STATE OF PUBLIC SERVICE COMMISSION

Proceeding on Motion of ) the Commission in Regard to ) Case 14-M-0101 Reforming the Energy Vision )

COMMENTS OF ON STAFF STRAW PROPOSAL

Direct Energy Services, LLC and Direct Energy Business, LLC (collectively “Direct

Energy”) are pleased to provide this response to the Staff Straw Proposal (“Staff Proposal”) in this case, which was released on September 22. The Staff Proposal comprises many elements, some of which Direct Energy will be responding to here.1 The most important point to make about the Staff Proposal, however, is one that addresses not any specific aspect of it but rather the overall focus of the proposal, which is clearly on the utility rather on the customer. While

Direct Energy remains strongly supportive of the goals of the “Reforming the Energy Vision,” or

“REV,” and agrees with the Staff Proposal’s conclusion that the tools needed to achieve those goals exist today, the approach recommended in the Staff Proposal should be modified to create a more streamlined approach that emphasizes customer needs and desires, with the DSP and the utility working together to provide a platform that will allow third parties to address those needs and desires by removing the barriers that keep this from happening under the current system. 2

I. Section I.B. Summary of Findings and Recommendations

Direct Energy agrees with many of the Staff Proposal’s conclusions about the large potential for the integration of DER into the New York electricity market through the use of a distributed system platform framework. We agree especially with the Staff Proposal’s statement

1 On other matters, Direct Energy relies on and joins in the response filed by the Retail Energy Supply Association (“RESA”), of which Direct Energy is a member in good standing. 2 As required by the ALJs’ order, these comments will address the numbered sections of the Staff Proposal as they appear in that document. 1 that the “integration of DER offers customers the opportunity to manage their usage and reduce their bills while at the same time creating important system and societal benefits such as increased system efficiency and reduction of carbon emissions.” Our belief in the customer’s ability to shape his or her own energy consumption through the kind of value-added products and services that would be enhanced by the REV vision is central to Direct Energy’s view of its own future. We also agree with the high-level critical path objectives described in the Staff Proposal:

 Increase the DER asset base in the state;

 Build customer and market confidence in the expanded role of DERs; and

 Begin the development of DSP capabilities.

Direct Energy also strongly concurs in the Staff Proposal’s conclusions regarding the technical feasibility of achieving the REV’s vision, based on both technical capabilities and consumer interest:

Technology to support the DSP platform is achievable and to a large extent already available. The DER resources needed to support REV objectives are available in the market as evidenced by the rapid growth nationally and in New York of key technology markets, and their value can be increased by the reforms proposed here by appropriately valuing the services DERs can provide. The level of interest and engagement in this proceeding as well as Staff’s assessment of the energy landscape indicate that DER providers, Energy Service Companies (ESCOs), and customers are ready in large numbers to participate in emerging DSP markets.

Direct Energy also believes that there are “significant barriers that will need to be overcome in order to optimize the use and penetration of DER,”3 and that some of the policy recommendations made in the Staff Proposal will lower these barriers and allow the State to make progress in achieving the goals of the REV.

The Staff Proposal misses the mark in several critical respects, however. Our concerns with the Staff Proposal nearly all flow from one central point, and that is the recommendation

3 Staff Proposal at 4. 2 that the REV vision will be brought to fruition by investing the distribution utility with extensive authority and control over the market for DER. The role for the utility envisioned in the Staff

Proposal is, indeed, pervasive.

 The utility would serve as the DSP, a role defined in the Staff Proposal as encompassing nearly all aspects of market operations, grid operations, and integrated system planning.

 The utility would be allowed to compete in the markets for DSP products and services for which it would also be the market maker and operator.

 The utility would be allowed to rate-base its investments in the products and services with which it would compete in the DSP markets.

 The utility would continue to control all data generated by distribution level infrastructure, with competitors being allowed access to it only second hand (and, presumably, not in real-time) through a yet-to-be-created data exchange.

 The utility would expand its time-of-use products while having no obligation to enhance its distribution infrastructure to give competitors access to systems and data that would allow them to design and market their own time-differentiated offerings.

 The utility would be given control of all energy efficiency programs, and would also be allowed to rate-base its investments in these programs.

 The utility would be given control of all main tier renewable procurements, a role previously handled ably by NYSERDA, again with all investments charged to utility customers, not shareholders.

 The utility would be allowed to own and rate-base all manner of DER, provided certain conditions are met.

To be sure, the Staff Proposal offers colorable reasons for placing each of these roles with the utility. Some aspects of the Staff Proposal also represent an understandable temptation to see the concept of the distributed system platform provider as being essentially an exercise in distribution system planning and optimization which, of necessity, would result in a central role for the utility. Nonetheless, taken together, the sum total of the responsibilities given to the utility in the Staff Proposal could well chill the development of the market and present the

Department with daunting monitoring challenges in preventing abuses that will be exceeding

3 difficult detect, existing as they would within an organization with unmatched access to and control over the people, systems, and data engaged in operating the DSP market.

