AARP White Paper Analysis of Xcel Proposals

Prepared for AARP, November 28, 2016

I. EXECUTIVE SUMMARY AND RECOMMENDATIONS

In a filing with the Colorado Public Utilities Commission in May 2016, the Public Service Co. of Colorado (Public Service) 2 stated that they are "hearing from our customers, communities, and legislators that they want more. They want more than the reliable and safe service we have been providing. They want more than us just complying with the renewable goals set by our state." Referring to a compilation of proceedings and initiatives, Public Service refers to these regulatory objectives as "Our Energy Future." The Company "invites" customers to "imagine a day when utility customers have more control over their energy and can design a plan that best suits their needs." 3

Unfortunately, Public Service’s proposals, for the most part, consist of an agenda designed to impose significant costs on ratepayers and implement rate design and ratemaking policies that are not in the best interest of residential ratepayers and their families. Most important, at no point in "hearing" from customers has Public Service clearly identified the cumulative bill impacts from these proposals and asked customers if they are willing to pay for these predicted and unsupported future benefits. These filings are replete with calls for immediate recovery of costs, but do not include any performance standards to ensure that the predicted benefits will occur. Under Public’s Service’s vision, ratepayers would bear all the risks that predicted benefits would incur while the Company’s shareholders would be assured that costs and a rate of return would be included in rates.

As a result of the analysis of pending proposals for new rate design pilots that will be implemented between 2017 and 2022, the flawed analysis submitted for the AMI and other grid investments, and the poor public policy represented by its proposed Decoupling Revenue Adjustment, the Commission should take the following actions:

Ensure that the evaluation of the newly approved Time of Use and Demand Rate pilots will include performance standards and verifiable and statistically valid results that are meaningful for the implementation of system wide pricing plans, an analysis that will be difficult in light of certain structural and incentive design features of these two pilot programs.

Reject the proposal to deploy Advanced Metering on the grounds that the proposal is premature and should be considered after the implementation and evaluation of the rate design pilot programs and identify the flawed benefit categories and methodologies that should not be relied upon for any further proposal for AMI.

Reject the Volt-Var proposal and order Public Service to install distribution-based Conservation Voltage Reduction technologies in the normal course without regard to AMI deployment and treat cost-effective Voltage Reduction investments pursuant to current efficiency program cost effectiveness policies and cost recovery methodologies.

Reject Public Service’s proposal for a Decoupling Mechanism applicable to residential and small commercial customers on the grounds that it is poor public policy, likely to be duplicative of the current revenue adjustment mechanism applicable to efficiency and demand response programs, and fails to send the proper price signal to customers about the value of usage reduction.

II. WHAT IS PUBLIC SERVICE’S "OUR ENERGY FUTURE" INITIATIVE?

This initiative is composed of a wide range of proposals pending with the Colorado PUC, all of which have the potential to significantly increase residential customer bills and rates for essential electricity service, as well as change the way in which residential customers are billed for electricity. The Company acknowledges the potential for overall bill increases for most of these proposals, but does not provide any specific information on the cumulative impact on customer bills. Among the key proposals:

 Public Service filed rate changes to impose a fixed Grid Usage Charge for all customers, as well as proposing to move residential customers to a mandatory Time of Use rate, and proposed a pilot Demand Charge Time of Use pilot for residential customers, linking these proposals to its pending proposal to adopt advanced or smart meters for all customers;

 Public Service filed for a new subscription program to purchase energy with a solar resource called Solar Connect;

 Public Service filed its updated Electric Resource Plan to evaluate the options for acquiring generation supplies for Colorado customers;

 Public Service’s Renewable Energy Compliance Plan would require the acquisition of sufficient renewable energy resources to meet Colorado renewable mandates;

 Public Service has proposed an Advanced Grid Intelligence and Security Plan that proposes to invest in smart meters with two-way communication systems and grid modernization technologies; and

 Public Service seeks to have the Commission approve a Decoupling mechanism for residential and small commercial customers that would allow for rate adjustments between rate cases.

