Policies to Support Recycled Energy
We work with state and local policymakers, regulators, and local
partners to identify and evaluate policy changes that encourage the
efficient production and use of energy - including energy recycling,
combined heat and power, waste energy recovery, and district energy.
Modernizing key energy-related policies will pave the way for new clean
energy projects. To realize its full potential, the barriers to recycled
energy need to be examined by the Public Utilities Commissions in the
intermountain states. A few of the most important issues to address are
as follows:
Standardized interconnection rules provide clear and uniform processes and technical requirements for safely connecting recycled energy to the electric utility grid.
A streamlined process reduces uncertainty, prevents delays, and ensures that the requirements are appropriate for the size, scope, and technology of the system. Standardized rules also assure that the project interconnection meets the safety and reliability needs of both the energy end-user and the utility.
The U.S. has seen enormous progress in the adoption of standardized interconnection rules over the past decade, but a few states have yet to enact standards. Others are in need of updating to match current best practices.
The most effective interconnection rules are those that have:
Note that interconnection standards based on net-metered systems are insufficient for recycled energy, because net metering rules are usually limited to only very small systems.
Intermountain Region Status: Colorado, New Mexico, and now Utah have statewide interconnection standards. Arizona and Wyoming are two of only 13 states across the nation that still do not have streamlined, statewide interconnection standards.
Further Resources:
In our current utility regulatory system, designed decades ago, most utilities face a variety of disincentives to connect small, local generation to the electric grid.
A Clean Energy Standard Offer Program (CESOP) changes this by allowing utilities to obtain recycled energy at a discount to new conventional plants. CESOP involves two steps:
- First, utilities and regulators determine the actual cost of developing new conventional generation - and the wires to deliver the power to users. This will establish what new power would cost without a CESOP program.
- Second, utilities then offer long-term contracts to any energy plant that can deliver new clean power for 15% less money. Eligible generation would include all generation that at least doubles today's delivered fossil efficiency per unit of useful output (or be from non-carbon emitting sources such as renewables). Time-of-use pricing should be included in the contracts, to encourage clean generation that follows the demand for power, instead of randomly encouraging off-peak generation.
A CESOP would encourage entrepreneurs to recycle presently wasted energy for a profit, thus strengthening our industrial sector. It would enable utilities to maintain their customer base and profits. And, it would provide consumers with more clean heat and power at a discount. This policy succeeds by making sure that all stakeholders see benefits.
Although this would best be enacted at a national level, state-level policies are important in the mean time.
Intermountain Region Status: There are no CESOPs in our region yet. Instead, local generators are usually paid the utility's "avoided cost" - the marginal cost of an existing conventional power plant's fuel, operation, and maintenance costs - but these do not include the cost of delivery. This 1978 PURPA-era policy presents disadvantages and barriers to recycled energy.
Further Resources:
Customers with recycled energy systems usually require standby/backup service from the utility to provide power when planned (e.g., routine maintenance) or unplanned outages occur. Electric utilities incur certain costs to keep sufficient generation, transmission, and distribution resources in reserve to supply power during these outages, just as they do for their own resources.
These charges are often a point of contention between the utility and the consumer who is considering a recycled energy installation, and without proper consideration of all benefits and costs can create unintended and burdensome barriers to recycled energy.
Some states have exempted new onsite generation from standby rates as policy means to encourage clean heat and power. Others are taking a close look at standby rates to ensure they reflect more realistic operating conditions and don't place undue burdens on local generators. Yet others are requiring standby rates to be similar to the backup amounts and charges that utilities themselves incur for their own resources.
To ensure that standby rates are fair and non-discriminatory, here are several elements of standby rates that Public Utility Commissions could consider:
- Examine if the current standby rates in place for regulated utilities accurately reflect the actual cost of providing standby power rather than simply a theoretical cost. Most existing standby rates are based on the cost of a local recycled energy system having an unplanned outage and needing full power during the utility's peak times, when electricity is scarce or at a premium cost. However, commissions may wish to assess the statistical probability of a recycled energy system going down at peak times, and furthermore the statistical probability of all interconnected systems incurring an outage at the same time during peak times, and reflect that statistical likelihood in the rates that recycled energy owners are charged.
