policy and incentives

Standardized interconnection rules provide clear and uniform processes and technical requirements for safely connecting clean 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 reasonable standards—or any at all. Others are in need of updating to match current best practices.

Top-rated interconnection rules are those that have:

Procedures and technical requirements based on model standards such as those from the Federal Energy Regulatory Commission (FERC), Interstate Renewable Energy Council (IREC), or the National Association of Regulatory Utility Commissioners (NARUC).

• http://www.ferc.gov/industries/electric/indus-act/gi.asp
• http://irecusa.org/wp-content/uploads/2010/01/IREC-Interconnection-Procedures-2010final.pdf
• http://www.naruc.org/Publications/dgiaip_oct03.pdf

1. Standard interconnection forms
2. A timeline for application approval
3. Simplified procedure for smaller systems (25 kW or less)
4. Limited additional insurance requirements, if any
5. Technical requirements based on IEEE 1547 (Standard for Interconnecting Distributed Resources with Electric Power Systems)
   http://grouper.ieee.org/groups/scc21/1547/1547_index.html

Note that interconnection standards based on net-metered systems are insufficient, because net metering rules are usually limited to only very small systems.

Pacific Region Status: California, Nevada and Hawaii have decent statewide interconnection standard. Get in touch to help us change that.

Further Resources:

1. Interconnection Fact Sheet (EPA CHP Partnership, PDF, 4 pgs)
   http://epa.gov/chp/documents/interconnection_fs.pdf
2. Connecting to the Grid: A Guide to Distributed Generation Interconnection Issues (IREC, PDF, 51 pgs)
   http://irecusa.org/wp-content/uploads/2009/10/Connecting_to_the_Grid_Guide_6th_edition-1.pdf

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 clean power at a discount to new conventional plants. CESOP involves two steps:

1. 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.
2. 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.

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 do not include the cost of delivery. This 1978 PURPA-era policy could use improvement.

Further Resources:

• CESOP Corrects problems of the Public Utility Regulatory Policy Act (PURPA) and the Clean Air Act (Recycled Energy Development, HTML)
  • http://www.recycled-energy.com/main/cesop
• Draft Clean Energy Standard Offer Program (Recycled Energy Development, PDF, 5 pgs)
  • http://www.recycled-energy.com/_documents/articles/CESOP.pdf

Most local generators stay connected to the grid, and contract with the utility company for electricity when their generators need to go down for planned or unplanned maintenance. These rates are known variably as standby rates, backup rates, partial requirements, and other terms. Utilities have typically justified these rates to regulators by saying there are costs involved in ensuring the power is available when needed, and there are costs to delivering it—which is true.

Unfortunately, many utilities’ standby rates have been unnecessarily high and have been used as a tool to discourage or prevent onsite generation. Public Utility Commissions must design appropriate standby rates that do not contain unintended barriers to clean heat and power, and that accurately reflect the true cost of providing standby power.

Most standby rates are based on a local generator having an unplanned outage and needing full power during the utility’s peak times, when electricity is scarce or at a premium cost. However, the likelihood of all interconnected generators going down at the same time during peak times is extremely low—and standby rates should reflect that.

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.

Fair and non-discriminatory standby rates are those that:

1. Are based on actual in-field data.
2. Reflect the statistical likelihood of all interconnected systems incurring an outage at the same time.
3. Reflect the statistical probability of local generators going down during utility peak periods, as opposed to off-peak.
4. Take into account the system benefits that CHP creates for utilities, which are often in excess to its costs. http://www.energy.ca.gov/2005publications/CEC-500-2005-061/CEC-500-2005-061-D.PDF
5. Quantitatively compare CHP to normal load variation.
6. Charge a per-kWh rate (energy rate) not more than that charged to the rest of the normal rate class.
7. Ensure that no standby charges are levied for plant shutdowns caused by events on the utility side of the meter.
8. Provide the option to take standby service or to decline such service and to remain on the otherwise applicable rate schedule (as recently passed in Hawaii and other states).

Further Resources:

1. Utility Rates Fact Sheet (EPA CHP Partnership, HTML)
   http://www.epa.gov/chp/state-policy/utility_fs.html
2. Are standby rates justified? (Electricity Journal, PDF, 5 pgs)
   http://www.recycled-energy.com/_documents/articles/sc_standby_rates.pdf
3. The Legal Case Against Standby Rates (Electricity Journal, PDF, 10 pgs)
   http://www.recycled-energy.com/_documents/articles/sc_electricity_journal11-07.pdf

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 out-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, unfortunately. 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 make the switch.
[[Hyperlink to Contact Us page]]

Further Resources:

