Ohio Utilities Commission Adopts Long Awaited Energy Efficiency and Alternative Energy Portfolio Standards

Posted on April 20, 2009 by Joe Koncelik

On April 15, 2009 the Public Utilities Commission of Ohio finally adopted the long awaited rules that will govern Ohio's energy efficiency requirements and its Alternative Energy Portfolio Standard (AEPS).  Ohio was one of the last states to have adopted a Renewable Portfolio Standard (RPS)- more broadly defined as a AEPS in Ohio.  However, as one of the largest energy intensive states in the Country the finalization of the rules will surely spur growth of "green energy" related business in Ohio.

As a former regulator, a frequent mantra in describing the decision making process was- "if both sides are unhappy then you know you did your job well."   Well the Commission appears to have followed that mantra in responding to the vast amount of comments that were filed on the rules.  It sided with the Utilities on many issues and it sided with consumer and green groups on many issues.  It rejected many suggestions and complaints by Utilities and it rejected many suggestions and complaints by consumer and green groups.

The rules cover three major aspects of S.B. 221 passed by the Ohio Legislature in the summer of 2008:

  1. Energy Efficiency and Demand Reduction Programs
  2. Alternative and Renewable Energy Portfolio Standards
  3. Greenhouse Gas Reporting and Carbon Dioxide Control Planning

Here is a brief recap of the changes made in response to comments.

Energy Efficiency and Demand Reduction Programs- The Commission completely restructured the rules governing energy efficiency and peak demand reductions.  The Commission revisions where designed to "reflect a focus on the program planning and review process."

  • Cost Effectiveness- added new definitions of "cost effective" and "total resource cost test" that are applied to energy efficiency programs.
  • Procedures for Review of Compliance Plans-  New hearing requirements were added on the planned portfolio of programs offered by an electric utility to meet energy efficiency benchmarks.  The hearing requirement was added in response to criticism that the benchmark review process be opened up and follow traditional Commission rate case procedures.
  • Independent Auditors- Commission requires use of independent program evaluators (hired by the Utility but work at the direction of Commission Staff) to review and verify claimed energy savings and peak-demand reductions
  • Calculating the Baseline for  Measuring Efficiency Improvements- the baseline will be measured by a "rolling average" of the last three years of kilowatt hours purchased instead of a fixed average of 2006 through 2008.  The Commission basically rejected claims by Utilities that using a rolling average keeps raising the bar because it incorporates the energy efficiency improvements each year.  As a result, the Utilities argued the energy saving requirement is closer to 39% than the 22.2% required in S.B. 221
  • Banking "Overcompliance"- Commission will allow Utilities to "bank" over compliance with the energy efficiency benchmark and apply the overcompliance to future years
  • Adjusting for Economic Growth- Baseline can be adjusted to account for either growth or reductions in economic growth.  The idea is to remove the influence of a changing economy on achieving energy efficiency improvements
  • Mandated Efficiency Improvements- Utilities cannot count energy savings that result from customer installed appliances or equipment that are mandated by law including the Energy Independence and Security Act of 2007

Alternative Energy Portfolio Standard- S.B. 221 splits the 25% of electricity energy by 2025 standard into two separate benchmarks- one for "alternative energy" sources and another for "renewable energy sources."  The rules put a lot more teeth into the renewable energy benchmark, including specific interim benchmarks. 

Overall, the Commission did not address significant concern with some of the loose aspects of the Alternative Energy benchmarks.  These include the definition of what constitutes "Clean Coal" as well as what can be counted toward meeting the Alternative Energy Benchmark.  However, as detailed below, the Commission did put teeth into the "cost cap" provisions associated with compliance with either benchmark.

  • RFP- Rejected a suggestion that renewable and alternative energy be procured through a Commission sponsored RFP process to ensure transparency
  • Biomass- with regard to wood resources, the Commission allows use of wood and paper manufacturing waste, urban wood and tree residues, forestry residues, forest management or other land clearing.  However, forest resources must be from "sustainable forest management operations."
  • Clean Coal- the Commission rejected criticism that the current rule would provide credit to technology that is "designed" to reduce CO2 irregardless of whether the reductions are actually achieved.
  • Co-firing- will qualify as a renewable energy resource as determined by the proportion of energy input from the renewable energy resource.
  • "Delivered into this State"- Commission will still require a power flow study and/or deliverability study to show power in the PJM or MISO transmission systems are deliverable into the state.
  • Distributed Generation- renewable energy credits (RECs) generated from distributed energy sources belong to the owner of the equipment
  • "Double Counting"- cannot use one project to meet both the energy efficiency benchmarks and the AEPS
  • "Unbundling"-  Cannot unbundle other positive environmental attributes associated with creation of a REC and sell those attributes separately.  The classic example is you cannot sell the climate change CO2 reductions as well as RECs from one project.  You will have to choose with credits are more valuable
  • Energy Storage- by itself cannot be considered a renewable energy resource
  • Cost Cap- rejected utilities argument that the advanced energy and renewable energy cost caps be aggregated as one 3% cap. Also, rejected claim that the 3% increase is measured by isolating cost of generating the renewable or alternative energy.  Rather, the cost cap is triggered only if overall cost of supplying all forms of electricity rises more than 3% in order to meet the alternative energy or renewable energy benchmarks.  This ruling makes it far more difficult for Utilities to trigger the cost cap provisions.
  • "Catch-up Provision- Commission effectively drops the requirement that future year benchmark compliance requirements be increased by the amount of undercompliance of the previous year due to the 3% cost cap

Greenhouse Gas Reporting Requirements

The Commission rejected concerns raised by Utilities regarding the mandate in the rules to become participating members in the Climate Registry.  The Commission noted that  S.B. 221 requires reporting and tracking of CO2 emissions must be performed.

