Massachusetts portfolio programme backs CHP

Kendall gas-fired cogeneration station in Boston, Massachusetts Credit: Fletcher 6

Alternative energy portfolio standard rules in Massachusetts, US, are encouraging commercial development of gas-fired cogeneration, reports Evelyne Kong of SourceOne Energy.

In 2009, Massachusetts implemented its Alternative Energy Portfolio Standard (APS) as part of a broad effort to develop renewable energies and other energy efficient technologies. The APS programme is aimed at developing alternative energy sources that could fall outside the state’s existing Renewable Energy Portfolio Standard (RPS).

The state’s first Renewable Energy Portfolio Standard ” later renamed RPS Class I ” was introduced in 2003 and obligated retail electricity suppliers (regulated and non-regulated) to source a percentage of their electricity sales from renewable sources such as solar, wind and landfill methane or other low-emission biomass technology.

Figure 1. Massachusetts RPS and APS obligation (percentage of retail load)

In 2008, the Green Communities Act expanded on RPS Class I legislation by adding a subclass within RPS Class I support and introducing three RPS Class II energy portfolio standards:

  • RPS Class I solar renewable energy certificates (SRECs) set a mandatory compliance percentage for PV projects within RPS Class I.
  • RPS Class II renewable energy certificates (RECS) support units with eligible renewables technology that started commercial operation before 1998.
  • RPS Class II waste energy certificates (WECS) support waste-to-energy or municipal solid waste plants that started commercial operation before1998.
  • Alternative Energy Portfolio Standard (APS), aimed at encouraging development of technologies with potential for reducing greenhouse gas emissions that may fall outside RPS Class I or RPS Class II.

Cogeneration under the APS

To qualify for the APS programme, generation units must use combined heat and power (CHP), flywheel energy storage, paper-derived fuel, or gasification with carbon capture and sequestration. Efficient steam technology is also covered by a provision in the law, although relevant regulation has yet to be developed.

Generation units, including behind-the-meter generation, must be within Massachusetts and within the control area of ISO New England (ISO NE), the regional transmission organisation. Units must have started commercial operation on or after 1 January 2008, unless they were retrofitted after that date.

Massachusetts Department of Energy Resources (DOER) also imposes a maximum CO2 emission rate of 890 lb (404 kg)/MWh net electricity (and useful heat in the case of cogeneration).

As a comparison, the EPA has proposed a new source performance standard (NSPS) for CO2 of 1000 lb (2205 kg)/MWh, about the emission rates for natural gas-fired combined-cycle plants.

Cogeneration, as the most mature eligible technology, makes by far the largest contribution to the APS obligation. All current APS qualified CHP units use natural gas, and the scheme excludes coal, nuclear and petroleum-derived fuels and materials.

CHP must meet several conditions to qualify for the APS standard. End-use customers for thermal loads must be in Massachusetts. Qualifying units must also have started commercial operation by the start of 2008, unless they are facilities where incremental electrical energy and/or incremental useful thermal energy have been added since then.

A facility that produces less electricity but additional useful thermal energy can qualify, so the APS programme incentivizes existing electric-only power plants to add useful thermal load and thermal-only plants to add electrical generation. The law also sets no maximum generator capacity.

Each quarter, APS qualifying units must report all electrical, thermal energy sales and consumed fuel. The amounts must also be verified by an ISO NE’s third party meter reader. No specific cogeneration, thermal or electrical efficiencies are set for APS-qualified units but the amount of alternative energy certificates (AECs) they generate depends on the thermal and electrical efficiency of the CHP.

For cogeneration units in commercial operation in or after 2008, APS attributes in MWh are calculated by the following formula (with electrical energy, useful thermal energy and fuel expressed in MWh):

For example, a CHP unit with 35% electrical and thermal efficiencies (HHV) can expect generating 1.42 AECs per MWh of electricity produced.

For CHP units where useful thermal energy and/or electrical energy has been added in 2008 or later a similar formula is used:

The assumed overall efficiency of the electrical production is 33% and the assumed thermal efficiency from the fuel conversion to the end customer is 80%.

