Despite months of effort, Senate Democrats have been unable to unite in support of a cap-and-trade program or a renewable standard.  A renewable standard requiring utilities to provide 15 percent of their power from renewable sources by 2021 was a key provision in an “energy-only” bill the Senate Energy and Natural Resources Committee approved last year with support from both Democrats and Republicans.  Nonetheless, Senator Reid has decided that he lacks the requisite 60 votes to pass either this standard or a cap-and-trade program.

In addition to the oil spill response provisions, the energy package that Senator Reid says he will push also includes provisions for the creation of clean-energy jobs through the “Home Star” energy efficiency retrofit program, tax incentives for manufacturing of vehicles that run on natural gas, and investments in the Land and Water Conservation Fund.  Reid suggested that many of the bill’s provisions may be based on language from previously-introduced bills; the oil spill response provision, for example, will likely rely heavily on bill S. 3305, sponsored by Senator Robert Menendez (D-NJ), which raises a company’s maximum oil spill liability amount from the $75 million cap set out in the Oil Pollution Act of 1990 to $10 billion. 

Most observers think that cap-and-trade and likely the renewable standard are now unlikely to move in this Congress.  Congress will only have a short session when it returns from the August recess before it adjourns for the elections.  Some have speculated that Congress might take up these issues in a lame duck session after the elections.

After EPA’s issuance of its Endangerment Finding (see Dec. 11, 2009 edition of the WER), EPA in April issued motor vehicle GHG regulations that made GHGs “subject to regulation” under the Clean Air Act.  This “Automobile Rule” triggered air permitting requirements for “major” stationary sources of GHG emissions under the Prevention of Significant Deterioration (“PSD”) program, forcing EPA to issue its “Tailoring Rule” to avoid requiring millions of small emitters of GHGs to obtain PSD permits (see May 14, 2010 edition of the WER).  The first phase of applying PSD to GHG sources is scheduled to begin January 2, 2011, a date that would be significantly delayed with the imposition of a two-year moratorium on EPA regulation of GHGs.

On March 4, 2010, Sen. John D. Rockefeller (D-WV) introduced legislation to impose a similar two-year moratorium on the EPA’s ability to regulate GHG emissions from stationary sources.  According to press reports, when the Senate voted against adopting Sen. Lisa Murkowski’s resolution to overturn EPA’s Endangerment Finding (see June 11, 2010 edition of the WER), Majority Leader Reid promised a vote on Sen. Rockefeller’s bill this year.

 All five panel Republicans, along with two panel Democrats, Reps. Alan Mollohan (D-WV) and Ben Chandler (D-KY) voted against the measure, creating a 7-7 deadlock and preventing the measure’s passage.

The proposed new rule, known as the Transport Rule, would require 31 states and the District of Columbia to reduce power plant emissions of either SO2 or NOx or both.  As with CAIR, the purpose of the program is to address the contribution of upwind states to downwind nonattainment of EPA’s ozone and PM2.5 standards.  The reductions required under the proposed Transport Rule are more stringent than those under CAIR principally because phase two of the CAIR program began in 2015 whereas phase two of the proposed Transport Rule begins in 2014.  In addition, although CAIR provided for a regional cap-and-trade program, the proposed Transport Rule provides only for intrastate trading and limited interstate trading.

Under the proposed rule, SO2 reductions would take place in two phases and would be divided among two groups of states.  Phase one would apply to all 26 states subject to SO2 standards under the rule.  In phase two, 10 states would become subject to significantly more stringent requirements in 2014. 

For NOx, all of the affected states would become subject to both annual and seasonal reduction requirements, and these requirements would become applicable in 2012 and would not change in 2014.  EPA, however, stated that it was still studying whether additional NOx reductions would be required from the EGU sector in 2014 and would have a proposal on that subject in the relatively near future.

Significantly, the proposed Transport Rule addresses compliance with EPA’s 1997 ozone standard and EPA’s annual PM2.5 standard established in 1997 and its 24-hour PM2.5 standard promulgated in 2006.  EPA, however, has already proposed more stringent ozone standards that it expects to finalize this year, and is working on new PM2.5 standards that are likely to be more stringent than the PM2.5 standards addressed in the proposed Transport Rule.  EPA states that it will propose a new transport rule that addresses the new ozone standards in 2011 and finalize it in 2012, and will also propose a new transport rule that addresses the new PM2.5 standards after those standards are finalized.

