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Rate design wars are the sound of utilities taking residential PV seriously

Imagine walking into your supermarket with a bag of zucchini from your garden and saying that you’d like to trade them straight up for an equal quantity of zucchini next month.

The store manager would explain that they aren’t in the business of making wholesale purchases at such small scale, and that when they do make wholesale purchases it is at a much lower price than the retail price at which they sell.

zucchini

Swapping zucchini today for zucchini tomorrow

You can, of course, eat the zucchini you grow, the manager might say, but once you start trading zucchinis with the store, you can’t expect to get the same price on sales to the store as you pay on purchases from the store.  The margin the store makes between the wholesale and retail price is what pays for the building, heating and cooling, labor, and other costs that are mostly fixed with respect to the amount you buy.

The same economics applies in electricity, only more so.  The retail price, especially in California, is covering a lot more than just the incremental cost of providing an extra kilowatt-hour to you.  In economic terms price is above the marginal cost of the incremental unit of energy, much further above than for goods you buy at the supermarket.  That price gap is paying for past losses from failed deregulation, costly nuclear power, expensive contracts with large scale renewables producers, and local distribution systems that carry power from the grid to your house, as well as metering consumption, billing and account collection.  As a result, when you consume less electricity, the cost the utility saves is much less than the revenue they lose.

Pricing above marginal cost means any decline in energy bought from the utility makes it harder to recover fixed costs, whether the quantity decline is from installing residential solar PV, improving energy efficiency, or just slow economic growth.  But buying less electricity for these reasons corresponds to growing your own zucchini (or just eating less zucchini).

Net metering of solar PV is equivalent to forcing the supermarket to take your zucchini on an even up trade for future zucchini.  The customer gets a one-for-one credit for electricity it puts into the grid against future consumption from the grid.  This expands the customer’s opportunity to save money, though in a way that reduces the utility’s net revenue.

This risk was largely ignored in the mid-1990s when net metering of residential solar PV was established.  It wasn’t that utilities or industry analysts failed to understand the simple math.  It’s that they didn’t think the exposure was very large, because solar PV was so expensive and the subsidies were smaller.  As recently as a decade ago, the cost of a residential system was still north of $10/watt, translating to at least $0.50/kWh.  Even with aggressive state subsidies and small federal subsidies, it was difficult to get the end-use consumer cost below $0.35/kWh.  The average retail price for the kWh replaced by a solar system was generally well below that, so very few consumers could really save money putting in solar.

But technology marches forward and PV panel costs have come way down.  Politics also marches (assign your own direction to it) and the effective subsidies for PV have increased substantially.  The war that is now erupting over tariff design is coming largely from utilities now taking distributed PV seriously.

A decade ago, utilities saw net metering as a small indirect subsidy to a nascent technology that was unlikely to ever be able to compete with even the retail price of electricity.  With plummeting prices of solar panels and some progress on installation costs, along with increased federal subsidies that now cover about half the cost, residential PV can now lower the retail energy bill of many California consumers, particularly customers of the large investor-owned utilities, which have the highest rates.

Two aspects of utility electricity tariffs are major contributors to the attractive economics of residential PV.  First, increasing-block pricing (“IBP”, higher price tiers as you consume more during the month) mean that for some heavy users, solar PV makes sense because it is replacing power on the highest tiers, where those consumers now pay $0.30-$0.40/kWh.  With lower costs and higher subsidies, PV has been able to beat those prices for at least a few years now.  That’s a major factor in the utilities pushing to flatten or eliminate IBP.

But the real panic in the industry has set in this year as the net-of-subsidy cost of PV has dropped below even the average retail price.  Even if increasing-block pricing were eliminated and the big IOUs sold all residential power for their average price of about $0.17/kWh, solar PV could beat that for many customers.  According to a recent report from Lawrence Berkeley Lab (and confirmed by other industry studies and media reports), the full cost of a typical residential system has fallen below $6/watt and may be below $5/watt by now, which corresponds to $0.25-$0.30/kWh.  The 30% federal tax credit and what’s left of the California Solar Initiative subsidies cuts that by about a third.  A less well-known tax effect – accelerated depreciation for leased systems – transfers another 15%-20% of the cost from the end-user to the federal government.  The net cost to the consumer can now be $0.15/kWh or less.

This is why we are hearing more often the phrase “death spiral” from the utilities.  If many customers act on the attractive economics of PV at home, the utility sells less energy and earns less above marginal cost to cover those costs of past sunk mistakes and ongoing fixed costs.  To make up the revenue, they would have to raise rates, which makes the economics of PV even better.

