Policies for Clean 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. Some states have made progress on these issues and have seen the benefits; others still have a ways to go. 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 CHP 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.
While most states have adopted standardized interconnection rules over the past decade, 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.
Southwest Region Status: Colorado, New Mexico, and now Utah have statewide interconnection standards. Arizona and Wyoming are two of 13 states across the nation that do not yet have streamlined, statewide interconnection standards.
Customers with CHP systems usually require standby 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. The utility's concern is that the facility will require power at a time when electricity is scarce or at a premium cost, and that it must be prepared to serve energy loads during such extreme conditions. Nevertheless, the probability that all interconnected CHP systems will need power at the same time is relatively low. Consequently, states are exploring alternatives to standby rates that may more accurately reflect realistic system operating conditions.
Options and Examples from Other States:
The Oregon Public Utilities Commission requires CHP systems in Portland General Electric's and Pacificorp's territory to contract for a backup of only seven percent of the CHP system'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. CHP 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.
The California Public Utilities Commission exempted new onsite generation from standby rates for 10 years, as policy means to encourage CHP. The exemptions applied to all CHP except those fueled by diesel and those over five megawatts.
Connecticut does not allow standby rates for CHP installed after January 1, 2006 as long as the CHP system’s generation is less than the customer’s peak load, and is available during peak periods.
Output-based Emissions Regulations
Output-based air emission standards encourage efficiency and pollution prevention as a way to meet air quality goals.
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. In-put-based regulations can unintentionally create 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.
Recently, air regulators have begun to make the switch from input-based to output-based regulations, 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.
Southwest Region Status: All of the states and local air quality districts in the southwest region still use input-based regulations. The U.S. DOE Southwest CHP Technical Assistance Partnership is available to assist states and air districts in evaluating output-based emissions, explaining the benefits, and helping advise a transition.
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)
Inclusion in Portfolio Standards
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.
Waste Heat to Power (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 emissions. Furthermore, it adds a way for industrial facilities to participate (and even profit from) renewable portfolio standards.
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.
Southwest Region Status: Arizona's RPS includes renewable-fueled CHP but does not include waste heat to power. Arizona's EERS, does include CHP. Colorado's RPS does include waste heat to power; Colorado does not yet have an EERS. New Mexico's RPS is unclear as to whether waste heat to power qualifies. Utah only has a renewable portfolio goal, not a mandatory standard, but it does include waste heat to power as an eligible resource. Wyoming has neither an RPS nor an EERS.
Inclusion in Demand Side Management
As an efficiency technology, CHP 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, an industrial process improvement, or other traditional end-use efficiency measures. However, CHP is often overlooked in DSM programs or ineligible for custom incentives. The U.S. DOE Southwest CHP Technical Assistance Partnership is available to provide information on how other states and utilities calculate the energy savings from CHP. 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
Decoupling Utility Revenues from Throughput
Electric rate structures can have significant impact on the economics of CHP projects. The most common current U.S. rate structure links utility revenues and returns to the number of kilowatt-hours sold, and this leads to an unintended disincentive for utilities to encourage customer-owned CHP and other forms of onsite generation. "Decoupling" (or separating) a utility’s revenue from the amount of energy it sells changes this disincentive. Decoupling can be combined with a sliding scale or range of earnings potential that rewards increasing efficiency. Decoupling is a policy not specific to CHP, but one that would nevertheless help encourage it.
Tax policies can significantly affect the economics of investing in new CHP systems. 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, bottoming cycle CHP 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.
See below for further resources on other policies not discussed above.
Clean Energy Standard Offer Program:
Revising Private Wires Laws: