Energy & Greenhouse Gas Solutions
Mission: To provide rigorous and timely information to decision-makers and the public regarding energy and greenhouse gas related policy in Hawaii and beyond.
The Energy and Greenhouse Gas Solutions research program (EGGS) was launched in 2007 by the University of Hawai‘i Economic Research Organization (UHERO). It serves as a resource for those interested in issues of energy and greenhouse gas emissions reduction in Hawaii and beyond. EGGS takes a transdisciplinary approach to research by bringing together economists, planners, engineers and system modeling experts to address urgent issues of energy and climate change mitigation.
EGGS Core Goals
- 1. Engage in rigorous analysis that contributes to a global community of scholars.
- 2. Develop and maintain data and models on Hawai‘i’s energy, economy, and resulting greenhouse gas emissions.
- 3. Develop solution-oriented analyses for decision-makers and energy-related stakeholders.
- 4. Design interactive education and outreach programs for a variety of audiences.
- 5. Showcase Hawai‘i-based energy policy solutions that may benefit other jurisdictions, including other States, the U.S., and island areas.
- May 3, 2016 What a Difference a Rate Makes
UHERO’s Energy Planning and Policy Group has been writing about how variable pricing of electricity, both wholesale and retail, can lower the cost of intermittent renewables. Get the rates right, and facilitate easy open-access to the grid for both buyers and sellers, and amazing things can happen. The idea is that variable rates will encourage households and businesses to shift electricity demand toward intermittent supply, and facilitate creative, low-cost storage of power, all of which would enable cheaper, faster growth of renewables.
Hawaiian Electric Industries (HEI) seems to be moving in this direction. With the right incentives they might move quicker. Unfortunately, the utility has little incentive to implement variable pricing, except to please the Public Utilities Commission (PUC), since these adjustments might do for free what otherwise requires investment in batteries, new power plants and other grid upgrades. Under current regulations HEI grows its profits by maximizing investment, regardless of whether or not those investments are cost effective.
But here I’d like to focus on another rate that can make a big difference in the cost of renewable energy: the interest rate used to finance capital investment. It’s a good time to write about this little detail as the PUC, Consumer Advocate, legislators and others pour over HEI’s latest, more comprehensive revision of the Power Supply Improvement Plan, or PSIP. While there’s lots to study and think about here—all 1200 pages of it—the interest rate assumptions strike me as, well, high. And I wonder if these could be a key factor underlying some differences between HEI’s plan and our own Matthias Fripp’s plan. The plan also includes off-shore wind, which at a cost of about $4/Watt, may be an economic part of the portfolio—it will be good to incorporate this possibility into Fripp’s planning model.
Table 1. Hawaiian Electric Industries assumed cost of capital in the PSIP (p. J-4)
Capital Source Weight Rate Short Term Debt 3.0% 4.0% Long Term Debt 39% 7.0% Hybrids 0.0% 6.5% Preferred Stock 1.0% 6.5% Common Stock 57% 11.0% Composite Weighted Average 9.185% After-Tax Composite Weighted Average 8.076%
Here’s the crux: interest rates have been trending down for the last 35 years, and sit near all time lows today. And there’s little hint in market data that they’re likely to go up much soon. Yet, in the midst of these low rates, HEI’s new PSIP uses rates that were typical for utilities some 20 years ago.
HEI’s assumed cost of capital is comprised of 57% equity, for which they claim a cost of 11%, which exceeds rates that many public utility commissions complained about as early as 2004, when market interest rates were much higher than they are today. Expectations for future rates of return on equities are smaller today than they were ten or twenty years ago, and utilities tend to have lower-than-average rates of return because they are considered safe, since returns are all-but-guaranteed by the government. Rates for debt also appear roughly 20 years old. Today, typical rates on corporate “a” bonds, a conservative rating for utility investments, are less than 3 percent on average, and barely over 4% for long-term issues. HEI assumes 7% for long-term debt, which is assumed to comprise 39% of capital costs. The return rate for equity is a policy decision, but it stands to reason that rates ought to follow market rates, which have come down 3-4 percent since 10% was typical.
