Tag Archives: tiered rates

Proposed TOU rate revisions are “fighting the last war” in California

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California’s investor-owned utilities (IOUs) have asserted that the underlying costs molding time variant or time of use (TOU) rate structures should be largely, or even exclusively, derived based on conventional fossil generation costs. The IOUs rely on “net load” to determine TOU prices, calculated by subtracting all load met by renewables, nuclear and hydropower generation—the majority of the utilities’ generation fleets.

In theory, net load is the portion of the load served by fossil-fueled generation that has the highest short-run operating costs, and therefore is “marginal.” The infamous “duck curve” shown above depicts the net load (not the metered load.) Yet, the marginal energy generation for most load is no longer served by natural gas; it is now met by renewable energy contracts. The utilities’ net load approach ignores the bulk of their true marginal costs to serve added load, which arise from procuring renewables.[1] The IOUs’ resource procurement has been dominated by adding solar, wind, biofuels, and other renewables since at least 2006 to meet the state’s renewable portfolio standard (RPS), first at 20 percent, then 33 percent, and soon 50 percent.

The tunnel-vision focus on net, rather than the entire, load is especially problematic in the context of State policy to phase-down fossil fuel generation. Eventually, natural gas production will even more significantly diminish, and could disappear from the grid entirely, leaving no price-setting metric under this paradigm. Insistence on the net load approach in the face of this transformation is akin to evaluating the economics of ridesharing based on the exclusive cost of taxis, without consideration of Uber® and Lyft®.

Once fossil-fuel resources are used minimally – an explicit state goal reflected in SB 350 – and potentially no longer on the margin, it is unclear what price benchmark the utilities will propose to set time-variant rates.  Continuing the trend toward fewer fossil-fuel resources is already reflected in pending legislation in Sacramento that proposes a clean-peak standard – AB 1405[2] – and a 100 percent Renewable Portfolio Standard—SB 584.[3] Relying solely on the cost of generation resources that State policy plans to phaseout to define TOU periods is inconsistent with good, long-term, ratemaking principles.  Instead, marginal energy generation costs should be calculated, at least in part, from a set of recent RPS-eligible PPAs, weighted by time of delivery.

Likewise, the marginal energy costs derived using the net load method, which drive the proposed shifts in TOU periods, reflect less than one-third of total average utility rates. The IOUs do not explain why cost differences within a modest component of overall rates should steer determination of TOU periods.

Further, it is not clear why the California Public Utilities Commission (CPUC) should rely on a speculative forecast about load shapes in 2024—seven years from now—to set today’s TOU periods. As the CPUC is well aware, the electricity system is changing rapidly along many dimensions. Infusion of utility-scale renewables, which is driving the IOUs’ rate analyses, is but one factor. Increasing amounts of storage and electric vehicles, shifting work patterns, and other social and economic factors will substantially influence load profiles over the next decade. In 2006, few energy experts foresaw stagnant, or even falling, electricity demand; there is even greater uncertainty today.

[1]This perspective excludes contributions made by utility-scale renewables that meet most of the remaining load, and by customer-side resources.

[2] See http://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=201720180AB1405

[3] See https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201720180SB584

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Using an event to measure energy savings program effectiveness (again)

Koichiro Ito again has used a discrete event to develop a “control” for an economic experiment. In this case, he has studied PG&E’s 20/20 rebate program in 2004. The “event” he uses is the eligibility date for the program–he uses new customers who connected to service just before and after that date. He finds that the program had almost no effect on coastal customers but that it was effective in reducing energy use for low-income inland consumers. 

Previously, he had looked whether tiered-block rates were better at inducing conservation across the entire pool of customers. The final version of his paper was published February in the American Economic Review. Discerning the true effects of tiered-rates has been very difficult due to the endogeneity problem–consumers essentially set their own marginal price by choosing their consumption level. Many studies have been conducted in both water and electricity trying to tease out this effect, but the results have always been questionable for this reason. 

Ito was able to use two key facts in his latter study: 1) the 2001 California electricity crisis caused rates to rise rapidly and 2) the SCE and SDG&E service areas are closely interlocked across similar communities in southern Orange County. He was able to run an after-the-fact experiment with two treatment groups that had similar socio-economics and were exposed to the same media market. It’s as if two groups of customers were presented with two different sets of rates from the same utility–a truly unique situation that probably can’t be duplicated. He found that the tiered rates induced no more change in energy use than simple average rates.

These well-done studies can cause policymakers to ask whether complicated proposals that seem to mitigate various concerns are truly effective. In these two cases, the answers are largely “no”.