ARKANSM PUBLIC SERVTCE COMMXSSION 

FLED 

IN THE MATTER OF THE CONTINUATION, ) 

EXPANSION, AND ENHANCEMENT OF 1 DOCKET NO. 13-002-U 

PUBLIC UTILITY ENERGY EFFICIENCY 1 ORDERNO. 7 

PROGRAMS IN ARKANSAS 1 

ORDER 

On January 4,2013, by Order No. 1 in this docket (“Order”), the Arkansas Public 

Service Commission (Tommission”) established a process and a timeline to resolve 

issues related to the development and implementation of the second three-year cycle of 

comprehensive utility energy efficiency rEE”) programs in Arkansas, The following 

investor-owned public utilities (“IOUs’’ or “utilities”) stre parties to the proceeding: 

Entergy Arkansas, Inc. rEAI”), Southwestern Elecbic Power Company (“SWEPCO”), 

Oklahoma Gas and Electric Company rOG&E”), The Empire Disbict Electric Company 

(“Empire”), CenterPoint Energy Arkansas Gas (“CenterPoint”), SourceGas Arkansas, 

Inc. (“SourceGas”) and Arkansas Oklahoma Gas Corporation rAOG”). The Arkansas 

Attorney General (the “AG”) and the General Staff of the Commission (“Staff”) are also 

parties. The following intervenors are parties: Arkansas Advanced Energy Association, 

Inc, (‘(MEA’’), Arkansas Community Action Agencies Association (“ACAAA”), Arkansas 

Electric Energlr Consumers and Arkansas Gas Consumers rAEEC/AGC”), National 

Audubon Society YAudubon”), Sierra Club, and Wal-Mart Stores Arkansas, LLC (“WalMart”). 

On January 17,2013, the Parties Working ColIaboratively (the “PWC“) submitted 

a Joint Motion to delay the procedural schedule and to delay implementation of the 
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second three-year program cycle by one year, in order to allow time for the Commission 

and the PWC to resolve the issues that were raised in Order No. 1. The PWC includes all 

parties except Wd-Mart, who did not object to the Motion. The Commission granted 

this motion by Order No. 2, on January 30, 2013, and accordingly, parties filed initial 

comments on May 15,2013, and Reply Comments on June 3,2013. 

The delay in the procedural schedule was granted in part because the first 

evaluation of a hll year of EE program data, conducted by the Independent Evaluation 

Monitor (%My’), Dr. Katherine Johnson, would not be filed until June 1, 2013. Dr, 

Johnson submitted her testimony and Annual Summaiy Report on EuaZuation, 

Measurement and Verifications Findings rEMW Repork’’) for Program Year (TY”) 

2012 on June 3,2013. 

On April 19,2013, the PWC submitted a Joint Motion to Request Potential Study 

(“Joint Motion,” or “JM”). On April 30, 2013, by Order No. 4, the Commission 

broadened the scope of testimony in this docket to include consideration of lessons 

learned and proposed program improvements that can reasonably be implemented 

during 2013 and beyond to address under-performance for particular programs during 

2012 and to more effectively target hard-to-reach customer segments. 

Issue 1: EE Program Procedural Issues 

A subset of the PWC-the Joint Commenting Parties ((‘JCP”)1-comment that the 

significant evolution of the framework surrounding EE programs during the time since 

the Conservation and Energy Efficiency C“C&EE”) Rules were adopted in 2007 merits 

changes to the current schedule for reviewing EE program performance and tariff 

1 The JCP are comprised of the IOUs, ACAAA, MEA, and Staff. While EAT is included in the JCP, it 

comments separately regarding avoided costs, non-energy benefits, and the incorporation of avoided costs 

into the utility performance incentive. 
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20 14 Annual Report & EECR (20 16 Budgct I 20 I4 truc-up) 

Order Approving Transition Filing 

Effective date of 20 15 EECR Rate Adjustment 

Order approving May 201 5 filings 

adjustment. JCP at 3-4. The JCP propose that the date for utilities and other program 

administrators to file EE Program Annual Reports and EECR rider updates be changed 

from April 1 to May I of each year, with any approved EECR rider updates taking effect 

on Januv 1 of the subsequent year. The JCP recommend that the 

Commission approve EECR adjustments by September 1 following the May 1 filing. Id. 

at 6. The JCP state that this schedule will place program year expenditures, program 

budgets, and EECR rates on the same calendar year basis. Id. at 5-6. The JCP 

recommend that this schedule be implemented in 2015, with a one-time exception to the 

schedule in 2014 to enable a transition between schedules. Id. at 6-7. 

Id. at 5. 

The JCP include the following table indicating their recommended timeline for 

schedule changes: 

JCP Pronoscd FilinP Datcs 

May I, 2015 

May 28,201 5 

June 1,2015 

September 1,201 5 

.I , I I I Effective date of 2014 EECR Rate I June 1.2014 I 1 

~- 

2016 Annual Report & EECR (2018 Budgetl2016 tme-up) 

Order approving May 201 7 filings 

Effective date of 201 8 EECR Rate 

~ 

I7Fromm Filing- I June 1.2014 I I 

May 1,2017 

September T,20 17 

Janum 1.2018 

1mlS-2017 Promrn Amroval I I November 27,2014 1 

I 2015 EECR Rate Transition FiIing (2015 Budget I no true- I I April 1,2015 I 
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The JCP indicate that the January 1 implementation date for EECR adjustments 

to go into effect will provide concurrent recovery of Commission-approved budgeted 

program costs, thereby eliminating the regulatory lag that has existed in the current 

mechanism. Id. at 5. By way of example, the JCP recommend that the May 1, 2015 

EECR filing would include the PY 2014 true-up and the projected costs €or the 2016 

program year. The 2016 EECR filing will include the PY 2015 true-up and the projected 

costs for the 2017 program year. Id. The JCP state that the proposed schedule 

represents a balanced approach, in that recovery of incentives for the prior program 

year is delayed from the current June I until January I, or a full year following the 

program year upon which the incentive was earned. Id. 

Regarding the transitional year, the JCP recommend that, during 2015, the trueup of the 2014 program costs would be addressed in the May 1 filing. This one-time 

EECR update would be effective through December 2015 and would be superseded by 

the 2016 Program Year EECR update, which would become effective January I, 2016. In 

subsequent years the recommended schedule would continue without the need for an 

additional adjustment. Id. 

The JCP oppose consolidation of EE program approvals within a single docket. 

Id. at 8. The JCP state that such consolidation will result in a massive, confusing record 

that complicates the required finding that each utility's EE programs are beneficid to 

the utility and ratepayers alike. Id. at 8-9. The JCP provide the example that it would 

be administratively inefficient and perhaps violate the requirement that intervenors 

must have a direct interest at stake to involve a party interested only in a single utiliQ's 

case in a docket addressing all utility's EE programs, Id. at 9-20. Further, the JCP state 
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that, with multiple utilities and parties, it may be unclear whether a party is addressing 

all of the utilities’ EE program portfolios, the portfolio of a single utility, or a single 

program. Id. at: 10- The JCP recommend instead that the Commission should retain 

separate utiliiy EE tariff dockets for approval of each utilitfs EE program and EECR 

adjustment, and pursue administrative efficiencies by alIowing pre-filed testimony to be 

introduced into the hearing record by stipulation. Id. at 8. 

Furkher supporting the JCP’s opposition to a consolidated EE docket, EAI states 

that, if anything, it may be more practical to have utilities begin to implement their own 

cycles for portfolio submission, with staggered filings, as in the integrated resource 

planning (“XW”) process. MI at 8. EAI notes that the PWC’s own efforts to gain 

administrative efficiencies by consolidating utiliiy EE reporting and making it more 

consistent was tabled due to the need to respond to Order No. I. Id. EAI recommends 

that the PWC be directed to focus on this further integration of EE reporting. Id. AIso, 

EAI generally comments that it is better for the Commission to propose policy issues for 

resolution by the PWC, rather than proposing solutions for litigated comment, as in 

Order No. I. Id. at 4-5. 

The AG agrees with the JCP regarding scheduling changes, except that the AG 

views a hard September 1 deadline for Commission EECR approval as unnecessary given 

that complex issues may arise and that the new EECR would not go into effect until 

January 1, and the AG sees no reason to delay the transition year to 2015, rather than 

2014. AG at IO, Other than these two exceptions, the AG states that the scheduling 

changes will significantly improve the annual process, alIorving time for more evaluation 

and review of EE program savings and EECR filings. Id. at 10-11. The AG states that the 
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merits of consolidating EE program review in a single docket are unclear: while a single 

docket might streamline consideration of core programs and cross-cutting issues, 

utility-specific issues will always arise as long as utilities separately administer their 

programs. Id. at 11-12. 

AEEClAGC supports the JCP’s proposed May 1 filing date for Annual Reports 

and EECR rider adjustments, with 60 days provided for review of the filings by parties. 

AEEC/AGC at 2. AEEC/AGC favors a schedule under which the Cornmission would 

approve tariff adjustments within 120 days. Id. AEEC/AGC states that these extensions 

to the current timelines for review are needed in light of the higher level of costs being 

requested for full program implementation, Id. at 2-3. While AEEClAGC opposes 

creation of a single EE docket for review of individud utility programs, it supports 

consideration of policy issues common to all utility EE programs within a single docket 

in order to ensure consistency and reduce administrative and participation costs. Id. at 

3. 

Sierra Club supports a combined EE docket in furtherance of standardized 

statewide programs, but in the alternative would favor handing cross-cutting issues 

within a single docket. Sierra Club at 2. Audubon similarly states that a more unified 

procedural approach would be congruent with collaborative EE program planning, but 

recommends that the Commission consider alternative approaches that may accompTish 

the same objectives, if necessary to address objections to consolidation. Audubon at 1. 

Ruling Rwardim Consolidated Docket and Proposed Alternative Schedule 

The Commission accepts the JCP‘s recommendation that individual utiIity tariff 

dockets be retained for utili3 EE program and tariff adjustment approval, in order to 
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preserve a distinct basis in substantial evidence for each decision. The Commission also 

accepts the recommendation by parties that cross-cutting or common issues should be 

addressed through a separate, single docket or dockets. 

The Commission accepts the JCP’s recommended schedule for transition in 2015 

to a May 1 annual filing date, as indicated in the table above, with a transitional-year 

filing in 2014, with the exception that the Cornmission will strive to approve programs 

and tariff adjustments by September I, but reserves the right in cases of controversy, if 

necessary, to investigate solutions for a longer period of time. The Commission agrees 

with the JCP that the recommended schedule will enhance the opportunity for 

performance review and that it will better align program implementation and cost 

recovery. Also, it is reasonable to schedule the transitional year filing for 2015 because 

the new three-year program cycle will be implemented during that year. 

Accordingly, the Commission approves the revised filing deadlines and 

procedural schedules for immediate use in the preparation and approval of the next 

three-year EE planning and program cycle for PY 2015-2017. Also, the Commission 

directs Staff to file a draft of any C&EE rule amendments necessary for the 

implementation of this scheduling change on or before noon of January IO, 2014, in 

Docket No. 06-004-R. 

Issue 2: Proposed Commission Targets and Motion for Potentia! Study 

Xn support of the Joint Motion, the PWC state that Order No. 1 contempIates 

substantial changes to the Commission’s C&EE Rules and the associated EE framework, 

and that the PWC has met several times to discuss the issues associated with those 
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changes.2 JM at 11 1 & 3. In that context, the PWC has determined a need for a 

Potential Study on the Performance Targets for 2015-2017. Id. at fl 3. The PWC 

recommend that the Commission consider Arkansas-specific market conditions through 

a Potential Study before establishing the proposed EE gods and targets for years 2015- 

2017. Id. at: 7 4. The PWC state that, absent a Potential Study, the EE goals or targets 

proposed in Order No. 1 will not reflect market conditions and other factors specific to 

Arkansas, such as changes in residential and commercial energy codes, availability of 

savings, avoided costs, and the amount of program expenditure needed to achieve 

energy savings. Id. at 14. The PWC seek approval to expeditiously issue a Request for 

Proposal (,,€WP’’) for the performance of a Potential Study that would be jointly funded 

by the IOUs, with costs recovered through each utility‘s Energy Efficiency Cost Recovery 

(“EECR”) rider. Id. at 1 5. The PWC state that time is of the essence, since it will take 

six to nine months after issuance of the RFP to complete the study, and then pdes 

would need to submit comments to the Commission on how to interpret the results to 

set EE goals. Id, The PWC indicate that they “anticipate working collaboratively to 

address the scope and other issues in connection with the proposed Potential Study.” 

Id. at 73. 

MI comments in support of the Potential Study that having the results of the 

first full year of existing program performance-which were not available until after the 

targets proposed in Order No. 14s critical to evaluating the reasonableness of the 

targets. EAI at 6. EAI states that the Commission’s proposed targets appear to be based 

upon results in other states, and thus to assume that a significant proportion of savings 

2 The Commission notes that, at this time, it has not proposed amendments to the Conservation and 

Energy Efficiency RuIes (“CME Rules”). 
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will be achieved through lighting programs. Id. EN notes that other issues addressed 

in Order No. I, such as the AG’s recommendations to quantify avoided capacity using a 

Real Economic Carrying Charge (VECC”) and to adjust EE program savings downward 

for leakage of installed measures to other jurisdictions, would significantly influence the 

reasonableness of the proposed framework.3 Id. 

AEEC/AGC supports the Potential Study to ensure that gods and funding levels 

are set at realistic levels which reflect recent reductions in market energy prices and 

relatively low economic growth, AEEC/AGC Reply at 11. AEBC/AGC also recommends 

that any expansion of EE programs be deferred, Id. AEEClACG asserts that the cost of 

most EE programs far exceeds the current market price fur energy and capacity, 

providing the example that the average cost of EAI’s EE program expenditures per MWh 

saved over the last four years was $334/MWh--more than 13 times the average SPP and 

MIS0 market prices of approximately $25/MWh last year. AEEC/AGC Reply at 2. 

AEEClAGC states that EAI, SWEPCO and OG&E’s more recent IRPs indicate a surplus 

of low cost baseload energy, rendering EE programs not cost effective currently, nor 

until market prices increase significantly. Id. at 2-3, AEEClAGC presents a table that 

sums EASs EE annual program savings in each year from 2009 through 2012: dividing 

those savings by MI’S total sales, AEEC/ACG concludes that M’s programs have saved 

only 0.28% of retail 1Wh sales. AEEC/AGC argues that it makes no sense to approve 

3 Leakage is the cross-territory energy savings that occur when EE program-incentivijsed efficient products 

are installed outside of the funding utility‘s service territory. Subsequent to this comment by W, the 

Commission, by Orders No. 63 and 85 respectively, of Dockets No. 07-082-TF and 07-085-TF, 

established a policy on Ieakage. On August 30,2013, the parties activeIy participating in the collaborative 

process in Docket No. io-loo-R (?he Moving Parties”, comprising the utilities, Staff, the AG, AW, and 

Audubon) submitted a Joint Motion to Approve Technical Reference Manual 3.0 and Waiver of Bearing, 

including a new Protocol K addressing leakage and incorporating the Commission’s directives in Order 

Nos. 63 and 85 above. 
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W’s 2013 EE program budget exceeding $70 million when alternative supply sources 

are available at much lower cost. Id. at 6. 

Audubon supports the Joint Motion and views the Potential Studfs results as 

indicating an approximate upper limit on reasonably achievable savings, Audubon at 2. 

Audubon cautions that potential studies are not program implementation plans and 

cannot account for various factors such as program portfolio design, differences among 

program adminisbator portfolios and resources, and the time required to “ramp up” 

programs. Id. at 2-3. Audubon states that savings goals must be scaled to an achievable 

level given available time and resources. Id. at 3. 

Sierra Club states that it supports the targets proposed by the Commission. 

Sierra Club at 2. Sierra Club, however, also supports a Potential. Study on the basis that 

it will increase confidence that the proposed targets are achievable, it may show that 

higher targets are achievable, and it will enable a more informed conversation regarding 

the targets, including whether perceived barriers are technical, economic, practical, or a 

matter of program design. Id. at 2. 

Dr. Johnson’s EM&V Report states that, despite mixed results, most programs 

achieved their savings goals and it is clear that the EE programs are gaining traction in 

the market, IEM Report at 72. She states that the progress made in the past 12 months 

has been remarkable. Id. She urges the utilities to “Stay the Course-Collaborativelywith Additional Joint ImpTementation.” Id, 

Her <‘first, critical recommendation” going forward is for the performance of a 

market potential study. Dr. Johnson adds that she made this same recommendation a 
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year ago in her PY 2011 Report. PY 2012 EM&V Report ai xii and 70.4 She also states 

that [all1 three evaluation teams engaged by the IOUs (ADM Associates, Inc. rADM”), 

Cadmus, and EnerNOC Utility Solutions Consulting rEnerNOC”)} identified the 

benefits that such a study would provide, including gathering information about 

customer preferences, participation likelihood, and savings potential across the entire 

state, as well as additional technologies to consider in future program designs. She 

indicates that the market potential study should be a multi-utility, cross-fuel effort to 

ensure the most efficient use of ratepayer funds, requiring coordination between dl 

members of the PWC.” Id. at 70. 