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EPA Proposes Greenhouse Gas Reporting Rule

Posted on March 16, 2009 by Joe Koncelik

In accordance with the FY2008 Consolidated Appropriations Act, the U.S. Environmental Protection Agency (EPA) has issued its proposed rule to require annual mandatory reporting of greenhouse gases from over 13,000 businesses.  Businesses covered by the rule must start tracking emissions by 2010 and report in 2011 on an annual basis. While specific sources are named, EPA has decided to use an emission threshold of 25,000 metric tons of CO2 equivalents (mtCO2e) to determine coverage for many businesses under the rule. 

The details of the EPA reporting rule may provide a glimpse into the structure of President Obama's Cap and Trade program.  For example, the 25,000 mtCO2e and specifically named source categories may be used to determine which businesses are covered by the cap.  It is also important to note, the coverage of the reporting rule contrasts with much lower threshold triggers used by other regulatory programs under the Clean Air Act.

Which gases are covered by the rule?

U.S. EPA will require reporting of anthropogenic GHG emissions covered under the United Nations Framework Convention on Climate Change (UNFCCC); carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), and sulfur hexafluoride (SF6), as well as other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers). These gases are often expressed in metric tons of carbon dioxide equivalent (mtCO2e). 

All the other GHGs have higher potential to cause global warming.  Therefore, as with other the European Union Trading System, a conversion ratio is applied to create carbon dioxide equivalents.  For example, 1 ton of methane is equal to 20 tons of CO2.  These conversion ratios are important to understand because they determine which businesses are covered by the reporting rule.

For example, a large agricultural operation will have significant emissions of methane.  The facility will need to convert its methane emissions to CO2 equivalents to determine if it is a facility covered. [Note: most agricultural operations are exempted from coverage under the rule]

How did EPA pick the 25,000 mtCO2e threshold?

EPA considered thresholds of 1,000, 10,000, 25,000, and 100,000 mtCO2e/year when developing the proposal. For each threshold, EPA assessed the number of facilities that would be covered as well as the total amount of emissions that would be covered. These analyses suggested that at a threshold of 25,000 metric tons of mtCO2e/year, 13,000 facilities and 85-90% of total GHG emissions would be covered. At a threshold of 10,000 mtCO2e/year approximately 20,000 facilities and 86-91% of GHG emissions would be covered.  EPA felt reducing the threshold increased costs for smaller businesses and would not result in a significantly larger inventory of emissions.

Are other facilities with lower than 25,000 mtCO2e required to report?

Yes.  EPA also named specific source categories that are covered by mandatory reporting regardless of whether they cross the 25,000 mtCO2e threshold.  These sources include, among others, the following: electric generating plants subject to the Acid Rain program, aluminum, ammonia, cement, electronics, lime, petrochemical, petroleum refining, certain underground coal mines, manufacturers of engines, and municipal landfills.

EPA also included "downstream" sources.  Those facilities that produce fuel that when burned result in GHGs emissions.  This producers include: coal, coal-based liquid fuels; petroleum products, natural gas and natural gas liquids; producers of industrial greenhouse gases as listed in the rule; and importers/exporters of 25,000 mtCO2e. 

How will this affect small and medium sized businesses?

Using this threshold,  EPA estimates this will capture 90% of GHG emissions and require 13,000 businesses to report. In rolling out its proposed rule, EPA tries to deflect criticism leveled by the U.S. Chamber and others that  EPA GHG regulations will have a negative impact on small and medium sized businesses.  EPA provides the following fact relative to the 25,000 threshold:

25,000 mtCO2e are equivalent to emissions from annual energy use of about 2,200 homes. It is also equivalent to just over 58,000 barrels of oil consumed or 131 railcars’ worth of coal.

This statistic does give you some perspective on the magnitude of the sources covered by the reporting rule.  However, just because these larger sources are covered by the reporting rule does not necessarily mean that regulation of GHGs under the Clean Air Act would not capture much smaller sources.  For example, the New Source Review permitting threshold for a major source is 100/250 tons of a pollutant.

What is the method for monitoring emissions?

EPA selected a combination of direct measurement and facility specific calculations as the general monitoring approach.  Direct measurement will require Continuous Emission Monitors (CEMs) on some sources.  Other sources will have to use emission calculations designed for that type of facility. EPA asserts that the emission calculations are similar to those used in other programs such as the Climate Registry or California's AB-32. 

Consistency is an important issues.  EPA estimates the cost to report will be around $13,000 per facility.  This is an average which means it will be much higher for some facilities.  Many companies have voluntarily begun measuring emissions under the Climate Registry or another approach.  Other companies are covered by mandatory state programs like RGGI. 

The ability to agree on a common method for measuring emissions is critical.  It will reduce compliance costs and prevent criticism that there are inconsistencies in the various programs.  For these reasons, the comments on this portion of the rule are critical. 

Has there been an early criticism of the rule?

Yes.  The largest amount of criticism has been focused on the reporting requirement being applied to both upstream and downstream sources of GHGs emission.  As an example, the coal mine and the power plant who later burns the coal are both required to report under the rule.  Some have criticized this approach as "double counting" or a waste of resources.  Others have pointed out that EPA needs to gather a range of data to keep policy options open for controlling GHGs. 

Additional Information:

For more information on the rule, see EPA's web page dedicated to the GHG reporting rule.  Also, EPA has prepared a four page fact sheet that does a good job summarizing the major components of the rule.

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