Before dismissing this approach out of hand, one should ask whether there are reasons to believe that such a utility-dominated system would transform the REV vision into reality. To a limited extent, the answer might be yes. If a utility commission directs a utility to acquire more of something through its rate base, the utility will do so. If a commission wants more traditional distribution infrastructure, that is what it will get. If a commission wants more DER, it will get that as well. So, if the Commission’s goal is merely to increase the level of DER in New York in a highly controlled manner by doing it through the regulated utility, the Staff Proposal might suffice.

But the REV is supposed to be much more than that. From the beginning, the allure of the REV has been the idea that engaged, informed, and empowered customers can drive a fundamental change in the direction of the market, away from the traditional central-station model of the electric grid and toward a more decentralized model that makes optimal use of the advantages of both the traditional system and new technologies at the customer level. Direct

Energy and other large, integrated non-utility market participants are fully committed to this idea, and are willing to invest heavily to make this vision a reality.

But there is no evidence that a market dominated by a vertically-integrated monopoly utility will deliver the kind of customer engagement and innovation that are at the core of the

REV vision. In fact, the restructured markets that have shown the most innovation in integrating the customer into the energy equation through the use of behind-the-meter technologies – for example, and the United Kingdom – have market structures that have removed the utility from a customer-facing role entirely. In both Texas and the UK, customers deal only with

4 competitive entities; utilities (or “TDSPs,” transmission and distribution service providers) have a relationship with retailers that is similar to the relationship that FedEx has with Amazon or

Zappos. Texas also made an early commitment to full smart meter deployment, with interval data being made available in near real-time to retail load serving entities. This has allowed retailers doing business in Texas to use customer-empowering products like Direct Energy’s

“Power to Go” prepaid product to influence consumption patterns using the distribution infrastructure as a true platform rather than a straitjacket. In the UK, the direct relationship with the customer, unmediated by the distribution utility, has allowed integration of commodity and customer-side services to such an extent that for the large players like British Gas (Direct

Energy’s sister company) they are part of the same company. A residential customer might take two, three or even more services from British Gas, and interact seamlessly with one sales representative, one bill, and one customer service center for all of them.4 These markets work because they are designed to lower the barriers that the vertically-integrated utility model placed between customers and the innovative solutions a true market can bring.

On the other hand, there is much evidence that over-reliance on the regulated utility model will not bring about the kind of innovation and market animation the Commission seeks through the REV. The evidence is the fact that the current system, which already relies extensively on the utility for a host of market functions, has not delivered this kind of innovation despite the fact that, as the Staff Proposal itself acknowledges, the technical capability to have such a system and the consumer interest in moving in this direction are both present in abundance. It is very risky to assume that placing even greater responsibility in the hands of the

4 Indeed, there is some irony in the fact that the UK’s approach to regulating network companies, “RIIO” (Revenue=Incentives+Innovation+Output), appears to be one of the models for the REV vision. The RIIO model may make sense in a market in which the utility does not compete with retailers in any sphere, but applying it to a market structure in which the utility will be an integrated player in the retail space is an unproven concept. 5 regulated utility, only under a somewhat revised regulatory regime, will bring the transformative change the Commission seeks. There is no evidence of such transformative change taking place in any industry without an emphatic commitment to allowing consumer preferences and choices to drive free market forces.

Direct Energy therefore strongly encourages the Commission to adopt an approach to the policy issues discussed in the Staff Proposal that focuses on what customers want and need and the barriers that prevent those customer preferences from being met today. Such an approach would be characterized by the following guiding principles:

 The distributed services platform should be designed primarily with the goal of reducing

or eliminating the barriers to customer engagement and product innovation that stand in

the way of the REV vision being realized under the current system.

 All stakeholders should work collaboratively to create near-term opportunities to prove

out the capability of DER to achieve critical goals of the REV, including through the

liberal use of demonstration projects.

 The utility’s involvement should be limited to those activities that can only be provided

efficiently by a single, monopoly provider, with other functions being provided by a

utility affiliate subject to appropriate codes of conduct.

 The effectiveness of the DSP market should be enhanced by the creation of appropriate

incentives that would reflect the value of DER and that would be available on a

nondiscriminatory basis, allowing customers, through the mechanism of the market, to

choose the optimal level of DER penetration.

 The financial health and stability of the DSP platform and markets should be enhanced

through the creation of appropriate incentives for the utility to facilitate the development

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and maintenance of new markets, and through the development of appropriate rate-

making structures that would allow the utilities to maintain their financial health in a

system that might be characterized by low, no, or even negative load growth.

Most of these concepts can be found in the Staff Proposal but they are obscured somewhat by the proposal’s intense focus on the role of the utility in the new market structure. With careful trimming, performed collaboratively by all stakeholders. we believe a compelling vision for achieving the goals of the REV can emerge from this process.

