February 2014, Vol. 26, No.2

Extra 2

Effects of a greenhouse gas tax on the water sector

Challenges, concerns, and opportunities

Bill Barber, Greg Priest, and Patricia Scanlan

In 2009 and 2010, the U.S. Environmental Protection Agency (EPA) finalized a Mandatory Greenhouse Gas (GHG) Reporting Rule (40 CFR 98.2) and the “Tailoring Rule” (officially PSD [Prevention of Significant Deterioration] and Title V Greenhouse Gas Tailoring Rule, 40 CFR 51, 52, 70, and 71), respectively, to collect, report, and permit GHG emissions. These rules do not impose limits or tariffs on GHG emissions; however, information developed through these tracking and reporting requirements will provide background for future GHG policy decisions.

Several countries have taken the next step of controlling GHG emission through taxes or tariffs. In 2012, Australia implemented a carbon tax to encourage GHG emission reductions. While water resource recovery facilities (WRRFs) generate a fairly small percentage of total U.S. GHG emissions — approximately 0.3% in 2011, according to EPA’s 2013 Inventory of U.S. Greenhouse Gas Emissions and Sinks — energy and resource recovery programs at WRRFs can result in important reductions to GHGs. Consequently, it is important to have carbon tax or incentive programs accurately identify potential GHG reduction benefits associated with wastewater treatment and resource recovery.

 

Biosolids and the carbon pricing mechanism in Australia

In July 2012, Australia enforced a price on carbon emissions as part of a series of initiatives to reduce its global carbon impact, which on a per-capita basis is among the highest in the world. The carbon price, known as the Carbon Pricing Mechanism (CPM), initially was to tax Scope 1 (see sidebar, p. 59) carbon emissions at AUD $23 (U.S. $21) per tonne of carbon dioxide equivalent ($/t CO2e) emissions (U.S. $21/t CO2e) for 3 years followed by incremental increases prior to entering an emissions trading scheme.

Its introduction was, and remains, highly controversial and often is discussed on the Australian political agenda. In fact, following a change in prime minister in mid-2013, the carbon price subsequently was discarded and will be replaced with an emissions trading scheme (ETS) as soon as July 2014.

At press time, the value of 1 tonne CO2e under the new proposal had dropped to AUD $6/t CO2e (U.S. $5/t CO2e). It is expected that moving to an ETS-based system will save the average Australian family $1 per day. While the carbon price primarily was aimed at heavy industry, it also applies to the water industry under a general waste category. Currently, under the National Greenhouse and Energy Reporting (NGER) guidelines (Australian Government Department of Climate Change and Energy Efficiency), water companies must report on their energy use and GHG emissions if, at a facility level, they do any of the following on an annual basis:

 

  • emit more than 25,000 tonnes of CO2e,
  • produce more than 100 terajoules (28 million kWh) of energy, or
  • consume more than 100 terajoules of energy (28 million kWh).

 

It is well understood that the responsible management of biosolids generated from the water industry can reduce the carbon footprint. Methods for carbon footprint reduction include  

  • production of renewable energy from biogas generated from anaerobic digestion,
  • displacement of fossil fuels attributed to fertilizer manufacture by land applying the biosolids to provide nutrients (as well as carbon retention) to agricultural land,
  • displacement of fossil fuel by direct burning of biosolids (which have similar calorific value to lignite) in purpose-built or third-party facilities, and
  • increased carbon sequestration of land by applying biosolids as a soil amendment.

The reductions in carbon footprint listed above will be offset somewhat by fugitive methane emissions that can occur during solids processing and the energy associated with biosolids treatment.

 

Concerns with calculation methodology

A recent study commissioned by the Australian and New Zealand Biosolids Partnership (ANZBP) — a member-based group consisting of utilities, consultants, academics, and government bodies committed to the sustainable management of biosolids — investigated the potential impact of the CPM on the biosolids industry. This study was, in part, aimed to inform the industry of current practice, while also reviewing the methodology proposed and highlighting opportunities going forward.

One finding of the study was immediately clear: The methods used to calculate emissions arising from biosolids treatment and management in the CPM have the potential to significantly over- or underestimate the emissions generated, resulting in unjustified carbon price liabilities. These errors arise partly from the emission factors used for certain treatment or management processes. For example, only five multiplier “options” are available:  

  • managed aerobic treatment,
  • unmanaged aerobic treatment,
  • anaerobic digester/reactor,
  • shallow anaerobic lagoon (less than 2 m [6.56 ft] depth), and
  • deep anaerobic lagoon (greater than 2 m [6.56 ft] depth).

 No methodology is available to calculate emissions for numerous commonly practiced processes in the biosolids industry, such as advanced anaerobic digestion, thermal and pasteurization systems, systems involving use of admixtures, or energy recovery through combustion processes. 

Since the existing calculation methodology fails to include processes that increase digestion performance — advanced digestion, for example — there is no incentive from the CPM to move toward systems that produce more biogas and are more carbon efficient.

