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*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.
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.
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
Circuits with installed PV up to and greater than 250% of daytime minimum load. Source: HECO
Hawaii leads the nation with the highest per capita installation of solar photovoltaic (PV). High electricity rates—three times the national average, —a generous state tax credit, plummeting PV costs, and net energy metering (NEM) policy have all contributed to the proliferation of PV. Considering future cost savings, PV is an attractive investment, yielding an internal rate of return of 23% with the state tax credit, equivalent to a payback period of four years (Coffman et al., 2016). In a recent analysis I answer the question of how PV is capitalized into a home’s value.
Using econometric tools, I assess the impact of PV systems on home value for single-family resale homes on Oahu. Using home resale and PV building permit data from 2000-2013, I find that PV adds on average 5.4% to the value of a home. This translates to approximately $34,000 relative to the sales price of the median non-PV home of $630,000.
This means that PV already installed on a home is worth about $4,000 more than the median value of a PV permit (approximately $30,000). While this may appear puzzling at first, issues of circuit saturation may well-explain this result. Calculating the stream of electricity savings* over 9 years (the average household tenure) and a typical 30-year mortgage respectively, reveals that a homebuyer is effectively paying $4,000 more for a PV home to receive between $14,000- 30,000 in electricity savings. This makes sense given many of the circuits in Hawaii have reached legal limits for PV installations and therefore new homebuyers have an expectation that future installations will be limited. Thus for many the choice isn’t purchasing a house without PV (and then installing it) but rather to gain access to PV (and future electricity savings).
An area of further inquiry in light of the recent PUC ruling is to extend the dataset to examine whether homes that are grandfathered under the NEM program are worth more.
Coffman, M., Wee, S., Bonham, C., and Salim, G. (2016). “A Policy Analysis of Hawaii’s Solar Tax Credit Incentive.” Renewable Energy, 85, 1036-1043.
In Hawaii, like most U.S. states, households installing rooftop solar photovoltaic (PV) systems receive special pricing under net-metering agreements. These agreements allow households with rooftop solar to buy and sell electricity at the retail rate, effectively using the larger grid to store surplus generation from their panels during sunny times and use it when
the sun isn’t shining. If a household generates more electricity than it consumes over the course of a
month, it obtains a credit that rolls over for use in future months. Net generation supplied to the grid in excess of that consumed over the course of a full year is forfeited to the utility. Net metering agreements often include
a monthly fee to support billing, transmission and operation of the grid.
A growing concern is that the utility has many costs besides the fuel used in electricity generation, and most of these “fixed costs” are lumped in with per- kilowatt hour (kWh) charges. As a result, under current net metering agreements, when a solar customer provides their own power, they don’t pay the fixed- cost component for each kWh they produce. Under a revenue-decoupling rule, those costs are shifted to households and businesses without rooftop solar. As less power is sold in Hawaii, fixed costs per kWh are rising fast. Most of the decrease in power sales is due to gains in efficiency, but some of it is due to installations of solar PV. Residential customers now pay roughly $0.17/kWh for fixed costs. After the drop in oil prices earlier this year, well over half the utility’s revenue from residential customers goes toward fixed costs.
The graph shows the average residential electricity price from 2000 to the present, and breaks out the generation component from the total (Adjusted ECAF). The difference between price and the Adjusted ECAF (Gap) accounts for all non-fuel or fixed costs.
A longer-term concern, particularly in Hawaii with its high electricity rates, is that an inefficient pricing system could encourage many households and businesses to install stand-alone systems, unplug from the grid, and further raise costs for everyone else.
In a new report UHERO's Energy Policy & Planning Group summarizes the benefits and challenges with distributed solar and sketch out a set of long-term solutions based on marginal-cost pricing as the primary platform. Marginal cost is the incremental cost of power production—the cost of generating one more kWh. This cost can vary a lot depending on total demand and the amount of renewable power, among other things, so ideal prices would vary over the course of each day, week, season and year. This is likely to become especially pronounced as the variable supply from renewable sources becomes more prominent.