Tag Archives: market design

California’s water futures market slow to rise as it may not be meeting the real need

I wrote about potential problems with the NASDAQ Veles California Water Index futures market. The market is facing more headwinds as farmers are wary of participating in the cash-only markets that does not deliver physical water.

Their reluctance illustrates a deeper problem with the belief in and advocacy for relying on short-run markets to finance capital intensive industries. The same issue is arising in electricity where a quarter-century experiment has been running on whether hourly energy-only markets can deliver the price signals to maintain reliability and generate clean energy. The problem is making investment decisions and financing those investments rely on a relatively stable stream of costs and revenues. Some of that can be fixed through third-party contracts and other financial instruments but the structures of the short term markets are such that entering or exiting can influence the price and erode profits.

In the case of California Water Index futures market, the pricing fails to recognize an important different between physical and financial settlement of water contracts: water applied this year also keeps crops, particularly permanent ones such as orchards and vineyards, viable for next year and into the future. In other words, physical water delivers multi-year benefits while a financial transaction only addresses this year’s cashflow problem. The farmer still faces the problem of how to get the orchard to the next year.

Whether a financial cash-settlement only futures market will work is still an open question, but farmers are likely looking for a more direct solution to keeping their farming operations viable in the face of greater volatility in water supplies.

Why are real-time electricity retail rates no longer important in California?

The California Public Utilities Commission (CPUC) has been looking at whether and how to apply real-time electricity prices in several utility rate applications. “Real time pricing” involves directly linking the bulk wholesale market price from an exchange such as the California Independent System Operator (CAISO) to the hourly retail price paid by customers. Other charges such as for distribution and public purpose programs are added to this cost to reach the full retail rate. In Texas, many retail customers have their rates tied directly or indirectly to the ERCOT system market that operates in a manner similar to CAISO’s. A number of economists have been pushing for this change as a key solution to managing California’s reliability issues. Unfortunately, the moment may have passed where this can have a meaningful impact.

In California, the bulk power market costs are less than 20% of the total residential rate. Even if we throw in the average capacity prices, it only reaches 25%. In addition, California has a few needle peaks a year compared to the much flatter, longer, more frequent near peak loads in the East due to the differences in humidity. The CAISO market can go years without real price deviations that are consequential on bills. For example, PG&E’s system average rate is almost 24 cents per kilowatt-hour (and residential is even higher). Yet, the average price in the CAISO market has remained at 3 to 4 cents per kilowatt-hour since 2001, and the cost of capacity has actually fallen to about 2 cents. Even a sustained period of high prices such as occurred last August will increase the average price by less than a penny–that’s less than 5% of the total rate. The story in 2005 was different, when this concept was first offered with an average rate of 13 cents per kilowatt-hour (and that was after the 4 cent adder from the energy crisis). In other words, the “variable” component just isn’t important enough to make a real difference.

Ahmad Faruqui who has been a long time advocate for dynamic retail pricing wrote in a LinkedIn comment:

“Airlines, hotels, car rentals, movie theaters, sporting events — all use time-varying rates. Even the simple parking meter has a TOU rate embedded in it.”

It’s true that these prices vary with time, and electricity prices are headed that way if not there already. Yet these industries don’t have prices that change instantly with changes in demand and resource availability–the prices are often set months ahead based on expectations of supply and demand, much as traditional electricity TOU rates are set already. Additionally, in all of these industries , the price variations are substantially less than 100%. But for electricity, when the dynamic price changes are important, they can be up to 1,000%. I doubt any of these industries would use pricing variations that large for practical reasons.

Rather than pointing out that this tool is available and some types of these being used elsewhere, we should be asking why the tool isn’t being used? What’s so different about electricity and are we making the right comparisons?

Instead, we might look at a different package to incorporate customer resources and load dynamism based on what has worked so far.

  • First is to have TOU pricing with predictable patterns. California largely already has this in place, and many customer groups have shown how they respond to this signal. In the Statewide Pilot on critical peak period price, the bulk of the load shifting occurred due to the implementation of a base TOU rate, and the CPP effect was relatively smaller.
  • Second, to enable more distributed energy resources (DER) is to have fixed price contracts akin to generation PPAs. Everyone understands the terms of the contracts then instead of the implicit arrangement of net energy metering (NEM) that is very unsatisfactory for everyone now. It also means that we have to get away from the mistaken belief that short-run prices or marginal costs represent “market value” for electricity assets.
  • Third for managing load we should have robust demand management/response programs that target the truly manageable loads, and we should compensate customers based on the full avoided costs created.

