Law and the Environment : Environmental Lawyer & Attorney : Foley Hoag Law Firm : Boston, Washington D.C.

Late last week, the Massachusetts Department of Energy Resources (DOER) filed with the Joint Committee on Telecommunications, Utilities, and Energy of the state legislature proposed final amendments to the Renewable Portfolio Standard (RPS) regulations governing the eligibility of woody biomass facilities and fuels to qualify to earn renewable energy credits (RECs).  DOER originally issued a draft of these regulations in September 2010, and made revisions after receiving written comments and holding 2 public hearings.  In addition to the revised regulations, DOER issued a regulatory package containing two sets of guidance in the forms of Excel spreadsheets, the Guideline for the Calculation of Overall Efficiency and Lifecycle GHG Analysis and the Guideline for the Determination of Forest Derived Eligible Biomass Woody Fuel. The Joint Committee has 30 days to review the rules and submit its comments to DOER for additional review. DOER hopes to promulgate the final rules early this summer.

At a time when the EPA appears to be favoring biomass a fuel (with actions like exempting it from the tailoring rule for 3 years), Massachusetts is making it very difficult to qualify “electricity only” biomass as renewable and eligible for RECs, as the rules strongly favor combined heat and power uses.   While the proposed changes to the regulation do not ban the development of biomass facilities in Massachusetts, they do set a very high bar to qualify for renewable energy credits under the RPS – so high that many believe that large scale biomass units may not be viable absent significant technological advances. Under the regulation, the term Eligible Biomass Fuel will include things like woody pellets, agricultural waste and by-products, food or vegetative material, algae and biogases, but officially excludes Construction and Demolition Waste.

Eligible Biomass Woody Fuel, the largest subset of eligible fuels, is now limited to forest-derived residues from timber operations, limited thinnings and invasive growth; forest salvage from storms or pest infestations; non-forest derived residues from lumber mills and woodworking shops, trees removed in converting forests to agricultural, residential or commercial uses (so long as all other permits have been obtained), yard wastes, and maintenance of parks and rights of way. The final category of Eligible Biomass Woody Fuel is “dedicated energy crops” which includes wood (but not cellulosic fuel) that has been purposefully grown to produce fuel, but contains a remarkably broad restriction that the trees may not have been grown in a place that “sequestered significant amounts of carbon” such as a forest, or on land that has the potential to support crops grown for human consumption as food. 

Biomass units are required to provide to DOER in their applications a lifecycle analysis of greenhouse gas emissions (GHG) and demonstrate emission reductions of at least 50% over 20 years compared to a new, combined-cycle natural gas generator using the most efficient commercially available technology. DOER will provide a standard analytical methodology in another set of guidance to accompany the Statement of Qualification Application. Under both the proposed regulations and Guidance #1 on GHG lifecycle analysis, facilities must account for direct emissions from production of the fuel stock and delivery to the biomass facility, as well as indirect emissions from land use changes, and temporal changes in forest carbon sequestration and emissions resulting from biomass harvests, regrowth, and avoided decomposition.

One new provision added since the September draft requires that the amount of forest-derived biomass material eligible to be removed be limited based on soil types and as set forth in Guidance #2 on Forest-Derived Fuel.  The regulation and guidance set a cap by percentage of weight of the total amount of material harvested from the site, ranging from zero (for very poor quality soils) to 40% (for highly productive soils) – the rest of the biomass harvested must be left in the forest for soil nutrient retention. To effectuate this requirement, foresters will have to develop a soil map for each harvest area and determine the maximum eligible biomass tonnage that can be removed. The September draft had set this cap at 15% across the board.

Both the September draft and this week’s proposed final rules require that biomass units meet a minimum overall efficiency rate of 40%, determined based on the biomass input heat content of the fuel, and accounting for GHG emissions associated with fuel refining and processing.  If operating at that level of efficiency, the unit will receive one-half REC for each MWh of generation. Units operating at an overall efficiency of 60% and above would receive a whole REC credit for each MWh they generate, and units between 40 and 60% would receive a proportional fraction of a REC.

Under the revised regulations, electricity generated by a unit that is used on-site (“behind-the-meter”) is included in the calculations of the unit’s overall efficiency. “Merchantable bio-products” (chemicals like additives and lubricants) created from the woody fuels at an on-site bio-refinery will also be netted out in calculating overall efficiency.  Finally, and perhaps most significantly, productive use of the large quantities of heat generated by the biomass facilities, so long as it falls within the defined term “useful thermal energy” under the regulation, will also be included in the overall efficiency calculation.  However, the revised regulation clarifies that any thermal energy used to dry or refine green woody biomass for use as a fuel will not count towards overall efficiency.  

