1. Skip to navigation
  2. Skip to content
  3. Skip to sidebar

Economic Currents

Keep up to date with the latest UHERO news.

Dr. Frank Wolak: "How Should the Public Utilities Commission Regulate Hawaiian Electric Company for Better Integration of Renewable Energy?"

On Friday November 2, Frank Wolak, the Holbrook Working Professor of Economics at Stanford and Director of Stanford’s Program on Energy and Sustainable Development, gave a special seminar “How Should the Public Utilities Commission Regulate Hawaiian Electric Company for Better Integration of Renewable Energy?” His talk summarized the many ways conventional regulation and rate design creates inefficiency in our electricity system. To lower costs of high-renewable system, he argues that Hawai’i should embrace a “cost based” market in which long-term competitive contracts for power would be used in conjunction with regulated optimization model that would set real-time prices for buying and selling of electricity and grid services.

Below is video of his talk and a link to his slides. https://www.youtube.com/watch?v=uX7HuyeUOOA This special seminar, organized by Governing Green Power (www2.hawaii.edu/~govgreen/), was co-sponsored by UHERO and Sea Grant.

Variable Pricing and the Cost of Renewable Power

How much will it cost to eliminate use of fossil fuels? There is reason for optimism. Technological progress has lowered the cost of wind and solar power to make them competitive with coal and natural gas on a levelized basis. Despite this progress, a recent study by Gowrisankaran, Reynolds and Samano, “Intermittency and the Value of Renewable Energy” (JPE, 2016) indicates that the variability of solar and wind power makes the system-wide costs grow considerably as their share of the power mix rises. While battery costs are falling too, they are still expensive, and cannot easily deal with seasonal or episodic variation in supply.

To economists, the obvious solution to intermittency is real-time retail pricing that reflects the incremental cost and marginal willingness to pay for electricity. Variable pricing would create powerful incentives to efficiently store energy on a distributed basis or otherwise shift consumption from times and places of relatively scarce renewable supply to times and places of plenty. Electricity consumers already have access to many low-cost appliances and devices that store energy in different forms. By carefully timing water heating, electric vehicle charging and water pumping, using ice storage for cooling systems, making micro-adjustments for some kinds of refrigeration, or other means, electricity use can be shifted from seconds to many hours at low cost. Such mechanisms would need to be automated by smart devices acting on customers' behalf. These technologies can make electricity demand highly substitutable over time, at least over horizons up to a day or so. In addition to shifting the timing of electricity consumption within the day, customers facing dynamic prices can also adjust the total amount of power they consume each day, reducing total consumption during extended periods when power is scarce, or increasing it when power is abundant.

In a new study, Imelda, Matthias Fripp and Michael Roberts develop a novel model of power supply and demand to examine the extent to which variable pricing can make renewable energy more cost effective in the state of Hawai‘i. The model is novel in the way it simultaneously optimizes investment in generation capacity, storage capacity, and real-time operation of the system, including an account of reserves, a demand system with different interhour elasticities for different end uses, as well as substitution between electric power and other goods and services. Both supply and demand sides of the model can also provide reserves. The model is an extension of Switch, developed by Matthias Fripp in his PhD dissertation and applied to California. Earlier versions of the model (lacking reserves and demand-side integration) have also been implemented the western United States and other areas. The model is open source and fully adaptable to other settings, but requires a rather substantial amount of data.

Consistent with earlier studies, the authors find that dynamic pricing provides little social benefit in fossil-fuel-dominated power systems, only 2.6 to 4.6 percent of baseline annual expenditure. But dynamic pricing leads to a much greater social benefit of 8.5 to 23.4 percent in a 100 percent renewable power system with otherwise similar assumptions, even if the overall demand for electricity is inelastic (0.1). If overall demand for electricity is elastic (2.0), the social benefits of renewable energy are even greater, and variable pricing can improve welfare by as much as 47 percent of baseline expenditure.

When fully optimized, future high renewable systems, including 100 percent renewable, are remarkably affordable. The welfare maximizing (unconstrained) generation portfolio under the utility's projected 2045 technology and pessimistic interhour demand flexibility uses 79 percent renewable energy, without even accounting for pollution externalities. This optimized share is over 80 percent with more elastic and/or flexible demand, and the cost of growing the share of renewables above this optimum is fairly modest until the last 5 to 10 percent of fossil fuels are eliminated.

