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Massachusetts Makes Smart Grid Mandatory

Jeff St. John's picture
Greentech Media
  • Member since 2018
  • 134 items added with 107,043 views
  • Jan 1, 2014

smart grid mass reform

Massachusetts has joined a growing list of states demanding that its investor-owned utilities invest in the smart grid — and find new models for how those investments should be valued. Consider it the latest move in a state-by-state reconfiguration of utility business models, aimed at creating new rules for sharing the costs and benefits of grid modernization between utility shareholders and customers.

Monday’s order (PDF) from the state’s Department of Public Utilities will require the state’s big utilities to submit a 10-year grid modernization plan (GMP) in the next six months. Advanced metering will be required as part of that plan — a significant development in a state which has seen almost no smart meters deployed to date.

These upcoming smart meter plans will need to include technology and business cases, not just for core automated meter reading functions, but for a range of additional features like outage detection and restoration, smart appliance communication and control capability, and support of power quality and conservation voltage reduction.

The plans also must include a request for pre-authorization of investments, along with “a mechanism to allow for more timely cost recovery than is typically available” under state regulations. That’s where the state’s proposal for coming up with a new way to measure the costs and benefits of these deployments comes in.

Massachusetts has about 3.4 million electricity customers, all but about 400,000 served by an investor-owned utility. Of those, nearly half are customers of the state’s two biggest utilities — NStar, which serves much of the greater Boston area and Southeastern Massachusetts, and National Grid (NGG), which serves broad swaths of the state from the coast to the western border.

Worcester, the central Massachusetts city that serves as one of National Grid’s operating division headquarters, has also been the site of a multi-year smart grid pilot project that has played a key role in the state’s grid modernization plans. The Worcester pilot includes tests of smart metering, distribution automation, home energy management, electric vehicle charging and demand response Itron (ITRI), Cisco (CSCO) and General Electric (GE), to name a few partners.

It also included what might be considered an organizational pilot project, which included 25 member organizations from consumer and environmental groups, utility and grid operators representatives, state agencies and “a wide range of clean energy companies and organizations,” who spent eight months talking through all the new capabilities they’d like to see come of a smart grid deployment — and how they’d like to share the costs of deploying them.

That working group came up with a set of concepts (PDF) for changing the cost-recovery mechanisms that guide typical utility investments, which has informed the state’s new smart grid mandate. That includes quantifying a long list of benefits that could come from smart meters, some of which are pretty hard to define:

(1) reduced meter-related operations and maintenance (“O&M”) expenses; (2) reduced capital expenditures; (3) theft prevention and revenue protection; (4) reduced unaccounted-for electricity; (5) reduced billing inquiries and customer service; (6) better outage management; (7) reduced energy consumption from inactive meters; (8) reduced bad debt expenses; (9) increased demand response; (10) increased energy efficiency; (11) increased use of EVs; (12) reduced carbon costs; and (13) the prevention or limitation of outages.

Several other states are asking their utilities to compile similar lists of benefits for their smart grid deployments — utility AEP’s Ohio’s GridSMART project is one good example. But Massachusetts is different in that it’s asking its utilities to include them as part of the planning process, rather than as additions to smart meter deployments already underway.

Other states are experimenting with new regulatory models that could help open future smart grid investments to different cost recovery mechanisms, such as Maryland’s “Utility 2.0” concept. In the case of Massachusetts, it’s targeting a so-called “capital expenditure tracking mechanism” that will allow each utility to bring rates in line with ongoing capital costs over time.  

Smart metering isn’t the end of the requirements Massachusetts is setting out. In future plans, utilities will need to address time varying rates for its residential customers, ensuring customer access to meter data while keeping it private and secure. The eventual goal for the state is to reach four “grid modernization objectives”: (1) to reduce the effects of outages; (2) to optimize demand, which includes reducing system and customer costs; (3) to integrate distributed resources; and (4) to improve workforce and asset management.

Electric vehicle (EV) infrastructure is also part of the state’s plans, though not in the form of any mandates. Instead, the Department of Public Utilities has opened a new proceeding into how best to promote electric vehicle charging, and grid systems and pricing policies to encourage EV adoption.

Photo Credit: Massachusettes and Smart Grid Regulation/shutterstock

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John Miller's picture
John Miller on Jan 3, 2014

Upgrading Utility Companies’ power grids’ to state-of-art smart technologies involves designing and installing advanced control systems, expanding/upgrading monitoring sensors,  adding more physical distributed switchgear/isolation hardware, and providing real-time cost data to Customer (smart meters) to encourage demand response.  These upgrades will definitely increase costs and provide significant future potential benefits.  But the question may eventually become, will these upgrades continue to facilitate or allow all Customers’ current uninterruptable, ‘on-demand’ power and at the Customer’s total-personal discretion?  One of the possible benefits of fully upgrading power grid controls will be reducing the level of reserve and backup peaking power required in the future as the penetration levels of variable renewable wind & solar continue to increase.  To further reduce the need for less efficient, higher carbon intensity backup peaking power could possibly require changing the current ‘on-demand’ business models to some form of mandatory ‘interruptable’ demand.  This could mean giving Utility Companies the authority to automatically control (ration) the power demand of most Customers, whereby the Customers are required to prioritize their appliance and lighting power demands as necessary for the Utility Company to automatically adjust (shutdown/startup) when needed Customers’ demand in order to properly balance power grids’ supply-demand at the most optimal levels (cost, reliability and ultimately carbon emissions).  How will this change from on-demand service or switch to a Utility ‘command-and-control’ system will be received by most Customers in the future will likely be strongly debated.

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