Clearly, higher overall interest rates would imply higher overall generation costs and higher rates for customers. But the rate also influences the cost-effectiveness of different generation mixes. For wind and solar, nearly all costs are for up-front capital. Conversely, for traditional power generation (oil, coal, natural gas and biofuels), fuel and operation costs generally comprise a larger share of cost than generating equipment. Higher rates therefore favor traditional generation.
Another more subtle consideration is that solar and wind investments have lower risk premiums than traditional fuel-based generation. The reason is that solar and wind pay a higher dividend if fuel prices spike, which is just the opposite of traditional fuel-based generation. This means solar and wind can do more to reduce risk from the larger investment portfolios of typical equity shareholders, and should therefore have a somewhat lower cost of capital.
The upshot of all this is that the high rates used in the PSIP artificially make natural gas and biofuels more attractive from a cost perspective than solar or wind, and generally cause the projected path of customer rates to be higher than they need to be. Two or three percentage points can make a really big difference, as any homeowner with a mortgage can tell you. You can also get a sense of the magnitudes by playing with our solar calculator (now mostly obsolete due to the end of net metering).
We shouldn’t blame HEI for doing what they can to negotiate rates up, for the rate on equity, and the share of capital they finance with equity, is their main channel for growing profits. HEI has a legal obligation to its shareholders to seek to maximize profits, which the new PSIP does skillfully. It’s even better for them if higher rates causes capital investments better-suited to HEI (like developing a new traditional power plant, or retrofitting an old one) to be more attractive than those best suited to a third-party provider. And making the rate for debt similarly high may help to obscure the fact that the equity rate is so high. The problem with cost-of-capital rates falling much less than market interest rates is not unique to Hawaii, although the PSIP rates still appear higher than typical.
As I’ve argued earlier, regulatory incentives could be changed such that HEI would have an incentive to find the most inexpensive and cost-appropriate capital possible and implement variable rates. This could also help HEI align its profit-oriented goals with the state’s affordable, renewable energy goals. The trick is to divorce their profits from the size of their own capital investments, and instead link profits to improvements in overall cost efficiency of the system, including distributed energy. Other states are also flirting with different incentives for utilities. Finally, build renewable energy goals directly into the cost structure by taxing fossil fuels and/or subsidizing renewables, regardless of source. This approach is one option for a “new business model” that many vaguely refer to.
Other models could work too. I gather that many see these high rates and conclude that a government municipality or cooperative, which would have considerably lower capital costs, as the answer. But it’s important to keep in mind that these alternative structures have incentive problems too. Another option would be to replace HEI with an Independent Service Operator, or ISO. I’m still learning sbout ISOs, but think the model could hold a lot of promise for Hawaii. I’ll have more on ISOs in another post.
Today’s low interest rates, combined with remarkable technological advance in renewable energy, creates what could be an amazing opportunity for Hawaii. It’s conceivable to me that we could transition toward 100% renewable faster than many currently believe. Maybe not in Dinah Washington’s 24 little hours, but soon enough. But to do it, and do it cost effectively, means getting the rates right.
- February 26, 2016 Incentives for the Utility
Perhaps the greatest obstacle to a renewable-energy future is that our utility, Hawaiian Electric Industries (HEI), has little or no incentive to transform its operation into a model more suited for renewable energy. While there has been a lot of hand-wringing and criticism of HEI for its monopoly and slow approval of distributed solar, it’s important to realize the truly unprecedented change they are being forced to undertake. And worse, the new cutting-edge system they are being asked to adopt will literally undermine its profits.
Revenue decoupling (PDF) was supposed to correct HEI’s incentives by ensuring that the utility could recover the same revenue toward its operation costs even if they generated less electricity due to growth of distributed solar or improvements in energy efficiency, both of which have factored into higher electricity prices.
Revenue decoupling does make HEI less vulnerable to improved efficiency and growth of renewable energy over the short run. But over the long run the utility profits mainly from making new capital investments. For such investments they receive a nearly guaranteed rate of return that far exceeds low-risk borrowing costs. If the utility is forced to retire its old power plants and instead buy renewable energy from independent providers—the apparent inclination of the Public Utilities Commission---its rate base and profitability decline. Thus, even under revenue decoupling, low-cost renewables do not accord with HEI’s interests.