Is the NASDAQ water futures market transparent enough?

Futures markets are settled either physically with actual delivery of the contracted product, or via cash based on the difference in the futures contract price and the actual purchase price. The NASDAQ Veles California Water Index future market is a cash settled market. In this case, the “actual” price is constructed by a consulting firm based on a survey of water transactions. Unfortunately this method may not be full reflective of the true market prices and, as we found in the natural gas markets 20 years ago, these can be easily manipulated.

Most commodity futures markets, such at the crude oil or pork bellies, have a specific delivery point, such as Brent North Sea Crude or West Texas Intermediate at Cushing, Oklahoma or Chicago for some livestock products. There is also an agreed upon set of standards for the commodities such as quality and delivery conditions. The problem with the California Water Index is that these various attributes are opaque or even unknown.

Two decades ago I compiled the most extensive water transfer database to date in the state. I understand the difficulty of collecting this information and properly classifying it. The bottom line is that there is not a simple way to clearly identify what is the “water transfer price” at any given time.

Water supplied for agricultural and urban water uses in California has many different attributes. First is where the water is delivered and how it is conveyed. While water pumped from the Delta gets the most attention, surface water comes from many other sources in the Sacramento and San Joaquin Valleys, as well as from the Colorado River. The cost to move this water greatly varies by location ranging from gravity fed to a 4,000 foot lift over the Tehachapis.

Second is the reliability and timing of availability. California has the most complex set of water rights in the U.S. and most watersheds are oversubscribed. A water with a senior right delivered during the summer is more valuable than a junior right delivered in the winter.

Third is the quality of the water. Urban districts will compete for higher quality sources, and certain agricultural users can use higher salinity sources than others.

A fourth dimension is that water transfers are signed for different periods and delivery conditions as well as other terms that directly impact prices.

All of these factors lead to a spread in prices that are not well represented by a single price “index”. This becomes even more problematic when a single entity such as the Metropolitan Water District enters the market and purchases one type of water which they skews the “average.” Bart Thompson at Stanford has asked whether this index will reflect local variations sufficiently.

Finally, many of these transactions are private deals between public agencies who do not reveal key attributes these transfers, particularly price, because there is not an open market reporting requirement. A subsequent study of the market by the Public Policy Institute of California required explicit cooperation from these agencies and months of research. Whether a “real time” index is feasible in this setting is a key question.

The index managers have not been transparent about how the index is constructed. The delivery points are not identified, nor are the sources. Whether transfers are segmented by water right and term is not listed. Whether certain short term transfers such as the State Water Project Turnback Pool are included is not listed. Without this information, it is difficult to measure the veracity of the reported index, and equally difficult to forecast the direction of the index.

The housing market has many of these same attributes, which is one reason why you can’t buy a house from a central auction house or from a dealer. There are just too many different dimensions to be considered. There is housing futures market, but housing has one key difference from the water transfer market–the price and terms are publicly reported to a government agency (usually a county assessor). Companies such as CoreLogic collect and publish this data (that is distributed by Zillow and Redfin.)

In 2000, natural gas prices into California were summarized in a price index reported by Natural Gas Intelligence. The index was based a phone survey that did not require verification of actual terms. As part of the electricity crisis that broke that summer, gas traders found that they could manipulate gas prices for sales to electricity generators higher by simply misreporting those prices or by making multiple sequential deals that ratcheted up the price. The Federal Energy Regulatory Commission and Commodity Futures Trading Commission were forced to step in and establish standards for price reporting.

The NASDAQ Veles index has many of the same attributes as the gas market had then but perhaps with even less regulatory protections. It is not clear how a federal agency could compel public agencies, including the U.S. Bureau of Reclamation, to report and document prices. Oversight of transactions by water districts is widely dispersed and usually assigned to the local governing board.

Trying to introduce a useful mechanism to this market sounds like an attractive option, but the barriers that have impeded other market innovations may be too much.

ERCOT has the peak period scarcity price too high

The freeze and resulting rolling outages in Texas in February highlighted the unique structure of the power market there. Customers and businesses were left with huge bills that have little to do with actual generation expenses. This is a consequence of the attempt by Texas to fit into an arcane interpretation of an economic principle where generators should be able to recover their investments from sales in just a few hours of the year. Problem is that basic of accounting for those cashflows does not match the true value of the power in those hours.

