Tag Archives: electricity

How to choose a water system model

The California Water & Environmental Modeling Forum (CWEMF) has proposed to update its water modeling protocol guidance, last issued in 2000. This modeling protocol applies to many other settings, including electricity production and planning (which I am familiar with). I led the review of electricity system simulation models for the California Energy Commission, and asked many of these questions then.

Questions that should be addressed in water system modeling include:

  • Models can be used for either short-term operational or long term planning purposes—models rarely can serve both masters. The model should be chosen for its analytic focus is on predicting with accuracy and/or precision a particular outcome (usually for short term operations) or identifying resilience and sustainability.
  • There can be a trade off between accuracy and precision. And focusing overly so on precision in one aspect of a model is unlikely to improve the overall accuracy of the model due to the lack of precision elsewhere. In addition, increased precision also increases processing time, thus slowing output and flexibility.
  • A model should be able to produce multiple outcomes quickly as a “scenario generator” for analyzing uncertainty, risk and vulnerability. The model should be tested for accuracy when relaxing key constraints that increase processing time. For example, in an electricity production model, relaxing the unit commitment algorithm increased processing speed twelve fold while losing only 7 percent in accuracy, mostly in the extreme tail cases.
  • Water models should be able to use different water condition sequences rather than relying on historic traces. In the latter case, models may operate as though the future is known with certainty.
  • Water management models should include the full set of opportunity costs for water supply, power generation, flood protection and groundwater pumping. This implies that some type of linkage should exist between these types of models.

We’ve already paid for Diablo Canyon

As I wrote last week, PG&E is proposing that a share of Diablo Canyon nuclear plant output be allocated to community choice aggregators (CCAs) as part of the resolution of issues related to the Integrated Resource Plan (IRP), Resource Adequacy (RA) and Power Charge Indifference Adjustment (PCIA) rulemakings. While the allocation makes sense for CCAs, it does not solve the problem that PG&E ratepayers are paying for Diablo Canyon twice.

In reviewing the second proposed settlement on PG&E costs in 1994, we took a detailed look at PG&E’s costs and revenues at Diablo. Our analysis revealed a shocking finding.

Diablo Canyon was infamous for increasing in cost by more than ten-fold from the initial investment to coming on line. PG&E and ratepayer groups fought over whether to allow $2.3 billion dollars.  The compromise in 1988 was to essentially shift the risk of cost recovery from ratepayers to PG&E through a power purchase agreement modeled on the Interim Standard Offer Number 4 contract offered to qualifying facilities (but suspended as oversubscribed in 1985).

However, the contract terms were so favorable and rich to PG&E, that Diablo costs negatively impacted overall retail rates. These costs were a key contributing factor that caused industrial customers to push for deregulation and restructuring. As an interim solution in 1995 in anticipation of forthcoming restructuring, PG&E and ratepayer groups arrived at a new settlement that moved Diablo Canyon back into PG&E’s regulated ratebase, earning the utilities allowed return on capital. PG&E was allowed to keep 100% of profit collected between 1988 and 1995. The subsequent 1996 settlement made some adjustments but arrived at essentially the same result. (See Decision 97-05-088.)

While PG&E had borne the risks for seven years, that was during the plant startup and its earliest years of operation.  As we’ve seen with San Onofre NGS and other nuclear plants, operational reliability is most at risk late in the life of the plant. PG&E’s originally took on the risk of recovering its entire investment over the entire life of the plant.  The 1995 settlement transferred the risk for recovering costs over the remaining life of the plant back to ratepayers. In addition, PG&E was allowed to roll into rate base the disputed $2.3 billion. This shifted cost recovery back to the standard rate of depreciation over the 40 year life of the NRC license. In other words, PG&E had done an end-run on the original 1988 settlement AND got to keep the excess profits.

The fact that PG&E accelerated its investment recovery over the first seven years and then shifted recovery risk to ratepayers implies that PG&E should be allowed to recover only the amount that it would have earned at a regulated return under the original 1988 settlement. This is equal to the discounted net present value of the net income earned by Diablo Canyon, over both the periods of the 1988 (PPA) and 1995 settlements.