While these filings are being considered separately, several of them are connected in intent and purpose. For example, the large scale implementation of Time of Use and/or Demand Rates are predicated on the installation of advanced metering that can record customer usage in 15-minute intervals. 3

III. A SETTLEMENT APPROVED BY THE COMMISSION WILL IMPLEMENT TWO LARGE TIME-BASED PRICING PILOT PROGRAMS THAT SHOULD BE COMPLETED AND EVALUATED IN A FORMAL PROCEEDING PRIOR TO ANY DEPLOYMENT OF EXPENSIVE ADVANCED METERING

The majority of the parties filed a settlement in August 2016 of several of these proceedings, namely the Rate Design, Solar Connect, and Renewable Energy Compliance Plan. 4 The Commission approved this Settlement on November 9, 2016. 5 Some of the key provisions of this settlement are the following important programs and initiatives that have the potential for significant long term impact on residential

customers:

 Public Service agreed to withdraw the Grid Usage Charge and any proposals for increasing the fixed monthly charge for residential customers;

 Public Service agreed to implement a pilot for "energy only TOU rates" for residential customers. This pilot program seeks to enroll up to 30,000 customers during 2017-2019 with an objective of at least 18,000 customers, 500 of whom would be identified as low income. Under this rate pilot, customers would be charged for electricity for three periods (on peak, off peak, and shoulder) each day and the rates for those periods would vary by season, with much higher rates for peak periods in the summer. Customers who agree to participate will be required to pay for a new advanced meter. After this pilot, Public Service would be authorized to file no later than December 2, 2019 a tariff to transition all 1.2 million residential customers to an energy only TOU rate after the sharing of the pilot’s evaluation with stakeholders. While the settlement does not infer that any party would approve any such proposal, the settlement clearly indicates that this objective is one that Public Service would pursue unless the pilot demonstrates that it should not be implemented. This approach suggests that it would be vital to obtain an independent third party evaluation of this and the Demand TOU pilot.

 Public Service also agreed to implement an additional pilot to test a Residential Demand TOU rate with the same enrollment scope as the Energy Only TOU rate pilot, i.e., 30,000 maximum and 18,000 as the objective. This pilot would test a three-part rate option that includes a demand charge as well as energy TOU charges based on the same peak, off peak, and shoulder periods. Again, the parties did not make any commitment about such a rate option or rate design in the long term.

All of the parties other than the Office of Consumer Counsel agreed that that they would not oppose the principle that the Company "should be permitted to have some form of a decoupling mechanism in place for its residential and small commercial customers." The details of this decoupling mechanism are not set forth in the Settlement and left for litigation in the pending proceeding for that proposal. The Consumer Counsel retained its right to advocate any position concerning the Company’s decoupling proposal, including recommending denial. However, Energy Outreach Colorado and other environmental organizations and the Commission Staff approved the language about the need for some sort of decoupling mechanism.

In its approval of the Settlement, the Commission raised concerns about the potential transition to these types of time-based rate structures and opened a new proceeding to gather and evaluate the information

related to the two pilot programs. The Commission also directed its Staff to participate in the stakeholder group and in its future determination as to whether the TOU rate option should be adopted or revised or eliminated. 6 Furthermore, Public Service filed a study design and evaluation plan for the two pilots on November 15, 2016, stating that it had consulted with the stakeholder group in the development of the evaluation plan. While the results of these pilot programs will be useful, there are aspects to these voluntary programs that will prove difficult to evaluate when considering a transition to a mandatory time varying rate structure, including:

 Neither of the pilot programs set forth specific performance or reporting requirements, but the parties committed to a development of those matters if the settlement is approved. As a result, the Commission is being asked to approve pilots without an evaluation plan or specific criteria that would determine the success or failure of the pilots.

 There is no formal commitment to use of an independent third party to conduct the evaluation of the pilots.