- Investigate if a full 100 percent of the power on standby for all interconnected recycled energy systems is actually available and unused for any other purpose (including for general reserve requirements) at all times, since that is typically what the recycled energy owners are being charged for. If it is not completely set aside for recycled energy only, then recycled energy owners should not be charged as if it is.
- Consider how recycled energy systems are similar to or different from normal load variability within a customer class, and how that affects rates that recycled energy users and regular customers are charged. If a manufacturing facility, for instance, installs a new process or production line that occasionally consumes additional energy, the utility is compensated for providing that additional energy through the facility’s higher demand rates and energy charges. Recycled energy systems that provide only a limited portion of a customers’ total load would in effect appear to a utility as similar load variation, and yet, those customers typically pay not only high demand charges for months when the generator goes down but also standby charges all year long.
- Ensure that the per-kWh energy rate for standby customers is not higher that charged to the rest of the normal rate class, as it is in some other parts of the country.
- Investigate if the costs charged take into account the system benefits that recycled energy creates for utilities, which at times are in excess to its costs.
- Ensure that no standby charges are levied for plant shutdowns caused by events on the utility side of the meter.
Options and Examples from Other States:
- The California Public Utilities Commission exempted new onsite generation from standby rates for 10 years, as policy means to encourage recycled energy. The exemptions applied to all recycled energy except those fueled by diesel and those over five megawatts.
- The Oregon Public Utilities Commission requires recycled energy systems in Portland General Electric's and Pacificorp's territory to contract for a backup of only seven percent of the recycled energy's "reserve capacity" (not 100%), the same reserve requirement for regular power plants. The "reserve capacity" is either the nameplate capacity of the installed system or the amount of load the customer does not want to lose in case of an unscheduled outage; if the customer is able to shed load at the time its unit goes down, then it will be able to reduce the amount of contingency reserves it must carry.
- The Hawaii PUC issued an order in 2008 making standby rates optional for 10 years. Recycled energy owners have the option to take standby service or to decline such service and to remain on the otherwise applicable rate schedule. Furthermore, if customers have an unscheduled outage, they have the option to waive their demand charges for billing purposes once a year. There is no ratchet in place.
- Connecticut does not allow standby rates for recycled energy installed after January 1, 2006 as long as the recycled energy generation is less than the customer’s peak load, and is available during peak periods.
Further Resources:
- Standby Rates for Customer-Sited Resources (Regulatory Assistance Project, ICF International, and EPA CHP Partnership; PDF, 37 pgs)
- Rate Structures for Customers with Onsite Generation: Practice and Innovation (Synapse Energy Economics and Regulatory Assistance Project for the National Renewable Energy Lab, PDF, 83 pgs)
- Utility Rates Fact Sheet (EPA CHP Partnership, HTML)
- Standby Rates for Customer-Sited Resources (EPA, PDF, 37pgs)
- Are Standby Rates Justified? (Electricity Journal, PDF, 5 pgs)
- The Legal Case Against Standby Rates (Electricity Journal, PDF, 10 pgs)
Output-based air emission standards encourage efficiency and pollution prevention as a way to meet air quality goals. With output-based regulations, efficiency is rewarded and inefficiency is penalized.
Even though output-based regulations have been used for regulating many industries, input-based regulations have traditionally been used for boilers and power generation sources. This creates a penalty for clean and efficient generation. Input-based regulations set air pollution limits based on how much fuel is put into a generating unit, rather than how much energy is produced. With input-based regulations, the more fuel a plant burns, the easier it is to meet the standards-thereby discouraging efficiency. Input-based regulations must be changed to output-based regulations.
Recently, regulators have begun to make the switch, as a way to promote pollution prevention, energy efficiency, flexibility, and innovation-while meeting the same air quality standards as before. Connecticut, Indiana, and Massachusetts are some of the states with output-based regulations.
By including energy efficiency and pollution prevention in air quality standards, clean energy technologies such as CHP, waste heat recovery, and district energy are not unintentionally blocked or penalized.
Intermountain Region Status: All of the states and local air quality districts in the Intermountain region still use the old system of input-based regulations. The U.S. DOE Intermountain Clean Energy Application Center is available to work directly with states and air districts to help evaluate output-based emissions, explain the benefits, and help advise a transition.