The larger problem is that the regulatory infrastructure is not conducive to a rapidly changing energy landscape in need of innovative and perhaps distributed solutions. HEI has little incentive to control costs, much less increase renewable energy in a cost effective manner.
It doesn’t need to be this way. We can fix regulatory incentives. But given the novelty of the renewable energy system we are creating, combined with Hawai`i’s geographic uniqueness, it seems unlikely that we can simply borrow a regulatory model from the mainland. Some are calling for our private utility to be replaced by publicly-run municipality, or possibly a cooperative like the one on Kaua`i. These models might work. But it’s not clear how long it would take to transition to these systems, or whether they will bring about the most innovative solutions.
What’s the fix? First, the utility needs to have some skin in the game. Full cost recovery via rate adjustments—the current regulatory situation---gives the utility virtually no incentive to be strategic in its management and planning. Instead, if costs fall due to cost-effective development or contracting of renewables, the utility should get to keep a share of the gains. The utility’s profits ought to be tied to its cost effectiveness, not the size of the capital outlay. At the same time, if oil prices rise, then the utility should absorb a share of the cost increases, such that it cares about oil price volatility just as its customers do.
Second, to the extent that the state wishes to favor renewables over fossil fuels, fossil fuels should be explicitly taxed and renewables subsidized. Such incentives could be made roughly revenue neutral and would be more effective at achieving renewable energy goals in a cost-effective manner than the state’s expensive and seemingly pointless renewable energy tax credits. Federal credits are more-than-adequate to make distributed generation cost-effective to homeowners, even under revised rate structures. And we should allow utility-scale and distributed renewable energy generation to compete on equal footing. Instead of the tax credit, customers should be able to sell all surplus generation to the grid at appropriate real-time rates.
Of course, regulators will need to negotiate a baseline profit level, how the baseline will change over time, the share of overall cost changes born by the utility and passed on to customers, and whether the utility’s share of cost improvements ought to phase out over a number of years. Regardless of these choices, these kinds of changes in regulatory structure would align the utility’s interests with their customers as well as the state’s renewable energy goals.
The big, encouraging news is that the cost of reducing greenhouse gas emissions and slowing global warming now looks cheap. While Hawai`i’s contribution to this global problem is minimal, if we can show the world how to do renewable energy in a smart, cost-effective manner, we could be a true global leader in helping to solve it. But without smart policy, we’ll only serve the interests of denialists and naysayers who will point to Hawai`i’s renewable energy boondoggle as an excuse for inaction.
- February 25, 2016 Embrace Policy Experiments for Demand Response
*This post follows up on the previous post in the Sustainable Energy Blog Series: Four Years to Improve Renewable Energy.
HECO has recently proposed new time-of-use rates and is developing pricing for various kinds of demand response programs. The proposed programs are a long ways from the open-access, marginal-cost pricing, but they are a big step in the right direction.
Table 1. Proposed Time-of-Use Rates in Hawai`i (cents per kilowatt-hour)
9am – 4pm
4pm – 12am
12am – 9am
Hawaiian Electric (Oahu) 11.0413 36.1997 13.6755 Hawai`i Electric Light (Big Island) 15.7148 46.3867 17.8685 Maui Div. of Maui Electric 23.8116 45.7002 26.8383 Lanai Div. of Maui Electric 36.6396 52.3616 35.7913 Molokai Div. of Maui Electric 36.6396 52.8520 29.6548
The new time-of-use rates embody high-powered incentives for shifting loads to different times of the day (Table 1). Depending on an individual household’s use profile, many should be able to reduce their bills even if they don’t change the way they use electricity. Alternatively, some households might be tempted to install batteries, charging with solar or cheaper electricity during the daytime and discharging during nighttime peaks. Such strategies should be economical given these price differentials.
Unfortunately, these rates only apply to residential customers, which is a small share of the load (about 27%). To maximize load shifting potential and make use of real time meters already in place, we should quickly introduce variable prices for commercial-scale customers.
