The CHP Revival

The CHP Revival

June 01, 2013 | By Keith Martin in Washington, DC

Low natural gas prices and the growing interest in distributed generation are causing power plant developers to refocus on combined heat and power or “CHP” projects. 

Various programs at both the federal and state level are also encouraging the shift. 

Portfolio financing models that were developed for the rooftop solar market can be readily adapted for use with CHP. CHP projects at state or other government facilities may be able to take advantage of tax-exempt bond financing. 


CHP refers to equipment that produces two useful forms of energy from a single fuel. The energy is usually in the form of electricity and either steam or mechanical power. The term CHP is often used synonymously with “cogeneration” (although the latter term is most often associated with programs implementing the Public Utilities Regulatory Policies Act of 1978 or PURPA). CHP fuels include biomass, biogas, natural gas, petroleum coke and municipal waste. 

By concurrently producing electricity and useful heat or mechanical power from a single fuel source, CHP is more efficient than technologies that produce these outputs separately. This efficiency reduces greenhouse gases from use of fossil fuel. A recent study by the Oak Ridge National Laboratory
concluded that increasing the cogeneration share of electricity generating capacity would significantly reduce carbon dioxide emissions. CHP is also credited with additional benefits such as the reduction of other air pollutants including sulfur dioxide, improved local reliability (produced because CHP may be distributed) and a reduction in otherwise necessary investment in transmission infrastructure. Adding to its potential appeal is CHP’s capacity to operate as a baseload facility, its use of technology that has been in use for some time and the potential in some states to displace higher-cost retail service from utilities. 

PURPA and federal tax incentives helped to expand CHP installed capacity from about 12,000 megawatts in 1980 to more than 66,000 megawatts in 2000. Yet CHP remains an underused resource, representing approximately just 8% of US generating capacity, compared with over 30% in some northern European countries. 

Federal Support for CHP 

The federal government has adopted a number of programs to encourage CHP. These programs take various forms, including federal tax subsidies and directives to increase electricity self-sufficiency at federal installations such as military bases. Electric utilities also remain obligated by PURPA to buy electricity from cogeneration facilities in some parts of the country. 

Owners of CHP projects can depreciate, or deduct, the cost of the projects on an accelerated basis, meaning the deductions are front loaded, over five to 20 years, depending on the fuel. The fastest depreciation is available on CHP facilities that use biomass as fuel. Projects put in service in 2013 or 2014 may qualify for a 50% depreciation “bonus,” meaning the ability to deduct half the “tax basis” in the facility immediately. The other half is depreciated normally.

Some CHP projects also qualify for an investment tax credit. Unlike depreciation, which is deducted from income, a tax credit offsets directly taxes that the CHP owner would otherwise have to pay. 

The tax credit may be 10% or 30%, again depending on the fuel. 

CHP facilities that use biomass, landfill gas or municipal solid waste as fuel qualify potentially for a 30% investment tax credit. However, such facilities would have to be under construction by December 2013. There is no deadline to complete such facilities to qualify. 

A 10% investment tax credit can be claimed on CHP facilities that have at least a 60% conversion efficiency ratio as fuel is converted into electricity. The credit is reduced to zero as the facility moves in size from 15 megawatts to 50 megawatts in capacity. At least 20% of the useful output must be in form of mechanical power or steam. Projects that use biomass as fuel do not have to meet the 60% efficiency requirement, but the credit is reduced proportionately to the extent the efficiency is less than 60. Projects must be completed by December 2016 to qualify for the 10% investment tax credit. 

Through a number of statutes, executive orders and directives from the Department of Defense, all branches of the military are engaged in processes to acquire renewable resources and move away from relying on local utilities. The US Army, in particular, has made a significant effort to procure renewables and CHP for the purposes of meeting a “net zero” goal. A “net zero” installation is one that produces as much energy on site as it uses on site over the course of any given year. 

PURPA was enacted after the Arab oil embargo in the 1970s in part to encourage the more efficient generation of electricity and decrease reliance on foreign oil. PURPA formally recognized cogeneration by creating a class of power generators called qualifying facilities or “QFs.” To be a QF, a project using fossil fuel must produce both steam and electricity, the stream must be put to use and the project must meet certain fuel efficiency requirements. For example, to satisfy the efficiency standard, a gas-fired cogenerator would have to show the useful power output plus half the useful steam output is at least 42.5% of the energy content of the natural gas used as fuel. 

As long as a facility qualifies as a cogenerator, PURPA requires a utility to buy the electricity at the utility’s “avoided cost” or what it would cost the utility to generate the same electricity. In 2005, Congress gave the Federal Energy Regulatory Commission authority to terminate the utility obligation to buy electricity from QFs in regional markets that are “workably competitive.” While FERC has found large swathes of the country “workably competitive,” utilities in some regions remain subject to the mandatory purchase obligation. 

