Lessons learned from a decade of CHP in California

The US state of California’s 2001 programme to support the installation of new distributed energy plants has so far resulted in over 1200 new facilities, including systems based on turbines, engines and fuel cells. The programme has been a success, but not without a few challenges, as George Simons reports.

The United States seems poised to embark on a long anticipated market growth in combined heat and power (CHP). Also known as cogeneration, CHP technologies were first used over 100 years ago.1 However, growth in the US CHP market was slow up through the middle 1900s. Spurred by concerns over economic disruptions, caused by the oil embargoes of the 1970s, CHP market growth was given a boost with the Public Utility Regulatory Policy Act (PURPA) of 1978.

PURPA supported development of renewable energy and more efficient cogeneration technologies by enabling owners of renewable energy and CHP facilities to recoup their investment through avoided electricity costs. The resulting growth propelled CHP capacity in the combined industrial and commercial sectors, from less than 10 GW in 1980 to nearly 44 GW by 1993.2

Future market potential in the US for CHP is significant. As of 2000, there were over 980 CHP facilities operating within the commercial sector ” representing an installed generating capacity of 5 GW.3 Studies indicate the market potential for CHP in the commercial sector to be over 15 times the installed capacity; roughly in excess of 77 GW.

The ability for CHP to achieve market potential depends on a number of factors. Lawrence Berkeley National Laboratory (LBNL) examined factors influencing CHP market potential in the commercial sector. LBNL found that forecasts of CHP market potential in the commercial sector varied from 35 GW by 2025 to nearly 60 GW by 2025 ” depending on natural gas prices, the ability to use CHP in retrofit situations, and the tax treatment of CHP facilities.4

A NEW HORIZON OF CHP MARKET DRIVERS

A confluence of concerns and interests may now be driving expanded CHP market growth. Like the 1970s, there are rising concerns over volatility in energy prices. More recently though, there has been an increasing awareness of the need to update the country’s transmission and distribution (T&D) system; plus there has been both unease and anticipation over the role of global climate change on the electricity sector.

Belief that CHP may play a pivotal role in modernizing the grid and addressing global climate change, has prompted several recent changes in energy policies. The Energy Independence and Security Act of 2007 created special programmes and funding to support development of renewable and CHP facilities, including establishment of incentives and grants for waste energy recovery projects.

Similarly, favourable changes in tax treatment of CHP facilities are provided under the Energy Improvement and Extension (EIE) Act of 2008. A key provision of the 2008 Act is a 10% investment tax credit covering costs for the first 15 MW of qualifying CHP facilities. Among requirements, qualifying CHP facilities must: produce at least 20% of their useful energy as electricity and 20% as useful thermal energy; be 60% or more more efficient (on a lower heating value basis); be smaller than 50 MW and be placed in service before 1 January 2017. But what are the chances that CHP facilities can not only meet these requirements but also provide expected reductions in greenhouse gas emissions and enhance the T&D system? To date, performance results have mostly been collected from individual CHP facilities, making it difficult to predict the impact of the significantly increased market penetration of CHP.

CALIFORNIA’S SELF-GENERATION INCENTIVE PROGRAMME

Over the past 10 years, comprehensive performance data has been collected from a collection of CHP facilities deployed under a legislatively mandated DG incentive programme in California.

During the late 1990s and early 2000, California was encountering increasingly severe peak electricity demand problems. Both southern and northern parts of the state were experiencing rolling brownouts and blackouts. In 2001, the California legislature passed Assembly Bill 970, establishing a series of approaches to mitigate the state’s burgeoning peak demand problem.


Figure 1. Distribution of CHP facilities within the SGIP, by Zip code
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One such approach was the establishment of the Self-Generation Incentive Program (SGIP), administered by the California Public Utilities Commission (CPUC) and implemented by California’s investor owned utilities. The SGIP is implemented by Pacific Gas and Electric; Southern California Edison; Southern California Gas Company and the California Center for Sustainable Energy on behalf of San Diego Gas and Electricity. Itron is the prime contractor for conducting measurement and evaluation activities.


Microturbines at the Ronald Reagan Presidential Library, Montana
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The intent of the SGIP was to help develop a market of DG facilities located directly at utility customer sites. These DG facilities would help offset all or a portion of the electricity needs of the customer, thereby alleviating some of the state’s peak demand problem. Like PURPA, the SGIP provided financial incentives to help grow the DG market.


