Tag Archives: UC Energy Institute

Can Net Metering Reform Fix the Rooftop Solar Cost Shift?: A Response

A response to Severin Borenstein’s post at UC Energy Institute where he posits a large subsidy flowing to NEM customers and proposes an income-based fixed charge as the remedy. Borenstein made the same proposal at a later CPUC hearing.

The CPUC is now considering reforming the current net energy metering (NEM) tariffs in the NEM 3.0 proceeding. And the State Legislature is considering imposing a change by fiat in AB 1139.

First, to frame this discussion, economists are universally guilty of status quo bias in which we (since I’m one) too often assume that changing from the current physical and institutional arrangement is a “cost” in an implicit assumption that the current situation was somehow arrived at via a relatively benign economic process. (The debate over reparations for slavery revolve around this issue.) The same is true for those who claim that NEM customers are imposing exorbitant costs on other customers.

There are several issues to be considered in this analysis.

1) In looking at the history of the NEM rate, the emergence of a misalignment between retail rates that compensate solar customers and the true marginal costs of providing service (which are much more than the hourly wholesales price–more on that later) is a recent event. When NEM 1.0 was established residential rates were on the order of 15 c/kWh and renewable power contracts were being signed at 12 to 15 c/kWh. In addition, the transmission costs were adding 2 to 4 c/kWh. This was the case through 2015; NEM 1.0 expired in 2016. NEM 2.0 customers were put on TOU rates with evening peak loads, so their daytime output is being priced at off peak rates midday and they are paying higher on peak rates for usage. This despite the fact that the difference in “marginal costs” between peak and off wholesale costs are generally on the order of a penny per kWh. (PG&E NEM customers also pay a $10/month fixed charge that is close to the service connection cost.) Calculating the net financial flows is more complicated and deserve that complex look than what can be captured in a simple back of the envelope calculation.

2) If we’re going to dig into subsidies, the first place to start is with utility and power plant shareholders. If we use the current set of “market price benchmarks” (which are problematic as I’ll discuss), out of PG&E’s $5.2 billion annual generation costs, over $2 billion or 40% are “stranded costs” that are subsidies to shareholders for bad investments. In an efficient marketplace those shareholders would have to recover those costs through competitively set prices, as Jim Lazar of the Regulatory Assistance Project has pointed out. One might counter those long term contracts were signed on behalf of these customers who now must pay for them. Of course, overlooking whether those contracts were really properly evaluated, that’s also true for customers who have taken energy efficiency measures and Elon Musk as he moves to Texas–we aren’t discussing whether they also deserve a surcharge to cover these costs. But beyond this, on an equity basis, NEM 1.0 customers at least made investments based on an expectation, that the CPUC did not dissuade them of this belief (we have documentation of how at least one county government was mislead by PG&E on this issue in 2016). If IOUs are entitled to financial protection (and the CPUC has failed to enact the portfolio management incentive specified in AB57 in 2002) then so are those NEM customers. If on the other hand we can reopen cost recovery of those poor portfolio management decisions that have led to the incentive for retail customers to try to exit, THEN we can revisit those NEM investments. But until then, those NEM customers are no more subsidized than the shareholders.

3) What is the true “marginal cost”? First we have the problem of temporal consistency between generation vs. transmission and distribution grid (T&D) costs. Economists love looking at generation because there’s a hourly (or subhourly) “short run” price that coincides nicely with economic theory and calculus. On the other hand, those darn T&D costs are lumpy and discontinuous. The “hourly” cost for T&D is basically zero and the annual cost is not a whole lot better. The current methods debated in the General Rate Cases (GRC) relies on aggregating piecemeal investments without looking at changing costs as a whole. Probably the most appropriate metric for T&D is to calculate the incremental change in total costs by the number of new customers. Given how fast utility rates have been rising over the last decade I’m pretty sure that the “marginal cost” per customer is higher than the average cost–in fact by definition marginal costs must be higher. (And with static and falling loads, I’m not even sure how we calculated the marginal costs per kwh. We can derive the marginal cost this way FERC Form 1 data.) So how do we meld one marginal cost that might be on a 5-minute basis with one that is on a multi-year timeframe? This isn’t an easy answer and “rough justice” can cut either way on what’s the truly appropriate approximation.