 There are also a number of design features commitments about the TOU pilot that would prove difficult to evaluate in terms of comparing this voluntary pilot to a mandatory rollout of a TOU rate to all customers, such as the requirement to promote incentives or rebates for customers to install a smart thermostat for controlling usage during peak periods and other offers for in-home feedback devices. In addition, with respect to the low income participants, Public Service has committed to a "hold harmless" clause that would inform these customers that they would not be required to pay a higher bill than they would have incurred under the standard residential rate as compared to the TOU pilot rate and that the higher bill not otherwise collected would be deferred and imposed on the entire residential class.

The presence of these incentives for devices and the hold harmless clause are unlikely to be duplicated on a full-scale implementation of TOU rates, thus suggesting the difficulty of evaluating this pilot for any full scale implementation predictions.

 The participants in this pilot would also have to pay an additional charge to cover the additional metering and billing costs, a barrier to entry that should be equal to the projected rate increase required to pay for the full deployment of AMI.

 The energy changes associated with these pilot programs would be reflected in any future Decoupling adjustment mechanism that the Commission may adopt in the Public Service Decoupling filing referenced in this Settlement. This aspect of the pilot program settlement, as well as the agreement "in concept" by all most parties (other than the Consumer Counsel) to develop a decoupling mechanism puts significant pressure on the Commission to accept some version of a new decoupling mechanism prior to its litigation and review by the public through testimony and hearings.

IV. PUBLIC SERVICE’S PROPOSAL FOR ADVANCED METERING AND OTHER GRID INVESTMENTS WOULD RESULT IN COSTS THAT EXCEED BENEFITS FOR RATEPAYERS EVEN UNDER PUBLIC SERVICE’S OWN FLAWED BENEFIT CALCULATIONS.

for a CPCN is to seek the PUC’s approval of these projects based on the estimated costs and benefit, but that it does not yet seek recovery of costs or ask for a specific method of cost recovery. In effect, Public Service wants pre-approval for this package of grid modernization investments before signing the contracts and installing these new metering, communication and distribution grid technologies.

In its filing, Public Service states that these particular projects are part of a larger Advanced Grid Intelligence and Security (AGIS) initiative to implement an "advanced electric distribution grid." Therefore, these particular proposals are only the first steps in a potentially expensive and complex set of future investments that are not identified. According to Public Service, other grid modernization investments would be made in the "normal course" of business and reflected in future base rate cases. However, these specific projects (AMI and voltage regulation investments) are the ones it seeks to get pre-approval for because they are not "in the normal course" of business."

The AMI project would install new digital or "smart" meters, a two-way communication system that would allow remote communications with the new digital meters, and information technology changes for capturing and billing interval usage data and integrating the smart meter information in the outage management system. The Volt/Var investment would install technologies in the circuits to implement Conservation Voltage Reduction, a technology that would allow the Company to modify the voltage for each customer and circuit to eliminate excess voltage and, as a result, reduce the necessary electricity needed to operate the system. The Company estimates total capital costs of $498.1 million and total Operational and Maintenance (O&M) costs of $64.3 million for the period of 2016-2021. These two projects would cost a total of $562 million that Public Service would include in rates in the future as they are incurred. If approved, the project would start in late 2016 and be completed by 2022.

Even a cursory review of this Application shows that the Company’s estimates of future benefits are seriously flawed. But even using the Company’s own flawed methodologies to identify benefits that are claimed to offset the $562 million in costs charged to ratepayers, the result is that the costs will exceed

benefits.

According to the Company’s own testimony, the AMI project has a benefit/cost calculation of 0.89 and the Volt/Var conservation system has a benefit/cost calculation of 0.76. 8 The combined benefit/cost ratio for the combined proposals is only 0.85. Any ratio less than "1" means that the costs will exceed the benefits. Public Service "excuses" these results in its filing by alleging that the costs that exceed benefits are relatively small and that other "unquantified" benefits would make these expenses acceptable. These calculations mean that the costs would exceed benefits by 15%. As a result, Public Service asks the Commission to approve projects that would never pass the straight face test applicable to other large investments. The Commission would not approve any other efficiency or demand response program unless the benefits exceed costs, yet Public Service is asking this Commission to impose costs on ratepayers that even the Company cannot identify as values that exceed the costs of these proposals.

