ELECTRICITY DISTRIBUTORS…

ELECTRICITY DISTRIBUTORS ASSOCIATION

 

2017 LONG-TERM ENERGY PLAN SUBMISSION

 

TABLE OF CONTENTS

 

Introduction        Pg. 3

 

Expanding Conservation and Integrating Climate ChangePg. 4

 

Success as Conservation Leaders

 

Target and Budget Parameters

 

Redefining Conservation

 

Enhancing Residential Conservation Programs

 

Strengthening the Framework

 

Expanding the Conservation First Framework

 

Integrating the Climate Change Action Plan

 

Other Priorities

 

Pursuing Further Efficiencies and SavingsPg. 11

 

Revising the RRRP Program

 

Regulatory Modernization and Streamlining

 

Coordinating Billing Changes

 

Phasing Out the Smart Metering Charge

 

Facilitating Partnerships         Pg. 18

 

Partnering on Innovation

 

Tax Certainty and Clarity

 

Driving Innovation         Pg. 19

 

Supporting Net Metering and Distributed Energy

 

Preparing for Electrification

 

Conclusion         Pg. 21

 

Appendix 1: Summary of EDA Recommendations Pg. 22

 

Appendix 2: Delivering Innovation – LDC Experiences  Pg. 26

 

 

 

INTRODUCTION

 

The Electricity Distributors Association (EDA) is pleased to provide input and strategic advice on the development of Ontario’s 2017 Long-Term Energy Plan (LTEP). The EDA is the voice of Ontario’s local electricity distribution sector, which consists of municipally and privately owned local distribution companies (LDCs). The distribution sector employs over 10,000 people directly and makes hundreds of millions annually in direct contributions to municipal and provincial revenues. LDCs deliver electricity to over 5 million residential, commercial, industrial, and institutional customers across Ontario and therefore are the trusted face of the electricity system for customers.

 

Over the last 10 years, there have been substantial changes to the electricity sector in Ontario. Developments such as the implementation of the Green Energy and Green Economy Act, 2009, growth of distributed energy, delivery of the Ontario Clean Energy Benefit and phase-out of the Debt Retirement Charge have had significant impact on LDCs and customers

 

According to the Independent Electricity System Operator’s (IESO) Ontario Planning Outlook (OPO), the electricity system is “well positioned to continue to meet provincial needs … while adapting to significant change across the sector”. As such, supply is not an immediate concern.

 

However, innovation, increased customer participation and policy decisions continue to modernize the electricity system, moving Ontario away from a system that has been characterized by a one-way flow of electricity. Policies related to the Climate Change Action Plan (CCAP), such as electrification, will also greatly impact the system. Outlooks C and D in OPO could return Ontario to a “winter-peaking jurisdiction”. All these changes will deeply affect the distribution of electricity. Consequently, the successful delivery of government policy priorities and innovation will depend inherently on strengthening, modernizing, and empowering Ontario’s distribution sector.

 

Therefore, the EDA recommends that the 2017 LTEP focus on: (I) Expanding conservation and integrating climate change; (II) Pursuing further efficiencies and savings; (III) Supporting partnerships; and (IV) Driving innovation.

 

 

 

I.EXPANDING CONSERVATION AND INTEGRATING CLIMATE CHANGE:

 

In the 2013 Long-Term Energy Plan, the Government of Ontario adopted a policy to put “Conservation First” before building new energy infrastructure, where cost-effective. Prior to that, the Green Energy and Green Economy Act, 2009 and the 2010 LTEP also pursued energy efficiency programs as a means to encourage Ontarians to conserve their energy usage and avoid building unnecessary expensive infrastructure. Conservation remains the cleanest and most cost-effective energy resource for the province of Ontario. Conservation can also be a means for households and businesses to manage their energy usage.

 

A significant portion of the reduction in Ontario’s gross demand between 2005 and 2015 has been due to the implementation of conservation programs. Per the Ministry of Energy’s Conservation First vision paper, conservation investments have helped Ontario avoid building new capacity that would have cost almost $4 billion, equivalent to four peaking natural gas generation plants.

 

LDCs continue to demonstrate leadership and pursue innovation in designing and delivering conservation programs across the province to all customer segments. However, there are opportunities to enhance conservation efforts, supporting the government’s commitment to utilizing conservation as a cost-effective energy resource.

 

SUCCESS AS CONSERVATION LEADERS

 

A considerable amount of the conservation success has been the result of the leadership of Ontario’s LDCs in designing and delivering conservation and demand management (CDM) programs to Ontario’s households, businesses, and industries.

 

During the 2011-2014 CDM Framework, LDCs successfully achieved 108% of the province’s 6000 GWh target set by the IESO. Currently, LDCs are nearly one-third of the way through the 2015-2020 Conservation First Framework (CFF), which has a target of 7,000 GWh (or 7 TWh) of persistent energy savings. As of the end of 2015, LDCs achieved 1.1 GWh of verified energy savings, which represents 16% of the province’s target.

 

LDCs have successfully leveraged their existing customer relationships to deliver the province-wide programs to their customers. In addition to the province-wide programs, LDCs have also designed several local pilots and programs under the current framework that are currently in market or are being approved by the IESO. To date, 8 local programs and 30 LDC pilots have been approved by the IESO under the CFF to be deployed in various LDC territories which furthers a culture of conservation amongst customers.

 

Several LDCs actively participate in the IESO’s conservation working groups, which continue to meet on a regular basis to review progress, recommend program improvements and discuss new program design and delivery.  LDCs are committed to conservation and continue to work collaboratively with the IESO and gas utilities to design and deliver conservation programs to foster a culture of conservation in the province.

 

Given the success of cost-effective conservation that has deferred or avoided the need for new generation infrastructure in the province, the EDA recommends that the government reaffirm its commitment to putting ”Conservation First”.

 

TARGET AND BUDGET PARAMETERS

 

Under current and previous frameworks, LDCs were provided with a fixed target and a fixed budget to deliver programs cost-effectively. The current parameters, however, are a disincentive for LDCs to deliver programs that have a higher upfront acquisition cost and are therefore not cost-effective the year of installation but passes the Total Resource Cost (TRC) test over the program savings.

 

For example, the residential HVAC rebate program costs more than $0.40 per kWh on a first-year energy savings basis (which aligns with how LDC budgets are allocated), but is cost-effective due to the long useful life of furnaces and air conditioners and therefore the persistence of energy savings.

 

The EDA recommends that the current budget structure be reviewed to remove disincentives to delivering programs with high upfront costs. The assigned budgets and targets should also be reviewed periodically and rolled forward as LDCs continue to deliver CDM. This will not only reaffirm the province’s commitment towards conservation as a more cost-effective tool than generation, but also encourage LDCs to further design conservation programs with deeper long-term savings.

 

REDEFINING CONSERVATION

 

There is increasing opportunities for LDCs to be innovative in daily operations, including designing and delivering conservation programs. However, based on the current definition of conservation as set in the Minister of Energy’s 2014 Directive to the Ontario Power Authority (now the IESO), many of these innovative programs are not being attributed towards LDCs’ conservation targets. Such programs include measures LDCs can implement within their own system to reduce consumption or support customers who generate and store their own electricity, thus taking pressure off the grid.

 

Programs at the distribution level, such as conservation voltage reduction (CVR) and line loss reduction, can not only reduce peak demand pressures off the grid, but also increase grid reliability and efficiency and improve power quality for the customer. A measure like CVR has proven to save 4-6% of energy usage and could potentially reduce energy consumption in the province to levels equivalent to the LDCs’ annual conservation targets under the CFF. Measures at the distribution level (i.e. in front of the meter not just behind the meter) can also help defer capital investments by LDCs and by the province.

 

Through the IESO Conservation Fund and the government’s Smart Grid Fund, several LDCs have developed and delivered unique programs to reduce voltage in the home without impacting the customer’s experience or initiated programs that minimize line losses to reduce distribution losses. However, as mentioned, energy savings from these programs and others are not included in an LDC’s conservation targets since programs that have system benefits are not included in the current definition of conservation that is established in the Minister’s 2014 Directive. Such programs allow LDCs to be more innovative to reduce pressures on their distribution systems, thus improving the quality and reliability of the grid.

 

Therefore, the EDA recommends that the Minister provide direction to expand the definition of conservation to include programs and measures at the distribution level.