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Section III.A. Identity of the DSP

The Staff Proposal recommends that incumbent utilities serve as the DSP, subject to performance review by the PSC. Staff’s argument in favor of the utilities serving as the DSP is that, as described in the Proposal, the functions of the DSP, including market operations, grid operations, and integrated system planning, overlap to such an extent with the current functions of the incumbent utilities that devolving the role of DSP onto a third party would result in duplication of functions and present daunting challenges of oversight and regulation. It is unclear at this point, however, that the role of the DSP must include all of the functions described in the Staff Proposal. The Proposal itself recognized that “[a]n alternative approach to an independent DSP is to separate the market function from the planning and operations functions that must be performed by the utility, with the DSP providing only the market function.” Staff Proposal at 20. While the Staff Proposal ultimately did not embrace this approach to the DSP, we encourage the Commission to continue to evaluate it as the collaborative processes that will build the technical platform and market designs move forward.

There are several reasons to keep this option for an independent DSP in play. First, as the Staff Proposal, there would be real advantages to an independent DSP, including avoiding the market power concerns in having the utility serve as the DSP while also owning and operating

DER and perhaps more effectively promoting the technological innovation that will move the market forward in achieving the goals of the REV.5 The Commission should not abandon these advantages too readily. Second, at least some of the advantages of defining the role of the DSP to include all of the functions described in the Staff Proposal and placing the utilities in that role,

5 Staff Proposal at 19. 8 may be ephemeral. Most importantly, the assumption that there will be economies of scope in having the utilities act as the DSP appears to presume that the DSP functions will reside wholly within the current utility structure, with little or no separation between those functions and the rest of the utility’s operations. This may not prove to be the case. To ensure that all market participants have confidence in the integrity of the DSP in providing services on a nondiscriminatory basis, Direct Energy strongly believes that a substantial degree of structural separation between the DSP’s functions and the rest of the utility’s operations will be required.

Thus, even if the incumbent utility serves as the DSP, it may prove to be more efficient to define that role more narrowly (again, perhaps limited to market operations), which would also make it easier to devolve that role on an independent third party.

Finally, as with a number of important matters in this proceeding, there is no need for the

Commission to make a definitive determination on this issue at this time. Through the collaborative processes that will determine the structure and functions of the DSP, the

Commission can continue to assess whether more narrowly defining the functions of the DSP and leaving open the option of devolving those functions on an independent third party will best serve the interests of New York electricity consumers.

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Section III.B.1.i. Data Exchange

The Staff Proposal lays out a plan to develop a “bi-directional electricity data information exchange from data acquisition assets such as meters and DER assets installed on both sides of the meter.”

The purpose of the data exchange is to enhance distribution system monitoring and control, reveal opportunities for near term DER products and services tied directly to customer data, and to support the development of innovative DER products and services to be traded on the DSP market.

While these are laudable goals, Direct Energy cautions that creating such an exchange is not likely to be the best way to address the most pressing needs in the area of data access. The customer engagement working group did identify shortfalls in customer data as a major impediment to achieving the goals of the REV, many of which are similar or identical to the business goals of current market participants, including Direct Energy. These comments focused on the difficulty of obtaining current and accurate data from utilities in a timely manner, the basic blocking and tackling of operating in the New York commodity markets. There are serious performance issues with respect to this basic aspect of data access that should be addressed in this proceeding, as getting timely access to accurate data will be a key to promoting DER.

Pulling the spotty data from the existing system into a different system, which would put retailers and other third parties at a further remove from direct access to data coming off customers’ meters, will not improve the situation; it will only create additional complexity and delay in dealing with the already inadequate data. If utilities simply provided the data they already have in their systems to third parties (upon appropriate customer authorization, of course) on an

10 accurate and timely manner, this would go a long way toward further development of a market- driven expansion of DER.6

Nonetheless, Direct Energy does support further consideration of a data exchange, though not as the primary source of specific customer data needed by retailers and other third parties to serve customers. The Staff Proposal does mention ways in which a data exchange could be fantastically useful. Making customer data available to “reveal opportunities for near term DER products and services tied directly to customer data, and to support the development of innovative DER products and services to be traded on the DSP market” would allow third parties to use the tools of big data to offer products and services on a customer-specific basis to those in particular areas where such products and services would be most valuable. This is the strategy that has allowed Google, Apple, Amazon and Facebook to transform the way people interact with each other in both the commercial and personal spheres. To be sure, there are serious issues of data privacy and security that will have to be addressed in creating an exchange that would be used for these purposes, but the potential customer and system benefits are great enough that we must find a way to overcome these issues. Direct Energy looks forward to working with the

Commission and other stakeholders in this process.

