Tag Archives: incentive based regulation

Using floods to replenish groundwater

ALMOND  ORCHARD FLOODING

M.Cubed produced four reports for Sustainable Conservation on using floodwaters to recharge aquifers in California’s Central Valley. The first is on expected costs. The next three are a set on the benefits, participation incentives and financing options for using floodwaters in wetter years to replenish groundwater aquifers. We found that costs would range around $100 per acre-foot, and beneficiaries include not only local farmers, but also downstream communities with lower flood control costs, upstream water users with more space for storage instead of flood control, increased hydropower generation, and more streamside habitat. We discussed several different approaches to incentives based on our experience in a range of market-based regulatory settings and the water transfer market.

With the PPIC’s release of Water and the Future of the San Joaquin Valley, which forecasts a loss of 500,000 acres of agricultural production due to reduced groundwater pumping under the State Groundwater Management Act (SGMA), local solutions that mitigate groundwater restrictions should be moving to the fore.

Don Cameron at Terranova Ranch started doing this deliberately earlier this decade, and working with Phil Bachand and UC Davis, more study has shown the effectiveness, and the lack of risk to crops, from this strategy. The Department of Water Resources has implemented the Flood-MAR program to explore this alternative further. The Flood-MAR whitepaper explores many of these issues, but its list of beneficiaries is incomplete, and the program appears to not yet moved on to how to effectively implement these programs integrated with the local SGMA plans. Our white papers could be useful starting points for that discussion.

(Image Source: Chico Enterprise-Record)

 

 

 

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Reaganomics for fuel economy?

electric-car

I chuckled when I saw this article extolling how CAFE fuel economy standards should be replaced with “clean tax cuts.” One proponent said, “If you want more of something, tax it less.”

But apparently, these incentives work only one direction. “It’s very common, historically, for companies to not meet the targets and just pay the fines,” said Josiah Neeley, a senior fellow for the R Street Institute. However, the auto companies were not happy with a proposal to increase the penalty 155%.  Does that mean that the penalty got large enough to incent greater compliance?

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.

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.