Tag Archives: incentive based regulation

Another market mechanism saving the environment

EDF posted a blog about the resuscitation of U.S. fisheries and how two-thirds of those fisheries are now sustainable thanks to changes in management practices. At the core of those programs are market-based incentives with individual transferable quotas (ITQ). Fishermen are allocated a certain amount of catch within a season and they can trade those quotas among themselves. The overall cap maintains the sustainability of the fishery while individual fishermen can catch an amount that best meets their own objectives and constraints.

A second element that’s often part of these programs is a buyout program to reduce the size of the overall fleet. This reduces the risk for the boats that remain in the fleet while compensating those who exit for their losses.

These are examples of successful “cap and trade” programs. These lessons are applicable to managing water rights and reducing GHG emissions.

Cap & trade and market design

Bob Sussman at Brookings writes favorably about the resurrection of cap and trade for GHG regulation as a viable policy option with the Chinese planning to implement a program and the US EPA Clean Power Plan encouraging market trading mechanisms in two forms of compliance. Yet as I read this (and also think about proposals to increase water trading to solve California’s ongoing drought), I can see an important missing element in these discussions–how can these markets be designed to gain success?

In 1996, I wrote “Environmental Commodities Markets: ‘Messy’ Versus ‘Ideal’ Worlds” that explored the issues of market design and political realities. As I’ve written recently, we are not always good at fully compensating the losers in environmental policy making, and these groups tend to oppose policies that are beneficial for society as a result. And market incentive proponents seem to always propose some variation on one of two market designs: 1) everyone for themselves in searching for and settling transactions or 2) a giant periodic auction.

In reality, carefully designing market institutions that work for participants is key to the success of those markets. Daniel Bromley wrote about how just “declaring markets” in Russia and Eastern Europe did not instantly transform those economies, much to our chagrin. The RECLAIM emissions market has woefully underperformed because SCAQMD didn’t think through how transactions could be facilitated (and that failure prompted my article.) Frank Wolak and Jonathan Kolstad confirmed my own FERC testimony that the disfunction of the RECLAIM market led to higher electricity prices in the California crisis of 2000-01.

For a presentation a few years ago, I prepared this typology of market structure that looks at the search and match mechanisms and the price revelation and settlement mechanisms. This presentation focused on water transfer markets in California, but it’s also applicable to emission markets. Markets range from brokered/negotiated real estate to dealer/posted-price groceries. Even the New York Stock Exchange, which is a dealer/auction probably works differently than how most people think. There are differences in efficiency and ease of use, often trading off. As we move forward, we need more discussion about these nuts and bolts issues if we want truly successful outcomes.

Market Typologies

Reexamining growth and risk sharing for utilities

Severin Borenstein at the Energy Institute at Haas blogged about the debate over moving to residential fixed charges, and it has started a lively discussion. I added my comment on the issue, which I repost here.

The question of recovery of “fixed” costs through a fixed monthly charge raises a more fundamental question: Should we revisit the question of whether utilities should be at risk for recovery of their investments? As is stands now if a utility overinvests in local distribution it faces almost no risk in recovering those costs. As we’ve seen recently demand has trended well below forecasts since 2006 and there’s no indication that the trend will reverse soon. I’ve testified in both the PG&E and SCE rate cases about how this has led to substantial stranded capacity. Up to now the utilities have done little to correct their investment forecasting methods and continue to ask for authority to make substantial “traditional” investment. Shareholders suffer few consequences from having too much distribution investment–this creates a one-sided incentive and it’s no surprise that they add yet more poles and wire. Imposing a fixed charge instead of including it as a variable charge only reinforces that incentive. At least a variable charge gives them some incentive to avoid a mismatch of revenues and costs in the short run, and they need to think about price effects in the long run. But that’s not perfect.

When demand was always growing, the issue of risk-sharing seemed secondary, but now it should be moving front and center. This will only become more salient as we move towards ZNE buildings. What mechanism can we give the utilities so that they more properly balance their investment decisions? Is it time to reconsider the model of transferring risk from shareholders to ratepayers? What are the business models that might best align utility incentives with where we want to go?

The lesson of the last three decades has been that moving away from direct regulation and providing other outside incentives has been more effective. Probably the biggest single innovation that has been most effective has been imposing more risk on the providers in the market.

California has devoted as many resources as any state to trying to get the regulatory structure right–and to most of its participants, it’s not working at the moment. Thus the discussion of whether fixed charges are appropriate need to be in the context of what is the appropriate risk sharing that utility shareholders should bear.

