test

 

By Jake Brooks

According to credible experts the electric power industry is about to see major restructuring. No one knows how widespread it will be or how quickly it will take over, but in all likelihood big change is already underway. Some experts are warning of major threats to the viability of existing utilities while others are saying it’s a huge opportunity and market participants should waste no time preparing to make the most of the new reality. Although the most dramatic change is expected in certain regions of the US, Canadians will likely see side effects and moderate versions of the same disruptions.

  Jim Hogan, Chair of Ontario’s Electricity Distributors Association, is positive about the prospects: “Distributed intelligence, coupled with broadband communications and automated control systems, will enable real-time market transactions and seamless interfaces among people, buildings, industrial plants, generation facilities, and the electric grid.” He expects Ontario’s distributors will be directly involved: “LDCs are positioning themselves to manage an intelligent distribution network with two-way power flows to both distribute and collect power; with advanced meter technology to provide real-time information on power consumption, quality and security; and that will enable CDM programs, improved reliability, automated system management and self-healing.”

          Analysts predict that the next decade will witness unprecedented moves to empower the electricity consumer. Although basic consumer choice was implemented in many parts of the continent more than a decade ago, only recently has the technology arrived that will enable large numbers of consumers to drive technology choices and participate directly in market functions, areas previously reserved for a limited number of specialists. In an industry that lives primarily on long-term investments and is famously slow to change, unprecedented plans are being drawn up to deal with potential upheaval, which for some could be as soon as the next 18 to 36 months.

          Three forces are driving this change: cheaper small-scale generation options, the spread of smart technology, and evolving regulatory policy. The first force, steadily declining prices for distributed generation (DG) technology including solar photovoltaics (PV), small-scale pre-engineered combined heat and power (CHP), and related control systems, is underpinning what many see as the quickly-approaching new reality.

          Secondly, the availability of relatively low-cost DG will combine with new types of intelligent power control systems, designed to optimize power use, production, and quality. These new categories of “smart grid” technologies will allow many more consumers to become active players in various types of energy markets. At the same time the new technology means that increasing numbers of consumers will consider hosting facilities that bundle together previously disparate functions including micro-grids, intelligent controls, distributed generation, energy storage facilities, demand response systems, electric vehicle infrastructure and more. Some of this equipment may be owned by the customer, but much of it need not be. It can often be installed and managed by independently-financed third parties on the customer’s site.

          The third factor facilitating change is the increasing use of regulatory policies designed to enhance customer choice, often in concert with public policies intended to increase the use of renewables and energy efficiency technology. Ontario has recently begun an important regulatory initiative on “revenue decoupling” that will likely make the province one of the leaders in the field.

          All of these forces have been at work for years, but many experts believe that the combination has recently reached a tipping point, at which increasing numbers of customers may noticeably reduce their demand on the electrical system, and even disconnect entirely. Any widespread move to disconnect completely from the grid would be highly problematic as it could lead to uneconomic installations and dramatic rate increases for those who remain on the grid. In short, it would not be good for other customers or the existing utilities – and therein lies the potential for serious conflict. Regulators are paying close attention to this type of risk.

          Ontario approaches these questions at a time when it is generally acknowledged that substantial reinvestment is needed in basic infrastructure – large amounts of aging equipment are expected to be replaced in the next decade or so. The two kinds of investments (replacement of aging infrastructure and the transition to smarter distributed systems) will likely overlap, creating the potential for both competition and synergy between them. It will therefore be critical to for utilities and consumers to deepen their understanding of the factors that will determine how these investment decisions are made, and to try to find efficiencies that will cover off both needs at once.

 

Global change

          An article titled “The disruptive potential of solar power ,” published in April by the highly respected consulting firm McKinsey & Company, said, “These cost reductions will put solar within striking distance, in economic terms, of new construction for traditional power-generation technologies, such as coal, natural gas, and nuclear energy. That’s true not just for residential and commercial segments, where it is already cost competitive in many (though not all) geographies, but also, eventually, for industrial and wholesale markets.”^[1] David Crane, the CEO of US Utility NRG has been telling the industry for years that it needs to get out in front of this kind of change and prepare to install distributed generation and smart control systems for customers, rather than being left behind with relatively expensive undepreciated power plants. In what may be an indication of battles to come, some US utilities have tried to discourage customers from installing their own self-generation equipment, saying that kind of investment should be the exclusive right of the utility.