While time-of-use pricing is a step forward, the proposed time-of-use prices, despite their apparent 4-digit precision, do not reflect the true incremental cost of electricity. The true cost can vary significantly across hours in each block in the table of proposed rates, and across different days and seasons of the year. Expensive peak loads, for example, fall off sharply by 9pm, but peak-load pricing extends until midnight. Also, the difference between peak pricing and midday pricing far exceeds the current cost of serving these loads. Values are likely to change rapidly as the generation mix shifts increasingly toward renewables, so it appears that proposed prices anticipate future changes in generation. While the incentives are strong enough to kick-start demand response programs, it’s hard for customers to know how the rate structures will change over time. The uncertainty could discourage entrepreneurs looking to Hawai`i as a place to test their demand response technologies.
Over time, variable pricing could be improved in a number of ways. First, it is important to make the price-setting mechanism clear and transparent, so that customers and entrepreneurs developing smart devices can reasonably anticipate how prices will change going forward. The guiding mechanism should link to the overall system’s marginal cost of electricity. Second, customers should be given more choices. Some may prefer time-of-use pricing with the proposed simple three-block structure; others might embrace full-fledged real time pricing; others may prefer something in-between. As long as rates reflect typical costs in each block, customers will be free to choose a level of flexibility they are comfortable with.
How much will the new rates shift loads away from the peak and toward midday and early morning? The reality is that it’s very hard to know. In fact, it will still be difficult to know even after new rates have been implemented. Many households could probably select time-of-use pricing and save money without shifting loads at all. We won’t be able to tell whether they always tended to use electricity during the low-cost times or changed behavior as a result of time-of-use pricing. To know, it is important to observe real-time electricity use before and after the rate change. And we would further need to rule out the possibility that other factors besides the rate change were affecting use.
To accurately measure how much demand-response bang for the time-of-use buck the system is getting from variable rates, or any other change in policy, we need to run actual experiments. The idea is to offer up different pricing menus to different households and businesses for a trial run of a year or two. The pricing menus would need to be randomly assigned across customers, in part for fairness, but also to ensure that observed changes are not a reflection of selection bias. Some households might obtain opportunities to install smart devices that aid automatic shifting of loads. Some randomly selected customers would be reserved as controls, without the opportunity to choose a variable pricing contract. Such experiments could measure the actual and potential demand response much more precisely than simply changing policy for everyone all at once.
Of course, the public would need to be let in on the whole policy experiment. And it would further help to have some guidelines for how policy will evolve based on the outcomes of the experiments. There are a number of successful examples of such experiments, some of which show great potential for curbing peak loads, and customers that are happy participating in the program. While we can learn from policy experiments elsewhere, the load shifting needed in Hawai`i is different and more substantial. We need our own, thoughtfully-designed experiments to learn the true potential for demand response.
- February 24, 2016 Four Years to Improve Renewable Energy
Without the debt-ceiling hijinks of earlier years, the federal budget bill passed at the end of last year with a lot less drama and press coverage. But little news turned out to be good news, at least for Hawai`i and renewable energy interests. The spending bill included an extension of the 30% tax credit for renewable energy that otherwise would have expired at the end of 2016. Under the new legislation, the tax credit will remain at 30% through the end of 2019, then step down gradually through 2021, and remain at 10% thereafter. The subsidy is especially valuable to Hawai`i because, under the State’s renewable portfolio standard, we will be ramping up renewable energy investments with or without it. That means free federal money for Hawai`i, potentially a whole lot of it, compliments of the other 49 states.
The extended subsidy, falling costs of renewable energy, plus an historic Paris Agreement, signed last month by all United Nations countries, gives great global momentum to renewable energy. A renewable-energy future now looks all too plausible, and there’s a chance it could happen fast. Even without subsidies, solar PV and wind are already competitive with coal and natural gas in the generation of electricity, and costs continue to fall. By the time federal subsidies bottom out, it appears likely that renewable energy will handily beat fossil fuels on a levelized-cost basis, not just in Hawai`i, but everywhere. Storage costs, the critical challenge for renewables, are also falling, and could fall much further as production scale increases for both electric cars and grid applications.
