.

D.19-08-034, pg 28.

5. Threshold of Review. D.19-12-021 revised the criteria that the CPUC will consider in

approving new or renewed REN business plans. Specifically, the decision states new RENs

must show also new or unique value to the CPUC’s energy, climate, and/or equity goals. In

addition, to qualify for consideration, a REN program activity must meet one or more of the

following criteria to be considered for approval:

• Activities that utilities or CCA program administrators cannot or do not intend to

undertake.

• Pilot activities where there is no current utility or CCA program offering, and where

there is potential for scalability to a broader geographic reach, if successful.

• Activities serving hard-to-reach markets, whether or not there is another utility or

CCA program that may overlap (D.19-12-021, pg 32).

6. Program Cost-Effectiveness Threshold. D.14-01-033 required the CCA’s portfolios to

meet the same cost-effectiveness tests as IOUs, with an exception in the three years

following their first application where a TRC of 1.0 is permitted (pg. 50). Regional Energy

Networks are not required to hit a cost-effectiveness threshold, but D.16-08-019 did

“encourage RENs to manage their programs with an eye toward long-term cost-

effectiveness” (D.16-08-019, pg 12).

7. CCA and REN Funding. CCA’s submitting applications to administer programs pursuant

to Section 381.1 shall receive funding only for electricity savings programs (D.14-01-033, pg.

54). For the three RENs, Southern California Edison Company, Southern California Gas

Company, and Pacific Gas and Electric Company remain the fiscal managers for their

contracts without exercising control over program design or program changes (D. 14-10-046,

pg.162). If funding year ends prior to CPUC disposition of program administrator budget via

their annual budget advice letter, RENs and CCAs will continue to receive prior years

funding (15-10-028, OP5, pg. 124).

8. Evaluation, Measurement and Verification Requirements. CPUC staff shall include

CCA -administered programs under PUC § 381.1 (a)-(d) within the scope of its EM&V

activities (D.12-11-015, pg. 51). REN evaluations, including impact and process evaluations

should be managed by CPUC staff. CPUC Staff shall retain an accounting consultant using

EM&V funds to cover the cost both to review prior cycle reporting and to develop a

proposal to rationalize accounting practices for energy efficiency going forward (D. 14-10-

046, pg.162). In OP 16 of D.16-08-019, CCAs and RENs funding for evaluation shall be set

on a proportional basis, based on total program budget, from among the up-to-40 percent

allocation within the relevant utility service territory.

IV. Cost-Effectiveness

This section provides the rules and policies governing cost effectiveness analysis for the

purposes of measuring the performance of program administrator programs and ensuring that

public purpose funds are responsibly allocated. This section also provides details regarding

program performance metrics as another metric to measure the performance of programs and

portfolios.

1. Standard Practice Manual (SPM). The cost-effectiveness indicators referred to in these

rules are described in the California Standard Practices Manual: Economic

Analysis of Demand-

Side Management (D.12-05-015, p. 28). Cost-effectiveness analyses must be performed in a

manner consistent with the indicators and methodologies

included in the SPM, with

clarifications indicated in CPUC decisions

relating to this subject.

2. Total Resource Cost Test (TRC). This CPUC 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. The TRC measures net costs as a resource option

based upon the total costs for the participants and the utility. The benefits are the net present

value of avoided costs of the supply-side resources avoided or deferred. The TRC costs

encompass the net present value of the net costs to participants for installed measures over

the measure life plus all the costs incurred by the program administrator. The net benefits and

net participant costs exclude the benefits derived from and costs paid by free-rider participants

(D.07-09-043, p. 157). The net cost to participants is the actual costs minus any rebates

from

the program administrator. The net present values are calculated using a discount rate that

Per SPM and Decisions including D.08-01-006, rebate amounts used to reduce participant costs are

defined to include only dollar benefits such as rebates or rate incentives (monthly bill credits) paid by the

program administrator to a participating customer (ratepayer). These costs are included in the program

administrator total cost so must not be counted twice. Rebates paid to free-rider participants are included as

TRC costs in the program administrators cost.

reflects each utility’s after-tax weighted average cost of capital (WACC), based on the most

recent cost of capital decision.

3. Program Administrator Cost Test (PAC). The Program Administrator Cost (PAC) test

of cost-effectiveness should also be considered in evaluating program

and portfolio cost-

effectiveness. Under the PAC test the program benefits are the same as used in the TRC

test. The costs include only the net present value of all costs incurred by the program

administrator while excluding the costs incurred by the participating customers. As in the

TRC test, the net present values for the PAC are calculated using a discount rate that

reflects each PA’s after-tax weighted cost of capital, based on the most recent cost of

capital decision.

4. Application of the TRC, RI M a nd PAC Tests. Though TRC is the primary cost

effectiveness test used by the CPUC, also considering the RIM and PAC test supplemental to

the TRC appropriately acknowledges the dual-cost issue unique to energy efficiency

investments (D.19-05-019, p. 24). Since it is expected that incentives offered for the

installation of a measure will not exceed the incremental cost of the measure, activities that

pass the TRC test normally will also pass the PAC test.

However, if deployment of the

program requires rebates or financial incentives to participants that exceed the measure

cost, then the program may pass the TRC test, but fail the PAC test. Incentives or rebates

that exceed the TRC cost for a measure must be justified in workpaper submissions

that

are approved by CPUC Staff.

The RIM test provides information on the rate impacts.

Therefore, all determinations based on the cost-effectiveness analyses of distributed energy

resources should include a written description of the results of the TRC, PAC, and RIM

(D.19-05-019, p. 25).

D.18-05-041 modified the portfolio requirements to include a 1.25 ex-ante TRC by 2023,

with an ex-ante TRC of 1.0 during the ramp years of 2020-2022 (p.72). The decision did not

D.12-05-015, p. 38 contains a table of the current IOU WACC values and OP 2 directs

the use of the after-tax

Weighted Average Cost of Capital as the discount rate. D.12-12-034 provides the latest review of utility cost of

capital. Further historical data is provided at http://www.cpuc.ca.gov/General.aspx?id=12056.

D.06-06-063, p. 72 recognizes only “limited instances for program design purposes where the cash rebate to the

customer exceeds the measure installation cost”

Originally defined in D.92-09-080, the dual test was last modified in D.05-04-051

modify that the evaluation of portfolios take into consideration passing both the TRC and

PAC tests for each service territory and for the entire approved portfolio, including RENS

(p.161). However, the TRC will not exceed the PAC unless incentives exceed incremental

measure costs.

5. Overall Cost-Effectiveness of IOU, REN, and CCA Portfolios. It is the responsibility of

the CPUC to approve the total portfolio- which includes both utility and REN proposals- and

ensure that it is cost-effective overall, because the IOUs are not in control of the REN

proposals and therefore cannot make the cost-effectiveness tradeoffs within their portfolio.

The CPUC therefore applies the dual test for overall portfolio

cost effectiveness, taking into

consideration passing both the TRC and PAC tests

for each utility service territory

portfolio without the RENS, as well as entire approved portfolio that includes the RENs

(D.12-11-015, p. 18). The CPUC emphasized in D.18-05-041 that RENS ought to focus in

filling gaps in IOU energy efficiency portfolios, piloting different approaches, and targeting

hard-to-reach customers. Due to challenges associated with RENs diversifying portfolios, the

CPUC did not adopt specific cost effectiveness requirements for RENs (p.95)

6. Avoided Costs and Other Inputs. TRC and PAC benefits should be computed using the

avoided cost methods and input assumptions, including avoided greenhouse gas emissions

related cost

that have been developed for the evaluation of energy efficiency programs in the

Standard Practice Manual and in Proceeding R.14-10-003. As set forth in D.16-06-007, data

for the avoided cost calculator shall be updated on an annual basis, and shall be conducted

through the CPUC Resolution process (D.16-06-007, p. 6 and OP 2, p. 26).

7. Cost Effectiveness Adjustments for Free-Ridership and Market Effects. Net to

Gross

(NTG) ratios are used to estimate and describe the “free ridership” that may be occurring

within energy efficiency programs, that is, the degree to may be occurring within energy

efficiency programs, that is, the degree to which customers would have installed the program

D.06-06-063, p. 72 recognizes only “limited instances for program design purposes where the cash rebate to the

customer exceeds the measure installation cost”

D.17-08-022 adopted a series of values based upon the California Air Resources Board Cap-and-Trade

Allowance Price Containment Reserve Price as an interim greenhouse gas adder value for use in the avoided cost

calculator when analyzing the cost-effectiveness of distributed energy resources. Resolution E-4942 incorporates

the update of these values set forth in D.18-02-018 for use in the IDER proceeding and any other proceedings that

rely on assumptions about the avoided GHG costs of DERs for evaluating cost effectiveness.

measure or equipment even without the financial incentive (e.g., rebate) provided by the

program. Cost-effectiveness of the portfolio shall be calculated as net of free riders, or on a

“net savings basis” for the purpose of establishing budget levels that meets the legislative

requirement in § 454.5.

a. CPUC Staff has the responsibility to perform research on free ridership and

market effects and to use the results of that research to

develop updated NTG

values for use in portfolio planning and utility reporting. This research often

involves interviews with customers and

others who participate in the utility

programs. The IOUs are required

to cooperate and facilitate this research. Utility

customers are required

cooperate with CPUC staff in this research as a

condition of receipt of energy efficiency funds. The IOUs must respond to

CPUC Staff’s request for evaluation data in a timely manner to

facilitate this

research so as to improve the reliability of NTG results (D.12-05-015, p.51).

Our

adopted DEER is the repository of the NTG values to be used for

planning

and reporting. CPUC Staff shall strive to update DEER

with uniform statewide

NTG values that represent typical expected

results (p. 54 and OP 6).

b. The “default” NTG values shall be used when there is a lack of research on the

NTG value for the program or delivery mechanism. This may apply to new or

existing measures (or if a proposed delivery mechanism has deviated substantially

from past related program activities).

When new measures or programs are

proposed, CPUC staff may utilize the results of previously completed research

produced during similar program or measure piloting activity to set an appropriate

NTG value (D.12-05-015, p. 339).

Alternatively staff may determine that no

piloting research is required and accept proposed use of default or other

appropriate NTG values.

c. For measures added to the portfolio as a direct result of Emerging

Technology Program activities (Emerging Technology measures) the IOUs

may request in their non-DEER work paper submissions that a measure be

assigned a NTG value at or above 0.85. CPUC Staff shall have the authority

to accept or reject a utility Emerging Technology measure classification and

Definition and calculation of Net-to-Gross adjustments to TRC test were described in Attachment 9 of D.07-09-

043.

D.12-05-015 adopted DEER NTG table. D.15-10-028 adopted the DEER update process through the rolling

portfolio cycle schedule which includes the update of default and prescribed NTG values.

to set any Emerging Technology measure NTG value at or above 0.85 as it

deems

appropriate (D.12-05-015, p. 62 and OP 14 and OP 15).

d. For all projects undertaken by schools, and for programs targeting specific

transmission, distribution, or generation constrained areas (other than bottoming-

cycle combined heat and power projects), for purposes of determining net

savings, default ex ante lockdown rules apply, except that a Net-to-Gross ratio of

.85 (before spillover effects) is “locked down” for all above code projects.

Eligibility includes requirements that customer incentives shall be the higher of

75 percent of incremental measure cost, or what is available under prior policies

(D.14-10-046, pp. 163-164).

e. For custom projects the adopted ex ante review process provides

CPUC Staff

with the ability to review and update ex ante values

including NTG for those

projects (OP 149).

The IOUs are expected to respond

to CPUC staff reviews by

taking steps to improve NTG results. Utility programs should strive to push

customers to augment projects

to include action that would not occur without

incentive support or redesign the incentive structure to encourage deeper and

more comprehensive activities as well as aligning the incentive amounts to

commensurate with the level of savings that can be attributed to the program

(p.61 and OP 12).

f. Market effects are defined as additional energy savings that occur as a result of the

energy efficiency programs, but that are not included in the utility savings claims.

The CPUC acknowledges that market effects occur. However, in D.12-11-015 the

CPUC determined that there were not sufficiently current or technically rigorous

market effects studies to base market effect estimates on, and instead determined

to apply a portfolio-level “market effects adjustment” of 5 percent, ex-post, across

all resource programs for the entire cost effectiveness calculation (D.12-11-015, p.

49).

This 5% market effect adjustment shall be applied to increase TRC and PAC

benefits as well as to increase TRC participant costs (excluding the deduction of

program rebates or incentives paid to participants).

8. Portfolio Filing of Prospective Cost Effectiveness. A prospective showing of cost-

effectiveness using for the TRC test (with consideration also given to PAC) for the entire

portfolio of ratepayer-funded

energy efficiency activities and programs (i.e., individual

programs, plus all costs

not assignable to individual programs, such as overhead, planning,

evaluation, measurement verification and administrator compensation and performance, if

applicable) is a consideration when authorizing ratepayer funds.

This consideration applies to each of the following: (1) the service- territory wide

program portfolios offered by each IOU and CCA Program Administrator, excluding: 1)

RENs, 2 ) emerging technologies programs, and (3) On-Bill Financing loans (D.09-090-

47, p.288). IOU program administrators must demonstrate that the first threshold

requirement is met on a prospective basis in their program funding applications to the

CPUC. IOUs must also

demonstrate that the proposed level of electric and natural gas

energy efficiency program activities are expected to meet or exceed the CPUC-adopted

electric and natural gas savings goals, by service territory.

a. The CPUC adopted several safeguards against certain risks that the annual

portfolios would not achieve their forecasted TRC estimates. As the basis for

determining cost-effectiveness of proposed program portfolios, IOU Program

Administrators omit codes and standards (C&S) advocacy costs and benefits, and

spillover effects. The CPUC also sets a higher prospective TRC threshold of 1.25

(D.12-05-015, p. 100 and D.18-05-041, pp. 54-55), to hedge against eventual

reductions in savings as determined by evaluations.

b. To support comparisons of all resources in the IOUs’ procurement portfolio, the

program administrators are required to also provide

levelized unit cost estimates

at the portfolio, end-use and measure level consistent with the methods

described in the SPM. This information should be submitted with the program

administrators’ compliance filings.