 

Customers are looking for innovative ways of combining behind-the-meter renewable energy installations such as rooftop solar installations with conventional conservation measures. However, current restrictions do not allow customers with the choice of going through a micro-generation program or through a conservation program. Therefore, the EDA recommends that the Ministry review the definition of conservation and direct the IESO accordingly to amend their interpretation of what projects should be included in conservation results. Customers should be able to install renewable generation in their homes under a micro-generation program or as part of a conservation retrofit, if the customer is not “double dipping” under both programs. This will allow LDCs to implement a combined program in the customer’s home or business and count it towards their conservation targets and the customer will see savings on their electricity bill.

 

There is currently a misalignment in how the IESO is expressing conservation targets for the purposes of power system planning versus for contracting with LDCs for CDM delivery. In the current LTEP, the 7 TWh refers to energy saving at the generator level, consistent with all other supply resources within the power system plan. The quarterly Ontario Energy Report reports progress against the 7 TWh target at the generator level.  However, the Conservation Division with the IESO is expressing individual LDCs targets for CDM at the end-user level (i.e. excluding avoided transmission and distribution losses).  The IESO and Ministry should confirm that LDC targets, as already established, should be taken to be at the generator level.

 

ENHANCING RESIDENTIAL CONSERVATION PROGRAMS

 

The energy savings contribution from province-wide residential conservation programs are considerably lower than the business or industrial savings. In the 2011-2014 CDM Framework, residential programs contributed 1,170 GWh of energy savings while the Business programs contributed almost 4 times as much results at almost 4,100 GWh. The province-wide business programs have seen considerable success in terms of uptake and contribution to LDC targets and have also been revised periodically to meet changes in technology and improve customer participation. LDCs would like to see the same level of success for residential programs as households continue to see the largest impact from rising electricity prices. Participation in conservation will provide them with tools to better manage their consumptions.

 

To enhance the availability and variety of residential conservation programs, the EDA makes the following recommendations:

 

•The IESO’s current process for reviewing and approving local programs and pilots takes a considerable amount of time, often leading to loss of momentum and potential savings. For example, Niagara Peninsula Energy’s Energy Concierge Pilot Program, which came into market in 2016, took the 18 months to approve. The IESO’s approval process for local programs and pilots should be further streamlined so LDCs can be out in the market faster to engage customers.

 

•Some residential program ideas that have been discussed at working groups or developed by LDCs may not get approval from the IESO to move ahead because they don’t meet the current Total Resource Cost (TRC) threshold. The IESO should work with LDCs to review residential programs that may have potential for significant uptake and customer engagement and lower the TRC threshold for such programs as appropriate. This may lead to LDCs launching/rolling out more social benchmarking initiatives that are not necessarily TRC positive but can drive behavioural changes in customers and encourage them to monitor their consumption and participate in more traditional conservation programs.

 

•To support increased participation in conservation, the government should dedicate a portion of the cap and trade proceeds to fund for residential programs, including increasing events and communication.

 

STRENGTHENING THE FRAMEWORK

 

Aspects of the current regulatory framework create challenges for LDCs to design and deliver conservation. The Minister of Energy’s 2014 Directive that established the 2015-2020 CFF encouraged increased collaboration between LDCs and gas companies to design and deliver electricity conservation and gas demand management programs to customers. The LDC framework is overseen by the IESO while the OEB oversees the DSM framework, making it difficult for LDCs and gas utilities to collaborate as their requirements are different under their frameworks.

 

The EDA recommends that during the upcoming Mid-Term Review, the OEB and the IESO should collaborate in finding common elements that will encourage LDCs and the gas companies to collaborate further in the second half of their frameworks.

 

The current development and implementation of the Whole Home Pilot Program is being overseen by the IESO and being delivered by the gas utilities, with LDCs getting involved marginally in the marketing of the program. The arrangement for the gas utilities to lead the delivery of this pilot was set up without consultation with the LDCs, even though the pilot includes both gas and electricity savings.

 

The EDA encourages government and the IESO to engage LDCs in any future discussions that involve collaboration with gas utilities. Furthermore, the EDA recommends that the IESO be directed to work with LDCs and gas utilities to develop a memorandum of understanding to foster a more streamlined approach to LDC-gas program collaboration which is beneficial to all parties, including the customer.

 

EXTENDING THE CONSERVATION FIRST FRAMEWORK

 

In the Ministry of Energy’s paper, Conservation First: A Renewed Vision for Energy Conservation in Ontario, the government made the commitment that conservation would be a long-term resource that was central to the electricity planning process and that there would be opportunities to find deeper and more sustainable savings to further promote a culture of conservation.

 

LDCs continue to see considerable interest from large commercial, institutional, and industrial customers in multi-year conservation programs that will yield significant energy savings for the province. However, many of these long-term projects such as combined heat and power generation, construction of new housing subdivisions and large process and systems upgrade projects are multi-year commitments that go beyond the current framework termination date of 2020. As such, LDCs are currently forced to forgo these opportunities to sign up customers as there is no guarantee of a future conservation framework beyond 2020. LDCs are concerned about the loss of valuable energy savings opportunities given this uncertainty.

 

To provide certainty for long-term conservation initiatives, the Ministry should extend the 2015-2020 Conservation First Framework immediately. The process for extending the framework should be streamlined to avoid major disruptions to LDCs and to customers. This will provide assurance to both large customers and LDCs that they can commit to large conservation projects and bring in more energy savings for the province.

 

INTEGRATING THE CLIMATE CHANGE ACTION PLAN

 

The Climate Change Action Plan (CCAP) will greatly impact LDCs, including the delivery of conservation programs and achievement of targets in the second half of the CFF.

 

The government, through the Green Bank, will collect the proceeds from the cap and trade program and provide financing for tools and incentives for residential and business customers to undertake several initiatives to reduce greenhouse gas emissions. These initiatives include financing the purchase of net zero homes (funding of $180-220 million); installation and retrofits of homes and businesses, including social housing complexes, with clean-energy systems such as advanced insulation and heat pumps (funding: $600-800 million); and free energy audits for pre-sale homes (funding: $200-250 million).

 

However, many of these initiatives are already being implemented under the province-wide programs of the CFF and therefore will be impacted by the CCAP. LDCs are concerned that implementation and funding for these initiatives under the CCAP may lead to increased customer confusion, potential duplication, and program erosion.

 

The current conservation framework is recognized and trusted by Ontario consumers. Therefore, the EDA recommends that the province leverage the existing conservation infrastructure to deliver CCAP programs as it will be more cost-effective than building a new governance and program delivery structure.  The government should align conservation goals with CCAP objectives to mitigate confusion and ensure conservation targets are not negatively impacted.

 

The CCAP’s cap and trade regulation, finalized in May, will have an impact on the 2015-2020 Conservation First results. Under the final regulation, combined heat and power (CHP) generation projects under 10 kt/year will not be eligible for free allowances and therefore will face increased costs that may discourage customers from participating in CHP projects under the province-wide Process Systems Upgrade (PSU) program. CHP projects are a key component of many LDCs’ CDM plans and those LDCs with smaller sized projects can potentially see lower results and may not meet their six year targets.

 

The cap and trade regulation was not considered in the previous Achievable Potential Study. While the IESO will be considering the implications of the regulation in the upcoming Mid-Term Review, the EDA recommends that the Ministry take into consideration the impact of the cap and trade regulation on its long-term projections of conservation savings.

 

OTHER PRIORITIES

 

RPP Pilots: The OEB is currently reviewing the current Time-Of-Use (TOU) pricing structure and has given LDCs the opportunity to design and run TOU pilots to explore new pricing structures and non-pricing initiatives that support innovation and empower customers. The EDA recommends that the government recognize the energy savings arising from pricing structures and non-pricing pilots as contributing towards those LDC’s conservation targets and provide appropriate direction to the IESO and the OEB that those results are attributed appropriately.

 

Industrial Conservation Initiative: The Ministry of Energy, as part of their on-going strategy to mitigate rising electricity costs, has amended the Industrial Conservation Initiative (ICI) to expand the threshold to include all customers above 1 MW of peak demand. While the industry is supportive of the enhancement, there is concern that some large customers who are at the 1 MW threshold will now be discouraged from participating in conservation programs if participation reduces their peak demand to below 1 MW, thus rendering them ineligible for the ICI. The EDA therefore recommends that the LTEP include direction that the ICI regulation be amended to allow customers to opt in to the ICI even if participation in conservation reduces their peak load.

 

Regional Constraints: The EDA would also like to note that in certain LDCs’ jurisdictions, large industrial conservation projects such as CHPs have been scaled back or postponed because of transmission constraints. The EDA recommends that regional issues, such as economic conditions and transmission constraints, be factored in the LTEP conservation projections.