4) Even if the generation cost is measured sub hourly, the current wholesale markets are poor reflections of those costs. Significant market distortions prevent fully reflecting those costs. Unit commitment costs are often subsidized through out of market payments; reliability regulation forces investment that pushes capacity costs out of the hourly market, added incremental resources–whether for added load such as electrification or to meet regulatory requirements–are largely zero-operating cost renewables of which none rely on hourly market revenues for financial solvency; in California generators face little or no bankruptcy risk which allows them to underprice their bids; on the flip side, capacity price adders such as ERCOT’s ORDC overprices the value of reliability to customers as a backdoor way to allow generators to recover investments through the hourly market. So what is the true marginal cost of generation? Pulling down CAISO prices doesn’t look like a good primary source of data.

We’re left with the question of what is the appropriate benchmark for measuring a “subsidy”? Should we also include the other subsidies that created the problem in the first place?

Study shows RPS spillover positive to other states

honda-windfarm

A study in the Journal of the Association of Environmental and Resource Economics entitled “External Impacts of Local Energy Policy: The Case of Renewable Portfolio Standards” finds that increasing the renewable portfolio standard (RPS) in one state reduces coal generation in neighboring states through trading of renewable energy credits (RECs). This contrasts with findings on greenhouse gas emission “leakage” under California’s cap and trade program put forth by the authors at the Energy Institute at Haas at the University of California here and here.

These latter set of findings has been used California Public Utilities Commissioners to argue against the use of RECs and implication that community choice aggregators (CCAs) are not moving forward increased renewables generation. This new study appears to land on the side of the CCAs which have argued that even relying on RECs in the short run have a positive effect reducing GHG emissions in the West.

Creative Pie Slicing To Address Climate Policy Opposition | Energy Institute at Haas

Severin Borenstein’s post raises an important issue that economists have ignore for too long. I posted the following comment there:

We gave politicians the tool of benefit-cost analysis which they have used to justify their policy objectives, but we completely failed to drive home the requirement that those parties who are on the losing end need to be compensated as well. I looked in my edition of Ned Gramlich’s book on Benefit-Cost Analysis (who taught my course), and the word “compensation” is not even in the index! Working on environmental regulations, I regularly see agency staff derive large positive ratios for the “general public” and then completely dismiss the concerns of particular groups that will be carrying all the burdens of delivering those benefits. If we’re going to teach benefit-cost analysis, we need to emphasize the “cost” side as much as the “benefit” that politicians love to extol.

Source: Creative Pie Slicing To Address Climate Policy Opposition |

A brief reply to “Real” Electricity Still Comes from the Grid

Source: “Real” Electricity Still Comes from the Grid

Catherine Wolfram at UC Berkeley posted about their paper looking at costs of distributed energy systems in Kenya and concluding that these were too expensive for households compared to connecting to the grid. However, the paper came under immediate criticism.

Here’s my thoughts based on her representation of the paper’s findings, some of which are mirrored by other commentators:

First, the paper talks about costs on one side, but doesn’t put them in perspective to the alternatives. The post lists the cost of the individual systems, but not the expected connection costs to the grid.

Further the paper takes a static look at current costs and doesn’t account for the differential trends in the sets of costs for an home-based system versus connecting to the grid. The latter costs can be expected to be steady or even rising, while it’s well known that both solar and storage costs have fallen rapidly.

Different scales of “grid” also are important. For example, solar projects show scale economies up to about 3 MW but then modular construction flattens the per kW cost. A village microgrid separate from a national central grid may be quite cost competitive.

Finally, the paper appears to lump large hydro in with other utility-scale renewables. The environmental (and economic development) record for large-scale hydro projects in the developing world is dubious at best. There is evidence of significant methane emissions from tropical reservoirs. Habitat is destroyed and poorly designed projects don’t deliver expected benefits. Hydro is by far the largest energy supplier on these grids, and they may be little better than coal from an overall environmental perspective.

Reblog: If you like your time-invariant electricity price, you can keep it

Severin Borenstein at the Energy Institute at Haas makes the case for giving customers the choice of TOU or fixed price rates. I’ve commented several times on the Energy Institute blog about this approach, and blogged myself about the need for this option.

Source: If you like your time-invariant electricity price, you can keep it

Reblog: Leaking Coal to Asia

Maximillian Auffhammer at UC’s Energy Institute @ Haas focuses on the issue of exporting coal from the Port of Oakland, but he turns to the issue I highlighted recently–the path to accomplishing environmental objectives should travel through compensating those who are worse off from such policies.

Source: Leaking Coal to Asia

A shocking finding on energy efficiency cost effectiveness

A study just released from the E2e Project finds that the investment costs in residential energy efficiency greatly exceed the realized benefits.  Earlier the same research program found that even if the energy efficiency measure packages, costing up to $5,000, were given away for free, only 6% of low income homeowners would participate. This is one of the first projects to track from start to finish a full set of energy efficiency projects. Much controversy has swirled around the accuracy of the engineering calculations used to estimate energy savings, and whether market barriers are impeding participation in what appears to be obvious cost saving actions. This study calls into question the premise of “costlessly” promoting energy efficiency actions.