In addition, as the CPM only applies to Scope 1 emissions, the study found that the methodology does not penalize processes that may have higher total carbon emissions. Based on current methodology, aerobic digestion, which has zero Scope 1 emissions — as a process which falls under a definition of “managed aerobic treatment” — will have a lower carbon price liability than anaerobic digestion despite the higher energy demand and overall carbon footprint.

Another concern is the principal calculation of Scope 1 methane emissions. These are based on the difference between a theoretical production and a measured quantity (that is based on methane used for cogeneration, flared, or exported). While the methodology is correct in principle, the factor used to calculate the theoretical figure is inappropriate as it is based on the production of biogas from glucose, which has a lower biogas yield and methane content than biogas from wastewater solids digestion. Consequently, the theoretical figure is too low and can lead to small or even negative results for methane emissions.

The effects of these anomalies are profound. Along with inaccurately determined tax liabilities, wastewater operators also are exposed to real financial and criminal risks, as well as reputational risks, if emission estimates are incorrect. If an audit indicates underestimated carbon emission, the operator may be subject to sizeable fines and criminal penalties attached to the carbon pricing legislation. Conversely, overestimation of emissions may lead to an excessive carbon price liability. Recommendations have been made calling for additional research to develop more accurate methodologies for carbon emissions estimates for biosolids processing.

 

Potential opportunities

While significant opportunities for reducing carbon emissions and recovering energy from biosolids exist, the current methodology fails to account for the emissions reduction directly from biosolids energy recovery. However, the potential value of this missed opportuntiy can be quantified.

As an example, the table on p. 60 shows the carbon emissions generated from the production of 1 MWh of electricity from coal, natural gas, and biogas. A coal-fired power station generating 100 MW of power would produce about 279,000 tCO2e Scope 1 emissions. This amount would be taxed at $6.42 million (U.S. $5.87 million) based on $23/t (U.S. $21/t) carbon.

If biosolids combustion generates 5% of the total power, the Scope 1 emissions would fall and save the generator $315,300 (U.S. $288,000). If biosolids are used in place of a portion of the coal, carbon emissions are reduced by 312 kg CO2e for each MWh resulting from biosolids combustion. Based on a biosolids energy content of 12 MJ/kg (7.3 kWh/lb), combustion of 5 MW equivalent of biosolids would be worth approximately $24/t (U.S. $21.90) dry solids in tax reductions alone.

Using biogas in place of natural gas for 5% of total power would result in a Scope 1 reduction of about 7700 tCO2e/yr, or $176, 200 (U.S. $160,913) annually. Examples of how biogas and biosolids can be used to decrease carbon effects in areas other than commercial power generation are shown in the figure on p. 58 (determined based on NGER methodology).

The Carbon Farming Initiative (CFI)enables farmers and land managers to earn carbon credits by storing carbon or reducing greenhouse gas emissions on the land. These credits then can be sold to people and businesses wishing to offset their emissions. Potentially, use of biosolids in lieu of inorganic fertilizers would be considered emission free and enable farmers using biosolids to claim carbon credits. However, biosolids use is not considered within the CFI.

Although the CPM has subsequently been replaced with an emissions trading scheme, solids processing and biosolids use will have an effect on carbon footprint and ultimately cost to water companies. While the ANZBP study has identified carbon benefits using the existing methodology, several concerns remain with the current calculation methods. If energy recovery and carbon emissions minimization are to be realized fully, it will be critical to accuately identify derived carbon benefits, especially those associated with final use of biosolids.

 

Australia defines terms

Scope 1 emissions refer to the release of greenhouse gases as a direct result of process activities — for example, loss of methane from anaerobic digestion infrastructure and stationary combustion.

In contrast, Scope 2 emissions are those generated by power companies in the production of electricity that is used by the facility. Examples of Scope 2 emissions during solids treatment include power consumed by biosolids dewatering equipment and natural gas required for biosolids drying.

Scope 3 emissions are indirect emissions other than those covered by in Scope 2. Examples include emissions associated with the extraction, manufacture, and production of products that a company purchases; waste-related emissions; and any business travel or employee commuting. Solids-related examples include use of polymer for thickening or dewatering and use of lime for pathogen deactivation.



 

 

Emissions for
1 MWh (kg CO2e)
 

Emissions for 100 MW facility
(tonne CO2e/yr)
 

Emissions for 100 MW facility (tonne CO2e/yr)
(5% biogas or biosolids replacment)
 

Emissions savings
(CO2e/yr)
 

Carbon tax savings ($/yr)*  

Gas combustion  

Natural gas 

185 

162,100 

146,300 

7700 

$176,200 

Biogas 

18 

Coal combustion  

Coal 

318 

278,600 

264,900 

13,670 

$314,300 

Biosolids 

6 

5300 

* Based on AUD $23 (U.S. $21) per tonne CO2e.  

 

Bill Barber is technical director in the Sydney office of AECOM (Los Angeles) and a member of the Water Environment Federation (WEF; Alexandria, Va.) Carbon Resource and Recovery Subcommittee. Greg Priest is program manager at the Australian Water Association (Melbourne). Patricia Scanlan is director of residuals treatment technologies at Black & Veatch (Overland Park, Kan.) and chairwoman of the WEF Residuals and Biosolids Committee.