Per D.04-09-060, p.2 savings from LIEE programs will also count towards these goals.

D.18-05-041 established the ramp period, program years 2019-2022, in the context of third party solicitations,

setting up the statewide administration framework, and affording the PAs an opportunity to improve portfolio

cost-effectiveness. Forecasted TRC must meet or exceed 1.25 in the ABAL, except during program years 2019 –

2022, when the forecasted TRC must meet or exceed 1.0.

If a Program Administrator’s prospective showing of cost effectiveness does not

meet the threshold set-forth by the CPUC

, the PA will need to file an application

with a revised business plan for CPUC approval.

9. Common Sector-level Metrics. Metrics should be designed to be valuable to implementers

as well as other stakeholders to improve the chances of longevity of the metric and associated

perspective of measuring it over time.

Program administrators shall set sector-level metrics

in the business plans and will set more granular, program level metrics in implementation

plans (D.15-10-028, p. 53)

In addition to sector-level metrics developed by program

administrators, CPUC Staff has developed common sector-level metrics to be reported

annually in the annual report by all program administrators to (1) consolidate metrics around

common problems identified by most program administrators for each sector, (2) enable

consistent tracking and progress assessment for the whole sector, (3) enable comparisons

across and within sectors, and (4) enable tracking of high-level portfolio progress over a

period of time.

Attachment A of D.18-05-041 provides a listing of the minimum set of

common metrics to be reported. PA’s can submit additional metric (fields) within the Annual

Budget Advice Letters, and submit associated data in their annual report.

10. Cost Sharing and Cost-Effectiveness Across Utility Service Territories. Energy

efficiency statewide program costs are shared between utilities on an upfront pre-set basis,

then trued up based on customer participation (D.16-08-019, p.110) Though costs are shared

upfront, program cost-effectiveness is still evaluated by utility area, considering just the

program costs and benefits relevant to the customers in that area (D.16-08-019, p. 55). The

budget for each statewide program in each utility territory shall be counted toward the cost-

effectiveness of each utility’s energy efficiency portfolio and each utility shall be given energy

savings and Energy Savings Performance Incentive credit consistent with their customers’

funding and program participation (D.16-08-019, p. 110, OP 7).

D.18-05-041 at pp. 133-134 further set annual budget advice letter approval criteria for IOU, CCA, and REN

program administrators.

D.15-10-028, OP 1 identifies the trigger events which require a program administrator to file a revised business

plan. The development of business plan filings are described in D.16-08-019.

D.18-05-041 dictates that a metric includes a baseline and a target or targets (short, medium, or long term). An

indicator does not include baselines or targets.

Guiding principles for business plan metrics are laid out in Table 2 of the May 10, 2017 Administrative Law

Judge’s Ruling Seeking Comment on Energy Efficiency Business Plan Metrics.

Administrative Law Judge’s Ruling Seeking Comment on Energy Efficiency Business Plan Metrics, May 10, 2017,

p. 5-6 and D.18-05-041, pp. 22-23.

11. Cost Effectiveness Requirements for Fuel Substitution Programs / Measures/

Projects. Fuel substitution programs/projects may offer resource value and environmental

benefits. Fuel-substitution programs should reduce the need for supply without degrading

environmental quality. For purposes of applying these tests, fuel substitution proponents

must compare the technologies offered by their program/measure/project with the baseline

technology determined in the same manner as for other measures in the energy efficiency

portfolio (namely, using code baseline, industry standards practice, or existing conditions

depending on the circumstances of the measure installation). The burden of proof falls on

the party sponsoring the analysis to show that the baseline comparison adheres to this

requirement. D.19-08-009 (OP 1, p.57) updates the Fuel Substitution Test as follows. Retrofit

measures in fuel-substitution programs/projects must pass the following Fuel Substitution

Test:

a. The program/measure/project must not increase source- British Thermal Unit

(Btu)

consumption when compared with the baseline comparison measure

available utilizing the original fuel, as currently defined by the baseline policies in

D.16-08-019 and Resolution E-4939, Attachment A.

b. The program/measure/project must not adversely impact the environment

compared to the baseline measure utilizing the original fuel. This means that the

use or operation of the measure must not increase forecasted CO2 equivalent

greenhouse gas (GHG) emissions.

The Fuel Substitution test does not apply to new construction applications. Program

Administrators proposing fuel substitution measures must provide all assumptions

and calculations for CPUC review, and utilize the most recent versions of the

Avoided Cost Calculator, Cost-Effectiveness tool, and other fuel substitution

documents available at the time the measure is proposed.

D.19-08-009 also directed CPUC staff to issue technical guidelines for fuel

substitution measures, including, but not limited to, guidance on calculation of source

energy savings and environment offsets for fuel substitution measures. Fuel

Substitution Technical Guidance for Energy Efficiency is a ‘living’ document, whose

first version was released on September 2019.

12. Mid-Cycle Funding Augmentations. Costs and energy savings from mid-budget cycle

funding additions for programs other than Energy Savings Assistance Programs (ESAP)

shall be counted when calculating portfolio cost-effectiveness

and shall count towards the

IOUs’ energy efficiency goals for resource planning purposes.

13. References. See the following references below for further information on cost

effectiveness.

a. CPUC Cost Effectiveness page – http://www.cpuc.ca.gov/General.aspx?id=5267

b. CPUC Standard Practice Manual –

http://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/Utilities_and_I

ndustries/Energy_-

_Electricity_and_Natural_Gas/CPUC_STANDARD_PRACTICE_MANUAL.pdf

c. CPUC Online Tool - https://cedars.sound-data.com/

V. Implementation Oversight and Reporting Requirements

The CPUC requires program administrators to both report on annual program achievements as

part of its regular reporting requirements and file budget requests for subsequent program year

based on prior-years’ performance.

1. Reporting Requirements. CPUC staff is directed to develop and update reporting

requirements to ensure that the types of data and the format of the information presented in

the IOUs’, RENs’ or CCAs’ filings and reports are as consistent as possible. The IOUs,

RENs and CCAs (except as modified for RENs and CCAs in Rule III.3) are required to

follow the CPUC’s Energy Efficiency Reporting Requirements Manual for the current

program cycle. Please refer to the California Energy Data and Reporting System (CEDARS)

at (http://www.eestats.cpuc.ca.gov) for the most current reporting templates and Energy

Division guidelines. The following regularly occurring reports are required:

a) Monthly Reports on expenditures and savings

b) Quarterly Reports on budgets and expenditure caps

c) Utility Tracking data to report program accomplishments, evaluation sampling and

cost effectiveness calculations

d) Common Sector Metric Annual Reporting - per D.15-10-028, program administrators

were relieved of reporting requirements laid out in Resolution E-4385. Program

administrators will report on metrics approved in D.18-05-041 in their Annual

Budget Advice Letter (ABAL) filings due September of each year and in the May 1

annual reports

e) Energy Efficiency Program Annual Reports

f) Annual Budget Advice Letters

g) Other reports as required by the CPUC.

2. Business Plans and Annual Budget Advice Letters. IOUs, RENs and CCAs are no longer

required to submit Program Implementation Plans, as they were associated with previously

three-year program cycle applications. As of January 1, 2017, IOU, REN and CCA program

administrators are required to submit Business Plans, which provide a 10-year high-level

description of a program administrator’s respective portfolio in terms of sectors, budgets and

strategies, as well as Annual Budget Advice Letters (ABALs), which are filed each year in

September and present the program administrator’s budget request for the subsequent program

year.

The Business Plans do not have a formal template; program administrators work with

CPUC staff to ensure relative similarity across the various program administrators filed plans.

Implementation Plans – As of January 1, 2019, IOU program administrator portfolios are

transitioning to a larger role for third party administrators. By 2023, at least 60 percent of the

IOUs’ respective portfolios (by budget) must be bid out to third party implementers, who will

be solely responsible for proposing, designing, implementing, and delivering programs for utility

program administrators. Consequently, the next few years will see a mix of program-level

implementation plans for existing programs that may continue as well as implementation plans

for new programs designed as part of the third-party expansion. (The program implementation

plan (PIP) addendum process required by D.04-12-048 is no longer in force.)

Pursuant to Attachment C of ALJ Ruling Adopting Annual Reporting Requirements for Energy Efficiency and Addressing

Related Reporting Issues, dated August 8, 2007

As required by D. 15-10-028.

Initial Business Plans were filed January 17, 2017 and subsequently approved via Commission Decision 18-05-

041 in June 2016. Program administrators may file a subsequent business plan of their own accord or in the

instance that they fail to meet specific portfolio review criteria as laid out in D. 18-05-041, including a failure to:

meet energy savings goals; be cost-effective; or maintain a budget under the authorized cap.

Implementation plans for existing programs that will be continued by the IOUs during the third-

party process will be posted to the California Energy Data and Reporting System (CEDARS) on

http://www.eestats.cpuc.ca.gov ) after a brief public review opportunity via CAEECC.

Implementation plans for new programs, developed as part of the third-party process, will be

reviewed subsequent to a contract signed between an IOU and a third-party implementer and

within the sector-specific Peer Review Group for that contract.

Implementation plan updates are likely to follow guidance provided in D.18-01-004, which

recognizes that implementation plans will be initially posted at the conclusion of the third party

solicitation process and requires IOU program administrators’ implementation plans to be

“developed and posted, consistent with the requirements of D.15-10-028, within 60 days after

contract execution.” As of January 2019, the timing and nature of updating implementation

plans that flow from successful third-party solicitation(s) has yet to be determined. However,

the IOU program administrators, CPUC staff, and stakeholders, as part of the third-party

Procurement Review Group(s) overseeing solicitations, are developing process that will guide

implementation updates.

If a REN or CCA desires to modify an existing implementation plan, it should notify the

appropriate utility and CPUC staff, and document the changes on the EEStats website, utilizing

the same process by which the IOUs make changes to their implementation plans.

3. Counting of Savings. The reporting of ex ante savings estimates in the compliance filings is

subject to Rule VI on ex ante review. When estimating ex ante savings values for either

portfolio planning or accomplishment reporting the IOUs, RENS and CCAs shall use values

and methods from the most recent version of Database for Energy Efficient Resources

(DEER) if the measure values are available. If DEER values and methods are not available, the

IOUs, RENs and CCAs may propose new values for staff review and approval, subject to Rules

VI 4-6. The protocols for developing ex post savings estimates are provided in the California

Energy Efficiency Evaluation Protocols,

updated in D.09-05-037, and through DEER

updates.

See ”Energy Efficiency Programs Implementation Plan Template” at Implementation Plan Template on EEStats

_________

April 16, 2006 ALJ Ruling in R.01-08-028

The definition of peak megawatt load reduction contained in the most recently adopted

DEER shall be used to estimate and verify peak demand savings values. The DEER method

utilizes an estimated average grid level impact for a measure between 2 p.m. and 5 p.m.

during a “heat wave” defined by three consecutive weekdays for weather conditions that are

expected to produce a regional grid peak event.

The new DEER peak timeframe of 4 p.m.

to 9 p.m. will replace the existing hours on January 1, 2020 (Resolution E-4952).

VI. Ex ante Savings and Review

This section explains the annual timeline of the Rolling Portfolio process to determine ex ante

values, and the role of CPUC staff, IOU’s and stakeholders in arriving at those values.

1. CPUC Oversight of Ex Ante Values. The estimated energy savings values for energy

efficiency measures used for planning and reporting accomplishments for energy efficiency

programs, referred to as the ex ante values, are subject to the review and approval of CPUC

staff. The ex ante review process must be managed by CPUC staff because it involves

judgments that can influence both the development of performance targets and the

measurement of program achievements (D.05-01-055, p.120). Due to the conflict-of-interest

concerns the IOU Portfolio Managers would not be the appropriate entities to manage or

directly contract for the ex ante review process (D.05-01-055, p.121).

2. DEER and non-DEER measures and workpapers – Non-DEER workpapers must use

DEER assumptions, methods and data

IOUs are instructed to use DEER values as starting points and/or apply the DEER

methodologies for estimating the non-DEER parameter value for cases in which any of the

specific parameters of an IOU installation differ from the assumptions that form the basis of

a DEER measure. The utilities cannot replace DEER assumptions and values with their

D.06-06-063 OP 1. The DEER version adopted in D.12-05-015 utilizes a 3-day “heat wave” that

occurs on consecutive days in June through September such that the three consecutive days do not

include weekends or holidays, and where the heat wave is ranked by giving equal weight to the peak

temperature during the 72-hour period, the average temperature during the 72-hour period and the

average temperature from noon – 6pm over the three days.

preferred values unless the CPUC Staff agrees with their proposal for such replacements

(D.12-05-015, p.331). Non-DEER values may not be used without CPUC Staff approval.

DEER measures are located in the official Ex Ante database (EAdb). Non-DEER

workpapers are typically new measures that have values from sources other than what is in the

DEER ex ante database. These may use some values in the DEER ex ante database but the

energy savings are determined externally and do not just adopt an energy savings value in

DEER.

Workpapers must use DEER assumptions, methods, and data in the development of non-

DEER values when available/appropriate and shall follow CPUC Staff direction relating to

the appropriate application of DEER to non-DEER values. Any proposed workpaper

measure definitions that are different from DEER definitions should be calculated using

DEER reference impacts (Statewide Deemed Workpaper Rulebook v.2.0, p.18). DEER is

updated on an annual basis. Workpapers must use the appropriate DEER version based on

their program implementation year.

If DEER values and methods are not available, new values may be proposed for CPUC Staff

review and approval. For non-DEER measures, DEER values should be used as the starting

point. In cases where any of the installation parameters differ from the assumptions for the

DEER measure, the Implementer should apply DEER methodologies for estimating the non-

DEER parameter value. Non-DEER values may not be used without CPUC Staff approval.

Direct replacement of DEER measures is not allowed in workpapers (Statewide Deemed

Workpaper Rulebook). Workpapers can be found at www.deeresources.net.

