What are the significant…

What are the significant challenges facing utilities and what can the government do to meet them?

The LDC of the future needs to evolve, not just in terms of their “structure, operations, innovation, and performance,” but also their business models and the regulatory constructs facing those utilities of the future needs to change as well.  The utility of the future will need to present customers with an amalgam of traditional and non-traditional services.  Those non-traditional services will be best served from a platform that is founded on and integrated with the distribution grid and the traditional services it can provide.  If Utilities are to develop their grids as a platform for services in the future, Utilities will need to know that they can develop these services unfettered from the traditional regulatory burden faced today.

What are the most important benefits of a modern grid? Increased reliability? Greater information on your energy usage?

While reliability is important, we need to redefine what reliability means, especially for commercial customers.  Currently, a momentary outage that clears a fault on the system and restores power is considered to improve reliability yet for many of our sensitive commercial and industrial customers this type of interruption is as disruptive as a long outage.  As storage technologies improve, they will provide an economical means for sensitive customers to ride-through these momentary interruptions.  A modern grid should be able to offer this type of service for a premium price.

Customer’s conservation efforts will be reinforced if they have immediate feedback to their actions.  Customers should have access to devices which display the immediate effects of a customer’s consumption changes such as turning off a stove or starting an air conditioner.  For these measurements to occur, communication devices need to be embedded in the meter and talk to a display device in the home.  These devices (Zigbee) were available when the Province mandated smart meters.  Utilities asked if the incremental costs ($15) of this technology could be recovered as part of the smart meter program and were denied.  Consequently, the Province made a 15-year decision (life of the meter) to preclude this technology.  The Province needs to reconsider these decisions and allow utilities recovery on these and related expenditures.

A modern grid includes advanced outage detection, isolation and restoration capabilities.  This enables a utility to operate with fewer staff and consequently a higher level of efficiency and lower cost to the customer.  Utilities have already reduced staffing levels and the opportunity to capture original baselines for efficiency improvements may have already passed. (The low-hanging fruit has already been plucked.)

A modern grid is a “communication-assisted” grid.  Utilities will need more reliable communication systems to operate their “Internet of Things”.  A promising communication media – WiMax – operating on 1.8 GHz (the frequency set aside for utility use by Industry Canada – the federal agency managing spectrum)  is limited by federal regulatory rules to devices which are stationary.  This means that utilities who invest in a WiMax infrastructure will not be able to achieve all the efficiencies they would otherwise achieve as they cannot utilize the infrastructure to enable their vehicles as data collection hubs.  Provincial assistance to provide relief on this rule would lower costs for customers.

While Ontario is paying attention to cyber security, many of its key distribution assets (transformer stations, generators) are very vulnerable to physical attacks.  In consideration of maintaining reliability of supply, the Province should consider improving the resistance of those assets to physical attack as a part of the LTEP.

Similarly, it is commonly accepted that climate change has already resulted in more frequent and more damaging incidents of storms.  In consideration of maintaining reliability of supply, the Province should include improving the strength and resilience of the transmission and distribution systems to withstand those weather disturbances, including the abilities of utilities to respond, as part of the LTEP discussion.

What are the best uses of microgrids in Ontario?

Microgrids offer customers the opportunity to improve their reliability and to reduce peaks and reduce their cost of power.  For a utility however, the proliferation of microgrids and distributed generation complicate the operation of the grid.   Incremental costs for utilities to accept and manage microgrids should be supported in rates.

As noted previously, a microgrid may provide an opportunity to provide a customer increased power quality.  Costs to manage this technology by the utility should be supported in rates.  Costs to deliver this technology to specific customers should be supported by the customers with incentives provided by the Province through a “CDM-like” mechanism.

Are there any barriers preventing the use of microgrids?

When a microgrid isolates from the grid, then that microgrid manages voltage and frequency within the microgrid.  While this is not a problem for single customer microgrids however multi-customer “neighborhood microgrids” present technical challenges.  The Province will need to consider and address issues that microgrid participants might experience due to the lack of grid voltage and frequency management.  Utilities must be exempted from any liabilities associated with microgrids and customers benefitting from microgrids must also accept any associated risks.

As well, power supplied by a microgrid to a customer in a multi-customer microgrid will need to be settled separate from power supplied by the utility grid.  This will require special monitoring and billing systems and perhaps special meters (current smart meter 1-hour resolution may not be sufficient).  These costs will need to be supported in rates.

Traditionally, large generator customers seek permission to connect from their utility whenever they want to re-connect to the utility after a period of non-generation.  Large microgrids should also be remotely “permitted” (issuing an electronic “pass” or approval) when re-connecting to the grid.  A remote, automatic means of managing these permissions should also be developed and will need to be supported by rates.

Would you be willing to participate in a program where your utility could use your home storage device from time to time to operate a more reliable electricity distribution system?

