Little less talk: With new revenue models, New York starts to put REV into action

The reforms to utility revenues in the Empire State could set the course for a new model of 21st century power providers.

Sometimes, news can make a splash even when it’s what everyone expects.

When New York regulators announced the creation of new revenue models for utilities under the state’s Reforming the Energy Vision (REV) docket last month, the order was in line with plans that commission staff laid out in a white paper nearly a year ago.

“What we saw was not really a surprise. It was in line with everything that we thought,” said Matt Ketschke, vice president of distributed resource integration at Consolidated Edison, the utility that serves New York City.

The REV docket aims to convert utilities into platform providers for the distribution grid — akin to an air traffic controller that facilitates the interconnection and management of a diversity of distributed resources. Key to that goal is the reform of utility revenue and ratemaking models so that utilities are incentivized to maximize system efficiency and encourage the deployment of third-party resources, like rooftop solar and storage.

Last July, regulators floated a series of new revenue opportunities aimed at addressing those issues. In addition to earning a rate of return on traditional grid investments, utilities would be encouraged to leverage new market opportunities based on their role as platform providers and respond to new performance metrics laid out by regulators on energy efficiency and customer engagement.

On May 19, regulators finalized the structure of those new revenue opportunities in a 160-page order, building on the concepts proposed in the white paper. While the new order may be short on surprises, the mere fact that New York is moving forward with the plans could prove significant for utility business models nationwide.

“There weren't any big surprises,” said Ryan Katofsky, senior director of industry analysis at Advanced Energy Economy (AEE), a trade group that represents clean energy companies in the proceeding. “But of course, what's significant is they are formalizing the direction that they were exploring with the white paper on utility business model change.”

REV’s push to reform utility business models

For over a century, utilities have made money predominantly through investments in large-scale grid infrastructure like transmission lines and power plants — a system called cost-of-service regulation.

While regulators authorize a certain rate of return for the utility based on the cost of those projects, no such incentives exist for the deployment of distributed resources or for enhancing efficiency. In fact, utilities often eschew these options because they can lower electricity sales, thereby reducing revenues.

The REV docket seeks to change that discrepancy. Launched in 2014, the proceeding aims to remove financial barriers to DER deployment and incentivize utilities to consider DER and efficiency solutions as a viable alternative to traditional grid and generation investments.

While New York has already enacted some reforms to the cost-of-service model around energy efficiency, Public Service Commission Chair Audrey Zibelman said she realized early in her tenure more reform would be needed.

“We've done an awful lot in this state around regulatory reform historically,” she told Utility Dive. “We have forward-looking test years, we've done revenue decoupling, we have revenue adjustment mechanisms so that utilities are not penalized through energy efficiency activities because they have less earnings.”

But what the state didn’t have, she said, was “a real incentive around innovating using third party capital.” Utilities could earn their rate of return by meeting system needs with their own projects, but no incentive existed for deploying technologies from other companies or using efficiency to meet the same grid demands.

While decoupled revenues make the state’s utilities less sensitive to higher DER penetrations, “there remain significant disincentives for utilities to take affirmative actions to increase the development and use of third-party capital and services that support DER penetration and system value,” regulatory staff noted in the white paper issued last July.

To help correct for this, last month’s order establishes that utilities will now be able to earn returns tied to meeting system demands with alternative methods, such as using customer-sited solar and demand management instead of new central station capacity.   

The order also codified two new types of revenue opportunities for utilities — platform-service revenues (PSRs) and Earning Adjustment Mechanisms (EAMs) — that will help utilities move away from cost-of-service regulation.

The PSRs push utilities to take advantage of their position as distribution service providers, deriving revenue from services like bundled communication offerings, information sharing with DER providers, or partnering with third parties to finance home energy technologies. The EAMs, a set of near-term performance incentives, offer utilities the chance to earn a regulated rate of return in exchange for meeting goals on customer engagement, energy efficiency and DER interconnection.

While the new revenue opportunities are significant, they won’t account for a wholesale change in utility business models overnight. Along with new revenue streams, regulators stressed that the traditional cost-of-service model would be retained for investments the utility must make in its role as a monopoly service provider.