The Commission takes administrative notice that several of the individual utility 

evaluation reports referenced by Dr. Johnson mention particular benefits of a market 

potential study. The evaluator for Centerpoint, AOG, and SourceGas EE programs 

(ADM Associates, IRC., or “ADM”) found that the current programs of these utilities 

have been designed and implemented without the benefit of guidance from a market 

potentid study, which should be done to make sure that program resources are 

allocated in an efficient manner. Centerpoint Annual Report, Appendix A at 2-8 

through 2-9; AOG AnnuaI Report, at 33 and Appendix A at: 4-31, 5-21 and 7-24; 

SourceGas Annual Report, Appendix A at 2-10. As part of its program evaluation of 

these programs, ADM took the opportunity to conduct surveys-which fell short of a full 

market potential study-of several hundred customers who did not participate in the 

4 In the Report for PY SOIT, the IEM recommended that utilities consider “performing market 

assessments, such as a market potentia1 study based on primary data from Arkansas,” in order to “ensure 

that planning projects are based on actual market conditions.n The IEM recornmended that the study 

“should be coordinatcd statewide and linked to other EM&V tasks to ensure cost-effectiveness.” Annual 

Summa y Report on Eualuotion, Measurement & VeriJcation Findings, Johnson Consulting Group, 

June I, 2012. 
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Centerpoint, AOG, and SourceGas EE programs. For example, ADM asked residential 

customers who did not participate in Centerpoint EE programs what percentage of them 

have tankless water heaters versus storage-tank water heaters, and the age of those 

units; similarly, ADM asked commercial customers to identify their highest gas loads 

and the age of equipment serving those loads. Centerpoint Annual Report, Appendix A 

at 2-8 through 2-9. 

Cadmus indicated that SWEPCO‘s initial estimates of market demand for some 

programs (Load Management Standard Offering Program, Appliance, and Home 

Performance with Energy Star) were Tow, and others (CFL, Small Business Direct 

Install) were high, SWEPCO Annual Report, Appendix A (Energy-E’ciency PorgoZio 

Evaluation Report 2012 Program Year) at 5 and 15-16. Cadmus recommends that 

SWPCO conduct market research or a potentials study to better understand customer 

preferences and participation and savings potentid. Id. at 16. 

Similarly, Cadmus recommended that Empire conduct market research to better 

understand residential customers’ housing characteristics and purchasing habits to 

inform residential prescriptive program design. Empire Annual Report, Attachment B 

(Empire, Eualuation Report) at: 7. As an example, Cadmus recommended that Empire 

seek to understand the types, ages, and quantities of electric WAC equipment found in 

customers’ homes, the types of new equipment they are likely to purchase, and where 

they purchase such equipment. Id. 

EnerNOC recommended that OG&E should research the target market for its 

commercial and industrial (“CH”) programs to find the current market share of high 

efficiency equipment; to understand the common characteristics of customers already 
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investing in energy efficiency and what characteristics make up the next tier of 

customers the program is hoping to reach; and to proactively identify specific 

equipment to promote. OG&E Annual Report, Appendix ID (Evaluation of OG&E 

Arkansas PY2012 Energy Eficiency Programs) at v. 

Dr. Johnson further testifies that the various evaluators this year provided more 

than 400 recommendations on ways in which to improve the EE programs. Johnson 

Direct at 5. Dr, Johnson recommends that the Commission continue to encourage jointcollaboration and implementation of cross-fuel programs. Id. at 6. She reports that 

such joint program implementation can significantly reduce the cost per achieved kWh 

or therm, by sharing the adminisbative cost of the programs, and even more so when 

measure costs are allocated across fuel types, IEM Report: at 72. 

She hrther recommends that utilities continue to improve database tracking; 

that evaluators undertake strategic primary evaluation research in 2013 to ensure that 

the TRM is reliable and based on Arkansas-specific data; that utilities and evaluators 

should track and report on the implementation of IEM recornmendations for program 

improvement; and that evaluators should take several steps to improve the timing and 

conduct of EM&V activities. IEM Report at 70-73. 

Besides the evaluator comments specifically addressing the Market Potential 

study and the IEM’s general program improvement recommendations, the utilities’ 

Annual Reports and accompanying (“Appendix A”) evaluator reports provide a snapshot 

of progress, challenges, and recommendations for improvement after the first full year 

of comprehensive program implementation. For instance, EAI’s EE Annual Report 

indicates that during this first fill year of comprehensive program implementation, 
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energy savings more than doubled and that EAI’s programs are building a growing 

network of vendors and contractors to support program implementation. Entergy 

Annual Report at 5-6.5 Overall, EAI achieved 111% of the Commission’s energy savings 

goals, while spending roughly $29 million (74%) of its $39 million planned budget. Id, 

at 5; Workbook at AI, EAI served about 510,000 participants, rather than the 934,568 

planned (in this case, rrparticipants” includes each individual light bulb or other 

measure); for programs other than upstream lighting and Residential Benchmarking 

(which each reach a mass market of over IOO,OOO customers), EAI served about 15,000 

of the planned 26,000 customers. Workbook at A2. 

Six of EM’S fourteen programs became available to customers later in the year 

than planned. Id. at 10-11. For instance, the EAI Residential Direct Load Control 

program (which installs controls on air conditioners allowing EM to reduce compressor 

cycling during peak events) installed almost 8,000 air conditioner control devices 

during 2012. Id., Appendix A at 247, Figure 39. However, over 5,000 of these devices 

were installed after August, and only two events were called in 2012. Id. While the 

program met only 40% of its demand reduction goal in 2012, EMS evaluators indicate 

that it is well-positioned to meet or exceed its 2013 goals. Id. at 240. Furthermore, 

based on the first year level of achievement, the program provided 32% of the Totd 

Resource Cost (“TRC”] test net benefits for the EAI portfolio, and was the largest factor 

contributing to a total EAI portfolio RIM test score of 0.98. EAI Annual Repod 

Workbook at B2. 

’ This performance has garnered an Award of JkelIence at Platt’s 20x2 Global Energy Awards. Id. at 6. 
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EAI notes that its 2012 IRP includes a Toad forecast showing that, by 2023, EAI 

could achieve 700 MW of cumulative peak demand reduction and 1,788,584 cumulative 

MWh of energy savings for a total cost of $750 million, which compares favorably with 

other potential resource options under most scenarios modelled. Id. at 134. EAI states 

that, while the IRP DSM assumptions remain valid for planning purposes, at the current 

level of EE effort, over the long term EAI will surpass them. Id. 

M’s evaluator (Cadmus) interviewed over 150 program participants across 

seven programs and about 80 non-participants. M Annual Report, Appendix A at 5. 

Cadmus states that “in. every case respondents listed lack of funding as their primary 

program barrier.” Id. at 5. Cadmus thus recommends offering low-cost financing to 

customers through partnerships with national lenders or local banks through an on-bill 

repayment mechanism. Id. 

Cadmus notes that seventy-five percent of non-participating customers indicated 

no awareness of any EAI EE programs. Id. at 6. No more than 4% of non-participants 

are aware of any particular program, and 1% of non-parIicipants are aware of most 

individual surveyed programs. Id. However, for program participants, a customer 

satisfaction survey of 400 participants in nine programs found 95% to 100% customer 

satisfaction for all but two suweyed programs, with the remaining two having customer 

satisfaction rates o€ 84% and 86%. Id. at 15. 

SWEPCO achieved 113% of the Commission’s energy savings goals while 

spending $5.3 million (78%) of its $6.8 million planned budget. SWEPCO Annual 

Report at 7. SWEPCO served 94,807 customers rather than the planned 28,556, but 

when CFL sales are removed from the calculation, it served roughly 3,800 of 15,600 
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planned customers. SWEPCO Annual Report Workbook at Az. SWEPCO reports that 

its long, non-contiguous, narrow territory is a significant challenge for implementation 

of each of its programs. SWEPCO Initial at 1-2. SWEPCO added new appliances to its 

upstream CFL/Appliance program, launched a new Home Performance with Energy 

Star program, and added direct-install program components targeted to multi-family 

housing, small businesses, and (late in 2012) dual-he1 commercial and industrial 

customers. SWPCO Annual Report at 6-7. 

SWEPCO’s evaluator (Cadmus) found that, overall, 82% of non-program 

participants are not aware of SWEPCO’s EE programs, kth 1-4% reporting awareness of 

individual programs, SWEPCO Annual Report, Appendh A at: 9. Cadmus notes that 

these results are not unexpected or unusual during early program implementation, and 

that it believes customer awareness will increase over time with strategic marketing 

efforts. Id. Cadmus reports 99% to roo% customer satisfaction with surveyed 

programs. Id. at 18. 

Cadmus found that, while SWEPCO’s programs are designed to provide 

comprehensive offerings, few achieved comprehensive uptake of whole building 

measures; that program goals and budgets could be significantly better aligned; and that 

SWEPCO does not offer residential load control or promote appliance incentive 

programs to its commercial customers, Id. at 15-16 and 31-32. Cadmus reports that 

SWEPCO is exploring the possibility of offering energy-efficiency home improvement 

loans in future years; Cadmus recommends that SWEPCO continue to explore this 

option. Id. at: 132. 
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Centerpoint achieved 114% of the Commission’s energy savings goal and spent 

78% of its planned budget. Centerpoint Annual Report at 45 and 6. Centerpoint served 

114,934 customers rather than the planned 61,546; however, other than the Home 

Energy Reports program and the program that mails customers free, low-flow 

showerheads and faucet aerators, CenterPoint served 4,753 of 7,746 planned customers. 

Id. at g,ii, 13,16,1g, 22,26,29,32, and 35. 

CenterPoint’s evaluator (ADM Associates) reports that there are many 

opportunities for cross-fuel coordination that are not being capitalized upon, including 

joint implementation of mailer kits, and that the portfolio has a gap in residential 

building envelope offerings, in that both the AWP and HEAL programs have 

participation criteria that may prevent most Centerpoint customers from participating, 

Id., Appendix A at 1-3 through 1-4. Evaluators note, however that HEAL could serve as 

a model for cross-fuel savings and for its measure financing provisions. Id. at 1-6. ADM 

states that CenterPoint’s C&I Solutions program (which produced over a quarter of its 

portfolio therm savings) was highly successful and that many projects already had 

incentives reserved for 2013. ADM notes, however, that the program has not yet 

engaged certain key trade allies in a meaningful manner. Id. at 1-5. 

The AG suggests that the Commission may need to scale back its proposed targets 

in order to reduce rate impacts on customers who do not participate in EE programs. 

AG at 13 (the AG’s concerns are Mer detailed below in the discussion of program cost 

effectiveness evaluation). Sierra Club disagrees that reduced targets are the answer to 

non-participant rate impacts, and states that reducing program goals to avoid nonparticipant impacts would be inconsistent with the purpose of the Energy Conservation 
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Endorsement Act ("ECEA"), which aims to achieve broader structural and societal 

benefits. Id. Audubon recommends that making comprehensive programs available to 

all customer sectors is a better way to address equiw and rate impact concerns. 

Audubon Reply at 4. 

Ruling Regarding Joint Motion and Targets 

The Commission appreciates the work of the parties in reaching consensus 

regarding a coordinated, joint Potential Study; the work of program administrators in 

ramping up EE program performance; and the assistance of Staff, the AG, evaluators, 

and intervenors in supporting, verZying, and providing constructive critiques of that 

performance. This "remarkable progress," noted by Dr. Johnson, is a credit to the State. 

Not inconsequentially, according to the IEM, "[c]ustorner satisfaction, a critical 

indicator of programs success, was overwhelmingly positive across the entire Arkansas 

energy efficiency program portfolio" including "high marks for a11 aspects of the 

program operations including the simplicity of the paperwork, rebate processing time, 

and interactions with the contractors." IEM Report at vii and 22. The Commission 

notes that its further rulings in later parts of this order are necessarily interconnected 

with the issues of energy savings potential and target-setting, because the setting of 

reasonable EE savings targets, and the evaluation and achievement of cost-effective EE 

potential, depends in part on the rdes for defining achievement and determining costeffectiveness. 

The Commission suppork implementation of a joint Potential Study, but requires 

clarification of several issues. The Joint Motion does not detail the purposes, scope, or 
Docket Nos. 13-002-U 

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methods of the proposed study. Rather, it indicates that “the scope and other issues” 

wi11 be determined in the future through PWC collaborative deliberation. 

The Commission takes administrative notice that the National Action Plan for 

Energy Efficiency (WAPEE”) indicates that potential studies may generally fdl within 

three categories (although a particular study can perform more than one function): (1) 

High-level studies that generally build a case for energy efficiency; (2) Investment-grade 

estimates of specific savings needed to avoid a p&cUlar supply-side investment or (3) 

Detailed Planning and Program Design studies. Guide for Conducting Energy 

Eficiency Potential Studies, NAPEE, November 2007, at ES-3. NAPEE further 

indicates that such studies may estimate four types of EE potential: (I) technical 

potential, (2) economic potential, (3) achievable potential (or “m~mum achievable 

potential”), and (4) program potential (or the potential achievable through the 

implementation of a specific set of programs). Id. at 2-4. Technical and economic 

potentials are theoretical maxima, independent of program design and real-world 

barriers to program achievement. Maximum achievable potential and program 

potential, however, are dependent upon program budgets and designs and (the 

Commission would assert) on related jurisdictional policies. Id. Finally, NMEE points 

out that, while detailed potential studies useful for program design must include various 

types of baseline, energy forecast, cost, and disaggregated des data, the quality and 

availabiIity of data is often the limiting factor of a potential study and drives the 

methods used. Id. at 3-3. 

Audubon’s comments that the PWC Potential study would indicate an 

approximate upper limit on reasonably achievable savings; that it would not account for 
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various factors such as program portfolio design, differences among program 

administrator portfolios and resources, and the time required to “ramp up” programs; 

and that savings gods would need to be scaled to an achievable level given available 

time and resources. These comments seem to indicate that Audubon currently views the 

proposed Potential Study as less than a program design study, and as an estimate of 

maximum achievable potentid, if not of economic potential. On the other hand, the 

recommendations of Cadmus, ADM, and the EM (in some cases with some level of 

explicit agreement by utilities), appear to focus on primary data collection necessary for 

the improvement of specific programs, and for the appropriate development of program 

portfolios and the strategic allocation of funding among programs within a portfolio, 

The Commission interprets the Joint Motion to refer to a study with enough data 

collection, analysis, and detail to inform program and portfolio design--in effect helping 

describe not only what the maximum achievable potential is, but also how to better 

realize it. Each purpose is legitimate, and each requires careful consideration of the 

types of data collection and analysis that would need to be specified for an RFP bidder. 

Furthermore, it seems reasonable that a joint, comprehensive Potential Study would 

overlap in purpose and methodology (as indicated by recent Cadmus surveys and the 

recommendations of the IEM), with program evaluation and the annual updating of the 

TRM and its Protocols. 

The Commission therefore directs the PWC to develop and submit to the 

Commission for its approval, on or before noon on November 1, 2013, an RFP and 

accompanying testimony that describes PWC’s more detailed recommendations for an 

Arkansas EE Potentid Study that reasonably lays the groundwork to maximize the 
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achievement of cost-effective EE potential, including: a clear set of objectives and 

expected outcomes and uses for the potentid study; a scope of work that includes data 

collection and study approach as well as a report outline; a recommended budget (or 

budget range with options); and a schedule with timelines for solicitation of a Potential 

Study consultant, data colIection, report preparation, review of drafts, and presentation 

of the final report. The RFP should provide that all data, assumptions, formulas and 

algorithms used to estimate EE potential shdl be transparent to the Commission and to 

stakeholders. The Potentid Study shall estimate potential, taking into account the 

rulings in this Order regarding avoided costs and program and portfolio screening for 

cost effectiveness. The Commission recommends that the PWC consider the parameters 

of the Potential Study with the following issues in mind and inform the Commission of 

the PWC’s recommendations about them when the RFP is submitted for approval: 

I. Which of the four common types of EE potential will be 

quantified, and over what time period? Will potential be presented as a 

specific number or a range with indicated estimates of confidence and 

precision? 

2. What time period will the Study cover (5 years, 10 years, 20 

years, etc.?); will the study assume only existing commercially available 

technology and/or make assumptions for future innovation? 

3. What will be the source(s) of data used to generate the indicated 

potentid for energy efficiency in Arkansas? What is the basis for knowing 

that such data are available within the cost and schedule indicated? 
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4. How is the budget-or range of budgets-for the potentid study 

estimated? What -trade-offs were made between Study schedule, costs, 

and accuracy of results? Are there some alternative budget, schedule, and 

quality options that the Commission should consider for the potential 

study? 

5. Will the Study include baseline market studies and will the Study 

use existing Arkansas TRM and EM&V data and/or be a basis for a 

coordinated effort to strengthen and update the Arkansas-specific 

measure/program baseline information in the TRM and thus be useful for 

other EM&V activities? 

6. Will the Study address subsectors of residential, commercial and 

industrial customer classes, such as: low-income residential, multifmily, 

institutional, agricultural and industry-specific industrial subsectors? Will 

the Study indicate results as state totals or by service territories; and/or by 

different regions (e,g., urbanlrural) and demographics in the state? 

7. WilI the Study include an assessment of the energy efficiency 

delivery markets (i.e. contractors, retailers, distributers, etc. that do or 

could serve the Arkansas market)? 

8. How will the Study account for inter-utili@ and cross-fuel EE 

savings opportunities and the administrative improvements recommended 

by the IEM and program evaluators? 