Hawai‘i has a natural advantage in adoption of large shares of renewable energy, with plentiful renewable resources and expensive conventional generation. However, the intermittency challenge is especially acute in Hawai‘i, due to the state’s geographic concentration. In continental regions, transmission provides a potentially low-cost alternative to storage and demand response for managing intermittency challenges, as well as transferring renewable power from areas rich in renewable resources to areas that are renewable energy poor. The new modeling framework can assess the substitution possibilities between transmission and demand response, and optimize high-dimensional chronological power systems in a realistic way.


The social cost of renewable electricity relative to a fossil future with flat pricing.

Click graph to enlarge.

Notes: Each line shows the social cost—the loss in total economic surplus (PS + CS)—as the share renewable electricity rises above the least-cost share, holding all else the same. Social cost is measured as percent of expenditure in the baseline scenario, which is a predominantly fossil system with flat pricing in the year 2045. Thus, values less than zero imply a welfare improvement compared to using a conventional fossil system in the future (excluding externalities). Graphs on the left assume current (2016) costs, while graphs on the right assume future (2045) costs. Comparison of the top two rows shows the influence of electric vehicles (EV), contrasting the current fleet share of 0.5 percent EV with 100 percent EV. In the top two rows the overall demand elasticity is fixed at the baseline of θ = 0.1. Comparison of the bottom two rows shows the influence of a more elastic demand (θ = 2 versus θ = 0.1), while holding the EV share fixed at 50 percent. In all graphs, black lines show the social cost with flat prices; dark green line show the social cost with variable prices and pessimistic interhour substitutability; and the light green lines show social cost with variable prices and optimistic interhour substitutability.

- Michael Roberts
UHERO Research Fellow and Professor of Economics


A Pocket Full of PIMs

In the arcane parlance of utility regulation, PIMs are “Performance Incentive Mechanisms.”

This is where we’re headed because, slightly against my expectation, Governor Ige recently signed SB 2939, a bill unanimously passed by the legislature that requires that the Public Utilities Commission:

“…establish performance incentives and penalty mechanisms that directly tie an electric utility revenues to that utility’s achievement on performance metrics and break the direct link between allowed revenues and investment levels.”

A nice summary can be found here. In the world of utility regulation, this act might be the equivalent of what Joe Biden called a “Big F[reaking] Deal” for health care. No other state has moved to change the investor-owned utility business model so radically, particularly to “break the direct link between allowed revenues and investment levels.” Like Obamacare, it’s still a compromise with the existing system, one that maintains our investor-owned utility but aims to change its incentives and business model in a profound way.

Just to be clear, PIMs are not new. They have been a part of utility regulation for a long time. But along the lines of what a colleague said the other day, existing PIMs are a bit like children splashing water against the hull of the Titanic in a futile effort to change its course. The core of the utility’s business model, in Hawai‘i and everywhere else, is revenue connected to an excessive rate of return on its own capital expenditure. This act promises to remove that, and make performance metrics the new profit engine.

Will it work?

Well, it depends. Like most things, the devil is in the details. It’s going to be important to get the performance metrics right, and to attach the right level of reward and penalty associated with each one.

In the old textbook model of utility regulation, the main performance metric is cost, and this is easily incentivized with a price cap, one that is just high enough for the utility to earn a fair return, and perhaps gradually lowered over time if the properly incentivized utility finds lower-cost ways of producing and delivering the goods. Sometimes the incentive to keep costs low needs to be buttressed with quality metrics, like customer service and reliability. This old Palgrave chapter by David Newberry has a nice review of the standard thinking.

But this standard thinking, or even Newberry’s longer treatment, probably won’t work with electric utility of the future currently envisioned in Hawai‘i and other places embracing renewables. What’s new is the growth of distributed resources. This isn’t just rooftop solar. It’s batteries, hot water heaters, air conditioners, electric cars and all manner of electricity uses that have potential flexibility in their timing, and can therefore be employed in a way that makes management of intermittent renewables less costly. This changes standard regulatory frameworks because the utility is unlikely to own most of these flexible distributed resources, yet the way they are used and integrated into the system is key to keeping costs low. And since these resources can compete with the utility’s own investments, it creates a palpable conflict with existing assets owned by HECO, those seeking to sell renewable energy storage services, and with customers.