Figure 2. Impact of SGIP CHP facilities on CA ISO peak (2007)
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An assortment of DG technologies have been eligible to receive incentives under the SGIP, including solar photovoltaic (PV) systems; wind turbines; both fossil and renewable-fuelled prime internal combustion engines (ICE); fuel cells; micro-turbines and small gas turbines. Since its inception in 2001, over 1200 DG facilities, representing over US$1 billion in investment and 300 MW of electricity generating capacity, have been installed under the SGIP.


Table 1. CHP systems in the SGIP, December 2007
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At the start of the SGIP, the CPUC established a measurement and evaluation (M&E) programme to monitor performance of the deployed DG facilities. As part of the M&E plan, performance data is collected on a statistically representative number of the SGIP facilities. The type of information collected and number of sites monitored are established using a statistical goal of achieving 90% confidence and 10% precision, depending on stratification of the sample population. Monitored performance information includes 15 minute interval data collected on an 8760 hour per year basis for net electricity generation output (ENGO); useful waste heat recovery (HEAT); and fuel consumption (FUEL). By the end of 2007, M&E data was being collected on over 300 CHP sites.

HOW CHP FARES IN A DG WORLD

CHP facilities have played a significant role in the SGIP; providing over 60% of the SGIP’s generating capacity. As of the end of 2007, there were over 330 CHP facilities contributing in excess of 160 MW of capacity in California.

The SGIP is a state wide programme and CHP facilities are located among the various utility service territories. Figure 1 shows the distribution of CHP facilities deployed under the SGIP. Unsurprisingly, there are heavy concentrations of CHP facilities in urban areas that inherently have larger numbers of commercial and industrial operations.

Somewhat more surprising is the emergence of renewable CHP facilities. While most of the CHP facilities are fuelled by natural gas, approximately 30 MW of the CHP capacity within the SGIP represents some 60 facilities powered by renewable fuel sources, such as biogas. Biogas refers to gas derived from biological sources such as landfills, wastewater treatment facilities and anaerobic digesters employed at dairies. Renewable CHP facilities play an important role in benefits provided by the SGIP and may be a harbinger of future DG deployment.

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MEETING MORE THAN ELECTRICITY DEMANDS
In addition to offsetting electricity demand at customer sites, CHP facilities provide needed thermal energy. Nearly two-thirds of the CHP facilities deployed under the SGIP provide process heat, while 20% address both heating and cooling needs, and 10% meet only cooling needs.

CHP facilities must meet both useful energy recovery and overall system efficiency requirements, as established in accordance with Public Utilities Code (PUC) 216.6. In general, CHP facilities must: provide more than 5% of the recovered waste heat as useful thermal energy; and meet an overall efficiency of 42.5%. (PUC 216.6(b) requires that the sum of the electric generation and half of the heat recovery of the system, exceeds 42.5% of the energy entering the system as fuel).

Table 2 summarizes how well SGIP CHP facilities have met PUC requirements. On average, most CHP systems installed under the SGIP, provide well in excess of 20% of their recovered waste heat as useful thermal energy. Consequently, if CHP facilities deployed under the SGIP are representative of CHP facilities at large, then most CHP facilities should have little trouble meeting the 20% useful waste heat recovery requirements in the EIE Act of 2008.

Table 2 also provides information about overall system efficiencies of CHP. On average, microturbines and IC engines tended to have PUC 216.6 (b) efficiencies of over 30%, whereas fuel cells and small gas turbines showed efficiencies in excess of 50%. In general, these results bode well for the ability of fuel cells and gas turbines to achieve the 60% overall system efficiencies required in the EIE Act of 2008. IC engines and microturbines may face some design challenges.

More in-depth evaluation found that a significant contributor to the lower system efficiencies is the mismatch between thermal and electrical loads.5 More specifically, lack of alignment in thermal and electrical loads can result in capture of waste heat with no practical use, or over sizing of equipment, with a commensurate reduction in efficiencies.

COST BENEFITS AND CRITICAL PEAK ELECTRICITY

Sustained CHP market growth will require that CHP systems deliver benefits to owners and the community. A cost-effectiveness study conducted on the SGIP found CHP facilities provide significant savings in costs and energy, not only to CHP owners but to society as well. Table 3 lists the type and estimated amounts of cost benefits provided by CHP facilities, including reduced transmission and distribution line losses, avoided commodity costs for energy and capacity, savings due to thermal energy provided by the CHP system, and reduced emissions.6

Moreover, CHP facilities are providing electricity directly at the demand centre. During 2007, CHP facilities installed under the SGIP provided nearly 554,000 MWh of electricity generation that would otherwise have to have been provided by the grid.7 Moreover, nearly half of the installed CHP systems provided electricity coincident to the California Independent System Operator (CA ISO) peak demand. The impact of SGIP’s CHP facilities on California’s peak electricity demand during the 2007 summer peak is shown in Figure 2 on page 32.

