Tag Archives: incentive based regulation

A Residential Energy Retrofit Greenhouse Gas Emission Offset Reverse Auction Program

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In most local California jurisdictions, the largest share of stationary emissions will continue to come from the existing buildings. On the other hand, achieving zero net energy (ZNE) or zero net carbon (ZNC) for new developments can be cost prohibitive, particularly if incremental transportation emissions are included. A Residential Retrofit Offset Reverse Auction Program (Retrofit Program) aims to balance emission reductions from both new and existing buildings s to lower overall costs, encourage new construction that is more energy efficient, and incentivize a broader energy efficiency marketplace for retrofitting existing buildings.

The program would collect carbon offset mitigation fees from project developers who are unable to achieve a ZNE or ZNC standard with available technologies and measures. The County would then identify eligible low-income residential buildings to be targeted for energy efficiency and electrification retrofits. Contractors then would be invited to bid on how many buildings they could do for a set amount of money.

The approach proposed here is modeled on the Audubon Society’s and The Nature Conservacy’s BirdReturns Program.[1] That program contracts with rice growers in the Sacramento Valley to provide wetlands in the Pacific Flyway. It asks growers to offer a specified amount of acreage with given characteristics for a set price–that’s the “reverse” part of the auction.

A key impediment to further adoption of energy efficiency measures and appliances is that contractors do not have a strong incentive to “upsell” these measures and products to consumers. In general, contractors pass through most of the hardware costs with little markup; their profits are made on the installation and service labor. In addition, contractors are often asked by homeowners and landlords to provide the “cheapest” alternative measured in initial purchase costs without regard to energy savings or long-term expenditures.

The Retrofit Program is intended to change the decision point for contractors to encourage homeowners and landlords to implement upgrades that would create homes and buildings that are more energy efficient. Contractors would bid to install a certain number of measures and appliances that exceed State and local efficiency standards in exchange for payments from the Retrofit Program. The amount of GHG reductions associated with each type of measure and appliance would be predetermined based on a range of building types (e.g., single-family residential by floor-size category, number of floors, and year built). The contractors can use the funds to either provide incentives to consumers or retain those funds for their own internal use, including increased profits. Contractors may choose to provide more information to consumers on the benefits of improved energy efficiency as a means of increasing sales. Contractors would then be compensated from the Offset Program fund upon showing proof that the measures and appliances were installed. The jurisdiction’s building department would confirm the installation of these measures in the normal course of its permit review work.

Funds for the Retrofit Program would be collected as part of an ordinance for new building standards to achieve the no-net increase in GHG emissions. It also could be included as a mitigation measure for projects falling under the purview of the California Environmental Quality Act (CEQA.)

The Retrofit Program would be financed by mitigation payments made by building developers to achieve a no-net increase in GHG emissions. Buildings would be required to meet the lowest achievable GHG emission levels, but then would pay to mitigate any remainders, including for transportation, charged at the current State Cap and Trade Program auction price for an extended collection of annual allowances[2] that cover emissions for the expected life of the building (e.g., 40 years) (CARB 2024).

M.Cubed proposed this financing mechanism for Sonoma County in its climate action plan.

[1] See https://birdreturns.org/

[2] Referred to as a “strip” in the finance industry.

A Working Lands Carbon Mitigation Bank Program

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A number of counties in California are largely agricultural, with a few small communities. Most of that agricultural land is intensively farmed, much of it irrigated. This situation presents the opportunity to sequester large amounts of carbon relative to the total greenhouse gas emissions from all county activities. In other words, the county can approach a level of net-zero emissions with a surplus available to share with other jurisdictions, particularly with those in within a county.

Since many of these counties are already planning to use this sequestration strategy to meet its own emission reduction goals, these reductions will be real, additional, and verifiable, meeting the gold standard for use as credits by other jurisdictions. The county has a strong incentive to ensure that these reductions are of sufficient quality to meet its own targets, which should make these attractive to other jurisdictions, unlike other credits offered in the marketplace.

A county would establish a Carbon Mitigation Bank using a similar framework to habitat conservation mitigation banks.[1] The county would establish the parameters that achieve the requisite carbon sequestration and then collect in-lieu fees to cover the costs of the bank’s expenses. By expanding the number of jurisdictions contributing and receiving coverage, overall carbon emissions can be reduced more cost-effectively.

Sequestration from working lands can be achieved at a lower cost than most alternatives. For this reason, a county can use its surplus to finance much of its share of the sequestration program by offering it to cities in the county at a margin above the implementation cost sufficient to cover the county’s share of the costs as well. For example, it may cost $50 per CO2e ton sequestered, and the County may use only half of the potential sequestration to meet its own target. The County could then offer its surplus credits to the other jurisdictions at $100 per ton, which is likely less than the cost of additional reductions elsewhere, to cover the full program costs.

M.Cubed proposed this financing mechanism for both Yolo and Sonoma in their climate action plans. Both counties could potentially sequesters hundreds of thousands of tons annually, implying this could be a major revenue source for meeting broader targets.

End the fiction of regulatory oversight of California’s generation

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M.Cubed is the only firm willing to sign the non-disclosure agreements (NDA) that allow us to review the investor-owned utilities’ (IOUs) generation portfolio data on behalf of outside intervenors, such as the community choice aggregators (CCAs). Even the direct access (DA) customers who constitute about a quarter of California’s industrial load are represented by a firm that is unwilling to sign the NDAs. This situation places departed load customers, and in fact all customers, at a distinct disadvantage when trying to regulate the actions of the IOUs. It is simply impossible for a single small firm to scrutinize all of the filings and data from the IOUs. (Not to mention that one, SDG&E, gets a complete free pass for now as that it has no CCAs.)

This situation has arisen because the NDAs require that the “reviewing representatives” not be in a position to advise market participants, such as CCAs or energy service providers (ESPs) that sell to DA customers, on procurement decisions. This is an outgrowth of AB 57 in 2002, a state law passed to bring IOUs back into the generation market after the collapse of restructuring in 2001. That law was intended to the balance of power to the IOUs away from generators for procurement purposes. Now it puts the IOUs at a competitive advantage against other load serving entities (LSEs) such as CCAs and ESPs, and even bundled customers.

This imbalance has arisen for several insurmountable reasons:

  • No firm can build its business on serving only to review IOU filings without offering other procurement consulting services to clients.
  • It is difficult to build expertise for reviewing IOU filings without participating in procurement services for other LSEs or resource providers. (I am uniquely situated by the consulting work I did for the CEC on assessing generation technology costs for over a decade.)
  • CPUC staff similarly lacks the expertise for many of the same reasons, and are relatively ineffective at these reviews. The CPUC is further limited by its ability to recruit sufficient qualified staff for a variety of reasons.

If California wants to rein in the misbehavior by IOUs (such as what I’ve documented on past procurement and shareholder returns earlier), then we have two options to address this problem going forward:

  1. Transform at least the power generation management side of the IOUs into publicly owned entities with more transparent management review.
  2. End the annual review and setting of PCIA and CTC rates by establishing one-time prepayment amounts. By prepaying or setting a fixed annual amount, the impact of accounting maneuvers are diminished substantially, and since IOUs can no longer shift portfolio management risks to departed load customers, the IOUs more directly face the competitive pressures that should make them more efficient managers.

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?

Using floods to replenish groundwater

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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)

 

 

 

Reaganomics for fuel economy?

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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

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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

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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

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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.