Energy storage gets a bigger seat at the utility planning table
The growing inclusion of storage in integrated resource plans is, to some extent, the next step in the evolution of the technology at utility-scale.
Utility Integrated Resource Plans (IRPs) are beginning to catch up with the growth of energy storage.
Utilities across the country from Duke Energy Carolinas to Southern California Edison have implemented energy storage projects for a variety of reasons, but until now few have included energy storage in their IRPs. Now, utilities in states ranging from Indiana and North Carolina to Arizona, New Mexico and Oregon have included energy storage in their long term planning processes.
Portland General Electric’s 2017 IRP proposes five storage projects in a range of sizes and applications. The utility’s IRP is, in part, a response to a state law passed in 2015, HB 2193, that required PGE to procure at least 5 MWh of energy storage and up to 1% of 2014 peak load (38.7 MW) by 2020.
PGE’s rationale for including storage in its planning process is the need to support grid flexibility as its use of variable renewable resources grows. Last year more than 40% of the energy PGE delivered was from carbon-free sources. The state’s renewable portfolio standard mandates that 50% of electricity sales come from renewable sources by 2040. PGE says that if hydropower resources are included, it will hit 70% carbon-free energy by 2040.
In its 2017 IRP, PGE says it plans to install a microgrid battery storage pilot project at existing solar and biomass facilities to improve resilience; a battery at a substation to provide energy and capacity and other ancillary services; a storage asset at the existing 1.75 MW Baldock solar facility; up to 500 residential behind-the-meter batteries that would be controlled by PGE to pilot the development of a residential storage program; and a 4 MW to 6 MW transmission-connected storage device that would create a hybrid plant at PGE’s Port Westward 2 facility.
Despite the fact that some of the projects are called “pilots,” they will all be commercial scale, PGE spokesman Steve Corson told Utility Dive. An explicit part of PGE’s strategy, he said, is “to explore a diverse range of technologies in a diverse range of applications and sites so we can learn in addition to having the assets themselves.”
The next step
To some extent, the inclusion of energy storage in utility IRPs is the next step in the evolution of utility-scale energy storage. Utilities have included energy storage in requests for proposals since 2011, but the requirements of the RFPs were not always favorable for storage. An energy storage developer “could battle it out at the procurement stage to be allowed to compete, but that is like skating uphill,” Jason Burwen, policy and advocacy director at the Energy Storage Association, told Utility Dive.
“The IRP informs the RFP,” Burwen said. Moving energy storage one step earlier in the process can give “a developer a better shot at procurement.”
Most current IRPs incorporate methodologies that are not designed to capture all the potential benefits of energy storage. The typical IRP uses three inputs: forecasted demand, capital costs and the operating profile of traditional technologies. Such IRPs are relatively uncomplicated. For instance, they usually use as a reference the operational profile and costs of a gas-fired generator.
Energy storage, particularly battery storage, which accounts for most of the storage market share, does not neatly fit into that analysis. In addition to backbone services such as capacity, storage can be used for flexible services such as frequency regulation and ramping support. For example, a utility-scale battery could provide peak capacity as well as grid services during non-peak hours.
In order to capture the value of energy storage’s flexible, always-on characteristics, utility planners should include sub-hourly, or at least hourly, intervals in their methodologies, Burwen said.
“Energy storage should be modeled as it will be dispatched,” in order to capture its capacity uses as well as its flexibility, Burwen said.
In head-to-head comparisons, storage can also be at a disadvantage because of the long time-frames used. Conventional technologies are mature and face rising costs because of inflation and higher labor and commodity costs, but the cost of energy storage is coming down. If declining costs are not factored into the planning process, it does not give a true picture of energy storage, Burwen said.
The simplest way to incorporate those benefits is to use a net cost of capacity approach, such as the one used by PGE in its 2016 IRP, he said. ESA’s analysis noted that PGE’s IRP found the operational benefits of storage were expected to be approximately two times larger than the capacity value.
A new methodology in New Mexico
The prospect of rising levels of renewable penetration has also prompted New Mexico to revisit its planning process. This summer, the New Mexico Public Regulation Commission amended the state’s 2017 IRP rules to include energy storage. The amendment creates a distinct listing for energy storage, separate from demand response, and directs investor-owned utilities in the state to evaluate all feasible supply-side and demand-side resources on a “comparable and consistent basis.”
Public Service Co. of New Mexico’s (PNM) 2017-2036 IRP found that energy needs are changing, and “replacing coal supply with renewable energy and more flexible generators will save money for customers in the long run.”
The utility said its near term resource mix could include energy storage, depending on the economics of the proposals it receives in response to an energy storage solicitation it intends to issue as part of its four-year action plan.
In its IRP, PNM took a new look at the usual methodology for utility planning. It looked at its grid and factored in increasing levels of renewable energy penetration and compared the economics of gas-fired peaking plants and energy storage under various levels of renewables.
That analysis typically includes a Loss of Load Expectation, usually expressed in a formula such as “as one day in 10 years,” but in its analysis, PNM added a value for flexibility.
The analysis is “fascinating,” Burwen said. It created a metric based on sudden changes in supply and demand and found that in some scenarios batteries are more cost effective than a gas turbine.
The analysis essentially takes into account the infamous duck curve, first identified in California to demonstrate what happens when solar power peaks mid-day and is followed by a sudden need for quick-ramping gas plants in the evening. PNM’s methodology aims to take in that need for flexible resources and adapt to that need. It is a shift from “static to dynamic modeling,” Burwen said.
PNM brings “a new and different lens to the conversation in that they are developing a new and critical reliability metric that traditional Loss of Load Expectation doesn’t capture,” Burwen said. The utility is “pioneering how to assess reliability in a future with more variable generation.” However, Burwen also noted that PNM still doesn’t include sub-hourly modeling and net cost of capacity like Portland General Electric did.
How well either of those methodologies will work remains to be seen, but it's clear that a growing number of utilities are including energy storage in their IRPs. “More and more utilities understand that if you’re looking out 15 or 20 years and you don’t have storage anywhere in your plan, then you’re not only missing a huge opportunity but also potentially liable for imprudent long-term investment decisions,” Burwen said.
Updated to clarify that PG&E's final 2016 IRP, and not just the draft, had a net cost analysis. Also clarifies input from the Energy Storage Association's Jason Burwen about storage developers competing at the procurement level.
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