3. Freezing of Ex Ante Values. The Rolling Portfolio schedule for review and approval of ex

ante values was established in D-15-10-028 (see Appendix F here; Appendix 6 in the

Decision). The Decision sets a “January 1 deadline for IOU’s to update their workpapers to

reflect changes in DEER values adopted by the CPUC earlier in September of the previous

year. These set of workpapers are also referred to as Phase 1 workpapers. Workpapers for new

measures, and workpapers that do more than just update values to conform with revised

DEER values, can be submitted by IOU’s at any time or on the first and third Monday,

respectively (D.15-10-028, p.84) and are referred to as Phase 2 workpapers. Upon approval

by CPUC staff, the ex ante values are frozen until the workpaper is superseded by a revised

workpaper or if the measure expires by virtue of the guiding disposition . This freeze of ex

ante energy savings values applies both to energy efficiency measures contained in the DEER

and non-DEER measures covered by workpapers which are developed by IOUs and other

program implementers. Unreviewed non-DEER workpapers are granted interim approval

(D.12-05-015, p.334). Interim approval indicates that all values and approaches have been

approved until a formal review occurs. If a formal review of an interim approved work paper

requires significant changes to be made, then those significant changes are applied

prospectively from the time of the completed review and the new values are then frozen and

entered into the non-DEER database. In the case of an error such as using the wrong

parameter values, the changes will be made retroactively. All active workpapers are posted at

the workpaper website (www.deeresources.net).

4. Mid-year updates of Ex Ante Values. Ex ante values should be adopted and held constant

throughout the year. However, mid-year updates of ex ante values are warranted if newly

adopted codes or standards take effect during the year. These changes are known at least one

year ahead of their effective date. The IOUs shall make appropriate adjustments to their

participation and incentive calculation rules as well as update their ex ante value calculations

in response to codes and standards changes (D.12-05-015, p.324).

IOUs, RENs and CCAs

are expected to update non-DEER workpapers with the latest Codes and Standards updates.

CPUC staff may perform mid-year review of any non-DEER workpapers with interim

approval and require revisions to those workpapers. Mid-year workpaper review shall follow

the Phase II review process outlined in the Rolling Portfolio schedule in D.15-10-028,

Appendix 5; p.2).

5. Ex-Ante Review of Non-DEER Measures. For non-DEER measures, the IOUs are

instructed to use DEER values as starting points and/or apply the DEER methodologies,

where appropriate, for estimating the non-DEER parameter value for cases in which any of

the specific parameters of an IOU installation differ from the assumptions that form the

basis of a DEER measure. D.12-05-015 directed the IOUs to update their WPs with all

applicable updated DEER values (D.12-05-015, p.290).

The current process allows only

Program Administrators (PAs) to submit workpapers for review, a Third Party must submit a

workpaper through a PA. The PAs do not have the option to replace DEER assumptions

and values with their preferred values unless the CPUC Staff agrees with their proposal for

such replacements (D.12-05-015, p.326). Additionally, PAs must utilize the latest information

available, including the CPUC’s most recently available evaluation results, when updating or

developing new workpapers (D.12-05-015, p.332). Current and past evaluation results are

available at https://pda.energydataweb.com. All ex ante values are to be updated or

developed in consideration of the latest information available, including Unit Energy Savings

(UES), Effective Useful Life (EUL), Installation Rate (IR), NTG and Cost. CPUC staff

reviews all utility proposed non-DEER assumptions and values. PAs work with CPUC Staff,

following the workpaper and non-DEER workpaper submittal, review and approval process

that was originally issued in the November 18, 2009 ruling and updated in D.10-12-054,

D.11-07-030, D.12-05-015, and D.15-10-028.

CPUC Staff’s review of “interim approval”

workpapers or new workpapers submitted mid-year adheres to the Phase 2 workpaper

review process, including the dispute resolution process described in Appendix D.

6. Installation Rate for DEER and non-DEER Measures. All deemed measures have an

installation rate, which is the ratio of the number of verified installations of that measure to

the number of claimed installations rebated by the utility during a claim period (D.11-07-030,

p.22). The installation rate is reported separately in claims and not included in the reported

savings for the measure. For any measures not listed in the DEER database, the installation

rate is be assumed to be 1.0. In their workpapers, PA’s include the proposed installation rates

for the measure covered by a workpaper. The Gross Savings and Installation Adjustment

(GSIA) is a DEER adjustment factor that combines the Realization Rate and Installation

Rate. It is dependent on both the measure technology and how the measure is delivered. The

GSIA table can be accessed at www.deeresources.com.

7. Establishment of Baseline for use in Establishing TRC Savings and Costs. The

approach to establish a baseline for ex ante gross savings values requires the review of the

evidence related to one of the three baseline choices: (1) new equipment that is normal

replacement, turnover or replacement due to normal retrofit and remodeling activities , and

new construction (NC); or (2) the pre-existing equipment used in the program-induced

accelerated replacement (AR) case. For new equipment choices that are selected under the

NR and NC cases and are subject to existing regulations, codes or standards, the baseline

equipment is determined by the regulation, code, or industry standard. The customer’s reason

for equipment replacement could alter the baseline choice, depending on whether compelling

evidence demonstrates that the replacement was a program induced accelerated replacement

(D.11-07-030, p. 40, Appendix I to Attachment B). Resolution E-4818 provides measure

level baseline assignment and guidance to establish eligibility for an accelerated replacement

baseline treatment.

a. In the cases when there is no regulation, code, or standard that applies, which would

normally set the baseline equipment requirements, the baseline must be established using

November 18, 2009 ALJ Ruling in A.08-07-021. D.09-09-047 OP 4 states that, “Review of completed IOU work

papers regarding ex-ante savings estimates are subject to Commission Staff review and approval, as set forth in an

ALJ Ruling of November 18, 2009 in Application 08-07-021, et al. Each IOU shall cooperate with Commission

Staff to allow upfront consultation regarding such work papers.

database (EAdb) or the preliminary ex ante review database (PRdb). Then click on the tabs: Support Table, Cost

Effectiveness and GSIA value.

a “standard practice” choice. For purposes of establishing a baseline for energy savings,

we interpret the standard practice case as a choice that represents the typical equipment

or commonly-used practice. Resolution E-4939 establishes the standard practice baseline

definition and baseline selection process.

b. For the case of program-induced accelerated replacement, the remaining useful life

(RUL) of the existing equipment is to be used as the starting assumption for the period

of accelerated retirement. To establish the period of accelerated retirement, we

recommend using one-third of the effective useful life in DEER as the remaining useful

life until further study results are available to establish more accurate values (see

Summary of effective useful life (EUL)-RUL Analysis for the April 2008 Update to

DEER, p.2). CPUC staff has been given flexibility to utilize alternative remaining useful

life values, based upon compelling project or technology specific evidence (D.12-05-015,

p.348).

c. The measure or project cost utilized in an early-retirement case is the full cost incurred to

install the new high-efficiency measure or project, reduced by the net present value of the

full cost that would have been incurred to install the standard efficiency second baseline

equipment at the end of the remaining- useful-life period. Thus, the early-retirement cost

in the cost effectiveness calculation is higher than the incremental cost used in a normal-

replacement case (previously referred to as replace-on-burnout), only by the time value of

the dollar amount of the standard equipment full installed cost, using the adopted cost-

effectiveness discount rate to calculate that time valuation.

d. A “dual baseline” must be utilized for program-induced accelerated replacement

measures. The dual baseline reflects the difference between the savings that should be

credited for the initial years of installation based upon the pre- existing or replaced

equipment versus the savings credit in later years that should be based upon an eventual

pre-existing equipment replacement assumed to occur if the measure had not been

installed as part of the program. At the later date, when the pre-existing equipment would

have been replaced due to normal turnover for reasons such as imminent failure or

remodeling, an alternate equipment efficiency baseline should be utilized. This “dual

baseline” requires two savings calculation periods:

• The remaining useful life (RUL) which DEER establishes as

one-third of the expected useful life (EUL) for the equipment type (which

may reflect the EUL of the new equipment rather than the replaced

equipment). During the RUL period (“first baseline”), savings is calculated

using the full reduced energy use between the measure and the pre-existing

condition. The measure cost for this period is the full cost of equipment,

including installation, for the measure.

• The period between the RUL and EUL defines the second baseline

calculation period. For this period, the savings are calculated based on the

difference between the measure and code/regulations or industry standard

practice baseline technologies. The measure cost for this period is the full

cost of equipment, including installation, for the second baseline equipment

measure. As discussed above, the TRC cost for an ER measure is calculated

by subtracting this value discounted by the RUL number of years at the

adopted discount rate from the measure cost utilized for the measure

equipment in the initial baseline period.

8. Custom Projects. The adopted process for CPUC staff’s review of custom projects is

provided in Attachment B of D.11-07-030 (p.40). The Program Administrators (PA) shall

follow the custom project ex ante value review process set forth in Attachment B (OP 7).

Section 381.2 of the Public Utilities Code (Senate Bill 1131), effective July 1, 2019, requires

the review of a proposed project to conclude within 30 business days of the CPUC receiving

the complete project documentation for review. The “CPUC Staff Selection and Response

Timing Protocol For Energy Efficiency Custom Projects Review” guidance document

operationalizes the timing of communication on custom project document review and

feedback between the PA and CPUC staff to meet this strict review timeline. This guidance

document and other custom projects review guidance documents are available on the Energy

Efficiency Custom Project Review Guidance Document webpage at:

https://www.cpuc.ca.gov/General.aspx?id=4133

The other guidance documents include:

• Energy Efficiency Savings Eligibility at Sites with non-IOU Supplied

Energy Sources

• Statewide Custom Project Guidance Document, version 1.0

• Statewide Project Feasibility Study template, version 1.1

• Statewide Post Installation Report template, version 1.0

• Industry Standard Practice, version 2.0

• Project basis as Early Retirement (ER)/Replace-on-burnout

(ROB)/Normal Replacement (NR)/New Construction (NC)/Add-on

Retrofit (Ret) and remaining/Effective useful Life (RUL/EUL), and

Preponderance of evidence

9. Heating, Ventilation, and Air Conditioning (HVAC) Interactive Effects. Measures,

such as lighting and refrigeration, have a secondary impact on heating and cooling loads and

thus heating and cooling energy consumption. These “interactive effects” are appropriate for

incorporation into DEER.

The gas and electric IOUs shall include those effects in non-

DEER workpapers and custom measures and projects calculations. In its review of IOUs’

workpapers and custom measures and projects, CPUC Staff shall ensure the IOUs include

these effects when Staff deems that inclusion has a significant impact on the savings estimate.

10. Persistence of Savings. Until EM&V results inform better metrics, the IOUs may apply a

conservative deemed assumption that 50 percent of savings persist following the expiration

of a given measure’s life (D.09-090-47, OP 49).

11. Gross Realization Rate. The gross realization rate (GRR) is a multiplier that addresses the

likely reality that not all CPUC-approved projects undertaken by IOUs will come to fruition.

Based on studies from past years’ outcomes, a GRR value of 0.90 shall be applied as a

conservative value to account for the difference between projected and actual energy savings

for unreviewed custom projects (D.11-07-030 p. 38, OP 6).

12. Statewide workpapers. The CPUC in Decision D.12-05-015, p.54 states that “similar

measures delivered by similar activities should have single statewide values unless recent

evaluations show that a significant variation between utilities and that difference is supported

by a historical trend of evaluation results”.

D.09-05-037, OP 3 denied the IOUs’ proposal to eliminate HVAC interactive effects from DEER.

The Program Administrators (PAs) will begin submitting statewide consolidated workpapers

for PY2020 in November 2018. The PAs have hired California Technical Forum (CalTF) to

consolidate multiple WPs for the same measure to a single, statewide workpaper.

Only one workpaper may be submitted for each set of programs/measures which are

adopted by more than 1 program administrator; such workpapers have been termed

“statewide workpapers” and program administrators have been directed to collaborate on

such efforts.

Prior to 2018, workpapers were submitted separately by PG&E, SoCalGas, SDG&E and

SCE for the same or similar efficiency measures. The CPUC instructed the IOUs to submit

one consolidated workpaper for each measure. The IOUs hired CalTF to consolidate their

four individual workpapers. These consolidated workpapers have been submitted from the

November 2018 through and through calendar year 2019. These workpapers will become

effective on January 1, 2020.

VII. Evaluation, Measurement and Verification (EM&V)

The CPUC is responsible for evaluating energy efficiency programs and provides annual savings

estimates to ensure that ratepayer dollars are spent cost-effectively and in accordance with the

achievement of the state’s energy efficiency goals.

1. Purpose of EM&V. The development of energy efficiency programs that deliver reliable

energy savings for California’s ratepayers depends on well-designed policies and methods

of portfolio performance evaluation, measurement and verification (EM&V). Rigorous

and strategically focused EM&V practices are required to gauge the performance of

IOUs, RENs, CCAs, and Implementers, verify energy savings, improve the design and

success of future energy efficiency programs and enhance the reliability of forecasted

savings for resource planning purposes.

In D.05-04-051 the CPUC ordered portfolio evaluation efforts to be structured such that

they can:

Ex Ante 2018-2019 Workpaper Workplan, p. 2

2017 Workpaper Guidance Memo

1) inform the program selection process,

2) provide early feedback to program implementers,

3) produce impact evaluations at the end of the funding period, and

4) feed the planning process for future program cycles.

D.07-10-032 and D.10-04-029 further updated the EM&V process.

D.16-08-019 described how the evaluation budgets for EM&V may shift and updated the

schedule requirements for EM&V studies.

2. IOU and ED Collaboration on EM&V Plan. Per D.09-09-047, D.10-04-029, and D.12-

11-015, the IOUs and CPUC staff are expected to jointly prepare an EM&V Plan in order

enhance timeliness, transparency and consistency across EM&V work products and to

streamline EM&V processes. The IOUs and CPUC staff are expected to adhere to the plan.

D.10-04-029 set out the roles and relationships among the CPUC staff, IOUs, and

stakeholders regarding Evaluation, Measurement and Verification (EM&V) of energy

efficiency programs for 2010 through 2012. In D.12-05-015, the CPUC indicated that

guidelines for collaboration, cooperation, and dispute resolution adopted by D.10-04-029 will

continue to apply to the 2013-2014 EM&V activities.