In other words, the integrated system’s costs no longer equal the utility’s costs.

This new law directs the Public Utilities Commission to reconcile conflicts by using performance metrics to better align interests and find the least cost path toward a renewable energy future.

All of which begs the question: What are the best metrics?

So far, the proposed metrics target plethora of narrow issues, hence the title of this post. These fall well short of an encompassing framework that could redefine the utility’s business model. But I think it’s possible to build such a metric. Economics provides some guidance, with reasonably comprehensive monetary metrics of the net social value of our electricity system, including distributed resources. We could even add costs of pollution externalities to such a metric.

Some may quibble with some of the assumptions, and that's an important conversation to have and revisit regularly. But if a reasonable consensus can be achieved about both the assumptions and the model, the PUC could tie the utility’s allowed revenue to a measure of this net social value. Or, more precisely, the difference between a reasonable, agreed-upon target for this metric and the outcome actually achieved. The target would be tied to clearly identifiable input costs, like fuel prices, the cost of renewable energy, battery storage costs, and even costs of capital, so that performance would hinge on how well the various resources are integrated and managed, if the utility can negotiate good deals for certain inputs, or avoid unnecessary expenditures through smart management. Utility ownership of assets would have nothing to do with it -- the utility would simply make more money if it facilitated more social value.

This idea bears more than a little resemblance to a standard way the PUC has always managed rate cases every three years or so to set allowed revenues and rate schedules. When they do this, the utility, PUC and consumer advocate rely on optimization models that are used to estimate costs and set allowed revenue. The idea laid out above bears some similarity to this process, except that it would encompass costs and benefits that would in one way or another extend beyond the utility’s own costs. The new big piece is incorporation of the demand side–-customers' benefits from electricity use. That’s something myself, Mathias Fripp and Imelda, a UH Mānoa PhD student, recently figured out how to do in order to show how much variable pricing and demand response can lower the cost renewable energy.

In conventional utility regulation, the model is used as a cost baseline to set allowed revenue. Here it would set the target level of social value.

Allowed Revenue = a + b ( social value - target social value)

Besides the model assumptions, which would set the target social value, the PUC would need to set levels for a and b, which set baseline revenue for the utility and the degree to which the utility would be rewarded or punished for exceeding or falling short of the target.

All of this may seem abstract, and on some level, it is. I can’t argue with the idea that this is a “black box” model (except that that is publicly available, and there is always a black box model). It will take some work to make it clearer for a broader audience. We'll work on that. It’s still early….

Stepping back, the big picture idea here is to cut all engines on the Titanic and harness the coordinated efforts of its captain together with those of a hundred tugboats to push the ship in better direction for everyone. The metaphorical iceberg here is mass grid defection, which I fear could be more likely, and sooner, than many realize.

- Michael Roberts
UHERO Research Fellow and Professor of Economics


Should regulators fear bond-rating agencies?

It seems that our political and administrative leaders worry about the bond rating agencies. Their fear is understandable. The cost of capital looms large in all manner of infrastructure projects, and the cost of that capital depends on how risky investors perceive repayment to be.

The cost of capital also looms large for our investor-owned electric utility. HECO has a lot of capital to finance, some of it through corporate bond issues. It is also the sole “off-taker” for many independent power producers, so its financial health may affect the borrowing costs of these counterparties.

This worry was one predictably raised in response to a bill, now on Governor Ige’s desk, that would force the Public Utilities Commission to:

“…establish performance incentives and penalty mechanisms that directly tie an electric utility revenues to that utility’s achievement on performance metrics and break the direct link between allowed revenues and investment levels.

What does this mean?

It helps to know a bit about the convoluted underbelly of utility regulation. Here in Hawaii, and I believe every other state with investor-owned utilities, Public Utilities Commissions (PUCs) set an allowed revenue that utility companies can collect. That revenue comes from a formula that looks something like the following:

Fuel + Purchased Power + O&M + (Capital Investment) x (Allowed Rate of Return)

The utility has to justify these costs to the PUC, which it must approve. Most costs are basically a pure pass through to customers. The utility makes its profit, enough to provide dividends to shareholders, in basically two ways:

  1. 1. It can try to cut operation and maintenance costs and pocket the savings, although it may lose that allowed revenue in the next rate case.
  2. 2. The allowed rate of return on capital.

