FERC opens one door and closes two others
Three orders by the Federal Energy Regulatory Commission in September will have significant effects on different segments of the US independent power market.
One order will make it harder for solar and other renewable energy projects that supply up to 80 megawatts to the grid — and add a battery — to qualify for power purchase agreements with utilities in parts of the United States that are not part of organized markets.
Another order will make it more difficult for renewable energy projects in [and around] New York to qualify for capacity payments from the New York grid operator.
The last order requires regional grid operators to let owners of rooftop solar and other “distributed energy resources” who can aggregate them earn additional revenue by supplying electricity or other services to the grid.
Since 1981, FERC has consistently held that the size of a qualifying small power production facility or “QF” is measured by the amount of capacity it can “send out” to the grid.
A project cannot exceed 80 megawatts to retain small-power QF status.
All electric utilities are required by a 1978 federal law called the Public Utility Regulatory Policies Act, or “PURPA,” to buy electricity from QF projects for the “avoided cost” that the utility would pay to generate the electricity itself. Since 2005, utilities have only had an obligation to purchase from QFs smaller than 20 megawatts, except in parts of the country without organized power markets where QFs can be as large as 80 megawatts. In a recent order, FERC reduced a utility purchase obligation in areas served by organized power markets to projects that are five megawatts or smaller in size.
FERC overturned settled principles in early September in an order revoking QF status for a solar project in Montana called Broadview Solar. The proposed project has a net capacity of 80 megawatts, even though the gross capacity of the solar modules will be 160 megawatts. It will also include a 50-megawatt battery or “BESS.”
The Broadview order contributes to a recent trend in unpredictable energy regulatory orders disturbing developer and investor expectations and elevating change-in-law risks.
Broadview Solar petitioned FERC for a declaratory order that the project will qualify as a QF.
Broadview acknowledged the 80-megawatt capacity limit in the law, but explained that the project inverters, which convert direct current (dc) power from the project to alternating current (ac) power as necessary to send power to the grid, are not capable of converting any more than 82.5 megawatts.
With parasitic load and losses of 2.5 megawatts ac from the inverter to the point of interconnection, the total amount of power that the facility can send to the grid is limited to 80 megawatts. The only way to increase the project’s capacity would be to install additional inverters. The project’s interconnection agreement also expressly limits the facility output to 80 megawatts. Broadview explained that it designed the project with an oversized solar unit combined with a BESS to increase the capacity factor and significantly enhance efficiency. The 50-megawatt BESS energy also must be transformed into ac power through the same inverters, so the BESS output and output from the solar arrays together cannot exceed 80 megawatts ac at the point of interconnection.
Under established FERC precedent, Broadview’s design would have been sufficient to qualify the project as a QF because it is physically impossible to send more than 80 megawatts to the grid.
FERC held nearly 40 years ago in an order called Occidental that determining “a facility’s power production capacity is not necessarily determined by the nominal rating of even a key component of the facility.” Instead, “the electric power production capacity of the facility is the capacity that the electric power production equipment delivers to the point of interconnection with the purchasing utility’s transmission system.”
In Broadview, FERC said that, “on further consideration” (after 40 years of following Occidental) the “send-out” analysis in Occidental is inconsistent with PURPA.
It held that the “power production capacity” of a facility is the maximum gross power production capacity, less certain parasitic loads and losses. According to FERC, the parasitic loads and losses cannot take into account controls, inverters and other “output-limiting devices” that restrict the amount of power that can interconnect.
As the dissent noted, FERC simply took one component of a power plant (the DC value of the solar modules) and called it the entire facility. It ignored the fact that the output from that component cannot synchronize with the grid without passing through an inverter to convert it to ac power, and the inverter size limits the output as measured at the grid to 80 megawatts. Therefore, the “facility is physically incapable of producing more than 80 MW of electricity for any subsequent use.”
FERC said all existing QFs will be grandfathered under the prior regime. The facility must actually be a QF — meaning it must have already submitted a FERC Form 556 — to qualify for grandfathering. Simply establishing a legally enforceable obligation or PPA with a utility pursuant to PURPA is insufficient.
The Broadview order turns on the fact that the solar system part of the facility alone (absent the inverter) exceeds 80 megawatts, and expressly dodged addressing the impact of the BESS on the determination.
The interconnecting utility, which opposed the QF determination that Broadview wanted, argued that the capacity of the BESS should be additive, because FERC “currently treats storage facilities as primary generation resources and does not treat them as ancillary or secondary to the generation process.” In contrast, the dissent said the BESS “cannot ‘produce’ power in any conventional sense of that term,” since its output must pass through the inverters to deliver output to the grid.
Entities seeking to combine renewable resources with a battery or other storage device are left without clarity as to the impact of storage on the facility’s QF eligibility.
At a minimum, if a renewable energy project must be a QF (in order to obtain power purchase agreements with vertically integrated utilities outside of liquid wholesale markets), the developer should consider requesting clarification from FERC before committing to include a BESS with a renewable resource when the combined capacity will exceed 80 megawatts.
