If you work in electricity markets and someone mentions “missing money,” it doesn’t make you think of a lost wallet or a sticky-fingered bank teller. Instead it evokes regulatory policies that lower the revenues electric generation companies can make in wholesale markets. Missing money is more than just a concern of corporate CEOs and shareholders. It could soon be a serious impediment to a low-carbon economy.
Money has been going missing for many years, according to owners of power plants. They’ve used the term for more than a decade to refer to the fact that wholesale electricity markets have price caps (mostly between $1,000 and $10,000 per MWh) that constrain how much sellers can make when supply is tight. Without that income, generators argue, it may not be profitable to build new capacity, or extend the life of existing capacity, that is needed to meet demand.
More recently, the definition of missing money has been expanded to include the price impacts of subsidized or mandated renewables generation. In California, New York and many other states, wind and solar are pushing down wholesale prices and making continued operation of some nuclear and fossil fuel generation unprofitable.
That may make some environmentalists cheer, but it makes many regulators worry, because wind and sun are not very predictable or controllable. In some cases, grid operators have said those conventional generators are needed to assure that demand can be met locally or systemwide and have offered them out-of-market payments to stay open.
For instance, new subsidies are under consideration for some nuclear plants to compensate for their missing money, but those proposals are triggering objections from gas-fired and coal-fired generators, because keeping the nukes open worsens their own missing money problem.
California’s Topaz Solar Farm
In a meeting I attended a few years ago, a solar advocate stated proudly that when solar enters a market wholesale prices always drop. I wondered aloud how producers in food, auto, steel, or any other industry would feel about government policy that drives down prices in their markets by subsidizing or mandating the use of higher-cost supply. (At the time, the solar power was much higher cost, even accounting for most estimates of the costs of GHG emissions from fossil-based sources.)
Of course, governments intervene in many energy and energy-related markets with mandates and restrictions that affect firms unevenly.
- Automakers must meet the federal Corporate Average Fuel Economy standard;
- Gasoline sellers must blend in ethanol to meet the federal renewable fuels standard (as well as the Low Carbon Fuel Standard in California, and the 10% ethanol minimum in Minnesota, among other state mandates);
- The electric vehicle mandate in California lowers the demand for gasoline (and raises the demand for electricity), as well as lowering demand for conventional vehicles;
- Some areas now require increased use of biogas (captured methane from landfills, dairy farms, and other natural sources) to replace fossil-based natural gas;
- Energy efficiency programs lower the demand for electricity everywhere.
Yet, you don’t hear talk of the missing money problem in the auto, oil refining and retailing, or natural gas markets, even when regulations reduce demand for their output.
Missing money is often discussed in terms of fairness: When policies change and the values of existing investments are affected, are losers due some compensation? That is a more pressing question in electricity, where the accelerated renewables rollouts in some places have lowered the quantities incumbents sell and dramatically reduced the wholesale prices they receive (as Meredith discussed last May).
Still, what makes electricity truly different is not the fairness issue, but the electrical engineering: supply and demand must balance every second in order to keep the grid stable. The grid operator has few, and very blunt, instruments to affect demand, so it relies almost entirely on controlling supply. In the short run, missing money can threaten the viability of plants that are needed for balancing the system, potentially requiring much more expensive alternative supply options, or forced reductions in demand.
There is also a long-run efficiency concern: If firms see an unstable regulatory environment where capital values can swing wildly with regulatory decisions (what former Duke Energy CEO, Jim Rogers, calls “stroke-of-the-pen risk”) they are less inclined to invest, even if capacity is desperately needed and may be well-remunerated in the short run.
These problems will almost certainly worsen in places where renewable energy targets are increasing, like Hawai’i with its 100% target by 2045, and California, which may soon adopt a similar goal.
In other industries if government policies reduce investment in supply capacity, prices rise and consumers purchase less for a while. That sort of market adjustment is not an option in electricity markets as they are currently configured.