While a Potential Study can help inform god setting, goal-setting and the 

establishment of the related utility performance incentive are ultimately the province of 
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the Commission, in its role of establishing a framework that produces a just and 

reasonable balance between utiliiy and ratepayer benefits. After three years of Quick 

Start programs without Lost Conbibution to Fixed Costs (“LCFC”) and utility 

performance incentives, the Commission in late 2010 approved an overall framework 

including those elements “only in the context of significant god setting . . . not [as] an 

independent right of utilities, but rather [as] a component of a coordinated group of 

policies reasonably calculated to deliver overall benefits to ratepayers, to utilities and to 

society in a cost-effective manner.” Order No, 14, Docket No, 08-137-U at 18. The 

Commission wiIl consider the results of the Potential Study-not as a definitive 

statement of what is possible-but rather as part of its reasoning in establishing gods 

and incentives for 2016 and 2017 and in approving three-year plans. 

With regard to goal-setting for 2015, the Annual Reports and EM&V reports show 

that most IOUs are exceeding existing Commission goals, despite spending less than 

their approved budgets and reaching fewer than planned participants. This is true 

despite growing pains during the first full year of program implementation, despite 

partial-year implementation of some programs and despite non-participant program 

awareness levels that are frequently at or near 1%. Evaluators make over 400 specific 

recommendations for program improvement, including cross-fuel improvements, 

facilitation of financing to address near-universal customer concerns with the first cost 

of measures, and filling of program gaps that can lower adminisQative costs per unit of 

energy saved and create new energy savings opportunities. Also, M indicates that at 

the current level of effort, it will exceed its long-term energy savings plans, which 

formed one of the bases for the targets proposed in Order No. I. This evidence is not, as 
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some parties suggest, borrowed from other states, but rather is rooted in the recent 

experience and considerable documentation by and work of parties in this docket. 

Also, the Commission interprets the JCP’s proposal to receive performance 

incentives for meeting up to 150% of Commission goals as an indication that the JCP 

believe that some level of achievement above the current level is possible. Multiplying 

the current level of achievement (0.75% for electric utilities and 0.40% for natural gas 

utilities) by 150% would yield an upper bound for incentives of 1.13% for elecbic utilities 

and 0.60% for natural gas utilities. This is one more indication that an initial, 

incremental increase in energy savings goals is reasonable. Finally, no parly indicates 

that the Commission’s proposed gods are unacbievable. 

Thus, given the time sensitivity and the need to carefully plan to maximize the 

usefulness of the Study, and in order to provide some clarit-y and direction, the 

Commission hereby relies upon the evidence of growing and more cost-effective 

achievement to establish a 2015 target of 0.9% of kWh des for electric IOUs and 0.5% 

of therm sales for natural gas IOUs. In deference to the concerns of the AG regarding 

rate impacts, these targets are slightly below the first year targets proposed in Order No 

1. This slower ramp-up of comprehensive program offerings provides more time for the 

PWC to coordinate programs to reduce duplicative costs, and to implement other 

lessons learned and efficiencies of scale. The Commission reserves the right to revisit 

the 2015 target at the time that it establishes targets for 2016 and 2017, based upon the 

Potential Study or other data that may become available, 
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Issue 2: Utility EE Performance Incentive 

The JCP agree with the Commission that the utility performance incentive should 

be reformed, but recommend alternatives to the Commission’s proposed revision. JCP 

at 11. The JCP agree that the incentive should increase linearly dong its range, rather 

than increasing step-wise from a cap of 5% of EE program budgets to a cap of 7% of EE 

program budgets at the transition from 99% to 100% of goal achievement. Id. The JCP 

further recommend that the cap on the performance incentive should range from 5% to 

15.5% of program budgets, rather than the 4% to 8% proposed by the Commission. Id. 

at 12. The JCP state that this incentive cap conforms with national best practices, which 

average 12-13%. Id., citing, Carrots for Utilities: Providing Financial Returns for 

Vti&y Inuestments in Energy Eficiency, American Council for an Energy Efficient 

Economy PACEEE”), 2011~ The JCP further recommend that the amount of the capped 

incentive should be based on 15% of net TRC benefits, rather than io%, as a means of 

motivating utilities to reach the higher anticipated performance goals. Id. The JCP 

recommend that performance should be awarded between 80% and 150% of god 

achievement, rather than the current 80% to 110% of goal, or the 80% to 120% proposed 

by the Commission in Order No, 1. The JCP note ACEEE’s finding that “when the 

available incentive falls within a range, most utitilities have earned at the high end of the 

range;” the JCP supports a performance range and associated incentives that encourage 

utilities to continue to deliver more energy savings. Id. at 13. The JCP also agree with 

the Commission that the utility avoided cost portion of the net benefits calculation 

should be held constant during each 3-year EE program cycle. Id. at 14. 
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The JCP recommend that the Commission retain the practice of awarding 

incentives based on annual performance, rather than shifing to a cumulative, 3-year 

performance award. Id. at 14. The JCP indicate that a cumulative incentive will be 

complex and may eliminate a utiliQ+s ability to earn an incentive in year 3 if its 

performance is above goal in years 1 and 2, or conversely if its performance in years I 

and 2 is substantially below goal. Id. at 14-15. If the Commission adopts a cumulative 

incentive, the JCP oppose any “claw-back” provision requiring the utility to refund 

earlier incentives based on later under-performance because it would increase 

regulatory uncertainty. Id. at 15. 

While EAI is included within the JCP, it does not agree with the PWC that 

avoided costs should be fixed for three years for purposes of calculating the EE 

performance incentive. M at 9. Rather, EAI favors annual adjustment of The avoided 

costs that are included in net benefits, to avoid hindering the integration of EE resources 

within the IRP process. Id. 

AEEC/AGC does not favor the award of utility incentives, but to the extent they 

are awarded, favors modifying the existing structure to provide a linear relationship 

between performance and incentive awards, and limiting them to modest levels that are 

paid only for superior performance. AEEC/AGC at 5. For instance, AEEC/AGC 

suggests that incentives could be awarded only for achievement above 110% of god, with 

the incentive capped at 5% of program budgets. Id. at 5-6. AEEClAGC object: that the 

JCP’s proposal to allow incentives of up to 15% of program budgets, in combination with 

EM’S LCFC costs of 15% of 2013 program budgets, could lead to LCFC and incentives 

comprising almost a third of a utility‘s program budget. AEECIAGC Reply at 17-18. 
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AEEC/AGC opposes any lowering of the threshold for allowing incentives and opposes 

the award of incentive payments for any program with a Ratepayer Impact Measure 

cost-effectiveness test rRTM test”) score below one. AEEClAGC at 6. 

Audubon and Sierra Club support the Commission’s proposed revisions to the 

utility EE performance incentive, including the three-year cumulative goals. Audubon 

at 3; Sierra Club at 3. Audubon argues that it is appropriate to use the same, ked 

avoided cost to determine net benefits that is used in establishing program savings 

targets, because this structure links financial rewards to factors that the EE program 

administrator can control-such as measure selection and program implementationrather than uncontrollable market prices for energy. Audubon at 3-4. Audubon states 

that updated avoided cost projections at the end of the three-year period may be no 

more accurate than those initially forecast. Audubon notes that the 

Commission’s proposal also fms the total amount of available incentive based on the 

three-year program budget, eliminating further uncertain-ty, and that the three-year 

cumulative incentive will reward midcourse adjustments by program adminisbators to 

compensate for underperformance. Id. Sierra Club favors the increase of the maximum 

incentive cap to 8% of program budgets, but has concerns about raising the incentive 

any higher; Sierra Club seeks to maximize the amount of program funds spent on 

implementation and to ensure that incentives are no larger than necessary to motivate 

cost-effective program implementation. Sierra Club at 3. 

Id. at 4. 

The AG reviews the existing performance incentive structure, finding that it 

includes some incentive for utilities to overspend due to caps based on EE program 

budgets, and to benefit from higher avoided cost numbers. AG at 4-5. However, the AG 
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finds that, overall, most factors included in the shared savings calculation dip utility 

interests with ratepayer interests. Id. The AG states that the Commission’s 

establishment of an IEM and robust EM&V have %been critical in producing reasonably 

accurate estimates of the amount of enerw savings and preventing a disconnect” 

between the reporting and reality of EE program benefits. Id. at 5-6. 

The AG supports a modified version of the proposed cumulative 3-year goal, 

under which the goal for each year simply adds to a total cumulative god, thereby 

rewarding early achievement of the total goal and eliminating any need for a clawback 

provision.6 Id. at 12. The AG also supports implementing a linear scale for incentive 

rewards over a broader achievement range-particularly with regard to expanding the 

high end of the range. Id. at 12-13. The AG contends that there is no need to increase 

the incentive caps or to increase the proportion of shared savings available for 

incentives because the current levels have been smcient to incentivize significant 

program expansion. Id. at 13. The AG furher states that, because LCFC in practice 

includes variable costs, it functions as an additional incentive. Id. at: 13. AOG finds the 

AG’s position favoring a higher range for rewarding utility performance, but opposing 

an increase in incentive caps or shared savings, to be inconsistent. AOG Reply at 7. 

Ruling Regarding the Utili& Performance Incentive 

The Commission accepts the recommendations of the JCP to retain an annual 

goal and incentive structure in order to avoid unnecessary complexity.7 The 

Commission accepts the widespread agreement that the incentive should be awarded on 

6 The AG does not specify how, or whether partial performance within each year would be rewarded. 

7 The Commission notes khat, in evaluating Centerpoint programs, Cadmus suggested that utiIities 

currently have no incentive to over-perform in a single year, leading to mid-year shutdown of some 

programs and Ioss of program momentum. Cadmus recommended dowing over-performance in a singlc 

year to be credited to the subsequent program year goal. Centerpoint Annual Rcport, Appendix A at 3-5. 
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a linear rather than stepwise basis, and that the range for award should not reach below 

80% of performance, and that the upper end of the range should be extended. The 

Commission retains its original proposal to set the upper end of the performance zone at 

120%; to cap the incentive at the sliding scale between 4% and 8% of program budgets 

(such that the incentive is capped at 4% of budgets for 80% achievement; 5% for go% 

achievement; 6% for 100% achievement; 7% for 110% achievement; and 8% for 120% 

achievement); and to limit shared savings to IO% of net benefits, in recognition of 

AEEC/AGC’s argument that performance incentives themselves need not and should 

not become a major share of EE program budgets. 

Issue 4: Utility Avoided Costs. 

The JCP generally agree with the majority of the Commission’s proposals related 

to the determination of utility avoided costs. JCP at 16. The JCP observe that the 

proposals leave sufficient opportunity for utilities to account for differences in their 

individual circumstances regarding utility-specific avoided generation capacie, energy, 

and transmission and disbibution rT&D”) costs. Id. 

Regarding avoided energy costs, the JCP agree that they should include the value 

of energy freed by EE programs and sold into the wholesale market or avoided market 

purchases, Id. at 17. The JCP also agree that utilities should differentiate avoided 

energy costs by time and season so as to facilitate the valuation of individual BE 

programs, or individual measures, if the measure forms a significant portion of portfolio 

energy savings. Id. 

Regarding avoided capaci’cy costs, the JCP agree that they may appropriately be 

based on the cost of a combustion turbine (“’ or “peaking unit”), as modified to 
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account for market conditions, and as applied to years in which the utility or relevant 

market area is not in surplus for capacily. Id. at 18, The JCP note that it may be 

necessary and appropriate to use CT-based values as a proxy if market based values are 

not available. Id. The JCP support the avoided capaciw calculations based either on 

actual prices that are escalated, or on modeling that is based on available market data, 

taking into account any signifmint, foreseeable changes to marginal capacity costs due 

to environmental conh-01s. Id. The JCP note, however, that specific values may not be 

readily available in the latter case, and that the JCP do not expect that the cost of nonpeaking resources will be brought to the margin or avoided during the planning horizon. 

Id. 

Regarding the economic valuation of capacity costs over time, the JCP support 

adoption of a Real Economic Carrying Charge (IIMCC,” described more fully below) to 

annualize the value of avoided capacity savings, to the extent that a utility uses a CI’ as a 

proxy for avoided capacity costs. Id. at 19. The JCP observe, however, that: a utility 

using market prices will not have a Tevelized capacity price or a smooth adation of 

costs. Id. 

Regarding transmission and distribution (“T&D”) costs, the JCP support the 

proposal that each utility should develop avoided T&D costs, but question whether 

specific costs for these categories can be determined, and observe that the calculation 

may involve more utility-specific data than is appropriate for the purpose, Id. at 19. 

Regarding the value of line losses, the JCP support the proposal to require that EE 

avoided costs should reflect marginal, rather than average, avoided line losses, although 

in some cases specific avoided costs may be difficult to accurately estimate. Id. at 19-20. 
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oraer NO. 7 

Regarding carbon pricing, the JCP are not unified, with contention surrounding 

the Commission proposal to deveIop a common assumption [per unit) for C02 

compliance costs. Id. at 20. The JCP state that agreement is possible only if the 

common CO2 cost is used solely for evaluating EE programs, without implied 

endorsement by the utiliw, and not for broader planning purposes. The JCP seek 

further time to develop consensus on this subject. Id. The JCP seek further time to 

consider this issue, but observe that the U. S. Energy Information Agency’s rEJA’s”) 

Annual Energy Assessment includes a credible, readily-accessible, cost-free estimate 

that may be useful, The JCP note that market prices for energy and capacity may 

include implicit estimates for carbon prices, and that a distinction may be drawn 

between projected C02 compliance costs (Le., EPA compliance) and broader COP 

damage costs (i.e., health impacts). Id. at 21. 

expresses general support €or many of the Commission’s proposed avoided 

cost guidelines, but is concerned that some elements would require “wholesale 

revisions” to EM’S current process for calculating avoided costs, EAI at io. EAI states 

that it currently relies on proxies for market: based costs for avoided capaciq, energy, 

and T&D which are consistent with the Commission’s proposals to use timedifferentiated costs, and to integrate avoided energy, capaci’cy and T&D costs. Id. EAI 

uses a levelized avoided capacity cost, rather than a WCC, because it views EE as a 

long-term investment: and assumes that a customer would install a measure as efficient 

as, or more efficient than, the EE program installed measure at the end of the measure’s 

life. Id. at 10-11. EAI states that a RECC approach would count only the earliest, lowestcost years of EAI’s long-term avoided costs, and is thus inconsistent with a long-term 
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view of EE. Id. at 11. EAI references AG Witness William Marcus’s tabular 

representation of levelized vs, RECC avoided capacity values to argue that the RECC 

approach undervalues EE and takes a short-term view, because the value of measures 

would be calculated starting from the date of individual measure installation, which is 

always in the early, low-cost years of the cost curve. Id. at 14. EAI comments that this 

approach never realizes the fu11 cost of avoided capacity because individual measures 

never have a life that equals that of the CT. Id. EAI also comments that the RECC’s use 

of measure-specific lives is inconsistent with the Commission’s focus on portfolio-based, 

rather than measure- or program-specific cost-benefit. Id. EAI warns that adoption of 

RECC methodology will drive the cost-effectiveness of comprehensive programs 

negative, eliminating whole-house or faciliv programs and leaving only a few 

commercially-available EE measures for delivery through standard-offer or measure-bymeasure discount approaches. MI Reply at 9. EAI warns that this decision will, in 

turn, affect: target-setting. Id. EAI notes that no party provides an example of how the 

RECC has been applied elsewhere, and that it is thus not a demonsbated ‘%best practice.” 

Id, at 11-12. 

EM views the Commission’s proposals to include non-peaking resources when 

they are brought to the margin, or transmission substation and line upgrade costs, as 

laudable goals if they increase accuracy, but cautions that such estimates are too 

granular, and potentially impossible to determine. Id, at 12. 

EAI comments that avoided costs used for EE program screening and evaluation 

should be utili@-specific and that using the same avoided costs across utilities would be 

inconsistent with the IRP Guidelines, and would lead to inconsistent assumptions 
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within a utility‘s XW. AEEClAGC agree with this comment. 

AEEC/AGC Reply at 15. EAI also does not agree that the PWC could or should reach 

consensus on a single C02 compliance cost forecast. EAI at 15, 

Id. at 11 and 15. 

AEEC/AGC note that avoided cost determination is inherently uncertain and 

should be pursued conservativdy by incorporating only costs that are known and 

measurable, or estimated with reasonable accuracy, AEEC/AGC at 6. AEEC/AGC 

support the use of market-based, hourly and seasonally differentiated avoided energy 

costs that are, to the extent possible, estimated using production cost models using the 

most up-to-date energy pricing data. Id. at 6-7. For capacity costs, AEEClAGC support 

the use of the levelized cost of a CT, as adjusted for current market prices and need for 

capacity. Id, at 7. AEEC/AGC are concerned that T&D avoided costs are difficult to 

reasonably estimate, but agree that they are appropriately included to the extent they 

can be identified and estimated with reasonable certainty. Id. AEEC/AGC support the 

use of marginal line losses. Id. at 8. AEEC/AGC state that, until carbon prices and 

compliance costs for other fume environmental regulations are known and measurable, 

their inclusion in determining avoided costs are purely speculative and would likely 

overstate market prices and EE 

Id. 

Sierra Club supports the 

Sierra Club at 4. Sierra Club 

program benefits, increasing cost risks for consumers. 

Commission’s proposed refinements of avoided costs. 

agrees with the Commission proposal that properlyconducted production modeling may incorporate environmental costs into energy costs, 

but cautions that such modeling must incorporate likely fkture environmental 

regulations such as strengthened wastewater discharge standards, disposal 
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requirements for coal combustion residuals, and more protective air qualiw standards, 

in order to avoid under-estimating EE benefits. Id, Sierra Club also suggests that 

agreement by the PWC on avoided carbon costs would be more likely with the 

involvement of an independent facilitator. Id. at 5. Sierra Club suggests that existing 

bansmission planning documentation should provide a reasonable basis to develop 

avoided T&D costs, and notes that recent proceedings concerning the proposed reb-ofit 

of the Flint Creek power plant (Docket No. 12-008-U) demonskate that very smalI 

increases in peak load may result in large utility investments. Id. 

