Tag Archives: renewables

CCAs don’t undermine their mission by taking a share of Diablo Canyon

Northern California community choice aggregators (CCAs) are considering whether to accept an offer from PG&E to allocate a proportionate share of its “large carbon-free” generation as a credit against the power charge indifference adjustment (PCIA) exit fee.  The allocation would include a share of Diablo Canyon power. The allocation for 2019 and 2020; an extension of this allocation is being discussed on the PCIA rulemaking.

The proposal faces opposition from anti-nuclear and local community activists who point to the policy adopted by many CCAs not to accept any nuclear power in their portfolios. However, this opposition is misguided for several reasons, some of which are discussed in this East Bay Community Energy staff report.

  • The CCAs already receive and pay for nuclear generation as part of the mix of “unspecified” power that the CCAs buy through the California Independent System Operator (CAISO). The entire cost of Diablo Canyon is included in the Total Portfolio Cost used to calculate the PCIA. The CCAs receive a “market value” credit against this generation, but the excess cost of recovering the investment in Diablo Canyon (for which PG&E is receiving double payment based on calculations I made in 1996) is recovered through the PCIA. The CCAs can either continue to pay for Diablo through the PCIA without receiving any direct benefits, or they can at least gain some benefits and potentially lower their overall costs. (CCAs need to be looking at their TOTAL generation costs, not just their individual portfolio, when resource planning.)
  • Diablo Canyon is already scheduled to close Unit 1 in 2024 and Unit 2 in 2025 after a contentious proceeding. This allocation is unlikely to change this decision as PG&E has said that the relicensed plant would cost in excess of $100 per megawatt-hour, well in excess of its going market value. I have written extensively here about how costly nuclear power has been and has yet to show that it can reduce those costs. Unless the situation changes significantly, Diablo Canyon will close then.
  • Given that Diablo is already scheduled for closure, the California Public Utilities Commission (CPUC) is unlikely to revisit this decision. But even so, a decision to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably would not open until almost 2021. The actual proceeding would take up to a year, so now we are to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there is likely no capital additions avoided by the early closure, so the cost savings would be minimal.

Nuclear vs. storage: which is in our future?

Two articles with contrasting views of the future showed up in Utility Dive this week. The first was an opinion piece by an MIT professor referencing a study he coauthored comparing the costs of an electricity network where renewables supply more than 40% of generation compared to using advanced nuclear power. However, the report’s analysis relied on two key assumptions:

  1. Current battery storage costs are about $300/kW-hr and will remain static into the future.
  2. Current nuclear technology costs about $76 per MWh and advanced nuclear technology can achieve costs of $50 per MWh.

The second article immediately refuted the first assumption in the MIT study. A report from BloombergNEF found that average battery storage prices fell to $156/kW-hr in 2019, and projected further decreases to $100/kW-hr by 2024.

The reason that this price drop is so important is that, as the MIT study pointed out, renewables will be producing excess power at certain times and underproducing during other peak periods. MIT assumes that system operators will have to curtail renewable generation during low load periods and run gas plants to fill in at the peaks. (MIT pointed to California curtailing about 190 GWh in April. However, that added only 0.1% to the CAISO’s total generation cost.) But if storage is so cheap, along with inexpensive solar and wind, additional renewable capacity can be built to store power for the early evening peaks. This could enable us to free ourselves from having to plan for system peak periods and focus largely on energy production.

MIT’s second assumption is not validated by recent experience. As I posted earlier, the about to be completed Vogtle nuclear plant will cost ratepayers in Georgia and South Carolina about $100 per MWh–more than 30% more than the assumption used by MIT. PG&E withdrew its relicensing request for Diablo Canyon because the utility projected the cost to be $100 to $120 per MWh. Another recent study found nuclear costs worldwide exceeded $100/MWh and it takes an average of a decade finish a plant.

Another group at MIT issued a report earlier intended to revive interest in using nuclear power. I’m not sure of why MIT is so focused on this issue and continuing to rely on data and projections that are clearly outdated or wrong, but it does have one of the leading departments in nuclear science and engineering. It’s sad to see that such a prestigious institution is allowing its economic self interest to cloud its vision of the future.