So, if a state wants to ramp up renewables, but the missing money problem is such a political, economic, and, ultimately, operational barrier, why not offer compensation for the disappeared dollars. Ah, if only it were that easy…
You see, at some point every firm discovers they are missing money. They invest in a market and then demand turns out to be softer than they expected, or other firms also invest in the market creating over-supply, or their costs rise (or their competitors’ costs fall), or they run into unforeseen logistical problems, or any number of other reasons that firms lose money. Money goes missing due to bad management or just bad luck.
All of those reasons are present in electricity markets as well, and are part of why many generators’ income statements look more red than black these days. How big a part? That’s a very tough question to answer. Soft demand, for instance, interacts with expanded renewables to push down wholesale prices. Any attempt to allocate responsibility will be subject to great uncertainty and, with much money on the line, to endless dispute. Plus, it will depend on what you think generators should have known and when they should have known it about renewable energy policies.
And even if we could sort all that out, there would be a disturbing asymmetry in such a compensation policy. We don’t tax a gas plant’s “found money” when mercury restrictions drive out coal-fired competitors, or levy a fee on nuclear plants in markets that start to price CO2 emissions, thereby driving up the market price and their profits.
Ok, even if we don’t compensate losers in general, can we address the grid reliability issues that may result?
Yes we can, but it’s not pretty and may not look much like a market. At the system level, it means the grid operator procures “capacity” (or requires retail electricity suppliers to do so). Capacity is the ability to deliver electricity, though the obligation to do so is sometimes not fully specified or doesn’t match up well with what’s actually needed for grid reliability. (A new Energy Institute working paper (WP-278) does an excellent job of explaining this murky topic.)
For particular local supply concerns, the grid operator identifies generation that is especially critical and signs contracts for their services in a bilateral negotiation. The plant operator’s threat is to shut down, so it may exaggerate its costs in order to push up the contract price, while the grid operator wants to get a reasonable price, but still assure that the operator is able to cover its costs. Starts to sound a lot like regulation, doesn’t it? In fact, it can lead back to cost-of-service compensation for the plant. Everything old is new again.
My point is not that it’s impossible to address the missing money problem(s), or that we should give up on competitive wholesale electricity markets. Research has shown that electricity markets create a lot of economic value (in efficient operation of fossil generation and nuclear generation, as well as efficient dispatch of electricity grids).
But at the same time, we need to move to lower carbon generation technologies. That will create economic disruption even if we do it primarily through a price on carbon, and especially if we don’t. If we are lucky, solutions will be worked out that keep grid disruption to a minimum and maintain incentives for efficient investment. But that will require thoughtful understanding of the missing money problem and careful weighing of the array of imperfect policy responses.
I tweet news and research on energy most days @BorensteinS
Severin Borenstein View All
Severin Borenstein is Professor of the Graduate School in the Economic Analysis and Policy Group at the Haas School of Business and Faculty Director of the Energy Institute at Haas. He received his A.B. from U.C. Berkeley and Ph.D. in Economics from M.I.T. His research focuses on the economics of renewable energy, economic policies for reducing greenhouse gases, and alternative models of retail electricity pricing. Borenstein is also a research associate of the National Bureau of Economic Research in Cambridge, MA. He served on the Board of Governors of the California Power Exchange from 1997 to 2003. During 1999-2000, he was a member of the California Attorney General's Gasoline Price Task Force. In 2012-13, he served on the Emissions Market Assessment Committee, which advised the California Air Resources Board on the operation of California’s Cap and Trade market for greenhouse gases. In 2014, he was appointed to the California Energy Commission’s Petroleum Market Advisory Committee, which he chaired from 2015 until the Committee was dissolved in 2017. From 2015-2020, he served on the Advisory Council of the Bay Area Air Quality Management District. Since 2019, he has been a member of the Governing Board of the California Independent System Operator.
