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Breaking News! California Electricity Prices are High

In case you missed it, a recent investigative piece in the LA Times unearthed the shocking fact that California retail electricity prices are high,  about 50% higher than the national average. The article’s main focus is on the fact that California has a lot more installed nameplate generation capacity then has historically been the norm. There are several causes identified in the piece.  Deregulation of the market in the late 1990’s is pointed to as a culprit. Somewhat inconsistently, the construction of regulated, rate-based plants also takes much of the blame. One factor that was barely mentioned, however,  was California’s renewable electricity policy.

The story of how California’s electric system got to its current state is indeed a long and gory one going back at least to the 1980’s. The system still suffers from some of the after effects of the 2000 era crisis.  The Long Term Procurement Process (LTPP) put in place in the wake of the crisis, and overseen by the CPUC, has been criticized from many sides.

However, since the power crisis of the early 2000’s settled down, the dominant policy driver in the electricity sector has unquestionably been a focus on developing renewable sources of electricity generation. As is well known (outside of the LA Times apparently), California has one of the country’s most aggressive renewable portfolio standards (RPS).  The RPS requires each firm that sells electricity to end-users to procure an increasing fraction (33% by 2020, 50% by 2030) of the energy they sell from renewable sources.

Desert Solar Array
The Times article’s focus on generation capacity does (a bit unwittingly) provide a nice starting point for a discussion about the cost and implications of this renewable energy policy. The policy, while undoubtedly effective at reducing the carbon intensity of the power sector, has also been quite disruptive to the economics of the sector.  It is forcing a rapid (and early) replacement of conventional sources with renewable, but variable, generation sources such as solar and wind. Since 2010, about 80% of new capacity has come from renewable sources and it’s likely that much of that capacity would not have been built if not for the RPS.  (Much of the remaining 20% has been coming online to replace the retired SONGS nuclear plant or capacity slated for retirement due to environmental issues with their water cooling  processes.)

New Capacity in California ISO by fuel type

Proponents of strong renewable standards have pointed to the fact that new contracts for renewable energy carry price tags that are (at worst) only modestly above those for a new conventional natural gas power plant. However comparing the cost of a brand-new solar plant to that of a brand-new gas plant overlooks two important facts.  First, renewable, variable output sources offer very different operational capabilities than conventional sources.  Second, right now we don’t really need new capacity of any kind, and are in fact struggling to find ways to compensate the generators that are already here.

The renewable portfolio standard provides an interesting contrast to the federal mileage standards on vehicles. Both require the replacement of older legacy, high-carbon sources with newer,  lower-carbon ones. However automobile standards work by requiring people to buy more fuel-efficient cars when they decide to buy a new car. Renewable portfolio standards require utilities to buy low-carbon energy by a certain deadline rather than when they are deciding to “trade-in” their old power plants. In California at least, the result has been a much more rapid turnover of legacy sources to the newer, cleaner ones. Another implication, however is the fact that the system now has a large amount of what can appear to be excess capacity. This is because renewable policies are rapidly forcing new “green” capacity into a market that was more or less fully resourced before the mandates really started taking effect.

I don’t mean to imply that the “replace it now” approach is definitively worse.  Research has shown that standards applied only to new purchases can inefficiently extend the lifetimes of older technology, from cars to power plants.  This can significantly dilute the environmental benefits of a technology mandate.  In contrast, instead of extending the lifetimes of old plants, the RPS is in effect forcing the early mothballing of legacy capacity. This improves the environmental impact, but also increases costs, sometimes in subtle ways. The effect grows larger with stricter mandates. At higher percentages, the RPS starts to displace increasingly newer (and cleaner) sources of generation.  The economic effects can be mitigated by allowing for renewable energy generated elsewhere in the country to count toward RPS compliance, but California has largely rejected such policies.

