Tag Archives: CAISO

PG&E apologizes, yet again

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(Image: ABC 7 News)

I listened to PG&E’s CEO Bill Johnson and his staff apologize for its mishandling of the public safety power shutoffs (PSPS) that affected over 700,000 “customers” (what other industry calls meters “customers”?) yesterday. And as I listened, I thought of the many times that PG&E has fumbled (or even acted maliciously) over the years. Here’s my partial list (and I’m leaving out the faux pas that I’ve experienced in regulatory proceedings):

  • Failing to turn off power locally in 2017 and 2018 under hazardous weather conditions, which led to the Wine Country and Camp fires.
  • Failing to install distribution shut off equipment that was installed by San Diego Gas & Electric and Southern California Edison after the 2007 wildfires in Southern  California.
  • Signing too many power purchase agreements with renewables in the 2009 to 2014 period that were for too long of terms (e.g., 20 years instead of 10 years). PG&E is unable to take advantage of the dramatic cost decreases created by California’s bold investments. For a comparison, PG&E’s renewable portfolio costs about 20% more than SCE’s. (I am one of a few that has access to the confidential portfolio data for both utilities.)
  • Failing to act on the opportunity to sell part of its overstuffed renewable portfolio to the CCAs that emerged from 2010 to 2016. Those sales could have benefited everyone by decreasing PG&E’s obligations and providing the CCAs with existing firm resources. That opportunity has now largely passed.
  • The gas pipeline explosion in San Bruno in 2010 caused by PG&E’s failure to keep proper records for decades. PG&E was convicted of a felony for its negligence.
  • Overinvesting in obsolete distribution infrastructure after 2009 by failing to recognize that electricity demand had flattened and that customers were switching en masse to solar rooftops. (I repeatedly filed testimony starting in 2010 pointing out this error.)
  • Deploying an Advanced Meter Infrastructure (AMI) system starting in 2004 using SmartMeters that claimed that it would provide much more control of PG&E’s distribution system, and deliver positive benefits to ratepayers. Savings have largely failed to materialize, and PG&E’s inability to use its AMI to more narrowly target its PSPS illustrates how AMI has failed to deliver.
  • Acquiring and building three unneeded natural gas plants starting in 2006. Several merchant-owned plants constructed in the early 2000s are already on the verge of retiring because of the flattening in demand.
  • Failing to act in May 2000 to end the “competitive transition” period of California’s restructuring by agreeing to the market valuation of its hydropower system.
  • If PG&E had ended the transition period, it would have been immediately free to sign longer term contracts with merchant generators, thereby taking away the incentive for those generators to manipulate the market. The subsequent energy crisis most likely would have not occurred, or been much more isolated to Southern California.
  • PG&E’s CEO in 1998 made a speech to the shareholders stating that it was PG&E’s intent to extend the transition period as far as possible, to March 2001 at least. (We cited this speech from a transcript in the 1999 GRC case.)
  • Offering rebuttal in the 1999 GRC that instead confirmed the ORA’s analysis that the optimal size of a utility is closer to 500,000 customers rather than 4 million plus. Commissioner Bilas wrote a draft decision confirming this finding, but restructuring derailed the vote on the case.
  • Being caught by the CPUC in diverting $495 million from maintenance spending to shareholders from 1992 to 1997. PG&E was fined $29 million.
  • Forcing the CPUC in 1996 to adopt the “competitive transition charge” which was tied to the fluctuating CAISO day-ahead market price instead of using Commissioner Knight’s up front pay out for stranded assets. The CTC led to the “transition period” which facilitated the ability of merchant generators to manipulate the market price.
  • Two settlement agreements allow PG&E to fully recover its costs in Diablo Canyon by January 1, 1998 based on its authorized rate of return from 1986 to 1998, but also allows it to put into ratebase about half of its “remaining” construction costs as a prelude to restructuring.
  • Getting caught in 1990 telling FERC that PG&E was short resources and needed to build more, while telling the CPUC that it had a long term surplus and that it needed to curtail its payments to third-party qualifying facilities (QF) generators.
  • In the early 1980s, failing to set up a rationale process for signing QF contracts that limited the addition of these resources. In addition, PG&E missed an important pricing calculation mistake in the capacity payment term that led to a double payment to QFs.
  • In the 1970s, making many construction management mistakes when building the Diablo Canyon nuclear power plant, including reversing the blueprints, that led to the costs rising from $315 million to over $5 billion. (And Diablo Canyon in 3 of the last 5 years has operated at a loss and should not have been generating for several months each of those years.)
  • In the 1960s, signing an agreement with Sacramento Municipal Utility District (SMUD) to finance the construction of the Rancho Seco nuclear plant that essentially gave SMUD free energy when Rancho Seco wasn’t generating. The result was the mismanagement of the plant, which was so damaged that it was closed in 1989 (in part as a result of analysis conducted by the consulting team that I was on.)