Isn’t the answer relatively easy? Run NYISO style REC purchases to meet the RPS target. Run a capacity market with PJM deliverability requirements. The commodity prices will be what they will be under such a regime, but generators will be rationally and reasonably compensated if they are correct in their REC/capacity pricing.
The problem appears to be that California doesn’t want a rational model. NYISO REC purchases would have made the cost of the RPS much more transparent and allowed for someone to realize that California pays $20+/MWh for something ERCOT manages to get done for $1-5. On the capacity front, an auction takes market power from the CAISO/utilities. The current market structure is perfect for avoiding compensating generators. New combined cycles get built under bilateral contracts. This keeps the capacity market oversupplied with older generators therefore perpetually needing to retire. Thus the market power for purchasing capacity sits with the utilities (there’s more capacity than need), and they can thus avoid having to pay much for it. (Though, they do pay significantly more in the long-run for this system because the cost of new build must be entirely recovered in the initial PPA since the plant is worthless once it goes off contract)
Absent reform, no one is going to supply capital to generate in the CAISO with risk. I mean, that’s already happened — the market isn’t a “market” anymore, it’s a vertically integrated SCED. There hasn’t recently – and won’t ever – ever be new merchant development .
What’s the difference between the putative “missing money” and rent? Peak prices that are capped in so-called “markets” (at $1500/MWh here in Ontario) are largely rents – i.e. amounts paid over the minimum required to bring a resource to the market (i.e. their costs). Face it, none of the electricity markets are markets as economics normally understands them. They are administrative auctions run by monopsonists. Naturally they create rents which those who garner them come to regard as entitlements; “missing money”. Doesn’t the phenomenon of prices being pushed down by higher cost but subsidized supply give a strong hint that these are not “markets”? As the piece says, “Yet, you don’t hear talk of the missing money problem in the auto, oil refining and retailing, or natural gas markets, even when regulations reduce demand for their output.” Exactly.
Missing money is a rent – a scarcity rent. And I doubt the Ontario market will attract many new resources with a price cap of $1500/MWh unless it has extensive capacity shortages accompanied by rolling blackouts. The only way an electricity market with so low a price cap an provide reliable service is by making capacity payments to the generators – which is the real source of market distortion.
There is no “missing money” problem in the markets cited is because they have no price caps, allowing prices to rise to whatever levels are needed to ensure resource adequacy.
ERCOT currently has a price cap of $9,000/MWh, which may be sufficient to attractive sufficient capacity to ensure resource adequacy, though certainly not enough to satisfy the “one-day-in-ten-years” industry standard. Most economists recognize that standard as being far too stringent and not economically justified.
Such high price caps is relying on a “casino market.” Steady infrastructure investment requires mitigating those risks. That’s why the reliance on the hourly markets fail. It’s like building a housing market based on hotel pricing.
Ontario has imposed a different solution: long-term contracts and quasi-contracts (government revenues cap on the dominant generator). Almost all Ontario power is covered by these, yet, officially we still have a “market”. You could read more at https://authors.elsevier.com/a/1Un9b3ic-~tsf
The electricity industry has been too enamored with hourly markets. Daily hotel rates do not set the housing market price. If there’s a relationship, it’s the other way around. There are too many distortions in the market, e.g., in California, rate based generation and average cost pricing on transmission instead of marginal cost. Multi-part tariffs (with clear price signals, e.g., for unit commitment in the CAISO) can work effectively in these markets. Also, customers should have the same access to long-term contracts as generators. We need symmetric, transparent markets, but not a reliance solely on hourly markets with band aids.
Mcubedecon, I think you have the cart before the horse.
An economically efficient short-term (hourly or even 5-minute) spot market is a necessary prerequisite for an efficient contract markets. This is one reason ENRON argued against such markets in California and in favor of bilateral markets which the firm could then exploit.
Nobody I know is arguing for sole reliance on hourly markets. Spot and contracts markets can coexist and the former supports the latter.