Electrical energy is regarded as ‘net electrical energy’, so any electrical parasitic load greater than 25 kW such as fuel gas compressors or boiler feedwater pumps must be subtracted from the APS electrical energy. Auxiliary system representing over 60% of the parasitic load must be metered. Supplemental firing of a heat recovery steam generator (HRSG) shall be metered and included in the fuel and other energy consumed by the CHP unit. The modified formula taking into account parasitic load and supplemental firing is:

Favourable regulation towards CHP has led to cogeneration projects supplying 99.1% of APS qualified generation in 2010 ” and 24 out of 26 qualified projects.

As of May 2012, flywheel storage is the only technology other than CHP represented in the current APS qualified generation units list. The main requirement for APS flywheel storage units is that the qualifying unit must participate in the ISO-NE market to help regulate the system frequency. The law assumes an efficiency of 65% so every MWh sent to the grid by the flywheel unit will generate 0.65 MWh APS attribute. Like APS CHP qualified generators, the electrical energy discharged by the flywheel unit must be verified by an ISO’s third party meter reader. Currently, two flywheel projects of 1 MW and 2 MW ” both by Beacon Power ” are qualified for the programme.

An APS generator can co-fire an eligible APS fuel along with an ineligible fuel. The whole facility will be subject to Massachusetts Department of Environmental Protection (MassDEP) emission rates for similar fuelled generation units and will have to document and report the fuel mix used. Only the portion of the electricity attributed to APS eligible fuel will qualify for APS attributes.

The applicant can also aggregate qualifying APS generation units under one application, provided all the units use the same technology.

APS compliance in 2009 and 2010

The amount of alternative compliance payments reflects demand and supply for AECs. The APS programme’s first years clearly show an undersupply of AECs, mainly because the programme is in early implementation and has yet to significantly affect the market.

Over 2009, the programme’s first year, retail electricity suppliers had to provide 163,844 APS certificates, representing 0.34% of the total retail load (less than the 1% set by the law due to exemptions for unregulated suppliers under contracts executed before 2009). Retail suppliers provided 119,325 AECs and paid for 44,519 alternative compliance credits. In 2009, only six units totalling 23.836 MW qualified as APS units.

In 2010, although APS credits almost doubled, AECs generated during the year or banked from the previous year only represented 37% of the total APS attributes required for compliance. An additional 10.915 MW qualified as APS generation units and started generating credits in 2010.

The DOER report for the 2011 compliance year has yet to be published but data shows that 324,780 APS attributes were certified, out of an estimated 852,272 APS certificates needed for compliance. The last update from the department shows that 13.308 MW of additional capacity qualified to generate APS credits in 2011.

The future of the APS programme

At this stage of the programme’s implementation, it is hard to forecast the price and supply of AECs through 2020. CHP will certainly remain the main technology used for APS generation and, if the APS market capacity continues to increase at the current rate, the supply of AECs would match demand between 2017 and 2019.

Figure 2. The outlook for meeting the APS mininum standard

That said, the supply of AECs could quickly pick up with new CHP projects entering the APS market, especially if big CHP units start generating AECs. Currently, although there is no limit on the capacity of generators entering the APS market, most APS-qualified generating units have a capacity of less than 2 MW. A 20 MW cogeneration unit could potentially generate more than 200,000 AECs each year.

Figure 2 shows the estimated APS-certified CHP capacity required to meet the APS minimum standard, if load grows in line with a DOER report up to 2016 and then by 1% per year up to 2020.

Over the next couple of years, the price for AECs is expected to closer to, but below, the alternative compliance payment rate (currently at $21/MWh). But the price could plunge once supply meets demand as Massachusetts CHP credits have no alternative market. Massachusetts has also set no floor price, unlike Connecticut RPS Class III credits, which are currently priced at the floor at $10/MWh after a few years of implementation.

Other parameters could affect the AECs market. The supply of APS certificates could be greatly impacted by any change in state or federal investment incentive regulation. Gas and electricity prices will also deeply influence the future capacity of CHP constructed in the next decade.

The Massachusetts APS programme is still in its early stage of implementation. Another 12 US states have introduced portfolio standards encouraging cogeneration, although their rules vary greatly. In some states, CHP competes with other renewables as no separate alternative energy portfolio exits. Others states, such as Connecticut, impose a minimum efficiency requirement or a combination of CHP and waste energy or a maximum capacity for CHP facilities. Each programme has its own design and particularities that should be carefully considered to understand the benefits of these production-type incentives.

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