Under its own Cost/Benefit analysis for a 20-year period, the AMI costs would exceed benefits by $51.1 million. Under its own Benefit/Cost analysis for a 20-year period, the Volt/Var costs would exceed benefits by $45 million.

In addition, Public Service fails to include any performance standards or criteria to ensure that even its flawed benefits would actually occur. As a result, this filing would transfer all of the risk to ratepayers that the costs would be as estimated, that the benefits would actually occur or be reflected in customer bills, or that its "unquantified" benefits would appear.

The following discussion presents the specific proposals in more detail and identifies the flawed assumptions reflected in the Company’s analysis that would greatly exacerbate the amount by which the costs would exceed any reasonable calculation of customer benefits.

a. Advanced Metering Infrastructure (AMI)

This is the largest and most expensive project included in this filing. If approved, 1.5 million meters would be replaced (1.4 million existing meters and another 100,000 for new growth). Public Service currently obtains monthly meter reading from its customers with an Automated Meter Reading or AMR system in which meters are read via a signal from an employee who drives a vehicle down the street to capture monthly meter readings, eliminating the actual interaction with the meter at the customer’s house. As a result, and typical of other utilities that have installed AMR, the avoided cost for meter reading when AMI is installed is much less than for those utilities with manual on-site meter reading systems because some of the efficiencies in eliminating meter reading costs have already been captured with AMR. 9 Public Service proposes to deploy AMI and replace meters starting in 2018 and through 2021.

Public Service recognizes that a small group of customers would ask to "out-out" of AMI and it proposes to charge such customers a $11 monthly fee and the significant cost to install a new meter with TOU capabilities, thus not allowing the continuation of their AMR metering system and allowing the Company to impose Time of Use rates on these customers as well as all AMI-enabled customers in the future. 10

Public Service’s estimates of the costs for AMI deployment are questionable.

First, the estimated capital and operational costs of AMI deployment may or may not be accurate and would not be known until Public Service actually negotiates the necessary contracts and implements and installs the new communication and metering systems and integrates those systems.

Second, the cost estimates fail to include the stranded costs of the current AMR system, a significant defect since the Company would want accelerated depreciation expense for the remaining life of these assets. As a result, the actual costs to Colorado ratepayers would include millions of dollars of stranded costs for a metering system that works and provides monthly meter readings for its customers.

Third, it is highly likely that costs associated with maintaining the cyber security of this new digital system in light of ongoing and known threats would be greatly in excess of the cavalier notion put forth in this filing that Public Service would respond to these concerns within the proposed budget.

Finally, the estimated costs do not include all the other incremental costs associated with the larger AGIS plan that would be implemented and for which cost recovery would be sought in rates as incurred in the future. Nor does the filing include any specific costs and type of future changes in rate design to implement either Demand rates and/or Time Of Use rates that the Company claims would be proposed in the future and that are relied upon for certain of the predicted benefits in this filing to justify these investments.

Most important, Public Service’s estimates of future benefits that are predicted would occur with AMI deployment are deeply flawed and replete with assumptions and predicted results that are controversial and should be rejected by the Commission.

The result is that costs would exceed the benefits that are realistic and reasonably likely to occur are far in excess of even the Company’s unsupported calculations. The removal of these flawed and unsupported benefit estimates would result in a project that would cost at a minimum $452 million. By removing the $276 million in flawed and questionable benefits identified in the Company’s business case as described below, the benefit/cost ratio falls to 0.28 and reflects $327 million in costs in excess of remaining benefits.