Audubon agrees that a market-based, time- and seasonally-differentiated 

approach to determining avoided energy costs is appropriate and environmental 

compliance costs should be included. Audubon at 5. Audubon supports the adoption of 

a reasonable third-party forecast of carbon compliance costs to be fixed for the threeyear program cycle, and as developed through PWC review of the relevant literature. 

Id. at 5-6. Audubon supports market-based avoided capacity costs, or a proxy valued 

under the RECC method. Id. at 6. Audubon states that long-run marginal utility T&D 

can serve as a reasonable basis for the determination of avoided costs, and supports the 

use of marginal line losses. Id. 

The AG generally agrees with the Commission’s proposals to bring some 

standardization to the methods for estimating energy, capacity, T&D, marginal line loss, 

and carbon-related avoided costs, because better avoided cost estimates will lead to 

appropriate sizing of programs and will increase ratepayer benefits. AG at 14-17. The 

AG specificalIy agrees with the JCP that market prices, where available, are preferable to 

proxies and that either method should be adjusted if necessary to incorporate 
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foreseeable changes in price or cost. Id. at 15. The AG also agrees with the JCP that 

accurately estimating avoided T&D costs can be problematic because it is difficult draw 

a linkage between aggregate efficiency measures and specific avoided infrastructure, Id 

Regarding avoided carbon regulatory costs, the AG notes that market prices, if used, 

may include avoided carbon costs that should not be duplicated. Id. at 16-17. 

Regarding the RECC (which was originally proposed by the AG), the AG indicates 

that, in general, the lowest-available cost to supply capaciv within a market wiIl be less 

than the cost of market enby (Le., building a new CT). AG at 5. Also, he states that, 

when the value of a CT is used as a proxy for avoided capacity costs, it is more 

appropriate to say that a short-lived EE measure defers that cost during the life of the 

measure rather than avoids it, AG at 5. Further, at the end of an EE measure’s life, the 

efficiency of any replacement measure should be measured against the baseline for 

efficiency at that future time, according to the AG, and cannot be assumed to exceed the 

new baseline by an amount equivalent to the original measure. AG at 6, In accordance 

with these observations, the AG argues that a RECC method, which estimates the value 

of deferred capacity as an escalating annual carrying charge, more accurately annualizes 

the value of deferring capacity during the specific life of the EE measure in question, 

allocating less value to short-term deferral and more value to long-lived measures. Id. 

at 6-7. Regarding incorporation of TRC results within IPS, the AG states that it is not 

unreasonable to use different, appropriate approaches and assumptions for 

comparisons between demand- and supply-side resources. AG Reply at 7. 

The AG disagrees, however, with the proposal to freeze avoided costs during the 

three-year EE program cycle, and advances the following arguments: (I.) while all future 
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estimates will be wrong, the accuracy of estimating avoided costs for the next year 

improves as the year gets nearer: avoided cost estimates for 2017 will be more accurate 

in 2016 than they were in 2014 (Id. at 17); (2) prudent utility operators must take into 

account changing market prices in managing generation, and ratepayers are similarly 

best served if EE program administers are required to manage using the best and most 

current available information (Id. at 17-18); and (3) the increased accuracy sought by 

the Commission through standardizing components of avoided costs such as line losses 

and T&D will likely be outweighed by the inaccuracy generated by freezing avoided cost 

for three years (Id, at 18-19). AEEC/AGC concurs with the AG on this point, favoring 

annual updates to EE avoided costs. AEEC/AGC Reply at 15. 

AOG responds, regarding freezing avoided costs, that the avoided cost for a 

natural gas utility is the commodiw cost of gas, which is set by the market. AOG Reply 

at 9. AOG states that freezing avoided costs during an EE program cycle is reasonable 

because the utility cannot control the fact that an EE portfolio submitted in year 1 can 

result in dramatically different TRC test results in year 3, inboducing significant risk to 

the utility that it will not earn an incentive. Id. at 9-10. AOG also notes that there are 

practical barriers to making changes to an BE portfolio because program changes take 

time to plan and implement. Id. at 10. 

AAEA states that, while the PWC notes that market prices for capacity and energy 

may include implicit estimates for carbon prices, carbon price estimates should include 

both direct regulatory costs and indirect costs such as property damage and health 
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impacts. AAEA 3.8 AAEA performed modeling to estimate direct: and indirect Iifecycle 

emissions costs, which it offers for consideration by the PWC. Id, at: 3-8. AAEA reports 

that 14 state utility commissions attempted to establish reliable avoided-cost metrics for 

carbon costs as early as 2008, and that six Mew England states have assigned avoided 

carbon costs for energy and capacity from 2005 through 2030 on a levelized basis. Id. 

at 9-10. AAEA points to the U. S. DOE Annual Energy Outlook as another potential 

source of carbon cost estimates. Id. at 11. MEA notes that, in recent Massachusetts 

estimates, carbon costs comprised a sizeable part of total avoided costs. Id. at 12. 

The AG replies to AllEll that the states cited by MEA appear to have been very 

successful at saving energy, but that nearly all have seen prices for elecbicity rise since 

the year 2000 at a faster rate than Arkansas. AG Reply at 8. The AG does not assefi a 

causal link between EE program success and higher prices, but does suggest that 

aggressive EE programs may not help to keep rates low. Id. at 8-9. ABEC/AGC 

similarly caution against modeling Arkansas EE program policies on jurisdictions with 

high rates. AEEC/AGC Reply at: 4. 

While Sta€f supports the PWC positions regarding avoided cost, Staff also agrees 

with IEAI that a levelized cost of a proxy CT is a reasonable approach, and that the RECC 

approach may not be appropriate with determining long-term avoided capacity costs. 

Staff Reply at 5. Staff also agrees with EAI that each utiliv will have utiliv-specific 

avoided costs for planning purposes, including utility-specific carbon costs. Id. 

8 While MEA agrees with the Commission proposal and ~4th the JCP that carbon regulatory costs should 

be included within utility avoided costs, the Commission notes that MU'S comments regarding avoided 

indirect costs could be included in the discussion of NEBS, below. In order to preserve Ws integrated 

discussion, the Commission summarizes it here. 
Docket Nos. 13-002-U 

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Ruling ReEardhg Utilitv Avoided Costs 

The Commission accepts the JCP’s recommendations (which were largely 

uncontroversid among parties) regarding the quantification of avoided energy and 

capaciv costs. As recommended by the JCP, avoided energy costs should include the 

value of energy keed by EE programs and sold into the wholesale market or avoided 

market purchases, and avoided energy costs should be differentiated by time and season 

so as to facilitate the valuation of individual EE programs, or individual measures, if the 

measure forms a significant portion of portfolio energy savings. Avoided capacity costs 

may be based on the cost of a combustion turbine (“CT” or “peaking unit”), as modified 

to account for market conditions, and as applied to years in which the utility or relevant 

market area is not in surplus for capacity. Avoided capaciv costs also may be based on 

available market data, taking into account any significant, foreseeable changes to 

marginal capacity costs, including any such foreseeable changes due to major 

investments such as environmental conbols. 

The JCP and the AG, argue persuasively that, when the cost of building a CT is 

used as a proxy for avoided capacity costs, the ECC is a more accurate reflection of the 

annual value of capacity deferral. One cannot assume that short-lived EE program 

measures will later be replaced by measures that equally exceed future efficiency 

baselines. Adoption of a RECC approach also is in alignment with the Commission’s 

original intent to promote long-lived measures by adopting a shared savings 

mechanism. 

The Commission adopts its proposed guidance, accepted by the JCP and others, 

regarding T&D avoidance, heeding the recommendation by Audubon that long-run 
Docket Nos. 13-002-U 

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Page 39 of 91 

marginal utility T&D can serve as a reasonable basis for the determination of avoided 

costs, and the numerous cautionary comments that proving specific T&D avoidance may 

be unreasonably difficult. The Commission adopts the use of marginal, rather than 

average line losses, which is unopposed by any paw, to quantify EE's incremental 

effects. 

With regard to the estimated cost of compliance with carbon regulation, the 

Cornmission accepts the JCP's recommendation to allow time for and accept for 

consideration a collaboratively-considered, reasonable third-party estimate that would 

be used solely for evaluating EE programs, without implied endorsement by the utility, 

and not for broader planning purposes. The Commission directs utilities and Staff, and 

requests the PWC more generally, to recommend a price for carbon regulatory cost 

avoidance as part of the EE Potential Study RFP submission. If the PWC are unable to 

reach consensus at that time, parties may make joint or individual recommendations for 

the selection by the Commission. The Cornmission accepts EAI's argument that each 

utility will have individualized avoided costs, including individualized forecasts of 

carbon compliance costs. Establishing a common assumption for the unit cost of 

carbon, however, brings reasonable uniformity and cost-comparabiliw to the evaluation 

of EE resources across utiIities, while preserving the flexibility (as the JCP suggest) for 

potentialIy widely-ranging, individualized overall carbon cost impacts on each utility's 

resource portfolio. The Commission retains the flexibility to take into account credible 

evidence that market prices for energy and capacity include implicit estimates for 

carbon prices. The Commission also acknowledges the distinction between projected 
Docket Nos. 13-002-U 

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C02 compliance costs (ie., EPA compliance) and broader C02 damage costs (i.e., health 

impacts), which are more properly addressed as societal NEBs. 

The Commission also accepts the JCP‘s recommendation to fix avoided costs 

during the three-year program implementation period. While EE program managers 

must frequently and rapidly adjust to market conditions, it is the changing markets for 

measure technologies, for consumer and contractor preferences and requirements, and 

for available delivery strategies, rather than fluctuating fuel and capacity prices (or 

forecasts of prices) that most require nimbleness in the pursuit of a long-term, 

incremental resource strategy. Given that nearly all portfolios submitted and approved 

to date remained cost effective through implementation under the TRC test, and even 

more so under the Program Administrator Cost (“PACT’’) test, allowing managers to 

focus on the factors they can most profitably control will create a better linkage between 

performance and reward. 

Issue 5: Cost-Effectiveness Screenim and Evaluation and Non-Enerm Benefits 

~NEBs”) 

The JCP support the Commission’s proposal to include appropriate, reasonably 

quantifiable NEBs in program screening and evaluation because EE programs may 

provide NEBs in addition to currently-evaluated energy savings. Id. at 21-22. The JCP 

do not, however, compTetely agree on which NEBs should be included and what values 

they should be given, and seek €ux“cher time to form agreement. Id. at 22 and 23. 

The JCP also favor the continued primary reliance on the TRC test with the 

inclusion of collaboratively-developed NEBs, rather than a shift towards reliance on the 

PACT test. Id. at 22. The JCP recommend that the same test be used in planning and 

evaluation of individual measures, programs, and program portfolios, and that the 
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Commission continue to require the presentation of all four standard cost-effectiveness 

tests, considering each as appropriate. Id. at 23, Particularly, the JCP recommend that 

the Commission retain the flexibility to include individual education, training and 

marketing programs that may not pass TRC Within overall program portfolios that are 

cost-effective. Id. at 23-24. 

The JCP agree with the Commission that NEBS may fall into three categories: 

benefits to the utility, benefits to customers, and benefits to society not captured in 

utility or customer NEBs. Id. Noting the Commission’s suggestion that parties could 

review the literature on the comfort and health benefits of weatherization and 

recommend reasonably quantifiable, significant NEBs for inclusion in program 

screening, the JCP agree and recommend that the phes should work to develop such 

recommendations. Id. 

MI generally agrees with the PWC regarding NEBS, but believes NEBS should 

only be included when they are quantifiable and material. Id. believes &at the 

statutory requirement that EE programs must be beneficial to both utility ratepayers 

and the utility itself may limit the Commission’s authority to take NEBs into account. 

Id. M supports reliance on the TRC test without NEBs as the most appropriate 

approach, but notes that the current C&EE Rules are flexible enough to allow a utility to 

present the Commission with Societal Test or other cost benefit analysis that includes 

NEBs, Id. at 16. EAI agrees with the JCP that the same cost-benefit tests that are used 

for program screening and approval should be used throughout the EE evaluation and 

review process. Id. 
Docket Nos. 13-002-U 

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AEEC/AGC urges the Commission to focus primarily upon the RIM test in 

screening EE programs, AEEClAGC at 8. AEEC/AGC emphasizes that the majority of 

ratepayers are non-participants in EE programs, and that the RIM test is the only test 

that captures the shift in costs among ratepayers caused by EE program LCFC. Id. at 9. 

AEEC/AGC recommends that the Commission require EE programs to pass the RIM 

test. Id. at IO. AEEC/AGC states that utilities may in certain instances not include 

utility performance incentives within RIM test results, and urge the Commission to 

establish by rule the standard components of each test, Id. AEEC/AGC opposes 

inclusion of health and environmental externalities in EE program cost evaluation, 

noting that such benefits may not accrue to ratepayers who pay all EE program costs. 

Id. at 10-11. AEEC/AGC argues that Arkansas law requires that EE programs benefit 

ratepayers, whiIe the law of other states such as California and Massachusetts is “in 

direct conflict” with this mandate, providing that EE is the highest-priority resource. 

AEEC/AGC Reply at 19. 

As indicated above, MEA favors inclusion of societal and customer NEBS, such 

as indirect environmental damage and health effects from air emissions. MEA also 

indicates that its computer modeling has the ability to estimate dollar savings for certain 

NEBS related to societal issues and economic development amenities such as Tower 

taxes and improved business competitiveness. AAEA at 23-24. 

Sierra Club supports continued reliance on the TRC test for program screening 

rather than PACT, because only the former reflects customer impacts. Sierra at 7. 

However, at the portfolio level, Sierra Club supports use of the PACT test as the best 
Docket Nos. 13-002-U 

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indication of potential customer bill impacts, and to provide consistency in comparing 

demand- and supply-side resources, Id. at 7-8. 

Sierra Club supports inclusion of NEBs within the TRC on the basis that the test 

is distorted if it includes all costs, but not key benefits. Id. at 6. Sierra Club suggests 

that it is penny-wise and pound-foolish to forego quantifying the more complicated 

NEBs, since the ultimate benefit realized through program implementation may greatly 

outweigh administrative costs of estimation. Id. Sierra Club indicates that Arkansas 

can draw on the work of states that already quantify certain NEBs, or fdow the example 

of other states that employ adders to account for hard-to-quantify NEB, Id. at 6-7. 

(CenterPoint believes that Sierra’s suggestion to use an “adder” to reduce NEB 

estimation costs may have merit. CenterPoint Reply at 4.) Sierra Club states that 

inclusion of NEBS within TRC does not conflict with resource planning guidelines, as the 

PACT is the proper test for comparing resources in that context. Sierra Club Reply at 4. 

Audubon supports program screening through the TRC test, and not the PACT 

test, because TRC is designed to account for net impacts on a11 resource costs, and 

because PACi’ does not account for costs and benefits of program participation that do 

not impact utility revenue requirements. Id. at 9-10. Regarding NEBs, Audubon states 

that, because EE investments do not serve the public interest if they do not decrease the 

cost of end-use service, program administrators should include only those NEBs that 

can be quantified with a level of confidence commensurate with prirnw program 

benefits such as avoided energy costs. Audubon at 6-7. Audubon therefore 

recommends that any included NEE must (1) be well-defined in terms of measurably 

reducing scarce resources; (2) have a quantifiable economic value; and (3) be clearly 
Docket Nos. 13-002-U 

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applicable to the specific program or measure at issue. Id. at 7. Audubon recommends 

that the use of generic “adders” should be avoided and that NEBs should be subject to 

the same EM&V standards and review as electric and gas energy savings. Id. Audubon 

offers the following examples of well-defined, quantifiable NEBs: 

a. avoided fuel costs (e.g., propane, oil, kerosene, wood, cod); 

b. avoided water and sewer costs; 

c. deferred equipment replacement costs for early-replacement measures; 

d. avoided equipment replacement costs for measures with longer useful lives; 

and 

e. avoided equipment repair or refurbishment costs (e.g., motor rewinding). 

Audubon at 7-8. Audubon also favors inclusion of the folIowing NEBs if they are welldefined, quantifiable, and if their magnitude justifies the cost of assessment and 

verification via Arkansas EMW impact evaluations: 

a. Avoided utility transaction costs associated with improved bill payment and 

reduced customer service calls; 

b. Secondary space-conditioning benefits resulting in resource savings (such as 

reduced space heater and fan use from infiltration reduction); 

c. Reduced labor or other inputs resulting from improved commercial space 

conditioning, lighting, and industrial processes; and 

d. Reduced waste disposal costs resulting from process improvements. 

Id. at 8, Audubon recommends critical review of the literature regarding putative health 

benefits of weatherization and does not support exceptional treatment for NEBs 

associated with weatherization or other particular programs. Id. at 9. Audubon 
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cautions that NEBs do not lend themselves to generic treatment and can vary 

significantly among customers participating in the same or similar programs, so that 

NEB policy should remain flexible. Id. Audubon allows, however, that consistent 

treatment of NEBs Within the TRM review process does provide for initial stipulation of 

documented values that are applicable to specific measures and programs, pending 

EM&V review, as warranted by the magnitude of the benefit and the cost of 

measurement and verification. Audubon Reply at 5. 