          The declining costs for solar photovoltaics and related control systems are a global phenomenon. In some regions where retail electricity prices exceed 20 cents per kWh, solar capacity is already competitive and installed DG is expected to grow quickly. This will in turn stimulate mass production, further research and likely further cost reductions, which will make the technology competitive in more locations.

          While Ontario does not have the same solar potential as some other jurisdictions, it does have access to relatively low cost natural gas, which in combination with micro-grids and storage could provide a range of high-value services to the electric system and represent a similarly challenging set of offerings to the market, and potentially eat into the revenue streams of existing utilities. Most Ontario generators are under long term contracts that protect them in many respects from the direct impacts of such change. However, no one is immune from technology innovation and such developments will almost certainly flavour the new opportunities that generators see in the future.

   Bruce Campbell, the CEO of Ontario’s IESO, recently stressed the significance of the change underway: “… [S]everal countries around the world have now reached the point where solar power provides a cheaper alternative to retail electricity rates without subsidies or feed-in floor prices of any kind. ... Somehow this is all starting to feel like very fundamental change across our sector.” He went on to say, “Just a decade ago, using information technology to optimize electrical flows on the power grid was pretty much the exclusive domain of a small club of system operators. Today, technology is advancing both the need and the ability to do this optimization at the distribution system level, the micro-grid level, the building site level, and even at home through the latest app on your smart phone.”

          Some of Ontario’s distribution utilities have stepped to the forefront, planning to adapt to the changes, finding ways to embrace the new opportunities or at least protect themselves from the risks associated with this kind of change. For the past five years, ever since the passage of the province’s Green Energy and Green Economy Act, LDCs have been “practicing” and learning how to connect decentralized generation.

          “The transformation of the electricity industry has been on our radar for several years now and we have been positioning ourselves to take advantage of what we believe are new and exciting opportunities,” explains Brian Bentz, President and CEO of PowerStream, a leading municipally-owned energy company that provides power and related services to more than 365,000 customers located in communities immediately north of Toronto and in central Ontario. “To this end, we are currently operating a successful rooftop solar generation business, developing behind-the-meter solutions that will provide consumers with more energy choices and testing technologies through our micro-grid demonstration project that will enable us to be involved in distributed generation projects to an even greater degree.”

          Atul Mahajan, the CEO of Oshawa Power and Utilities, another Ontario-based utility, has been preparing for change management. Oshawa Power now owns and operates natural gas fired co-generation and solar assets. It is working with multinational technology providers to set up a micro-grid project running into several megawatts and just recently submitted bids to the IESO for providing storage-based voltage regulation and frequency support services. Mahajan says, “Distributed Generation with the help of sustainable clean and green technologies, such as cogeneration and solar, is the smart way to produce and use energy. It is efficient as it saves both transmission and distribution losses when you transport power that is generated by central plants that by design are, for most part, in remote locations.” He adds, “The cost-effective reliable disruptive technologies that are already here and those that are around the corner will finally provide the customers the options that they did not have in a traditional monopolistic model. … Eventually, they will become as ubiquitous as the smart phone. So ignoring them is the risk that we cannot afford both at the industry and societal level.”

 

Ontario’s Revenue Decoupling initiative

          Ontario has been particularly proactive in preparing for the prospect of large scale restructuring. In addition to establishing a policy framework that priorizes conservation, and maintaining a wholesale market that in some respects places demand management on an equal footing with generation, the province’s energy regulator has announced plans to ensure that electric distribution utilities will not be at risk of revenue loss if customers choose to use less electricity. In a letter released April 3, the Ontario Energy Board advised that it had released a Draft Report of the Board on Rate Design for Electricity Distributors, and that it intends to pursue a “fixed rate design solution” to achieve revenue decoupling for distributors for low-volume (residential and small commercial) customers. The OEB will address rate design for larger consumers at a later date.