 

II.PURSUING FURTHER EFFICIENCIES AND SAVINGS

 

The distribution portion of the electricity bill is approximately 20 per cent for the average residential customer bill in Ontario (assuming 750 kWh monthly consumption). It is approximately between 5 and 15 per cent for businesses with over 50 kW of demand.

 

In contrast to generation, distribution costs for almost all LDCs (excluding Hydro One) have largely stayed in line with the Consumer Price Index (CPI). Below is an illustrative example from one of our medium-sized members:

 

MEDIUM-SIZED LDC: TOU RATES VS. CPI ADJUSTED RATES (2006-2015)

 

As per the 2013 LTEP, Module 4: Cost of Electricity Service chart from the IESO, forecast increases in distribution costs are largely attributable to forecast household growth.

 

Nonetheless, LDCs continue to take the initiative to pursue operational and administrative efficiencies, such as shared services, that support reliability and avoid costs for ratepayers. For example, one medium-sized LDC partnered with another LDC on a control room, avoiding an investment of almost $1 million and on-going costs of approximately $450,000 annually.

 

LDCs are supportive of the government’s objective to mitigate rising electricity prices. While the delivery charge represents one-fifth of the average bill, the EDA recognizes that we can all further contribute to cultivating efficiencies that can reduce the impact to ratepayers of increasing electricity and Global Adjustment costs. Specifically, there are four areas in which savings can be achieved, while maintaining reliability and supporting innovation.

 

REVISING THE RRRP PROGRAM

 

In the 2016 Throne Speech, the government announced enhancements to the Rural or Remote Rate Protection (RRRP) program, increasing the amount of assistance eligible rural ratepayers would receive. The total amount of rate protection for eligible consumers would increase from a maximum of $127 million to a maximum of $237 million each year.

 

There are approximately 330,000 customers who receive Rural or Remote Rate Protection (RRRP) in four LDC service areas, Hydro One Networks, Hydro One Remote Communities, First Nation LDCs and Algoma Power.

 

As per the OEB’s 2016 rate order on RRRP, all customers, including those who are RRRP eligible, are charged a $0.0013 per KWh on their monthly consumption. The collected funds are transferred by all LDCs to the IESO, who transfers it directly to the four LDCs whose customers are eligible for this rate protection. The credit appears directly on those eligible customers’ bills.

 

In 2016, the cost of the RRRP will be approximately $175.5 million. The current monthly contribution per household is approximately $0.975 per month ($11.70 per year) towards the RRRP.

 

The average monthly RRRP charge for each customer in 2017 would be $0.0021 based on similar demand forecast. With the enhancement announced by the Ministry of Energy, the RRRP charge on the average monthly bill will increase by about $0.60 per month, or over 60 per cent.

 

Using Ministry of Energy estimates and adding an approximate $0.60 increase, the monthly RRRP charge in 2017 will be $1.58 per month (or $18.96 per year).

 

Current RRRPEnhanced RRRPDifference:

 

Per Household$0.975/month ($11.70/year)$1.58/month ($18.96/year)Over 60 % increase

 

While the EDA recognizes and supports the government’s commitment to assist customers in rural communities, the EDA is concerned that all ratepayers bear the cost of this social policy. Therefore, the EDA recommends that the government fund the RRRP through the tax base. This would bring the RRRP in line with a similar energy program, the Northern Ontario Energy Credit (NOEC) which helps Northern Ontario residents with the higher energy costs. The credit is part of the Ontario Trillium Benefit.

 

We believe the government should have a consistent approach to providing electricity relief for customers who face unique regional circumstances. The government should deliver RRRP through the tax base, consistent with the delivery of the Northern Ontario Energy Credit, which would result in savings for the average residential customer of almost $20 per year.

 

REGULATORY MODERNIZATION AND STREAMLINING

 

A modern, innovative electricity distribution sector is pivotal to the successful adoption of technology changes and integration of increased distributed energy resources. LDCs are eager serve customers in more innovative ways and pursue new business opportunities. However, the pursuit of innovation and modernization by LDCs has been deterred by compounding regulatory requirements and government policy decisions.

 

Ontario needs a strong, streamlined, modern regulatory framework that can support future changes to the electricity system such as the growth of distributed energy resources, modernization of the grid, electricity storage and emissions reductions.

 

As noted in a previous EDA report, The Case for Reform: How Regulatory Streamlining Could Benefit Ontario’s Electricity Consumers, the following Guiding Principles should govern the streamlining of regulatory requirements:

 

•There is a need to balance costs of regulation with the benefits to customers;

 

•The amount of regulation and reporting requirements should be proportionate to the policy objective/outcome;

 

•More emphasis should be placed on policy outcomes, not process;

 

•Duplication and overlap of reporting requirements should be eliminated;

 

•Administrative burden to LDCs should be minimized, streamlined;

 

•Distributors should be provided flexibility to address their local circumstances; •Distributors should not be involved in addressing social problems;

 

•Distributors should be allowed to recover their costs to address aging infrastructure in a timely manner;

 

•Increased certainty and transparency should be provided for cost recovery by distributors; and •Decision-making by regulators needs to be timely.

 

Unfortunately, the OEB’s current Renewed Regulatory Framework for Electricity (RRFE), does not currently reflect these Guiding Principles. Rather, LDCs have seen a significant increase in the cost and resources associated with regulatory filings.  For example:

 

•A medium-sized LDC spent the equivalence of almost 1,000 business days on its 2016 Cost of Service (COS) rate application.

 

•For several LDCs, the cost of preparing recent COS rate applications increased over 200% while the costs for a few LDCs increased over 300% because of increased reporting requirements. In one example, an LDC saw the cost of its COS application increase by over 200% even without an OEB oral hearing on the application.

 

•A medium-sized LDC’s application and interrogatory responses totaled almost 3,500 pages.

 

Based on a canvass of our members, the EDA found that the cost of recent COS applications had increased significantly compared to previous applications. The below chart illustrates the costs incurred by ten LDCs of varying sizes:

 

The COS process has become increasingly onerous. Document requirements such as the Distribution System Plan (DSP) and Lead Lag Study are costly and complex.  Given the technical complexity of distribution system planning, customer consultation on technical documents such as the DSP has limited value.

 

In addition to rate applications, LDCs are also required to prepare quarterly and annual reports for the OEB under its Reporting & Record Keeping Requirements (RRR). While the OEB has automated some aspects of these reports, the requirements are onerous and repetitive. The cost-benefit of some of these requirements is unclear.

 

Currently, the regulator scrutinizes the costs of delivery, but doesn't evaluate or consider the increasing costs to distributors of preparing and defending regulatory submissions.  LDCs also incur significant costs satisfying OEB and intervenor requirements to provide hard copies of documents.  In this day and age, distribution of documents electronically should be the standard. If hard copies are required, parties should pay for printing themselves, not the ratepayers or LDCs.

 

To help distributors be more competitive and pursue innovative opportunities, the government should promptly review regulatory requirements with a view to simplifying the process, modernizing the requirements, making it more customer friendly, and reducing unnecessary costs.

 

The EDA recommends:

 

•Year over year, new requirements have been placed on LDCs resulting in increased costs to consumers. The government should immediately expand the scope of the Ministry of Economic Development, Trade and Employment's Burden Reduction Strategy to consider the regulatory requirements placed on distributors and provide independent recommendations for streamlining requirements.  This review should also be prioritized.

 

•Regulations should be reviewed and modernized to enable innovation, including the consideration of distributors providing specific services to each other, without the need to get OEB pre-approval.

 

•While the OEB has made an effort to streamline quarterly and annual reporting requirements, there is more work to be done. OEB should phase-out quarterly RRR filing requirements.

 

•All regulatory requirements from the OEB should provide a cost-benefit analysis for customers and distributors.

 

•As part of the OEB’s commitment to facilitate consumer engagement, the filing guidelines should be simplified to make the submissions consumer-friendly.

 

•In harmony with the government’s Digital Strategy, the regulator should immediately move to eliminate the requirement for LDCs to submit hard copies of applications and reports. This initiative will reduce hundreds of thousands of dollars of printing costs incurred by LDCs.

 

COORDINATING BILLING CHANGES

 

In the last 10 years, LDCs have made dozens of costly last-minute adjustments to the Customer Information Systems (CIS) to accommodate government policy direction. Bill design revisions are imposed upon LDCs with little or no consideration for the associated costs and interruptions to business processes.

 

These changes have included:

 

•Ontario Clean Energy Benefit (OCEB): LDCs had less than eight weeks to implement the OCEB, which included a separate line, on-bill and envelope messaging, and bill inserts.

 

•Measurement Canada Compliance: LDCs had to make changes on their bill presentment to meet registered read requirements set by Measurement Canada.