If the allowed rate of return exceeds what the utility must pay in dividends to shareholders and/or interest rate payments, then utilities have a perverse incentive to tilt everything it does toward maximizing its own capital investment. The only check on the prudency of its investments is the PUC, which must approve most such expenditures.

The good thing about this strange profit mechanism is that, because it basically guarantees that the utility will earn a return on its investments, it’s quite easy for utilities to sell stock and bonds to finance the investment. All of which brings us to the bill on the Governor’s desk and our leaders’ fears of bond-rating agencies.

The bill tries to eliminate this perverse incentive, which basically rewards the utility for maximizing costs, by instead setting revenue based on performance metrics – outcomes that measure value to the utility’s customers and the larger community. These can be anything from measures that show better operation of its power plants to save costs, higher customer satisfaction, and better pollution outcomes.

Performance adjustments already exist in a limited form, but to my knowledge, performance outcomes are not used as the main source of return for any utility. The bill pushes for an unprecedented break from the status quo, and I gather that the Governor is worried (after very intense lobbying by certain interests) that if he signs the bill, HECO’s stock price and its bond rating could be punished by Wall Street.

So, two questions:

  1. 1. Is this fear of bond-rating agencies well justified?
  2. 2. Regardless of bond-rating fears, is this a good bill?


First, I think bond-rating fears are overblown. I don’t believe the bill casts reasonable doubt on the idea that the utility will be allowed to make a reasonable return on its investments. It just says that we need to break the “direct link” with capital investments. All manner of corporations easily raise capital monies with debt and equity issues under the expectation of an indirect link between the investments they make and the value of what they produce with those investments. I think it’s clear that this is the bill’s intent.

More pointedly: the PUC must, due to Supreme Court precedent, allow the utility an opportunity to make a fair return. If I were reading this bill the wrong way – and I think it’s clear that I am not – and the bill were to unfairly keep HECO from making a fair return, it would be quickly struck down by the courts. Wall Street knows this. The bond-rating agencies know this.

Incidentally, HECO’s stock price is up relative to a standard utility index since the bill passed the legislature.

Besides, bond rating agencies have a famously poor track record of predicting anything. (Anyone recall AAA stated-income mortgaged-backed securities?) The academic literature indicates that ratings changes mostly follow the market, with a long lag. Below is a graph from an early classic paper on the link between bond rating changes and stock market returns. It shows that upgrades follow good performance and downgrades follow bad performance. But the upgrades and downgrades have no apparent effect – or possibly even a countervailing effect — on returns after the rating change.

Source: Pinches and Singlelton, Journal of Finance, 1978

The literature shows that bond yields bear a similar relationship with rating changes. Some papers seem to show a subsequent effect for small firms with persistently low-rated corporate debt. But the size of the effect is small.

I’m not the only economist who is cynical about the bond rating agencies. Paul Krugman has noted how markets shrugged after US and Japanese debt got downgraded.

So, don’t fear the bond-rating agencies. Instead, look squarely at fundamentals. Which brings us to the second question: Is this bill a good idea?

Economists have long criticized rate-of-return regulation given its perverse incentive to maximize capital investment and the difficulty of the PUC in policing every investment decision. Here in Hawai‘i, our PUC has famously difficult staffing issues due to limited funding and a revolving door between them, the utility and other interests. Unsurprisingly, the utility pays higher salaries. It’s a challenging dynamic, to put it politely.

Worse, rate-of-return regulation gives the utility no incentive to find innovative solutions. If there is any advantage to having an investor-owned utility rather than a municipality or cooperative like KIUC (Kaui‘i’s electric utility), it is that they should have strong incentives to control costs and find innovative solutions to problems. Rate-of-return regulation undercuts that advantage.

This bill comes at a time when innovative solutions are increasingly important, capital investment is about to explode, and regulation is increasingly difficult. These changes are happening due to rapidly changing technologies and our transition toward 100% renewable energy. These changes expand the scope for innovation to better integrate and manage the variability of sun and wind resources. Many if not most of these opportunities involve investment by customers and independent power producers. Under rate-of-return regulation, these third-party investments can be efficient, but may be explicitly or implicitly resisted by the utility since they displace their own capital investment and source of profit. In other words, rate-of-return regulation causes more problems today than it has in the past.