As a preliminary matter, the Company’s analysis relies on several assertions reflected in an AMI business case prepared by Ameren Illinois for its AMI deployment. It is not clear why Public Service selected this utility to justify some of its benefit predictions since there is a wide range of AMI business case proposals that have been litigated and relied upon in, for example, Maryland, 11 Maine, 12 Delaware, 13 Pennsylvania, 14 Oregon, 15 and California. 16 Furthermore, the Illinois example is particularly not relevant because the Illinois AMI installation programs were mandated by statute with a formula rate recovery mechanism. 17 Furthermore, if Public Service seeks to follow the Illinois precedent on AMI deployment, it would have to adopt the performance standards and potential penalty mechanisms included in the Illinois statutory approval for gird modernization investments, an approach conspicuously missing from Public Service’s filing. Under the Illinois grid modernization statute, the utility must meet certain performance standards or suffer penalties in its implementation of AMI and other grid modernization investments. 18 Public Service’s justification for relying on the Ameren Illinois business case for AMI should be rejected.

The following analysis of the Company’s alleged benefits and estimation methodologies confirms that the Commission should reject the AMI proposal. For those items that reflect questionable and inappropriate benefit categories or methodologies, the lifecycle benefit estimate are those reflected in the Company filing in the Testimony of Samuel Hancock.

According to Public Service, the Company would routinely reduce its storm related outage expenses by 10% due to the ability to remotely detect whether the meter is "on" or "off" without a site visit. However, how Public Service could connect this functionality with a significant reduction in severe storm restoration expenses is questionable. Public Service just multiplied 10% by its average annual storm related capital and O&M costs to predict this benefit. 19 Nor is it possible to even track and determine whether such a result has occurred even if the Company had offered to do so as a condition of its investment (which it has not done). In order to actually determine if this result has occurred, Public Service would have to develop a methodology to objectively measure what the outage duration results would have been had the AMI system not been in operation. No evidence has been presented by Public Service nor have state AMI decisions and orders relied on this type of calculation in state regulatory commission analysis of an AMI business case. 20 Major storms are unique in their cause, impact, and restoration experience. It is correct that the AMI system would allow Public Service to "ping" the meter to determine if the customer’s meter is operational or whether service has had service restored, thus allowing a more targeted approach to restoration activities. This feature also would allow the Company to avoid extra visits to a specific location to determine if service has been restored following restoration activities in the area. However, major storms that cause widespread damage would find this particular feature a minor part of what is required to actually repair the poles and wires caused by tree damage on the wires, or fix a substation that has been damaged due to flooding or lightning. The Commission should eliminate this benefit (or, alternatively, most of this predicted dollar amount of benefit) from the analysis of the business case.

Estimated Lifecycle Benefit: $1,068,273

The Company claims to eliminate premise visits for disconnection for nonpayment, a controversial and dangerous denigration of consumer protection policies. 21 Under the current policies, a utility cannot disconnect service for nonpayment (or any other reason) without a physical visit to the meter itself. The elimination of a premise visit to disconnect service for non-payment or other involuntary actions would raise important consumer protection issues and concerns. For example, whether or not Public Service is required to "knock on the door" by current regulations, the current practice of visiting the customer’s premises to disconnection service means that customers have an opportunity to interact with the Company’s metering employees and offer payment or describe potential adverse health or welfare impacts if disconnection occurs as intended. As a result, utility employees naturally have the ability to observe the dwelling and possibly interact with customers who may seek to communicate with the utility employee undertaking the disconnection process. In such interactions, it is common for the utility employee to refrain from actual disconnection if informed of a medical emergency (to allow the customer to obtain the formal notice from a medical professional) or if the employee observes indicia of potential harm to members of the household (such as unsupervised young children or a vulnerable elderly resident, etc.) These discretionary and informal actions by utility employees who are trained to observe and make judgments about health and safety would be completely eliminated with remote disconnection for nonpayment allowed by AMI and included in this proposal. Indeed, under current Colorado PUC regulations, the customer has the right to make payment in full to a utility