 

•Line Loss: The government changed the presentation of line loss so it now appears as part of the delivery line vs. being a separate line item.

 

•Customer Service Rule Changes: LDCs were directed to make necessary CIS changes related to deposits, disconnections and other customer service provisions.

 

•Ontario Electricity Support Program (OESP): LDCs made CIS changes to accommodate the implementation of the OESP in 2016.

 

•Monthly Billing: In 2015, OEB mandated that all LDCs transition to monthly billing. •Fixed Delivery Cost: As LDCs move to a fixed charge, CIS changes will be necessary. •Retailer Adjustments: OEB mandated several changes for LDCs to make on their bills to make retailer information more visible for customers.

 

•Removal of the Debt Retirement Charge (DRC): Despite the removal of the DRC from the bill, LDCs are still required by government to provide a separate line item and an on-bill message reminding customers of the avoided cost.

 

•HST Rebate: This will appear on bills beginning in 2017. LDCs had less than two months to make the complex CIS changes. LDCs will also incur the cost of ordering new envelopes and printing new bill inserts in response to the government’s requirements. Delivery of this initiative will also require LDCs to inform, identify and enroll applicable commercial and industrial customers.

 

Although LDCs were supportive of most of the policy changes identified above, it must be noted that each change related to customer billing diverts LDC business processes and costs thousands of dollars in changes to billing systems. LDCs incur additional costs related to envelopes, printing, mailing and inserts. LDCs also divert resources to rapidly train customer service and billing representatives to respond to increased customer queries.

 

Pacing the implementation of CIS changes would reduce interruptions and costs. For example, the Ontario Regulatory Policy requires regulations impacting business generally come into effect twice a year. Therefore, the EDA encourages the government to take into consideration the cost and impact of CIS updates when determining timeframes for the implementation of government policy. To minimize cost and business interruptions, the EDA recommends that the Ministry work closely with LDCs to pace the implementation of CIS changes.

 

PHASING OUT THE SMART METERING CHARGE

 

Currently, each customer pays approximately $0.80 per month for Ontario’s “Smart Metering Charge” (SMC) which funds the expenses of the central Meter Data Management and Repository (MDM/R). According to the IESO, the SMC will have covered all related expenses to the MDM/R by October 2018. The IESO is currently considering ways to expand the MDM/R beyond its original functionalities. The OEB recently approved a 5-year extension of the Smart Metering Entity’s (SME) license to allow IESO to identify uses that “unlock further value” in the MDM/R.

 

The EDA is confident that unlocking further value of LDC customer data, while balancing privacy and security, can be done more efficiently, effectively and at a lower cost, if the responsibility were transferred to LDCs. Customers trust LDCs to protect their interests. All LDCs take this responsibility seriously, therefore if the government’s objective is to “unlock further value” by providing access to third parties for analytical and academic purposes, it must be done with LDCs playing a leading role, otherwise the customer trust will not exist.

 

The MDM/R is complex for billing purposes and requires synchronization back to a LDC’s CIS. It also requires duplication/ transmission of daily residential customer’s interval data to a central repository.  LDCs currently bill commercial and industrial customers without use of the MDM/R and there are no barriers to billing residential customers directly.

 

LDCs have either an in-house Operational Data Store (ODS) system or rely on a 3rd party ODS providers (such as Savage Data Systems, Utilismart) for operational purposes and that could now be extended for residential billing without a requirement for the MDM/R.

 

The Green Button open standard exchange platform (multi-vendor) can provide province-wide reporting, data aggregation, analytics, scaling for near real time data, and supporting both residential and C&I customers as an alternative to expanding the MDM/R.

 

Based on our analysis, the EDA recommends allowing LDCs to perform the same, and additional, functions as the MDM/R but at lower cost, resulting in savings for customers.

 

III.FACILITATING PARTNERSHIPS

 

In the 2015 Ontario Budget, the government announced time-limited relief on taxes pertaining to the transfers of electricity assets to promote consolidation in the electricity distribution sector. While these initiatives are helpful, they don’t comprehensively address the various barriers that LDCs face to pursuing private partnerships that support innovation or consolidation.

 

PARTNERING ON INNOVATION

 

Private partnerships have the potential to spur innovation in the distribution sector and allow an injection of capital while retaining local ownership in LDCs. However, current Transfer Tax rules act as a disincentive to LDCs pursuing innovative private partnerships.

 

When an LDC transfers the business to a partnership and has the investor invest in the partnership directly to fund the capital expenditure, the government continues to collect payment in lieu of taxes (PILs) on the LDC’s share of the business and the investor will pay mainstream income taxes on its share of the business. The regulations should be changed to guarantee this result.

 

Currently, it appears that Transfer Tax rules can be applied in this situation, even if the LDCs value of the business is the same both before and after the private investment. The LDC may be subject to Transfer Tax on the same dollar amount twice, once on the initial investment by the investor and again on the ultimate disposal of the interest retained by the LDC.

 

The EDA recommends that the Ministry of Finance amend appropriate regulations to make it clear that if an investor invests in a partnership where one or more municipal LDCs are partners that the Transfer Tax rules will only apply if the value of the investment held by the municipal LDC decreases as a result of the investment, thereby losing its municipal exempt status.

 

TAX CERTAINTY & CLARITY

 

The government’s current tax-relief measures are set to expire in two years. Since the measures were announced, only a few mergers and acquisitions have taken place, or serious discussions have occurred.  As mergers and acquisitions take time, the three-year window is not conducive to exploring and completing transactions.

 

The EDA recommends providing certainty to LDCs by extending the tax-relief measures. This may encourage others to pursue voluntary consolidations.

 

There is also a lack of clarity around the treatment of PILs credits following the merger of municipally-owned LDCs. The EDA recommends that the government amend legislation to provide certainty PILs credits can be carried over in the event that the now merged municipally owned entity in a subsequent transaction were to lose its tax exempt status.

 

The EDA also recommends that the government address any unintended tax consequences following a merger and/or acquisition so that the business case for the transaction is not unduly impacted by unforeseen tax consequences.

 

Despite the temporary reductions and exemptions that reduce the tax cost of consolidation and private partnerships, some transactions continue to result in significant tax exposure. The deemed disposition will generally result in tax on recaptured depreciation, goodwill gains and tax on other potential capital gains (for example if the utility owned real estate). Transactions, even for Municipal Electric Utilities (MEUs) with fewer than 30,000 customers, will be subject tax on recaptured depreciation on the MEU’s depreciable assets. The EDA recommends the government provide time-limited temporary relief of tax on recaptured depreciation.

 

IV.DRIVING INNOVATION

 

As noted in the OPO, innovation, technological advancements, increased customer engagement and policy decisions continue to modernize the electricity system, propelling Ontario towards a system that can facilitate the two-way flow of electricity. In addition, electrification will have significant implications not only for the provincial grid, but for the distribution system.

 

SUPPORTING NET METERING AND DISTRIBUTED GENERATION

 

As Ontario moves towards decentralized delivery of energy, LDCs are ready and excited to take on the important role of balancing customer service, enabling new innovative technologies while continuing to ensure reliability. Distributed energy resources provide opportunities and benefits to the system and customers

 

For LDCs to easily enable the adoption of distributed energy resources, the government should immediately address regulatory issues and restrictions, such as allowing third party ownership of net metering projects. The government should also provide certainty regarding funding. Specifically, the OEB should move to immediately complete the distribution rate design for commercial and industrial customers. As Ontario evolves away from a centralized electricity system, regulatory processes and policies also should be decentralized. The government, OEB and the IESO should coordinate with LDCs to streamline the integration of distributed generation in a way that does not compromise reliability or strand assets.

 

PREPARING FOR ELECTRIFICATION

 

Infrastructure to support electric vehicles and the proposed increase in electric heating will intrinsically affect LDC operations, assets and reliability. Electrification will require careful planning with LDCs on costs, analyzing loads and upgrading assets while protecting reliability. Therefore, the EDA recommends that LDCs are integrally involved in the implementation of the various electrification initiatives across the province as outlined in the CCAP.

 

As noted in the IESO’s OPO “electrification and the growth of distributed energy resources would also drive the need for significant investments at the distribution level.” Such investments should be considered as part of the regional planning process and be pursued after rigorous cost-benefit analysis. However, necessary investments should not be encumbered by onerous regulatory approvals.

 

LDCs are eager to pursue innovation and modernization of the electricity system in a balanced way that considers the cost and impact on the customer. Appendix 2 provides details on several innovative initiatives by LDCs. These examples demonstrate LDC leadership in designing and delivering innovative programs that benefits its customers. The EDA encourages the government to showcase these initiatives in the 2017 LTEP.