So, the spirit of this bill is right on target.

The gaping hole in this bill is what it excludes: specific performance metrics that would replace rate-of-return and provide the new source of the utility’s revenue allowance. It kicks these details to the PUC.  Getting these metrics right for the utility of the future is critical. It’s also largely unchartered territory.

The PUC, of course, knows about all of these issues and could make all of these changes unilaterally. It doesn’t need this bill to change the way it determines the utility’s allowed revenue.  And just the other day the PUC opened a docket on performance-based regulation. The timing of the docket’s opening and the Governor’s decision about whether or not to sign this bill is unlikely a coincidence.

The PUC is telling Governor Ige: Don’t sign the bill! We got this!

But do they?

We have a laudable PUC and Consumer Advocate. These agencies are underfunded and overworked, and I think it is clearly evident that despite all the pressures they face, they do work tirelessly for the public interest. They are not captured by the utility.

But I do fear that the regulatory process is largely captured by the utility industry and the armies of consultants and vested interests that travel the country to testify on their behalf. And while change can occur within this process, it is slow. Very slow. With regard to this particular feature of regulation – the excessively high rate of return on the utility’s own capital investment – there appears to be a universal intransigence. To my knowledge, no PUC in the country has accomplished more than a tiny reduction in the allowed rate of return, much less a complete removal of the direct link and full reliance on performance metrics.

So, I gather that the PUC, and the utility, worry about how this law would constrain them. It would force profound change between now and January 2020 when the bill would go into full effect. That’s not much time to completely reinvent the utility’s revenue model. The standard process does not normally invoke that much change so quickly.

While I can understand why the PUC feels this is a risky bill, I fear that the risk is greater if we do not change fast enough. HECO’s costs are rising and technological change is relentlessly advancing, giving customers more options. The utility is pushing hard for grid upgrades that are expensive, but could become obsolete if enough customers leave the grid. A grid defection death spiral could be near.

The larger risk is a mountain of stranded assets, combined with punishingly high electricity prices for the most vulnerable customers—renters who cannot defect. This risk is also the State’s risk, since it may be on the hook for a bailout if the PUC approves investments in assets that quickly become obsolete. (I am told that the State probably would not be on the hook legally, due to this precedent, but the end game here would be ugly regardless.) And political leaders who enabled the catastrophe will, of course, have to answer to voters.

We can’t kick this can anymore. We have to act. This bill isn’t ideal—it doesn’t tell us the right performance metrics that would better align the utilities incentives with the public interest. But it does force us to make these hard choices soon.

- Michael Roberts
UHERO Research Fellow and Professor of Economics


Bringing together energy and climate change policy

We hear a lot about Hawaii’s Renewable Portfolio Standard (RPS) which requires 100% of the utilities’ net electricity sales to come from renewable sources by 2045. Subsidies, rapidly declining solar panel costs, and high electricity prices have led to the proliferation of distributed rooftop solar photovoltaic (PV). By the end of 2016, roughly 1 out of 7 occupied housing units on Oahu had a solar PV system (City and County of Honolulu, 2017; ACS, 2017). Integrating increasing amounts of intermittent renewable energy, including utility-scale solar and wind, presents a challenge for electricity grid operators since at any moment supply must equal demand. While it is easy to get wrapped up in how to enable more cost-effective renewable energy on an outdated grid, designed for centralized generation and a one-way flow of electricity, I’d like to step back for a moment and remind ourselves of the rationale for renewable energy policies to ensure we meet our policy objectives and, towards that end, are using the appropriate policy instruments.

Like the U.S., Hawaii relies heavily on fossil fuels to meet its electricity needs (see Figure 1 for Hawaii’s generation mix in 2016).1 Since fossil fuels are a depletable resource, the transition to renewable energy is theoretically inevitable absent any policy intervention. It is the speed of transition that is inefficient from a social perspective due to the presence of environmental externalities (Gillingham and Sweeney, 2010).2 The damages from greenhouse gas (GHG) emissions are spillover costs not reflected in current market prices for fossil fuels. As a result, there is both more fossil fuel consumption than socially optimal and the transition time to renewable energy is slower. Basic economics tells us that the best way to mitigate climate change is to “get prices right” by imposing a tax equal to the marginal damage cost of emissions or apply emissions trading.3 Such market-based incentives are less costly and allow for more flexibility than traditional command-and-control policies in which uniform standards (ambient, emissions, or technology) must be met by affected sources. The marginal damage cost of GHG emissions can be given by the "social cost" of carbon—the per unit present value of the total damages from carbon dioxide (CO2) emissions or alternatively the benefit from emissions abatement.