State Support for CHP 

In terms of state support, a number of states have renewable portfolio standards that include CHP as a qualified resource. Some state RPS programs include a specific set aside, meaning a special target, for CHP. Some states also offer tax incentives to support CHP, as well as minimum pricing and a mandatory purchase program for renewable energy credits from CHP facilities. Finally, certain states have authorized the use of their bonding authority to pay for CHP facilities owned by state and local governments. 

Of the 13 states that include CHP or waste energy recovery in their RPS targets, California is perhaps the most aggressive in providing a CHP set aside. The California program also provides form power contracts for use with CHP projects. California utilities have a mandatory procurement obligation of 3,000 megawatts of capacity from CHP facilities. PPAs offered under the CHP set aside have terms of up to seven years for existing CHP facilities and up to 12 years for new CHP facilities. The utilities are required to provide updates on their procurement of CHP. To qualify for the CHP set aside, facilities must qualify as cogeneration QFs under PURPA as well as satisfy other guidelines including greenhouse gas emission reduction targets. 

There is a formal RFP process for utilities buying electricity from CHP projects, but the California Public Utilities Commission or CPUC also allows utilities to procure CHP through bilateral negotiation of PPAs. However, the bilateral process is limited in scope. The CPUC has separated CHP into categories based on size (20 megawatts or less and larger than 20 megawatts). There are additional efficiency requirements on large CHP projects to qualify for the procurement set aside.

The CPUC also adopted a program to encourage new behind-the-meter CHP facilities. Further, California law has directed the CPUC to establish a feed-in tariff for small CHP systems (less than 20 megawatts) that are new (meaning in operation after January 1, 2008) and highly efficient (operating at better than 62% efficiency).

Illinois offers grants for CHP. The grants cover 50% of a project’s cost up to $225,000 for biogas CHP facilities and $500,000 for biomass CHP facilities located in the state. Eligibility is limited to the purchase and installation of generating equipment for the facility. The Energy Resources Center at the University of Illinois Chicago assists the state’s Department of Commerce and Economic Opportunity in administering the incentive program, which expires December 15, 2015.

In New York, a CHP acceleration program is administered by the New York State Energy Research & Development Authority. The program, designed for relatively small CHP facilities of between 0.5 and 1.3 megawatts, provides incentives for installation of pre-qualified and conditionally qualified CHP systems by approved CHP system vendors. Incentive funds are allocated on a site-by-site, first-come-first-served basis. The maximum incentive per project is $1.5 million out of a total program budget of $20 million. The incentive commenced on February 15, 2013 and will expire on December 30, 2016.

Connecticut has a CHP set aside in its renewable portfolio standard. Under the state RPS, electricity suppliers were required to supply at least 4% of their retail loads by 2010 using distributed CHP systems at customer sites. As load grows, the electric suppliers in the state are required to maintain the 4% threshold. These facilities must have a minimum operating efficiency of 50% and must be installed at commercial or industrial facilities in Connecticut on or after January 1, 2006. 

Connecticut also has a minimum price and purchase obligation for RECs produced by facilities that qualify based on their emissions and efficiency. Connecticut Light & Power and United Illuminating Company are subject to this requirement. The “LREC” program applies to RECs from projects with limited emissions that are no larger than two megawatts. 

The Massachusetts renewable portfolio standard requires 3% of the state’s electric load to be supplied from alternative energy sources by 2013. This mandate grows to 5% by 2020. “Alternative energy” includes CHP. 

Massachusetts has also established a Renewable Energy Trust Fund that is funded by a non-bypassable surcharge of $0.0005 per kWh imposed on customers of all investor-owned electric utilities and competitive municipal utilities in Massachusetts. The fund provides grants, contracts, loans, equity investments, energy production credits, bill credits and rebates to customers. The total fund size was $23 million starting in 2011. The fund is authorized to support CHP systems less than 60 kilowatts in size.

The New Jersey Board of Public Utilities has two incentive programs. Incentives for CHP systems with installed capacities of up to one megawatt and that produce useful waste heat and achieve annual system efficiencies of at least 60% range from $1 to $2 a watt. An additional incentive of 25¢ a watt is available and paid on a performance basis. The incentives available for small CHP systems are effectively capped at $2.25 million per project. 

CHP facilities larger than one megawatt in size are subject to a different incentive program. After the incentives are approved by the Board of Public Utilities, they are paid by check in stages (20% upon purchase of the equipment, 60% after installation and the remaining 20% after the first year of operation).


As with other forms of distributed generation, CHP can be challenging to finance due to its small size. CHP technologies vary in design, size, fuel source and prime-mover technology. During the heyday of PURPA, cogeneration facilities were coal- or gas-fired, the projects were large and the prime-mover was a combustion turbine or boiler and steam turbine. Today’s CHP can be biomass-fired, use reciprocating engines and be sized and designed for individual industrial and commercial customers. 

To the extent the small size of each facility is an impediment to financing, there are parallels in the rooftop solar market. As is the case with rooftop solar, CHP can be aggregated into portfolios. The key to this approach is repeatability. CHP owners will find it easier to arrange financing if all their facilities have similar technical designs, use similar customer agreements and have similar warranty coverage. 