 

In addition, the EDA is currently developing a comprehensive paper on the future of the distribution sector. The paper is expected to focus on the innovative opportunities and challenges facing LDCs over the next decade and to identify important changes required to the regulatory and policy environment to ensure that the “LDC of the Future” is well positioned to meet customers evolving needs The EDA will be releasing this paper in early 2017.

 

CONCLUSION:

 

LDCs have a record of delivering innovative programs through conservation and supporting government policy initiatives such as the Green Energy Act. The electricity system is again on the cusp of extensive changes including the decentralization of generation, adaption of innovative technologies, incorporation of climate change objectives and enabling greater customer participation. Ontario’s local distribution companies remain ready to play leading roles in this evolution. LDCs are eager to support innovation, the implementation of climate change initiatives and integration of distributed generation.

 

The EDA encourages the government to focus the 2017 LTEP on: (I) Expanding conservation and integrating climate change; (II) Pursuing further efficiencies in the distribution sector; (III) Supporting partnerships; and (IV) Driving innovation. This should include providing certainty on conservation, streamlining and modernizing Ontario’s regulatory system and enabling LDC participation in innovative opportunities.

 

APPENDIX 1: SUMMARY OF EDA RECOMMENDATIONS

 

EXPANDING CONSERVATION AND INTEGRATING CLIMATE CHANGE:

 

1.Given the success of cost-effective conservation that has deferred or avoided the need for new generation infrastructure in the province, the EDA recommends that the government reaffirm its commitment to putting “Conservation First”.

 

2.The EDA recommends that the current budget structure be reviewed to remove disincentives to delivering programs with high upfront costs. The assigned budgets and targets should also be reviewed periodically and rolled forward as LDCs continue to deliver CDM.

 

3.Programs at the distribution level, such as conservation voltage reduction (CVR) and line loss reduction, can not only reduce peak demand pressures off the grid, but also increase grid reliability and efficiency and improve power quality for the customer.  The EDA recommends that the Minister provide direction to expand the definition of conservation to include programs and measures at the distribution level.

 

4.Current restrictions do not allow customers with the choice of going through a micro-generation program or through a conservation program. Therefore, the EDA recommends that the Ministry review the definition of conservation and direct the IESO accordingly to amend their interpretation of what projects should be included in conservation results.

 

5.The IESO and Ministry should confirm that LDC targets, as already established, should be taken

 

to be at the generator level.

 

6.To enhance the availability and variety of residential conservation programs, the EDA makes the following recommendations:

 

a.The IESO’s approval process for local programs and pilots should be further streamlined so LDCs can be out in the market faster to engage customers.

 

b.The IESO should work with LDCs to review residential programs that may have the potential for significant uptake and customer engagement and lower the TRC threshold for such programs as appropriate.

 

c.The government should dedicate a portion of the cap and trade proceeds to fund for residential programs, including increasing events and communication.

 

7.During the upcoming Mid-Term Review, the OEB and the IESO should collaborate in finding common elements that will encourage LDCs and the gas companies to collaborate further in the second half of their frameworks.

 

8.The EDA encourages government and the IESO to engage LDCs in any future discussions that involve collaboration with gas utilities. Furthermore, the EDA recommends that the IESO be directed to work with LDCs and gas utilities to develop a memorandum of understanding to foster a more streamlined approach to LDC-gas program collaboration which is beneficial to all parties, including the customer.

 

9.To provide certainty for long-term conservation initiatives, the Ministry should extend the 2015-2020 Conservation First Framework immediately. The process for extending the framework should be streamlined to avoid major disruptions to LDCs and to customers.

 

10.The EDA recommends that the province leverage the existing conservation infrastructure to deliver CCAP programs as it will be more cost-effective than building a new governance and program delivery structure.  The government should align conservation goals with CCAP objectives to mitigate confusion and ensure conservation targets are not negatively impacted.

 

11.The EDA recommends that the Ministry take into consideration the impact of the cap and trade regulation on its long-term projections of conservation savings.

 

12.The EDA recommends that the government recognize the energy savings arising from pricing structures and non-pricing pilots as contributing towards those LDC’s conservation targets and provide appropriate direction to the IESO and the OEB that those results are attributed appropriately.

 

13.The ICI regulation should be amended to allow customers to opt in to the ICI even if participation in conservation reduces their peak load.

 

14.Regional issues, such as economic conditions and transmission constraints, should be factored

 

in the LTEP conservation projections.

 

PURSUING FURTHER EFFICIENCIES AND SAVINGS:

 

15.The government should have a consistent approach to providing electricity relief for customers who face unique regional circumstances. The government should deliver RRRP through the tax base, consistent with the delivery of the Northern Ontario Energy Credit.

 

16.The government should immediately expand the scope of the Ministry of Economic Development, Trade and Employment's Burden Reduction Strategy to consider the regulatory requirements placed on distributors and provide independent recommendations for streamlining requirements.  This review should also be prioritized.

 

17.Regulations should be reviewed and modernized to enable innovation, including the consideration of distributors providing specific services to each other, without the need to get OEB pre-approval.

 

18.While the OEB has made an effort to streamline quarterly and annual reporting requirements, there is more work to be done. OEB should phase-out quarterly RRR filing requirements.

 

19.All regulatory requirements from the OEB should provide a cost-benefit analysis for customers and distributors.

 

20.As part of the OEB’s commitment to facilitate consumer engagement, the filing guidelines should be simplified to make the submissions consumer-friendly.

 

21.In harmony with the government’s Digital Strategy, the regulator should immediately move to eliminate the requirement for LDCs to submit hard copies of applications and reports. This initiative will reduce hundreds of thousands of dollars of printing costs incurred by LDCs.

 

22.The EDA encourages the government to take into consideration the cost and impact of CIS updates when determining timeframes for the implementation of government policy. To minimize cost and business interruptions, the EDA recommends that the Ministry work closely with LDCs to pace the implementation of CIS changes.

 

23.The EDA recommends allowing LDCs to perform the same, and additional, functions as the MDM/R

 

but at lower cost, resulting in savings for customers.

 

FACILITATING PARTNERSHIPS:

 

24.The Ministry of Finance should amend appropriate regulations to make it clear that if an investor invests in a partnership where one or more municipal LDCs are partners that the Transfer Tax will only apply if the value of the investment held by the municipal LDC decreases as a result of the investment, thereby losing its municipal exempt status.

 

25.EDA recommends providing certainty to LDCs by extending the tax-relief measures.

 

26.The government should amend legislation to provide certainty PILs credits can be carried over. The EDA also recommends that the government address any unintended tax consequences following a merger and/or acquisition.

 

27.The EDA recommends the government provide time-limited relief of tax on recaptured

 

depreciation.

 

DRIVING INNOVATION:

 

28.The government, OEB and the IESO should coordinate with LDCs to streamline the integration of distributed generation in a way that does not compromise reliability or strand assets.

 

29.Electrification will require careful planning with LDCs on costs, analyzing loads and upgrading assets while protecting reliability. Therefore, the EDA recommends that LDCs are integrally involved in the implementation of the various electrification initiatives across the province as outlined in the CCAP.

 

 

 

APPENDIX 2: DELIVERING INNOVATION – LDC EXPERIENCES

 

LDCs are actively engaged in supporting and pursuing innovative opportunities in Ontario. The following examples have been provided by LDCs.

 

A.TRANSFORMING INTO “UTILITY 2.0” – OSHAWA PUC

 

Oshawa PUC, a mid-sized utility serving 55,000 customers, recognizes the need to change the way it does business to address increasing customer expectations and electricity costs, frequent severe weather events, and aging infrastructure. It must also do so while being lean and nimble.

 

The utility is making significant headway in its efforts to become the community’s “Utility 2.0” by concurrently improving its analytical capabilities and developing new energy efficiency programs and distributed energy resources. The utility has already integrated multiple systems and leveraged new technology to pinpoint outages more effectively and restore power faster, even without a 24/7 control room.

 

With new systems in place, Oshawa PUC is also leveraging the power of smart meter data to understand their customers’ energy usage patterns and tailoring their energy efficiency programs to meet individual customer needs. For example, the utility’s Bidgely HomeBeat App, which identifies and tracks the major appliances in the home, is providing customers with personalized tips for saving energy and money. Preliminary results of the program show increased customer satisfaction and engagement with the utility, as well as positive behavioural changes and energy habits. Through its efforts 24 per cent of customers have signed up for e-billing, changing the customer experience and interaction with Oshawa PUC

 

Oshawa PUC has also established innovative partnerships with Japanese company Tabuchi Electric and Panasonic Eco Solutions to launch one of the largest microgrid projects in Canada. Thirty homes will be equipped with solar panels and batteries free of charge, and switched to net metering contracts. The utility aims to demonstrate how an efficient solar energy management system enhances reliability through the creation of connected, self-sufficient and energy-secure communities that provide back-up power supply and shift demand from on-peak to off-peak periods.