employee dispatched to discontinue service to avoid disconnection of service 22 and this right would be improperly eliminated under Public Service’s benefit calculations that eliminate any premise visit or attempt to contact the customer at the time of disconnection for nonpayment. While it may be beneficial to capture efficiencies associated with implementing remote disconnection upon request of the customer and remote reconnection for any customer, the Commission should eliminate savings associated with remote disconnection of service for nonpayment as contrary to the current regulations and potentially harmful to residential customers. In fact, other states have taken a similar approach when considering potential benefits for AMI deployment. Several states, such as New York, Massachusetts, Ohio, Maryland, and the District of Columbia have rejected proposals to eliminate these consumer protections, even though such rejection has resulted in lower savings associated with AMI, on the grounds that the likely increase in disconnection of residential customers would occur with remote disconnection and may result in dangerous health and safety conditions due to the loss of essential electricity service. California has mandated premise visits prior to disconnection for nonpayment for certain categories of vulnerable customers. Indeed, the very foundation of consumer protection policies governing electric and gas utilities is the notion that disconnection of electricity carries important health and safety consequences. State commissions have routinely adopted consumer protections and policies designed to make disconnection the last resort to respond to non-payment. Public Service’s attempt to circumvent this important policy with its calculating of benefits for remote disconnection for nonpayment should be rejected.

Estimated Lifecycle Benefit: Included in $32.3 million in Reduced Field Meter Operations (assume at least a 50% reduction in benefits due to remote disconnection for nonpayment)

 The Company relies on a "value of service" methodology to calculate customer "savings" associated with experiencing an estimated amount of fewer outage hours. 23 Under this approach, Public Service uses a methodology or calculator devised by the U.S. Department of Energy to evaluate its smart grid investments. This methodology uses historical survey data conducted by utilities throughout the U.S. that ask customers how much they would be willing to pay (or how much they would avoid spending) to avoid an hour of an electric outage. Public Service’s use of this methodology should be rejected for the following reasons:

o The value that results from the averaging of the results from these disparate surveys has nothing to do with utility rates or ratemaking policies. In other words, these "benefits" in the form of hypothetical value would not be reflected in the Public Service rates or bills to offset the costs of AMI. Customers would not save one penny on their Public Service bill with this "benefit."

o To argue that customers are willing to pay a certain dollar amount to avoid an outage without informing the customer what it would take in the form of higher utility bills to avoid the outage is unreasonable on its face.

No other U.S. jurisdiction has relied on such a benefit calculation to approve an AMI investment. No state regulatory commission has given DOE’s calculator evidentiary consideration or relied on the results in retail electric utility ratemaking decisions for an AMI investment. The DOE methodology has never been adopted in any

adjudicatory or formal proceeding and has not been "tested" in a formal hearing with evidence and argument. Rather, this DOE method of calculating the benefits of its smart grid projects funded by the federal recovery act in 2009 (and used presumably to justify the results of DOE’s grid modernization grants) has no force or effect on state regulatory commissions.

o The surveys and other data from these unidentified utility studies are not publicly available and the survey methodologies vary and are also not publicly available.

o Public Service has not proposed to actually deliver the estimated outage reduction that is reflected in this benefit calculation in its filing.

Estimated Lifecycle Benefit: $18,066,119

Public Service includes its estimated benefits in the form of reduced electricity prices based on the future implementation of unidentified rate design changes that would result in "customer demand savings in response to new rate structures." 24 This benefit is apparently related to the Company’s proposals for Time of Use and Demand Rates in other proceedings, but has now resulted in a settlement by most parties to conduct extensive pilot programs for these alternative rate structures. As a result, including any predicted lower electricity prices in the form of lower capacity costs prior to the completion of these pilot programs (none of which will occur prior to the Commission’s decision on this request for AMI approval) would be premature.

Estimated Lifecycle Benefits: $9.8 million in "demand response" and $231.5 million in price response (elasticities) to demand and TOU rates.

b. Voltage Regulation.

As part of its Grid filing, Public Service proposes to install new grid technologies and communication systems to interact with its proposed new AMI system to monitor and alter voltage regulation throughout the system. Public Service calls this project "Volt-Var" to refer to the variation in voltage that would be possible. When voltage is altered to be lower than required to serve the load (while still meeting the load serving requirements), the result is a lower use of energy on the grid, lowering revenues collected in the cents per kWh charge. The Grid Filing proposes to install these technologies in 2017-2022.