The other two California IOUs are guilty of some of these same errors, and SMUD and Los Angeles Department of Water and Power (LADWP) also do not have a clean bill of health, but the quantities and magnitudes to don’t match those of PG&E.

The Business Roundtable takes the wrong lesson from California’s energy costs

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The California Business Roundtable authored an article in the San Francisco Chronicle claiming that the we only need to look to California’s energy prices to see what would happen with the “Green New Deal” proposed by the Congressional Democrats.

That article has several errors and is misleading in others aspects. First, California’s electricity rates are high because of the renewable contracts signed nearly a decade ago when renewables were just evolving and much higher cost. California’s investment was part of the reason that solar and wind costs are now lower than existing coals plants (new study shows 75% of coal plants are uneconomic) and competitive with natural gas. Batteries that increase renewable operations have almost become cost effective. It also claims that reliability has “gone down” when in fact we still have a large reserve margin. The California Independent System Operator in fact found a 23% reserve margin when the target is only 17%. We also have the ability to install batteries quickly to solve that issue. PG&E is installing over 500 MW of batteries right now to replace a large natural gas plant.

For the rest of the U.S., consumers will benefit from these lower costs today. Californians have paid too much for their power to date, due to mismanagement by PG&E and the other utilities, but elsewhere will be able to avoid these foibles.

(Graphic: BNEF)

CAISO: Renewables served 42% of California demand on May 16, setting record | Utility Dive

During the 2 p.m. hour, renewables served more than 70% of power demand, setting another record in California.

Source: CAISO: Renewables served 42% of California demand on May 16, setting record | Utility Dive

Repost: CAISO notches record, serving 56.7% of demand with renewable energy in one day | Utility Dive

Solar and wind power combined also hit a peak on the same day by serving 49.2% of demand.

Source: CAISO notches record, serving 56.7% of demand with renewable energy in one day | Utility Dive

Push comes to shove on whether electricity markets are functioning

Over the last year, various states have introduced subsidies and preferences for different electricity resources that have circumvented the independent system operator (ISO) markets that the Federal Energy Regulatory Commission (FERC) approved in the 1990s. FERC’s intent was that hourly markets would provide all of the price signals needed to induce appropriate investment. As we’ve found out in California, that hasn’t worked out that way. These markets have difficulty conveying the full price information for all services (in part because many utility-owned generators are subsidized through state rate of return regulation) and the environmental and technological benefits that may be difficult to monetize in an hourly price.

FERC has challenged some of these new rules, and both won and lost in the courts.  Now the market monitor in the biggest market in the U.S. that covers the Northeast and Midwest is joining the fight. If the market monitor wins, this will raise the salient question of whether FERC needs to rethink its policy, or will states begin to withdraw from the ISOs to pursue their own policy goals?

PJM market monitor opposes Illinois nuclear subsidies | Utility Dive

The market monitor argues the state’s subsidies “unlawfully intruded” on FERC’s authority over wholesale interstate electricity sales. 

Source: PJM market monitor opposes Illinois nuclear subsidies | Utility Dive

What lessons should we take from the last wave of California utility reform?

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We’re now in the midst of the “third wave” of electricity industry reform in California. The first was in the early 1980s with the rise of independently-owned cogeneration and renewable resources. Mixed with increased energy efficiency, that led to a surplus of power in the late 1990s, which in turn created the push for restructuring and deregulation. Unfortunately, poorly designed markets and other factors precipitated the 2000-01 energy crisis. The rise of renewables and distributed resources is pushing a third wave that may change the industry even more fundamentally.

I wrote a paper in 2002 on how I viewed the history of California’s electricity industry through 2001 and presented this at a conference. (It hasn’t yet been published.) I identify some different factors for why the energy crisis erupted, and what lessons we might learn for this next wave.

 

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.