Largely due to the RPS, we have a surge of new, low marginal cost energy, flooding into a wholesale market that already had enough generic energy, thereby driving down wholesale prices. Since wholesale prices cannot support the cost of this much generation (new and old), increasingly the gap must be  made up through rising margins between wholesale and retail prices.  Utilities and other retailers have to pay  high market prices for new renewables instead of being able to “buy low” on the wholesale market.  Because all retailers face the same regulation, they pass these costs on to end users. And this doesn’t even consider the costs of new transmission, most of which is being added to boost the power system’s ability to access and absorb large amounts of renewable energy. Transmission costs, which are also charged through to electricity end users as part of the retail prices cited in the Times article, will continue to grow in coming years. The Tehachapi transmission project alone is projected to cost over $2 Billion.

The result is the seemingly perverse situation where customer rates are rising while (conventional) generation sources are simultaneously struggling for revenue and threatening to retire. Such conditions are a recurring theme on this blog and are often drivers of significant change. Unfortunately, despite the glut of electrical energy, we will likely still need the conventional capacity to handle the ramping and back-up needs created by the increased reliance on variable sources (wind and solar).

One of the debates lurking in the background is who should be responsible for the cost of these disruptions. Richard Schmalensee has observed that deregulation may make it easier for State policy makers and regulators to ignore wholesale market effects. This is because the assets being stranded today are largely owned by non-utility generation companies in contrast to the late 1990’s when the stranded assets were a joint problem of regulated utilities and their rate payers.

California led the way with developing renewable energy in the 1980’s,  with the deregulation of the power sector in the 1990’s and 2000’s, and now with high-volume renewable mandates since 2010. We are learning a lot about how to physically manage and finance a cleaner energy system. We also need be realistic about the costs of such policies.  When you combine the cost of policies of the past with the aggressive goals for the future, you get retail electricity prices that, yes, continue to be pretty darn high.



43 thoughts on “Breaking News! California Electricity Prices are High Leave a comment

  1. “…cost of relicensing Diablo Canyon (which does not have the same operational problems that SONGS had) would cost at least $105 per MWH. SONGS would have cost at least this much. That SCE got away largely scot-free is a travesty of regulatory capture, and Mike Pevey has been revealed as corrupt. Compared to renewable contracts going for as little at $40 per MWH, closing SONGS has been a savings, not a cost.”

    You may be right about closing SONGS but not based on your comparison of the $105 per MWH cost of SONGs with the $40 per MWH of renewables (i.e., large-scale solar of wind – certainly not rooftop solar, which is closer to $100 per MWH). An appropriate comparison is the total cost of renewables plus the cost of the storage needed to produce a base load resource (which SONGs is). Maybe replacing SONGS with a new gas-fired combined cycle plant makes sense; replacing it with renewables does not – at least not today and probably not by 2024.

    SCE’s decision to retire SONGS is based on politics not economics.

    • California politics are screwed Up? An understatement! Insane policy, no regard for the residence. Then you top off the power expense with the low wages and high taxes, it equals poverty with a view. Yet, somehow we keep voting the same fools back into office. Its a very, very sad time for Californians.

      • Is this the Mike Robinson that I know? Last time we talked he wasn’t living in California.

        Mike, if you moved welcome to the holy land. Wish I were there – even with the screwed up politics. LOL

  2. How does $171 billion in surplus retail cost strike you? That’s what California’s last two decades of policy “innovation” have cost consumers as of 2015, the last time I calculated our higher rates against the U.S. average. And to compare apples to apples, I did the calculation for Texas (another big state with lots of renewables) and got an even larger gap.
    Here’s the bad news: We got far less carbon reduction than if we had simply set a carbon quota instead of RPS and let utility engineers repower to combined-cycle gas with strategic renewable supplementation where appropriate.
    My column on this:

    • Did you adjust for the higher usage that would have occurred, both from the lower rates and from reduced energy efficiency financed by those higher rates? This is far from a one-sided equation.