The Electric Reliability Council of Texas (ERCOT) runs an unusual wholesale electricity market that supposedly relies solely on hourly energy prices to provide the incentives for incenting new generation investment. However, ERCOT is using the same type of administratively-set subsidies to create enough potential revenue to cover investment costs. Further, a closer examination reveals that this price adder is set too high relative to actual consumer value for peak load power. All of this leads to a conclusion relying solely on short-run hourly prices as a proxy for the market value that accrues to new entrants is a misplaced metric.

The total ERCOT market first relies on side payments to cover commitment costs (which creates barriers to entry but that’s a separate issue) and second, it transfers consumer value through to the Operating Reserve Demand Curve (ORDC) that uses a fixed value of lost load (VOLL) in an arbitrary manner to create “opportunity costs” (more on that definition at a later time) so the market can have sufficient scarcity rents. This second price adder is at the core of ERCOT’s incentive system–energy prices alone are insufficient to support new generation investment. Yet ERCOT has ignored basic economics and set this value too high based on both available alternatives to consumers and basic regional budget constraints.

I started with an estimate of the number of hours where prices need the ORDC to be at full VOLL of $9000/MWH to recover the annual revenue requirements of combustion turbine (CT) investment based on the parameters we collected for the California Energy Commission. It turns out to be about 20 to 30 hours per year. Even if the cost in Texas is 30% less, this is still more 15 hours annually, every single year or on average. (That has not been happening in Texas to date.) Note for other independent system operators (ISO) such as the California ISO (CAISO), the price cap is $1,000 to $2,000/MWH.

I then calculated the cost of a customer instead using a home generator to meet load during those hours assuming a life of 10 to 20 years on the generator. That cost should set a cap on the VOLL to residential customers as the opportunity cost for them. The average unit is about $200/kW and an expensive one is about $500/kW. That cost ranges from $3 to $5 per kWh or $3,000 to $5,000/MWH. (If storage becomes more prevalent, this cost will drop significantly.) And that’s for customers who care about periodic outages–most just ride out a distribution system outage of a few hours with no backup. (Of course if I experienced 20 hours a year of outage, I would get a generator too.) This calculation ignores the added value of using the generator for other distribution system outages created by events like a hurricane hitting every few years, as happens in Texas. That drives down this cost even further, making the $9,000/MWH ORDC adder appear even more distorted.

The second calculation I did was to look at the cost of an extended outage. I used the outages during Hurricane Harvey in 2017 as a useful benchmark event. Based on ERCOT and U.S. Energy Information Reports reports, it looks like 1.67 million customers were without power for 4.5 days. Using the Texas gross state product (GSP) of $1.9 trillion as reported by the St. Louis Federal Reserve Bank, I calculated the economic value lost over 4.5 days, assuming a 100% loss, at $1.5 billion. If we assume that the electricity outage is 100% responsible for that loss, the lost economic value per MWH is just under $5,000/MWH. This represents the budget constraint on willingness to pay to avoid an outage. In other words, the Texas economy can’t afford to pay $9,000/MWH.

The recent set of rolling blackouts in Texas provides another opportunity to update this budget constraint calculation in a different circumstance. This can be done by determining the reduction in electricity sales and the decrease in state gross product in the period.

Using two independent methods, I come up with an upper bound of $5,000/MWH, and likely much less. One commentator pointed out that ERCOT would not be able achieve a sufficient planning reserve level at this price, but that statement is based on the premises that short-run hourly prices reflect full market values and will deliver the “optimal” resource mix. Neither is true.

This type of hourly pricing overemphasizes peak load reliability value and undervalues other attributes such as sustainability and resilience. These prices do not reflect the full incremental cost of adding new resources that deliver additional benefits during non-peak periods such as green energy, nor the true opportunity cost that is exercised when a generator is interconnected rather than during later operations. Texas has overbuilt its fossil-fueled generation thanks to this paradigm. It needs an external market based on long-run incremental costs to achieve the necessary environmental goals.

Moving beyond the easy stuff: Mandates or pricing carbon?

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Meredith Fowlie at the Energy Institute at Haas posted a thought provoking (for economists) blog on whether economists should continue promoting pricing carbon emissions.

