Tag Archives: reliability

Outages highlight the need for a fundamental revision of grid planning

The salience of outages due to distribution problems such as occurred with record heat in the Pacific Northwest and California’s public safety power shutoffs (PSPS) highlights a need for a change in perspective on addressing reliability. In California, customers are 15 times more likely to experience an outage due to distribution issues rather than generation (well, really transmission outages as August 2020 was the first time that California experienced a true generation shortage requiring imposed rolling blackouts—withholding in 2001 doesn’t count.) Even the widespread blackouts in Texas in February 2021 are attributable in large part due to problems beyond just a generation shortage.

Yet policymakers and stakeholders largely focus almost solely on increasing reserve margins to improve reliability. If we instead looked the most comprehensive means of improving reliability in the manner that matters to customers, we’d probably find that distributed energy resources are a much better fit. To the extent that DERs can relieve distribution level loads, we gain at both levels and not just at the system level with added bulk generation.

This approaches first requires a change in how resource adequacy is defined and modeled to look from the perspective of the customer meter. It will require a more extensive analysis of distribution circuits and the ability of individual circuits to island and self supply during stressful conditions. It also requires a better assessment of the conditions that lead to local outages. Increased resource diversity should lead to improved probability of availability as well. Current modeling of the benefits of regions leaning on each other depend on largely deterministic assumptions about resource availability. Instead we should be using probability distributions about resources and loads to assess overlapping conditions. An important aspect about reliability is that 100 10 MW generators with a 10% probability of outage provides much more reliability than a single 1,000 MW generator also with a 10% outage rate due to diversity. This fact is generally ignored in setting the reserve margins for resource adequacy.

We also should consider shifting resource investment from bulk generation (and storage) where it has a much smaller impact on individual customer reliability to lower voltage distribution. Microgrids are an example of an alternative that better focuses on solving the real problem. Let’s start a fundamental reconsideration of our electric grid investment plan.

PG&E fails to provide safety support in Davis

This article on a local webnews site, the Davis Vanguard, describes how PG&E was slow to respond and has since failed to communicate with homeowners about subsequent measures to be taken. Note that in this case, the power lines run down an easement through the backyards of these houses. 

Chasing gold at the end of the rainbow: how reliance on hourly markets doesn’t spur generation investment


Commentators have touted the Texas ERCOT market as the epitome of how a fully functioning hourly electricity market can deliver the economic signals needed to spur investment in new capacity. They further assert that this type of market can be technology neutral in what type of investment is made. The Federal Energy Regulatory Commission (FERC) largely adopted this position more than two decades ago when it initiated restructuring that led to the creation of these hourly markets, including the California Independent System Operator (CAISO). And FERC continues to take that stance, although it has allowed for short term capacity markets to backfill for reliability needs.

But now we hear that the Texas market is falling short in incenting new capacity investment. ERCOT which manages the Texas grid projects near term risks and a growing shortfall at least to 2024. At issue is the fact that waiting around for the gambler’s chance at price spike revenues doesn’t make a strong case for financing capital intensive generation, particularly if one’s own investment is likely to make those price spikes disappear. It’s like chasing the gold at the end of the rainbow!

This is another sign that hourly markets are not reliable indicators of market value, contrary to the view of proponents of those markets. The combination of the lumpiness of generation investment and the duration of that generation capital, how that new generation undermines the apparent value in the market, and the lack of political tolerance for failures in reliability or meeting environmental targets require that a much more holistic view of market value for these investments. The value of hedging risk, providing cost stability, improving reliability and resilience and reducing overall portfolio costs all need to be incorporated into a full valuation process.

Repost: A catalog of studies on whether renewables create grid instability | Greentech Media

GTM compiles the studies done over the last month in anticipation of the release of the study ordered by Energy Secretary Rick Perry to examine how increased renewable energy threatens grid reliability.

Source: The Rising Tide of Evidence Against Blaming Wind and Solar for Grid Instability | Greentech Media

Study shows investment and reliability are disconnected

Lawrence Berkeley National Laboratory released a study on how utility investment in transmission and distribution compares to changes in reliability. LBNL found that outages are increasing in number and duration nationally, and that levels of investment are not well correlated with improved reliability.

