In a transmission plan approved in March, the California Independent System Operator cancelled 13 sub-transmission projects that previously had been approved in Pacific Gas & Electric (PG&E) territory. PG&E supported the project cancellations, which will save customers $192 million. The utility pointed out that rooftop solar and energy efficiency have reduced their load forecast and stated, “The need for those is just not there anymore.”
This is a clear example of distributed solar’s reducing utility infrastructure costs, but it does not answer the question of how to quantify future spending reductions that result from increasing amounts of solar.
Optimal Locations For Solar
A primary conclusion of the recent net-metering debate in California was that more time is needed to accurately measure the benefits of distributed solar. That effort is now in full swing, with multiple working groups and proceedings.
The question is complicated by the fact that solar is more valuable to the grid in some places than others. Utilities have traditionally spread costs and benefits evenly across their service territories, but the California Public Utilities Commission (CPUC) may decide to give distributed solar different value depending on where it is connected. Nobody is quite sure where these regulatory discussions will end up, but they are certainly heading in an interesting direction.
A.B.327, passed in 2013, is known as the legislation that led to flattening the residential rate tiers and forcing the creation of NEM 2.0. A lesser noticed portion of the bill directs utilities to “identify optimal locations for the deployment of distributed resources.” Under the direction of the CPUC, utilities filed plans last July with proposals for how to determine location-specific costs and benefits.
One of the first steps is to improve the mapping of existing capacity on the grid. Many solar developers in California are familiar with the “RAM maps” that were created for the renewable auction mechanism. These maps show distribution circuits throughout a utility territory that are color-coded based on how much capacity there is to host new solar installations. Developers have been able to use the maps to identify good locations for site development. The idea is good, but the data has been crude and unreliable.
As part of the new planning process, these maps are now being improved. The ultimate goal is a plug-and-play grid, where circuits are essentially pre-engineered to determine how much solar can go in each location at any time.
Currently, the maps show hosting capacity based on distributed resources that are already connected, but there is no way to know if there are other projects already in the queue that will use up available capacity. If developers are going to rely on the maps, and the interconnection process is going to use them, the maps need to include projects under development. To update their maps in real time as projects move through the development process is no small feat for the utilities.
Another initial step that is moving in parallel with the mapping exercise is to develop a methodology for determining location-specific values for the benefits of solar and storage. Stakeholders have identified the categories of benefits that need to be quantified. Once that list is finalized, the hard work begins to decide on the math.
One practical outcome in the near term is to look at the list of distribution system projects that are already planned and figure out which ones can be deferred by distributed alternatives.
Southern California Edison has held competitive solicitations to address local needs stemming from the loss of the San Onofre nuclear power plant. These have been generally successful, and the experience can be applied to ongoing system growth and maintenance. In addition, the CPUC has proposed a pilot project that would direct utilities to announce at least two requests for offers (RFOs) per year for alternatives to traditional investments.
The proposal includes a sweetener for the utilities: guaranteeing them equal profit for distributed and centralized solutions. Utilities have traditionally resisted giving solar credit for its value to the grid because utility profits are pegged to capital expenses on infrastructure. Their fiduciary responsibility to shareholders pushes them to favor substation upgrades over customer-sited solutions.
CPUC Commissioner Michel Florio has responded to this problem with a proposal to give utilities an incentive to propose alternatives to substation upgrades. The proposal seeks to give utilities the same return on distributed solutions to grid challenges as centralized infrastructure solutions. Utilities put out an RFO for distributed energy resources in a specific area, companies bid project portfolios, utilities sign a power purchase agreement, developers build systems, utilities get a return and everybody’s happy.
It is not clear, however, that regulated profit on utility procurement of distributed solutions would truly motivate utilities to propose alternatives to the traditional way of doing things. Their official response was that consideration of incentives and profit motive is premature.
Data And Tariffs
An alternative to encouraging utilities to propose distributed solutions is to make enough data available for third parties to be able to see system needs and propose alternatives. Solar and storage companies have recommended a long list of data types to become publicly available. Utilities are concerned that companies competing in RFOs would not price their bids low enough if they have too much visibility into utility cost-savings.
Yet another approach would be to create tariffs based on locational benefits and let the competitive market deliver results. Getting the utilities to change their procurement strategies to address system needs is one thing; trusting markets is another.
Nobody wants tariffs that change every time you turn the corner, but markets can move faster than top-down procurement. The CPUC is looking for the right balance between consistency and precise price signals.
One potential tariff structure is simply the inclusion of a locational benefits adder that could be layered on top of existing rate schedules for projects located within specified zones. Other ideas may emerge. The CPUC has signaled it will develop tariffs incorporating locational benefits but intends to work on competitive solicitations first.
From last October through February of this year, a failed wellhead at a natural gas storage facility at Aliso Canyon, located near Los Angeles, leaked an estimated 5.4 billion cubic feet of natural gas. The greenhouse-gas emissions from this leak equate to half a million cars driving in circles for a year.
Aliso Canyon is the largest natural gas storage facility in the West. It has been key to assuring electric system reliability in the transmission-constrained LA Basin. During hot summer months, when demand can increase quickly when people turn on air conditioners, gas-fired power plants ramp up production in a hurry.
On some days, gas pipelines and electric transmission lines are tapped out, and it is only local power plants fueled by gas stored in Aliso Canyon that can meet demand. This summer, that’s not an option, and regulators have warned of potential blackouts.
The state has been scrambling to clear the way for more solar PV, solar water heating and energy storage in the LA Basin to help alleviate this problem. In this case, nobody is even questioning whether local energy solutions can avoid the need for new transmission. It is painfully obvious.
As solar penetration grows, solar customers will probably be required to pay more in fees or accept less in compensation for exported power. Location-specific values may become available to offset those changes for customers that are in the right places, and improved interconnection tools can reduce soft costs. If the solar sales process keeps pace with more sophisticated opportunities, market growth can remain strong.
Author’s note: Brad Heavner is policy director at the California Solar Energy Industries Association.