Note: This question is assumed to refer to the use of customer’s battery storage to provide frequency regulation to the grid.  This frequency regulation is typically provided by the transmitter rather than the distributor.  Frequency regulation can be provided by drawing power from the connected, charging battery or reducing load from the grid by stopping the charging of the battery.

The use of distribution customer’s battery storage for frequency regulation can be managed with current technology however this should be subject to verification of the participant’s actual participation to ensure the participant does not collect credits while bypassing the system operation.  This is likely best done at the distribution utility level and would require systems, staff and (likely) meters capable of sufficient resolution.  These costs will need to be supported in rates.

Given current costs of batteries, losses on charge and discharge and decreasing ability to fully recover energy injected into today’s batteries, it is highly unlikely that energy arbitrage would be viable with today’s technology.  It will take several significant leaps in battery technology and cost effectiveness for arbitrage to be a viable proposition.  This would then seem to limit energy storage to high value transactions or roles.

Unreliability of wind generation drives the operation of “spinning reserves” – generally, natural gas fired generators that run on idle but can ramp quickly and fill in for variable resources that drop out of the supply mix with little notice.  The use of battery or other storage to backstop spinning reserves may allow the spinning reserves to stand down and not consume natural gas nor emit greenhouse gases when they are idling.  Storage devices would bridge the gap between when a reserve supply was called upon and when it could start, run and ramp to meet demand.

How can Ontario further support innovative energy storage technologies that leverage our existing natural gas infrastructure assets and take advantage of our clean electricity system?

Natural gas systems typically experience their lowest demand at the time that the electricity systems experience their highest demand – for summer peaking utilities only.  Natural gas microturbines are a technology that may be used to generate electricity when the gas delivery system is at a low point in their usage cycle and the electricity distribution system is at its high point in the usage cycle.  The gas turbines may be able to generate power that can be stored for later use – for example at night time when solar supplies are not available or are insufficient.

Which innovations offer the greatest benefit to your community and the energy system as a whole?

The customer’s participation in the management of the generation and distribution of electricity needs to be simple and predictable for the customer.  Projects offering cost effective and simple means for this participation will benefit the community and energy system.

How should the public and private sectors cooperate to encourage innovation in the energy section? n/a

Should Ontario set provincial conservation targets for other fuel types such as natural gas, oil and propane?

The Province’s position on other fuel types is confusing to customers.  On the one hand, the Province has stated that they want customers to move away from natural gas  and are imposing a carbon cap and trade system while on the other hand are offering incentives for customers to install behind-the-meter natural gas fired co-generation.  This dichotomy of messages leaves customers confused and less willing to invest in new technologies.

To meet the province’s climate change objectives, how can existing or new conservation and energy efficiency programs be enhanced in the near and longer term?

The carbon cap and trade program is confusing to most customers, including sophisticated commercial energy buyers.  Implementation of similar systems in other jurisdictions have shown that the carbon credit market is weak.  A simpler means of discouraging the use of carbon is suggested.  As well, the Province has, while issuing FIT and microFIT contracts, reserved for itself those carbon credits that might arise out of the use of solar rather than carbon-fuel energy sources.  This will likely be seen as duplicitous by the general public as those rights were taken before anyone had any idea that they would someday have value.

How can we continue to inform and engage energy consumers?

The public is generally ill-informed about the state of the generation, transmission and distribution systems, the needs for investment in those systems and the consequences of not investing in those systems.  Local utilities can help deliver those messages however messaging and funding to deliver it should be provided to the utilities.  Too often, the energy system operators blame each other and government policy for the high price of electricity.  Customers do not always distinguish between distributors, generators, transmitters, regulators and policy makers.  A strong common front between these system participants is needed in order for customers to believe that the system is being managed for their best advantage.

What role should distributed renewable energy generation play in the ongoing modernization and transformation of Ontario’s electricity system?

Distributed renewable energy generation is related to grid modernization and transformation but it is not a fully coadjutant relationship.  Distributed generation (DG) is forcing grid modernization and transformation.  Renewable energy generation was likely going to happen due to market forces and technology improvements at some future time regardless of its Provincial promotion.  Grid operations with high levels of DG penetration have not yet been fully vetted in North America and there is still much to learn about the ways and means by which such systems are best operated. Forums to share best practises and support for utility costs to modernize and transform the grid to enable high penetration DG are encouraged.  DG cannot be counted upon as an always available source of supply.  In fact, whenever there is a system upset, DG is forced off and not able to return to the system until the system is stable.  Consequently, grid systems still need to be sized for full “cold load pick-up”.  Renewable generation may reduce greenhouse gases and help mitigate climate change but traditional, centrally sourced supplies will still need to be available and capable of supplying the full load.

Solar renewable energy generation technology and costs are continually improving and consequently have a high likelihood of becoming a larger part of the supply portfolio in the future.  The LTEP should include a projection of the technology and cost improvements and be informed by that projection.