ACM agrees with Audubon’s recommendations regarding specification of 

NEBs where they can be readily quantified through EMW, and opposes the use of 

generic adders. ACAM Reply at 4. ACU, however, also recommends that, where 

values for other NEBs have been established through extensive research relied upon in 

jurisdictions that have implemented EE programs for many years, the PWC should 

review and adapt such research appropriately to Arkansas, for Commission approval. 

Id. at 4-5. 

The AG submits the following views regarding the four standard costeffectiveness tests, which utilities must apply under the current C&EE Rules: In practice 

the Participant Cost Test: (“PCT”) is nearly always the most positive and has little policy 

impact, AG at 6, The next-highest scoring test is usually the Program Administrator 

Cost Test (“PACT”), which includes avoided utility system supply costs and amounts 

paid to customers as EE measure incentives, but not LCFC, which the AG characterizes 

as a weakness. Id at 6-7. PACT determines which system resources are cheapest from 

the utility‘s perspective, but it only addresses aggregate customer bill impacts, rather 

than impacts to specific customers, and thus fails to recognize potential non-participant 
Docket Nos. 13-002-U 

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rate and bill increases. Id. TRC tends to be lower than PACT because it adds the total 

cost of EE measures to the avoided utility supply costs, and shares the same weakness of 

viewing LCFC as a transfer within system costs rather than an added cost. Id. at 8. The 

Ratepayer Impact Test (TIM”), which alone includes LCFC, determines whether rates 

will increase and is often overlooked, in part because utility rates will increase even 

without EE programs. Id. RJM results below 1 indicate that both rates and bills for 

non-participants wilI rise, and that for these non-participants, EE resources are more 

costly than supply-side resources, Id. at 8-9. 

The AG states that EE portfolios in Arkansas tend to pass Pa, PAa and TRC, 

indicating that participants and the system are benefitting and that utilities are choosing 

the cheapest supply options, but that lack of attention to RIM scores has given utilities 

little incentive to address rate impacts. Id. at 9. The AG notes that, when customers 

install alternative resources, such as solar panels, improved insulation, or load control 

devices, they conbibute system resources and it is not necessarily unfair for the share of 

supply resources paid by other customers to increase. AG Reply at 3. The AG 

emphasizes, however, that over-reliance on EE programs that do not pass RIM can 

rapidly increase rates, Id. at 4. The AG provides the example that the revenue 

requirement for EAI’s current EECR, at $63,086,302, is comparable to the $73,781,760 

increase in base revenues approved in its last rate case, and has resulted in an increase 

from $0.23 per month to $3.55 per month for a typical customer since the inception of 

EE programs. Id. The AG estimates that EE programs have benefited some customers 

and probably produced aggregate benefits, but has not benefited al2 customers. Id. The 

AG concludes that the TRC test is a reasonable way to gauge EE program cost 
Docket Nos. 13-002-U 

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effectiveness and to calculate performance incentives, but that the Commission should 

consider mitigating non-participant impacts by including RIM net benefits within the 

shared savings calculation (while still giving TRC greater weight) or by setting less 

aggressive goals, which should be based on a potential study. AG at 13; AG Reply at 4-5. 

The AG contends that only quantifiable utility-perspecthe NEBS-such as 

avoided bad debt, avoided arrearages, and avoided customer service are appropriate for 

inclusion in a modified TRC test, because TRC is intended to estimate benefits to the 

system. AG at 19. According to the AG, any NEBs included within a cost-effectiveness 

test should be those that take the perspective of the particular test-ie., customerperspective NEBs should be included in the Participant Test, and societal NEBs should 

be included in the Societal Test, but neither customer nor societal NEBs should be 

included within the TRC test. Id. at 19-20. Particularly, customer NEBS are a benefit to 

individual customers, and not the system as a whole. Id. at 20. 

CenterPoint states that the AG’s suggestion to include RIM net benefits within 

the shared savings calculation should be “summarily rejected” on the basis that few EE 

programs pass the RIM test and that it would thus reduce utility incentives for factors 

beyond their control. Centerpoint Reply at 3. Sierra Club states that it is sensitive to the 

non-participant rate impacts highlighted by the AG, but suggests that they can be 

minimized by requiring programs to pass the PAa test, or by giving preference to 

portfolios that include programs with better RIM test scores. Sierra Club Reply at 2. 

Sierra Club and ACAAA disagree with the AG’s statement that TRC assesses 

‘“oenefits to the system,” encompassing “benefits to the utilily,” arguing instead that it 

addresses all costs and benefits to the utility and to customers. Sierra Club Reply at 3; 
Docket Nos. 13-002-U 

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Page 48 of 91 

ACAAA Reply at 3. ACM argues that the AG's concern that NEB inclusion may raise 

rates or exacerbate non-participant cost shifting is misplaced because inclusion of NEBS 

influences how EE budgets are allocated, but not the size of the budgets. ACAAA Reply 

at 3. ACAAA states instead that the Commission sets overall EE budgets. Id. 

Audubon, in comments echoed by ACAAA, rejects suggestions by the AG and 

Sierra Club that RIM test results should be incorporated into program screening or 

shared savings. Audubon Reply at 1-2. Audubon comments that the outcome of the 

RIM test is intrinsically determined by utili@ cost allocation and rate design, and that 

the same measure with identical cost, energy savings and avoided cost can pass or fail 

the RIM test depending on which utili'cy administers the program or even on the 

participant rate class within the same utility. Id. at 2. Audubon adds that an energy 

saving measure with zero total resource implementation cost will fail the RIM test if the 

resulting reduced customer payment for energy is less than the avoided cost of 

supplying and delivering the energy (i.e., if marginal rates exceed marginal costs). Id. 

AOG adds on this point that, for natural gas utilities, the retail rate will always be higher 

than the avoided cost €or a gas utility. AOG Reply at 9. 

Audubon further asserts that a negative RIM score indicates the amount that 

utili@ revenue must increase to maintain revenue requirements, but that it is 

independent of the mechanism for recovering the shortfall in fixed cost recovery, which 

might include ratepayers (including program participants), shareholders, or a 

combination of the two, Id. A program that fails RIM will do so regardIess of the 

magnitude of any subsequent rate increase, according to Audubon. Id. Audubon 

further notes that a customer who implements their own efficiencies outside of utility 
Docket Nos. 13-002-U 

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EE programs causes a similar revenue reduction and potential rate impact on other 

customers. Id. Audubon suggests that utilities should be encouraged to aggressively 

promote the broad distribution of such customer benefits, thereby transforming 

markets so that, over time, installation of efficient equipment becomes standard and 

even non-participants benefit. Id. at 3-4, Audubon argues that use of the RIM test for 

program screening will preclude or limit the attainment of such benefits, and states that 

the AG's concerns are best addressed through implementing a broad EE program 

portfolio that makes cost-reduction available to all ratepayers through broad 

participation. Id. 

Audubon dso takes issue with the AG's recommendation to include customer 

perspective NEBS within the Pa, but not within TRC. Audubon Reply at 5. According 

to Audubon, the CaZlj"ornia Standard Practice Manual adopted by the Commission 

provides for the inclusion of the same participant avoided costs for alternate fuel devices 

as a benefit in both the PCT and TRC tests. Id. Audubon sees no sound economic basis 

to exclude any quantifiable energy or non-energy cost savings from TRC, Id at 6. 

In response to the AG's recommendation to lower costs by including RIM test 

results within net benefits, AOG indicates that LCFC and incentives totaled less than 

io% of program costs in 2012, and that the practical impact of relying on RIM would be 

to significantly decrease EE programs and energy savings in Arkansas. AOG at 8-9. 

Staff responds to suggestions that the Commission give greater weight to the RIM 

test by recommending that the Commission continue to require submission of all tests, 

and continue to rely on TRC as the primary cost-effectiveness test. Staff Reply at 3. 
Docket Nos. 13-002-U 

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Page 50 of 91 

Staff states that NEBs should be included only when they are quantifiable, material, and 

relevant to the specific program or portfolio. Staff Reply at 6. 

Ruling ReEarding Cost-Effectiveness ScreenhE and Evaluation and NEBs 

The Commission accepts JCP's recommendation to rely primarily on TRC with 

the inclusion of collaboratively-developed NEBs, for the screening of programs and 

portfolios rather than shift toward reliance on PAa. The Commission accepts the 

recommendation of JCP that the same test be used in planning and evaluation of 

individual measures, programs, and program portfoTios, and that the Commission 

continue to require the presentation of d1 four standard cost-effectiveness tests, 

considering each as appropriate. The Commission thus retains the flexibility to include 

individual education, training and marketing programs that may not pass TRC within 

overall program portfolios that are cost effective. 

The Commission declines to systematically increase the weight of the RIM test, or 

to insert it into utility performance incentive calculations for EE programs. The 

Commission declined to use the RIM test as the primary means of screening EE 

programs in Order No. 12 of Docket No. 06-004-R.9 

Regarding the use of the RIM test for utility performance incentives, the 

Commission credits Audubon's careful reasoning regarding the precise information 

regarding theoretical rate impacts that is produced by the RIM test. Programs should 

not be developed and planned on a basis which is inkinsidly determined by utility cost 

allocation and rate design, rather than by comparing the total costs and benefits of 

9 The Commission there found that various beneficial supply-side investments, such as tree trimming, 

wonId fail the RIM test, and that, with proper program planning and over time, all ratepayers will benefit 

from programs approved after consideration of all of the standard tests. Order No. 12, Docket No. 06- 

004-R at 32. 
Docket Nos. 13-002-U 

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alternative resources. Nor should programs that save natural gas be excluded whenever 

(as AOG claims) the retail rate is higher than the avoided cost for a gas utility. TRC has 

the primw purpose of comparing total resource costs, and is the better test to evaluate 

overall program cost-effectiveness and performance. Furthermore, as ACAAA notes, 

while cost-effectiveness tests are used to screen programs, they do not dictate program 

budgets, which are instead proposed by program administrators and approved by the 

Commission. 

The Commission, however, appreciates the concerns of the AG and of AEEClAGC 

regarding RIM scores and rate impacts, which become more salient as EE portfolios 

reach scale. As in all ratemaking matters, the Commission seeks to maximize the value 

of ratepayer funds invested, and to minimize overall ratepayer impact. The evidence 

that the largest EE program portfolio-that of EAI-can achieve a neukal RIM score 

(0.98, as detaiIed above) in significant part through the first-year implementation of a 

residentid load control program is one indication that portfolio composition can 

reasonably address RIM test cost-effectiveness. The IEM’s recommendations for crossfuel coordination and for program improvements also explicitly aim to yield cost-saving 

efficiencies. Improved data tracking also should enable Parties and the Commission to 

understand whether and to what degree EE programs, over time, are leading to lower 

bills not only for participating ratepayers and for ratepayers in the aggregate, but also 

for the majority of ratepayers. The one-year extension of current EE programs and the 

Potential Study provide an opportunity for all stakeholders to carefulIy consider and to 

develop strategies on ongoing practices that maximize the value of ratepayer investment 

and mitigate ratepayer impacts related to EE portfolios. 
Docket Nos. 13-002-U 

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Further, with regard to AEEC/AGC’s concerns regarding program cost and costeffectiveness, the $334/Mtvh average energy savings cost cited by AEEC/AGC may 

conflate first-year EE program savings with program lifecycle savings.10 The 

$334/MWh average savings cost cited represents total program costs divided by firstyear savings, and not savings over the lifecycle of the program; it thus greatly overstates 

the lifecycle cost of energy saved. Similarly, AEEC/AGC’s summary of EAI’s 

achievement (0.28% of retail sales over four years) appears to omit the persistence of 

any savings from year to year, greatly understating the impact of the ongoing program 

portfolio. 

The Commission accepts JCP’s proposal to review the literature on the comfort 

and health benefits of weatherization and to seek consensus on any recommended, 

reasonably quantifiable, significant NEBs for inclusion in program screening. The 

Commission also accepts Audubon’s well-reasoned guidelines for NEB consideration 

and inclusion, with some modification: Audubon recommends the inclusion of only 

those NEBs that can be quantified with a level of confidence commensurate with 

primary program benefits such as avoided energy costs. Audubon also recommends 

that NEBs should be well-defined in terms of measurably reducing scarce resources; (2) 

have a quantifiable economic value; and (3) be clearly applicable to the specific program 

or measure at issue. The Commission’s modification of the Audubon guidelines is that 

some NEBS should be quantified because they add value or reduce costs, rather than 

because they reduce the use of scarce resources. AIso, while Audubon cautions that 

weatherization should not receive special treatment, the JCP’s proposal to seek 

10 The Commission accepts this number for purposes of discussion only, without exploring whether it is 

appropriately weighted for the different amounts of program savings in different years, whether it takes 

into account capacity avoided, or whether it is otherwise appropriateIy presented. 
Docket Nos. 13-002-U 

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consensus on any reasonably quantifiable, significant NEBs specific to weatherization 

need not vary horn Audubon’s recommendation that NEBs should be well-defined, 

quantifiable, and specific to the program at issue. 

To address concerns by AEEC/AGC, EAI, the AG and others that inclusion of 

NEBs may require ratepayers to fund non-utility service, the Commission clarifies that 

any inclusion of customer NEBs within the TRC is intended to make the primary 

program and portfolio screening tool accurately assess the available EE resource, The 

Commission intends that, at the measure incentive level, ratepayer incentives to 

customers, and thus the ratepayer resources spent to achieve EE savings, would remain 

constrained by utility system avoided costs (Le,, by PACT analysis, which might 

properly include utility NEBs, but not customer NE3s). A TRC test properly including 

NEBs will therefore give program administrators a broader range of EE measures and 

programs from which to select, theoretically enabling lower cost or more comprehensive 

services; but it WiIl not entail customer incentive spending to subsidize individual 

customer NEBS, At the portfolio level, the concern can be met by ensuring that EE 

program portfolios pass both TRC and PACT tests. In this way, both programs and 

portfolios will remain cost effective as compared to alternative resources, while 

retaining the flexibiliw to include auxiliary programs such as training and education, or 

programs aimed at ensuring that all ratepayers have access to EE senices.11 

The Commission does not specify, as mentioned by JCP, that individual measures 

should pass the TRC test, in order to allow for the possibility that combinations of 

measures might reasonably be part of a program that passes TRC. Regarding the 

11 OG&E’s window air-conditioner program or M’s mobile home efficiency program might be examples. 
Docket Nos. 13-002-U 

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Societal Test (which includes societal NEBS), current C&EE rules allow, and the 

Commission continues to accept, voluntary utility submission of the Societal Test for the 

Commission’s consideration in approving EE programs and portfolios. 

Issue 6: Process and Tasks for Continuous Promam Improvement 

Order No. 1 proposed that utilities and other stakeholders should collaborate over 

the next program cycle to develop core EE programs €or each rate class that, insofar as 

possible, have standardized, bansparent features to promote comparability across 

utilities, better understanding and participation by customers, contractors, vendors, and 

trade dies across the state, and increased administrative efficiency and cost savings. 

Order No. 1 at 39. The Commission acknowledged the value of the PWC’s collaborative 

development of proposed rules, ongoing management implementation issues, and role 

in creating and updating the deemed savings values, the TRM and its EMW Protocols, 

and standards for administrative costs and Reporting Needs. Id. at 40. Order No. 1 

proposed to build on these successes through an enhanced Continuous Program 

Improvement Collaborative (“CPI Collaborative”) that, under the leadership of Staff, 

would select and engage a facilitator with extensive experience in the development of 

utility EE programs to manage collaborative resolution of issues, Id. The CoIlaborative 

would take advantage of expert technical assistance, facilitation and procedural reforms 

in order to facilitate stakeholder cooperation and Commission reliance on its results. 

The CPI Collaborative would include the utilities, Staff, the AG, all parties to this docket, 

and any other participants that the Commission might deem appropriate. Procedurally, 

it would aim to reach consensus on each issue addressed, make a record of its decisions 
Docket Nos. 13-002-U 

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for reporting to the Commission, and provide for any dissenting reports to the 

Commission on issues not resolved by the parties. Id. 

The Commission proposed that the CPX Collaborative would address ten 

substantive tasks, developing a core group of statewide EE programs.12 Id, ai 41. The 

CPI Collaborative's consultant(s) would help identify and capture opportunities for 

program improvement and increased statewide coordination and standardization. The 

Commission proposed that the consultants and the facilitator selected should be 

independent of the utilities and other stakeholders, i.e, they should not have financial 

or business interests with any of the stakeholders, and that they should be paid for by 

using a small portion of the total annual energy efficiency budgets, with costs alIocated 

to all utilities using the joint-utility cost allocation methods developed by the utilities for 

the AWP, EEA, and EM&V programs. Id. at 42-43. According to the Commission 

proposal, the consultants should have demonstrated technical expertise in the design, 

planning, implementation, and improvement of EE programs and strong fami1iarit-y 

with best practices in those areas. The Commission stated its view that the CPI 

Collaborative should be the client of the consultants, who are expressly intended to 

perform tasks separate from the consultants and vendors used by the utilities and EE 

program administrators to design, implement, and evaluate their programs and 

12 These tasks were (I) Standardizing and achieving efficiencies in the delivery of whole-house 

weatherization senices; (2) Developing joint-utility EE senices offerings to national accounts customers; 

(3) Eqloring an expanded role in EE planning and implementation for Arkansas Manufacturing 

Solutions YAMS") and the Arkansas Industria1 Energy Clearinghouse ("AIEC"); (4) Increasing 

participation and achieving deeper energy and demand savings in the industrial sector; (5) Improving 

cost-effcctivcness of commercial programs; (6) Making EE programs more consistent across the state; (7) 

Separating new construction EE programs fkom retrofit programs; (8) Strengthening EE program delivery 

methods in order to increase participation; (9) Improving pIanning assumptions so that EE plans better 

reflect likely savings, participation, and cost estimates and (io) Exploring creation of a statewide 

database. 
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separate from the EM&V responsibilities performed by the EM. Order No. 1 indicated 

that the Commission would establish a procedural schedule for the work to be done by 

the CPI CoTlaborative following its review of comments received in response to the 

proposal. Id. at 41-42. Finally, Order No. 1 stated that the CPI Collaborative’s mission 

should be ongoing, with annual reporting of ib findings and recommendations. Id. 