3. Energy Division Role in EM&V Administration. D.05-01-055 adopts an approach to

EM&V administration whereby Energy Division has management and contracting

responsibilities for all EM&V impact-related studies that will be used to:

1. Measure and verify energy and peak load savings;

2. Generate data for savings estimates, cost-effectiveness inputs, and the CPUC’s

adopted performance basis; and

3. Evaluate whether portfolio goals are met.

Additionally, in D.10-04-029 the CPUC determined that the ED is permitted to manage

evaluations that may be considered process or formative evaluations. ED may, on a case by

case basis, use program implementers as a vehicle for collecting EM&V data when this would

clearly be more efficient.

4. IOU Role in EM&V Administration. D.05-01-055 adopts an approach to EM&V

administration whereby IOUs may directly contract for (and serve as technical lead in

managing) early EM&V, process and program design evaluations as well as market

assessment studies. Managing these studies assists IOUs in selecting and managing a portfolio

of programs to meet the CPUC’s objectives as well as provide them with access to

information on a real-time basis to improve program delivery. While soliciting input from

CPUC staff, the IOUs should also take the lead in allocating CPUC-authorized funding for

this category of EM&V across individual studies, develop the scope of work for each study

and prepare the RFPs when needed. In their program plan applications, the IOU should also

describe each type of study (including general scope of work) that they plan to manage

and/or directly contract for in this category. All interested parties should have an opportunity

to consider whether any of those proposed studies would create a conflict of interest if the

IOU or program implementers managed and directly contracted for them.

The EM&V budget is set at four percent of the total portfolio budget per D.12-05-015 and is

split between the program administrators and Energy Division, with the program

administrators responsible for 27.5 percent and Energy Division responsible for 72.5 percent.

While the IOUs and Energy Division are responsible for setting budgets for the evaluation

work they respectively oversee, the IOUs administer the overall budget in that they are

responsible for paying evaluation contractor invoices. The program administrators’ portion

of the budget may be increased to a maximum of 40 percent, however an increase above 27.5

percent is subject to discussions through the EM&V planning process, as outlined in D.16-

08-019.

5. ED Role in IOU EM&V Studies. CPUC staff’s role for approval and involvement in IOU

EM&V projects shall be as set forth in Attachment 2 of D.10-04-029.

a. An IOU shall seek approval from CPUC staff before initiating EM&V ex-ante studies,

or EM&V process and formative evaluations. The EM&V ex ante studies referred to

here are studies conducted by an IOU to develop energy savings estimates in specific

cases where there is no existing ex-ante estimate or an existing estimate is out of date

and needs testing, and for which CPUC staff is not already conducting or planning to

conduct a project to develop estimates for the same measure (regardless of the funding

dollars). The IOU management role for developing ex-ante savings estimates or

EM&V process or formative evaluations shall be under the oversight of CPUC staff,

who shall have the authority to deny approval of IOU proposed projects. This

authority is limited to situations where there is a conflict of interest with a contractor

the IOU wishes to hire, where there is duplication or significant overlap with studies

already planned or carried out by Energy Division, or where CPUC staff can specify

why a study is unnecessary or inappropriate. Energy Division’s approval process for

IOU’s ex-ante studies, or EM&V process or formative evaluations, is limited to no

more than two weeks. Any CPUC staff denial of approval shall be in writing to the

IOU requesting approval. If the proposed IOUs study is not approved within the two-

week timeframe, then it will be approved by default.

b. If CPUC staff expects to take three months or more to complete an ex ante study, an

IOU may request to develop the ex-ante study in order to ensure more timely

information. The CPUC staff may approve, or reject the request by providing the

IOU, within two weeks of the IOU’s request, with a written statement indicating that

such rejection is due to duplication of a study that will also be completed within 3

months, conflict of interest or other specific rationale.

c. CPUC staff may make case-by-case exceptions to the CPUC-adopted firewall policy

regarding program implementers in order to collect data needed for EM&V.

6. IOU Role in Energy Division managed EM&V Studies. All EM&V related projects

undertaken by the IOUs and Energy Division, regardless of funding source, shall adhere to the

same policies and procedures adopted in D.10-04-029 as EM&V-funded projects, except that

such EM&V policies and procedures do not apply to projects not previously considered to be

in the EM&V category. The process for the IOUs involvement in ED’s EM&V studies shall

supersede the process adopted in D.05-01-055, and shall be as follows:

a. CPUC staff and the IOUs will convene publicly-noticed meetings among their staff,

EM&V contractors, and stakeholders to share key results and EM&V findings that

might lead to improvements in the portfolio and identify best practices and possible

improvements to evaluation methods. Such meetings will take place sometime around

the middle of the program cycle or at such time when significant results from various

EM&V projects are available. If asked by parties or stakeholders, ED or IOUs, or

both, should hold short informal meetings with groups or individual organizations, to

discuss EM&V work progress and results.

b. CPUC staff and IOUs will convene ad hoc meetings (approximately quarterly) among

CPUC staff, EM&V contractors, IOU EM&V staff and IOU program managers to

discuss work progress and results. These meetings are to provide for timely feedback

to program design and implementation. The IOUs can request meetings with ED to

discuss work progress and results at any time.

c. When significant results are produced by the EM&V work, and a technical report is

not immediately pending, the CPUC staff and/or the IOUs will provide informal

written summaries of the results to the IOUs and other stakeholders. These written

summaries will be posted on the same website used for posting EM&V work plans

and comments.

7. Dispute Resolutions. A party may file a “Motion for Evaluation, Measurement and

Verification Dispute Resolution” (EM&V Motion) with the assigned Administrative Law Judge

for resolution of an EM&V matter. The EM&V Motion must include a statement from CPUC

staff giving its side of the dispute and documentation of an attempt at informal dispute

resolution. The Administrative Law Judge may issue a Ruling to resolve the dispute. The filing

party or the CPUC staff may ask that the matter be resolved by the assigned CPUC or the full

CPUC. In that case, the Administrative Law Judge (ALJ) will consult with the assigned

Commissioner to determine the appropriate course of action. In this situation, the assigned

Commissioner or ALJ may issue a Ruling to resolve the dispute. If the assigned Commissioner

determines the matter should be brought before the full CPUC, the ALJ or assigned

Commissioner shall issue a Proposed Decision and allow for comment under Rule 14 of the

CPUC’s Rules of Practice and Procedure. An EM&V motion filed pursuant to D.10-04-029

may be used for the following purposes only:

• Dispute over selection of an EM&V contractor;

• Disputes about project-specific final EM&V work plans;

• Disputes over results of EM&V studies or reports (except for Energy Division

Verification Reports, which are issued via draft resolutions per D.08-12-059);

• Disputes regarding final EM&V technical reports; and

• Disputes concerning public vetting of EM&V projects.

8. Public Vetting Process. ED shall determine which EM&V projects should be publicly

vetted and shall follow the process laid out in the Energy Division Straw Proposal, pages 8-

11, issued by Ruling in Proceeding A.08-07-021 on July 7, 2009. CPUC staff should

coordinate with other pertinent state agencies wherever such coordination enhances the

State’s overall energy policy goals. ED should weigh the value of public input on EM&V

studies versus the extra time such input would entail.

9. EM&V in the Rolling Portfolio. The adoption of the Rolling Portfolio in D.15-10-028 also

laid out an updated approach to ED-led impact evaluation studies. While market and

process evaluations are not tied to any evaluation schedule other than that in their respective

research plan(s), impact evaluations of uncertain measures are conducted within the Rolling

Portfolio schedule on an annual basis. Each year features a list of “bus stops” that are

deadlines for the critical steps in the portfolio update process. Bus stops set a “reliable,

regular schedule for future updates, so that any new information that ‘misses a bus’ can get on

board when the bus rolls around to the stop the following year.” The annual evaluation “bus

stop” schedule flows first from the annual EM&V plan update, which is expected to be

completed at the end of each year and reflect studies planned for the following year. In

addition to the timeline for impact evaluation studies, the bus stop process includes deadlines

for IOU workpaper updates as well as ED-determined DEER updates. D.15-10-028 as well

as the EM&V Plan (will be hyperlinked when updated) provide specific information on the

bus stop schedule and ongoing evaluation planning.

The EM&V funds for RENs and CCAs should be proportional to the program budgets

implemented by those administrators. Additionally, EM&V budget allocation to program

administrators may be increased to 40 percent on an approved and as-needed basis.

VIII. Shareholder Incentive Mechanism

This section outlines the Energy Savings and Performance Incentive (ESPI) Mechanism

established in D.13-09-023, as modified through D.15-10-028 and D.16-08-019, to promote

achievement of energy efficiency goals through programs. This new mechanism supersedes

the Risk/Reward Incentive Mechanism (RRIM) originally adopted in D.07-09-043 and

subsequently modified through a series of later decisions.

The ESPI Mechanism applies to EE program activities that began effective January 1, 2013,

and will continue in effect for subsequent cycles until further notice or direction. Relevant

supplemental documentation related to the ESPI include Resolutions E-3497, E-3510, E-

4807, E-4897, and E-5007 which have approved IOU incentive awards for program years

2013, 2014, 2015, 2016, and 2017.

1. Incentive Mechanism Criteria. The ESPI mechanism complements, integrates with, and

promotes EE programs and policy goals as adopted in D.12-11-015 (in Proceeding A.12-07-

001 et al). The following criteria inform the design of the incentive mechanism. The

incentives offered must:

• Be effective in spurring the utilities to a commitment to capture all cost-effective energy

savings as the first priority in the loading order by fostering innovation in approaches to

capture energy savings.

• Value longer-lasting and deeper savings. The mechanism should value efforts that

achieve deeper, more comprehensive, and longer-lasting savings. The mechanism should

maximize GHG reductions and encourage both market transformation and resource

acquisition programs.

• Rely on accurate, transparent, and timely EM&V to ensure clear, fair, and timely

implementation.

• Prudently use customer funds to ensure that customers are better off when utilities

invest in efficiency instead of supply-side alternatives (D.13-09-023, p. 19).

2. Energy Savings and Performance Incentive (ESPI) Categories. The ESPI mechanism

shall incorporate opportunities for performance incentives in the following categories:

a. Energy Efficiency Resource Savings:

An incentive is offered to encourage energy efficiency resource savings, paid as a

combination of ex ante “locked down” and ex post verified units of savings results,

according to the level of uncertainty of the measures for which savings are being claimed.

The methodology for measuring resource savings is modified from previous cycles to

focus on net lifecycle savings. Incentives for EE resource savings are capped at 9 percent

of resource program budgets, minus funding dedicated to administrative activities, codes

and standards programs, ME&O, On Bill Financing, EM&V, and CCA/RENs.

The energy savings performance award is split between ex-ante (i.e., estimated savings

pre-implementation) and ex-post (i.e., evaluated savings post implementation) savings

values. IOUs may file for incentive payments for ex-ante savings in the year following the

program year (PY+1) and for ex-post savings two years following the program year

(PY+2). Ex-post savings values will apply to custom measures and deemed measures on

the ESPI Uncertain Measure List for the corresponding year. Ex-ante values will apply to

deemed measures not on the ESPI uncertain measure list for the corresponding year

(Resolution E-4897, p. 5).

b. Ex-Ante Review Process Performance:

For performance in implementing the lock down of ex ante parameters, a performance

award shall be paid based on the scoring of performance metrics in accordance with the

protocol set forth in Section 7 of D.16-08-019.

The ex-ante review performance award is the product of the final IOU score and the

earnings cap for the component. Each IOU’s score is based on an evaluation of their

respective ex-ante review activities in accordance with the metrics below (further detailed

in Section 7 of D.16-08-019:

The award is capped at 3 percent of approved resource program expenditures.

Administrative costs, On-Bill Financing Loan Pool budget, and IOU Direct

Implementation Non-incentive (DINI) expenditures incurred beyond 20 percent of

resource program expenditures are subtracted from the authorized resource program

expenditures before calculating the 3 percent award. In case the IOU expenditures

exceed the authorized budget for resource programs, the approved annual budget for the

resource program category is used for calculating the caps. In that case, administrative

costs, On-Bill Financing Loan Pool budget, and IOU Direct Implementation Non-

incentive (DINI) expenditures incurred beyond 20 percent of resource program

expenditures are subtracted out from the approved program budget.

c. Codes and Standards (C&S) Program Management Fees:

An incentive for savings from building C&S advocacy is paid as a management fee equal

to 12 percent of approved C&S program expenditures, not to exceed authorized

expenditures, and excluding administrative costs.

d. Non-Resource Program Management Fees:

For performance in implementing non-resource programs (which support savings based

programs but in which there are no direct savings), a management fee shall be paid equal

to 3 percent of non-resource program expenditures, not to exceed authorized

expenditures for these programs exclusive of administrative costs (D.13-09-023, pp. 19-

20)

Incentive caps are specific to each component. If a utility does not earn up to the cap of

one component, those incentives are not available to be earned under a different

incentive component (D.13-09-023, p. 95, OP 3).

3. Scaling Incentive Earnings Potential for Resource Savings. It is the intent of the

mechanism to award incentive based on net savings goals, adjusted for the effects of “free

riders” and "spillover”(D.13-09-023, p. 36). For purposes of designing incentive performance

metrics, incentive earnings potential are scaled in relation to the appropriate level of resource

savings goals (D.13-09-023, p. 33-34). Savings incentive earnings accrue as a function of: (a) a

pre-determined level of earnings potential, and (b) designated efficiency savings goals (D.13-

09-023, p. 32).

The following formula derives net lifecycle goals (in units of energy savings) (D.13-09-023, p.

