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Maine PUC Begins Inquiry Into Decoupling

On May 20th, the Maine Public Utility Commission issued a Notice of Inquiry"to obtain information and viewpoints regarding whether there is a need to provide different or additional financial incentives to the State’s transmission and distribution (T&D) and natural gas utilities to encourage customers to use energy more efficiently."  The NOI is in response to language included in the American Recovery and Reinvestment Act that required states to try to implement a policy that would align utility incentives with helping consumers use energy more efficiently as a condition of receiving additional State Energy Program funds. 

That language is generally understood to refer to "decoupling": changes in rate structures to address the fact that under traditional ratemaking policies utilities make more money as consumers use more electricity and gas. This makes it difficult to enlist utilities in efforts to encourage energy efficiency.  Those rate structures also create disincentives for T&D utilities to support behind the meter renewable distributed generation, such as residential roof-mounted solar photovoltaics or home wind turbines, which have the same effect of reducing total energy use by end users, and thus utility profits.  Decoupling is often paired with net metering, which allows home users to use on-site energy generation to offset energy consumed and reduce or in some cases eliminate their retail electricity bill.

The tone of the NOI is, on the whole, skeptical about the prospect of adopting a "decoupling" regime for Maine's transmission and distribution utilities.  The Commission notes Maine's prior experience with decoupling, including a failed implementation with Central Maine Power in the early 1990s, and a series of investigations and reports by the Commission that concluded the negative impacts (or risk thereof) of new rate designs exceeded any potential benefits.  They also note that the state's electricity efficiency programs are already administered by a separate entity, Efficiency Maine, and not the utilities themselves, reducing the conflict of interest inherent in utility-run efficiency programs absent decoupling.

Nonetheless, the Commission seeks input from interested persons on the following questions (additional questions relating to natural gas are omitted here):

1. Is there a need for Maine to implement alternative rate structures or other incentives for T&D utilities that would encourage energy efficiency measures by consumers?
2. Are there rate design or ratemaking techniques that were not considered in the prior investigations into efficiency incentives for Maine’s electricity utilities that could provide substantial benefit to the State?
3. Are there unintended consequences to implementing alternative rate structures or other efficiency incentives for T&D utilities that were not considered previously by the Commission?

Comments in this proceeding, Docket No. 2009-159 are due June 19, 2009, with reply comments to be filed by July 3, 2009.

Eliciting a Response

Current ISO-NE demand response (DR) programs are set to expire in one year (June 1, 2010) and ISO-NE has initiated a stakeholder process (pdf) to decide what comes next.  Key features of two of the DR programs currently offered by ISO-NE include: 

• Real-Time Price Response Program, under which participants may interrupt their power use when the forecast price of power reaches $100/MWh or more and the ISO lets participants know the eligibility period is open.  Participants are paid $100/MWh or the LMP at the time of their interruption, whichever is higher. 
• Day-Ahead Load Response Program, which allows participants to submit offers to interrupt power use along with submissions of supply offers in the day-ahead energy market.  Participants are paid the Day-Ahead LMP for the cleared interruptions, and real-time deviations are charged or credited at the Real-Time LMP.

In a recent FERC filing (pdf), ISO-NE noted that this stakeholder process touches on a variety of policy issues.  Many of these policy issues reflect the need to encourage demand response (making it economically advantageous to reduce power use at times of peak load and providing DR opportunities to all customer classes, for example) without distorting the market (by offering DR subsidies disproportionate to their actual benefits to transmission system reliability). 

Market-based capacity programs like those currently available at ISO-NE can inspire huge growth in DR, particularly in the wholesale and industrial customer classes.  According to ISO-NE, DR resources (mostly wholesale and industrial) in the region have gone from 100 MW to 2,500 MW since the inception of these programs.  Still, the FERC estimates (pdf at 33) there could be 41 GW of demand response available in the United States; if that estimate’s right, there should be a lot more to be found in New England, especially among customers who lack direct access to capacity programs, like residential customers.  The rapidly emerging SmartGrid standards will have a large impact on how DR programs are designed – and how much access various customer classes have to them.  Makes sense, then, that the most recent meeting of the ISO-NE Demand Resources Working Group was held jointly with the Demand Resources IT Infrastructure Working Group. 

ISO-NE intends (pdf) to file an updated report on this stakeholder process with the FERC by the end of July, 2009, detailing areas of consensus.  Any rule changes resulting from this discussion will be presented to stakeholders and filed with the FERC by the end of 2009.

Betting Big On Better Batteries

Last week, General Electric announced (pdf) a $69 million investment by GE and others in Watertown, MA battery company A123.  Some of those funds will go toward the production of car batteries for electric and plug-in hybrid cars, some will also be used to produce utility-scale batteries that can help balance the addition of variable, renewable generation to the power grid. 

Good news for batteries is good news for renewable energy, since cost-effective storage will make it easier to manage the variability issues that arise with the introduction of large amounts of renewable resources to the grid.  Utilities are increasingly turning to energy storage to manage their use of wind and solar power, and storage is a key component of the much-ballyhooed smart grid.

A123 makes advanced lithium batteries; a technology that has drawn a fair amount of attention in the press of late.  But advanced lithium batteries are just one of many potential grid-scale storage technologies.  The United States currently has about 22,000 MW  of storage in the grid today (about ¼ of the global total), the vast majority of which is pumped storage hydro.  Even older technologies are seeing innovation, with updated grid-scale versions of lead acid batteries and new twists on pumped storage hydro, like Riverbank Power’s plans to build underground pumped storage by digging huge reservoirs 2,000 feet beneath Wiscassett, Maine.

Given its focus on renewable energy, it’s not surprising that the American Reinvestment and Recovery Act (ARRA)  includes significant support for storage technologies, with grants for manufacturing advanced batteries (and training workers to make them) and tax credits and grants for potential customers (like renewable energy suppliers and purchasers of hybrid vehicles).  Most recently, the Department of Energy announced a $615 million draft Funding Opportunity Announcement for Smart Grid Demonstration Projects that include funding for “utility scale energy storage demonstrations.”