The JCP respond that a new collaborative with a third-party facilitator is not 

needed and that the existing framework, including the EM&V activities and input of the 

IEM, effectively address the development and improvement of EE programs and other 

issues. JCP at 24. The AG agrees with the JCP’s comments, AG I~tial at 21. 

The JCP oppose creation of a duplicate process with additional uazlecessaxlf costs 

and activities. Id, at 25. The JCP recommend instead that the Commission direct the 

PWC to engage third-party consultants as needed, or the PWC may request such 

authorization, including for issues such as program planning, financing, cross-company 

program coordination, and others. Id. at 25 and 33. The JCP present, for example, the 

PWC’s request to hire a consultant to conduct a Potential Study. Id. at 25. 

The JPC note that EM&V activities and planning activities are interrelated and 

should not be separated, and that NAPEE has similarly endorsed the concept that 

EM&V should provide a feedback loop for timely program enhancement. Id. at 25-26, 

The JCP indicate that that the PWC process is already addressing program 

standardization; program cost and NEB issues; incorporation of lessons learned to 

increase consistency, transparency, and comparability among programs; resolving 

differences among stakeholders; strengthening EE program delivery options to increase 

participation; and improving EE program planning assumptions to better reflect likely 
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cost: and energy savings per participant and expected pdcipation. Id. at 30-31. The 

JCP state that the current EM&V activities already support program consistency, 

transparency, and comparability across the state, while preserving the ability of 

individual utilities to design, propose, and implement EE programs that best fit their 

respective customers. Id. at 34. The JCP add that the XOUs currently secure the services 

of experienced national and international consulting firms that develop, design and 

implement “best in class” EE efforts. Id, at 33. 

While the JCP agree that consistency among IOU programs is desirable where 

possible, they indicate that program consistency is not achievable in all sectors of the 

Arkansas market and that it is not practical to offer completely uniform portfolios for 

each utility. Id. The JCP note that many states that began mandating statewide 

programs subsequently modified this stance after realizing that customers are not 

homogeneous from one utility to another. Id. The JCP note that the IOUs continue to 

share best practices to promote program consistency, particularly in the area of home 

weatherization and energy services. Id. at 34-35. 

EAI supports the JCP’s comments and asserts that the utilities should continue to 

determine what programs they will offer to their customers, subject to the Commission’s 

approval, because the utilities are ultimately responsible for achieving the EE goals. EAI 

Initial Comments at 17. If utilities lose control over their programs, states that they 

should be relieved of responsibility for achieving results. Id, at 19. M adds that a new, 

facilitated collaborative process may hamper the abirity to adapt to real-time market 

changes, create market confusion by changing programs and requiring new training, 

conflict with the Cornmission’s Comprehensiveness Checklist (which requires, inter alia, 
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EE senices for all major end-uses of electricity and natural gas), lower the costeffectiveness of programs administered by individual utilities, and stifle innovation. Id. 

at 17-20, EAI notes that the program improvement proposals in Order No. I were 

issued at a time when only partial-year, PY 2011 results were available, and that in 2012 

EAI exceeded EE targets using best practice programs that were planned in conjunction 

with world class consuTtants and expertly implemented. EM at 5 and 21. 

Centerpoint and Staff also agree that, while there is value to program consistency, 

a “one-size-fits-all“ approach to program standardization is “unlikely to be a workable 

model in the State of Arkansas,” Centerpoint Reply at 5, Staff Reply at 7. Centerpoint 

states that the degree of standardization that is appropriate in a rural state bears further 

discussion, parficularly considering the waiver from C&EE Rules granted to rural 

ekctric cooperatives. Centerpoint Reply at 5. 

Sierra CIub states that the proposed enhanced stakeholder collaborative is an 

excellent way to achieve increased standardization and transparency in order to create 

economies of sde in program delivery. Sierra Club at 8. Sierra Club indicates that 

independent, neutral facilitation is important and has worked in Arlm~sas and in other 

states. Id. Sierra Club cautions that, while it supports the creation of statewide, 

standardized programs, utilities need flexibility to meet unique senice categories when 

their customers have very different needs, Id. at 9. 

Audubon notes that the success of collaboration ultimately depends on effective 

communication, consultation, and decision processes that promote a focused effort to 

achieve consensus on major issues and to advance the collaborative planning agenda 

toward the fulfilhent of its stated objectives. Audubon adds that an experienced 
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facilitator can render critical assistance to organize and run effective meetings, facilitate 

group decisions, and create a record of collaborative deliberations and decisions - all of 

which activities can constitute a contixluous program improvement process in which the 

stakeholders and the Commission can place their confidence. Audubon Initial at 10-12. 

Audubon replies to the JCP’s concern that time and expense would be needed for a 

facilitator to become familiar with the unique characteristics of Arkansas EE program 

experience, asserting that the requirement of neutrality does not ide out the 

employment of a facilitator that has direct experience with the Arkansas EE issues. 

Audubon Reply at 7. Audubon maintains, however, that neukality does prohibit the 

assignment of such a role or responsibility to collaborative stakeholders, a party to these 

proceedings, or others who have interests with any of the parties or stakeholders. 

Audubon accordingly proposes that a neutral third party facilitator with previous 

experience in Arkansas be considered as a qualified candidate to assume this 

responsibiliw, but that such experience should not be a prerequisite for consideration. 

Id. See also Sierra CIub Comments at 5, 8 and ACAAA Reply Comments at 1-2. ACM 

agrees with JCP that it is not necessary to fund a new collaborative to promote statewide 

consistency among EE programs and shares their concern regarding the cost and time 

needed to educate a facilitator unfamiliar with the Arkansas EE experience. ACAAA 

Reply at 1. ACAAA states that these views can be reconciled with Audubon’s support for 

an independent facilitator and technical experts by relying on a member of Commission 

advisory staffto facilitate resolution of the issues proposed in Order No. I. The advisory 

staff facilitator would propose agendas, organize meetings, facilitate consensus, and 

ultimately present a proposal on behalf of the collaborative to the Commission without 
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divulging party negotiations or supporting the proposal with testimony. Id. at 2. 

AEEC/AGC is concerned that: the CPI Collaborative would increase costs and 

recommends that any decision to implement: a new collaborative should be deferred 

until its need is further evaluated and cost-justified. AEEClAGC at 11. 

Ruling on Procedure for Continuous Promam Improvement 

The Commission generally agrees with the JCP that a duplicative CPI 

ColIaborative is not necessary to promote increased consistency, coordination, and 

standardization of EE programs, Further, as noted by EAI, PY 2012 program 

performance generally exceeded targets, and program administrators and EM &V 

evaluators are focusing on cross-utility and cross-fuel coordination, achievement of 

deeper savings, standardization of processes, improvement of data collection and 

participant backing, and a host of other program improvement recommendations that 

overlap with many of the objectives outlined in Order No. 1. The Commission also 

acknowledges the JCP’s summary of areas of overlap between the current PWC’s 

activities and the proposals in Order No, I, and EM’S suggestion that a new 

Commission-ordered process could disrupt progress on resolving these issues. 

The record does not indicate, however, how the collaborative is operating with 

respect to the PWC’s schedule, agendas, or methods of building consensus and making 

and/or recording and reporting decisions, For example, it is unclear to the Commission 

whether the AWP and other weatherization issues discussed below are being addressed 

by the full PWC or by a subgroup of the PWC, and whether the collaborative process is 

currently facilitated by Staff, the IEM, the AWP program administrator (the Central 

Arkansas Development Council, “CAD C”) or program coordinator (ACU). Moreover, 
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no evidence was submitted regarding what procedures or practices guide the provision. 

of notice for meetings, information gathering and sharing by parties, and issue 

discussion and resolution. The Commission is under the impression that the IEM 

currently serves as a convener for some purposes and that Staff and/or ACAM does for 

others. 

The Commission also finds that certain issues such as cross-fuel coordination 

(particularly with regard to weatherization) and facilitation of uniform offerings for 

commercial customers-including national accounts customers-should be addressed to 

the fullest extent possible prior to the initiation of the next program cycle, which was 

delayed in part to allotv resolution of these issues. The Commission agrees that each 

utility needs flexibility to address customer segments and utility circumstances unique 

to its territory. The Commission also does not wish to burden the detailed, vital ongoing 

work of the PWC with unnecessary bureaucracy. 

Reasonable uniformiQ in core programs, however-particularly as they appear to 

and affect customers and trade allies-need not conflict with necessary variation in 

program offerings among utility territories. Also, the increased administrative duties of 

faciIitation and increased transparency have value when parties with differing interests 

address a complex, time-sensitive task with significant resources at stake. The 

Commission is not persuaded that such facilitation must be an expensive and timeconsuming undertaking. Further, while a facilitator with exhaustive experience with the 

Arkansas EE landscape would be a strength, a capable facilitator that lacks such 

familiarity might bring the benefit of neutrality, which is typically required in issue 

resolution among parties with different points of view and disparate resources for 
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collaborative participation. Moreover, a skilled facilitator with strong experience in 

energy utility issues should be able to study and prepare in relatively quick course. As 

the PWC embarks on its second three-year cycle, it is evident that it has reached a stage 

of maturity in which a more sophisticated process is necessary to match the objectives of 

providing Arkansas citizens with comprehensive, cost-effective energy efficiency 

programs. 

The Commission agrees with the JCP that d1 FWC meetings do not require 

independent, outside facilitation, and that the PWC may request authorization to engage 

third-party consultants as needed, and that in some cases the Commission should direct 

the PWC to engage facilitation or technical expertise. To that end, the Cornmission 

herein directs that (1) general meetings of the PWC should, nevertheless, follow certain 

basic procedural guidelines led by a facilitator that may be chosen from within the PWG 

and (2) that the specific task of developing a more unified approach to residential 

weatherization should be facilitated either by a member of the IEM's team who is expert 

in weatherization, or by an outside facilitator, with adequate technid expertise 

available to the PWC. These decisions acknowledge the progress of the PWC as reflected 

in advances in program achievement during 2012 and the indications that the PWC wilI 

address program coordination and improvement, as recommended by the IEM. 

The Commission directs the PWC to propose for Commission approval on or 

before noon on January IO, 2014, procedural guidelines to govern meetings and 

deliberations of the PWC. The Commission requests that such guidelines address the 

designation of a facilitator for meetings, notice and development of agendas, the timely 
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provision of information and materials, and the manner in which decisions are made 

and recorded, including the recording of any dissenting opinions. 

The Commission also accepts JCP’s general recommendation that the 

colIaborative may request authorization to hire, or may be directed to hire, facilitation 

or technical expertise as needed with respect to any issues being addressed by the 

colIaborative. In the event that there is no consensus on this point, any party may 

petition the Commission at any time to seek technical assistance or facilitation for the 

collaborative. 

With respect to weatherization, which includes services for not just severely 

energy inefficient homes, but for all residential customers, the Commission provides the 

following procedural directive: The PWC shall identi@ a facilitator to guide 

deliberations concerning the standardization of the existing models of weatherization 

approaches detailed below and coordination of weatherization programs in time for 

implementation during the next three-year EE program cycle, taking into account the 

discussion below regarding existing weatherization programs. The IEM, through a 

person on the IEM’s team with specific expertise in weatherization may serve as the 

weatherization facilitator, or the PWC may identify a person independent of all the 

parties and with expertise in the coordination and delivery of utiIi@-funded and/or 

federally-funded weatherization senices. The PWC shall also ensure that any technical 

expertise necessary to establish best-practice program elements, to maximize the 

leveraging of the resources of the federal WAP program and other potential program 

partners, and to establish financing mechanism[s) that enable customers to implement 

comprehensive whole-house retrofits and to avoid lost opportunities for savings, is 
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made available to the members of the weatherization colIaborative throughout its 

process for timely, in-depth consultation. To provide greater transparency to the 

existing and the enhanced PWC process, the weatherization facilitator shalI folIow the 

procedures enumerated above for all faditation. 

With respect to the utilities’ respective C&I Prescriptive and Custom programs 

the PWC shall, as detailed further below, also develop uniform offerings that allow 

commercial customers-including particularly national accounts customers-to 

transparently access EE services through a single application process across fuels and 

utilities. 

These two taslrs (weatherization and enhanced C&I program standardization), 

along with a third area of exploration (continuing improvement of uniform data 

collection and reporting) - each of which is further outlined below - represent a 

prioritized, simplified consolidation of the ten collaborative agenda items origina1Iy 

proposed in Order No. 1. The Commission adopts this more focused agenda in 

consideration of the evidence in the record that: utilities have made substantial progress 

toward, and that program evahtors and the IEM, through their program improvement 

recommendations are substantially advancing, the same goals that the Commission had 

in making its earlier proposals. 

Given the need to ensure that the objectives of this Order are met with due 

consideration of all the stakeholder positions and with proper Commission oversight of 

the process and the budget that may be required for such purposes, the Commission 

directs utilities and Stafl, and requests other members of the PWC, to submit on or 

before noon on November I, 2013, a plan describing how the PWC would engage a 
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facilitator(s) and other consdtants to assist the PWC in developing a unified 

weatherization approach and weatherization program coordination, and how the PWC 

will address standardization of core C&I programs across fuels and utilities, The plan 

shall describe the PWC collaborative process going forward, including the roles 

performed by Staff, the IEM, and other parties, and a proposed scope of work that 

addresses the enhanced responsibilities outlined above pertaining to the weatherization 

collaborative and that identifies the tasks to be performed by the collaborative for which 

a facilitator and/or consultant are sought. 

Utili&-Funded Weatherization Promams and Services in Arkansas 

In Order No. 1, the Commission proposed that the PWC, or perhaps a subgroup 

of the PWC that has a particular interest in weatherization and building thermal 

envelope issues, should develop a standard approach to whole-house weatherization 

activities that would be followed by all utility programs, and ultimately by a single, 

statewide coordinated utility weatherization program. The Commission stated that this 

approach should dlow trade allies, customers, and the Commission itself to understand 

one set of rules the eligibility and analysis of residential buildings; for the ranking, 

selection, and implementation of covered measures; for rebates and incentives to 

customers and trade allies; and for the training, and qualifications required of 

contractors, and for EM&V activities. 

In addition, the Commission proposed that the FWC explore the development of 

appropriate financing mechanisms for statewide weatherization sewices for both 

residential and small commercial buildings, through exploration of state or federal 

revenue bond financing or otherwise leveraging non-utility program resources as a 
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complement to the ratepayer-funded AWP, The Commission also stated its belief that 

the PWC should convene the program administrators of the AWP program, the 

statewide federally-funded Weatherization Assistance Program for Low-Income 

Customers ((IWAP”), the joint-utility dual-fuel weatherization program offered by OG&E 

and AOG, and the Home Energy Assistance Loan C“HEAL”) Program Partnership 

between Centerpoint and the William J. Clinton Foundation’s Clinton Climate Initiative 

(TCI”), as well as the other utilities and the state’s electric cooperatives, to explore 

these issues. The Commission summarizes below testimony, comments, and other 

evidence in the record regarding these and other utility-funded programs providing 

weatherization services in Arkansas. 

I. The Arkansas Weatherization Program I“AWP”1 

The AWP is a utility-funded program administered by the Central Arkansas 

Development Council (TADC”), a CommuniQ Action Program (YAP”) agency, and 

coordinated by ACAAA. For a home to be eligible for AWP services, it must be buiIt 

prior to 1997 and must be “Severely Energy Inefficient,” based on a checklist of features 

such as inadequate insulation, or a non-working heating system or heating system with 

less than 70% efficiency. AWP Annual Report at 42. 

Since 2007, AWP has weatherized nearly 4,000 homes. ACAAA at 2. AWP 

weatherized 641 homes in 2012-a slight decrease from 2011. Annual Report at 3. 

WAP-eligible customers accounted for d1 but four of these homes. Id. at 4. AWP 

performed 1,047 projects at the 641 homes, which was 61% of its planned target. Id. 

AWP implemented nineteen different types of EE measures, including insulation, 

reduction of infiltration, tune-up or replacement of air conditioners, furnaces, and heat 
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pumps, lighting improvements, water heater insulation and replacements, window 

sealing and replacements, and storm windows. Ceiling insulation and infiItration 

reduction were among the top three sources of savings for both electriciw and natural 

gas. Lighting improvements and refrigerator replacements contributed significantly to 

electricity savings, and window replacements contributed significantly to natural gas 

savings. AWP EM&V Report at 1-5. Because of its connection to the federal WAP, AWP 

provides non-cost-effective heating unit replacements and home repairs that save little 

to no energy.13 

Utilities spent almost $1.2 million on AWP, and federal funds (including 

American Recovery and Reinvestment Act (“ARRA”) funds) contributed about $3 

million. Id. AWP produced over 1.1 million kWh in annual energy savings within IOU 

territories and almost igo,ooo in annual therm savings. Id. at 3-5. AWP also produced 

an estimated 1.8 million kwh of lifecycle (not annual) savings in municipal and electric 

cooperative territories (although these utilities did not participate in program funding). 