What do you see in the future of relying on renewables? Is it economically feasible to build excess renewable capacity that can supply enough storage to run the system the rest of the day? How would the costs of this system compare to nuclear power at actual current costs? Will advanced nuclear power drop costs by 50%? Let us know your thoughts and add any useful references.

End the fiction of regulatory oversight of California’s generation

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M.Cubed is the only firm willing to sign the non-disclosure agreements (NDA) that allow us to review the investor-owned utilities’ (IOUs) generation portfolio data on behalf of outside intervenors, such as the community choice aggregators (CCAs). Even the direct access (DA) customers who constitute about a quarter of California’s industrial load are represented by a firm that is unwilling to sign the NDAs. This situation places departed load customers, and in fact all customers, at a distinct disadvantage when trying to regulate the actions of the IOUs. It is simply impossible for a single small firm to scrutinize all of the filings and data from the IOUs. (Not to mention that one, SDG&E, gets a complete free pass for now as that it has no CCAs.)

This situation has arisen because the NDAs require that the “reviewing representatives” not be in a position to advise market participants, such as CCAs or energy service providers (ESPs) that sell to DA customers, on procurement decisions. This is an outgrowth of AB 57 in 2002, a state law passed to bring IOUs back into the generation market after the collapse of restructuring in 2001. That law was intended to the balance of power to the IOUs away from generators for procurement purposes. Now it puts the IOUs at a competitive advantage against other load serving entities (LSEs) such as CCAs and ESPs, and even bundled customers.

This imbalance has arisen for several insurmountable reasons:

  • No firm can build its business on serving only to review IOU filings without offering other procurement consulting services to clients.
  • It is difficult to build expertise for reviewing IOU filings without participating in procurement services for other LSEs or resource providers. (I am uniquely situated by the consulting work I did for the CEC on assessing generation technology costs for over a decade.)
  • CPUC staff similarly lacks the expertise for many of the same reasons, and are relatively ineffective at these reviews. The CPUC is further limited by its ability to recruit sufficient qualified staff for a variety of reasons.

If California wants to rein in the misbehavior by IOUs (such as what I’ve documented on past procurement and shareholder returns earlier), then we have two options to address this problem going forward:

  1. Transform at least the power generation management side of the IOUs into publicly owned entities with more transparent management review.
  2. End the annual review and setting of PCIA and CTC rates by establishing one-time prepayment amounts. By prepaying or setting a fixed annual amount, the impact of accounting maneuvers are diminished substantially, and since IOUs can no longer shift portfolio management risks to departed load customers, the IOUs more directly face the competitive pressures that should make them more efficient managers.

PG&E has cost California over $3 billion by mismanaging its RPS portfolio

CCA Savings

When community choice aggregators take up serving PG&E customers, PG&E saves the cost of having to procure power for the departed load. Instead the CCAs bear that cost for that power. The savings to PG&E’s bundled customers are not fully reflected when calculating the exit fee (known as the power charge indifference adjustment or PCIA) for those CCAs. As a result, the exit fee does not reflect the true value that CCAs provide to PG&E and its bundled customers.

The chart above shows the realized and potential savings to PG&E from the departure of CCA customers. The realized part is the avoided costs of procuring resources to meet that load, shown in yellow. The second part is the foregone sales opportunity if PG&E had sold a portion of its portfolio to the CCAs at the going price when they departed. In 2019, these combined savings could have reached $3.2 billion if PG&E had acted prudently.

Many local governments launched CCAs to address their climate goals, and CCAs issued multiple requests for offers of RPS energy.  However, PG&E failed to respond to this opportunity to sell excess renewable energy no longer needed to serve their customers.  By deciding to hold these unneeded resources in a declining market, PG&E accumulated additional losses every year.  Indeed, the assigned Judge on the exit-fee proceeding at the CPUC concluded that PG&E must benefit from “holding back the RECs [renewable energy credits] for some reason.”

This willingness to hold onto an unneeded resource that loses value every year is contrary to prudent management.  However, shareholders, are shielded entirely from contract that are too costly, and only pay penalties for failing to meet RPS targets.  Instead, ratepayers—both bundled and CCA—pay all of the excessive costs, and shareholders only have a strong incentive to over-procure using those ratepayer dollars to avoid any possibility of reduced shareholder profits.  Holding these contracts also inflates the exit-fee departed customers must pay, making it harder for alternatives like public power and distributed generation to PG&E to thrive.

