The first change: which we knew was coming; New Jersey is officially out.  The second:  the reserve price, the lowest price at which allowances may sell, has been increased by 4 cents to $1.93, in line with the Consumer Price Index.  The third:  although RGGI usually offers allowances from two different compliance periods for sale at each auction, March's auction will offer only 2012 allowances, raising some questions about RGGI's own view of its future past this compliance period's end in 2014.  The fourth change:  the participating states announced that they will retire 87 million of the allowances that went unsold during the 2009-2011 auctions, a move that may indicate the states' willingness to set the cap for 2012 below the earlier levels, to avoid such over-allocation of allowances in future years.

The original plan for the RGGI program, when it was introduced in 2008, was to set the emissions cap on large power plants in the Northeast at 188 million tons (estimated 2005 levels) through 2014, then lower the cap by 2.5% per year over the next four years, for a net change of 10%.  But in the intervening years, emissions in the Northeast have declined significantly due to decreasing generation from higher-carbon dioxide sources such as fuel oil and coal, increasing generation from natural gas and renewable, carbon-free sources, and expanded energy efficiency programs -- many of which were paid for by funds collected by the states through the RGGI auctions.  As a result, emissions are now far below the planned reductions already -- 2011 emissions were 34% below the cap, according to Environment Northeast's analysis released last week.  As these changes in emissions are expected to be permanent, the RGGI cap would have to be lowered by a significant amount before the cap-and-trade program became the driving factor in carbon reductions.  

The participating states are currently working on a planned comprehensive review of the RGGI program, with the most recent topics of discussion including evaluating the use of offsets and other cost-containment mechanisms in the future.  While the participating states' willingness to retire the unsold allowances from the first compliance period may be a signal of their intentions to re-set the cap for the 2012-2014 compliance period as well, it remains to be seen whether the states will merely adjust the cap to reflect observed emission trends or try to create even further cuts in emissions. 

The report does not try to predict what will happen or should happen to RGGI to update it for 2012 and beyond. Instead, it takes the last three years as a snapshot, and models the impacts that the allowances sold and money spent by the states through the last 3 years will have over the next 10 years.

Overall, the 10 states took in $912 million from the auctions, which, when invested by the states in various programs and initiatives, added $1.6 billion in net present value to the region's economy, even when taking into account the nearly $1.6 billion loss in income that power producers face with more efficient energy usage reducing prices and consumption. The report also found that the first three years of RGGI have created over 16,000 new “job years” – from employing people to conduct energy efficiency audits or install efficiency measures,  to maintaining workers in state-funded programs that might have been cut had a state not used RGGI funds to close budget gaps.

The study found that, although the cost of the allowances was largely passed along to consumers, RGGI only increased consumers’ bills by an average of 0.7% over the last 3 years. The study predicts that, over time, RGGI will lower consumers’ bills, because the states invested a substantial amount of the allowance proceeds on energy efficiency programs.  By 2021, consumers of electricity in the 10-state region will enjoy a net savings of nearly $1.1 billion on their electricity bills, and, due to efficiency programs focused on insulation and heating efficiency, another $174 million in savings from avoided expense on natural gas and heating oil. 

The analysis I found the most interesting concerns how state decisions to spend RGGI proceeds affected local economies. The Memorandum of Understanding that set up RGGI required that the states invest at least 25% of the proceeds for “public benefit,” but left the rest up to each state. As a result, there was a divergent approach to spending that, according to today's report, resulted in significant differences in returns.

New England states spent 86% of their RGGI funds on energy efficiency, and only 3% on direct  assistance to low-income consumers. Because the investment in energy efficiency introduced funds into the economy twice – both when the state paid into the efficiency program, and when consumers paid less for electricity, leaving them free to spend elsewhere in the economy – the overall macroeconomic impact of RGGI in New England was almost $900 million, even though those states only took in $275 million in allowance funds.

In comparison, the states in the PJM regional transmission organization (New Jersey, Delaware and Maryland), spent 41% of their funds on direct bill assistance and only 13% on energy efficiency.  The direct bill assistance also freed consumers to spend money elsewhere in the economy, but the analysis found that, without the multiplier effect of energy efficiency, the returns for these states were not as great.   As a result, although these three states received more money from allowance sales than New England -- $310 million – the net positive impact of RGGI was only $341 million.

It’s not much of a surprise that the investment of auction proceeds in energy efficiency is one of the big success stories of the first three years of RGGI. Nonetheless, it will be interesting to see whether the report’s conclusions regarding the relative impact of spending on energy efficiency as compared to low-income assistance will influence how states spend their auction proceeds going forward. 