6 These comments address the general lack of interval data for mass market customers in its comments on the Customer Acceptance portion of the Staff Proposal, below. 11

Section III.B.2 Customer Acceptance – Time-of-Use Rates

In this portion of the Staff Proposal, Staff rightly observes that “[b]roader acceptance of optional time-of-use pricing has been very limited.” They attribute this limited acceptance to several possible factors, including “knowledge of the rates and their potential consumer savings benefits, availability of interval meters or alternatives, existing usage patterns, and the ability to modify those patterns.” While all of this may be true, the Staff Proposal’s suggested solution is puzzling: it directs utilities to “revisit their time-of-use rates for mass market customers seeking to develop and provide easy-to-understand interval rates and tools for customers to easily determine the benefits of those rate designs for their individual needs.” Staff Proposal at 28.

In other states, market forces are already addressing this problem, without utility involvement, other than in the role of providing interval data upon which third parties can base time-differentiated products. In Texas and , where interval data is generally available for all mass market customers, time-differentiated products offered by competitive suppliers are readily available. In these states, companies like Direct Energy are offering “Free

Power Day” or “Free Nights” products to customers, who respond to these price signals because they are both compelling and easy to understand. The main limitation of traditional two-period utility “time-of-use” rates is not that customers don’t understand them, but that they do.

Customers reject these rate schemes because the difference between the peak and off-peak rate is not enough to drive customer behavior. This is true because these rates are designed using traditional tools of utility ratemaking rather than modern marketing tools. The solution to the lack of customer interest in utility time-of-use rates is not to try to explain to them in more detail why those rates, which customers have eschewed for years, really are good for them. It is to make data and metering technology available that will allow companies that know how to market

12 to customers to design products that customers understand and find compelling, like “Free

Saturdays.”

Making progress on the availability of time-differentiated pricing through third parties rather than through the utility raises important issues that are mentioned only briefly in the Staff

Proposal. The first is third party access to the means of providing the existing utility time-of-use rates. As the Staff Proposal notes, “all customers have the option to opt-in to time-of-use pricing” using existing meters and utility billing systems. Giving third party retailers the ability to use this functionality to offer their own two-period products (and, just as importantly, bill them through the utility consolidated billing platform) would immediately bring the creativity and innovation seen in places like Texas and Pennsylvania to New York mass market customers.

Going beyond simple two-period rate schemes will require the Commission to address the issue of advanced metering infrastructure and the dearth of interval data available for mass market customers. In this respect, New York lags many states (including Texas, Pennsylvania,

Ohio, , and ) badly, and there is barely any discussion about how to close this gap.7 The Staff Proposal mentions this problem only obliquely, in the following statement: “To the extent that the cost of advanced metering equipment presents a barrier to customer adoption of DER programs or time variant pricing, utilities and market participants should consider alternatives to AMI technologies to enable program delivery.” Staff Proposal at 28. The question of what those costs might be, how they might be recovered, whether the benefits of having advanced meters would outweigh them, and what alternatives might be available is like a phantom limb that begs to be scratched.

7 Direct Energy was pleased to see the comments of the New York State Smart Grid Consortium in response to the Track 1 briefing questions, in which the Consortium (which includes the State’s two largest utilities, Consolidated Edison and National Grid) recommended developing a plan for broad smart meter deployment. 13

Direct Energy readily acknowledges that the issue of smart meter deployment in a state as large and varied as New York is daunting in its complexity, and we do not claim to have any clear answer (much less the right one) about how to proceed. We do believe that it is absolutely critical to the success of the REV concept to address this issue head-on, in all of its complexity.

We also believe that the best way forward in addressing this critical question is to use the tool that Staff recommends for the most difficult questions in realizing the REV vision: use the collective expertise of the stakeholders in this process to examine the issue and suggest possible solutions. While the question of advanced metering technology, cost, and cost recovery could warrant a separate collaborative process, Direct Energy sees a natural place for this investigation in the stakeholder process that will examine technical platform design and market design issues

(described in Section V.F.2 of the Staff Proposal), and we encourage the Commission to make advanced metering a part of that process.8

8 As discussed below, in Section V.B., advance metering would also be an excellent candidate for demonstration projects. 14

Section III.B.3 Customer Acceptance – Billing and Engagement

The Staff Proposal appropriately recognizes the limitations of the current billing options for retailers and other third parties as a material barrier to customer engagement in DER. Direct

Energy strongly supports the Staff Proposal’s recommendations in the area, which include a collaborative effort to examine improvements in the content and format of the consolidated utility billing platform (which continues to be the means by which the great majority of mass market customers are billed for commodity service in New York), and the development of an

ESCO bill message of up to 1,000 characters (the equivalent of more than seven tweets!).