We testified on behalf of the Agricultural Energy Consumers Association in both the SCE and PG&E General Rate Cases about how distribution investment is not justified by the available data. Both utilities asked for $2 billion to meet “growth” yet both have seen falling demand since 2007. PG&E invested $360 million in its Cornerstone Improvement program, but a good question is, what is the cost-effectiveness of that improved reliability? Perhaps the new distribution resource planning exercise will redirect investment in a more rationale way.

Questions yet to be answered from the CAISO Symposium

While attending the CAISO Stakeholder Symposium last week I had rush of questions, not all interconnected, about how we manage the transition to the new energy future. I saw two very different views about how the grid might be managed–how will this be resolved? How do we consider path dependence in choosing supporting and “bridge” resources? How do we provide differential reliability to customers? How do we allow utilities to invest beyond the meter?

Jesse Knight, former CPUC Commissioner and now chairman at SDG&E and SCG, described energy utilities as the “last monopoly” in the face of a rapidly changing economic landscape. (Water utilities may have something to say about that.) SDG&E is ahead of the other utilities in recognizing the rise of the decentralized peer-to-peer economy.  On the other hand, Clark Gellings from EPRI described a world in which the transmission operator would have to see “millions” of nodes, both loads and small generators, to operate a robust network. This view is consistent with the continued central management implied by the utility distribution planners at the CPUC’s distribution planning OIR workshop. At the end of the symposium, 3 of the 4 panelist said that the electricity system would be unrecognizable to Thomas Edison. I wonder if Alexander Graham Bell would recognize our telecommunications system?

One question posed to the first “townhall” panel asked what role natural gas would have in the transition to more renewables. I am not aware of any studies conducted on whether and how choices about generation technology today commits us to decisions in the future. Path dependence is an oft overlooked aspect of planning. We can’t make decisions independent of how we chose in the past. That’s why it’s so difficult to move away from fossil fuel dependence now–we committed to it decades ago. We shouldn’t ignore path dependence going forward. Building gas plants now may commit us to using gas for decades until the financial investments are recovered. We may be able to buy our way out through stranded asset payments, but we learned once before that wasn’t a particularly attractive approach. Using forethought and incorporating flexibility requires careful planning.

And along those lines in our breakout session, another question was posed about how to resolve the looming threat of “overgeneration” from renewables, particularly solar.  Much of the problem might be resolved by charging EVs during the day, but it’s unlikely that a sizable number of plug-in hybrids and BEVs will be on the road before the mid-2020s. So the question becomes should we invest in gas-fired generation or battery or pumped storage, both of which have 20-30 year economic lives, or try to find other shorter lived transitions including curtailment contracts or demand response technologies until EVs arrive on the scene? It might even be cost effective to provide subsidies to accelerate adoption of EVs so as to avoid long-lived investments that may become prematurely obsolete.

Pricing for differential reliability among customers also came up. Often ignored in the reliability debate at the CAISO is that the vast majority of outages are at the distribution level. We appear to be overinvested in transmission and generation reliability at the expense of maintaining the integrity of the local grid. We could have system reliability prices that reflect costs of providing flexible service to follow on-site renewable generation. However the utilities already recover most of the capital costs of providing those services through rate of return regulation. The market prices are suppressed (as they are in the real time market where the IOUs dump excess power) so we can’t expect to see good price signals, yet.

Several people talked about partnerships with the utilities in investing in equipment beyond the meter. But the question is will a utility be willing to facilitate such investments if they degrade the value of its current investment in the grid? Fiduciary responsibility under traditional return on capital regulation says only if the cost of the new technology is higher so as to generate higher returns than the current grid investment. That doesn’t sound like a popular recipe for a new energy future.  Instead, we need to come up with creative means of utility shareholders participating in the new marketplace without forcing them down the old regulatory path.

Margaret Jolly from ConEd noted that the stakeholders were holding conversations on the new future but “the customer was not in the room.” Community, political and business leaders who know how electricity is used were not highly evident, and certainly didn’t make any significant statements. I’ve written before about offering more rate options to customers. I wanted to hear more from Ellen Struck about the Pecan Street study, but her comments focused on the industry situation, not customers’ behaviors and choices.