CHP facilities can also help lower the carbon footprint by reducing net greenhouse gas (GHG) emissions. CHP facilities achieve this in several different ways:

  • direct displacement of carbon dioxide from electricity otherwise generated by the grid
  • indirect displacement of carbon dioxide from cooling processes, tied to waste heat recovery/adsorption chillers processes
  • direct replacement of carbon dioxide from waste heat recovery processes, which reduce the need for on-site use of natural gas
  • reductions in methane emissions from CHP facilities powered by renewable biogas.

Fuel cells at TST Corporation. Fuel cells represent an increasing amount of the new generation being installed in California. Clean and quiet, fuel cells are ideal candidates for supplying base load power in urban settings
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NOT ALL ROSES
The California CHP market has experienced its fair share of problems. California has some of the most progressive air quality regulations in the country. In response to growing concerns over worsening smog conditions, the Legislature passed Senate Bill 1298 in 2000 ” requiring DG facilities achieve new and significantly stricter NOx emission limits. Under the new guidelines, all DG units were required to meet a NOx emission limit of 0.07lb (32 grams) of NOx per MW/h of generated electricity by 1 January 2007. IC engines and microturbines have had difficulties in achieving the lower NOx requirements, although some newer units have made progress towards the goals.

Similarly, CHP deployment during the start of the SGIP occurred in a flood. Many businesses adopting CHP systems embraced them with the expectation of reduced energy costs and increased energy independence. With increased volatility in natural gas prices and stagnant electricity rates, the resulting ‘spark gap’ left many CHP owners wondering how best to obtain economic rewards from their systems. In a number of instances, there was also little recognition of the day-to-day maintenance and business integration issues associated with running CHP systems.

Furthermore, as time went by, some of the original internal champions for the CHP systems found new jobs or new responsibilities. For some businesses, this wake up from the honeymoon period and lack of an internal champion led to disappointment and eventual shut down of the CHP system.

LOOKING BACK TO MOVE FORWARD

CHP facilities can provide a wide array of benefits both to their owners and to the community in which they are located. In California, several key factors have driven forward the market adoption of CHP, while others have created potential pitfalls for the industry. The most important attributes of a successful CHP facility includes:

  • achieving on-site energy needs
  • providing a good economic fit between offsetting electrical loads and meeting on-site thermal needs
  • educating system owners of the benefits and the demands of operating a successful CHP system
  • flexibility in adopting to changes in the energy or regulatory landscapes
  • maintaining good communication with the CHP owner to ensure the presence of an effective project champion.

California is currently investigating the ability for DG facilities to provide up to 25% of the state’s peak electricity demands by 2020.8 CHP technologies, with their ability to meet on-site electrical and thermal needs and help reduce carbon footprint, has great promise in helping meet these and other needs of the state.

George Simons is the director of the consulting and analysis group, with Itron Inc., California, USA.
e-mail: George.simons@itron.com

References

  1. One of the first CHP facilities was an electric steam generator employed at the Coronado Hotel in San Diego in 1884, where recovered waste heat was used for space heating. From the website for the Center for Energy Efficiency and Renewable Energy, https://ceere.org
  2. R. Neal Elliot and Mark Spur, ‘Combined Heat and Power: Capturing Wasted Energy,’ May 1999, from the website for the American Council for an Energy Efficient Economy, https://uschpa.org
  3. ONSITE SYSCOM Energy Corporation for the Energy Information Administration. ‘The Market and Technical Potential for Combined Heat and Power in the Commercial/Institutional Sector,’ January 2000, pg. 4
  4. LaCommare, K.H., Edwards, J.L., Gumerman, E. and Marnay, C., ‘Distributed Generation Potential of the U.S. Commercial Sector,’ Ernest Orlando Lawrence Berkeley National Laboratory, May 2005
  5. Itron, ‘CPUC Self-Generation Incentive Program: In-Depth Analysis of Useful Waste Heat Recovery and Performance of Level 3/3N Systems,’ for the CPUC, February 2007
  6. Itron, ‘CPUC Self-Generation Incentive Program: Preliminary Cost-Effectiveness Evaluation Report,’ for the CPUC, September 2005
  7. Itron, ‘CPUC Self-Generation Incentive Program: Seventh Year Impact Evaluation,’ for the CPUC, September 2008
  8. Rawson, Mark and Sugar, John, ‘Distributed Generation and Cogeneration Policy Roadmap for California,’ California Energy Commission, March 2007 (CEC-500-2007-021)

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