In 1996, we calculated what PG&E should be allowed to recover in the settlement given this premise.  We assumed that PG&E would be allowed to recover the disputed $2.3 billion because it had taken on that risk in 1988, but the net income stream should be discounted at the historic allowed rate of return over the seven year period.  Based on these assumptions, PG&E had recovered its entire $7.7 billion investment by October 1997, just prior to the opening of the restructured market in March 1998.  In other words, PG&E shareholders were already made whole by 1998 as the cost recovery for Diablo was shifted back to ratepayers.  Instead the settlement agreement has caused ratepayers to pay twice for Diablo Canyon.

PG&E has made annual capital additions to continue operation at Diablo Canyon since then and a regulated return is allowed under the regulatory compact.  Nevertheless, the correct method for analyzing the potential loss to PG&E shareholders from closing Diablo is to first subtract $5.1 billion from the plant in service, reducing the current ratebase to capital additions incurred since 1998. This would reduces the sunk costs that are to be recovered in rates from $31 to $3 per megawatt-hour.

Note that PG&E shareholders and bondholders have earned a weighted return of approximately 10% annually on this $5.1 billion since 1998. The compounded present value of that excess return was $18.1 billion by 2014 earned by PG&E.

Calculating the risk reduction benefits of closing Germany’s nuclear plants

Max Aufhammer at the Energy Institute at Haas posted a discussion of this recent paper reviewing the benefits and costs of the closure of much of the German nuclear fleet after the Fukushima accident in 2011.

Quickly reading the paper, I don’t see how the risk of a nuclear accident is computed, but it looks like the value per MWH was taken from a different paper. So I did a quick back of the envelope calculation for the benefit of the avoided consequences of an accident. This paper estimates a risk of an accident once every 3,704 reactor-operating years (which is very close to a calculation I made a few years ago). (There are other estimates showing significant risk as well.) For 10 German reactors, this translates to 0.27% per year.

However, this is not a one-off risk, but rather a cumulative risk over time, as noted in the referenced study. This is akin to the seismic risk on the Hayward Fault that threatens the Delta levees, and is estimated at 62% over the next 30 years. For the the German plants, this cumulative probability over 30 years is 8.4%. Using the Fukushima damages noted in the paper, this represents $25 to $63 billion. Assuming an average annual output of 7,884 GWH, the benefit from risk reduction ranges from $11 to $27 per MWH.

The paper appears to make a further error in using only the short-run nuclear fuel costs of $10 per MWH as representing the avoided costs created by closing the plants. Additional avoided costs include avoided capital additions that accrue with refueling and plant labor and O&M costs. For Diablo Canyon, I calculated in PG&E’s 2019 ERRA proceeding that these costs were close to an additional $20 per MWH. I don’t know the values for the German plants, but clearly they should be significant.

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

1542383922472

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.

Should California just buy PG&E?

berkshirehathawaylogo1

Governor Gavin Newsom asked Warren Buffet to use Berkshire-Hathaway to buy PG&E. Berkshire-Hathaway has been acquiring utilities throughout the West including PacifiCorp and Nevada Power. However, other than deep pockets, it’s not clear what Buffet has to offer in this situation.

PG&E’s stock fell as low as $3.80 per share on Tuesday, closing at $5.03. The total market value, including the natural gas utility, is now $2.66 billion. The invested book value on the other hand is about $26 billion.

Not sure why California doesn’t just buy the company for, say, $5B instead of appealing to an out of state private owner. Several state legislators, including a key state senator, Bill Dodd, have expressed support for some sort of state acquisition. Then the state can either parse it out to public utilities, set up a cooperative or bid out the franchises to multiple operators or owners. Ratepayers/taxpayers will have to pay most of the wildfire liabilities anyway, so why not remove the high-cost (and apparently incompetent) middleman?

VCEA offers PG&E $300 million for Yolo County

vce_logo_color_white-border

Valley Clean Energy Alliance made its official offer to PG&E to acquire the Yolo County distribution system for $300 million. The offer is being submitted in PG&E’s bankruptcy proceeding. This offer is substantially higher than the $108 million that Sacramento Municipal Utility District (SMUD) offered in 2005, and not far below the $400 million that PG&E countered with.

San Francisco offered $2.5 billion for PG&E’s system, and San Jose announced that it also will make a bid. Municipalities believe that the bankruptcy court will be more receptive to accepting the offers as a means of raising cash for the bankrupt utility.