While these measures are important, Direct Energy notes that the absence of a direct billing relationship between ESCOs and their customers through ESCO consolidated billing was identified by a number of ESCOs as the single greatest barrier to customer engagement. In jurisdictions that rely on retailer billing (including Texas, , and the UK), retailers use the bill not only as a means of establishing a closer customer relationship, unmediated by the utility, but are also limited only by their own capabilities and initiative in the products and services they can make available through the bill. In the UK, for example, a British Gas customer might purchase electricity, natural gas, a HomeCare® home warranty plan, and a Hive Active Heating™ smart thermostat, all of which will appear on a single bill that can be viewed and paid online. It would be impossible to achieve this level of customer engagement through the utility consolidated billing platform without introducing significant redundancy and inefficiency into the billing process. Retailers like Direct Energy have the means to do this kind of billing themselves today and simply want to get on with it, without depriving any other company of the ability to use the utility platform if they prefer.

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The Staff Proposal mentions ESCO consolidated billing, but only to say, in a footnote, that “Staff intends to further evaluate CEB in Case 12-M-0476.” Staff Proposal at p. 29, n. 23.

This evaluation may yet prove to be sufficient, but for what many large, integrated retailers see as a significant (if not the most significant) barrier to customer engagement, Direct Energy had hoped for a more positive endorsement of ESCO consolidated billing as an important element in creating engaged and informed customers who would be able to buy and pay for a diverse array of DER products and services from third parties unfettered by the limitations of the utility billing platform. Direct Energy urges Staff to provide further guidance, at its earliest convenience, regarding its intentions to address this issue in Case 12-M-0476 and the timing for doing so.

Enabling a more robust relationship between customers and ESCOs that would include the ability to provide not only commodity service but also DER products and services on a single,

ESCO-branded bill will be a critical step in achieving the Commission’s vision for the REV, and such a relationship cannot be established using only the tools available now or those specifically proposed in the Staff Proposal.

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Section IV.B. Benefit Cost Analysis

The Staff Proposal finds appropriately that a “sound benefit-cost analysis (BCA) framework is required to support policy, investment, and pricing choices as the implementation of REV moves forward.” Staff Proposal at 42. Direct Energy strongly supports the Staff

Proposal’s recommendation for the creation of a stakeholder process to design the BCA framework, and looks forward to participating actively in that process. In the meantime, Direct

Energy provides the following comments on how best to design that framework and the elements within it.

As outlined by DPS Staff in Section IV.B, a framework for conducting a comprehensive benefit cost analysis of the REV components and structure will be critical to ensuring that all stakeholders have transparency into the overall impacts, as well as winners and losers, under the evolutionary transformation of New York’s electric industry. Direct Energy has a direct interest in ensuring that any benefit cost analysis undertaken is one that fulfills the principles outlined by

DPS Staff in Section IV.B.1.

Direct Energy believes the Staff proposal for measuring benefits and costs of the REV proposal – or individual elements – represents a reasonably comprehensive approach. However,

Direct recommends two key refinements that are not fully addressed in the DPS Staff’s proposal.

First, the REV proceeding and any benefit cost analysis should clearly articulate how a given policy change affects all of New York State’s policy goals, including economic and environmental goals that thus far are only marginally addressed in the DPS Staff’s proposed framework. Second, the benefit cost framework proposed by DPS Staff should be refined to include a macroeconomic analysis of the impacts identified in Table 3 and Table 4 of the straw

17 proposal, in order to determine how effective program elements are in achieving the state’s economic objectives.

New York State has a rich history of setting and meeting ambitious targets to achieve a combination of economic, environmental, and energy policy objectives. Today more than ever,

New York’s energy and environmental policy proposals position it as a leader among the states.

The REV proceeding is a perfect example; the state’s vision captures a wide range of critical policy objectives, including power system efficiency, consumer empowerment, lower bills for businesses and residents, market stimulation and competition, carbon reduction, and power system resilience and reliability. In short, New York seeks to foster the evolution of the state’s electric industry in a way that promotes clean, affordable, decentralized, and reliable power, and does so in a way that helps generate efficient economic outcomes in the state. In this way, the wide-ranging economic and environmental objectives of the REV proposal recognize the broader impact the electric system has on the economy and environment.

Given the state’s objectives, the benefit cost framework contained in the straw proposal should be expanded to measure the broad economic and policy objectives of the state’s vision.

The framework principles noted in Section IV.B.1 do include a “Societal Cost Test” which could be a starting point for evaluating environmental impacts in the context of broader state policy goals. Yet a more explicit and detailed method and framework than that included in Table

4 can help stakeholders and the Commission in understanding and evaluating the effectiveness of proposed changes on economic and environmental policy objectives. Direct Energy believes that given the transformative nature of the REV platform in its current proposed state, it would be beneficial to include a method or methods within the framework to identify these other goals and

18 calculate the impact of the REV platform in a more inclusive framework than currently proposed.