So, the utilities are now desperately pushing for tariff changes that a few years ago they saw as only a distant dream.  Not only do they want to eliminate increasing-block pricing, they want to further reduce the incremental energy price by implementing a fixed monthly charge on each customer, aimed at covering some of the costs of retail distribution, metering and billing.  Most economists support such changes as they move electricity pricing towards a more cost-based system.  In fact, the large publicly-owned utilities – Sacramento (SMUD) and Los Angeles (LADWP) – already have the tariff design the IOUs are now fighting for.  SMUD’s fixed monthly charge is $13, going up to $20 in a few years.

Not surprisingly, solar advocates love IBP and hate fixed monthly charges.  They argue that the proposed changes would hurt the poor – which is true if the changes aren’t accompanied by expanded discounts for low-income customers — though solar PV advocates don’t have a credible track record of protecting poor rate payers.  They also assert, with much less support, that solar PV adds so much extra value to the grid – by reducing line losses and the need for infrastructure upgrades – that solar should be  favored through the advantages that current tariff design gives them.

What makes the policy debate so difficult to resolve is that tariff design is a very indirect way to support residential PV.  In Germany, they’ve gone with feed-in tariffs for solar PV instead – a direct subsidy for every kWh of energy coming from your PV system.  Much simpler, and allows a reasoned debate on tariff design apart from solar PV policy.  But also makes it easier to see how much they are paying people to eat zucchini, and how that is driving up the bills of the people who prefer carrots (as made clear in a recent article in the center/left magazine Spiegel).

In the coming months, we are going to hear a lot of talk about tariff redesigns, solar PV penetration, and the utility business model.  Unless policy makers can separate rate design from residential PV policy, it’s not going to be easy to follow, or pretty to watch.

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Severin Borenstein View All

Severin Borenstein is Professor of the Graduate School in the Economic Analysis and Policy Group at the Haas School of Business and Faculty Director of the Energy Institute at Haas. He received his A.B. from U.C. Berkeley and Ph.D. in Economics from M.I.T. His research focuses on the economics of renewable energy, economic policies for reducing greenhouse gases, and alternative models of retail electricity pricing. Borenstein is also a research associate of the National Bureau of Economic Research in Cambridge, MA. He served on the Board of Governors of the California Power Exchange from 1997 to 2003. During 1999-2000, he was a member of the California Attorney General's Gasoline Price Task Force. In 2012-13, he served on the Emissions Market Assessment Committee, which advised the California Air Resources Board on the operation of California’s Cap and Trade market for greenhouse gases. In 2014, he was appointed to the California Energy Commission’s Petroleum Market Advisory Committee, which he chaired from 2015 until the Committee was dissolved in 2017. From 2015-2020, he served on the Advisory Council of the Bay Area Air Quality Management District. Since 2019, he has been a member of the Governing Board of the California Independent System Operator.

45 thoughts on “Rate design wars are the sound of utilities taking residential PV seriously Leave a comment

  1. This is very interesting, You are a very skilled blogger.

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  2. Good thread.
    I believe that SMUD is approaching this correctly with the phased-in fixed customer charges for various fixed cost elements like T&D capacity, revenue cycle services, and maybe a fraction of public goods programs. Costs for providing firm energy services collected in generation rate elements (that could be fixed and/or volumetric) that would cover EE, DR, storage, fast start peakers should be in a commodity portion, so the customer can seek whatever provider services or physical technologies to optimize that portion of the bill they most directly control. Also need to permit the retail providers to include intermittent integration costs in contracting decisions, which the CPUC has rejected again. Large consumers should be permitted to secure competitive retail services, so a greater portion of our economic engine can better compete nationally and internationally. Lower net consumption (whether from enhanced EE, or DG, or with DR) should also carry a lower carbon cost, particularly if solar production ramp downs can be mitigated or shifted via storage.
    Those ideas could yield some realitively complex rate structures that may improve price signals from an economist’s view, but be perceived by smaller consumers as inequitable or “rigged”, especially if the commodity portion is as dynamic as the CAISO spot markets. But the key concept that residential/small rates need to reflect is the fixed cost recovery component that covers they system T&D requirements for a load shape that will be changing materially with the deployment of enhanced technologies at load centers. There are many moving pieces of the puzzle, particularly with various retirements and need to replace aged firm capacity resources with new resources that will will have high value and relevance over the next few decades.