Id, at 3-4. Accomplishment of targets within specific IOU territories ranged from a low 

of 30% for SWEPCO to a high of 78% for Centerpoint. Id. at 5. AWP cost effectiveness 

in 2012 ranged from a TRC score of 1.06 to 5.01 among natural gas utilities, and from 

0.31 to 3.65 among elecbic utilities. Table 8.2., Annual EE Report Workbooks. 

The network of WM/AWP providers received nearly 7,000 person-hours of 

training in 2012, resulting in 335 certificates awarded to trainees. Annual Report at 8. 

Taking into account non-AWP WAP homes, this network currently has the capacity to 

weatherize over 2,000 homes per year, Id. at 22. 

13 AWP measures may include replacement of glass and/or windows, doors, ground cover, duct and plenum 

repair, return air cavity sealing, CO detectors, and smoke detectors, some of which may not be cost-effective for 

energy savings. OG&E PY 2012 Annual Report at 47. 
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ACAAA comments that, when AWP was established in 2007, it offered the 

promise of leveraging existing, trained personnel, infrastructure, and funding from the 

federd Weatherization Assistance Program (“WAF’), reaching severely energyinefficient homes, and serving a long waiting list of hard-to-serve homes through a dualfuel, comprehensive approach.14 ACU at 1-2. ACAAA indicates that Am‘s strengths 

include ongoing collaboration among the IOUs and their contractors, CAP agencies, and 

the Arkansas Department of Human Senices (“ADHS”) (until July 1, 2013, the state 

administrator of the WAP), and the ability to provide one point of contact for customers 

across electric and gas utility services. Annual Report at 7. 

ACAAA reports that three major challenges have become apparent. Id. at 2. 

First, Am’s success has proven to be dependent on fluctuating federal funding: the 

number of AWP-weatherized homes fell in 2012 because CAP agencies were required to 

prioritize the spending of ARM funds on the WAP program, and also because federal 

funding declined for the regular WAP funds that provide a match for utility funding for 

WAP-eligible AWP customers. Id. 

Second, AWP has had difficulty in reaching non-WAP eligible customers (who 

might otherwise provide an independent source of program funding). Id. This is 

because their incomes exceed the WAP eligibility limit (200 percent of the Federal 

Poverty Level) and thus do not qualify for federal funds to pay the $1500 co-pay to cover 

AWP weatherization services. Many of these customers are working-poor or near-poor 

and thus lack the resources to cover the co-pay costs. Id. Third, AWP has experienced 

The current DOE WAP waiting list is over 3,000, many of which likely arc eJible for AWP. AWP 

Annual Report at 22. Some CAP agencies report that they have stopped promoting the program or are no 

longer referring customers to WAF because customers become un-interested in the program when thcy 

learn about the wait time. AW EM&V Report at 3-5. 
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geographic gaps in service delivery because, under the WAP program individual CAP 

agencies can opt not to provide services within their territories (and some have done so). 

Id. 

ACAAA notes that the Arkansas General Assembly in 2013 enacted Act 1111, 

which authorizes the transfer of the WAP program from ADHS to the Arkansas Energy 

Office (,,AEO”). ACU reports that AEO is restructuring WAP to include the Clinton 

CIimate Initiative’s (TCI”) Home Energy Affordability Loan (“HEAL”) program in an 

as-yet-to-be-determined role, and to involve the PWC in determining a new WAP 

program design, Id, ACAAA agrees with AEO that the existing AWP Collaborative 

should discuss restructuring of WAP and AWP, Id. at 3. ACM indicates that the 

transfer and restructuring of WAP should allow modifications that can enhance 

program delivery for both WAP and AWP. AWP Annual Report at 7. Given the 

uncertainty facing WAP and AWP, ACAAA. recommends no specific changes for PY 2013 

for AWP, but reports that CCI has recommended that HEAL should have access to AWP 

funding for the remainder of 2013 in order to offer services within under-subscribed 

parts of the state. Id. 

ADM evaluated Am‘s 2012 activities. ADM agrees that dependence on federal 

funding and the ability of individual CAP agencies to decide their level of involvement in 

WAP have been AWF program barriers, and that decreased federal funding could be a 

greater barrier in the future. AWP EM&V Report at 1-5 through 1-6. ADM also agrees 

that financing and marketing issues hamper AWP’s ability to serve non-WAP eligible 

customers. ADM finds that AWP will likely be unable to attract many non-WAP-eligible 

customers without addressing the upfiont cost barrier presented by the co-pay 
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requirement, Id, at 1-7. ADM adds that the WAP waiting list is a barrier to AWP 

performance, and that the association between AWP and WAP creates confusion 

requiring new marketing approaches if AWP is to reach out to non-WAP-eligible 

customers. Id, at 1-7 and 3-2, ADM notes further that, while measures are installed for 

WAP customers based on cost-effectiveness, AWP customers may choose which 

measures to instalI, creating the risk that customer choices will erode the costeffectiveness enjoyed by WAP. Id. at 1-9. ADM cites the comprehensiveness of AWP 

whole-house offerings as a strength. Id. at 1-6 and 2-2 at Table 2-1. ADM’s interviews 

with CAP agency staff suggest that, while the current collaborative structure is sufficient 

for operating the program as it is currently designed, it would be difficult for it to 

produce agreement in a timely fashion among all involved parkies on specific program 

improvements. Id. at 3-7. 

II. The Home Enerm Assistance Loan ?‘HEAL’’) Promam 

The HEAL program is administered by the Clinton Climate Initiative and is a part 

of the Centerpoint Energy Arkansas’s Bnergy Eficiency Program PorvoIio. Large 

employers with a minimum number of low-to-moderate income employees receive a 

free audit and complete energy efficiency retrofits to their facilities. The employer then 

makes fuxlds generated by energy efficiency savings available to its employees. 

Alternatively, an employer works with commercial pmers such as credit unions to 

provide Tow- or no-interest loans to employees to retrofit their homes. Centerpoint 

AnnuaI Report at 12 and Appendix A at 11-1. In some cases, NEAL may offer the 

program to non-emplops living in neighborhoods adjacent to participating employers, 

Id, at 12. Employees receive a free home energy audit, including a blower-door test and 
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duct blaster. Loans to employees for EE measures are repaid through payroll 

deductions. Id. 

Centerpoint’s HEAL program began in mid-2011 and installed 217 measures at 75 

homes in PY 2012. Id. While there is no income restriction on program participation, 

HEAL, is largely limited to participating employers. Id. at 12 and 14. HEAL produced 

annual savings of 19,636 therms in PY 2012 and had a TRC cost effectiveness of 2.80. 

HEAL achieved these savings through three measures: air sealing, ceiling insulation, 

and duct repair. Id., Appendix A, at: 11-6.15 

ADM evaluated the HEAL program and found that, although it is a very small 

portion of Centerpoint’s overall EE portfolio, it could provide a model going forward for 

cross-fuel services and customer financing. Centerpoint Annual Report for PY 2012, 

Appendix A at 1-6. ADM notes that, while CCI frequently obtains both Centerpoint and 

EAI incentives for HEAL customers, there is litkle cross-utility coordination between 

Centerpoint and Entergy and as a result, some parlicipants may be receiving retrofits at 

no cost when incenthized by both utilities. Id. at 11-5. ADM also indicates that, other 

than for that limited number of customers eligible for and served by HW, Centerpoint 

lacks residential building envelope rebates. ADM recommends that 

Centerpoint make such rebates available more broadly, citing the successful example of 

the OG&E/AOG joint weatherization program. Id. 

Id. at 3-3. 

15 The Commission notes that electricity savings for those Centerpoint HEAL customers who also are IOU 

electric customers presumably are included in the reporting for electric utility EE residential programs, to 

the degree that HEAL assembled natural gas and eIectric rebates for the customer to achieve these 

savings . 
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111. The AOG/OG&E Weatherization Prosam 

The AOG/OG&E Weatherization Program rl lint Weatherization Program,” or 

“Program”) is a cooperative program funded by both utilities. To be eligible for 

weatherization, the structure must show that it has “substantial energy efficiency needs” 

by requiring three of seven listed weatherization measures in order to receive sentices. 

ADM Evaluation of Joint Weatherization Program (“Joint Evaluation”) at 1-1. The 

auditors for this program are certified by the Building Performance Institute or the 

Residential Energy Services Network (“RESNET”). OG&E Annual Report at 15. The 

total utility contribution (from both utilities combined) is limited to $3,000 per eligible 

customer, with no out-of-pocket costs required of the customer. Joint Evaluation at 3-1. 

The Program served a total of 1,631 OGM homes (7% of the homes in OG&E’s 

Arkansas territory] axld 1,360 AOG homes in 2012. OG&E Annual Report: at 6 and Joint 

Evaluation at 1-4. It produced 3.6 million kwb in mud electricity savings and 0.2 

million therms in annual natural gas savings. Joint Evaluation at 1-4. Three highlycost-effective measures (air infiltration reductions, ceiling insulation, and CFLs) 

accounted for almost all of the program’s gross energy savings. Joint Evaluation at 2-3. 

The Program also covers water heater jackets and pipe wrap, and occasionally provides 

refrigerator replacement. Id. at 1-4. For instance, while 1,387 OG&E customers 

received ceiling insulation, only 158 received refrigerator replacements. Id. at 5-8. 

ADM notes that despite limited marketing, the Program has high customer 

awareness, participation, and satisfaction, with several hundred customers per month 

seeking sentices. Id. at 3-3 and 3-5. ADM finds that word-of-mouth marketing, the 
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Program’s short wait time, and its high incentive levels account for the high level of 

customer participation, ADM Evduation at 3-3 through 3-5. 

Program conbactors indicated to ADM that the majority of participant homes 

would benefit from further energy efficiency improvements that are not covered by 

Program offerings. Id at 3-6. However, the contractors expressed concern that the 

further improvements might not be adequately cost-effective. Id. Some customers 

expressed interest in paying for further improvements, but did not foIlow through due to 

the cost. Id. at 3-5. ADM recommends that OG&E and AOG explore offering further 

services such as wall insulation or heating system improvements and explore opening 

the program gradually to a larger pool of homes than those meeting the current criteria. 

Id. ai 1-7. 

IV. Other EE ProErams ProvidinE Weatherization Services. 

Under M’s Home Energy Solutions (,,HES’’) program, customers may seek an 

energy audit through the program to learn about potential EE improvements, or may 

directly contact a contractor if they are aware of their needs. EAI Annual Report at 26. 

HES offers incentives for energy audits, direct-install measures such as faucet aerators 

and low-flow showerheads, ceiling and wall insulation, infiltration reduction, duct 

sealing, and replacement of WAC equipment. Id. at 30. In order to promote 

comprehensive home EE improvements, EAI provides a bonus incentive to customers 

who choose to implement multiple measures. Id. at 26-27. Customers installing 

multiple measures increased from 9% in PY 2011 to 23% in PY 2012. For testingintensive measures such as duct and air sealing and wall insulation, 14% of participants 

who had an energy assessment in PY 2012 adopted these measures, as opposed to 7% in 
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2011. Id. Implementation contractors also may receive a bonus for installing multiple 

measures. Id. at 27. 

Just over 350 customers ordered an assessment in 2012. Id. This constitutes 

0.64% of M’s 584,559 residential customers. EAI FERC Form 1 Supplement Annual 

Report for 2012 at E-I. Of those, 38% (138) installed at least one measure and 72% of 

that subset (loo) instalIed two or more measures. EAI Annual Report at 27. EM notes 

that some HES customers were also CenterPoint HEAL customers. HEM, performed 

157 assessments, of which 32% (50) installed at least one measure and 66% of those 

(33) installed two or more measures. Id. at 27-28. 

HES achieved over 3.2 million kwh in net annual savings in PY 2012, which was 

101% of its goal. Id. at 28. In 2013, EAI plans to require all participating contractors to 

have at least a BPI-Building Analyst or RESNET Home Energy Rater Certification 

(except that insulation-only con*actors may have appropriate certifications from 

Pulaski Technical College or BPI), and to grow its contractor network to include out-ofstate firms. EAI also plans to use more mass marketing to raise customer awareness, 

and to implement 25 recommendations by its independent evaluator, Cadmus. Id. at 

29-30, 

Cadmus found that HES served 1,970 homes with either direct install measures, 

rebated measures, or both, EM EM&V Report at 70. (The Commission does not discern 

how many of the 1,970 homes were served only with direct install measures and how 

many received more comprehensive services.) Approximately 82% of kwh savings from 

rebated measures in PY 2012 derived from ceiling insulation. Id. at 62. Duct sealing, 

heat pump replacement, and air sealing accounted for 8%, 3%, and 3% of rebated lcwh 
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savings, respectively; direct-instal1 measures as a whole produced lower total kWh 

savings than these individual rebated measures. Id. at 62-63. 

SWEPCO offers customers a Residential Standard Offer Program (“MOP”) and a 

Home Performance with Energy Star rHPwES”) Program. RESOP pays incentives to 

customers and to conbactors for insulation, infiltration reduction, duct sealing, AC 

tune-up, ENERGY STAR windows, window film, and replacement of central air 

conditioners and heat pumps. SWEPCO Annual Report at 36. RSOP completed 545 

projects (aside from direct install measures targeted through the same program to 

multi-family housing). Id. at 39. This constitutes 0.56% of SWEPCO’s 95,979 

residential customers in 2012. SWEPCO FERC Form 1 Annual Report at E-1. Among 

non-direct-install customers and measures, ceiling insulation at 348 homes provided 

the vast majority of energy savings, followed by 39 heat pump replacements and 75 

central air conditioner replacements. SWEPCO EM&V Report at 96. 

HPwES, which SWEPCO launched in the Spring of 2012, is a US DOE and EPAbacked, whole-house program that begins with a comprehensive home energy audit. 

SWEPCO Annud Report at 40. The program covers similar measures to the RSOP, but 

also promotes the comprehensive energy audit, contingent upon installation of at least 

two major measures, Id. at 41. HPwES offers enhanced incentives compared to the 

RSOP for installation of major measures such as insulation and €WAC replacement. Id. 

at 41. After having only two HPtvES participants in 2012, SWEPCO began in December 

2012 to partner with HEAL to deliver HPtvES services; 14 of 20 audited by HEAL homes 

installed measures in early 2013. Id. SWEPCO reports that, despite extensive 

marketing efforts, HPwES participation was constrained by low customer awareness, 
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challenging market conditions, and limited contractor engagement. Id. at 43. SWEPCO 

also reports that: many contractors are unfamiliar with building-science-based 

efficiency. Id, SWEPCO is discussing joint implementation of HPwES with various gas 

utilities. Id. at 4. 

According to SWEPCO's evaluator, Cadmus, a large percentage of SWEPCO 

customers cannot afford to make significant purchase or repairs to increase home 

energy efficiency, and approximately one third of these may be eligible for WAP, 

SWEPCO EM&V Report at 112. SWEPCO is reportedly considering offering home 

improvement loans as one way to remove financial barriers to participation. Id. 

RulinE Regarding Weatherization Collaborative 

Since 2007, weatherization program administrators in Arkansas have innovated 

to meet the considerable challenges inherent in seeking to provide comprehensive, 

whole-house EE senices. These challenges have included creating an educated and 

trained contractor sector; educating consumers; keeping program offerings costeffective and within budget; tracking projects, customers, and energy savings; delivering 

services in various overlapping or non-contiguous territories; accounting for 

administrative and marketing costs (whether for an individual utility or across utilities) 

and helping customers address the cost of home improvement, The Commission salutes 

the effort and accompIishment to date and finds that it is time to consolidate lessons 

learned so far. 

AWP offers the longest track record of cross-fuel energy savings and the most 

comprehensive services, but its abiIity to deliver within any particular year is strongly 

influenced by federal rules and funding affecting WAP. WhiIe AWP has allowed WAP to 
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sene a larger number of WAP-eligible customers, AWP has been largely unable to reach 

beyond this core market, although senice to other customers might reduce its 

dependence on federal funds. Also, a variety of constraints have limited Am’s ability to 

deliver senices on behalf of utilities, thereby negatively affecting the expected 

performance of utility portfoTios in some cases. The variation in AWP performance 

among utiliv territories demonstrates both the challenges involved in funding services 

through CAP agencies that may decide not to participate, and also the strong costeffectiveness that can result when implementation runs more smoothly. 

The original AWP goals of leveraging federal funding and trained personnel, 

providing comprehensive whole-house semices across fuels, ensuring the participation 

of low-income customers in ratepayer-funded services, and targeting severely energyinefficient sbwtures remain valid. Experience has shown, however, that these goals 

cannot be fully realized without further colIaboration and program development. While 

the Commission does not regulate WAP, ratepayers have a strong stake in WM’s 

improved operation because AWP cannot reach its goals so long as it merely 

“piggybacks” on the federal program. Rather, AWP stakeholders should take the 

opporhmity of WAP reorganization to contribute to the coordination of WAP with AWP 

so that the state plan for WAP provides as much flexibility under federal regulation as 

possible in order to enable the achievement of joint WAP, utiliw, and AWP goals, 

Technical expertise regarding ways to achieve regulatory flexibility and to build a joint 

AW-WAP structure that can address the WAP waiting list and reach out to non-WAP 

eligible customers must be a part of that ColTaborative effort. 
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The AOG/OG&E Joint Weatherization Program has demonstrated an ability to 

coordinate utility efforts across fuels, and to weatherize a significant percentage of 

customers‘ homes within a short period of time, It minimizes marketing costs and 

maintains a pipeline of projects, in part because it shares with WAP the characteristic 

that a certain level of highly-cost-effective, core senices are free to the customer. As 

with AWP, it offers the largely unrealized opportunity to provide additional costeffective measures. Its implementation contractors report customer interest in these 

further measures, but note that customers are unlikely to implement them so long as the 

initial cost is unmanageable for them. 