I see, however, that this question should be answered in the context of an evolving regulatory and technological process.

Originally, I argued for a broader role for cap & trade in the 2008 CARB AB32 Scoping Plan on behalf of EDF. Since then, I’ve come to believe that a carbon tax is probably preferable over cap & trade when we turn to economy wide strategies for administrative reasons. (California’s CATP is burdensome and loophole ridden.) That said, one of my prime objections at the time to the Scoping Plan was the high expense of mandated measures, and that it left the most expensive tasks to be solved by “the market” without giving the market the opportunity to gain the more efficient reductions.

Fast forward to today, and we face an interesting situation because the cost of renewables and supporting technologies have plummeted. It is possible that within the next five years solar, wind and storage will be less expensive than new fossil generation. (The rest of the nation is benefiting from California initial, if mismanaged, investment.) That makes the effective carbon price negative in the electricity sector. In this situation, I view RPS mandates as correcting a market failure where short term and long term prices do not and cannot converge due to a combination of capital investment requirements and regulatory interventions. The mandates will accelerate the retirement of fossil generation that is not being retired currently due to mispricing in the market. As it is, many areas of the country are on their way to nearly 100% renewable (or GHG-free) by 2040 or earlier.

But this and other mandates to date have not been consumer-facing. Renewables are filtered through the electric utility. Building and vehicle efficiency standards are imposed only on new products and the price changes get lost in all of the other features. Other measures are focused on industry-specific technologies and practices. The direct costs are all well hidden and consumers generally haven’t yet been asked to change their behavior or substantially change what they buy.

But that all would seem to change if we are to take the next step of gaining the much deeper GHG reductions that are required to achieve the more ambitious goals. Consumers will be asked to get out of their gas-fueled cars and choose either EVs or other transportation alternatives. And even more importantly, the heating, cooling, water heating and cooking in the existing building stock will have to be changed out and electrified. (Even the most optimistic forecasts for biogas supplies are only 40% of current fossil gas use.) Consumers will be presented more directly with the costs for those measures. Will they prefer to be told to take specific actions, to receive subsidies in return for higher taxes, or to be given more choice in return for higher direct energy use prices?

Reverse auctions for storage gaining favor

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Two recent reports highlight the benefits of using “reverse auctions”. In a reverse auction, the buyer specifies a quantity to be purchased, and sellers bid to provide a portion of that quantity.  An article in Utility Dive summarizes some of the experiences with renewable market auctions.  A separate report in the Review of Environmental Economics and Policy goes further to lay out five guidelines:

  1. Encourage a Large Number of Auction Participants
  2. Limit the Amount of Auctioned Capacity
  3. Leverage Policy Frameworks and Market Structures
  4. Earmark a Portion of Auctioned Capacity for Less-mature Technologies
  5. Balance Penalizing Delivery Failures and Fostering Competition

This policy prescription requires well-informed policy makers balancing different factors–not a task that is well suited to a state legislature. How to develop such a coherent policy can done in two ways. The first is to let the a state commission work through a proceeding to set an overall target and structure. But perhaps a more fruitful approach would be to let local utilities, such as California’s community choice aggregators (CCAs) to set up individual auctions, maybe even setting their own storage targets and then experimenting with different approaches.

California has repeatedly made errors by overly relying on centralized market structures that overcommit or mismatch resource acquisition. This arises because a mistake by a single central buyer is multiplied across all load while a mistake by one buyer within a decentralized market is largely isolated to the load of that one buyer. Without perfect foresight and a distinct lack of mechanisms to appropriately share risk between buyers and sellers, we should be designing an electricity market that mitigates risks to consumers rather than trying to achieve a mythological “optimal” result.

CCAs reach RPS targets with long-term PPAs

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As I listen to the opening of the joint California Customer Choice En Banc held by the CPUC and CEC, I hear Commissioners and speakers claiming that community choice aggregators (CCAs) are taking advantage of the current market and shirking their responsibilities for developing a responsible, resilient resource portfolio.

The CPUC’s view has two problems. The first is an unreasonable expectation that CCAs can start immediately as a full-grown organization with a complete procurement organization, and more importantly, a rock solid credit history. The second is how the CPUC has ignored the fact that the CCAs have already surpassed the state’s RPS targets  in most cases and that they have significant shares of long-term power purchase agreements (PPAs).