37):

Annualized

Goals *

Target Effective Useful Life

Target Net-to-Gross %

Lifecycle

(in kWh,

MW, MMth)

(in years)

(in %)

Net

Target

Goal

Earnings rate coefficients shall be calculated as the amount that correlates incentive earnings

potential for resource savings with a cap of 9 percent of the approved resource program

budget for each savings type, excluding funding for administrative activities, Evaluation,

Measurement and Verification, codes and standards programs, On Bill Financing Loan

program budgets, Marketing Education and Outreach program budget, and the Regional

Energy Network/Community Choice Aggregation programs not administered by the utilities

(D.13-09-023, p. 97, OP 13). The coefficient (i.e., earnings per unit of resource savings) that

correlates incentive earnings with EE Net lifecycle goals is calculated based on the following

formula (D.13-09-023, p. 33):

(Total incentive earnings potential) / (Net Lifecycle units of resource savings)

= Incentive Earnings Per Unit of Savings

Target EUL values of 12 years for electric measures and 15 years for gas measures, and a

target NTG of 0.8 for both electric and gas measures shall be utilized in calculating lifecycle

goals to emphasize the importance of challenging the IOUs to stretch their capabilities to

reach higher standards of performance over time (D.13-09-023, p 37).

4. Ex Ante Review Performance Scoring. Energy Savings Performance Incentive scores for

deemed and custom activities shall be weighted for the utility program administrators based

on the proportion of deemed savings and custom measures in each utility’s portfolio. The

annual scores for deemed and custom activities be weighted by the fraction of portfolio

annual net lifetime savings kWh and therm claims, as reported in the utility annual advice

letter filed in September of each year. Combined electric and gas utilities would additionally

weight their electric and gas net lifetime claims by the total incentives paid for gas versus

electricity.

5. Uncertain Measures. For custom projects and for specific "deemed" measures with ex

ante parameters that are identified as highly uncertain, CPUC Staff shall require ex post

evaluations as the basis for calculating savings incentive payments. The savings award for the

remaining "deemed" measures will be calculated based on the locked down ex ante parameter

values, and only the claimed measure count will be subject to ex post adjustment for these

measures (D.13-09-023, p. 50).

By October 31 of each year prior to the program year, CPUC Staff will identify deemed

measures, in the DEER or in an IOU-submitted non-DEER workpaper, for which one or

more savings parameters are sufficiently uncertain that the savings claim should be subject to

ex post verification in order to be included in the incentive payment. For ESPI purposes,

"sufficiently uncertain" measures are defined as those measures for which the CPUC believes

the net lifetime savings of the current DEER or non-DEER savings estimate may be as

much as 50 percent or more under- or over-estimated (D.13-09-023, p. 51). The resulting list

is called the ’Uncertain Measure list.’

D.16-08-019, p, 113, OP 19. Adopts the weighting methodology provided in the June 8, 2016 Administrative

Law Judge’s ruling seeking comment on Evaluation, Measurement, & Verification and Energy Savings

Performance Incentive issues, p. 12.

6. Calculating Resource Savings Incentive Awards. Efficiency Savings and Performance

Incentive awards for resource savings shall be derived as the sum of the following

components that increase as a linear function up to the earnings target for each respective

savings type (D.13-09-023, p. 96, OP 9):

--For savings of electric consumption:

(Units of kWh Savings) * (Earnings Rate Coefficient)

--For reduction of peak electric demand

(Units of mega-watt (MW) Reductions) * (Earnings Rate Coefficient)

--For savings of natural gas consumption:

(Units of MMTherm Savings) * (Earnings Rate Coefficient)

7. Verification of Expenditure and Claims Data. In order to verify Codes and Standards

and non-resource program expenditures for the purposes of awarding these management

fees, CPUC Staff will rely upon public versions of the CPUC’s Utility Audit, Finance and

Compliance Branch reports. Upon completion, the CPUC’s Utility, Audit, Finance and

Compliance Branch shall serve on the service list in this proceeding (or its successor) a notice

of availability of the public copy of its audit report detailing its review of annual expenditures

for the Energy Efficiency programmatic activity of the respective program year(s) (D.13-09-

023, p. 98, OP 17).

To avoid data discrepancy across various submissions, the IOUs must use their final official

program year tracking data as the basis for all their submissions that include data associated

with that specific program year. IOUs may not make any changes to the data after the final

submission, save for the following provision: if an IOU discovers any errors in the data after

the final tracking data is submitted, then the IOU must update its tracking data in CEDARS

and notify the Energy Efficiency Branch Program Manager; the Utility Audit, Finance and

Compliance Branch Program Manager; and all parties to the active energy efficiency

proceeding (i.e., Proceeding R.13-11-005 or its successor) of any such changes (D.18-05-041,

pp. 131-132).

8. Resource Savings Claim and Expenditure Eligibility. IOUs should only include savings

for measures installed (the year the measure has been physically installed and became

operational to deliver savings) in the same year they are claiming incentives for.

IOUs

should indicate the measure installation date in their data submissions.

9. Approval of Incentive Claims. In accordance with the schedule set forth in Attachment 6

of D.15-10-028, an annual Tier 3 advice letter shall be filed for approval of incentive claims

in accordance with the schedule adopted in this decision. The first annual advice letter will

occur beginning in 2014, and continuing annually thereafter, to claim recovery of Efficiency

Savings and Performance Incentive (ESPI) incentive elements in the following sequence

(D.13-09-023, pp. 95-96, OP 4):

Claims for ESPI awards covering the first program year (PY) of each cycle shall be made

during the first following year (PY +1) for the following ESPI elements:

• Non-Resource program management fee

• Codes and Standards program management fee

• Ex ante performance award

• Preliminary ex ante locked down deemed measure savings award

Claims covering the first program year of each cycle shall be made in the second following

year (PY +2) for the following ESPI elements:

• Custom projects

• Ex post verified deemed measure savings

• True up of preliminary ex ante lockdown award based on verified counts.

10. Dispute Resolution of Ex Post Evaluations. If necessary to resolve disputes over ex post

results, and only after other more informal efforts at resolution have been exhausted, parties

may invoke the dispute resolution process established in D.10-04-029, in accordance with the

process set forth in Attachment 4 of D.13-09-023.

The annual installation date based claims requirement was introduced in D.04-09-060 (at 33 and Findings of

Facts 14) , clarified and reiterated in D.05-04-051 (at 55, Findings of Fact 36-42, Conclusion of Law 3, Ordering

Paragraph 17), D.05-09-043 (at 84) and again in Resolution G-3510 (at 13), Resolution E-4807 (OP.10), and

Resolution E-4897 (at 15-16) .

D.13-09-023, p. 96, OP 9.

11. References. See the following attachments and references below for further information on

the ESPI process.

a. http://www.deeresources.com/index.php/espi

b. http://www.cpuc.ca.gov/General.aspx?id=4137

IX. Third Party Solicitation Process

Senate Bill (SB) 350 increased reliance on pay-for performance strategies and meter based

energy savings evaluation for energy efficiency programs in California. These requirements

increase the reliance on third party energy efficiency program and delivery which are inherently

performance based. This legislation resulted in the following:

• The CPUC adopted D.16-08-019 setting a minimum target of 60 percent of the utility’s

total budgeted portfolio, including administrative costs and EM&V, (up from the

previously target of 20 percent) to be third-party designed and delivered by the end of

2022 via a stepped approach (see below). The rationale for this requirement reflects the

CPUC’s view that the utility role should focus more on the design and management of the

energy efficiency portfolio overall, and less on individual program design and

implementation.

D.16-08-019 emphasized that third party design and implementation should become the

default for much of the portfolio, unless the utilities can justify why use of utility

personnel should continue. This same decision defined third-party as a program primarily

designed and presented to the utility by a third party, in addition to delivered under

contract to a utility (p. 69 – 70). Specifically the Decision stated; ”A program must be

proposed, designed, implemented, and delivered by non-utility personnel under contract to

a utility program administrator.” This direction requires clear solicitation protocols amid a

likely increase in third-party IOU program administration contracts. Solicitation efforts

aim to reach the 60 percent third-party target, using the new third-party definition adopted

in D.16-08-019. via a phased approach (D.18-05-041) of minimum percentages of 25

percent by December 19, 2019; 40 percent by December, 31, 2020; and 60 percent by

December, 31, 2022.

• In January of 2018 the CPUC adopted D.18-01-004. This decision addresses the required

process for third party solicitations in the context of pre-existing rolling portfolio

structure for energy efficiency programs overseen by the investor-owned utility (IOU)

program administrators (PAs); The CPUC adopted D.15-10-028 in October of 2015,

which established a “Rolling Portfolio” process for regularly reviewing and revising energy

efficiency program administrators’ portfolios.

1. Two-Stage Solicitation Process: A two-stage process should be used unless there is a

specific -schedule related- reason that a shortcut must be used where the first stage is a short

request for abstract and the second stage is a full request for proposals. The first stage is the

Request for Abstract (RFA) Stage. In this stage, third-party implementers would provide a

short abstract summarizing their proposed program, approach, qualifications and experience,

and indicative pricing. If there was a robust response, the IOUs would then issue a request

for proposal (RFP) soliciting detailed offers from qualified bidder respondents. RFP

responses would then be evaluated with qualitative and quantitative criteria and would also

utilize inperson- interviews. The most competitive participants would then be notified that

they are short-listed and would proceed to the contract negotiation phase. D.18-01-004, p. 7

2. Scoring Solicitations: Once participant submit their abstracts in the RFA phase described

above, “[t]he IOUs would then select potentially qualified respondents following scoring and

evaluation of the abstracts including the viability and usefulness of the programs proposed in

the RFAs.” The RFA shortlist results are not required to be shared among PAs. Doing so

may not only be impractical, but also may violate expectations of confidentiality on the part

of bidders and it is not clear what benefits would override those considerations. Each PA is

ultimately responsible for its own solicitation process, while as much informal

communication and coordination among the PAs as possible is encouraged (D.18-01-004, p.

48). A separate scoring process will be developed and implemented in the Request for

Proposal (RFP) phase of the solicitation process.

D.18-01-004 also established a stakeholder advisory groups known as a “Procurement

Review Group” (PRG) comprised of Energy Division staff and eligible non-market

participants to consult with the IOUs in the design of the RFP and the evaluation of bids on

a quarterly basis (see Section X.2. below for more information on the PRG).

3. Solicitation Schedule: Implementation plans for third party programs will necessarily be

developed and posted after solicitations have concluded. However, the timely and up--to-

date- posting of those implementation plans as soon as practical, but no later than 60 days

after contract execution, is still required. For programs that will be bid out in later rounds of

the solicitation schedule, posting of implementation plans is still required after the CPUC’s

decision on the business plans, to reflect programs available to customers in the interim

before additional third-party solicitations are scheduled to take place.

4. Energy Division Review of Solicitations: Any contract that has a value of $5 million or

greater and/or a term of more than three years, must be submitted to the CPUC for approval

via a Tier 2 advice letter. Contracts may be submitted in batches, at the discretion of the

contracting utility. CPUC staff should ensure the contracts filed by advice letter comply with

the utility’s approved business plan, all CPUC decisions and direction, are not the result of a

biased solicitation process, and do not thwart the intentions of successful program design,

delivery, and realized savings, for some or all sectors and subsectors of customers. CPUC

staff always can review any contract informally at any time, including those that do not meet

the dollar or length thresholds identified above for required submittal by advice letter.

In addition to the advice letter process described above for contracts valued at $5 million or

greater and/or a term of more than 3-years, CPUC staff will also serve on the PRG utilized

for general solicitation review…”Each utility will have at least one PRG, and at its discretion,

may utilize more than one PRG, if the IOU prefers to tailor the PRGs for specific market

segments or other purposes. The PRGs shall consist of non-financially interested- parties,

representing diverse stakeholder interests, as well as CPUC staff, including ORA.” D.18-01-

004, p. 35

5. Independent Evaluator’s (IEs) Role in Solicitation Process: In D.18-01-004, p. 2, 9, 33,

and 36-38 the CPUC requires the IOUs to utilize Independent Evaluators to support the

solicitation process. More specifically, the Decision directs the IEs utilized by the utilities for

these energy efficiency third party solicitations to be hired specifically for this purpose and to

possess energy efficiency expertise. The role of the IEs is designed to lend arms

length- expertise evaluating the fairness of the conduct and results of the solicitation process

by the IOUs. In addition, IOUs should consult with Energy Division staff during the

selection process and the Energy Division director should have final approval over the pool

of IEs selected by each utility.

“…The IEs monitor the entire solicitation process and provide a written report at the end

that is delivered formally to the CPUC as part of the contract evaluation and approval

process.” Because not all third party contracts will be submitted for formal approval by the

CPUC, a formal IE report will accompany only those contracts required to be submitted via a

Tier 2 advice letter (i.e., those contracts valued at $5 million or more and/or with terms of

longer than three years), (D.18-01-004, p. 37).

The IEs provide recommendations on all solicitations which shall be submitted to the

members of the PRGs. The IEs should also monitor the entire process from RFA design to

contract execution for all solicitations and contracts, not only those required to be submitted

to the CPUC for approval. For the entire solicitation process the IE will serve as a consultant

to the PRGs by participating in PRG meetings and shall also provide assessments of the

overall third party solicitation process and progress on at least a semi-annual basis to the

CPUC via reports filed in the relevant energy efficiency rulemaking. The CPUC may, as this

process progresses, see a need for a stronger IE function. The CPUC therefore reserves the

right, at any point in the future, to hire an IE or multiple IEs itself, as part of our evaluation

and oversight functions. (D.18-01-004, p. 38)

6. Workforce Standards: The workforce standards are applied to non-residential HVAC and

lighting projects for both existing utility programs and 3P solicitation starting July 1, 2019.

These are intended as a starting point for potentially more far-reaching requirements in the

future. Incentivized projects of $3,000 for HVAC and $2,000 for lighting will have specific

criteria requirements of installation technicians

. (D.18-10-008, pg. 76-77)

With respect to third party contracts for the workforce, the utilities will propose a set of

requirements for the contract among the modifiable terms with specific recommendations for

each market or sector to identify the applicable workforce installer standards that would reduce

the risk of lost energy savings from poor installation of energy efficiency measures including any

specific skills certification requirements and/or broader occupational training and experience

requirements (such as journeymen and apprenticeship requirements). D.18-01-004, p. 40 - 41, in

OP 9, all EE program administrators shall define "disadvantaged worker," for purposes of their

Requirements of installation technician doing work onsite. For Lighting: California Advanced Lighting Controls

Training Program (CALCTP) certification. For HVAC: Completed or enrolled in a California or federal accredited

HVAC apprenticeship; Completed at least five years of work experience at the journey level as defined by the

California Department of Industrial Relations and passed a practical and written HVAC system installation

competency test and received credentialed training specific to the installation of the technology being installed; or

Has a C-20 HVAC contractor license from the California State Contractor’s Licensing Board.