  3. Severin,
    Great article. A quick question – why did utilities impose increasing-block pricing (“IBP”, higher price tiers as you consume more during the month) in the first place? There must have been some value to them, or it was imposed by the PUCs?
    Thanks!

  4. Behind the meter resources have value. The CPUC has to find a way to quantify value, and make sure customers who provide it are adequately compensated. There’s a growing set of customers who want, and are able to acquire fancy systems (PV, batteries, electric cars, energy management software…you name what comes next here). This equipment will be able to provide genuine capability directly relevant to grid operation. If the CPUC and utilities do not provide a pathway for customers to monetize value to the grid, when they truly deliver it, does anyone think development of this kind of technology will just stop?

    It will not stop. Technology marches forward. Imagine you really like PV and want the latest and greatest. Perhaps you purchase some modest batteries, software, and move the panels so that peak production occurs in late afternoon. You’ve seen the duck curve and arrive at the logical conclusion that your utility will pay the highest price for surplus generation during those later hours; probably an even higher price if it’s delivered in a flat block without spikes or dips. And you read that smart inverters are the way to go, so you install one that does voltage support. You get on the phone with the utility and find all that’s available is a customer charge and an administratively calculated TOU rate for solar purchase, not to mention they’ve done away with the block design and you no longer enjoy the tier 1 rate for low volume users. You call your equipment supplier for advice, who looks at your load and generation profiles and utility rate options, and offers to finance some more batteries and energy efficiency measures so you can self generate 90% of the time. You politely ask your utility for standby service. Then it’s back to the equipment supplier who counters the utility standby rate with an offer of yet more batteries and electricity-to-gas fuel switching. You disconnect utility service.

    Maybe a this tale is a bit far fetched, but now it’s something other than implausible, in the same sense that low cost PV was seen as implausible in the 90s. And I think there’s a market for this sort of thing in California. For folks who want to one-up their neighbors with the latest technology, now perhaps they can do the same to their utility. If it becomes the case that these customers can derive the greatest value from their investments by disconnecting, that’s a real problem for California. On the other hand, it would be even worse if we create a situation that slows down the innovations that are pushing in that direction.

    I offer a solution, one that some may argue could be even be more far fetched than the story I made up about the disconnecting customer. If the CPUC were to allow direct participation of bundled customers with the ISO, and the ISO were to craft a forward capacity market, anyone who has capacity to sell could find a revenue source. Customers like the one above would have a reason to stay connected and increase participation, rather than withdraw their resources and stop innovating.

  5. Above I commented on economic issues. I also worry about the operational problems caused by FITs. We have the problem of excess production by wind at night, causing high frequency and transmission overloads out of wind pockets. We have the “California duck curve” that projects a huge decline in mid-day thermal generation as PV takes over and then a huge climb in the need for thermal generation in the early evening. These operational issues need to be supported by financial incentives that would both control the excesses and incent production during the shortages. Those financial incentives might do better at getting new storage systems in place.

    • Mark, there are many ways to “flatten the duck,” including first and foremost including out of state imports, which we already do, and which were inexplicably excluded from that chart by CAISO. When we also include realistic estimates for energy efficiency, demand response, storage, smart inverters, etc., the duck looks much more like a halibut. My client, the Clean Coalition, has done a lot of work on this. Email me if you’re interested in seeing charts, etc., at tam dot hunt at gmail.

      • Tam, I see a problem with relying on out of state network. I remember attending a renewable workshop by BPA in about 2009 in Portland where California ISO people talked about it giving the rest of the west free electricity during a spring run off. They seemed smarmy about it. And when I considered that California ISO had negative pricing at times, it was making money giving the free electricity away since it was charging generators through its negative pricing.

        My thoughts are that the industry needs a cashout of unscheduled flows of electricity between and among utilities (including ISOs as utilities.) I even wrote a paper on it. Send me a message MbeLively at aol.

  6. As always, this is a great post Severin. The zucchini simplification is one I’m sure I’ll be able to adapt for use as an introduction to the issue with less technical friends and family.

    I’m studying engineering, but recently I’ve taken an interest in learning more about finance and economics. Could you explain further (or point me in the right direction) about the “accelerated depreciation for leased systems” you mentioned? That’s a new piece in the puzzle for me to understand.

  7. Jardinero1 conveniently ignores the externalities involved in other methods of energy production. The cost of greenhouse gases and air pollution justifies the subsidies. They approximate the hidden subsidies given to the other forms.

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