Further Resources:
- Output-Based Regulations: A Handbook for Regulators (EPA, PDF, 86 pgs)
- Output-Based Environmental Regulations Fact Sheet (EPA, PDF, 4 pgs)
- Output-Based Emission Standards: Advancing Innovative Energy Technologies (Northeast-Midwest Institute, PDF, 68 pgs)
- Clean Energy-Environment Guide to Action: Policies, Best Practices, and Action Steps for States (Section 5.3) (EPA, PDF, 410 pgs)
Similar to air quality regulations for SOx, NOx, and particulates (see above), output-based allocations can be used in climate change regulations. In a cap-and-trade framework, they can be a simpler, fairer, and cheaper method of allocating CO2 allowances than other proposed methods (including lump-sum grandfathering, sector-based allocations, auctioning, carbon taxes, or picking technology winners).
Allocating based on past emissions can have undesirable consequences, because it rewards the least efficient plants and prevents new, highly-efficient plants from competing fairly. Allocating sector-by-sector can also have less-than-optimal consequences, because of the subjectivity and preferential treatment for certain industries over others, regardless of their efficiencies or emissions.
Here's how output-based allowance work. First, give all electric and thermal energy producers a set of initial allowances based on the prior year's national average output of CO2 emissions (per MWh per Btu). Second, require electric and thermal energy producers to acquire allowances equal to their CO2 emissions (i.e. to make up any difference between the national average and what it actually produces). Then, ramp down the amount of allowances over time.
With this approach, electricity consumers won't see an increase in the average cost of electricity, since the cost of companies purchasing allowances will equal the revenue to companies selling the allowances. In other words, this policy is fiscally neutral - high carbon emitters pay low-carbon emitters.
All allowances, whether from new or old generators, should be based on a common baseline – the output of useful energy.
Further Resources:
The majority of U.S. states have enacted a renewable portfolio standard or renewable energy standard (RPS or RES), specifying the amount of electricity that must come from renewable sources. Almost half of the states have enacted an energy efficiency resource standard (EERS), requiring a percentage reduction in energy use from energy efficiency measures. However, in their first iterations, many of these standards neglected to include recycled energy. In most cases, this was simply due to an oversight; policymakers lacked awareness and education on the renewable and efficiency benefits of waste heat recovery and CHP respectively.
Waste heat recovery (electricity generated from industrial waste heat or pressure) is considered by some states to be a renewable energy (and is recognized as such in renewable portfolio standards). Similar to other renewables, it uses no additional fuel and creates no additional greenhouse gasses or other pollutants. And, to boot, it uses energy presently being thrown away. In addition to strengthening the goals of RPSs and the means of meeting them, it adds support from a state's industrial sector by giving those businesses a way to profitably participate. States that have not yet included waste heat recovery in their RPS may wish to consider doing so, and states without an RPS at all should consider how waste heat recovery makes an RPS economically advantageous to the state.
Combined heat and power is fundamentally an energy efficiency measure. States that have not specifically included CHP in their EERS may see beneficial results from adding it, since it is more efficient than separate heat and power generation.
Intermountain Region Status: Arizona's RPS includes renewable-fueled CHP but does not include waste heat recovery. Arizona's EERS, however, does include CHP, but the mechanism for calculating it is still being worked out. Colorado's RPS does include waste heat recovery, and Colorado does not yet have an EERS. New Mexico's RPS is vague and unclear as to whether waste energy recovery qualifies. Utah only has a renewable portfolio goal, not a mandatory standard, but it does include waste energy recovery as an eligible resource. Wyoming has neither an RPS nor an EERS, despite a large potential quantity of industrial waste heat that could be profitably recovered with the right policies in place, potentially offering significant benefits to Wyoming's industrial sector.
Further Resources:
As an efficiency technology, recycled energy lowers demand on the electricity delivery system, frequently reduces reliance on traditional energy supplies, makes businesses more competitive by lowering their costs, reduces greenhouse gas and criteria pollutant emissions, and refocuses infrastructure investments towards a next-generation energy system. (Read more about these benefits here.)
These benefits correspond with many of the same reasons state pursue demand-side management (DSM).