Paris Agreement on Climate Change

Canada (16-10-05) as well as the US (16-09-03) are signatories to the Paris Agreement on Climate Change which comes into force on November 4, 2016. With this agreement, it is expected that the playing field will be leveled in terms of the “greening” of the energy supply.  Currently, Ontario has one of the greenest grids in North America.  This comes with some cost that manifests as higher electricity costs than neighbouring jurisdictions.  Hopefully, as the terms of the agreement come into force, those neighbouring jurisdictions will move away from their cheap, carbon-fueled electrical supplies and their costs come more into line with those paid by Ontario customers.  The LTEP should recognize that Ontario is leading other jurisdictions in this regard and consequently its customers are finding it difficult to be competitive with other countries and provinces.  The Province should not just look to its own rate forecasts but also be informed by the rate forecasts of its neighbours and it should ensure that it trends towards establishing power rates that are competitive with its neighbours, as a long term goal.

The Paris Agreement also contemplates the elimination of fossil based fuels by 2060.  The Province has stated a goal to eliminate the use of natural gas in many sectors.  Nevertheless, the natural gas distribution infrastructure must be maintained without an expectation of a revenue return over the accustomed number of years.  In order that this infrastructure remain viable, depreciation rates for investments will need to adjust for the expected decrease in asset useful life.

Transmission Expansion

The LTEP contemplates an expansion of transmission to bring power from new hydro generation facilities in Northern Ontario and power from Quebec to central Ontario where the greatest usage growth exists.  The costs of this expansion are stated to be “system costs shared by the electricity ratepayers.”  Southwestern Ontario has surplus generation already and has supported wind and solar generation that benefits the province at the expense (some say) of the quality of life in this area.  It is proposed that electricity ratepayers in the southwest be exempted from these incremental costs to serve the GTA.

Natural Gas Storage to Support Electricity Generation During Summer Peaks

The Province states, “Since natural gas is also used to generate electricity, the storage facilities in Ontario can also be used to supply generators during periods of high electricity demand.”  The natural gas transmission system has ample capacity to supply summer peaking generation without drawing gas out of storage.  In fact, the storage facility exists because that transmission system does not have sufficient capacity to supply demand for gas during winter heating peaks.  This storage system should not be used to supply natural gas generators during summer peaks.

How can Ontario further support innovative energy storage technologies that leverage our existing natural gas infrastructure assets and take advantage of our clean electricity system?

During summer, natural gas demand dips and the natural gas line compressors across the province generally are idle or lightly used.  The engines on these compressors could power generators rather than compressors during summer peak periods.  This would obtain a higher usage factor on these assets and potentially eliminate or minimize investment in generator-only facilities.

The Discussion Guide states, “Once RNG (Renewable-sourced natural gas) is processed to remove impurities, it can be mixed in with conventional natural gas and use the same pipelines and equipment.”  The problem with RNG is that it is rife with caustic liquids and gases (landfill gas) and has a high carbon dioxide content.  It is expensive to condition that gas to pipeline quality. It is less expensive to build a steam generator with a combustion chamber designed for the gas quality produced by the renewable source.  Once converted to electricity, issues with quality disappear.

Renewables

The Province allocates capacity to accept generation on feeders and stations on the basis that all generators will be generating their maximum capacity, all at the same time, at a time that the feeder/station is at minimum load and least able to absorb the generation.  These assumptions are very safe however this situation only rarely occurs on a feeder/station.  These assumptions limit the amount of generation allowed to connect or alternatively drive significant investment in reactors to limit the available fault current on a feeder/station.  A different construct, whereby distribution utilities are allowed to manage generator access to the grid would allow greater numbers of customers to participate in renewable generation and defer costs of fault current remediation.

It will be helpful to explain how the LTEP will impact the Climate Change Action Plan, and vise versa?  Currently, the respective Ministries seem to be developing programs to best accomplish their goals in the absence of other Ministerial and/or Provincial initiatives.  An example of this is Behind-the-Meter Generation (BMG).  These projects (which largely depend on Natural Gas) were just included under the Conservation First Framework in 2015, yet the Province just announced their new Cap & Trade system which could significantly impact the viability of these projects.  Clarity on how the Ministries can and will work together through the LTEP and Climate Change Action Plan to ensure there is minimal duplication of efforts and confusion amongst the ratepayers of Ontario would be helpful in gaining acceptance of the programs.

Currently if a customer has taken advantage of energy conservation programs , and their load drops below class A thresholds they are not allowed to participate in the Industrial Conservation Initiative (ICI) program.  It is suggested that  this be addressed in the LTEP (or other vehicle) to allow them to be credited for conservation efforts to bring them back to Class A.

CDM targets are known until 2020, however it is hoped that the LTEP will clarify the future of CDM after 2020? Will will it continue?  How will it be funded? Will it be rate based?

[Original Comment ID: 205121]