As a way to specifically assist the Commission and stakeholders in the evaluation of impacts noted above, Direct Energy believes that any benefit cost analysis undertaken in the

REV proceeding should include a macroeconomic component in addition to the more traditional benefit cost analysis framework proposed by DPS Staff. Such a macroeconomic analysis would use as inputs the results of the benefit cost components outlined by DPS Staff in Table 4, in addition to information about the specific economic sectors that various costs and benefits would flow between. Additionally, elements of a macroeconomic analysis would include more information than the categories of costs and benefits defined by DPS Staff in Table 4. For example, wholesale market price impacts are currently categorized as a benefit in Table 4, yet only analyzed in the “rates” and “bill” models proposed by DPS Staff, and not included in the

“societal” model. Yet decreases in wholesale market prices – and increased in-state economic activity as a result of smart grid and energy efficiency investments (through, e.g., meter installations or retrofit construction activities) – would likely have a substantial positive impact on electric customers, and a negative impact on generation assets earning revenues from energy sales. The effects of both impacts should be accounted for in the benefit cost analysis. Finally, the impact on jobs and income for New York State as a result of these changing flows of dollars in the economy remain hidden in the proposed framework, potentially missing an important measure of economic costs or benefits to the state of the REV proposal, or various specific elements of the proposal (e.g., the comprehensive installation of smart meters).

Direct Energy believes the staff proposal contains a well-reasoned and detailed approach to assessing the benefits and costs of various REV elements in a transparent manner. Given the

19 explicit and broad economic, environmental and energy policy objectives of the state’s proposal,

Direct believes that the Commission needs also ensure that as benefits and costs are measured, the analysis includes the economic benefits and costs to the state as whole that flow from the various changes in consumer and producer spending under a new industry structure. The addition of a comprehensive, New York State-based macroeconomic analysis to evaluate the impact on all New York residents and businesses is a valuable and needed enhancement to the framework proposed by DPS Staff in their proposal.

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Section V.A.3. Clean Energy – Energy Efficiency with Load Management Controls

The Staff Proposal calls for transitioning the existing energy efficiency programs, which are operated by both the utilities and NYSERDA, completely to utility control and revising the funding mechanism from the current energy efficiency surcharge to the utility’s rate base. Staff

Proposal at 50-51. Direct Energy has serious concerns that this approach will not achieve the results that the Staff Proposal itself envisions for the REV.

At the outset, the Staff Proposal observes that New York has begun the necessary process of moving away from “almost exclusive reliance on one-time incentive based programs,’ and that to achieve the State’s energy goals will require “an order of magnitude greater investment,” which “cannot be supplied by ratepayers alone, but will depend upon the mobilization of private capital and the transformation of the state’s energy market.” Id.

Elsewhere, the Staff Proposal observed that:

To achieve the State’s carbon reduction goals, an expansion of energy efficiency efforts will be needed. Current program targets effectively constitute a ceiling; they will need to become a floor. This cannot, however, be achieved by expanding conventional ratepayer-funded programs. By valuing the system and environmental benefits of efficiency, REV markets will create incentives for third party providers and customers to pursue innovative efficiency methods.

Staff Proposal at 54.

There is currently a disconnect between the desire to mobilize private capital and the plan to wholly transition the responsibility for the State’s energy efficiency programs to utilities that will be operating them as part of the rate base. As is the case with utility ownership of DER generally, private capital is not eager to compete with the utility in areas in which the utility has a profit-incentive to favor its own products and services, and the ability to act on that incentive through the control of data and systems essential to the operation of the market. The means by which the Commission will maintain the integrity of the market in a system that will have one

21 entity acting as system operator, market maker, and active, for-profit market participant is the most serious gap in the Staff Proposal. Filling this gap will be particularly important in the area of energy efficiency because, as the Staff Proposal notes, relying solely on ratepayer-funded programs to achieve the transformation sought by the REV will not be a successful strategy. The creation of appropriate incentives for “third party providers and customers to pursue innovative efficiency methods,” which Direct Energy supports, will not be enough to entice private capital into the New York market for energy efficiency without solid assurances that efforts to make use of those incentives will not be thwarted by unfair competition from the DSP.

Curiously, the development of the utilities’ Energy Efficiency Transition Implementation

Plans (ETIPs), which would be a natural place to address this basic issue of market integrity, neither addresses the issue nor invites participation from third parties, as does many other parts of the REV implementation plan set forth in the Staff Proposal. Direct Energy encourages the

Commission to make the development of utility ETIPs the subject of a stakeholder process that would address concern about DSP market power in the provision of energy efficiency products and services.

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Section V.B. Demonstration Projects

The Staff Proposal sets forth the following description of and justification for demonstration projects related to the REV objectives:

While many of the technologies needed to develop a DSP are available today, further technology integration and validation is needed to demonstrate and fully implement DSP functionalities. Development of mature DSP functionalities will involve technology and programmatic choices that can be better informed through data acquired from selective demonstration projects. Demonstrations can also serve to measure and predict customer responses to programs and prices associated with future DSP markets.

Generally, staff defines demonstration projects as those focused on beta-testing DER provider and utility DER services with a limited group of customers. . . .

Staff Proposal at 55-56.