Most rooftop solar facilities are financed in the tax equity market. The developer enters into a master financing facility with a tax equity investor. These facilities may take one of three forms: a partnership flip, sale-leaseback or inverted lease. 

In a partnership flip, the developer forms a partnership with the tax equity investor. The partnership takes assignment of the customer agreements and hires the developer to install the systems. The partnership will own the systems, supply electricity under power contracts to customers or lease the systems to customers and collect rents. It receives the tax benefits and allocates them largely to the tax equity investor.

In a sale-leaseback, the developer sells the systems to a tax equity investor within three months after installation and leases them back. The lessor claims the tax benefits and shares them indirectly with the developer in the form of a reduced rent for use of the systems.

In an inverted lease, the developer leases the systems to the tax equity investor and assigns the tax equity investor the customer agreements. The tax equity investor claims the investment tax credits on the systems. The developer keeps the depreciation and receives most of the customer revenue as rent from the tax equity investor.

All three structures are “master” financing facilities in the sense that the terms are spelled out in a set of master financing documents. Each month, the developer brings a file folder with the new customer agreement it proposes to sign. As each additional batch of projects is added, an additional schedule is added to the back of the master financing documents. 

The financing facilities usually run $50 to $100 million in size but can be smaller. The tax equity investor agrees to finance up to that amount in equipment or to finance all systems that are presented through a date 12 to 18 months in the future, whichever is reached first.

Some states offer programs to offset the costs of CHP and fund those programs with revenue bonds. However, a state’s bonding authority may also be used to fund the capital costs of CHP. To the extent the bonds are tax-exempt, the project sponsor will have to fit within the rules for “private activity bonds” or other programs designed to assist with waste disposal. 

Barriers to CHP

The US Environmental Protection Agency said in a recent presentation that the potential market for CHP at existing industrial facilities is just under 65,000 megawatts with roughly an equivalent potential market for CHP at commercial and institutional facilities. What are the barriers to the further development of CHP?

The value proposition for utilities is not entirely clear. From a utility’s perspective, CHP is similar to distributed solar. Both technologies reduce and change the load shape of the utility’s customers. This becomes a problem for the utility as it relies on electricity sales to those customers. The conundrum for regulators is how to encourage CHP, with its benefit to the environment and potential overall benefit to utility customers, while still allowing utilities to earn necessary revenues. 

Regulators faced similar issues in the context of efforts to increase demand-side management and in the era of retail deregulation. Both of these policies led to smaller electricity sales by utilities. 

CHP can require a substantial capital investment. In some states, CHP owners sell both electricity and steam or waste heat to an industrial or commercial host. If a CHP owner builds a project to serve a host, then the CHP owner will be relying on the financial strength of that host. Thus, from a practical perspective, the CHP owner will be subject to the same economic pressures that affect the host’s business. Some hosts will not be willing to commit to the CHP owner for a long enough term to allow recovery of the CHP owner’s costs and expected margin or, even if the commitment is there, the host at some point may not be able to fulfill its commitment. 

In cases where CHP owners sell electricity to a utility and steam or waste heat to an industrial or commercial host, the overall concern with the host’s financial strength is blunted but not eliminated. State programs encouraging CHP often come with requirements for fuel use efficiency. If the steam host is lost, then the CHP owner may also lose the incentives or other support that allowed the owner to make the CHP investment in the first place. 

There are still retail sale restrictions in most states that limit how a distributed CHP project can be structured. Fifteen states allow customers to choose their electricity suppliers. In other states, only the local utility can sell electricity at retail in its monopoly service territory. In such states, the CHP owner will have to lease the system to the customer rather than sell the electricity. However, leases do not work when dealing with customers who are government or tax-exempt entities because most of the federal tax benefits will be lost. More creative thinking is required for projects with such customers. 

There are other regulatory issues to be considered. CHP facilities, while reliable, will not operate to serve a host’s load 100% of the time. CHP is also unlikely to be sized in a manner that matches a host’s load on a time-of-day basis. This means that the host will have to rely, to some extent, on the local utility. The cost of providing “standby service” (service to the customer or the CHP facility when the facility is not operating) or “supplemental service” (service for load in excess of the electricity produced by the CHP facility) is subject to state regulation and the pressures regarding loss of utility load discussed earlier. There may be resistance from the local utility to providing such service. 

Further, unless the CHP facility is disconnected entirely from the utility grid, there will be interconnection and power scheduling issues for the CHP owner to consider. Finally, CHP projects can have interesting local permitting issues. 


For example, even in states where thermal generation is regulated at the state level, CHP may not meet the capacity threshold requirements to qualify for centralized state permitting and, as a result, CHP may be thrust into a confusing maze of state and local permitting requirements. In California, for instance, while permitting for thermal generation in excess of 50 megawatts is governed by the California Energy Commission, smaller thermal generation is permitted at the county level. CHP is a thermal resource that will have air emissions and may require discharge of cooling water. Thus, regardless of whether land use is regulated locally, CHP facilities will still have to meet state and federal emissions and, potentially, effluent requirements.