Renewable energy indirectly gained further momentum on the mainland from a Supreme Court ruling that upheld a rule by the Federal Energy Regulatory Commission (FERC) that forces grid operators to reward demand response at the same rates as incremental generation. The ruling should open up new markets for demand response, which in turn should improve the system-level cost effectiveness of variable and intermittent renewables. Although the ruling has no direct bearing on Hawai`i, the nascent industry of demand response systems could be helpful to our state and its renewable energy goals.
So, how can Hawai`i make the most of the situation? Part of the answer involves maximizing the benefits of extended federal subsidies, which probably means getting more renewables onto the grid sooner than later.
And part of the answer involves fully exploiting our leadership in renewable energy. Due to the high cost of imported oil and our old infrastructure, renewable energy is more economically viable here than in most places. At the same time, our isolated island economy makes the intermittency problem especially acute. But if we can do renewable energy right—which means efficiently dealing with intermittency challenges of solar and wind—it could bring economic opportunities to the State that far exceed any direct benefits from subsidies, lower dependence on imported, oil or even lower electricity bills.
The greater opportunity is that Hawai`i could become an innovation hub for new smart devices, batteries, thermal storage and perhaps other technologies that can aid demand response and can help solve intermittency challenges. Entrepreneurs should be anxious to test their new technologies in the place where they will be economical first. If new technologies are proven here, in subsequent years they will likely find much larger markets in California, other mainland states, Japan and the rest the world.
To some degree this kind of thing is already happening, but the potential is far greater. If Hawai`i can attract this kind of investment, it will bring high-skilled and high-paying jobs, along with the broader social and economic rewards that typically accompany them.
Open-Access Variable Pricing
The key to making all this happen boils down to better pricing and easy, open access to the grid. A few months ago UHERO’s Energy Policy and Planning Group argued that we should work toward a system in which anyone can buy or sell at the incremental cost of electricity generation, which varies a lot over seasons, hours of the day, and certain events, like unexpected power plant failures. While the FERC ruling does not force Hawai`i to price demand response as it does generation, we should nonetheless figure out a way to embrace the spirit of that ruling, and more.
Open-access variable pricing allows anyone to buy low and sell high, and thereby make a profit while helping to solve intermittency challenges, effectively rescheduling electricity use toward intermittent supply. Everyone benefits, whether they participate in variable pricing or not, since it lowers the overall cost of the system. Open-access variable pricing might improve efficiency a little today, but its benefits will grow much more with greater wind and PV solar penetration.
This vision stands in stark contrast to our current system in which a centralized utility adjusts supply to match time-varying demand. Demand response embraces the idea that balancing supply and demand need not be a one-sided proposition. A lot of electricity is used to heat water, pump water from aquifers and up hills to storage tanks. Perhaps as much as 40 percent of the load is used for air conditioning. All of these demand sources, and perhaps many others, could employ any number of technologies to shift electricity demand toward supply of renewables. These technologies, like smart, price forecasting water heaters, variable speed pumps and ice storage, could be automated to respond to price changes, saving money for hotels, the water utility, the military, and other large electricity customers. Such systems might even be used to stabilize short-run fluctuations in the grid, exacerbated by passing clouds and variable winds.
Savvy residential consumers might strategically time clothes washing, water heating, electric car charging and air conditioning, to save a few bucks or enjoy a cooler, more comfortable living situation when renewable energy is plentiful and prices are low. Or, more likely, engineers could build smart controllers for these machines such that they automatically run at opportune times. While this kind of residential demand response is not where the largest opportunities lie, the benefits could add up. The problem today is that, without real marginal-cost pricing for either buyers or sellers of electricity, there’s no incentive to create smart, price-forecasting controllers for appliances.
A greater potential for load shifting may lie with large-scale uses. Well over two thirds of electricity consumption on Oahu comes from commercial and industrial class customers. These large-scale users have a real stake in lowering energy cost and many already have real-time meters. It’s easy to imagine that 20-30 percent of our load might be shiftable to different times of the day. The savings could amount to the difference in cost between a 100 percent renewable systems and our conventional fossil-fuel based system.
Regardless of the potential savings, focusing on demand response first is the least-cost way to help balance a grid with a growing share of variable renewable supply. The longer we can put off investments in storage capacity, the less expensive those investments will be. And the pricing policies needed to entice demand response will provide a larger framework for optimally managing storage and the grid of the future.