“The cost of service model has been a very useful and a good model for utilities and their investors. It provides a great deal of stability and certainly has historically allowed us to attract capital at a relatively low cost for consumers,” Zibelman said. “We don't want that to change."

“[E]ven with regulatory reform, there will be substantial utility investment in conventional rate-based infrastructure, and that reform must be carefully modulated to avoid costly and counterproductive changes in financial risk,” regulators wrote in the May order. “... the approaches we are taking in this order strike the balance of taking immediate steps to unlock market forces and technology innovation while preserving the ability of utilities as regulated monopolies to maintain stable and reliable electric service for all customers as well as retain their opportunity to earn a fair return.”

Platform Service Revenues

Early in the REV process, officials split the proceeding into two parts — Track 1 and Track 2.

Track 1 deals with the details of establishing the utility as a distribution system platform (DSP) provider. Instead of the old model of power moving from straight from central generators to customers, REV aims to reshape the utility into an impartial arbiter of a multi-directional grid, helping to connect customer-sited resources, manage their power flows, and reduce the need for bulk system power.

On June 30, New York utilities will file their Distribution Service Implementation Plans — planning frameworks for how the utility will operate as a DSP provider. But already in Track 2, regulators are thinking about how the utilities' new role will affect revenue opportunities.

Termed “market-based earnings” in last July’s white paper, the platform service revenues envisioned by regulators involve the utility leveraging its emerging role as the manager of a dynamic, multi-resource distribution grid.

In their order, regulators cited some examples of potential services that could generate revenue, including “customer origination via the online portal; data analysis; co-branding; transaction and/or platform access fees; optimization or scheduling services that add value to DER; advertising; energy services financing; engineering services for microgrids; and enhanced power quality services.”

This part of the July paper was “the most speculative,” AEE’s Katofsky recalled. While regulators, using stakeholder comments, floated many ideas for PSRs, it’s hard to know which ones represent significant opportunities for revenue before they are tested. Under the May order, utilities will submit PSR proposals in their rate cases before the commission.

After last July's white paper, some DER companies expressed concern that utilities would overreach on the PSRs, using monopoly power to force third parties out of the market or charging them for grid services that should be expected for free. To help assuage concerns, regulators laid out five criteria for PSR approval:

  • whether the service facilitates the growth and operation of markets;

  • whether there is already a third-party market for the service that adequately serves all sectors of the market;

  • whether utility economies of scale and/or existing utility expertise are likely to result in cost-effective stimulation of the market;

  • whether utility provision of the service is likely to prevent other providers from entering the market;

  • the extent to which a utility has proposed placing shareholder funds at risk.

Those criteria have helped AEE’s members, including solar, storage and efficiency companies, become more comfortable with the idea of PSRs, Katofsky said.

“Even if a PSR is approved and put in place, conditions may change where perhaps that service no longer meets the criteria. There's actually a process for parties to petition to revisit those PSRs, so I think that helps a lot,” he said. “And I think the order made it more clear that the PSRs are really designed around stimulating markets, facilitating markets, as opposed to being more in direct competition with competitive providers.”

The idea of market facilitation is at the core of both the PSR proposal and the REV docket at large. By floating multiple ideas for PSRs, the commission hopes to inspire utilities to push the creation of markets for grid services and products in the state.

“We think there is a significant opportunity to build up these transactional markets and that those markets will benefit consumers and also help evolve the utility model,” Zibelman said. “But it will take time.”

ConEd is already thinking about how it can leverage PSRs, Ketschke said. The utility has three demonstration projects in the REV proceeding — a connected home platform, an efficiency marketplace for large customers, and a clean virtual power plant. Those demo projects, and numerous others operated by other state utilities, should help point power providers toward the PSR opportunities that are right for them.

“For example, the project we're doing on virtual power plant, where we're looking to aggregate rooftop solar and storage, gives us some opportunities to earn platform service revenue for how we manage and dispatch and get the most out of those distributed resources and solar,” Ketschke said. “And our connected homes demonstration, where we are providing customers with analytics about their usage, gives us the opportunity to provide them with info about their specific usage and then potentially marry them up with distributed resource and energy service providers who could provide them solutions.”