Biomass generating units that have already secured their Statement of Qualifications will also have to demonstrate compliance with the new regulation. They must prove use of Eligible Biomass Woody Fuel by 2013, and comply with all provisions, including the requirement for overall efficiency, by 2015.

 

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A recent amendment to the EPA’s Mandatory Reporting of Greenhouse Gases Rule (40 CFR part 98) requires companies that report their emissions to also provide information on corporate ownership,  North American Industry Classification System (NAICS) codes, and whether any of the emissions come from a cogeneration unit. The goal behind collecting this information is to gain a better understanding of the aggregate greenhouse gas (GHG) emissions from corporations and specific industry sectors, and identify potential differences in emissions between otherwise similar facilities due to cogeneration. Such information can be used to guide future GHG regulations and mitigation strategies. The rule was signed by Administrator Jackson last week and is to be published the Federal Register shortly. 

The final rule requires facilities and suppliers reporting GHG emissions (large industrial facilities that emit 25,000 metric tons or more per year, plus suppliers of fossil fuels and industrial gases, and a few others) to include, in their first annual GHG emission report due on March 31, 2011,  the name and address of each US parent company and a breakdown of the percentage share that each parent owns. It also requires the facilities to report any NAICS codes that apply to the facility – both the primary code as well as any others that are appropriate.

The third requirement takes the form of a checkbox indicating whether the report includes emissions from a cogeneration unit, defined by EPA as “a unit that produces electrical energy and useful thermal energy for industrial, commercial, or heating or cooling purposes, through the sequential or simultaneous use of the original fuel energy.”  In the final rule, EPA notes that there are no current programs that require facilities to identify whether they have cogeneration units – EPA’s Combined Heat and Power Partnership is only a voluntary program, and while the Energy Information Administration collects information on cogeneration from power generators greater than 1 megawatt, this program likely does not cover all of the facilities and suppliers subject to 40 CFR part 98.

The information collected on cogeneration through this rule is just a start, and useful primarily to merely identify the facilities using cogeneration. As EPA correctly notes, the information likely will not be sufficient to determine the quantity of GHG emissions occurring from particular NAICS sectors or cogeneration units within an individual reporting facility, or the degree to which cogeneration emissions at the applicable facilities displace onsite use of fossil fuel or other emissions from centralized electric generation. Nonetheless, information on the types and characteristics of facilities that use cogeneration could be important to the future development of GHG mitigation strategies.

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Greenwire reported yesterday that EPA plans to issue its endangerment finding on emissions of greenhouses gases, in response to Massachusetts v. EPA, by the end of April. Greenwire also released EPA’s internal presentation regarding its recommendation to the Administrator.

Although EPA’s anticipated decision is not a surprise, it is still noteworthy. Among the highlights:

• The finding will conclude that greenhouse gas emissions endanger public health (the proposed endangerment finding that the Bush administration EPA had prepared, but then withdrew, was limited to public welfare issues.
• The finding will apparently note that there are environmental justice implications associated with climate change. This is particularly interesting, given that there is also concern that there are equity issues associated with the likely responses to climate change – Warren Buffett this week described a cap-and-trade plan has as a “regressive tax.”
• EPA’s preferred option at this point is to base the endangerment finding on identifying the entire group of GHG as the “air pollutants” that cause the endangerment. One specific rationale is that doing so will facilitate flexibility in setting standards for these pollutants. In other words, if GHG are grouped together, EPA will be able to propose a regulatory program that will allow netting and offsets among the different GHGs. 

Other than the nod to regulatory flexibility provided by grouping GHGs, EPA has not tipped its hand regarding the nature of any regulatory regime for GHGs, let alone when it might be able to propose and finalize such regulations. Doing so remains a gargantuan task. 

Moreover, while EPA is clearly committed to addressing this issue, if one believes the statements of Congressional committee chairs to the effect that climate change legislation will get done promptly, there is a certain logic to waiting for such direct legislative authority. On the other hand, fear of what EPA may do remains part of the calculus on Capital Hill, so EPA may decide to move forward aggressively with regulatory development under current Clean Air Act authority simply in order to keep pressure on Congress. 

It’s going to be a busy – and interesting – year.

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