As stated in our July 18 responses to the Track 1 briefing questions, Direct Energy strongly supports the use of demonstration projects as described in the Staff Proposal. The criteria that would be used to guide investments in demonstration projects are also sensible, consisting of the following: (1) directly related to the six REV policy objectives; (2) scalable; (3) replicable; (4) technology neutral; (5) consistent with a portfolio approach to integrate all types of DER; (6) expedient; (7) having well-defined and measurable outputs; (8) having a defined method for value exchange; and (9) favoring partnerships with third parties. In addition to providing critical information and experience that can inform the ongoing development of the

DSP platform and market design, the use of demonstration projects should allow utilities acting as DSPs to begin to allay concerns regarding their multiple roles as market maker, distribution system operator and active market participant. In other words, demonstration projects can be used as a test bed not only for DER technologies and the DSP platform but also for the regulatory structures that will allow private capital to invest with confidence in the new DSP markets.

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Direct Energy looks forward to working with DSPs and Staff to propose specific demonstration projects as the REV process moves forward. We suggest that the Commission establish a more formal structure for proposing and vetting demonstration projects, which structure could be developed as part of the Technical Platform and Market Design stakeholder processes.

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Section V.E. Demand Response Tariffs

In response to the court ruling that vacated FERC Order 745, the Staff Proposal makes the following recommendation:

[T]he Commission should direct a process in which stakeholders work with distribution utilities, Staff and the NYISO to immediately develop programs that allow demand response providers, interfacing with the distribution utilities, to respond to bulk power system needs currently addressed by the NYISO’s Special Case Resource (SCR) and Emergency Demand Response Programs. Staff intends to immediately convene discussion with utilities and stakeholders to begin the development of the programs.

Staff Proposal at 63.

While we agree that the Commission should monitor the status of FERC Order 745 closely and be prepared to take action should there ultimately be a permanent impairment of the

NYISO’s ability to operate its demand response programs, we are not convinced that having all of the utilities develop DR tariffs is an appropriate response to the situation at this time. This is especially true if the utility DR tariffs are meant to go beyond the reliability programs currently operated by the NYISO (and Consolidated Edison, for that matter) and into the realm of purely economic DR. (This appears to be the case, as “economic demand response” is listed in the Staff

Proposal as one of the functions of the utility in its role as DSP. Staff Proposal at 20, Table 1.)

There are many interpretations of the impact of the DC Circuit’s May 23, 2014 decision on the DR market in the RTOs subject to FERC jurisdiction, and we tend to agree with those who see it as having a more limited impact than that envisioned by the Staff Proposal. As the

Proposal notes, the court’s decision implicates FERC’s jurisdiction over DR to the extent it is a retail product, which would be subject to state control. If upheld, the decision might prevent

NYISO from allowing retail customers to participate directly in its reliability DR programs, the

Special Case Resource and Emergency Demand Response Program. In our view, even this result might not have a major impact on the DR market in New York, for several reasons. First, one

25 interpretation of the DC Circuit’s decision is that it would not affect in any way the ability of demand response providers (like Direct Energy) that are load serving entities from continuing to interact with the NYISO as they do today. When Direct Energy or another DR provider aggregates DR assets and incorporates them into its portfolio of resources that it bids into the

ISO markets, it is engaging in wholesale activities over which FERC and the NYISO have clear jurisdiction. There is no reason to believe the DC Circuit’s decision would prevent these activities from continuing.

Second, regardless of the ultimate disposition of the DC Circuit’s decision,9 the NYISO will remain a single-state ISO which, in conjunction with the Commission, has sufficient authority to ensure the reliability of the grid. Should the NYISO lose the ability to operate its reliability DR programs as it does today, in our reading there is nothing in the DC Circuit’s decision that would prevent the Commission (which would, by definition, have jurisdiction over whatever aspect of the NYISO programs that had been found to be retail in nature and, thus, outside the jurisdiction of the NYISO) from delegating to the NYISO the authority to operate the

DR programs required to maintain the reliability of the grid. In this view (which we acknowledge that everyone might not share), the affirmation of the DC Circuit’s decision would only be a problem for the NYISO DR programs if the Commission decides to make it a problem.

While it is generally true that uncertainty creates risk and risk is unhelpful to DR providers, it is also true that one should avoid liquidating a particular element of risk in a manner that creates even greater uncertainty and risk. The alacrity with which Staff intends to involve the utilities more directly in the DR market could cause as much concern as the DC Circuit’s

9 The Court of Appeals denied requests for rehearing in this matter on September 17, meaning that the court’s decision will remain in effect unless any parties seek and obtain a writ of certiorari from the U.S. Supreme Court. 26 decision itself.10 We look forward to finding out more about how Staff intends to proceed in this matter once the discussions among utilities and stakeholders mentioned in the Staff Proposal begin in earnest.

