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100% of What?

Could California’s ambitious zero carbon electricity policy make it harder to cut greenhouse gasses overall?

Sometimes two ideas that seem joined at the hip end up butting heads. A couple current discussions in the energy blog-o-sphere illustrate. One is the debate over moving to 100% carbon-free electricity in California. Another is the push for “electrification” of transportation, water heating and anything else that these days relies on burning natural gas, oil or coal.

The two policy initiatives seem to be complimentary in their pursuit of a low-carbon future: One policy cleans up electricity while the other gets people to switch from using other dirty fuels over to clean power. Except there’s a hitch: Money. If zero-carbon standards significantly increase the retail of price power, then firms and consumers are going to be less likely to favor electricity-intensive products.

Too much of the debate we’ve heard over 100% targets are stuck on the question of whether it is technically feasible. I don’t have strong doubts that it is technically possible. After all you could always resort to rolling blackouts when renewable energy falls short. That’s technically feasible. Buying enough Tesla batteries will (eventually) be technically feasible. Importing hydro power from the Pacific Northwest is definitely technically feasible.

The relevant question is the cost gradient as we scale up from 60 to 70 to 80 percent and higher. What if going from 90 to 100% renewables triples the cost? The timing of the targets also affects the cost, because a zero carbon standard without demand growth requires the early mothballing of existing fossil fueled facilities rather than a diversion of new building from fossil to zero-carbon sources.

It’s not just about cranky electricity customers and a “ratepayer revolt” anymore. Not if we are trying to electrify new sectors. Now you may be thinking: “Of course customers would love electric cars. Isn’t gasoline hella expensive in California?” There certainly has been a lot of media attention paid to gasoline prices, from the potential repeal of the new infrastructure gas tax to the impacts of the low-carbon fuel standard, not to mention one blogger’s obsession with the “mystery surcharge.”

Look at these two trends, however. The right-hand panels plot gasoline prices in California (red) vs. Texas (black). The lower right-hand panel plots the ratio of California gasoline prices over Texas prices. The left-hand panel plots residential electricity price levels and the ratio for the same two states. Not surprisingly, gasoline has always been more expensive in California relative to Texas, and has grown somewhat more so in recent years. The main impression is that both are dominated by global oil prices.

comparison
Not Everything’s Bigger in Texas: Energy Price Comparisons

The electricity story is more complicated. Upon restructuring, both the California and Texas markets became more closely tied to the price of natural gas. Both markets rode the gas price up in the 2000s. Texas power prices have ridden the gas price back down again since 2008, while California prices have continued to increase.

The differences are not a result of differential costs of wholesale power in the two markets. In fact, wholesale prices are a little lower in California. A closer look at an electric bill in California provides some more detail.  Conveniently, PG&E and other California utilities break down the component costs of retail rates into several categories. Also conveniently, I have a colleague who is, um,  “detail oriented” enough to keep careful records of every aspect of his/her energy expenses over a long period of time.

rate_breakdown
Cost Breakdown from a Representative PG&E Residential Customer

This figure plots the component parts of my colleague’s PG&E rates over time. Unfortunately, comparisons before 2013 become difficult as PG&E’s treatment of the increasing block structure changed in 2013. Distribution and transmission costs have been rising this decade, but what is most striking is that the cost of energy procured by PG&E has been rising, while the wholesale price of energy has been falling. The blue bars constitute PG&E’s average (procured) energy costs, including all its contracts, regulated plants, and other purchases and fees. The black line illustrates the wholesale energy price, as based upon day-ahead northern California June prices in the CAISO’s market. Energy prices in the CAISO market have been trending downward, yet the overall cost of procured energy is going in the opposite direction.

Now I wager that some commenter is going to blame PG&E for this, but this trend of higher procurement cost and lower wholesale prices is a general one for California. It is captured in the comparison of California rates with those of Texas. The Renewable Portfolio Standard (RPS) is likely playing a big role. The growing gap between wholesale and retail prices is a consequence of rapidly adding renewable capacity at costs above the wholesale price that in turn drives down the wholesale market price even farther. It is true that renewable costs are declining, but so is the value of renewable output as captured by the wholesale price. Recent work by Kevin Novan and I have estimated that the additions of utility-scale solar over the last half-decade have reduced power prices by close to $20/MWh during mid-day. Since most new renewable capacity is producing in those same time periods, a solar contract signed in 2016 produced power worth half as much as a contract signed in 2012.