This is not a one-side discussion about how groups of ratepayers should share the relative risk among themselves for the total utility revenue requirement. That’s exactly the argument that the utilities want us to have. We need to move the argument to the larger question of how should the revenue requirement risk be shared between ratepayers and shareholders. The answer to that question then informs us about what portion of the costs might be considered unavoidable revenue responsibility for the ratepayers (or billpayers as I recently heard at the CAISO Symposium) and what portion shareholders will need to work at recovering in the future. As such the discussion has two sides to it now and revenue requirements aren’t a simple given handed down from on high.

Overwhelmed by “opportunities” at the CPUC

The opening of yet another rulemaking at the CPUC and the revelations of more contacts between PG&E and CPUC Commissioners are two sides of a larger conundrum in state electricity policy development and implementation. The OECD recently issued a wish list for how regulatory agencies should be structured and behave. (Thanks to Mark Pearson for posting this.) Yes, some are “pie in the sky” but they provide a useful means of evaluating how a regulatory agency is performing.

Looking at the first principle, the CPUC has been set adrift in part by the lack of role clarity in the state. At one point at least 8 statewide agencies had significant roles in electricity planning and ratemaking. (Along with the CPUC, there’s been the CEC, CAISO, CARB, CDWR, SWRCB, Electricity Oversight Board, and California Power Authority, the last 2 now defunct.) And there are additional local agencies (e.g., SCAQMD). This has blurred the lines of authority and allowed forum shopping.

And perhaps most importantly the number of proceedings at the CPUC have proliferated to a point where it is impossible for intervenors to devote enough resources to follow what’s happening everywhere. At least 14 different rulemakings are looking at interdependent elements of planning for increased renewables and the transformation of the electricity market. These include the long term power procurement, renewables portfolio standard, energy efficiency, water-energy nexus, demand side response, utility shareholder incentives, storage, distributed generation and self generationsolar initiative, net energy metering, alternative fueled and electric vehiclesresidential rate design, CCA rules, and recently, distribution resources planning.  And these don’t count the many utility applications such as the green tariff and community solar garden proposals. Some of these proceedings have been open over a decade with only partial resolution, and the CPUC has opened direct successors up to 4 times. While looking to develop a consistent regulatory framework for evaluating integrated demand side resources is an admirable goal, it could be overwhelmed by the divided attention demanded from all of these other proceedings. That undermines another OECD principle–transparency–even if appearances look differently.

Finally funding for both intervenors and skilled CPUC staff has become untenable and effective participation in declining, further eroding yet another OECD principle. This allows the well-funded utilities to influence outcomes while no one is looking. The documentation of the meetings and emails are only a reflection of the underlying problems.

The answers would seem to include:

  • to consolidate proceedings rather than opening new ones,
  • not adding yet more ratesetting proceedings for specific add ons, and
  • funding intervenors on a more equitable basis with utilities and paying those groups sooner than two years after the relevant decision.

Some of these will require legislative action; others might be implemented after the current CPUC president has left. But it will only happen if intervenors collectively demand reform.

What are the missing questions in California’s distribution planning OIR?

The CPUC has opened a long awaited rulemaking to revisit (or maybe visit for the first time!) how utilities should plan their distribution investments to better integrate with distributed energy resources (DER). State law now requires the utilities to file distribution plans by next July. But the CPUC may want to consider some deeper questions while formulating its policies.

To date the utilities have pretty much been able to make such investments with little oversight. For one client, AECA, we submitted testimony pointing out that PG&E had consistently overforecasted demand and used that demand to justify new distribution investment that probably is unneeded. Based on a corrected forecast that recognizes that that PG&E’s (and the state’s) demand has turned downward since 2007, PG&E’s loads don’t return to 2007 levels until at least 2014. (We found a similar pattern in SCE’s 2012 GRC filings.)

 

AECA - PG&E 2014 GRC Testimony: Comparing Demand Forecasts

AECA – PG&E 2014 GRC Testimony: Comparing Demand Forecasts

Both PG&E and SCE justified new investment based on phantom load growth, but they would have been better served to show what investment might be required for the evolving electricity market. SCE has responded with the Living Pilot that tests out how to best integrate preferred resources.

The CPUC is relying on Paul De Martini’s More than Smart paper as a roadmap for the rulemaking. The CPUC has asked a number of questions to be addressed by September 4 with replies September 17. A workshop is to be held September 18.Beyond these questions, two more questions come to mind.