Together with Matthias Fripp, Makena Coffman, and graduate students in UHERO’s Energy Policy & Planning Group, we are working to develop ballpark estimates of the potential savings. First-cut estimates indicate overall cost savings of roughly 20 percent if 30 percent of the load in each hour can be shifted to other times of the day. Looking forward, we hope to pin down more concrete estimates of shiftable loads at different times of day, season and weather-related circumstances.
I will follow this post with two more over the next couple days, one that discusses recently proposed time-of-use rates and ways they could be improved, and another discussing how we need to change incentives for our utility, Hawaiian Electric Industries, such that they better align with state goals.
- January 4, 2016 A Status Update on Federal GHG Emissions Reduction Policy for Hawaii
In early August, President Obama announced and the U.S. Environmental Protection Agency (EPA) released the final details for the Clean Power Plan (CPP). These rules are designed to lower levels of carbon pollution from existing U.S. power plants – aiming to curb U.S. electric sector emissions by 32% from 2005 levels by 2030 (EPA, 2015a). The CPP is an important first step in making good on the U.S.’s global commitment to reduce economy-wide greenhouse gas emissions by at least 26% below 2005 levels by the year 2025*.
Under the CPP, states have been given the choice of meeting either a rate- or mass-based goal for their existing fleet of power plants. In the draft version of the CPP, Hawaii was given a goal of reducing its emissions rate to 1,306 pounds of CO2 per MWh by 2030 (Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 2014). This target included energy efficiency gains and, given Hawaii’s Renewable Portfolio Standard goal of 100% renewable sources for net electricity sales by 2045 (and 40% by 2030), the CPP target was almost certainly achievable. Our modeling of Hawaii’s electric sector suggests that it was cost-effective to go beyond this draft target, even without factoring in energy efficiency.
Yet, Hawaii is not included in the last version of the CPP. Between the draft and final, the EPA based its decision on a continental grid-based modeling approach (EPA, 2015b). As such, non-contiguous regions are currently left without regulation. The EPA states that further regulations will be developed, though no timeline for completion has been given (EPA, 2015b). In addition, Hawaii is excluded from generating potentially valuable emission rate credits (ERCs), even if a target is determined in the future. The CPP regulations state that the “resources must be connected to, and deliver energy to or save electricity on, the electric grid in the contiguous United States.” This regulation unnecessarily excludes Hawaii (and Alaska and Puerto Rico) for geographic reasons, when economic markets do not have to be geographically bound.
One of the ways that the federal programs will regulate GHGs is to limit future coal-fired power. The New Source Performance Standards (NSPS) for the construction and operation of new power plants will effectively prohibit new coal units (without carbon capture) from coming online in the U.S., including Hawaii (Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Units, 2014). This of course is a positive outcome in terms of limiting future emissions and most relevant to coal-intensive states. In Hawaii, limiting new coal is something that the Hawaiian Electric Companies voluntarily agreed to in 2008. The NSPS makes this official**.
In sum, the EPA’s recent actions toward GHG emissions is important at the national scale but will have limited to no impact on Hawaii.
*This commitment was made in 2014 between President Obama and China’s President Xi Jinping, representing the world’s two largest GHG polluters. China committed to peaking its carbon emissions around the year 2030 and to increase the share of non-fossil fuel energy consumption to about 20% by 2030 (Office of the Press Secretary, 2014).
**Oil-burning units in Hawaii are excluded from regulation under the NSPS (Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Units, 2014).
Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 78 Fed. Reg. 34830 (proposed June 18, 2014) (to be codified at 40 C.F.R pt. 60). Available here
Office of the Press Secretary, 2014. Fact Sheet: U.S.-China Joint Announcement on Climate Change and Clean Energy Cooperation. Available here
Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Units, 70 Fed. Reg. 1430 (proposed January 8, 2014) (to be codified at 40 C.F.R pts. 60, 70, 71, and 98). Available here
U.S. Environmental Protection Agency (EPA), 2015a. Fact Sheet: Clean Power Plan Overview.
U.S. Environmental Protection Agency (EPA), 2015b. Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Final Rule. Available here