      I agree that the state botched its roll out of restructuring. (We should have used Jesse Knight’s proposed buy out instead.) But to a large degree we can blame that debacle on Sen. Steve Peace who wrote into law a provision that largely prohibited the long-term contracting that would have prevented the market manipulation. (FERC market pricing rules and its failure to step in to stop the manipulation in August of 2000 also was a major cause of the crisis.) It appears you calculated the cost of the energy crisis at $110 billion or 64% of those costs. However, you failed to account for the fact that the DWR contracts actually ended up saving the state money later in the decade when natural gas prices spiked.

      I agree that California could have gotten GHG reductions for less cost by relying much more on a carbon tax or cap & trade (see my testimony to the CARB in 2008 on behalf of EDF). But you did not account for the lower costs of renewables now and going forward induced by the accelerated investment earlier.

      As for San Onofre, you’re simply wrong. PG&E has filed testimony estimating the cost of relicensing Diablo Canyon (which does not have the same operational problems that SONGS had) would cost at least $105 per MWH. SONGS would have cost at least this much. That SCE got away largely scot-free is a travesty of regulatory capture, and Mike Pevey has been revealed as corrupt. Compared to renewable contracts going for as little at $40 per MWH, closing SONGS has been a savings, not a cost.

      Upgrading SCE’s distribution system has nothing to do with the closure of SONGS. PG&E is spending similar amounts and only announced the closure of Diablo Canyon in 2024 last June. Utilities across the country are making similar investments regardless of whether they are closing plants or not.

      As for the consequences of declining usage, why haven’t you raised the obvious solution–making utility shareholders bear the risk just as they do in other industries?

      Your article uses a false premise that technology and consumer preferences are static and that the industry was operating just fine. You have taken a snapshot view without looking at the dynamic situation. It’s like comparing the upfront cost of buying a house to renting for a month–of course renting is cheaper when you look at it that way. Instead you should be looking at how these costs evolved over time.

  3. JB,
    Many economists have claimed that one problem w/ renewable subsidies, including FITs, is that they will lower prices, thus incurring excess burden on the demand side as well as on the supply side. You and The Economist (“A World Turned Upside Down,” Feb 25) are among the first to point out that retail prices can go up, even as wholesale prices go down. Where does it end? Here are some possible outcomes:
    1. To avoid the “death spiral” of rising prices and falling demand (as well as consumption), subsidies from tax and ratepayers are ever increasing, exemplifying black-hole economics.
    2. The technology of storage, renewable generation, grid management and demand-side conservation improve enough to break the vicious circle.
    3. Gas is increasingly used as a “bridge fuel,” and RPS mandates are rescheduled.
    Any guess?

  4. I’m not a big believer in 20-20 hindsight. Could it been handled better? Probably. However, shorter term PPA’s mean shorter financing periods, and much higher costs.

    Second issue that should be considered. Between now and 2024, California will be closing some 17.6 GW of coastal fossil units that utilize once through cooling. Here is a link to a descriptive document;

    Another factor to consider is the WECC assessment of Ca/Mx reserve capacity. Here is a link to that report;

    It shows (on pg 18-19), reserve margins in the 20’s. A 20% reserve margin is not out of line with customary utility practices.

    • In my case, it’s not hindsight. I was advocating for shorter and fewer contracts in 2006, and even in 2001 when DWR went overboard. We saw lots of new gas plants with shorter contracts and even merchant development from 1997-2003, and the amount of renewable capacity in the queue around 2010 was multiples of the RPS requirement. Clearly investors have been willing to take the risks in building these plants. The CPUC and IOUs should have taken advantage of this, rather than the other way around.

      The CAISO reserve margin is in excess of 30% in 2021 according to the LARS report. Peak load is forecasted to fall between 2017 and 2021.

      • Is that reserve margin based on maximum capability or is it adjusted for the ELCC for each individual generating resource? The reason I bring this up is that wind and solar resources typically have ELCCs down in the 20 percent to 30 percent range, whereas nuclear, hydro and fossil plants have ELCCs up around 80 percent to 95 percent of maximum capability.

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