The Project is run jointly by the University of California’s Energy Institute at Haas, the University of Chicago’s EPIC, and MIT.

Reexamining growth and risk sharing for utilities

Severin Borenstein at the Energy Institute at Haas blogged about the debate over moving to residential fixed charges, and it has started a lively discussion. I added my comment on the issue, which I repost here.

The question of recovery of “fixed” costs through a fixed monthly charge raises a more fundamental question: Should we revisit the question of whether utilities should be at risk for recovery of their investments? As is stands now if a utility overinvests in local distribution it faces almost no risk in recovering those costs. As we’ve seen recently demand has trended well below forecasts since 2006 and there’s no indication that the trend will reverse soon. I’ve testified in both the PG&E and SCE rate cases about how this has led to substantial stranded capacity. Up to now the utilities have done little to correct their investment forecasting methods and continue to ask for authority to make substantial “traditional” investment. Shareholders suffer few consequences from having too much distribution investment–this creates a one-sided incentive and it’s no surprise that they add yet more poles and wire. Imposing a fixed charge instead of including it as a variable charge only reinforces that incentive. At least a variable charge gives them some incentive to avoid a mismatch of revenues and costs in the short run, and they need to think about price effects in the long run. But that’s not perfect.

When demand was always growing, the issue of risk-sharing seemed secondary, but now it should be moving front and center. This will only become more salient as we move towards ZNE buildings. What mechanism can we give the utilities so that they more properly balance their investment decisions? Is it time to reconsider the model of transferring risk from shareholders to ratepayers? What are the business models that might best align utility incentives with where we want to go?

The lesson of the last three decades has been that moving away from direct regulation and providing other outside incentives has been more effective. Probably the biggest single innovation that has been most effective has been imposing more risk on the providers in the market.

California has devoted as many resources as any state to trying to get the regulatory structure right–and to most of its participants, it’s not working at the moment. Thus the discussion of whether fixed charges are appropriate need to be in the context of what is the appropriate risk sharing that utility shareholders should bear.

This is not a one-side discussion about how groups of ratepayers should share the relative risk among themselves for the total utility revenue requirement. That’s exactly the argument that the utilities want us to have. We need to move the argument to the larger question of how should the revenue requirement risk be shared between ratepayers and shareholders. The answer to that question then informs us about what portion of the costs might be considered unavoidable revenue responsibility for the ratepayers (or billpayers as I recently heard at the CAISO Symposium) and what portion shareholders will need to work at recovering in the future. As such the discussion has two sides to it now and revenue requirements aren’t a simple given handed down from on high.

Repost: Californians Can Handle the Truth About Gas Prices

Sev Borenstein writes about the two sides of the argument on whether transportation fuels should be rolled into the cap-and-trade program in January 2015.

I have an observation that that has only been alluded to indirectly in the debate. The main point of the legislators’ letter calling for a delay in implementation is that low income groups may be particularly hit. The counter argument that we need the inclusion of transportation fuels under the cap to incent innovation seems to pit the plight of the poor against the investment risk of wealthy entrepreneurs. We haven’t really done a good job of addressing affordability of the transformative policies that can change GHG emissions. The proposal to use carbon tax revenues to rebate to low income taxpayers has been floated at the national level, but of course that died with the rest of the national cap and trade proposal. A similar proposal was made to mitigate electricity price impacts.

Our state legislators are rightfully concerned about the impacts on those among us who have the least. Nevertheless, that problem is easily addresses with the tools and resources that are already available to the state. Those families and households who now qualify for the CARE and FERA electric and natural gas utilities rate discounts can be made eligible for an annual rebate equal to the average annual gasoline consumption multiplied by the amount of the GHG allowance cost embedded in the gasoline price. This rebate could be funded out of the state’s allowance revenue fund. For example, if the price is increased by 15 cents per gallon and the average automobile uses 650 gallons per year, an eligible household could receive $97.50 for each car.

About 30% of households are currently eligible for CARE or FERA. On a statewide basis, the program would cost about $650 million, which is comparable to the cost for CARE for a single utility like PG&E or Southern California Edison. Those legislators who are most concerned can coauthor legislation to put this program in place.

(BTW, I think the DOE fuel use calculator is outdated–on my many trips to LA I haven’t seen these types of fuel economy changes. My average MPG is pretty much the same no matter how much traffic there is on I-5.  But that’s just a fun fact aside…)