A Simple Solution for NEM 3.0 ?

Well, admittedly nothing is simple when it comes to the California Public Utility Commission (CPUC) rule-making process and energy politics more generally in California.  But the following proposes a solution as to how some greater equity can be established in utility billing without gutting the essential growth of rooftop solar in this state.  As will be shown, a 5-year shortening of the benefit period and moderate increase in PV household utility payments allows homeowners to retain a competitive return on their PV investment while correcting some of the cost-shifting of the current approach.

To review, there are two sides to the debate on establishing new billing/ cost recovery rules for utility customers with rooftop solar PV systems.  (Utilities are the investor-owned utilities (IOUs), primarily Pacific Gas & Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E)).  These utilities observe that rooftop solar has grown to 25% of peak load for PG&E, 33.1% for SDG&E and 16.1% for SCE—well beyond the targets set in original enabling legislation. They contend this high share of rooftop generation has created such problems as:

  • A cost shift of $200+ per year from “wealthier” single family homeowners who are more likely to have installed PV systems to those of middle- and lower-income who are less likely to have such systems (this is reportedly a $2.8 billion cost shift).
  • Overly generous compensation of PV customers; as costs of PV systems have fallen, payback times are as short as 5 years, but benefits continue for 20 years.
  • The cost shift (as above) produces higher electric rates for most Californian’s which results in delaying the environmentally-desired shift to such technologies as electric heat pumps and electric vehicles.
  • Being tied to retail electricity rates, the program benefits are greater for higher income households than for those who participate in statewide electricity price-discount plans (such as the California Alternative Rates for Energy, or CARE).
  • Inadequate price signaling to promote more modern technologies and use patterns (to reflect time-of-day variations as example).

Those supporting a more solar-supportive NEM argue that specific changes proposed by the utilities to address the above problems would double the cost of solar with such changes as:

  • increasing utility charges by $56 to $96/month (depending on IOU)
  • substantially reducing the credit received from electricity supplied to the grid to 5.7¢ (from possibly 25¢ at present)
  • eliminating carry-overs for excess solar production, so excess production in summer would not credit against higher level of grid-obtained electricity in less sunny months

They further contend:

  • The $200 cost shift estimate is twice as high as it should be in reality (from $200 to $100 per year)
  • The proposed changes would eliminate much of the $4-billion, 65,000-employee, rooftop solar installation industry
  • The utility industry argument (resulting in fewer solar PV installations) will result in more transmission and distribution investment on which the utilities make a profit and guaranteed rate of return.
  • The utilities misrepresent the long-term benefits of rooftop solar PV, there-by cutting the “cost” of these investments to non-user by half (from $100 per year to $50/year)
  • The benefits of older rooftop solar installations in avoiding costs that would have been borne by customers is not fully recognized; if included these would further reduce the costs paid by non-users from $50/year to $25/year
  • The utility argument of the cost differential between rooftop solar and larger (utility-scale and other off-site) solar projects is incorrect as it assesses only generation costs, and not the added transmission and distribution costs of moving the electrons.
  • No value is assigned to use of “rooftop” space versus desert or farmland, nor to the reduced fire risk from the added load on transmission lines.

 

There are clearly some major differences of fact and perspective.  And to some extent, a few arguments on each side are not addressed by the opposing perspective.  (Meaning they aren’t being challenged?)

But what seems salient to us is:

  • More needs to be done to seriously address climate change induced by rising atmospheric greenhouse gases. The report by the International Energy Agency released in May this year (https://www.iea.org/reports/net-zero-by-2050) highlights how the efforts by all nations need to be increased significantly if we are to keep atmospheric warming below 1.5°
  • Rooftop PV systems can be a critical part of the necessary transition to renewable energy. A 2016 study by the National Renewable Energy Laboratory (NREL) concluded that rooftops of small buildings (less than 5,000 square feet) in California had the potential to generate almost 44% of the state’s electrical demand (Table 3, https://www.nrel.gov/docs/fy16osti/65298.pdf).  While time-of-day issues aren’t addressed, this substantial potential source of production cannot be ignored.
  • Grid management and time-of-use is becoming increasing important as the amount of intermittent renewable-generated electricity, solar and wind, increase as a share of generation. Indeed, there have been times when the renewables have provided over 90% of the state’s power needs (https://www.latimes.com/environment/newsletter/2021-04-29/solar-power-water-canals-california-climate-change-boiling-point .  This leads to exporting power, and in some cases paying users to take it, https://www.latimes.com/projects/la-fi-electricity-solar/ ). The “duck curve” effect has become increasingly extreme during hours of high solar production. (https://www.enerdynamics.com/Energy-Currents_Blog/The-Duck-Curve-Becomes-Extreme-in-California.aspx ).  Incentives for storage to shift behind-the-meter supply from sunnier to later hours is increasingly desirable.
  • The cost-shift argument appears to have some merit on both sides, recognizing that the exact amount (and its significance) remain in dispute.
  • Infrastructure problems such as wildfire threats are growing as the climate dries; finding ways of reducing the need for substantial transmission system expansion appear desirable. Admittedly, this will also require a change in how IOU investments and investor returns are calculated—not a small change!
  • Finally, we observe the state mandate for rooftop solar on new homes that went into effect in 2020 shouldn’t end-up burdening home buyers with excessive electricity costs and charges for systems they are required (by law) to acquire.

So where do we (CaliforniaSolar.org) see an opportunity for common ground?  We find taking the economic perspective of a homeowner who is considering a solar PV system helps identify this opportunity.

This perspective arises as a neighbor (“Bob”) asked this editor to help him evaluate a PV system for his home in June 2021.  (Disclosure: this editor has had a 2 kW rooftop PV system for 10 years.)  Bob’s annual consumption is 6200 kWh; we identified that a system of about 4 kW at a cost of about $13,000 (about $10,000 after tax if he could fully utilize the benefits) would meet Bob’s household demand. 

Would this be a good investment for Bob?  ABSOLUTELY!  With projected PG&E cost increases and NEM 2.0 rules, this investment (using the after-tax cost and other fixed charges) provided him a 20-year return on investment of 18%– substantially better than any other opportunity. Bob’s problem is now finding an installer with the capacity to take on the project!

BUT what if Bob could only benefit for 15 years?  Still a 14% rate of return.  Shortening the duration of the benefit period from 20 to 15 years would not be a “deal breaker” for him.  Or, what if he was required to pay a share of the grid-supplied electricity he was not using, perhaps 25% of the retail rate of what he was self-generating? (In effect, a cost recovery or “in lieu of” fee.)    His rate of return (20 years) would be 10%, a return he still found attractive.  Finally, allowing him to pay a 25% cost-recovery fee AND for only 15 years (before returning to full retail) would make his financial return marginally more attractive (compared to other investments) at 7%, but for him still desirable as he’s also committed to producing environmental (carbon emission reduction) benefits.

We observe that as Bob’s cost-recovery payment would be about $400 per year ($35 per month), he would eliminate any cross subsidy he was placing on homeowners who could not afford a PV system even assuming the highest (IOU) charges identified.

Our conclusion? From the perspective of a possible PV customer, a 5-year shortening of the benefit period and a modest rise in fees (25% or less then full retail equivalent) appears not to have a strong adverse impact on the financial benefits of a PV system as an investment for a homeowner.  It appears there is room to maneuver with increased utility revenues and reductions in benefits to homeowners installing PV systems that result in benefits to each, while continuing California’s lead (and example-setting) for the energy transition we badly need.

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