The Greenhouse Gas Protocol Initiative (a collaboration between the World Resources Institute and the World Business Council for Sustainable Development) finalized its two newest global greenhouse gas standards on October 4. The GHG Protocol are the most widely used suite of accounting tools for measuring, managing and reporting greenhouse gas emissions -- for instance, in 2010, more than 85% of the nearly 2,500 respondents to the Carbon Disclosure Project survey used these standards. With the addition of the two new standards -- the Corporate Value Chain (Scope 3) Accounting and Reporting Standard and the Product Life Cycle Accounting and Reporting Standard -- companies have more guidance on a methodology and common language to report the impacts of their operations as they span the supply chain and the life cycle of their products. The GHG Protocol website even includes a cute video to explain what Scope 3 emissions are and why they claim these new protocol will save the world.

The new standards, which have taken three years to develop, involved the input of close to 2,500 partners, and were actively road-tested by 60 companies from 17 countries. The final standards have been influenced by the many comments received since they were published in draft form last November, and are intended to build upon the GHG Corporate Standard from 2004 which details how to report Scope 1 emissions (direct emissions from sources a company owns or controls, like factory smokestacks and company-owned cars) and Scope 2 emissions (indirect emissions attributable to the electricity, heat and cooling the company directly consumes).

Scope 3 emissions, which include everything else, are the great unknown variable in greenhouse gas reporting. They contain the vast majority of emissions, and accordingly, have the biggest opportunities for reductions. The authors of these new standards hope that they provide companies with a “treasure map” to identify and locate these opportunities to help both the environment and the business’s bottom line. At the very least, these protocol will simplify and reduce the costs for companies taking on a Scope 3 inventory, and improve the relevance, completeness, consistency, transparency and accuracy of the emissions reported each year. 

The key conclusion the IG reached is that the Technical Support Document (TSD), in which EPA summarized the results of the leading scientific assessments on climate change, did not meet the OMB’s peer-review requirements. The problem turns on whether the TSD was a “highly influential scientific assessment” -- defined in the OMB regulations as an assessment that could have an impact on the public or private sector of more than $500 million in one year or is novel, controversial or precedent setting.   Such assessments require more attention to peer review, and agencies have to follow specific peer review procedures laid out by the OMB and certify that they have done so. 

The IG concluded the TSD was a "highly influential scientific assessment" because EPA weighed the strength of the available science and chose what information to include.  In summarizing the world of data down to a manageable document, the IG argues, EPA made choices that qualify as science. EPA officials, on the other hand, argue that the TSD does not meet this threshold, since it does not contain any new science or conclusions.  Instead, it's more of an annotated bibliography, summarizing findings from prior studies, all of which had been extensively peer-reviewed. 

The EPA’s Peer Review Handbook allows use of already-peer-reviewed studies to support EPA decisions, so long as the EPA checks to see whether the earlier peer review meets its standards. The IG criticizes that EPA didn’t certify to this double-checking in any of its publicly released documents.  Additionally, although the EPA did have the TSD reviewed by a panel of 12 climate change scientists before publishing it, the IG concludes that this did not meet the OMB requirements for a “peer review” because the review results and EPA response were not publicly reported, and one of the twelve panelists was an EPA employee.   

The story that EPA failed to follow its own procedures in analyzing the science behind this critical decision certainly reads well, and could be very potent fuel to add to anti-EPA rhetoric.  But my conclusion is that this dispute seems manufactured, or at the very least, far too focused on form over function and style over substance. Although the quality of data in science is a real issue, the primary issue here seems to be that EPA could have been better at showing its work, rather than a question of whether it, or the world's climate scientists, did the work to begin with.  

AES Corporation is a defendant in Native Village of Kivalina v. ExxonMobil Corp., which alleges that the utility's emissions contributed to the rising sea levels that are endangering the Alaskan village, located on a barrier island.  That suit was originally dismissed in 2009 on the grounds that regulating greenhouse gas emissions was a political issue that needed to be resolved by Congress, rather than by courts, and an appeal is pending before the 9th Circuit Court of Appeals.

Steadfast Insurance Company, which was defending AES under a reservation of rights, filed this suit, seeking a declaratory judgment that the commercial general liability policies AES held did not require it to provide insurance coverage.  The Virginia Supreme Court upheld the decision of the lower court, finding that Steadfast owes no duty to AES because the allegations in the Kivalina complaint do not constitute an "accident" or "occurrence" within the meaning of the policies.