 

For Oshawa PUC, the way of the future lies in behind-the-meter generation and energy storage.  All these efforts are building an interconnected system with many moving parts that create two-way power flows – a departure from the traditional LDC business model that can improve system operations and deliver on customer expectations.

 

B.DOING BUSINESS BETTER – NIAGARA PENINSULA ENERGY INC.

 

For Niagara Peninsula Energy Inc. (NPEI), innovation is about doing business better. The utility has the third largest service territory and the second highest number of agricultural electricity customers in the province, as well as a large group of commercial customers in the centre of Niagara Falls. Like other utilities in Ontario, NPEI is also contending with different preferences in customer service among its diverse customer base. While younger generations want information readily available online or through their mobile app, other customers who are not as comfortable using technology, or who live in areas with a low rate of broadband, want to deal with their utility on the phone or in-person. Quite evidently, flexibility in customer service models is a necessity for NPEI.

 

NPEI’s innovative efforts have focused on offering specialized services that meet their customers’ needs. As a first step, the utility undertook a market segmentation study to understand these very different customer segments. The study uncovered multiple barriers faced by the hospitality sector in accessing conservation incentives. This led to NPEI launching an 18-month conservation pilot program known as the Energy Concierge for Hotels and Motels, which runs until January 2017. This program focuses on space heating and cooling – a major priority identified by hotels and motels – and offers customers a three-year energy management plan complete with technical assistance and financial incentives for certain types of upgrades to significantly boost energy efficiency.

 

Agricultural customers also benefit from having access to specialized incentives to address their energy needs.  NPEI offers these customers access to audit funding, retrofits, small business lighting and high-performance.  In addition, NPEI is collaborating with Hydro One, subject to approval from the Independent Electricity System Operator, to launch in the spring of 2017 a joint High Efficiency Agricultural Pumping Program. This program is being designed to increase the uptake of high performance, smarter, pumping systems by local farmers through financial incentives for these pump sets, as well as education about the equipment in order to influence the stocking practices of this equipment by suppliers and contractors.

 

NPEI has also undertaken various system upgrades to ensure the utility operates as efficiently as possible. The utility is one of the few in the province to have its geographic information system integrated with other operating systems, creating a powerful business intelligence tool that not only enables quick power restoration, but also effective infrastructure upgrades and planning.

 

Efficiency is key. As a mid-sized utility, NPEI has to consider resource implications when developing new programs or procuring services. One solution to broaden its purchase power is to pursue cooperative business models, which it is doing through its membership in the GridSmartCity Cooperative.

 

For Brian Wilkie, President and CEO of NPEI, establishing and maintaining a high-caliber team is also critical to achieving excellence and driving innovation. It is the people behind the programs, services and campaigns that contribute to NPEI’s positive reputation within its community and in the industry.

 

C.A NEXT GENERATION UTILITY – POWERSTREAM

 

PowerStream is transforming from a local distribution company into an integrated, innovative, energy solutions provider that plans, designs and implements on and off-grid energy services. PowerStream’s new business strategy is driven by the need to respond to the challenges imposed by rising electricity bills, increasing carbon dioxide emissions, frequent weather disturbances, grid congestion, new technologies and integration of renewable electricity generation. PowerStream’s existing work on residential solar-storage technology, EV integration, pricing models and utility-scaled microgrids are helping the utility build smart communities, supported by a strong, flexible grid and customized energy services and programs for consumers. This work has earned PowerStream a place among the top 10 Smart Grid Solution Providers by Energy Insights Online.

 

POWER.HOUSE

 

POWER.HOUSE is a state-of-the art technology that collects solar energy through solar panels and converts it into electricity, and then sends that energy to a battery backup, the customer’s home, or the grid, depending on what’s best for the customer. The program offers customers a no-worry system as PowerStream controls the entire process through a software management system. POWER.HOUSE provides customers with many other benefits, including immediate backup in case of an outage, savings on the electricity bill and the ability to earn bill credit for exporting excess electricity back to the grid.  Units are installed “behind-the-meter” (i.e.  directly in on a customer’s home), however they are owned and operated by the utility.  This ownership structure allows the utility to aggregate the resources into a “Virtual Power Plant” (VPP), providing operators with the capability to deliver grid-scale energy services using a collection of residential-scale assets.

 

PowerStream recently received an Innovation Award from Energy Storage North America in the category of Distributed Storage for the project – a clear sign that programs such as POWER.HOUSE offer added value to consumers and can be replicated by distributors elsewhere. The project also earned a CanSIA Game Changer award.

 

Other utilities have expressed interest in testing this technology, evidenced by Thunder Bay Hydro signing a partnership agreement with PowerStream to introduce the technology to Thunder Bay customers.

 

EV Integration

 

PowerStream identified electric vehicles as a major opportunity for sustainable mobility in late 2010 and purchased the first two Nissan LEAF electric vehicles ever delivered in Canada. It was the first in North America to demonstrate a vehicle to grid technology, which is connected to its head office microgrid. The utility continues to lead the charge for better and wider access to charging infrastructure, with DC fast chargers at its head office and in Markham. PowerStream’s continued leadership in promoting electric vehicles earned it the Canadian Electricity Association’s inaugural Tom Mitchell Electric Vehicle Leadership Award in 2016.

 

Advantage Power Pricing

 

The first of its kind in Canada, PowerStream’s Advantage Power Pricing is a technology enabled, voluntary dynamic pricing pilot program for residential customers in which the daily on-peak price varies in response to overall provincial demand for electricity.

 

Participating customers pay a low price for off-peak electricity use (5.9 cents per kilowatt-hour), while peak use, from 3:00 to 9:00 p.m. on weekdays, consists of three variable rates set at low, medium and high. These daily prices are sent to customers the day before to help them schedule their electricity consumption. Participating customers are mailed a monthly report summarizing their energy consumption and costs, and have the option to be equipped with an intelligent thermostat and a ZigBee-enabled smart meter that can automatically adjust their heating and cooling in response to the peak price. Customers pay the lower of the Advantage Power Pricing rate or the regular Time-of-Use rate, and so at the end of every six months of the pilot, customers whose participation resulted in cost savings receive a cheque in the mail (to a maximum of $500).

 

The program has shown some very good results. A recent survey showed that 83 per cent of participants felt that the program helped them to develop lasting energy-saving behaviours and habits at home, and 87 per cent said they would likely recommend it to friends.

 

This unique approach to delivering added value to consumers and applicability to the sector earned PowerStream an EDA Innovation Excellence Award in 2016.

 

KEPCO Microgrid and MiDAS

 

In partnership with the Korea Electric Power Corporation (KEPCO), PowerStream officially launched a utility-scale microgrid which has the capacity to provide several hours of backup power supply to 400 customers in Penetanguishene. At the heart of this cutting-edge solution is the Microgrid Distributed Energy Resource Automation System (MiDAS), an advanced microgrid controller that can operate autonomously and optimize the way in which power is delivered. In addition to providing backup power supply, it reinforces the existing grid by increasing resiliency and operational efficiency in a safe, secure way. MiDAS can also facilitate the use of renewable power sources to provide a lower carbon footprint and ultimately a cleaner environment.

 

D.ENWIN'S LEADING EDGE UAV TECHNOLOGY WILL BENEFIT CUSTOMERS AND FIRST RESPONDERS

 

Windsor will be among the first cities in Ontario to benefit from unmanned aerial vehicles (UAVs), better known as drones, which are increasingly employed in the maintenance of hard-to-access infrastructure, across North America.

 

While many local electricity utilities are exploring the potential for this equipment in assessing and maintaining electrical infrastructure, ENWIN Utilities Ltd. has received a standing Special Flight Operations Certificate (SFOC) from Transport Canada, and is now fully licensed to employ the technology for infrastructure assessment and inspection.

 

The utility can now begin to use the small flying machines routinely, to check transformers, powerlines and other infrastructure necessary to maintain the safety and reliability of the local distribution system.

 

If the power does go out, the utility can use the unassuming mini-copters to locate and assess

 

the cause, without the time and expense of sending out a crew and a truck. This will also improve response times, and help avoid potential emergency situations.