ConEd is in the midst of a rate case currently, so any proposals for PSRs from it won’t come until the next one, Ketschke said. But in the meantime, the utility will evaluate more opportunities for demonstration projects and apply those learnings to future revenue proposals.

“I think in the near term, demonstration projects are a place where we will find out what these revenue opportunities would look like and then they would evolve into the kind of base rate and operation of the companies going forward.”

Earning Adjustment Mechanisms

Establishing platform service revenues will help utilities move away from reliance on the cost-of-service model, but “we also know that’s going to take time,” Zibelman said. “In the meantime, we have very near-term needs that we saw as significant advantages to consumers in the state.”

“Those are really expressed in the Earnings Adjustment Mechanisms,” she said.

The EAMs are transitional performance metrics that allow utilities to earn a higher rate of return if they meet targets in four areas:

  • System efficiency, "defined as a combination of peak reduction and load factor improvement." Each utility will propose and file "a system efficiency targets, with a strategy to achieve it, a demonstration of cost effectiveness, and an earnings incentive."

  • Energy efficiency "tied to targets recommended by the Clean Energy Advisory Council (part of the new Clean Energy Fund), that are above and beyond the currently approved targets."

  • Interconnection, which focuses on improving utility-solar cooperation "by providing a positive incentive tied to developers indicating satisfaction with utility responses."

  • Customer engagement, which encourages utilities "to propose EAMs tied to customer uptake in specific innovative programs."

At first, utilities will be able to earn up to 100 basis points on top of their usual rate of return for meeting the four performance metrics, though that number could change over time.

The EAMs are called transitional, Zibelman explained, because in the future, regulators expect market forces will “help yield where we need to go.” But commissioners had priorities for the utilities to meet before that time, inspiring the performance metrics.

“We are very concerned about the system efficiency, so we wanted to make sure there was a clear incentive around that,” Zibelman said. “As we're moving toward having more and more distributed energy resources and utilities start treating these resources like customers … making sure their needs are being met was something that was very important.”

Like the PSRs, how the EAMs will manifest themselves in utility practices remains to be seen. While some efficiency targets will be recommended by the Clean Energy Advisory Council, utilities will propose other metrics around efficiency, engagement and interconnection in their rate cases.

“They've put a lot of the onus on utilities to come up with the specific metrics and targets for the EAMs, so it's not clear to me or anyone yet what those specific targets are going to look like,” AEE's Katofsky said. “While the order clearly said we are going to have performance metrics in these areas, it didn't specify how aggressive they would be and what the actual rewards would be except that they said broadly that the total incentive utilities could earn would be up to 100 basis points for all the EAMs combined.”

ConEd has already put some of the practices envisioned by the EAMs into action, Ketschke said. The utility's Brooklyn Queens Demand Management (BQDM) project, referenced multiple times throughout the order, provides an example of what regulators hope to inspire with the EAMs and by allowing utilities to earn a rate of return on non-traditional investments.

In 2014, regulators turned back a ConEd proposal to build a new $1 billion substation to compensate for demand increases in Brooklyn, saying the utility should find a cheaper option. ConEd returned with an request for 52 MW of distributed resources and demand-side solutions to meet the same need for significantly less cost.

Under the old regulatory model, ConEd could not earn a rate of return on those DER and DSM investments. But it would be able to do so under the new order, and such projects could also help it increase its ROI by hitting the performance standards laid out in the EAMs.

“What you saw in BQDM is that we do have an opportunity to earn on those as regulatory assets and earn on those through performance metrics,” ConEd's Ketschke said. “If we hit certain performance criteria, there are basis point increases on our ability to earn on those things.”

Cost-of-service, plus

While other states are considering reforms to utility business models, REV is undoubtedly the most comprehensive remake of utility revenue models pushed by regulators in a long time.

Even so, the new revenue models seek a gradual transition away from the cost-of-service model — not an immediate overhaul. For investments in traditional grid infrastructure, like poles, wires and substations, the old model may never go away.