Figure 1. Hawaii’s Electricity Generation Portfolio, 2016.

Source: EIA, 2017.

Instead of a broad carbon tax, most of the focus in Hawaii has been on taxing the barrel of oil. This of course also discourages fossil fuel use; however, the barrel tax we have is quite modest so its major impact is as a source of funding. As only $1.05 per barrel is levied—and this excludes aviation fuel and fuel sold to a refiner—it does not capture the full externality cost. And the dirtiest fuel, coal, is also currently exempted.4 We also rely on policy instruments like the RPS or subsidies for renewable energy, which though they likely reduce carbon, not necessarily at least-cost.5 These policies were not founded on the basis of environmental impacts (namely climate change), but instead were primarily driven by affordability6 and a stronger local economy.7

To address climate change specifically, we have a separate policy, Act 234 (2007), which requires Hawaii to reduce its GHG emissions to 1990 levels by 2020. The statewide GHG limit is 13.66 million metric tons of carbon dioxide equivalent (MMTCO2e), excluding air transportation and international bunker fuel emissions and including carbon sinks. In response, GHG rules were established for the electricity sector in 2014; facilities emitting over 100,000 tons of CO2e per year (excluding municipal waste combustion operations and municipal solid waste landfills) are required to reduce emissions by 16% from 2010 levels in 2020. Partnering across the 20 affected facilities is allowed to achieve cost-effective emissions reduction.

Figure 2. GHG Emissions Inventory, 1990 and 2007.

Source: ICF, 2008.

Figure 2 shows Hawaii’s 1990 and 2007 GHG emissions inventory—the most recent inventory to date.8 It shows that the electricity sector produces approximately 30% of GHG emissions. Other sectors matter too, especially transportation. By focusing on economy-wide GHG emissions reduction, coupled with the appropriate policy instrument to meet the policy objective, not only will it encourage more renewable energy in the electricity sector, but it will also facilitate coordinated efforts in other sectors. For instance, ground transportation comprises many individual actors, which together account for 14-18% of emissions. It is also the fastest growing sector (38% increase between 1990 and 2007). Emissions from ground transportation have likely continued to increase despite increased fuel efficiency and the growth of electric vehicles (EVs) in recent years.9 This suggests that even if the electricity sector were to comply with or exceed the 16% reduction, the growth of ground transportation likely outpaces the decline in the electricity sector; without coordinated state action we may not meet Act 234.10

Climate change policy offers a potentially economy-wide approach that can align multiple policy goals—whether it is more affordable, locally produced electricity or the electrification of transportation. An economy-wide carbon tax also means that the same $/ton cost would be levied on gasoline. While there is a federal gasoline tax of 18.4 cents/gallon and a state gasoline tax of 16 cents/gallon (EIA, 2017), this does not necessarily amount to the full externality cost of pollution.11 With the proper price signals, getting more EVs on the road will happen without any other overarching goals or mandates in the transportation sector. Whereas federal Corporate Average Fuel Economy (CAFE) standards increase the fuel efficiency of new vehicles, they do not encourage people to drive less. A carbon tax would target both vehicle purchase and driving decisions for new and used vehicles. Moreover, a carbon tax offers the opportunity to address distributional impacts. Carbon taxes are perceived to be regressive because fuel comprises a greater share of spending for low-income households. However, mandates are more regressive than a revenue-neutral carbon tax which can redistribute revenues to taxpayers by cutting other taxes (e.g. payroll, personal income, and corporate taxes) or through direct payments (flat “check in the mail”).12

Lastly, a carbon tax would also address flaws in today’s current energy policies. For instance, the 100% RPS, as currently calculated, does not translate into Hawaii generating all its electricity from renewable sources since distributed rooftop PV is counted in the numerator (renewable generation) but not in the denominator (total electricity sales). As calculated, only electric utilities are subject to the law. The gas utility and other large commercial customers who install their own generators are not part of the picture, perhaps prompting large customers to switch to gas or defect from the grid entirely. Instead of devising an amended metric to close such loopholes,13 stronger GHG policy—a carbon tax to either complement or replace the RPS—would align statewide goals and avoid the consequences of any “leakage” across sectors.