First, who will be allowed to play in the DER world? The OIR asks about non-IOU ownership of distribution lines, particularly related to microgrids, but it doesn’t consider the flip side–can utilities or affiliates participate in the DER market? Setting market rules in the face of rapid evolution and uncertainty, current participants will look to protect their current interests unless they are shown a clear opportunity to gain the benefits of a new market. The CPUC ignores the political economy of rulemaking at our risk.

The second is how is this proceeding to be integrated with the multitude of other proceedings at the CPUC that set various resource targets? The LTPP, energy efficiency, demand response and solar initiatives, along with others, all seem to run on parallel tracks with little in the way of interactive feedback. Megawatt targets seem to be set arbitrarily with little evaluation of comparative resource costs and effectiveness, and more importantly, how these resources might best integrate with each other. How are the utilities to adapt to the spread of DER if the CPUC hasn’t considered how much DER might be installed?

Both of these questions are about market functionality. Who are the likely participants? What are their incentives to act in different situations? How would the CPUC prefer that then act? How are price signals to be coordinated to create the preferred incentives? The system investment and operation rules are a necessary component of anticipating the market evolution, but they are not sufficient. California ignored the incentives of market participants in the previous restructuring experiment, at the cost of $20 to $40 billion. We should take heed of what we’ve learned from the past about the paradigm we should use to approach this impending change.

Looking beyond performance based ratemaking in New York’s Utility 2.0

Rory Christian of EDF has written about using performance-based ratemaking “+” (PBR+) in New York’s Reforming the Energy Vision proceeding. EDF, in taking an important step for an environmental advocate, recognizes the importance of providing the right economic incentives for market participants to achieve environmental goals. Prescriptive solutions too often are misguided and inflexible leading to failure and high costs.

That said, PBR+ may not be the best solution (and I don’t have the immediate answer to this question.) PBR hasn’t had a great track record in California. Diablo Canyon suffered from excessive costs that led to the push for restructuring. The competitive transition charge (CTC) opened the door for market manipulation. And the CPUC couldn’t say “no” when it awarded incentives for questionable energy efficiency gains. Other jurisdictions have had mixed results. Mechanism design is critically important to make PBR work.

Taking a step back from specific policy proposals, an important perspective to consider is that the “regulated utility” is not the same as “utility shareholders.” Shareholders are the true stakeholders in the discussion about the new utility business model. (Utility managers may hijack that role but that probably is not a sustainable position.) So we should be looking outside the box of standard regulatory tools, even PBRs, and ask “how else can utility shareholders see value from the electricity industry outside of their regulated utility affiliate?” There are potential models for alternative approaches that might ease the political and economic transition to the new energy future.

Chuck Goldman at Lawrence Berkeley National Lab made a presentation on the various business model options that are available. The Energy Services Utility (ESU) is an option that deserves greater exploration, particularly in concert with a distributed system operator (DSO). An ESU might provide a model for utility holding company shareholders to participate. But the devil could be in the details.

Nudge and counter-nudge: one combatant

The Atlantic reviewed Cass Sunstein’s latest book on using public policy to redirect individual’s choices. Some complain that the government shouldn’t be influencing daily life in this manner.  However, we already have many other private groups, most businesses, attempting to redirect daily decisions in their favor. But there at least good reasons why we might decide as a larger society to instill counter nudges that lead to overall improved economic decisions and outcomes.

The first is moral hazard where two parties have different amounts of information or levels of incentives. A classic example is a real estate agent and a home buyer. The agent is paid on the percentage of the house price and knows much more about the local market. These conspire to lead to a higher house price on average than would occur in a frictionless market.

The second is the principal-agent problem. In this case, the economic decision-maker is not the actual consumer or producer in the transaction. The health care industry is one classic case where patients defer most of their decisions to a physician, who also happens to be the benefiting service provider. Another case is the split-incentives in the rental housing market where the landlord could make energy-efficiency investments that reduce a tenant’s energy bill, but the tenant actually pays the bill. (I’ll write more on this in a future post.)

Some of this might not be needed with acted like the mathematical automaton that Milton Friedman envisioned, but we do have significant limitations on our abilities to make rational economic decisions. A decentralized price system is probably the best means of allocating use of scarce resources among us. Yet that doesn’t mean that society, through its government, shouldn’t agree to manipulate that price system to arrive at a more preferred set of individual decisions. Thus we should nudge and counter nudge as Sunstein suggests.