Utility success with corporate renewables demand raises questions for existing load
“We’ve got a good formula for new load; now what do we do about everybody else?”
Anybody who says utilities and regulators are not innovative has not noticed how they are meeting skyrocketing demand from corporate buyers for renewables. And innovation 2.0 is coming.
Some 71 Fortune 100 companies, at least 215 Fortune 500 companies, and many more small companies with clean energy or sustainability targets are their target market. Utilities need to serve that market, or those potential new customers may take their business to independent power producers.
To meet that new demand, utilities, regulators and corporate buyers have collaborated to develop 17 green tariffs in 13 states. The tariffs have brought 900 MW of new renewables onto the grid since 2015. The 360 MW added so far in 2017 far surpasses 2016’s 200 MW. At least 465 more MW of new load is in negotiation. But utilities now face a new challenge.
News vs. existing load
“Green tariffs work for new load but the next question is how to meet the demand for renewables from existing load,” said Letha Tawney, the World Resources Institute (WRI) director of utility innovation. It is a question of growing importance among members of the Renewable Buyers Alliance (REBA), a utility-corporate buyer-policymaker collaboration led by WRI and other non-profits.
The Puget Sound Energy (PSE) Green Direct tariff is the only one so far approved that “matches existing load to a new resource,” Tawney said. The difficulty is that if existing utility customers use new renewable generation, they are not using generation assets the utility previously built to meet their demand.
“The utility made an investment in generation on behalf of those customers and those customers now say they want a different type of generation,” Tawney said. “The utility wants to know how it can pay for the generation it bought or contracted for them.”
Stranded costs could result if too much existing load moves to renewables. That could be avoided by higher charges to non-participating customers, but the principles of good rate design require green tariffs to meet new demand without imposing such costs.
A REBA initiative was just announced to answer Tawney’s new question: “We’ve got a good formula for new load; now what do we do about everybody else?”
The Microsoft strategy for existing load
Advanced Energy Economy (AEE) Senior Vice-President for Policy Malcolm Woolf said finding a solution to serve existing load is “a serious but solvable challenge.”
For its Washington state campus, Microsoft convinced regulators to approve a special contract allowing the tech giant to purchase 80% of its power at market rates. The company paid a $23.6 million exit fee to cover the under use of PSE assets.
Commissioner Ann Rendahl of the Washington Utilities and Transportation Commission said in a recent AEE webinar, the commission concluded this “suite of commitments” prevented the special contract from imposing “unreasonable and unaffordable rates for remaining customers.”
Other large Washington state corporate buyers, including Wal-Mart, Sam’s Club and Krogers, have shown interest in this innovative agreement.
“It is not a complete solution but it could be part of the solution for some companies,” Woolf said.
Subscription strategies for existing load
With Washington regulators’ approval, PSE initiated its Green Direct tariff by contracting as off-taker for a 130 MW wind project. The utility aggregated subscribers for the project’s output from mid-sized commercial and institutional customers whose existing load is not large enough to contract for a utility-scale project's entire output.
To avoid stranded assets, PSE limited the size of the program’s first phase, did not contract for the wind until customers committed to 75% of the output, and imposed a fee for early withdrawal. According to Commissioner Rendahl, the program was “fully subscribed by the end of the first year.”
Tawney added that the new wind did not replace existing assets or contracted off-take. It “essentially reduces utility market transactions in the years this PPA is delivering energy.”
Green Direct is the first tariff to both allow aggregation of customers and meet all six Buyers' Principles, as outlined by early REBA members to guide renewables purchases and utility green tariff design.
Its initial price will be higher than PSE’s retail rate but the fixed price of the renewables contract offers subscribers a hedge against fluctuations in the price of PSE electricity.
AEE’s Woolf said the two approaches to meet existing load that Washington’s regulators approved address the emerging challenge. “Corporate buyers need flexibility because a solution that works for Microsoft may not work for smaller customers,” he said. “There wil not be a one-size-fits-all solution.”
To design tariffs that offer flexibility and avoid stranded assets and a shift of costs to non-participating customers, “utilities and regulators will need to be creative,” he added.
Creative advances in green tariffs
Other states are also developing creative green tariff approaches.
The Consumers Energy (CE) voluntary pilot offers two options for customers to purchase renewables-generated power, according to Teri VanSumeren, executive director for renewables. One option will meet demand from new large customers through customer-owned or customer-contracted renewables generation delivered through the CE system.
The second option allows smaller customers with a minimum aggregated load of 1 MW to purchase between 20% and 100% of their power from the output of a 35 MW CE-owned wind project.
With both options, the customer pays the retail rate for electricity plus a $0.045/kWh premium. But the fixed rate can work as a hedge against the value of the renewable energy and capacity settled in the Midcontinent Independent System Operator (MISO) market, VanSumeren said.
The utility began taking reservations for the program on September 22 and has received “a considerable amount of attention,” she added.
WRI’s Tawney said data center giant SWITCH, a potential new customer, and General Motors, already a CE customer, asked CE to develop a renewables strategy for large customers. “They’ve been in conversation ever since, and this high-quality tariff has both excited.”