          What this means for the lower volume customer classes is that utilities will be expected to charge those customers a flat fee for the distribution portion of the bill (about 20-25% of a residential customer’s bill) on a monthly basis, regardless of how much electricity is used, while passing through the actual cost of electricity consumed. This is a departure from the current rate structure in which the distributor’s revenue requirement is recovered through a combination of a fixed monthly charge and a volumetric charge based on electricity consumption and/or demand. The OEB sees this approach as having a number of advantages. Among them:

• Consumers will better understand the fixed nature of these distribution charges and infrastructure costs, and will be better able to focus their conservation efforts and investments on the costs that vary primarily with use and time of use – that is, generation;

• Distributors will have greater revenue certainty to support their long-term capital plans;

• With increased conservation activity, revenues based in part on volumetric charges can erode. A fully fixed charge will allow distributors to more aggressively pursue opportunities to support and deliver conservation programs; and

• A fixed charge approach will be simpler from a regulatory perspective, eliminating the need for detailed kWh forecasts necessary for determining volumetric rates and avoiding the need for rate increases and true-ups to offset lost revenues associated with conservation. (The OEB sees the increases as counter-intuitive to customers.)

          Distributors will no longer have a driving need to maximize electrical throughput. In fact, under the new rules many circumstances are possible where an active program to encourage efficiency and/or self-generation would benefit the utility and its customers through the reduction or deferral of expensive capital upgrades, or because its competitive affiliate could make money directly as a partner in energy project investments. This would allow for greater harmonization between the utilities’ businesses and government-mandated programs to encourage conservation and DG. Under Ontario’s Affiliate Relationships Code distributors themselves may pursue business opportunities in generation and energy services, within certain limits. Such initiatives could compliment or even lead projects pursued by the utilities’ competitive affiliates. Distributors who had once seen embedded generation as a threat to their revenue base could adopt a new outlook – and start assessing the benefits available from appropriately located generation in their territories. See our more complete article on revenue decoupling, also in this issue.

          With major programs for demand response and conservation underway, it is undoubtedly wise in policy sense that distributors be freed from any built-in pre-disposition for or against customer energy initiatives – supply, demand or otherwise. Although there are legislative and regulatory limits on how far distributors and their competitive affiliates may go in terms of becoming directly involved as proponents, facilitators or collaborators with various customer-driven projects, some uncertainty remains. With many new business opportunities likely to be on offer, questions will likely be asked as to where on the spectrum of active involvement a given utility should position itself, and indeed, whether the rules need to be refined to recognize the full range of new business opportunities. In some cases there would be great value to be gained, but in almost all cases there are significant transition costs in moving to a network structure from a simple distributor model. In all likelihood, there will be winners and losers as the deregulation of the telecommunications industry demonstrated.

          As for the revenue decoupling process, the OEB has presented three potential options for the fixed rate design (for illustration purposes only), is seeking stakeholder comment, and intends to meet with stakeholder groups. The proceeding is expected to continue through the summer. For more information, readers may wish to visit the OEB website and search for information on its revenue decoupling proceeding (OEB File No.EB-2012-0410).

 

Managing the risk of stranding

About 20 years ago there was a round of industry restructuring in which independent power producers, mostly gas-fired, began offering supply at prices that undercut the output from much larger existing generation. This left Ontario Hydro and many other similar utilities with a financial problem known as “stranded assets” – long term investments that had to be paid for, even though they were in some respects outmoded. It is possible that some utilities could face a similar problem in the next decade as new competitive options for production and management of power become increasingly attractive before some existing assets have been paid off.

          Existing utilities are likely already assessing their exposure in these areas. Many are likely thinking about how best to manage existing assets under various scenarios of change, and also about what type of investments to commit themselves to in future.

          Another example of the rapid spread of smart new technology has been the learning thermostat, marketed by Nest Labs. The equipment helps homeowners manage consumption by learning their habits and establishing an internet-connected smart data platform. Google announced earlier this year that it was buying Nest for $3.2 billion. “Google will help us fully realize our vision of the conscious home and allow us to change the world faster than we ever could if we continued to go it alone,” company co-founder Tom Fadell wrote. “We’ve had great momentum, but this is a rocket ship.” Nest has been selling more than 40,000 thermostats per month and has signed up more than 12 major utility partners across the U.S.