 

Longer-term benefits could include the early detection of potential electrical fires. Poor connections get hot, and drones equipped with infrared cameras are able to detect them and

 

flag them for repair. Helga Reidel, CEO of ENWIN Utilities, anticipates that this could also benefit the City’s Emergency Management team.

 

E.SMARTMAP – COLLUS POWERSTREAM’S SWISS ARMY KNIFE FOR ACCESS TO DATA

 

With the implementation of Smart Meters, there is an overabundance of data that can help drive decisions, but this data can also be the cause of frustration. By providing the data in a useable format, a model of the distribution network can be created to allow for a view into real time operations. SmartMAP provides Collus PowerStream with the data needed to better serve its customers.

 

SmartMAP is a new innovative software solution that has improved outage restoration and operational efficiency, decreased system expansion costs, reduced theft of power, energy savings, and improved customer service for Collus PowerStream. SmartMAP has been designed for the utility with end-use electricity customers as a number one priority. This comprehensive solution gives Collus PowerStream useful insight into the state of their system, and extends this information into an outage management system, customer energy reports, web portals, asset management tools and engineering analysis giving utilities the power to effectively perform all of their tasks in one application.

 

For Collus PowerStream the direction was clear—become a 21st Century Utility. By acquiring this innovative technology, the utility has been able to:

 

•Leverage technology to make better, more informed decisions

 

•Eliminate waste

 

•Drive value to the rate payer

 

•Prevent failures

 

•Minimize reactive work and become proactive

 

•Improve service reliability and quality

 

•Extend life of its assets

 

•Respond to an outage from the software, not from customer call

 

F.GRID-EDGE CONTROLS: A CANADIAN FIRST

 

This story was originally published in the EDA’s 2015 fall issue of “The Distributor” magazine.

 

By Matthew Meloche, P.Eng., M.A.Sc., System Planning Engineer, Entegrus Powerlines Inc.

 

Trevor Grant, M. Eng., Project Manager, Smart Grid Fund Project, Consultant, Varentec Inc.

 

Ontario’s electrical grid is at a historic turning point, as renewable energy and grid modernization gain traction. Under these new conditions, some utilities find themselves struggling because traditional grid management tools are unable to control voltages adequately within this new framework. Now a new technology, the first of its kind in Canada – introduced as a pilot project – has been successfully installed to help improve voltage stability, customer satisfaction and energy savings on the electrical grid. Underway at Entegrus in Erieau, a picturesque community on the shore of Lake Erie, the pilot is showing that innovative controls, placed at the grid edge, can overcome these limitations. Many factors are contributing to the changing grid conditions and the need for new tools. One key factor is Ontario’s significant commitment to the integration of PV solar and wind distributed generation (DG) systems. The increase in DG is producing two-way power flows along with new power quality issues, such as voltage and load dynamics.

 

Drawbacks among traditional control tools in the presence of DG

 

Several tools located on the medium voltage side of the distribution grid have traditionally been relied on by LDCs for voltage control. Among these tools are load tap changers – at both high and lower power utility sub-stations, which adjust the voltage delivered from these sub-stations. Other tools include line voltage regulators that adjust voltages to compensate for line droop, and capacitor banks. All of these tools are still used to provide basic voltage control, but through modernization efforts, they are being integrated with more complex controls to automate voltage management. Helpful as these tools are, their distance from the grid edge – where residential customers are connected – makes them unable to adequately control lower system voltages. They also do not act fast enough to respond to and regulate dynamic voltage variations because of their location far from the grid edge as well as equipment reliability constraints that limit the number of control operations per day.

 

The case for better voltage control in Erieau

 

Erieau, a community of about 420 people served by Entegrus, presents nearly perfect conditions for a community that will benefit the most from grid-edge voltage control technology because of its distance from the transformer station and the presence of renewable generation. Erieau would experience voltage variations when customers connected between its location and the main power source at the transformer station varied their loads. Similarly, voltage variations also occurred when the power being injected into the grid from secondary power sources such as renewable generators would vary. During the summer in Erieau, it was traditionally challenging to maintain Canadian Standards Association voltage standards during both peak and light load conditions. The presence of wind DG further complicated the situation. Customers were experiencing significant voltage fluctuations throughout the day as feeder conditions changed. Entegrus regularly received concerns about dimming lights and commercial customers complained of premature equipment failures. Since Hydro One owns many of the transformer stations in the province where voltage adjustments are made, Entegrus has had to rely on Hydro One to make voltage adjustments. Given the changing feeder operating conditions, this manual voltage control by Hydro One made it difficult to provide consistent and timely adjustments to maintain steady voltage levels.

 

Pilot testing grid-edge control technologies

 

Entegrus was introduced to and embraced an opportunity to evaluate an innovative grid-edge management technology, offered by VarentecTM, called the Varentec Grid Edge Management SystemTM (GEMSTM) platform. The Erieau feeder was an ideal candidate to evaluate the GEMSTM system because of the distance from the distribution and transformer stations, and the presence of DG systems. Entegrus is the first to deploy this technology in Canada through a demonstration project sponsored by Ontario’s Ministry of Energy and funded in part through its Smart Grid Fund initiative, Hydro One, and the technology company. Pilot testing is ongoing on the Erieau feeder, as well as in two other utilities in Ontario.

 

The GEMSTM system deploys multiple, fast-acting and autonomously controlled voltage regulators, called Edge of Network Grid Optimization™ or ENGO™ devices. These devices are installed in parallel with the output windings of distribution transformers along a feeder (these distribution transformers convert the high voltages supplied by the substation to the low voltage levels used by customers). The aggregate impact of the multiple devices flattens the voltage profile along the entire feeder, enabling utilities to provide voltage support, improved power quality, enhanced integration of wind and PV solar, and integrated voltage control.

 

Another potential benefit of the GEMSTM system is providing utility-side demand management through conservation voltage reduction. This system would enable utilities to realize as much as five per cent energy savings on a feeder, which could ultimately offer them a utility-controlled mechanism for significantly accelerating the time frame for meeting conservation targets.

 

The Entegrus deployment and early results

 

For the Erieau pilot, Entegrus deployed 35 ENGO-V10 devices. Installation was accomplished in under two weeks and the system was commissioned and operational in one day. The early results are very encouraging. In addition to improved voltage conditions, Entegrus has already observed a reduction of customer concerns in Erieau and attributes this improvement to the GEMSTM platform. Based on these early results, Entegrus has several other feeders under consideration for deployment of this technology. The Smart Grid Fund Project that is sponsoring the Entegrus pilot will run through the first quarter of 2016, and results will be reported to the LDC community.

 

G.PROVING THAT INNOVATION CONTRIBUTES TO BETTER CUSTOMER SERVICE

 

This story was originally published in the EDA’s 2015 fall issue of “The Distributor” magazine.

 

Horizon Utilities Corporation believes that effective communication with customers is the first step in building relationships. Continuously improving engagement to ensure a genuine focus on its customers is part of the Horizon Utilities culture. But in order to be truly innovative, the utility is adopting creative methods to be an industry leader in customer service.

 

Horizon Utilities recently launched Take Charge·Save Energy·Earn Rewards, an online conservation and demand management (CDM) pilot program that rewards residential customers with Air Miles® reward miles for reducing their household energy use.

 

The online pilot program, funded by the Independent Electricity System Operator (IESO) and Simple Energy, will wrap up this October. The program has already demonstrated how a virtual engagement platform can help customers manage their own electricity costs and support Horizon Utilities’ overall CDM targets.

 

This innovative program combines behavioural science and technology as a way to engage customers around energy conservation while providing them with tools to manage their own electricity costs.

 

Customers enrolled in the program receive a personalized weekly energy insight email to help them better understand their household energy consumption and provide customized insights based on smart meter data and usage comparisons to similar households. Participants are incentivised with Air Miles® reward miles when they complete energy-saving tips and record other actions on their customer dashboard.

 

The project dovetails another recent award-winning customer engagement campaign – Just Ask Us. Horizon Utilities received the Gold MARCOM award for its customer engagement initiative designed to encourage customers to be proactive in energy conservation. Horizon Utilities’ customers were encouraged to call on their energy savings experts to help find solutions to reduce energy use and save money.

 

Similar to the online pilot project currently underway, the Just Ask Us campaign focused on personal interaction with in-house conservation experts. As part of its commitment to environmental sustainability, conservation experts continue to work with residential and business customers to deliver value to customers.

 

Innovation often requires the use of proven methods while employing new technologies and techniques. This is why Horizon Utilities continues to expand its focus on self-serve 24/7 options that offer customers convenience at the click of a button through online channels.