Regulators responding favorably
Guided by customer pushes like that from SWITCH and GM in Michigan, regulators across the U.S. are responding quickly and favorably to green tariff proposals, Tawney said. Regulators also now understand that properly structured tariffs won’t shift costs to other customers.
Though controversial, the Xcel Energy Minnesota and Colorado Renewables*Connect green tariffs, pioneering subscription-based programs, now have commission approval. Colorado’s is for new load but Minnesota’s includes a “neutrality adjustment” for existing load to eliminate cost shift concerns.
But the Xcel and PSE projects are much bigger than typical community installations and the billing arrangements for the green tariff and community renewables projects are similar. But emerging subscriber-based, market-based green tariff programs will have more complicated billing that will compare contract rates to market rates and change in real time.
Dominion's tariff unique
WRI’s Tawney said Dominion Energy’s new green tariff program is especially unique. Not yet approved by regulators, it is a subscription-based and market-based offering.
It is significantly different from Dominion’s existing Schedule MBR, a special contract designed in partnership with Amazon. MBR capitalized on the tech giant’s familiarity with renewables transactions in the PJM wholesale market.
Through its MBR tariff, Amazon can pay for power at Dominion’s fluctuating PJM market rate and sell fixed-price, PPA-acquired renewables-generated electricity into the market. If the PPA price is below PJM’s market price, the customer saves. If the PPA price is higher than the market price, the customer pays more for the renewables but gets the balance of its electricity at the market clearing price.
Dominion’s just-introduced Schedule CRG plan offers six different tariffs and a portfolio of resources for new or existing load. Any non-residential customer with an aggregated load of 1 MW or more can participate.
The utility would obtain a PPA or PPAs through the PJM wholesale market, for the resource or resources the customer wants. A second contract between Dominion and the customer would set the “all-inclusive” electricity rate, which is unique to that portfolio of resources and its market prices.
“Ring-fencing” eliminates concerns about stranded assets by containing all portfolio costs in the customer’s PPA price.
“Dominion,” Tawney said, “has been building on lessons learned from Schedule MBR and has designed this new one to meet the needs of a different customer class.”
Dominion’s newest offering uniquely includes opportunities to providers of large-scale distributed generation. It moved in this direction because “like utilities all over the country, it is competing for customers.” Tawney said.
But with demand for electricity flat and existing load moving to renewables, utilities are competing and at the same time facing the question of how to pay for existing assets, she added. To confront this dilemma, REBA member utilities and corporate buyers will, in 2018, come together in a new working group to seek solutions for existing load.
The answer may be in combining green tariffs with things like energy efficiency, electric vehicles (EVs), or load shaping, Tawney said.
“If existing customers add workplace EV charging with 100% renewables, it would be new load that might be folded into a green tariff deal,” she suggested.
An energy efficiency option may be in NV Energy's deal with Las Vegas. It was able to deliver renewables and energy efficiency without a premium price because the utility obtained revenue from building out the city’s efficiency infrastructure.
No green tariff design has included load shaping to flatten customers’ demand charges, Tawney said. “But if new renewables drive down the demand charge enough to lower the overall bill, it could leave the customer, and therefore the system, neutral. Is there a way that works for the utility? That remains to be seen.”
The key is planning
CustomerFirst Renewables advises corporations and utilities on renewables purchases. CEO Gary Farha said green tariffs are part of an electric power system transformation “that everyone knows is coming.”
The first question utilities must answer “is whether they see customers’ evolving needs as a threat or whether they will find ways to benefit from serving those needs,” he added. If they choose to participate, “they could discover both new supply-side and demand-side ways to recover what otherwise would be stranded costs.”
AEE’s Woolf said options now available to utilities could work for existing load without stranding assets if utilities make one adjustment. “Planners need to assume a market-based green tariff will attract a certain portion of the utility’s existing load and factor that into their Integrated Resource Plans.”
A Center for the New Energy Economy (CNEE) report made the case for including corporate renewables demand into the planning process,” Woolf said.
It “will benefit a wide range of stakeholders, including corporate buyers, electric utilities, renewable energy developers, utilities commissioners, consumer advocates, legislators, governor’s offices, and economic development agencies,” CNEE reported.
Planning for renewables “minimizes risk to corporate purchasers and ratepayers” because it avoids “undue impact on non-participating ratepayers,” CNEE added. And it protects renewables buyers from being “unfairly over-charged for their participation.”
Planning also allows utilities to foresee the revenue impacts of the current seemingly unstoppable transition to renewables and confront alternative opportunities, CNEE concluded.
A cautionary tale
WRI’s Tawney said turning over the asset base faster than was planned for “is the core of the utility transformation.”
AEE’s Woolf recalled that when NV Energy would not provide the MGM Grand with the renewables options it wanted, it convinced the Nevada commission to allow it to pay an $87 million exit fee and move to direct purchase.
“MGM agreed to the exit fee and then helped pass a ballot initiative that now threatens NV Energy’s franchise. It is a cautionary tale,” he said. “If utilities don’t meet corporate demand, they risk losing their market.”