EE portfolios and tracking metrics or indicators associated with them, as an individual that meets

certain criteria

(D.18-10-008, pg. 79).

X. Advisory Groups

The CPUC’s approach to policy making and practicing administrative law relies on a

combination of formal and informal public input that support the development of a record in

an administrative proceeding.

For energy efficiency proceedings, the CPUCs continues to promote informal advisory group

opportunities for obtaining stakeholder input:

1. California Energy Efficiency (EE) Coordinating Committee (CAEECC): In D.15-10-026,

(p. 71 - 72) the CPUC established a statewide coordinating committee. Per this decision, “There

is no need for Program Administrator (PA)-specific Program Advisory Groups (PAGs), as the

PAs all deal with a similar set of issues. The focus now can be on how the PAs incorporate the

ideas and concepts developed by the coordinating committee into their specific portfolios.

A single coordinating committee should facilitate greater statewide coordination and

harmonization of statewide programs across PAs. As we said in D.05-01-055, “we expect the PAs

to ensure that statewide residential and nonresidential program offerings take advantage of best

practices and avoid customer confusion by being as uniform and consistent as

possible…Subcommittees should be along sector lines, not separated by PA.

a. Scope of Work for CAEECC:

i. Provide input into development of business plans prior to and throughout the

drafting process (see notes below re scope of input and timing);

ii. Provide input into development of implementation plans, again, prior to and

throughout the drafting process;

Disadvantaged Workforce Criteria: Total household income is below 50 percent of AMI; is a recipient of public

assistance; lacks a high school diploma or GED; has history of incarceration of more than one year; is a custodial

single parent; is chronically unemployed; was in the foster care system; has limited English proficiency; or lives in a

high unemployment ZIP code that is in the top 25 percent of only the unemployment indicator of the

CalEnviroScreen Tool.

iii. Provide input into development of annual budget advice letters, again, prior to and

throughout the drafting process; and,

iv. Provide input into development and revision of metrics for inclusion in business

plans and implementation plans as part of i and ii.

v. Provide a clearinghouse for discussion of the scope and schedule of other

stakeholder processes.

In this same decision, the CPUC acknowledged, “the Coordinating Committee will obviate the

need for some current stakeholder processes. From a practical perspective, some current

processes will have to give way, as stakeholders and CPUC Staff have time for only so many

processes…(We) repeat here the admonition we gave in D.05-01-055: we provide general

guidance and expectations for the [stakeholder] group structure, but purposefully do not specify

every implementation detail.”

D.18-05-041 directed the PA’s Annual Budget Advice Letter (ABAL) proposals be shared with

CAEECC. Additionally, this same decision stipulated, “…the program administrators shall host a

forum for stakeholder input on implementation plan development for new programs either

through the California Energy Efficiency Coordinating Committee or another workshop hosted

by the program administrators following the issuance of this decision.”

D.18-10-008 which established EE related workforce requirements and third-party contract terms

and conditions also directed the CAEECC to convene a stakeholder process, no later than July 1,

2020, to consider further application of workforce standards beyond those adopted in this

decision including any additional lighting controls certification. This will allow time for

consideration of experience with the standards required herein.

For more detailed information about the CAEECC including role of the PAs vs. the

Coordinating Committee, Energy Division Staff participation on the Committee, sub-committee

guidance, and meeting schedule / agenda development, etc. please see: D.15-10-028. For more

information about the CAEECC’s roll in reviewing PA Rolling Portfolio submissions please see:

D.18-05-041

2. Procurement Review Group (PRG): In D.02-08-071, p. 24, the CPUC established stakeholder

advisory groups known as “Procurement Review Groups (PRGs) comprised of eligible non-

market participants to consult with the IOUs in the design of the RFP and the evaluation of bids

on a quarterly basis; “In order to ensure that interim procurement contracts entered into by the

utilities are subject to sufficient and expedited review and pre-approval, we will require each utility

to establish a PUC-authorized “Procurement Review Group” whose members, subject to an

appropriate non-disclosure agreement, would have the right to consult with and review the details

of, and assess proposed contracts and provide written comments to the IOUs before they submit

contract(s) to the CPUC.”

Over the years the usefulness and purpose of these stakeholder groups became questionable

given the changing regulatory landscape and competition for stakeholder engagement resulted in

limited stakeholders for these purposes. In D.18-01-004, Section 3.4 the concept of the PRG was

resurrected again, “We agree there is value in continuing the PRGs, which have existed in some

form for some time. The PRGs are a useful vehicle for following the solicitation processes and

providing feedback to the PAs. Continuing the PRGs balances the goals of oversight and

transparency, as well as timely feedback, with the desire to have an expeditious solicitation

process.”

Each utility has at least one PRG, and at its discretion, may utilize more than one PRG if the

IOU prefers to tailor the PRGs for specific market segments or other purposes. The PRGs shall

consist of non--financially interested- parties, representing diverse stakeholder interests, as well as

CPUC staff, including ORA. In terms of the PRG’s ultimate responsibilities, we expect the

PRGs to be involved at all levels in the solicitation process, including:

• Draft RFA review

• Review of RFA bids and shortlist

• Draft RFP review

• Review of RFP bid selection criteria

• RFP shortlist and selected contractor review

• Review IE evaluations of all solicitations.

D.18-05-041 requires PAs to “…consult the new energy efficiency PRG and present its proposal

to meet the Annual Budget Advice Letter (ABAL) review criteria in future program. For more

information about PRGs including direction related to PRG composition, meeting, the PRG

Handbook and meeting minutes please see:

https://www.caeecc.org/third-party-solicitation-process

XI. Affiliate and Disclosure Rules

1. Transactions with IOU Affiliates. To avoid anti-competitive behavior and cross- subsidies

between IOUs and their affiliates, all transactions between the IOU administrator and any

implementer that is an affiliate of PG&E, SCE, SDG&E or SoCalGas are banned (D.05-01-055).

2. Treatment of Energy Efficiency Service Providers. The IOUs, RENs and CCAs will not

provide preferential treatment to any provider of an energy efficiency service that uses energy

efficiency program funds.

3. Conflict of Interest. Bidders for EM&V contracts, including program design evaluation and

market assessment studies, shall provide full disclosure of any potential conflicts of interest,

including all current non-energy efficiency related contracts with IOUs, RENs, CCAs and

program implementers. Each utility should have at least one PRG, with members who are not

financially interested in solicitation results and represent diverse stakeholder interests, to provide

feedback during the third party solicitation process. The PRGs should be involved at all stages of

the solicitation process participants should be eligible for intervenor compensation (D.18-01-004,

pg. 57).

XII. Process and Procedural Issues

1. Energy Efficiency Policy Manual Disclaimer. This Policy Manual is a summary of CPUC

rules for energy efficiency. It does not supersede any CPUC Decision. IOUs, RENs and

CCAs are required to meet the orders of previous CPUC decisions regardless of whether or

not they are included in this policy manual. If there is any conflict between this Policy Manual

and a CPUC decision, the CPUC’s decision controls.

2. Modifications to Policy Manual and Related Rules. Energy Division will update this

manual as needed based on significant changes related to Energy Efficiency policy. Due to

the unknown frequency of policy changes, and potential lag time in updating this manual,

interested parties are encouraged to use other sources to receive the most up to date

information keeping in mind that some references to older decisions in this manual may have

been superseded by more recent CPUC guidance. It is the responsibility of the reader to

ensure the most recent policies, pertinent to their policy related questions, are referred to.

3. Complaints and Dispute Resolution. Any program proposal for energy efficiency funding

must describe a dispute resolution process to be used in dealing with complaints from end-

use gas or electric consumers participating or attempting to participate in the program. In

programs where the IOUs, RENs, and CCAs hold contracts with third parties, those

contracts will also be required to include dispute resolution provisions.

APPENDIX A: ADOPTED FUND SHIFTING RULES

As modified by D.12-11-015, 12/22/2011 ACR (R.09-11-014), D.09-09-047, D.09-05-

037,D.07-10-032, D.06-12-013, andD.05-09-043

Notes

Any fund shifting will be shown on the quarterly fund shifting report which will be provided to

the Energy Division beginning 7/1/13 (and every 90 days thereafter).

Fund Shifting

Category

Shifts Among Categories

Statewide

Program

(except ET,

ME&O, and

C&S)

No formal

Commission

review/appr

oval

required

No formal

Commission

review/approv

al required

Advice letter required for

shifts >15% between

statewide program

categories in either

direction (based on each

category funding level)

per annum. See rules

below for shifting away

from ET,

ME&O, and C&S.

Third Party

Programs

(competitively

bid)

(See Notes

Below)

No formal

Commission

review/appr

oval

required

No formal

Commission

review/approv

al required

Advice Letter required

for shifts >15% between

statewide and Third

Party (competitively bid)

program categories in

either direction (based

on total category funding

level) per annum.

Advice Letter is required if

allocation to competitively

bid programs falls below

20% of total portfolio

funding.

Local

Government

and

Institutional

Partnerships

(See Notes

Below)

No formal

Commission

review/appr

oval

required

No formal

Commission

review/approv

al required

Advice Letter required for

shifts >15% between

statewide and Local

Government and

Institutional Partnership

program categories in

either direction (based on

category funding

level) per annum.

No program or sub-program shall be eliminated except through the Advice Letter process.

For adding new programs, except those chosen during a competitive process, an Advice

Letter must be filed.

“Third Party Programs” include any third-party programs that are competitively bid and count

towards the percentage competitive bidding requirement. In aggregate, these programs constitute

a twelfth category (in addition to the 11 statewide program categories), subject to the 15 percent

fund-shifting rule requiring an Advice Letter if the amount transferred from this category is

greater than 15 percent in either direction. Fund-shifting of any amount within this twelfth

program category is allowed without an Advice Letter.

“Local Government and Institutional Partnerships.” In aggregate, these programs constitute a

thirteenth category (in addition to the 11statewide program categories, and third-party programs),

subject to the 15 percent fund-shifting rule requiring an Advice Letter if the amount transferred

from this category is greater than 15 percent in either direction. Fund-shifting of any amount

within this thirteenth program category is allowed without an Advice Letter.

“Other Programs” include local programs and any other programs not capture in the

aforementioned categories. In aggregate, these programs constitute a fourteenth category (in

addition to the 11statewide program categories, third-party programs, and local government and

institutional partnerships), subject to the 15 percent fund- shifting rule requiring an Advice Letter

if the amount transferred from this category is greater than 15 percent in either direction. Fund-

shifting of any amount within this fourteenth program category is allowed without an Advice

Letter.

The 15 percent fund-shifting rule, requiring an Advice Letter if the amount transferred from this

category is greater than 15 percent in either direction, is applied to the category funding level in

the authorized budget adopted in the compliance filing pursuant to the most recent authorizing

decision (or the decision itself, if there is no compliance filing).

Utility program administrator may carryover/carryback funding during the current program

cycle without triggering a review/approval process.

Changes to incentive levels or modifications to program design (such as changes to customer

eligibility requirements) will not trigger Energy Division or formal CPUC review. Program

administrators will notify the CPUC of all incentive level changes that take place through the

Program Implementation Plan Addendum process.

Advice letters are subject to General Order (GO) 96B.

Marketing Education & Outreach and EM&V programs are subject to overall caps adopted in

D.09-09-047 OP 13. Program administrators may request fund shifting augmentations if they

wish to increase budget caps. In addition, the fund shifting changes adopted in D.09-09-047 are

not intended to change Rule II.2 of the Energy Efficiency Policy Manual V.5 as applied to EM&V

and ME&O spending below the adopted caps, nor to change the fund shifting rules for C&S or

Emerging Technologies programs.

APPENDIX B: GLOSSARY

COMMON ENERGY EFFICIENCY

TERMS AND DEFINITIONS

Adopted Program Budget

The program budget as it is adopted by the CPUC. Inclusive of costs (+/-) recovered from other

sources.

Advanced Technologies

Measures or processes which exceed the efficiency or thermodynamic performance of standard

energy using equipment or processes.

Affiliate

Any person, corporation, utility, partnership, or other entity 5 percent or more of whose outstanding

securities are owned, controlled, or held with power to vote, directly or indirectly either by an

administrator or any of its subsidiaries, or by that administrator's controlling corporation and/or any

of its subsidiaries as well as any company in which the administrator, its controlling corporation, or

any of the administrator's affiliates exert substantial control over the operation of the company

and/or indirectly have substantial financial interests in the company exercised through means other

than ownership. For purposes of these Rules, "substantial control" includes, but is not limited to, the

possession, directly and indirectly and whether acting alone or in conjunction with others, of the

authority to direct or cause the direction of the management of policies of a company. A direct or

indirect voting interest of five percent (5 percent) or more by the administrator, its subsidiaries, or its

affiliates in an entity's company creates a presumption of control.

Avoided Costs

Avoided costs refers to the incremental costs avoided by the investor-owned utility when it purchases

power from qualifying facilities, implements demand-side management, such as energy efficiency or

demand-response programs, or other wise defers or avoids generation from existing/new utility

supply-side investments or energy purchases in the market. Avoided costs also encompass the

deferral or avoidance of transmission and distribution-related costs. (D.08-01-006, Footnote 2)

Baseline Data

The state of performance and/or equipment that what would have happened in the absence of the

program induced energy efficiency.

California Energy Efficiency (EE) Coordinating Committee (CAEECC)

In D.15-10-026, (p. 71 - 72) the CPUC established a statewide coordinating committee whose role is

to facilitate greater statewide coordination and harmonization of statewide EE programs across

program administrators (PAs).