1. Output-based Regulations: A Handbook for Regulators (EPA, 86 pgs)
   http://epa.gov/chp/documents/obr_final_9105.pdf
2. Output-Based Environmental Regulations Fact Sheet (EPA, 4 pgs)
   http://www.epa.gov/chp/documents/output_based_regs_fs.pdf
3. Output-based Emission Standards: Advancing Innovative Energy Technologies (Northeast-Midwest Institute, PDF, 68 pgs)
   http://www.nemw.org/images/stories/documents/output_emissions.pdf
4. Clean Energy-Environment Guide to Action: Policies, Best Practices, and Action Steps for States (Section 5.3) (EPA, PDF, 410 pgs)
   http://www.epa.gov/statelocalclimate/resources/action-guide.html

Similar to air quality regulations for SOx, NOx, and particulates (see above), output-based allocations can and should be used in climate change regulations. In a cap-and-trade framework, they are a simpler, fairer, and cheaper method of allocating CO2 allowances than other proposed methods (lump-sum grandfathering, sector-based allocations, auctioning, carbon taxes, or picking technology winners).

Allocating based on past emissions is a poor choice, because it rewards the least efficient plants and prevents new, highly-efficient plants from competing fairly. Allocating sector-by-sector is also a poor choice, because the industries with the best lobbyists get the most allocations—whether they are efficient or not efficient, high-emitting or low-emitting. 

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.

1. Reduce Greenhouse Gasses Profitably (Issues in Science and Technology, 4 pgs)
   http://www.recycled-energy.com/_documents/articles/dm_issues-wntr09.pdf

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 a renewable energy, and should be recognized as such in renewable portfolio standards. It uses no additional fuel and creates no additional greenhouse gasses or other pollutants—making it just as pristine as wind or solar. And 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 should do so, and states without an RPS at all should consider how waste heat recovery makes an RPS economically advantageous to the state.

• http://www.recycled-energy.com/newsroom/news/the_case_for_gray_power

Combined heat and power is fundamentally an energy efficiency measure. All systems that are more efficient than conventional generation should be included as an eligible technology in meeting energy efficiency resource standards. States that have not specifically included CHP in their EERS ought to add it. ACEEE has released a model standard and guidelines on how to calculate and allocate the efficiency benefits of CHP within an EERS context, helpful for states drafting rules. 

• http://www.aceee.org/energy/state/eers_statemodel.pdf
• http://www.aceee.org/energy/national/SS09_paper_panel4_10.pdf

Pacific Region Status:

Further Resources:

1. Renewable Portfolio Standards and CHP (EPA CHP Partnership, HTML)
   http://www.epa.gov/chp/state-policy/renewable.html
2. Energy Portfolio Standards and the Promotion of Combined Heat and Power (EPA CHP Partnership, PDF, 12 pgs)
   http://www.epa.gov/chp/documents/eps_and_promotion.pdf
3. Clean Energy-Environment Guide to Action: Policies, Best Practices, and Action Steps for States (Section 5.3) (EPA, PDF, 410 pgs)
   http://www.epa.gov/statelocalclimate/resources/action-guide.html
4. CHP Savings and Avoided Emissions in Portfolio Standards (ACEEE, PDF, 12 pgs)
   http://www.aceee.org/energy/national/SS09_paper_panel4_10.pdf

Customer-sited clean energy investments ought to form a critical component of least-cost planning activities that seek to minimize ratepayer-funded investments in system load growth.

Utility generation assets that are purchased, deployed, and operated by regulated utilities nearly always add to the rate base (and therefore increase energy rates for consumers), while those like CHP that are put in by unregulated entities do not factor into the rate base. Thus, grid benefits that are created by CHP deployment are realized at little to no cost to the ratepayer.

CHP investors assume 100 percent of the capital risk when they install their power plant, as compared to utility investments, which spread their risk across all electric consumers. Thus, ratepayers realize all the benefits of good private sector investment decisions while bearing none of the risk for bad private sector investment decisions. This is usually inverted for regulated utilities, where shareholders are consistently insulated from poor investment decisions, since these costs are invariably passed along to ratepayers (as many a nuclear plant cost-overrun will attest).

Seen from the perspective of resource planning, this means that a grid that maximizes CHP will also realize the maximum social benefit per dollar of rate base capital investment. Note that this is true no matter what the economics of the CHP system are, since in virtually all cases, those investments are made with unregulated dollars.

Unfortunately, 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.

An industrial plant that generates excess heat usually has to throw most of that heat away. It is 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 not even allowed to deliver power from a CHP on one side of the street to its operations on the other. It is allowed to pipe hot water, chilled water, or steam across the street, but not electricity. It can only sell it back to the utility grid, at an often prohibitively-low price.

A better policy would allow qualified a local generator to install private wires that move power to its neighboring retail electric users. This would be consistent with 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.

Under the current regulatory structure, utility revenues are tied to sales volume (in kW and kWh). In other words, the more they sell, the higher their profits, and the less they sell, the lower their profits. This often leads utilities to discourage energy efficiency measures, including CHP, that reduce electricity sales. Decoupling revenue from throughput would help fix this incentive problem. Decoupling could be combined with a sliding scale or range of earnings potential that rewards increasing efficiency.