          There are significant costs associated with retrofitting distribution grids to accommodate so much customer-owned generation. Ontario’s distribution grids were generally engineered to support only one way power flows. See the related story from IPPSO FACTO, January 2009 on the complexities of accommodating a move to widespread use of distributed generation in Ontario: “A host of issues to address to get the system ready for DG.”

          Regulators and affected parties will likely be struggling with questions about how transition costs will be shared. For example, some will soon be asking questions like this: “Under what conditions is it justifiable to impose costs on all grid customers that are primarily a result of individual customer or generation-related adaptation costs?” Clearly this kind of question calls for shared principles to be developed and applied consistently across the province.

 

The localization of power

One of the long term effects could be the transition to a power grid that is significantly more focused on local production, consumption and management issues than it is today. Jim Hogan says, “Our vision is for Ontario’s LDCs to play a leadership role in the smart use of electricity to develop the sustainable communities of tomorrow. … Sensors and control systems will link appliances and equipment from inside buildings and factories to the electricity distribution system. The smart grid will provide the ability to tailor electricity supplies to suit individual needs for power, including costs, environmental impacts, and levels of reliability and power quality.”

          However it will not be a walk in the park. He notes that, “LDCs are aware of the challenges that greater integration of disruptive technologies bring to bear on the aging distribution systems such as:

• The impact on real and reactive power losses, voltage profile, phase imbalance and fault levels,

• The need for evolution of interconnection standards, procedures, and practices with respect to the safety of customers and workers, and

• The impact on infrastructure security and reliability, and resulting needs to protect utility and customer assets.”

          Nonetheless, “LDCs are preparing to make the necessary changes to utility system planning and operations to address those challenges,” Hogan says.

          He believes planning will take on a new more localized character in this environment. “Distribution planning will be done by LDCs at the community level, in collaboration with transmission companies and local and regional municipalities, to identify the needs and appropriate sources of supply, and to plan and execute to meet them. LDCs will develop local energy solutions by engaging in community energy planning to define the amount, location and timing of future energy needs and to establish priorities for development, within the framework of the province’s Long Term Energy Plan.”

          Greater Sudbury Hydro Inc. (GSUI) is another utility taking a proactive approach. Despite the northern location, significant numbers of Sudbury residents have installed solar photovoltaic generation on their roofs. Brian McMillan, Vice President of Distribution Electrical Systems at GSUI, explains that “There is an expectation from our customers that when they want to self-generate we will be in a position to allow them to do so. We can see serious issues – but we know that we have to prepare for this kind of change because it is coming.”

          Similar to the issues identified by the EDA, McMillan is concerned about strains that could be created on the electric system following the widespread use of PV. For example, the level of supply being fed into the grid could be more volatile than it is today, and power factor correction may be required more often.

          In response to some of these issues, GSUI has initiated a demonstration project in local power regulation. They are installing an IPR (In-line Power Regulator) from GridCo Systems in a region where a number of their customers have PV systems. They plan to carefully monitor the results of the project and share the findings with other distributors and customers.

          McMillan stresses the planning challenges faced by utilities: “We absolutely see this kind of change coming. We are trying to prepare for it as best we can – with full knowledge that we can’t predict how technology or markets will develop.” Like many other distributors, they are organizing themselves to monitor developments closely and adjust plans as they go. GSUI is active in smart grid-to-battery storage technology and in the IESO storage RFP.

          “This is the future, the status quo is not going to continue,” he says.

 

Utility adaptation

David Crane, the CEO of US utility NRG, published an open letter on March 26 in which he said change is not only inevitable but that utilities will soon be considered accountable for how quickly they responded to the current situation. He laid out business plans to reflect this assessment: “[W]e are in the process of reorganizing ourselves from the customer’s perspective. Our conventional generation business will be not only focused on maintaining our existing 50,000 MW fleet in top operating condition, but also on repowering select plants with flexible fast start units located in advantageous positions on the grid. Furthermore, in response to the increasing realization in the business community that no serious industry or commercial enterprise can prudently run their business based on 100% dependence on the grid, we see a growing B2B opportunity for our wholesale business in ‘on-site’ generation for industry and large-scale commercial customers. The cost to our business customer of maintaining localized generation will be defrayed by our ability to sell excess capacity and generation, on behalf of that customer, into the traditional grid.”

          “As lack of confidence in the grid coincides with the introduction of new technologies, businesses and homeowners will realize that there is a better way. And, for them, that means generating most of the electricity they consume on the premises, from their own resources. In this new reality, our ‘mass’ retail electricity franchise, consisting of Reliant, Green Mountain and NRG itself, becomes ever more important. Our retail focus is on ensuring that we remain a first mover in bringing technological innovation aimed at the home energy consumer to our customers, on terms that they find attractive. Our marketing relationship with Nest, and their award-winning learning thermostat, is a case in point. But it is only the beginning. We expect to be soon-to-market with a robust platform offering rooftop solar to homes and businesses and other forms of sustainable and clean generation that will offer our customers the ability to dramatically reduce their dependence on system power from the centralized grid.”

          Barry Chuddy, the CEO of Guelph Hydro, a smaller utility of 52,000 customers west of Toronto says, “Utilities need to treat customers like customers even if there is regulatory protection today.” Mr. Chuddy is convinced that over time, “the prospect of residential and commercial as well as industrial customers as self-sufficient competitors operating local, customer-owned generation becomes a real possibility.” Despite being a self-proclaimed “generation guy,” he recognizes that there is nothing more reliable than a customer connected to distribution wires. “But people will make choices based on reliability and cost – the LDC should not be doing that for them.” Guelph Hydro has behind-the-meter generation, local gas-fired and solar generation, and has positioned itself as a generation-friendly LDC in a distributed generation-friendly community. Chuddy says, “We believe a combination of conservation, local generation, and an LDC that does not stand in the way of change, particularly when that change comes as a result of customers wanting choice, is the best bet for Ontario.” He adds, “There is room for all technologies including large-scale generation and transmission upgrades, but as costs go up, customers will want to see that they have options. The initiatives LDCs and others are taking on are, I believe, about an ability to give consumers the choices they want.”

 

A future of expansive possibilities

          Some utilities in the US have begun to speak about operating as “Distributed System Platform Providers.” In fact the state of New York’s April 23 “Reforming Energy Vision” (REV) initiative makes this concept a feature of its regulatory plans. The whole picture is changing for distributors. Although there will still be a central control room for each electrical control area, there will also be other kinds of control centres scattered throughout the system with specialized communication links to each other and to the central control room. Local distributors will likely have large repositories of data that will be key to grid operation. With new relationships emerging between control rooms all over the province, and new technologies available for co-ordinating operations, the scope for potential innovation is unprecedented. “It will be an interesting place to be,” McMillan says.

          Hogan believes “The intelligent grid will … allow for more precise management of power flows, and real time information on consumption, so LDCs will be able to offer a variety of demand response programs, conservation programs, assurances around power quality and even different price offerings based on better knowledge of customers’ consumption patterns, power flows, and costs.”

          In fact, the deployment of new technology so close to consumers could have cascading effects throughout the electricity system: the systems for generating and controlling power flows could be spread out to more and more locations, the business priorities for utilities could change, and the flows of new investment could be affected. With regulatory rules like revenue decoupling easing the way, technology change could re-write the rules for how utilities relate to their customers. Depending on how systems evolve, these developments could determine whether utilities become active participants in customer based investments in ways that would have been unthinkable in years past. Although the immediate impacts will be felt most directly by utilities and their customers, in the longer term the deployment of new customer-based energy technology could impact the way forward for many parts of the larger more centralized system of generation.

          Perhaps Bruce Campbell summed it up best when he said, “It is not enough to think of smart grid technologies from our individual perspectives. Something much bigger is taking shape – something that will truly connect the customer and the control room. We’re now moving toward a more fundamental debate regarding the roles of the various organizations in the sector – and maybe even the role of the electricity system itself.”

 

See related stories:

PowerStream microgrid goes live

Revenue Decoupling initiated in Ontario

Preparing the power system for a changed climate

Open letter from David Crane, CEO of NRG