State law in fact penalizes excess procurement of RPS-eligible power by requiring that 65% of that specific portfolio be locked into long-term PPAs, regardless of the prudency of that policy. PG&E has already demonstrated that they have been unable to prudently manage its long-term portfolio, incurring a 3.3 cents per kilowatt-hour risk hedge premium on its RPS portfolio. (Admittedly, that provision could be interpreted to be 65% of the RPS target, e.g., 21.5% of a portfolio that has met the 33% RPS target, but that is not clear from the statute.)

 

Why the CPUC’s RA Market Report gives the wrong reliability price metric

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In its annual report on resource adequacy (RA) transactions, the CPUC reports the wrong result for the market price to be used for valuing capacity from the RA market data. The Commission’s decision issued in the PCIA rulemaking on establishing the CCA’s “exit fee” uses this value in error. In the CAISO energy and ancillary services markets, the market clearing price used to set the value of the energy portfolio is determined by the highest accepted bid in a single hour, and then averaged across all hours. In contrast, the average reported RA price in The 2017 Resource Adequacy Report incorrectly reports the average of all transactions. This would be equivalent to the CAISO reporting the average of all accepted bids, including those at zero or even negative, as the market clearing price.

The appropriate RA price metric is the highest RA transaction price for each month. This price represents the market equilibrium point at which a consumer is willing to pay the highest price given how low a price a supplier is willing to provide that quantity of the resource. (The other transactions are called “inframarginal” and such transactions are common in many markets.) In a full auction market, all transactions would clear at this single price, which is why the CAISO reports a single market clearing price for all transactions in a single hour. That should also be the case for the RA market price, except the time unit is a month.

Due to a lack of an auction for the moment, it is possible to manipulate the highest apparent price through a bilateral transaction. Instead, the Commission could choose a price near the highest point, but with sufficient market depth to mitigate potential manipulation. Using the 90th percentile transaction is one metric commonly used based on a quick survey of market price reports.

What type of regulation when?

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I like this taxonomy of what type of regulatory/liability framework to use in which situation posted in Environmental Economics. (Reminds me of a market-type structure I created for my 1996 paper on environmental commodity markets.) However, I think the two choices on the right side could be changed:

  • Lower right corner to “incentive-based regulation”: The damages are clear and can be valued, but engaging in market transactions is costly. For example, energy efficiency has a clear value with significant spill over benefits, but the costs of gaining information about net gains is costly for individuals. So setting an incentive standard for manufacturers or in energy rates is more cost effective.
  • Upper right corner to “command and control regulation”: The damages are known and significant, but quantifying them economically, or even physically, is difficult. There are no opportunities for market transactions, but society wants to act. In this case, the regulators would set bounds on behavior or performance.

Commentary on CPUC Rate Design Workshop

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The California Public Utilities Commission (CPUC) held a two-day workshop on rate design principles for commercial and industrial customers. To the the extent possible, rates are designed in California to reflect the temporal changes in underlying costs–the “marginal costs” of power production and delivery.

Professor Severin Borenstein’s opening presentation doesn’t discuss a very important aspect of marginal costs that we have too long ignored in rate making. That’s the issue of “putty/clay” differences. This is an issue of temporal consistency in marginal cost calculation. The “putty” costs are those short term costs of operating the existing infrastructure. The “clay” costs are those of adding infrastructure which are longer term costs. Sometimes the operational costs can be substitutes for infrastructure. However we are now adding infrastructure (clay) in renewables have have negligible operating (putty) costs. The issue we now face is how to transition from focusing on putty to clay costs as the appropriate marginal cost signals.

Carl Linvill from the Regulatory Assistance Project (RAP) made a contrasting presentation that incorporated those differences in temporal perspectives for marginal costs.

Another issue raised by Doug Ledbetter of Opterra is that customers require certainty as well as expected returns to invest in energy-saving projects. We can have certainty for customers if the utilities vintage/grandfather rates and/or structures at the time they make the investment. Then rates / structures for other customers can vary and reflect the benefits that were created by those customers making investments.

Jamie Fine of EDF emphasized that rate design needs to focus on what is actionable by customers more so than on a best reflection of underlying costs. As an intervenor group representative, we are constantly having this discussion with utilities. Often when we make a suggestion about easing customer acceptance, they say “we didn’t think of that,” but then just move along with their original plan. The rise of DERs and CCAs are in part a response to that tone-deaf approach by the incumbent utilities.