Coincident Peak Demand

The metered or estimated demand of a device, circuit, or building that occurs at exactly the same time

as the system peak for a given year and weather condition.

Community Choice Aggregators

Organizations created by local governments pursuant to Assembly Bill 117 for the purpose of

procuring power and administering energy efficiency programs on behalf of local citizens.

Competitive Solicitation

The process whereby parties are requested to submit bids offering innovative approaches

to energy savings or improved program performance.

Conservation

Reduction of a customer's energy use achieved by relying on changes to the customer's behavior

which may result in a lower level of end use service.

Conservation Measures

Activities and/or behaviors aimed at reducing energy consumption.

Conservation Programs

Programs which are intended to influence customer behavior as a means to reduce energy use.

Cost Effectiveness

An indicator of the relative performance or economic attractiveness of any energy efficiency

investment or practice when compared to the costs of energy produced and delivered in the absence

of such an investment.

Cost-Effectiveness Tool

Avoided Cost Calculator Tool

Cream Skimming

Cream skimming results in the pursuit of a limited set of the most cost-effective measures, leaving

behind other cost-effective opportunities. Cream skimming becomes a problem when lost

opportunities are created in the process.

Cross Subsidization

Benefits enjoyed by one group, such as a customer class, which are funded by another group.

Custom Measures/projects

Energy efficiency efforts where the customer financial incentive and the ex ante energy savings are

determined using a site-specific analysis of the customer’s facility (D.11-07- 030 page 31).

Customer

Any person or entity that pays an electric and/or gas bill to an IOU or CCA and that is the

ultimate consumer of goods and services including energy efficiency products, services, or

practices.

Cumulative Savings

As clarified in D.07-10-032, cumulative savings represent the savings in that year from all previous

measure installations (and reflecting any persistence decay that has occurred since the measures

were installed) plus the first-year savings of the measures installed in that program year.

Deemed Measure

A prescriptive energy efficiency measure.

Delayed Installation

Products which are claimed as installed in a specific quarter but are likely to be installed at a later date

(D.11-07-030, page 21).

Dual Test

The requirement that an energy efficiency activity pass both the TRC and the PAC cost-

effectiveness test.

Effective Useful Life (EUL)

An estimate of the median number of years that the measures installed under the program are

still in place and operable.

Electricity Savings

Reduced electricity use (or savings) produced by either energy efficiency investments which maintain

the same level of end use service or conservation actions which usually reduce energy use by reducing

the quantity or quality of the baseline energy services demanded.

Emerging Technologies

New energy efficiency technologies, systems, or practices that have significant energy savings

potential but have not yet achieved sufficient market share (for a variety of reasons) to be

considered self sustaining or commercially viable. Emerging technologies include late stage

prototypes or under-utilized but commercially available hardware, software, design tools or energy

services that if implemented appropriately should result in energy savings.

Emissions Reductions

The CPUC requires annual reporting of reduced emissions of carbon dioxide (CO2), sulfur oxides

(SOx), nitrous oxides (NOx), and particulate matter (PM10) as a result of energy efficiency savings.

The IOUs use the E3 calculator to compute the annual electric and natural gas emissions

reductions, which are the units implemented in the year times the annual emission reduction for a

particular measure. The E3 calculator calculates values of CO2 in tons per kWh or therms; NOx

and PM10 are in pounds per kWh or therms.

The following equations are from the “E3 Calculator Tech Memo” found at the following web link:

https://www.ethree.com/wp-content/uploads/2017/02/E3_Calculator_TechMemo_6d.docx

Electric Reductions: CO2 tons per year (Emission[E][CO2])

( )

MMMQMy

GRRIRCOERNTGAwtdkWhINCOEEmission **]2[**__*]2][[

4*)1(1



−+=

Where

y = year of consideration. First year of program cycle = 1.

Q = Quarter of the year.

INM,Q = # of incremental of measures implemented in quarter Q.

NTGM = Net–to-Gross ratio for energy for measure M, adjusted for market effects.

ER[CO2]M = Emission rate of CO2 in tons per kWh of measure M.

NOX and PM-10 equations are the same. Just replace [CO2] with the appropriate indicator.

Note that CO2 emission rate is in tons per kWh. NOX and PM-10 are in pounds per kWh.

Gas Reductions: CO2 tons per year (Emission[G][CO2])

( )

GCTMMQMy

GRRIRCOERNTGAwtdThINCOGEmission **]2[**__*]2][[

4*)1(1



−+=

Where

y = year of consideration.

Q = Quarter of the year.

INM,Q = # of incremental of measures implemented in quarter Q.

NTGM = Net–to-Gross ratio for energy for measure M, adjusted for market

effects.

ER[CO2]GCT = Emission rate of CO2 in tons per therm, based on the gas combustion

type (GCT) specified on the input sheet for the measure.

NOX and PM-10 equations are the same. Just replace [CO2] with the appropriate indicator.

Note that CO2 emission rate is in tons per Therm. NOX and PM-10 are in pounds per Therm.

Energy Efficiency Groupware Application (EEGA)

The IOUs post reports to the EEGA webpage, which is accessible to the public:

http://eega.cpuc.ca.gov.

End Use

1) The purpose for which energy is used (e.g. heating, cooling, lighting).

2) A class of energy use that an energy efficiency program is concentrating efforts upon.

Typically categorized by equipment purpose, equipment energy use intensity, and/or

building type.

Energy Efficiency

Activities or programs that stimulate customers to reduce customer energy use by making

investments in more efficient equipment or controls that reduce energy use while maintaining a

comparable level of service as perceived by the customer.

Energy Efficiency Measure

An energy using appliance, equipment, control system, or practice whose installation or

implementation results in reduced energy use (purchased from the distribution utility) while

maintaining a comparable or higher level of energy service as perceived by the customer. In all cases

energy efficiency measures decrease the amount of energy used to provide a specific service or to

accomplish a specific amount of work (e.g., kWh per cubic foot of a refrigerator held at a specific

temperature, therms per gallon of hot water at a specific temperature, etc). For the purpose of these

Rules, solar-powered, non- generating technologies are eligible energy efficiency measures (D.09-12-

022, OP 1).

Energy Efficiency Programs

Programs that reduce customer energy use by promoting energy efficiency investments or the

adoption of conservation practices or changes in operation which maintain or increase the level of

energy services provided to the customer.

Energy Efficiency Savings

The level of reduced energy use (or savings) resulting from the installation of an energy efficiency

measure or the adoption of an energy efficiency practice, subject to the condition that the level of

service after the investment is made is comparable to the baseline level of service. The level of

service may be expressed in such ways as the volume of a refrigerator, temperature levels, production

output of a manufacturing facility, or lighting level per square foot.

Evaluation, Measurement and Verification (EM&V)

Activities that evaluate, monitor, measure and verify performance or other aspects of energy

efficiency programs or their market environment.

Evaluation Project Budget

The project level evaluation budget as it is defined by the program administrators or Energy Division

for internal program budgeting and management purposes. Inclusive of direct and allocated overhead

and costs (+/-) recovered from other sources.

Ex Ante (Forecast) Values

Estimated savings values calculated based on assumptions prior to the evaluation of the portfolio cycle.

These savings reflect the IOU reported savings, which are trued up with final evaluation.

Ex Ante (Forecast) Review

The review process that occurs before savings for a measure or project savings claim is “frozen” to

verify that the ex ante values used to calculate the reported savings are reasonable and based on best

available information.

Financial Incentive

Financial support (e.g., rebates, low interest loans, free technical advice) provided to customers as

an attempt to motivate the customers to install energy efficient measures or undertake energy

efficiency projects. (See Rebate)

Free Drivers

A free driver is a non-participant who adopted a particular efficiency measure or practice as a

result of a utility program. (From April 2006 EM&V Protocols)

Free riders (Free Ridership)

Program participants who would have installed the program measure or equipment in the absence of

the program.

Fuel Substitution

Programs which are intended to substitute energy using equipment of one energy source with a

competing energy source (e.g. switch from gas furnaces to electric resistance heating).

Funding Cycle

Period of time for which funding of energy efficiency programs have been approved by the CPUC.

Gas Savings

Reduced natural gas usage (or savings) produced by either energy efficiency investments which

maintain the same level of end use service or conservation actions which can reduce energy use by

reducing the quantity or quality of the baseline services provided.

Gross Savings

Gross savings count the energy savings from installed energy efficiency measures

Irrespective of whether or not those savings are from free riders, i.e., those customers who would

have installed the measure(s) even without the financial incentives offered under the program. Gross

savings are adjusted by a net-to-gross ratio to produce net savings, that is, to remove the savings

associated with free riders.

Gross Realization Rate

Gross Realization Rate (GRR) is the ratio of achieved energy savings to predicted energy savings; as a

multiplier on Unit Energy Savings, the GRR takes into account the likelihood that not all CPUC-

approved projects undertaken by IOUs will come to fruition.

Hard to Reach, Residential

Those customers who do not have easy access to program information or generally do not participate

in energy efficiency programs due to a language, income, housing type, geographic, or home ownership

(split incentives) barrier. These barriers are defined as:

Language – Primary language spoken is other than English, and/or

Income – Those customers who fall into the moderate income level (income levels less than 400

percent of the federal poverty guidelines and/or

Housing Type – Multi-family and Mobile Home Tenants, and/or Geographic – Businesses in

areas other than the San Francisco Bay Area, San

Diego area, Greater Los Angeles Area (Los Angeles, Orange, San Bernardino, Riverside and

Ventura counties)or Sacramento, and/or

Home Ownership – Renters

Incremental Measure Cost

The additional cost of installing a more efficient measure calculated from the price differential

between energy-efficient equipment and services and standard or baseline state. These costs include

any direct or indirect incremental cost that is attributable to the energy efficiency activity. This may

include design assistance, surveys, materials and labor, commissioning costs, etc.

Independent Evaluator (IE)

A consultant selected by the IOUs to serve as an independent advisor to the IOUs and the PRG

members involved in overseeing the third-party solicitation process as described in D.18-01-

004, p. 2, 9, 33, and 36-38.

Information & Education

Information and education programs can provide a wide range of activities designed to inform or

educate a customer or customer group. Generally these range from in-depth, one-on-one, on-site or

centrally located classroom style instruction in topics related to energy efficiency, to programs that

target information to specific types of customers, to general information provided to a wide range of

customers, to short inexpensive public service announcements on FCC approved communication

frequencies. Programs intended to provide customers with information regarding generic (not

customer- specific) conservation and energy efficiency opportunities. For these programs, the

information may be unsolicited by the customer.

Innovation Incubator

A low-cost, stand-alone program designed to grow innovative energy saving programs and processes

for the larger portfolio over the long term. The incubator funds new program ideas that meet

reasonable scientific scrutiny for potentially cost-effective energy savings and peak reduction.

Installation Rate

Installation Rate is the ratio of the number of verified installations of a measure divided by the

number of claimed installations rebated by the utility during a claim period. Typically Installation

Rates used on an ex ante basis will be based upon previous ex post evaluations.

Institutional Barriers

A type of market barrier: In this case, the internal organizational hurdles that inhibit the evaluation

and or choice to take energy efficiency actions.

Least Cost/Best Fit

The procurement of cost-effective supply and demand-side resources that, regardless of ownership,

meet capacity and energy deliverability requirements. Energy efficiency resources are constructed

from the bottoms up approach that aggregates the demand and energy savings from various energy-

saving measures and activities into applicable end-use categories such as space cooling, space heating,

lighting, and refrigeration, in order to provide near- and long-term peaking, intermediate, and

baseload requirements.

Levelized Cost

An estimate of the annualized cost of installing an energy efficiency measures divided by the annual

energy savings. Typically calculated by multiplying the incremental cost of the measure by capital

recovery factor (function of discount rate and expected useful life of the measure) and then dividing

by annual energy savings.

Load Management

Programs which reduce or shift electric peak demand away from periods of high cost electricity to

non-peak or lower cost time periods, with a neutral effect on or negligible increase in electric use.

Lost Opportunities

Energy efficiency measures that offer long-lived, cost-effective savings that are fleeting in nature. A

lost opportunity occurs when a customer does not install an energy efficiency measure that is cost-

effective at the time, but whose installation is unlikely to be cost-effective if the customer attempts to

install the same measure later.

Market Effect

A market effect is a change in the structure or functioning of a market or the behavior of participants

in a market that result from one or more program efforts. Typically these efforts are designed to

increase in the adoption of energy-efficient products, services or practices and are causally related to

market interventions. Market effects include reductions in energy consumption and/or demand in a

utility’s service area caused by the presence of the DSM program, beyond program related gross or

net savings of participants. These effects could result from: (a) additional energy efficiency actions

that program participants take outside the program as a result of having participated;

(b) changes in the array of energy-using equipment that manufacturers, dealers and contractors offer

all customers as a result of program availability; and (c) changes in the energy use of non-participants

as a result of utility programs, whether direct (e.g., utility program advertising) or indirect (e.g.,

stocking practices such as (b) above or changes in consumer buying habits)." Participant spillover is

described by (a), and non- participant spillover, by (b) and (c). Some parties refer to non-participant

spillover as “free-drivers.” (From EM&V Protocols, April 2006)

Market Transformation

Decision (D.)09-09-047, defines market transformation as “long-lasting, sustainable changes in the

structure or functioning of a market achieved by reducing barriers to the adoption of energy

efficiency measures to the point where continuation of the same publicly-funded intervention is no

longer appropriate in that specific market. Market transformation includes promoting one set of

efficient technologies until they are adopted into codes and standards (or otherwise adopted by the

market), while also moving forward to bring the next generation of even more efficient technologies

to the market.

”

Marketing, Education and Outreach (ME&O)

Communications activities designed to identify, reach and motivate potential customers to take

actions to either learn more about or invest in energy efficiency opportunities.

Measures

1) Specific customer actions which reduce or otherwise modify energy end use patterns.

2) A product whose installation and operation at a customer’s premises results in a reduction in

the customer’s on-site energy use, compared to what would have happened otherwise.