When Sonoma Clean Power launched in 2014, the average price of RPS energy was $128/MWh.  It has declined every year, and now sits at $57/MWh.  PG&E’s decision to not sell excess energy at 2014 prices, and to protect shareholders at the expense of ratepayers has cost customers over $3 billion dollars in the last 6 years as shown in the green columns below.  As RPS prices continue to decline, and the amount of customer departing increases, this figure will continue to increase every year.  Indeed, it surpassed $1.1 billion for 2019 alone.

PGAE Mismanagement Costs

Further, the hedging value of the RPS resources that PG&E listed as key attribute of holding these PPAs instead of disposing of them has diminished dramatically since PG&E pushed that as its strategy in its 2014 Bundled Procurement Plan. As shown in the chart above, the hedge value fell $1.3 billion from 2014 to 2019, from a high of $961 million to a burden of $343 million. PG&E’s hedge now adds $33/MWH to the cost of its renewables portfolio.

In comparison, Southern California Edison’s renewables portfolio costs just under $20/MWH less than PG&E’s. SCE did not rush into signing PPAs like PG&E and did not sign them for as long of terms as PG&E.

 

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.

Upfront solar subsidy more cost effective than per kilowatt-hour

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This paper from the American Economic Review found that consumers use a discount rate in excess of 15% in valuing residential solar power credits, compared to a social-wide discount rate of 3%.  The implication is that a government can incent the same amount of solar investment through an upfront credit for as little as half the cost of a per kilowatt-hour ongoing subsidy.

The California Solar Initiative had two different incentive methods, the Performance Based Incentive (PBI) which was paid out over 5 years and the Expected Performance-Based Buydowns (EPBB) paid out upfront. The former was preferred by policy makers but the latter was more popular with homeowners. Now we know the degree of difference in the preference.

U. of Chicago misses mark on evaluating RPS costs

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The U. of Chicago just released a working paper “Do Renewable Portfolio Standards Deliver?” that purports to assess the added costs of renewable portfolio standards adopted by states. The paper has two obvious problems that make the results largely useless for policy development purposes.

First, it’s entirely retrospective and then tries to make conclusions about future actions. The paper ignores that the high initial costs for renewables was driven down by a combination of RPS and other policies (e.g. net energy metering or NEM), and on a going forward basis, the renewables are now cost competitive with conventional resources. As a result, the going forward cost of GHG reductions is much smaller than the historic costs. In fact, the much more interesting question is “what would be the average cost of GHG reductions by moving from the current low penetration rate of renewables to substantially higher levels across the entire U.S., e.g., 50%, 60% etc. to 100%?” The high initial investment costs are then highly diluted by the now cost effective renewables.

Second, the abstract makes this bizarre statement “(t)hese cost estimates significantly exceed the marginal operational costs of renewables and likely reflect costs that renewables impose on the generation system…” Um, the marginal “operational” costs of renewables generally is pretty damn close to zero! Are the authors trying to make the bizarre claim (that I’ve addressed previously) that renewables should be priced at their “marginal operational costs”? This seems to reflect an remarkable naivete on the part of the authors. Based on this incorrect attribution, the authors cannot make any assumptions about what might be causing the rate difference.

Further, the authors appear to attribute the entire difference in rates to imposing an RPS standard. The fact is that these 29 states generally have also been much more active in other efforts to promote renewables, including for customers through NEM and DER rates, and to reduce demand. All of these efforts reduce load, which means that fixed costs are spread over a fewer amount of kilowatt-hours, which then causes rates to rise. The real comparison should be the differences in annual customer bills after accounting for changes in annual demand.

The authors also try to assign stranded cost recovery as a cost of GHG recovery. This is a questionable assignment since these are sunk costs which economists typically ignore. If we are to account for lost investment due to obsolescence of an older technology, economists are going to have go back and redo a whole lot of benefit-cost analyses! The authors would have to explain the special treatment of these costs.

Why do economists keep producing these papers in which they assume the world is static and that the future will be just like the past, even when the evidence of a rapidly changing scene is embedded in the data they are using?