EPA is proposing one approach under the Transport Rule, but is also taking comment on two alternatives.  In EPA’s preferred approach, EPA is proposing to set a pollution limit for each of the 31 states and the District of Columbia, allowing limited interstate trading among power plants.   In the first alternative, EPA is proposing to set a pollution limit for each state, allowing only intrastate trading among power plants.  In the second alternative, EPA is proposing to set a pollution limit for each state and to specify the allowable emission limit for each power plant.

EPA will take public comment on the proposed rule for 60 days following its publication in the Federal Register.  A full copy of the proposed rule is available here.

All underground coal mines that are already subject to quarterly or more frequent sampling of mine ventilation systems by the Mine Safety and Health Administration (“MSHA”) will be subject to these GHG monitoring and reporting requirements. 

EPA, however, withdrew its proposal that coal suppliers report the imputed CO2 emissions of their coal when it is combusted by end users to whom the coal is sold.  EPA determined that the emissions reports that end users of coal, principally electric generating stations, are required to submit to EPA are sufficient to determine emissions from coal. 

Mines must monitor and report their methane, carbon dioxide, and nitrous oxide emissions at both ventilation and degasification wells or shafts.  No threshold will be implemented for reporting of underground coal mines’ GHG emissions.  However, mines will not be required to measure or report fugitive or surface emissions, as EPA found that such a monitoring requirement would be too difficult and burdensome to implement.

Mines will be required to measure emissions amounts either by quarterly or more frequent sampling, or by continuous monitoring of flow rate and methane concentration.  Mines are now allowed, but not required, to use Continuous Emissions Monitors (“CEMs”) to measure emissions at both degasification and ventilations systems.  Additionally, facilities will be allowed to use CEMs to aggregate their degasification emissions sampling.  Mines may use CEMs to monitor methane emissions at points of aggregation, as long as emissions from all wells, shafts, and boreholes are addressed, and the methodology for calculating total emissions from all wells is documented.

A copy of the rule is available here

EPA’s analysis found that projected allowance prices under Kerry-Lieberman would be $16-$17 per metric ton of carbon dioxide equivalent in 2013 and $23-24 in 2020 (in 2005 dollars).  These numbers are the same as EPA’s allowance cost projections under the Waxman-Markey bill (H.R. 2454) passed by the House of Representatives last year and are highly sensitive to the availability of both domestic and particularly international offsets.  EPA projects domestic offsets as providing 19 percent of the total greenhouse gas (“GHG”) abatement under the bill and international offsets as providing 18-29 percent of the total greenhouse gas abatement.  Without the constraints on international offsets set forth in the bill, allowance prices would dip to $12 in 2013 and $17 in 2020.

EPA’s analysis showed that the bill would have relatively low impacts on U.S. consumers.  According to EPA, average household consumption compared to the business-as-usual scenario would be reduced by 0.0-0.2 percent in 2020, 0.2-0.5 percent in 2020, and 0.9-1.1 percent in 2050. 

EPA utilized the Integrated Planning Model (“IPM”) to simulate near-term (to 2025) changes in the electricity mix as a result of the bill.  According to the IPM model, renewables generation will increase in both the business-as-usual and Kerry-Lieberman cases, and this increase is “largely driven” by the American Recovery and Reinvestment Act of 2009, the so-called stimulus legislation, which provide various tax and other incentives for renewable generation.  According to the IPM model, the Kerry-Lieberman bill will result in less than a 10 percent increase in renewable generation as compared with the business-as-usual case, with most of this increase coming from biomass co-firing which grows by around 35 percent by 2025.

The IPM model assumed 15 GW of additional CCS capacity by 2025 on top of the 2 GW assumed in the business-as-usual case.  Of this 15 GW, 6 GW of new generation with CCS was “forced” into the model based on early deployment funding in Kerry-Lieberman; the model would not have selected this amount on its own.  The other 9 GW of CCS represents retrofits of existing generation facilitated by the bonus and wires charge funding provisions of the legislation.  The IPM model also produced 8 GW of new nuclear capacity by 2025 attributable to the investment tax credit and other financial incentives provided in the bill. 

The model also shows reductions in the use of coal and oil for generation.  Under the business-as-usual scenario 5 GW of coal and 36 GW of oil generation retire by 2025.  Under the Kerry-Lieberman scenario, these numbers increase to 30 GW of coal and 65 GW of oil.  No new conventional coal plants are built, and even with the addition of new coal-with-CCS plants, total coal production for electricity generation decreases, from 1,065 million tons in the reference case to 903 million tons in the Kerry-Lieberman case in 2025.