To the extent that Public Service determines to implement a Volt-Var project independently of its proposed AMI deployment, it should refile its proposal to eliminate the impact of the AMI system on its projected benefits and undertake such projects, if at all, pursuant to a normal rate case filing that gradually installs such technologies on its circuits and justifies such investments based on standard efficiency program criteria. Other utilities are implementing Conservation Voltage Reduction without AMI.

V. THE DECOUPLING MECHANISM IS FLAWED IN DESIGN AND SHOULD BE REJECTED.

Public Service has proposed a decoupling mechanism that would apply only to residential and small commercial customers. This proposal would allow the Company to adjust rates every year based on whether a revenue target had been met. The revenue target would be based on weather normalized average use per customer. If the revenue target is not met, Public Service could increase rates without a rate case.

The Company already has an approved revenue adjustment to reflect the impact of approved energy efficiency programs. As a result, the Decoupling proposal is intended to reflect revenue target changes for

other programs, including usage changes by customers who agree to enroll in the Time of Use pilots set forth in the Settlement, changes in usage resulting from the Conservation Voltage Reduction program in the Grid investments, the impact of net metering, 25 and solar and distributed generation programs. Most of these programs are included in or slated to be significantly expanded in the Company’s "Our Energy Initiative" programs pending before the Commission.

An Application and three company witnesses with attachments support the Decoupling filing. According to the filing, "The Company is proposing revenue decoupling to align our interests with the preference of our customers." 26 Public Service states that this new rate adjustment is required because all these new programs "have the effect of reducing the Company’s ability to recover all of its fixed costs." Further, the Company states that if Decoupling is not approved it would withdraw its Conservation Voltage Reduction program (Volt/Var) in the Grid CPCN docket on the grounds that those revenues losses (which are all based on predictions!) could not be incurred without revenue adjustment in between rate cases. 27

Based on "recent forecasts," the Company claims the impact of this proposal will be less than a 2.2% impact on customer bills. However, this estimated bill impact does not reflect the cost of all the new programs that would "require" the Decoupling Adjustment, such as AMI, Volt/Var investments, expanded solar programs, and Time of Use pilot programs.

This Decoupling proposal should not be adopted for the following reasons:

 While the Company claims that this revenue adjustment would not double count the adjustment mechanism already approved for reflect the impact of efficiency programs, the ability to actually identify the particular reasons why usage per customer has decreased is highly unlikely so that double counting is more likely to occur.

 It is highly unlikely that Public Service can determined how revenue losses in between rate cases impact its ability to recover "fixed costs" as opposed to "variable" costs. In other words, decoupling creates a disincentive to become more efficient and cut costs.

 Decoupling is another word for a rate case without analysis of all costs and revenues.

 Decoupling in this case would require customers to pay higher rates for new investments in AMI, grid modernization, expanded solar programs, new Time of Use rate options, expanded renewables programs, and then pay AGAIN to Public Service to protect its profits and lost revenues. It is a "lose-lose" for customers.

 The emphasis on "fixed costs" is linked to Public Service’s intent to move to fixed cost rate recovery in the future as stated in its Phase II testimony and its near term residential Demand TOU rate option in Phase II. Residential customers should not pay for essential electric service with higher fixed charges or demand rates.

The Company promises "weather normalized" but it can’t promise or reflect "economic" trends and events that have a significant impact on customer usage, customer growth, and average usage per customer. The Company’s own chart on Historical Use per Customer shows a decline in 2009-2012 that is no doubt connected to the economic rescession, followed by a slight increase in per customer usage in 2013. 28 Under the Decoupling proposal, economic events are more likely to impact the formula for in a rate change than actions by Public Service under its rate structures.

If Public Service finds that its revenues do not reflect the obligation to provide reasonable and reliable electric service, the Company should file a rate case in which all costs and revenues can be evaluated.

(For end notes and citations, please call 303-764-5988.)