“When it comes to traditional investments, the utilities are entitled certainly to receive return on their investments, and the traditional cost of service model that reflects that is absolutely appropriate in that sense,” Zibelman said. “Those are obligations that the state has to provide to the utilities, but also to provide a stable revenue stream and outlook when it comes to deploying capital, and we saw no reason to disrupt that model."

That perspective was welcome news for ConEd and the state’s other utilities. Throughout the proceeding, they pushed the commission in their comments to preserve the traditional cost-of-service model alongside any changes to revenues and ratemaking.

“We did make the point that we thought traditional cost-of-service ratemaking, particularly for the invested infrastructure that's in place today, and for other things that are really best executed as your traditional regulated monopoly, should still exist,” Ketschke said. “So the cost of service construct should continue to exist.”

The utility industry's desire to preserve cost-of-service stems from their need for stable revenues. For generations, investors have viewed utility stocks as safe bets — value investments that you hold onto for dividends and to hedge against risk. Much of that safety comes from the predictability of utility revenue streams under the cost-of-service model, which offers predictable returns on utility outlays and protects them from market volatility.

If that model changes too quickly, it could hurt investor confidence in utility stocks, which in turn would affect their ability to access cheap capital — a must for big projects. Zibelman said that preserving utilities’ financial health and capital access have been priorities throughout the proceeding.

“It's very important for us that our utilities, because they have a lot of capital to invest, remain extremely attractive investments from an investor standpoint because high costs of capital doesn’t help them and it doesn't help customers, and our ultimate goal is to keep customers in mind at all times,” she said.

Even AEE endorses the continuation of cost-of-service regulation, at least for now.

“I do think moving forward in the near term there still has to be a lot of cost of service in the mix of ways utilities can make money in the near term until these other mechanisms get proven out,” said Lisa Frantzis, senior vice president of strategy at AEE. “But I would hope moving forward, out five or six years, that we would actually be moving much more toward a larger percentage of the portfolio that would shift more to the performance-based type earnings mechanisms. It just allows for much more innovation both on the product and service sides.”

From ConEd’s perspective, the transition may not happen that fast. While the utility is already planning on how to take advantage of the new revenue options, Ketschke expects traditional investments to make up the bulk of its revenues for the foreseeable future.

“We don't know yet, but I think our view in the both very-near and near-mid-term is that the vast majority of the revenues of the utilities will likely be made up predominantly from our cost-of-service regulation on the existing system that we have,” he said. “Even as you begin to evolve into these other revenue sources, even things that would be significant to you or me are relatively small compared to the revenues of a company the size of ConEd or National Grid.”

While saying a concrete timeframe for the transition is impossible to know, Zibelman said that ConEd’s vision of the future is likely largely correct.

“I'm sure they look at it like we look at it. There's a lot of investment they make today and will probably continue to make,” she said. “But when we say the foreseeable future, the future can change very quickly as these markets grow, and I just hesitate to put any timeline or suggest it's any percentage.”

While there may be some apprehension from power providers today, Katofsky and Frantzis think the transition may materialize faster than many stakeholders expect, if the new revenue opportunities prove lucrative enough.  

"As more energy storage and efficiency comes onboard I think the cost of service model is challenged,” Frantzis said, “and I think these other mechanisms provide them with other ways of bringing revenue to the utility, so I would hope they would welcome them.”

Under the cost-of-service model, the rate of return is capped, Katofsky pointed out. But through PSRs and EAMs, utilities will be able to deliver more value to shareholders by accelerating their transition to a cleaner, more distributed grid.

“EAMs are directly saying we'll increase your profits by so much if you meet certain targets, so you could have in theory a utility … where the revenues may not be growing, or even shrinking, but the profit is going up, and there's nothing wrong with that if the utility is doing what you expect it to.”

Going forward, how utilities react to the new revenue opportunities will be watched by power sector stakeholders nationwide hoping to glean lessons for their own reform initiatives.

“I don't think many states are ready and willing to do the comprehensive approach New York has taken,” Frantzis said, “but I think there are a lot of eyes on New York right now and if they start seeing some success stories and elements of the plan that are working well, they will start to adopt those in their states.”

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