A carbon tax could also help to make good on the goals of Hawaii’s energy efficiency portfolio standards (EEPS). In contrast to an RPS which targets the supply-side, the EEPS focuses on electricity consumption, calling for a 30% reduction by 2030, equivalent to 4,300 gigawatt hours based on a 2008 baseline forecast of electricity consumption in 2030. Measuring progress according to the design of the standard is extremely difficult without a “counterfactual”—that is, electricity consumption absent any energy efficiency savings. In addition, similar to CAFE standards in the transportation sector, some efficiency gains are offset by increased consumption (a rebound effect). There are also many individual actors, some regulated by the Public Utilities Commission, and others, unregulated. An economy-wide carbon tax would incent fossil fuel conservation by all. Note also the volumetric surcharge design to support energy efficiency programs currently presents regressive impacts.14

There’s a lot of background activity around compliance with Act 234 on the horizon with affected facilities submitting their updated emissions reductions plan and the DOH updating and developing GHG inventories and projections. As we move forward, we should consider not only working towards compliance in one year but in perpetuity. This blog post has highlighted the critical link between our broader energy goals and how climate change policy and its policy instruments can enable us to reach those objectives. Maybe Act 32 (2017), which commits Hawaii to meeting some of the principles and goals laid out in the Paris Accord, will be a way to keep us on track. But without any specifics as to how we are to achieve such reductions—through a carbon tax or otherwise—it is largely symbolic. It’s time for a comeback in energy and GHG policymaking.

- Sherilyn Wee 
UHERO Affiliated Researcher


1Though the composition of fossil fuels differs; in the U.S., natural gas and coal comprise roughly 30% each and nuclear, 20% in 2016 (EIA, 2017).

2Yet with technological advances and the discovery of new reserves, it could also be argued that the supply of fossil fuels are “nearly limitless.” In either case, without correcting for the market failure, the transition would be to slow to mitigate the impacts of climate change (Covert et al., 2016).

3For instance, the Regional Greenhouse Gas Initiative, is an electric sector cap-and-trade program between nine Northeastern States.

4See Act 73 (2010), Act 107 (2014), and Act 185 (2015).

5Emissions reduction depends on the generation source displaced and on increased consumption due to reduced prices. Murray et al. (2014) show tax credits have a small impact on GHG emissions, and in some cases, emissions increase. Palmer and Burtraw (2005) show that neither a production tax credit or an RPS leads to as high of and as cost-effective a reduction as a cap-and-trade program.

6Note low cost and renewable energy is often incorrectly regarded as synonymous; such treatment depends on context (e.g. PV versus non-PV customers) and the procurement of renewable energy sources (benefit from low-cost utility-scale renewables is shared amongst all customers). Also, if Oahu’s coal plant—the cheapest source of energy at around 3 cents/kWh—were to go offline (power purchase agreement to expire in 2022), energy costs would increase dramatically.

7See HB1464 (2009) and HB623 (2015).

8The Department of Health (DOH) is in the process of updating prior GHG inventories and developing new GHG inventories for 2015, 2016, and 2017.

9There are 6,490 EVs statewide, comprising less than 0.01% of all registered passenger vehicles as of October 2017 (DBEDT, 2017).

10Contrary to the Department of Health’s (2014) statement that “these rules will ensure that the state returns to 1990 GHG emission levels by 2020 as required under Act 234, 2007.”

11GHG emissions are a global pollutant and therefore global damages should be accounted for.

12See for example David and Knittel (2016) and Levinson (2016) on fuel economy standards.

13In the 2017 legislative session, the Department of Business Economic Development and Tourism (DBEDT) for the second time, proposed to amend the RPS calculation to correct for this error (see SB906, HB1040).

14As a per kWh charge, customers who are able to reduce or offset their energy use through energy efficiency and distributed PV pay a lower dollar amount than customers who do not have access to such technology. The expansion of distributed PV puts a greater burden on these (generally) lower-income customers.

Page: 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9