One theme of my work with Severin Borenstein has been that pressure for disruptive change in the power industry grows with the gap between retail prices and wholesale costs. In the past, such pressure help create the Independent Power Producer industry and later spurred the movement for electricity deregulation. Now the pressure may be pushing users off the grid. Anecdotes from Hawaii, another state with a 100% renewable electricity law, point to the risks of pushing the electricity industry too far in front of other sectors.  When I last visited, I heard several stories of large commercial or industrial customers considering on-site (gas-fired) generation.  Such measures become increasingly attractive as the retail electricity prices rises farther above the option of self-generation, which is not subject to the RPS.  It’s enough of a concern that the state is now debating a possible renewable mandate for natural gas.

This is another example of what Meredith Fowlie has called the waterbed effect. You push carbon down on one side and it pops up on another. Just as high energy costs may drive energy-intensive firms to other states, high-cost electricity may drive consumers away from electric power just when we are trying to lure them in. We may resort to the always-popular tool of subsidizing investments for electrification, but the costs of those subsidies are bound to rise if the cost disadvantage of electric water heating or heat pumps grows. And those subsidies are often paid for out of electric rates, making the cost-gap even larger.

Goals like 100% clean or “net-zero” carbon sound like nice round numbers and are  politically popular, and there is no easier target than the highly-regulated electricity sector. As we have repeatedly written on this site, however, the world’s climate problem is not going to be solved just by cleaning up the electricity industry, let alone the California electricity industry. Eventually we are going to need a holistic approach that considers all sources of greenhouse gases and makes some attempt to balance the costs of abatement across sectors.

William Nordhaus was just announced as a Nobel Laureate in Economics, largely for his work on the concept of broadly applied carbon pricing. The increasing substitutability of gasoline, electricity, and natural gas illustrates why such an approach is so much more effective than sector level technology mandates. While the Competitive Enterprise Institute may complain that carbon taxes raise electricity and gasoline prices, alternative regulations that pursue piecemeal and uncoordinated solutions ultimately cost more.

Keep up with Energy Institute blogs, research, and events on Twitter @energyathaas

8 thoughts on “100% of What? Leave a comment

  1. I don’t have a lot to say here, but just wanted to remark that (1) climate projections improve over the years, and (2) it was always clear that, if we waited collectively long enough before reducing, in order to hit cumulative emission targets we would necessarily have to retire fossil fuel assets well before their depreciation or actual lifetimes. Climate projections have gotten worse, and the urgings to stop building fossil fuel assets, including natural gas facilities, have not been heeded.

    Accordingly, to now say it’s a waste to retire these assets is an imperfect analysis, at least when assigning the blame for why that is the case. It’s clearly the case because some of them shouldn’t have been built in the first place. To the degree that could not be foreseen, the need to shut them down early can also not be foreseen.

    Finally, while California is its own jurisdiction, clearly energy supply and management is a regional problem.

  2. I’d like to piggyback on Jim Lazar’s comment without agreeing or disagreeing with anything he said….

    It is very feasible for a state to go 100% renewable and rely on imports and exports to provide balancing. What if all the states around California also went 100% renewable? What if everyone west of the Rockies went 100% renewable? Of course you could look to balancing from Canada and Mexico, but that is not really the point. What I take from Jim’s post is that thermal resources provide balancing, even if they are out of state. Take away all the thermal resources and balancing will rely on storage or load shedding.

    I know some will counter that the interties between east and west need to be strengthened. While that may be true I would point out that if all states in the east also try to go 100% renewable, then increasing transmission only solves some of the problem. The rest of the problem still needs to be solved through storage or load shedding.

  3. Nice piece Jim. Thanks! Nonetheless, I would accuse you one-handed economistism here. What if not going from 90 to 100% results in climate catastrophe? It’s as unreasonable to not balance costs and benefits as it is to establish arbitrary standards, e.g. zero net energy consumption or 100% renewable power generation.

  4. I’m still wondering exactly what index must reach 100%. It’s certainly not the percent of generation since some the generation goes for line losses, own-utility and other uses. Instead the denominator is “retail sales.” I’m a bit suspicious because Hawaii’s index has net utility sales in the denominator and total renewable generation in the numerator. So distributed solar for example goes into the numerator, but is netted out of the denominator. This makes it plausible to have 50% of generation renewable and still achieve an index equal to 100%. California has a different index but there is some vague wording in the amended law about being able to count renewable credits that may allow for a similar illusion. Any clarification would be appreciated.