Net savings

The savings realized when free ridership is accounted for. The savings is calculated by multiplying the

gross savings by the net to gross ratio.

Net to Gross Ratio

D.09-09-047 at p.354, OP 10

A ratio or percentage of net program savings divided by gross or total impacts. Net to gross ratios

are used to estimate and describe the free-ridership that may be occurring within energy efficiency

programs.

Non-price Factors

Those factors included in cost effectiveness tests, other than commodity prices and transportation

and distribution costs, e.g., environmental factors.

Non-Resource Program

Energy efficiency programs that do not directly procure energy resources that can be counted, such

as marketing, outreach and education, workforce education and training, and emerging technologies.

Participant Test

The Participant Test is the measure of the quantifiable benefits and costs to the customer due to

participation in a program. Since many customers do not base their decision to participate in a

program entirely on quantifiable variables, this test cannot be a complete measure of the benefits and

costs of a program to a customer. (See SPM link under Attachment A.)

Partnership

Coordinated efforts of a utility and a local government or other entity to use the strengths of both

parties to achieve energy savings goals.

Peak Demand, Reported (per OP 1 of D.06 -06-063 as modified by D.12-05-

015)

The peak megawatt load reduction contained in the most recently adopted DEER used to estimate

and verify peak demand savings values. The DEER method utilizes an estimated average grid level

impact for a measure between 2 PM and 5 PM during a “heat wave” defined by a three consecutive

weekdays for weather conditions that are expected to produce a regional grid peak event. DEER

utilizes a 3-day “heat wave” that occurs on consecutive days in June through September such that the

three consecutive days do not include weekends or holidays, and where the heat wave is ranked by

giving equal weight to the peak temperature during the 72-hour period, the average temperature

during the 72-hour period and the average temperature from noon – 6 PM over the three days.

Peak Demand-General (kW)

1) The maximum level of metered demand during a specified period, such as a billing month, or

during a specified peak demand period.

2) Extremely high energy use, usually with reference to a particular time period.

Peak Savings- Coincident (kW)

The estimated peak (e.g. highest) demand savings (MW or kW) from a program for a specific time,

date, and location coincident with the forecasted system peak for a given area and a given set of

weather conditions. This estimate must also include consideration of the likelihood that the

equipment is actually on at the time of coincident peak. Usage of this definition: Resource

planning- for making adjustments to forecasts of peak usage for understanding reserve margins and

reliability purposes.

Peak Savings- Daily Average (kW)

The average peak demand savings (kWh impacts/ # of hours in the peak rate period) for a given

utility during their peak season. Example for SCE-Peak period is for summer weekdays from 12-6

PM. So - daily average savings would be the number of kWh saved/ # of kWhs saved for all

weekday peak periods (= kWh/5 days/week * 12 weeks/ summer* 6 hours/day = kW average.

Usage: Cost effectiveness analysis, primarily for valuing energy savings that occur during the peak

period using “peak” average avoided costs.

Peak Savings –Non coincident (kW)

Estimated highest level of peak savings (kW or MW) for a given program during the peak time

period for a given utility on the hottest day of a “normal” weather year. Thus if a group of measures

saved 1MW at 2PM, 1.7 MW at 3PM, 1.6 MW at 4PM, 1.0 MW at 5 PM and 1.2 MW at 6 PM, the

peak non coincident savings would be 1.7 MW. This savings estimate does not take into account how

many of the affected devices or equipment will be operating during the peak time period. Usage:

Cost effectiveness analysis and procurement.

Peer Review Group (PRG)

A subset of the Program Advisory Group consisting of non-financially interested members who will

review utility submittals to the CPUC, assess overall portfolio plans, plans for bidding out pieces of

the portfolio, and the bid evaluation criteria for selecting third-party programs.

Performance Uncertainties

A market barrier: refers to new technologies or systems whose efficiency or system

performance levels are uncertain due to lack of experience.

Portfolio

All IOU and non-IOU energy efficiency programs funded by ratepayers that are implemented during

a program year or cycle. May also refer to a group of programs sponsored, managed, and contracted

for by a particular IOU.

Portfolio Reporting

Regularly scheduled reporting by the portfolio administrators directly to the CPUC. Metrics reported

are: portfolio budgets and expenditures, measures installed, services rendered, and other program

activity deemed relevant to Energy Division’s responsibility to support the CPUC’s responsibilities of

quality assurance, policy oversight, and EM&V.

Pre-commercialization

A phase in the life of a product before it is readily available on the market.

Program

A collection of defined activities and measures that

• are carried out by the administrator and/or their subcontractors and

implementers,

• target a specific market segment, customer class, a defined end use, or a defined set of

market actors (e.g. designers, architects, homeowners),

• are designed to achieve specific efficiency related changes in behavior,

investment practices or maintenance practice in the energy market,

• and are guided by a specific budget and implementation plan.

Program Activities

Any action taken by the program administrator or program implementer in the course of

implementing the program.

Program Administrator

An entity tasked with the functions of portfolio management of energy efficiency programs and

program choice.

Program Administrator Cost (PAC) Test

Under portfolio evaluation of cost effectiveness, the PAC test contains the program benefits of the

TRC test, but costs are defined differently to include the costs incurred by the program administrator

but not the costs incurred by the participating customer. (See the SPM link under Attachment A.)

Program Advisory Group (PAG)

Advisory groups for each utility service area composed of energy efficiency experts representing

customer groups, academic organizations, environmental organizations, agency staff and trade

allies in the energy market.

Program Cycle

The period of time over which a program is funded and implemented.

Program Implementation Plan

A detailed description of a program that includes program theory, planned program processes,

expected program activities, program budget, projected energy savings and demand reduction and

other program plan details as required by the CPUC, assigned ALJ, or Energy Division.

Program Implementers

An entity or person that puts a program or part of a program into practice based on contacts or

agreements with the portfolio manager.

Program Strategy

The set of activities deployed by the program in order to achieve the program’s objectives.

Program Year(s)

The calendar year(s) during which the program operates.

Ratepayer

Those customers who pay for gas or electric service under regulated rates and conditions of

service.

Rebate

A financial incentive paid to the customer in order to obtain a specific act, typically the installation of

energy efficiency equipment.

Remaining Useful Life (RUL)

An estimate of the median number of years that an measure being replaced under the program

would remain in place and operable had the program intervention not caused the replacement.

Report Month

The month for which a particular monthly report is providing data and information. For example,

the report month for a report covering the month of July 2006, but prepared and delivered later

than July 2006, would be July 2006.

Resource Programs

Energy Efficiency programs that generate energy savings that are quantified and tracked by program

administrators.

Resource Value

An estimate of the net value of reliable energy (e.g., kWh, therms) and capacity (e.g., kW, Mcfd)

reductions resulting from an energy efficiency program. This includes the net present value of all of

the costs associated with a program and all of the estimated benefits (both energy and capacity). The

calculation of resource value and associated benefits should be consistent with the avoided costs

adopted in the most recent CPUC proceeding or otherwise provided for by the CPUC.

Ratepayer Impact Measure (RIM) Test

The Ratepayer Impact Measure (RIM) test measures what happens to customer bills or rates due to

changes in utility revenues and operating costs caused by the program. Rates will go down if the

change in revenues from the program is greater than the change in utility costs. Conversely, rates or

bills will go up if revenues collected after program implementation are less than the total costs

incurred by the utility in implementing the program. This test indicates the direction and magnitude

of the expected change in customer bills or rate levels.

Savings Decay

The reduction of cumulative savings due to previous measure installations passing their Remaining

Useful Life or Effective Useful Life. Per D.09-09-047 and until EM&V results inform better metrics,

IOUs may apply a conservative deemed assumption that 50 percent of savings persist following the

expiration of a given measure’s life.

Service Area

The geographical area served by a utility.

Short Term/Long Term

Planning terms referring to the timing or expected timing of program activities, program impacts,

or program funding. Short term indicates program activities, program impacts, or program

funding that occurs during the current program cycle. Long term indicates program activities,

program impacts, or program funding that occurs beyond the current program cycle.

Source-BTU Consumption

Conversion of retail energy forms (kWh, therms) into the BTU required to generate and deliver the

energy to the site. This conversion is used to compare the relative impacts of switching between fuel

sources at the source or BTU level for the fuel substitution test required for fuel-substitution

programs.

Standard Practice Manual (SPM)

The California Standard Practice Manual: Economic Analysis of Demand-side Programs and Projects

is jointly issued by the California Public Utilities Commission and the California Energy Commission.

The SPM provides the definitions for the standard cost effectiveness tests and their components

used for energy efficiency programs. SPM tests are further clarified in CPUC Decisions as cited in the

Cost-Effectiveness Rules in this Policy Manual.

D.09-09-047 at p.334

Statewide

Energy efficiency programs or activities that are essentially similar in design and available in

all CPUC regulated utility service areas in California.

Third Party/Non-IOU

Non-regulated implementers of ratepayer funded energy efficiency activities.

Total Resource Cost Test (TRC)

The TRC test measures the net resource benefits from the perspective of all ratepayers by

combining the net benefits of the program to participants and non-participants. The benefits are the

avoided costs of the supply-side resources avoided or deferred. The TRC costs encompass the cost

of the measures/equipment installed and the costs incurred by the program administrator. (See SPM

link under Attachment A.)

Two-Stage Solicitation Process

A solicitation process that includes two stages; an initial Request for Abstract and a follow-up

Request for Proposal phase as described in D.18-01-004, p. 7

Unit Energy Consumption

Unit Energy Consumption (UEC) is the expected annual energy consumption of a technology, group

of technologies, or process.

Unit Energy Savings

Unit Energy Savings (UES) is the estimated difference in annual energy consumption between a

measure, group of technologies or processes and baseline, expressed as kWh for electric

technologies and therms for gas technologies

Upstream Incentives

Incentives provided to manufacturers or retailers of high efficiency products in order to encourage

their production and sales, in contrast to the more common downstream incentives, which are

provided directly to customers as rebates.

Workpapers

Documentation prepared by the program administrators or program implementers that documents

the data, methodologies, and rationale used to develop ex-ante estimates that are not in already fully

contained in the Database for Energy Efficiency Resources (DEER) (D.10-04-029, footnote page 20).

Zero Net Energy

Zero Net Energy is defined as the implementation of a combination of building energy efficiency

design features and on-site clean distributed generation such that the amount of energy provided by

on-site renewable energy sources is equal to the energy consumed by the building annually, at the

level of a single “project” seeking development entitlements and building code permits. Definition of

zero net energy at this scale enables a wider range of technologies to be considered and deployed,

including district heating and cooling systems and/or small-scale renewable energy projects that serve

more than one home or business. (D.07-10-032, Footnote 42.)

(END OF APPENDIX B)

APPENDIX C: Cost Categories and Related Cap and Targets

IOU shall reflect all costs associated with the delivery of their energy-efficiency programs in

their filings in the energy-efficiency portfolio applications and shall note, where applicable,

when the costs are recovered in other proceedings.

The CPUC has established various (hard) caps and (soft) targets as summarized in the table

below:

Budget Categories

rge

Utility program administrative costs

Third-party / Gov’t partnership administrative

costs

Marketing & outreach costs

Direct implementation non-incentive (DINI) costs

Evaluation, measurement & verification (EM&V)

costs

The IOUs will forecast and report total Administrative, Marketing, Direct Implementation costs

by program and subprogram in the cost categories and sub-categories. A detailed

characterization of the specific types of costs that are allocated to each of these categories is

provided below.

D.09-09-047, OP 13a and p. 62

D.09-09-047 at p. 63

D.09-09-047, OP 13b and at p. 73

D.09-09-047 OP 13c and at p. 74; D.12-11-015 at p. 101

D.12-11-015 at p. 59; D.09-09-047, COL 6

Utility Administrative Costs

Administrative costs for utility energy efficiency programs (excluding third party and/or local

government partnership budgets) are limited to 10 percent of total energy efficiency budgets.

Administrative costs shall not be shifted into any other costs category.

Administrative costs are necessary to support energy efficiency programs but costs must be

reasonable and limited to overhead, labor and other costs discusses below needed to implement

quality programs with ratepayer funds.

All IOUs shall reflect all labor-related costs associated with the delivery of energy-efficiency

programs, as defined at page 49 of D.09-09-047, in their energy-efficiency portfolio filings, and

shall clearly delineate where any expenses or costs have been or will be recovered in proceedings

other than energy efficiency applications.

Administrative costs include the following:

Overhead (G&A Labor/Materials): administrative labor, accounting support, IT services and

support, reporting databases, data request responses, CPUC financial audits, regulatory filings

support and other ad-hoc support required across all programs.

Labor (Managerial & Clerical): This category includes utility labor costs related to either

management or clerical positions directly related to program administration. SDG&E and

SoCalGas also add payroll taxes.

Human Resource Support and Development: This includes payroll taxes, payroll support, as

well as pensions.

D.12-11-015 OP 39

D.09-09-047, OP 13a and at p. 50; with additional detail from Attachment A to PG&E AL. 3065-G/3562-E

D.09-09-047 at 50 states that these Administrative Cost categories do not include EM&V or Marketing Outreach

D.09-09-047 at p. 56 says “Attachment 5-A of the December 2008 ruling [the Allowable

Costs Attachment] lists payroll tax and pensions as included in the Human resources Support Category.”

Travel and Conference fees: This includes labor, travel and fees for conferences.

This

category includes utility sponsorships for energy efficiency program-specific events or activities

such as including membership-based, issue-specific trade organizations that include as a

component of membership benefits entry into conferences. However, utility sponsorship fees

for major national energy efficiency conferences that provide company recognition or status are

prohibited as energy efficiency allowable costs. Such costs shall not be funded with energy

efficiency program funding.

CPUC Division of Water and Audits allows travel costs, such as meeting with customers, can to

be charged to the applicable program area (i.e., to DINI or to Marketing and Outreach).

Travel costs by IOU staff should be limited, but this will be achieved via the cost targets for

marketing. Travel costs to EE conferences and other activities shall be charged to administrative

costs with the following exceptions:

Travel costs for DINI activities and marketing can be charged to those respective cost