Last month, the Federal Energy Regulatory Commission approved Order 2222, a groundbreaking effort to open up U.S. wholesale energy markets to aggregated solar systems, smart inverters, batteries, electric vehicles, smart appliances, grid-responsive building controls and other distributed energy resources (DERs). 

But ordering the country’s transmission grid operators to comply with FERC Order 2222 doesn’t mean those multibillion-dollar markets are open to the hundreds of gigawatts' worth of DERs coming onto U.S. power grids — at least, not yet. 

First, the country's independent system operators and regional transmission coordinators must solve thorny issues of utility control over the distribution grids that connect behind-the-meter DERs to transmission grids and determine state jurisdiction over the interconnection rules and retail energy tariffs that regulate how they’re operated. 

States and utilities have so far lost legal challenges against FERC’s authority over these matters, but more could be on the way. And it’s possible that the wholesale market opportunities that emerge may not be worth the effort, cost and complications involved, compared to sticking to those on offer from utilities and state-mandated programs. 

That's the view from Tuesday's webinar hosted by the Peak Load Management Alliance trade group. Participants stressed that their views were their own, not those of the utilities, state organizations or companies they work for. But they all agreed that Order 2222 faces a long and complicated path to achieving the market transformation it envisions. 

1) Jurisdictional challenges 

Order 2222 is the latest in a line of FERC orders that have expanded its authority over the retail side of the electricity system, including Orders 741 and 745 that opened wholesale markets to demand response and Order 841 which does the same for energy storage.

The overarching trend has been an “ongoing shift of all state and local resource decisions” to FERC-regulated wholesale market operators in terms of “the way that energy services are being made available to retail customers,” said Jay Morrison, vice president of regulatory issues with the National Rural Electric Cooperative Association. 

In a sense, FERC's mandate can be seen not just as offering DER-equipped customers more opportunities but also as giving companies active in wholesale energy markets more access to customers, "even when those customers are being served by utilities in states that don’t have retail competition.”

And while FERC’s orders have made some allowances for states and utilities to avoid the complications of being exposed to these wholesale markets, it’s increasingly narrowing those exemptions, he said. FERC Order 741 offered state regulators the option to “opt out” of opening demand response to wholesale markets, for example — but Order 841 specifically bars a similar opt-out for energy storage participation. 

2) Legal challenges 

Each one of the aforementioned FERC orders has drawn legal challenges. Power generator groups took a challenge to FERC’s demand response orders all the way to the U.S. Supreme Court before being denied in 2016. And utility trade groups and state regulatory commissions saw the U.S. Court of Appeals for the District of Columbia Circuit reject their challenge to Order 841 earlier this year.

Order 2222 does allow small utilities, including short-staffed electric co-ops, to choose whether or not they participate, he said. It also calls for balancing wholesale market tariffs with states’ authority over DER interconnection and retail program policy. 

But in the month since the order was approved, “there are already rehearing requests challenging FERC’s decision to provide that deference to states,” Morrison said. A newly filed complaint asking FERC to undo its demand response opt-out rules in Order 719 indicates the risk of retroactive challenges to change the legal landscape, he added.   

Future divisions of authority between states and grid operators could also be subject to legal challenge, he said. What if a DER customer decides that the state interconnection regulations it faces are unfairly barring access to wholesale markets? “I think that will wind up in court,” Morrison said. 

3) Technical challenges 

Allowing DERs to access wholesale markets will “require huge upgrades and investments in our systems,” said Anja Gilbert, who works on DER integration policies for Pacific Gas & Electric. “IT systems, communications platforms and many new systems are needed for system visibility and control,” in order to manage problems including large numbers of DERs responding to wholesale market dispatches in ways that could disrupt local distribution circuits. 

California has more rooftop solar, behind-the-meter batteries and EVs than any other state, and PG&E and the state’s other utilities are seeking regulator permission to invest billions of dollars in grid upgrades and technology to manage those resources. But not all utilities are as far along as California’s in preparing for these grid edge management complications, and as they start to engage in the costs of doing so, “you’ll see this play out in utility rate cases.”

Mathew Sachs, senior vice president of strategic planning and business development for demand response provider CPower, agreed that “there’s going to be a huge challenge for distribution utilities and their regulators. […] How we work through this will really be key [because] it doesn’t work without them.”

Marcus Hawkins, executive director of the Organization of MISO States, which represents the 15 states served by the Midcontinent Independent System Operator, noted that independent system operators and regional transmission organizations will also need to engage in major software and technology upgrades to engage DERs at scale. 

MISO has delayed implementing its Order 841 plan for energy storage market participation until 2022, for instance, because “it wouldn’t be possible to include them until they have some significant technology upgrades,” he said. “Those are some of the things that might limit the level of transformation.”

4) Economic challenges 

Whether or not all this work creates wholesale market opportunities worth going after is the final question. PG&E’s Gilbert noted that California grid operator CAISO has allowed DER aggregations for years now. But restrictive and costly participation requirements have so far made it an unappealing option, compared to the more lucrative options available from state-regulated demand response programs and pilots. 

“We think a lot of the value of DERs is still at the local level and will be determined by the retail rates and the structures at the commissions,” Hawkins agreed. “In MISO, where there is no centralized capacity market that produces a meaningful capacity price, the rates at the state commissions will really determine how a lot of DERs end up integrating into the system.” 

Of course, much depends on “how much DERs will be out there,” Hawkins added. “Some parts of the country have tremendous transformation; some don’t.”

Demand response is already a major part of many ISOs' resource mix. Battery aggregations are taking part in wholesale energy market openings created through Order 841 in ISO New England territory, and New York ISO’s dual-participation model is a prototype for how batteries today, and aggregated DERs in the future, could earn both retail and wholesale revenue. 

These kinds of advances will start to reveal how DERs can help provide capacity and other grid services at the transmission scale, Sachs said. “From an investor standpoint, it’s increasing visibility across the market.”

That will allow companies like CPower, Enel X, Engie and others aggregating DERs as virtual power plants to target emerging markets with “even more available capital, or less expensive capital, which could make economics better for all.”