The net energy savings from CHP (once the additional fuel input is netted out) are akin to the energy savings from a lighting project, a motor upgrade, or an industrial process improvement. However, recycled energy is often overlooked in DSM programs or eligible for custom incentives. If recycled energy passes applicable resource cost tests, it could be considered as an eligible DSM measure alongside traditional end-use efficiency measures. The U.S. DOE Intermountain Clean Energy Application Center is available to provide information on how other states and utilities calculate the energy savings from recycled energy. Although CHP systems consume additional fuel onsite, less fuel is burned at the utility power plant to supply that same load, and less total electrical and thermal losses occur. Waste heat recovery systems use no extra fuel and thus represent 100% energy savings
Options and Examples of CHP in Utility Efficiency Programs in Other States
Further Resources:
Recycled energy is an important energy resource that can be incorporated into least-cost planning activities that seek to minimize ratepayer-funded investments in system load growth.
Including recycled energy in integrated resource plans can be either through rate-based systems or through encouragement of privately-funded customer-sited resources.
As recycled energy deployment becomes statistically significant (proven firm and reliable for an agreed upon number of years), then integrated resource plans need to incorporate these amounts of recycled energy and subtract them from planned utility resource adequacy capacity additions.
CHP and other forms of energy recycling are usually overlooked in the resource planning process. While a few states and utility regulatory commissions require a consideration of customer-sited CHP and other forms of energy recycling, most do not.
Options and Examples of Recycled Energy in Integrated Resource Planning Processes
- Oregon's IRP guidelines require the evaluation of distributed generation technologies "on par with other supply-side resources," and should consider the benefits of DG.
- In Connecticut, the state's general statutes require CHP to be included in the state's energy and capacity resource assessment. Procurement plans must consider the “extent to which generation needs can be met by renewable and combined heat and power facilities.” (See here and here.)
- California utilities must prepare long-term procurement plans with a specific Distributed Generation (DG) forecast. Investor-owned utilities must also evaluate DG as an alternative to distribution system upgrades.
- Georgia, Iowa, Indiana, Kentucky, Nebraska, New Mexico, and Nevada also require consideration of CHP integrated resource planning.
An industrial plant that generates excess heat usually has to throw most of that heat away. It is typically not allowed to sell electricity made from that heat to a neighboring plant across the street. A company with operations on both sides of a public street is often not even allowed to deliver power from a CHP system on one side of the street to its operations on the other. The law typically allows the piping of hot water, chilled water, or steam across the street, but not electricity. The industrial plant, in that case, can only sell the electricity back to the utility grid, at the utility’s "avoided cost."
An alternative approach is that recently adopted in New Jersey, which allows sales from CHP to adjacent and across-the-street properties. (This is similar to the Federal Energy Regulatory Commission's current regulation of natural gas transmission, which allows gas users to apply for a tap on an interstate gas pipeline and construct a private pipe crossing public streets.) Alternately, another approach is that of Alberta, Canada, which allows any generator to sell power to any customer anywhere in the province subject to a standard grid "wheeling" charge-as long as the charge is based on distance.
Further Resources:
Electric rate structures can have significant impact on the economics of recycled energy projects. The most common current U.S. rate structure links utility revenues and returns to the number of kilowatt-hours sold, and this is a large disincentive for utilities to encourage customer-owned recycled energy and other forms of onsite generation. “Decoupling” (or separating) a utility’s revenue from the amount of energy it sells would help fix this incentive problem. Decoupling could be combined with a sliding scale or range of earnings potential that rewards increasing efficiency. Decoupling is a policy not specific to recycled energy, but one that would nevertheless help encourage it.
Further Resources:
Tax policies can significantly affect the economics of investing in new recycled energy equipment such as CHP. CHP systems do not fall into a specific tax depreciation category, and their depreciation periods can range from 5 to 39 years. These disparate depreciation policies may discourage CHP project ownership arrangements, increasing the difficulty of raising capital and discouraging development.
In another important tax issue, recycled energy systems that convert waste heat to power do not qualify for tax incentives that other renewable and clean energy technologies do. Adding these waste-heat-to-power systems to list of eligible systems would encourage more installations.
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