The HEAL program is short in numbers (perhaps due to budgetary consbaints), 

but by combining electric and gas rebates for some customers, it appears to achieve 

something similar to WAP and to the OG&E/AOG program: free, or near-free 

weatherization services for the most cost-effective measures. Early results in SWEPCO 

territory suggest that this approach increases the rate at which the administrative costs 

spent on comprehensive audits are converted to cost-effective, multi-measure projects. 

Furthermore, HEAL appears to offer a model for customer financing of more 

comprehensive projects, at least for that portion of customers who may have access to 

payroll deduction for loan re-payment. It is clear that HEAL has so far been made 

available only to a small portion of CenterPoint’s (and EAI’s) customer base. 

By virtue of EAI’s large customer base, the HES program has developed the 

essential market of auditors and implementation contractors in a way that no other 

utility could. It exceeded energy savings goals on only 75% of budget, and offers a 

rebate structure designed to inceniivize more comprehensive projects, which may be 
Docket Nos. 13-002-U 

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gaining traction, although not all of the evidence is clear on this at this stage of 

implementation. For instance, per-house annual savings appears to be significantly 

greater for the OG&E program than for HES (2231 kWh per home vs. 1629 kWh), 

although EAI obtains greater peak savings per home and simiIar energy lifetime savings. 

EM may be less IikeIy to capture infiltration savings (based on the fact that only 3% of 

HES program savings derive from infiltration, as opposed to 14% for OG&E), but HES 

achieves air-conditioner and heat pump replacement savings not covered by the OG&E 

program. While each program had similar TRC scores (1.57 and 1.47), the levelized cost 

of HES savings in 2012 was g cents per lWh and that for OG&E weatherization was just 

above 2 cents. 

While these kinds of differences are subject to variation from year to year as 

programs develop, they provide evidence that lessons from each program can be 

consolidated to form a more optimal unified program. Also, the fact that the number of 

homes weatherized, the number and me of measures implemented at each home, the 

amount of electricity and the natural gas saved per home based on specific measures, 

and the ratepayer-funded cost per home and per measure cannot easily be compared 

among utility territories (except to some degree for AWP and the OG&E/AOG program) 

on the basis of the same metria, is one strong indication that further standardization 

would benefit all ratepayers. 

Based on this review, the Commission refines its original proposal and directs the 

utiIities and Staff, and requests the PWC in general, to collaboratively develop uniform 

whole house program offerings for dI residential customers, including those in severely 
Docket Nos. 13-002-U 

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energy inefficient homes, for implementation by January, 2015 that include the 

following elements: 

I. Joint funding between electric and natural gas utilities of whole 

house energy assessment and energy efficiency services that are available 

to customers, to the fulI extent that elecbic and natural gas utility 

territories overlap, and with uniform offerings to all-electric IOU 

customers in non-gas areas, and to natural gas customers within 

municipal and elemic cooperative territories. The jointly-funded program 

should particularly address any first costs for comprehensive auditing and 

should provide unified incentives and services for measures that benefit 

both heating and cooling applications, thereby reducing the overall 

administrative cost for implementation of measures where the costs can be 

reasonably allocated between the gas and electric utilities, The PWC 

should carefully consider the value of an approach that offers major, costeffective services such as insulation and idhation reduction and 

potentially other services-up to some initial dollar amount, for little or no 

upfront cost to the customer. 

2. A comprehensive technical standard that governs the 

qualification and energy assessment of homes, the recommendation and 

selection of measures, and the implementation of measures performed by 

all utility-sponsored and government-funded energy efficiency programs. 

This technical standard should ensure high-quality, best-practice work 

that maximizes available savings and avoids lost opportunities to improve 
Docket Nos. 13-002-U 

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homes and equipment, It also should include a single set of standards for 

education, training, certification, and continuing education of 

implementation personnel delivering IOU-funded programs, and should 

be coordinated to the fullest extent possible with the standards that apply 

to federally-funded weatherization services, 

3. A proposal by the PWC for the provision of a financing 

mechanism or mechanisms by utilities, or the facilitation of a financing 

mechanism or mechanisms through non-utility parties that dlow 

customers to finance any measures with significant costs that go beyond 

initial no-cost measures and to thereby implement multiple cost-effective 

measures, in effect allowing the customer to implement a multiplemeasure, cost-effective energy plan to substantially reduce whole-house 

energy use. Based on the apparent success of the HEAL model, the 

Commission favors financing options that feature automatic repayment 

through payroll or utility colledion (regardless of whether the utili@ 

actually finances the measures). The Commission requests that the PWC 

assess the extent to which HEAL’S financing mechanism could be extended 

to and would likely be implemented by employees of state agencies and 

other employers who may be willing to adopt its payroll collection method. 

The financing mechanism should, inter alia, enable non-low-income 

residential utility customers to obtain or afford the “good funds” required 

to participate in the AWP; 
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4. The elimination of duplication in programs that would prevent 

implementation contractors and wade allies from searnksdy providing 

services across participating utility territories, or that might engender 

confusion among customers. 

5. Active participation in the reorganization of WAP to optimize its 

coordination with utilityfunded weatherization services, and coordination 

of utility-funded whole house weatherization services with WAP so as to 

leverage available personnel and federal funding. 

6. A plan to effectively market joint-utility weatherization services, 

as appropriate to the various sub-sectors of residentid customers and 

markets, including exploration of the marketing aspects of the HEAL 

Program model. 

The weatherization collaborative shdl file in this docket a report on or before 

noon on April 1, 2014, which includes its recommendations for implementation by 

January 1,2015, of the statewide weatherization program meeting these requirements. 

RulinE Rwarding Joint-Utility EE Services Offerings to Commercial and National 

Accounts Customers 

During the 2012 hearing to review OG&E’s EECR, OG&E Witness Billy Dean 

Pollock testified that there is merit to working out a national chain program with the 

other utilities because all of the utilities confront the same barriers when they address 

big-box store managers who often lack decisional and budget authority to sign up for EE 

programs. Docket No. o7-075-TF, June 14, 2012, Tr, at 118. Only the JCP commented 

on the Commission’s proposal that the PWC should focus on this task, in that it included 

“Focus on National Accounts” as a proposed new requirement: for the collaborative. 
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However, the JCP did not comment on its importance or how it might be accomplished. 

Joint Comments at 27, Table 1. 

Given the lack of objection to this task, the Commission directs the PWC to 

develop a joint, cross-utility and cross-fuel program to submit in time for 

implementation on or before January I, 2015, that provides energy auditing, technical 

assistance, prescriptive measure (including lighting, WAC, building thermal envelope, 

refrigeration, and other common end uses), custom measure, and marketing provisions 

that are appropriate for the end-uses represented by national accounts customers in 

Arkansas.16 Such offerings need not represent a separate national accounts program per 

se, but should give national accounts customers a single pathway for participation in the 

C&I programs of all Arkansas IOUs. Such offerings should thereby avoid program 

overlap and duplication, reduce confusion over programme names, standardize 

elements offered measures, rebates and services, and facilitate marketing to these 

customers. The development of these uniform offerings shall be responsive to the many 

recommendations for C&I program improvement of the evaluators and of the IEM. 

Utilities need not and should not abandon cost-effective EE services appropriate to 

commercial sectors that are uniquely important in their individual territories, but 

rather, may and should provide such sewices additionalIy to the core offerings, as 

appropriate within their EE program porkfolios, In order to develop these offerings, the 

PWC may hire facilitation and technical expertise as needed for this task, and shall 

16 The Commission takes administrative notice that the U. S. Department of Energy‘s Building 

Technologies Office has, subsequent to the initiation of this proceeding, launched an Advanced Rooftop 

Unit (“RTU”) Campaign to address the air conditioners used in 60% of commercial buildings nationally, 

which might provide a model or supporting technical information for one aspect of service to national 

accounts customers. 
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submit any request for budgetary resource needed to accomplish this task as an addition 

to the weatherization collaborative filing on or before noon on November I, 2013. 

RulinE Regarding exploring the Benefits and Challenges Involved in Establishing and 

Maintaining a Statewide EE Database with Enhanced Tracking 

of Promam Participation 

Order No. I requested comment on the development of a statewide database that 

would consolidate of all EE planning and achievement data, particularly including unduplicated, cumulative data for customer participation and for program and measure 

impacts and costs. The proposed database would be publicly available on the internet, 

and would allow a user to aggregate and manipulate the data using standard data base 

queries and searches, and to produce a variety of reports in formats dictated by the user. 

The database would facilitate information sharing among utilities and comparison and 

review by all parties. Order at 63-64. 

The JCP states that it does not support creation of such a database at this time. 

JCP at 31. No party comments on any of the specific parameters outlined above, and no 

party comments in direct support of the Commission proposal. The JCP, the utilities, 

and AEEClAGC argue that it would be duplicative of ongoing efforts, costly, and time 

consuming. JCP Initial at 31-33; AEEC/AGC Initial at 12; EAI Initial at 20-21. The JCP 

detail a series of tasks that would be necessary to implement a statewide database and 

conclude that it would take 12 to 18 months, JCP at 32. AEEC/AGC comment regarding 

customer privacy that the only information that could be provided to the data base 

would be usage information in the aggregate by customer class. AEEClAGC Reply at 12, 

21. 
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The Commission clarifies that assembly of the database might start with 

information that is currently presented in the EE Plans, the Annual Repork and 

Workbooks, and the EM&V reports of the evaluators and the IEM, such as program 

implementation costs, broken out by categories of costs; energy and capacity savings; 

benefits; net benefits; benefit-cost ratios; customer participation and participation rates. 

With refinement, it might allow useful metria such as energy savings, the cost to save a 

unit of energy, and costs per participant, to be calculated across programs, across 

utilities, and over time, and to be aggregated in a non-duplicative manner. The 

development of such capabilities could enhance program review and improvement and 

facilitate evaluation of how many ratepayers benefit directly from programs over time. 

The Commission notes that much of this data is already collected, in utilityspecific form, as part of the Energy Efficiency Standardized Annual Report Packet 

(,,SARP”) approved by the Commission in Docket No. io-010-U on September 14,2012. 

On November 19, 2012, the PWC filed in that docket, and the Commission granted by 

Order No. 15, a motion requesting that the PWC be given until September 27,2013, to 

file comments and/or testimony in support of any proposed changes to the SARP. 

Given that those comments may reasonably address some of the Commission’s concerns 

regarding program comparability, enhanced analfical value, and non-duplicated 

participant tracking, the Commission defers further ruling on this issue until &er the 

imminent SARP filing. 

Finally, AEEClAGC requested that the Commission initiate a rulemalcing to enact 

new rules consistent with the provisions of Act 253 of 2013 and encouraged the 

Commission to decrease the peak demand requirements for a non-residential business 
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consumer to opt-out of utility energy efficiency programs to an electrical demand of at 

least 200 kW at: a single facility+ AEEClAGC Reply Comments at 9. Staff responded 

that the Self-Direct (SD) Rules are not part of the issues identified by the Commission in 

Order No. 1, noting that the SD Rules were developed in Docket No, io-101-R and 

approved by Commission Order No. io and subsequently modified by Order No. 28. 

Staff asserts, and the Commission agrees, that this docket is not the appropriate 

proceeding in which to address modifications to the SD Rules. Staff Reply at 4. On July 

8,2013, by Order No. 29 in Docket No. IO-IOI-R, the Commission directed Staff to file 

proposed amendments to the Commission’s C&EE Rules as they pertain to SD programs 

to comply With Act 253 of 2013. 

Accordingly, based on the comments and evidence in this docket, the 

Commission directs and orders: 

1. That the programs, portfolios; and tariffs of individual utilities will 

continue to be considered within individual utility tariff dockets; provided 

that cross-cutting issues may be addressed, as needed, in separate policy 

dockets; and that filings related to EE programs, portfolios and tariffs shall 

conform to the JCP’s proposed schedule (as displayed on page 3 of this 

Order); provided that the Commission will strive to approve portfolios by 

September 1 of each year, but reserves the right to extend that deadline as 

necessary; and that Staff shall file, on or before noon of January io, 2014, 

any proposed changes to the C&EE Rules necessary to effectuate this 

amended filing schedule. 
Docket Nos. 13-002-U 

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Page 87 of 91 

2. That the PWC may and shall cause to be performed an EE Potential 

Study, jointly funded by the utilities; provided that an RFP and testimony 

describing the study and its purposes, in accordance with the more 

detailed directives outlined above, shall be filed in this Docket for 

Commission review and approval on or before noon on November I, 2013; 

and that the energy savings goal for 2015 is established at 0.90% of 2014 

retail kwh sales for electric utilities and 0.50% of 20x4 retail natural gas 

sales for natural gas utilities, with the Commission reserving the right to 

revisit the 2015 target at the time that it establishes targets for 2016 and 

2017, based upon the Potential Study or other data that may become 

available 

3. That the utility performance incentive shall be awarded in a linear, 

rather than stepwise basis, within a range from achievement of 80% to 

EO% of the Commission's established goals; annual performance 

incentive earnings shall be based on io% of program net benefits, but shall 

be capped on a sliding scale between 4% and 8% of approved program 

budgets, as described in the ruling under Issue 3 in this Order. 

4. That the development and application of utility avoided costs for 

the purposes of EE program and portfolio screening and approval and 

performance incentive calculation shall follow tbe guidance established in 

the ruling on Issue 4 in this Order; and that the PWC shall consider and 

recommend, as part of the testimony supporting the proposed EE 

Potential Study RFP, the adoption of a reasonable third-party estimate of 
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the cost of compliance with carbon regulation; and that, for the purpose of 

calculating any utility EE performance incentive, the approved avoided 

cost component of net benefits shall be fixed during the three-year 2015- 

2017 EE program cyde. 

5. That utilities shall continue to submit the TRC, RIM, PACT, and PT 

tests for consideration, as currently provided in the C&EE Rules; and that 

the Commission will continue to evaluate approval of portfolios and 

programs primarily based upon the TRC test, retaining the flexibiliw to 

include measures and programs that individually do not pass the TRC test; 

and that the TRC test shall include well-defined NEBs which (a) 

measurably reduce scarce resources, add significant value or reduce costs; 

(b) have a quantifiable economic value; and (c) are clearly applicable to the 

specific program or measure at: issue; provided that the PWC shall review 

the literature on the non-energy benefits of weatherization services and 

seek consensus on any reasonably quantifiable, significant NEBs for 

inclusion in program screening for the 2015-2017 EE program cycle; the 

Commission, however, constrains the amount of customer rebate or 

incentives provided at the level of a measure (or group of measures) to an 

amount equal to the utility's avoided cost, 

6. 

improvement: 

That with respect to procedures for continuous EE program 

a. the PWC may request authorization to engage third-party 

facilitation or technical consultants as needed to address issues; 
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Page 89 of 91 

b. in some instances the Commission may direct the PWC to 

engage facilitation or technical expertise. 

c. meetings of the PWC, whether facilitated by a Party, the IEM, or 

an outside facilitator, shall follow procedural guidelines proposed 

by the PWC and approved by the Commission; 

d. the specific task of developing a more unified approach to 

residentid weatherization shalI be facilitated by either a member of 

the IEM’s team who is expert in weatherization, or by an outside 

facilitator, with adequate technical expertise available to the PWC; 

and 

e. the cost of facilitation and technical consultants shdl be 

allocated to all utilities using the joint-utility cost allocation 

methods developed by the utilities for other EE programs such as 

the AWP. 

7. That, with respect to weatherization services for residential customers, 

the facilitator identified by the PWC shall guide deliberations concerning 

the standardization of existing weatherization approaches in Arkansas and 

the coordination of such programs in time for implementation during the 

next three-year EE program cycle. 

8. That, with respect to the utilities’ Commercial and Industrial 

Prescriptive and Custom programs, the PWC shall develop uniform 

offerings that allow commercial customers, including national accounts 
Docket Nos. 13-002-U 

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Page 90 of gi 

customers, to transparently access EE services through a single application 

process across fuels and utilities. 

9. That the utilities and Staff, with the participation of the other members 

of the PWC, shall submit on or before noon on November I, 2013, a plan 

describing how the PWC would engage a facilitator(s) and other 

consultants to assist the PWC in developing a unified weatherization 

approach and weatherization program coordination as described in this 

Order, and how the PWC will address standardization of core C&I 

programs across fuels and utilities. 

io. That the PWC shall file on or before noon of January io, 2014, a 

proposed general collaborative process going forward, in accordance with 

the ruling in Issue 6 of this Order. 

11. That the weatherization collaborative shall file in this docket a report 

on or before noon on April I, 2014, which includes its recommendations 

for implementation by January 1, 2015, of the statewide weatherization 

programs meeting the requirements of this Order. 

12. That, regarding the Commission’s proposal to require development of 

a statewide database consolidating all EE planning and achievement data, 

the Commission defers a ruling pending the PWC filing on September 27, 

2013, of the updated EE SARP. 
Docket Nos. 13-002-U 

Order No. 7 

Page 91 of 91 

BY ORDER OF THE COMMISSION, 

This q'day of September, 2013. 

Colette D. Honorable, Chairman 

Oh W. Reeves, Commissioner 

Elana C. Wills, Commissioner 

D& 

hsti mude, Secretary of the Commission