10 On this point, the ambiguity of the language used in the Staff Proposal may be creating unwarranted concern. At page 63, the Staff Proposal states, with respect to the proposed utility DR programs, that “Staff intends to immediately convene discussion with utilities and stakeholders to begin the development of the programs.” In this context, it is difficult not to interpret the term “immediately” as meaning just that, as in “right now,” rather than “immediately following a Commission order in this matter.” Clarification would be helpful on the question of whether this is a correct interpretation and, if so, under what authority Staff will proceed on this point in advance of Commission action. 27

Section V.F.2. Planning REV Implementation – DSP Platform and Market Vision Planning

The Staff Proposal lays out a plan for implementing the DSP Platform and Market vision that appropriately includes recognition of the importance of standardization among the various

DSP markets in order to attract participation by DER providers. For large, integrated companies like Direct Energy, which do business in a number of different markets, standardization is critical to avoiding unnecessary and counter-productive processes that erect barriers to providing a robust suite of products and services to customers in those markets. The Staff Proposal describes three stakeholder processes to achieve this goal, including a Technical Platform Design

Stakeholder Process, a Market Design Stakeholder Process, and a Jointly Filed Uniform DSP plan, which would be developed through a stakeholder process.

While Direct Energy supports the goal of standardization and using stakeholder processes to do this important work, we also strongly support the recommendation of the New York State

Smart Grid Consortium that these three processes should be combined into a single, integrated stakeholder process. The subjects of the three stakeholder processes laid out in the Staff

Proposal are deeply inter-related, with decisions made in each feeding back into the other processes. We fear that having separate processes could lead to inefficiency and make the overall process more time-consuming than necessary. Having a single, integrated process will also allow more extensive and meaningful participation by stakeholders who may not have the resources to cover three separate processes, especially if they are run concurrently.

We also support the Consortium’s recommendation that the Consortium lead such an integrated stakeholder process that would address the issues of the technical platform, market design, and the content of the jointly filed DSP plans. The Consortium is well-suited to lead this effort, including, as it does, the New York utilities and power authorities, State policy makers,

28 the New York Independent System Operator, global grid technology companies, NYSERDA, the

Brookhaven National Laboratory, and the State’s leading universities. Direct Energy believes the processes described by the Consortium would give New York would allow for the development of the key parts of the REV architecture in a manner that would be open, inclusive, collaborative, and transparent, and we would be pleased to participate actively in such a process.

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Section VI – Mitigating Market Power

While this is a critical issue for Commission decision, Direct Energy will attempt to heed the requests of the ALJs in this case to avoid duplicative comments where possible. As a member of RESA and IPPNY, both of which will provide extensive comments on this issue,

Direct Energy believes its views on the subject are well-represented and we will not belabor those arguments here. We would like to provide our view on what may be a misconception on the part of Staff that the perceived competitive threat from utility affiliates is “at least equivalent to” the perceived competitive threat from a distribution utility engaging in competitive activities in its own right and recovering the costs through rate base. At page 73, the Staff Proposal states:

“Unregulated utility affiliates present a different question [from direct utility ownership]. In some respects the market power concern is at least equivalent, as the prospect of an affiliate earning unregulated returns increases the utility’s incentive to favor the affiliate’s product, or to delay system improvements on circuits where the affiliate enjoys revenues.”

Speaking only for itself, Direct Energy sees the competitive threat from having regulated utilities undertake competitive activities in their own right, collecting the costs through rate base and possibly sharing in the upside of such activities, as of far greater concern than the competitive threat from utility affiliates.11 The logic on this point is simple: anything a utility might do to favor an affiliate it can do to favor itself, in a manner that will be much more difficult to prevent and detect. Moreover, where the possibility exists for a utility to share in the upside of a what should be a competitive activity, the utility’s competitive edge is even more pernicious than that of a utility affiliate, as the utility is protected from downside risk by its regulated rate recovery, an advantage not shared by a utility affiliate that is subject to appropriate

11 We note that RESA has several members in good standing that are utility affiliates, including ConEdison Solutions, and that among the representatives of those utility affiliates (once again, including ConEdison Solutions) are some of the most effective advocates on competitive matters working in the industry today. 30 cost allocation practices. This concern leads Direct Energy to subscribe to the “Yellow Pages” test for whether a particular activity should be done the utility or (if at all) by a utility affiliate. If you can find a listing in the Yellow Pages (or whatever the current electronic equivalent might be), that activity is better performed by a utility affiliate than by the utility itself. We believe that rule of thumb should apply to DER as well.

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Conclusion

Direct Energy continues to look forward to working with the Commission, Staff and

other stakeholders to bring about the transformative change described in the Staff Proposal. We

appreciate the opportunity to provide these comments at this stage of the proceeding.

Respectfully submitted,

Direct Energy

______Christopher H. Kallaher Senior Director, Gov’t and Regulatory Affairs

162 Cypress Street Brookline, 02445 (617) 879-0668 (617) 462-6297 [email protected]

Dated: September 22, 2014

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