Applying this new policy to an associated BESS system would seem contrary to the policy rationale behind the recent FERC Order No. 845, which seemed to encourage combining batteries with variable renewable energy resources in order to take advantage of unused interconnection capacity. (For more information on Order No. 845, see “Big changes in how new power projects connect to the grid” in the June 2018 NewsWire.)
New York Capacity Auctions
FERC issued a separate order in September rejecting a proposed modification to the capacity bidding rules used by the New York independent system operator, or NYISO, that would have allowed certain facilities that meet the state’s clean energy priorities to avoid offering a minimum price when bidding into the state’s capacity auctions.
The priority would have permitted the capacity from these renewable projects to clear the capacity auctions.
Under current NYISO rules, a new project would have to clear in 12 consecutive monthly auctions in New York City and surrounding metropolitan areas before it could avoid having to offer a minimum price in future auctions under a so-called “buyer-side market power mitigation rule.”
This is analogous to the PJM minimum-offer price rule, or MOPR, construct. Using essentially the same rationale that it used to modify the PJM capacity auction rules to require all new renewable generation with a state subsidy to offer a minimum-offer price in PJM capacity auctions, FERC held that giving a preference to any technology is discriminatory, and it rejected the NYISO proposal to exempt from offering a minimum price projects that the state wants to encourage.
The existing rules, which were not changed, already provided certain exemptions from the mitigation rule, including for projects that satisfy one of two types of price-forecast tests. Test A requires a demonstration that the first-year capacity cost of the project will exceed the minimum-offer price. Test B requires a showing that the average forecasted price for the first three years is higher than the minimum price.
NYISO wanted to modify these tests by giving priority to renewable resources up to a capacity cap.
The renewable resources to which it wanted to give priority would be picked ahead of conventional fossil resources that may have a lower cost.
NYISO explained in its application that since the state has aggressive clean energy requirements, relying solely on economic merit order would incentivize conventional energy when those projects will not be needed to meet the state’s clean energy goals. NYISO also explained that its proposal would not have the effect of suppressing market prices, because the total amount of capacity to be exempted from the minimum-price rule would not be affected.
In rejecting the proposal, FERC ignored the argument that the NYISO modification would not suppress market prices, and ruled strictly on a claim that the priority was discriminatory. It also ignored the facts that the proposal had the support of the NYISO independent market monitor as well as the New York Public Service Commission and a large majority of NYISO stakeholders and had no significant adverse intervention.
The ruling does not eliminate the ability of renewable resources to obtain an exemption by meeting existing tests. However, it will make doing so significantly more difficult.
The effect on state ratepayers is expected to be a significant increase in costs, as they would have to pay the capacity costs of conventional resources that clear the auctions as well as the capacity value associated with the renewable resources required to meet the state’s renewable energy standards.
FERC noted this potential, as it did when it imposed the new MOPR requirements in the recent PJM capacity auction order, but again relied on a federal court holding in a different context that states “are free to make their own decisions regarding how to satisfy their capacity needs, but they ‘will appropriately bear the costs of [those] decision[s] . . . including possibly having to pay twice for capacity.”
A FERC order in mid-September will let companies that develop small-scale projects, like rooftop solar, earn additional revenue by participating in regional wholesale power markets through aggregation of systems that the companies also own and use to sell electricity to residential and business customers.
The order, known as Order No. 2222, is designed to allow small distributed energy resources or DERs to aggregate systems in order become large enough to sell one or more energy services in competitive regional transmission organizations, or RTOs. RTOS include PJM, MISO, NYISO, CAISO, SPP and ISO-NE.
The new policy does not apply to ERCOT, which is regulated by the Public Utility Commission of Texas, not by FERC.
The order requires the RTOs to amend their tariffs to enhance commercial viability of a wide range of distributed resources by allowing DER aggregators to sell capacity, energy and ancillary services from these resources. “DER” is defined as “any resource located on the distribution system, any subsystem thereof or behind a customer’s meter.”
Thus, battery or other energy storage, rooftop solar, fuel cells, electric-car batteries and similar sources of energy could be eligible for such aggregation.
The minimum aggregation size for eligibility as a market participant in an RTO is 100 kilowatts.
FERC said that permitting such DER aggregation will increase market competition and could improve load forecasting and reduce over-procurement of resources.
For the DER resource owners, the order has the potential to add another revenue source, provided that the service offered in the RTO does not lead to double counting of the energy service provided.
The new policy also requires the RTOs to take into account the specific, sometimes multiple characteristics and functions that the DER resources can provide when redesigning their tariffs. For example, some battery storage can be a generation resource, a demand resource or a transmission resource and may be able to participate in different markets at different times.
Each RTO has nine months to file new tariffs to accommodate aggregation of DER resources.
Given the complexity of the task, most RTOs are likely to seek an extension of the compliance deadline. The policy is subject to rehearing. The rehearing deadline is October 19. If a rehearing is denied, the RTOs or other intervenors, including competitive suppliers, could still challenge the new policy in court.