I’m not sure that’s true. The problem is the importance of the missing interhour markets for both commitment and storage. ERCOT avoids many of these problems to date because they don’t have hydropower and they’ve used baseload coal plants for most of their unit commitment. They have a relatively uncomplicated physical system compared to everywhere else. And unfortunately, the FERC (and CA) have pushed towards a sole reliance on hourly markets or just one step removed. The PJM problems illustrate this as well. I’ve expressed skepticism about the hourly market in the West due to the dominance of hydro since the mid 1990s. Transparent contract markets would be a much better pursuit.
Can you state which working paper?
My apology. It’s WP-278, “Capacity Markets at at Crossroad”
I think your map has some inaccuracies. Probably from following state lines. ComEd should be red, for example.
Figure 10 in WP 278 has a label that reads “Figure 10: Map of States in the Lower 48 that have Retail Choice (Blue Outline) and States that have Bilateral RA Requirements (Orange) or Centralized Capacity Markets (Red).” In text of the paper, we explain: “Figure 10 shows the 48 states and Washington DC. The map shows which states have retail choice by outlining the state in blue. In addition, the figure depicts which states have bilateral RA requirements in orange or centralized capacity markets in red. While some ISOs cover only part of some states, we code the RA status of a state based the majority status.” The figure does not imply that the coded states are exclusively one type of resource adequacy territory. The state of Illinois did have, at the time, bilateral RA requirements for a large fraction of the state. While we could have shaded Illinois another color as well as other states that are not completely within an ISO, or traced out ISO/RTO boundaries, we were trying to make a map that was easy to read.
The plants are serving the role of ‘energy storage’. Some mechanism to incentivize investment which factors in the cap and operating cost of traditional power plant and of storage could be developed. That would set the limits on rates for these ‘missing money’ situations.
This is a great article.
In response I would just like to point out that the Zero Emissions Credits (ZECs) that New York proposes to pay to in-state operating nuclear power plants are economically justified to the extent that they are surrogates for a tax based on the social cost of carbon. Yes, these are “out-of-market” payments but they are being paid in a market that is flawed because it does not internalize the cost of CO2 emissions.Providing ZECs that are based on the social cost of carbon gets us much closer to a defensible “second-best” policy that any of the politically motivated renewable energy portfolio standards adopted at the state level.
” Its wrong to say certain renewable policies are “distortionary” when the clean energy they are bringing would have been likely under a carbon price.”
This qualitative generalization is inaccurate. It glosses over the issue of how much clean energy would be brought forth by a carbon tax and what form it would take. The renewable energy standards adopted at the state level (and by California in particular) bear no relationship to any rational, explicit economic analysis; instead, they are the product of political bargains responding to the influence of special interest groups. This becomes even more evident when one examines the various set-asides that many states have adopted for distributed resources, including rooftop solar, which discriminates against lower-cost, large-scale solar connected to the high voltage transmission grid. There is no doubt that renewable energy portfolio standards have distorted electricity markets.
“Some renewable policies (but not all) are pretty close second best policies.”
Really? Based on what rigorous analysis? If it exists I would be most interested in seeing that analysis.
“especially considering price risk which is not factored into prices as it should be, and in turn helping reduce those costs further.”
While this argument is routinely made in favor of renewable energy, which imposes no fuel price risk, it ignores the fact that a renewable energy resource imposes a different type of risk, i.e., the burden of the owner having to recover the renewable resource’s high capital investment, which remains invariant to future market conditions. So which is preferable, incurring a high fixed-cost that has to be paid for regardless of the state of the economy? Or a future cost that goes up when the economy is good (and the energy purchaser has more ability to pay) and goes down when the economy is soft (and the energy purchaser has less ability to pay)? I submit that the issue of avoided price risk has not yet been clearly addressed and resolved.
“Until then, we should carefully design efficient second-best policies.”
I agree with this statement, as I believe would Fred Kahn, were he alive today. He addressed the second-best issue extensively in his 1970 landmark works, “The Economics of Regulation.” But to claim that state RPS targets constitute second-best policies is laughable.