 

Customers are realizing the benefits of information at their fingertips through smartphones, tablets and computers. Horizon Utilities offers its customers online or in-person options to view transactions and account balances, manage their accounts and even view daily usage. With an emphasis on 24/7 service – Horizon Utilities has ensured customers can be hands on in their own energy saving efforts.

 

Horizon Utilities has increased its focus on the use of electronic communications vehicles such as social media to ensure broader reach for its customers. While these communications mediums are great for providing information and updates during power outages, they also provide additional tools for promoting new CDM initiatives beyond a website presence.

 

Horizon Utilities believes that innovation in all aspects of its business is contributing to greater value and customer satisfaction. This was evident according to the results of the 2015 UtilityPULSE Electrical Utility Customer Satisfaction Survey where Horizon Utilities received a 92 per cent overall customer satisfaction rating, well above the Ontario average of 86 per cent.

 

In fact, the annual customer satisfaction survey indicated Horizon Utilities’ commitment and innovative approach to customer service is paying off with an increase of five per cent from 2014.

 

Diligent research and communication have provided a greater understanding of where customers turn to for information. Horizon Utilities is continuously looking at new ways of embedding innovation into all aspects of customer service to ensure recent satisfaction success continues to improve.

 

H.HYDRO OTTAWA – BUILDING NORTH AMERICA’S FIRST-EVER DISTRICT UTILITY

 

Imagine living in a brand new, green, and technologically-advanced community – one where sustainability is seamlessly integrated into your way of life. Your home is an ultra modern condominium overlooking the picturesque Ottawa River, with electric vehicle charging stations in the garage, a net Zero-Carbon heating and cooling system, and real-time home energy monitoring through a mobile app.

 

While developments around the world can boast some of these characteristics, Ottawa’s Zibi community will be the first to bring these features and more together in one place. And a new business model – a district utility – will serve as the hub for operating, managing, monitoring and reporting on the sustainability of the community's energy system.

 

Hydro Ottawa is partnering with the Windmill Development Group, Dream Unlimited and the MaRS Advanced Energy Centre to make this vision a reality. The ultimate goal is to ensure Zibi becomes a One Planet Community – the first of its kind in Canada, and only the tenth such community worldwide. To be certified to the “One Planet Standard”, Zibi must achieve zero-carbon, zero-waste, and eight other principles within its lifetime  – all of which will ultimately make sustainable living easy and affordable for everyone in the community.

 

The partners have worked together on this project since late 2014, making important progress in refining the vision for Zibi's energy systems and developing strategic plans. On May 2015, the Advanced Energy Centre, in partnership with Hydro Ottawa, convened a group of urban planners, entrepreneurs, investors, industry leaders, as well as policy and regulatory experts for an intensive planning session, called a design charrette.

 

After defining the ideal human experience, the group brainstormed new solutions at the distribution edge that could enable a net-zero carbon energy system at Zibi. The group focused on ideas for new utility business models and methods for achieving sustainability targets. For example, the district utility could offer a community aggregated demand response. It could also share the community's progress on sustainability, energy demand and other measures through visualization tools, such as an electronic community billboard.

 

Another idea is the Digital Sustainability Concierge, which would provide residents and businesses with access to data on the community’s energy usage, including consumption data for each suite or business. It would allow customers to easily compare their energy usage with others within the community. The Concierge could also issue rewards and incentives, push carbon intensity or pricing notifications to customers, and enable them to remotely control their smart energy devices. In addition, it could use the One Planet Community framework to give personalized targets to customers based on the framework's principles as well as ways to better manage their energy usage and save money.

 

Following the design charrette, the Zibi project leaders defined high-priority utility business opportunities. These include the district's heating and cooling system, its electrical distribution, billing services, lighting, green generation, the energy "Internet of Things" infrastructure, the customer experience, and telecom services.

 

Then in late April 2016, representatives from Hydro Ottawa, Windmill Developments, and the MaRS Advanced Energy Centre participated in the Electricity Innovation Lab (eLab) Accelerator event hosted by the Rocky Mountain Institute. This invitation-only, four-day working meeting brought together teams from across North American that are working on high impact and innovative projects in electricity distribution.

 

Through structured sessions designed to accelerate progress, the Zibi project team worked on the business model for the district utility including its asset ownership, rate structures, investment strategy, and operations plan. It explored options for what a new district utility for the Zibi community could look like, narrowing these down to two potential ownership structures. The first was a “business as usual” model where Hydro Ottawa would only participate in the community’s electrical distribution. The second was a “New Co” model where a joint venture between Hydro Ottawa and Windmill Developments would act as the community’s complete energy provider.

 

At the eLab Accelerator event, the Zibi team also detailed the timeline for achieving the key energy-related milestones in the community over the next few years, especially those that must be in place for early 2018 when Zibi will be ready to welcome its first residents. Much of the discussion focused on Zibi's heating and cooling system, which is the linchpin in the district's energy system. There's an opportunity to develop a eco-friendly system reusing heated process water from a nearby paper mill, instead of typical forms of energy such as electricity or gas. That would go a long way in ensuring that Zibi is carbon neutral.

 

Now, the project team is refining its strategic plans and working with stakeholders to more clearly model how Hydro Ottawa or the New Co would operate. This work will inform the project team's recommendations, which will then be presented to the internal stakeholders of each of the partner organizations for approval.

 

Located in the heart of our Nation’s capital, Zibi is an ambitious development project that presents an unprecedented opportunity for Hydro Ottawa and its partners to explore ground-breaking technologies, tools and services that will engage customers, reduce carbon emissions and enhance the efficient use of resources.

 

Bryce Conrad, President and Chief Executive Officer of Hydro Ottawa, believes that:  “This partnership is a natural fit for Hydro Ottawa as we continue to drive for performance excellence, while furthering our goal to be Canada’s leading electricity company of tomorrow.”

 

I.BUILDING A RESILIENT ELECTRICITY DISTRIBUTION SYSTEM WITH MICROGRIDS AND INNOVATIONS IN ENERGY USE: VERIDIAN CONNECTIONS

 

Veridian Connections (“Veridian”), a utility showing great interest in deploying new technologies and service models that provide increased value to their customers, is part of a ground-breaking, multi-phased microgrid pilot project which leverages the latest technology, including the Tesla Powerwall battery. The pilot project integrates multiple sources of residential clean energy, while maximizing load efficiencies, energy utilization levels and provides backup power in case of grid outages – helping to create a resilient grid.

 

Canada’s first two Tesla Powerwalls were installed at Veridian’s corporate headquarters in Ajax in June 2016 for phase one of the pilot project. The units are located in the lobby, offering visitors and customers an opportunity to learn about the capabilities and benefits of battery storage systems. The second phase of the project involves the addition of a solar powered carport canopy with electric vehicle charging stations at the company’s corporate headquarters. The final phase will see the deployment of two potential residential microgrids involving two homebuilders – managed and operated by Veridian’s 24/7 System Control Centre, and controlled by Opus One’s GridOS® Microgrid Energy Management System. The pilot project supports electric vehicle technology, and greatly benefits the environment – lowering air pollution, reducing GHG emissions and climate change.

 

Veridian’s microgrid is adding flexibility by allowing more distributed generation to come on line – providing customers more choices. Perhaps more importantly, Veridian is providing more resiliency to its grid. Greater risks of extreme weather events from climate change can increase power vulnerability, as seen with Hurricane Sandy in 2012, the ice storm in 2013, and flash flooding in Greater Toronto in 2013. Several utilities, in addition to Veridian, are starting to see microgrids as a solution for mitigating customer impacts of power outages during extreme weather events.

 

As the province moves to net zero homes by 2030 and many more electric vehicles, Veridian and its partners are leading the work to try and optimize the home environment and functionality for customers while optimizing the electricity grid of the future. The optimal sizing and location of components and new technologies will provide a greater likelihood of meeting GHG reduction targets, reducing customer costs and increasing the overall quality of service.

 

Veridian President and CEO Michael Angemeer says, “Our goal is to demonstrate and evaluate the benefits of microgrids, battery storage, renewable energy and electric vehicles for our residential customers, and make progress towards net-zero carbon emission homes and eventually virtual power plants – providing direct benefits and expanded services to our customers.” He added “It is important to test out flexible systems in the home or business and connections to our 24/7 System Control Centre from a technical and customer interface perspective to allow the optimal sharing of benefits between the customer and the utility.”

 

Veridian Connections will continue to conduct pilot programs, sharing its learnings and best practices with the industry and customers.

 

[Original Comment ID: 207151]