  5. Two issues: First, “hourly” markets and “wholesale” markets are not the same thing. Wholesale markets are composed of contracts and resources of of varying lengths and terms. The CAISO hourly energy market that is cited here has not been used to meet load growth in California since at least 2010 and is only relevant for load balancing purposed in the transmission grid. All incremental resources are now added through either renewables or distributed resources, of which the vast majority are procured through long-term contracts or behind the meter investments. The prices for those transactions have become disconnected from the hourly market prices for a variety of resources, and the hourly prices are as relevant to the larger wholesale market as AirBNB bedroom rental rates are to the housing market.

    Second, the blog states “because a zero carbon standard without demand growth requires the early mothballing of existing fossil fueled facilities.” That last significant natural gas plant in California was added in 2010. A utility-owned plant investment will be paid off in 30 years, or by 2040 BEFORE the 100% renewable goal in 2045. But the real investment is in merchant gas plants. Those have been financed with a 20-year return (not 30). We reported this fact in the CEC’s Cost of Generation reports. Almost all of these plants were built before 2010 (there might be a couple small ones since), which means that their economic lives will be done by 2030. So there’s almost no stranded assets there either. Notably, all of the utilities’ PPAs with merchant plants expire by 2027 (I’ve seen the contracts and this was provided in the PCIA OIR).

  6. Great post. I was anticipating where it would end up (carbon pricing) as I was reading along — ultimately the only way to get a truly firm mattress for effective carbon control.

    Next stop after pricing is atmospheric CO2 removal offsets (a “negative price,” i.e., reward, for additional sequestration). Carbon pricing that is both binding and sufficiently even-handed (loophole free) seems likely to remain the economists’ fantasy for some time. But perhaps we can do thought experiments that ask what would happen at the sectoral level if we priced carbon strongly, projecting the likely behavioral (technology and program investment) changes. . Might we then use those results to guide sectoral policies that are less inefficient?

  7. This is a nice post, and it raises an important set of questions:

    1) Why are California retail prices so high? There are many reasons, partly rooted in state policy, part in generous rate making, and part in the high cost of doing business in California.
    2) What is the MARGINAL resource that will serve load growth, including electrification load?
    3) What pricing changes will be needed to encourage beneficial electrification?

    I’ll address only one aspect of one of these questions: what is the MARGINAL resource? The post says “we can import hydro from the Northwest”. Not so simple.

    California seldom imports hydro from the Pacific Northwest. It happens in the Spring, when there is a surplus of hydro above northwest electricity loads. But the rest of the year, nearly all imports are really coming from thermal generating resources.

    That is, except for the Spring freshet, PNW in-region loads exceed PNW in-region hydro production. Given the “regional preference” law passed by Congress, utilities in the region have first call on any surplus from the federal hydro system.

    It’s a game that California plays, pretending that the power they get from the PNW is clean. It’s not. And extensive data on this was presented to CARB when the AB32 implementation process was underway.

    You can look at the BPA system resources and loads in real-time at https://transmission.bpa.gov/business/operations/wind/baltwg3.aspx If you add up the “fossil” and “nuclear” generation in the region, it usually exceeds the “interchange” amounts. “Interchange” means power exported from the region, nearly all of which leaves on the AC and DC interties to California.

    However, what this does NOT tell you is the nature of the non-BPA loads and resources, including utilities like Puget Sound Energy, Pacific Power and Light, and Avista. Those utilities operate significant amounts of coal and gas generation, If the PNW federal system has a surplus of hydro, they have first right of refusal. Often they do buy that hydro in the region, and continue operating and exporting their thermal resources if market prices are high enough.

    Pragmatically, what happens is that the hydro is consumed in the PNW, and our thermal (nuclear, coal, and natural gas) generation flows to California. Ask yourself a simple question: if the intertie lines were not operational, which would get shut down in the PNW: hydro, coal, nuclear, or gas? Obviously the units with variable fuel and operating costs (ranging from a penny or so for nuclear to three cents or so for coal and gas) are the units that would be shut down. Reopen the interties, and the thermal generation would resume operation.

    It’s very different in April, May, and June. In average and wetter years, nearly all of the thermal resources are shut down, and we still have a surplus of hydro. During those months, California does get hydro from the PNW. In the rest of the year, it’s a ruse to pretend it’s clean power coming from the North.

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