“3) One person’s “out of market” purchase is another person’s in-market purchase.”
I’m not sure what to make of this entire paragraph. Markets are agnostic in that they offer goods and services to buyers without regard for individual consumers’ preferences. What are you trying to say?
“4) Voluntary (not mandatory) long term contracts are part of the market, not part of the problem. They hedge price risk for consumers. Some markets have too little long term contracting and that puts too much pressure on central capacity markets, which then requires ever-increasing administrative band aids and stakeholder politics-driven capacity market design changes.”
I generally agree with this paragraph – particularly the criticism of all central capacity markets. The most efficient power market in the US today is ERCOT, which does not have a capacity market.
“As variable generation sources grow, paying for flexibility becomes more important.”
True. However, we also need to address the issue of who should bear the cost of that flexibility. Following the well-established principle of cost-causation, the variable resources (e.g., wind and solar resources) should be billed for the payments made to the flexible resources. Those payments represent an ancillary service that would not be needed if the variable resources did not exist. These ancillary services should not be simply (and blindly) passed to the consumers through the ISO’s energy price uplift.
There are flaws to fix. There is a lot of misdiagnosing and over-stating going on though, not by you but by others in RTO and FERC proceedings.
1) It is wrong to blame renewables for most of the lower-than-expected generator revenues. Clearly low gas prices are by far the leading cause of that. Nuclear plants, gas plants, coal, renewable, and every other kind of generation is getting less revenue than they would have if gas prices had not fallen so far. Gas prices have such an overwhelming influence because gas plants set the price so frequently in all organized markets. No suppy source is happy about it. Markets are brutal.
2) Its wrong to say certain renewable policies are “distortionary” when the clean energy they are bringing would have been likely under a carbon price. All market participants should have been well aware for at least the last decade that some form of carbon regulation or pricing was likely. To be sure the most sound economic policy is to price the externality directly. But equally obviously, most states and at the federal level, a carbon price isn’t happening in the near term. Some renewable policies (but not all) are pretty close second best policies. They are deploying a lot of low cost carbon solutions, especially considering price risk which is not factored into prices as it should be, and in turn helping reduce those costs further. Transitioning policies over time to a carbon price would be sound policy. Until then, we should carefully design efficient second-best policies.
3) One person’s “out of market” purchase is another person’s in-market purchase. JC Penney probably considers my Amazon Prime purchases out of market. From the consumer’s perspective, its all part of “the market.” Some consumers never liked going to the mall. States, utilities, and now a large group of large corporate energy users are choosing renewables or other supply sources and that is their right. Markets should give them a forum for exchanging the goods and services they want, they shouldn’t tell the consumer their preferences are wrong.
4) Voluntary (not mandatory) long term contracts are part of the market, not part of the problem. They hedge price risk for consumers. The California energy crises of 2000-2001 will always be Exhibit A for that. They also reduce the financing cost for generation. It sucks when you’re the supplier that didn’t get chosen. But that shouldn’t be a basis for preventing willing buyers and sellers from contracting in that way. Gas and nuclear generation in particular should like to have a portfolio which include long term contracts and capacity value incorporated into them. Some markets have too little long term contracting and that puts too much pressure on central capacity markets, which then requires ever-increasing administrative band aids and stakeholder politics-driven capacity market design changes.
We absolutely do need to make sure power markets buy sufficient energy, reserves, and reliability services. As variable generation sources grow, paying for flexibility becomes more important. With new kinds of storage coming into the market, we need to be especially careful to make the markets technology-neutral, and not construct barriers to entry by assuming the supplier will be one technology or another. Lifting offer/price caps and installing operating reserves demand curves as ERCOT did make good economic policy sense to get price signals right. It’s never easy as a regulator to support those, but there’s probably never been a better time to do so.
-Rob Gramlich, firstname.lastname@example.org