AES had argued that Steadfast's duty was triggered because the plaintiffs in Kivalina accused it of negligence -- the classic event that triggers CGL policies.  However, the language of the policy required Steadfast to defend AES against claims for damages of bodily injury or property damage caused by an occurrence or accident, with "occurrence" defined as "an accident, including continuous, repeated exposure to substantially the same general harmful condition."   The court found that the Kivalina lawsuit did not meet this definition, because the complaint alleged that the utility intentionally emitted carbon dioxide, and knew or should have known that the impacts of its emissions would lead to global warming and effect vulnerable communities like this coastal Alaskan village. 

The Virginia judge found that, even if AES was ignorant of the effect of its actions and did not intend to cause harm, Kivalina still alleges that the damages were a natural and probable consequence, not a fortuitous event or accident, as Virginia law requires for insurance coverage to be triggered.  Consequently, the judge concluded that, "whether or not AES's intentional act constitutes negligence, the natural and probable consequence of that intentional act is not an accident under Virginia law."

It is important to remember that, since insurance cases are decided under state law, this decision applies only to Virginia and this particular policy, and it remains to be seen whether other courts will follow the same rationale.  As plaintiffs bring new climate change claims under state tort law and based on creative legal theories, other courts may reach different conclusions about whether the unintended effects of intentional emissions can ever be an "accident." 

The report analyzes the responses the Global 500 companies submitted to a questionnaire that has CDP has sent on behalf of institutional investors every year since 2002.  Participation has increased each year -- up to 81% for 2011 -- as has the quality of the companies' answers and reporting, and the targets and goals that companies set for themselves.  This year's results show significant progress by all of the reporting companies in a few key areas, such as 74% of respondents setting greenhouse gas reduction targets, and 59% reporting a payback period of 3 years or less on their emission reduction activities. This year's survey also marked the first time that a majority (68%, up from 48% in 2010) of respondents have integrated carbon reduction efforts into the heart of their business strategies.

The set of 58 companies that doubled the returns of their peers were listed by CDP as part of the Carbon Disclosure Leadership Index (CDLI) (those that scored the highest on carbon emission measurement techniques and subsequent public disclosure) and Carbon Performance Leadership Index (CPLI) (those that fell within the top 10% of respondents when scored on strategic commitment to the business issues related to GHG emissions, energy use, and climate change).  There were 23 companies who made both lists.  Companies in Canada, Japan and the US were under-represented on these lists, compared to their peers in Australia, Germany, Italy, Switzerland and the U.K.  Surprisingly, given the regulatory focus it faces, the energy sector lags behind other sectors with the lowest proportion of companies setting targets (55%) and under-representation on both the CDLI and CPLI.

What did the CDLI and CPLI companies do differently?  As the report highlights, one notable difference between the companies named to the CDLI and those that were not is the practice of setting emissions reduction targets on which the company places significant emphasis -- 96% of the CDLI companies have emissions reduction targets, versus just 70% of the remaining companies.  Also significant seems to be whether the companies dedicated resources and time to identifying the new opportunities, investments and potential partnerships that a low-carbon economy could bring about -- the average score for the CDLI companies on this rubric is 88 (out of 100) compared to 54, across all respondents.  Similarly, all 29 of the CPLI companies have integrated their climate-related risks and opportunities into their business strategy, and used monetary incentives to encourage employees to meet carbon reduction goals.  The CPLI companies also universally submitted their emissions data for adequate verification -- something that only 37% of the remaining companies did, despite the importance of providing investors validated data.

Although the authors of the report argue that this data is a clear indicator that it makes good business sense to manage and reduce carbon emissions, correlation is not necessarily causation.  The companies who are better managing their carbon may just be better managed overall, leading to better performance.  Either way, the fast-rising number of Global 500 companies who are moving to capitalize on these opportunities highlights that more sustainable business models are, increasingly, simply the way business is done.

The states other than New Jersey then held an auction offering 1.8 million allowances from vintage year 2014, which can be used to comply in the next compliance period, from 2012-2014.  In perhaps the most direct sign of uncertainty for the future of RGGI, no one bid on these allowances. 

Per the Market Monitor report, there were not any market barriers to bidding in the auction of future compliance period allowances.  Bidders were just not interested.  The future of RGGI could seem  uncertain to would-be-bidders, between member states' reconsidering their involvement -- for instance, New Hampshire's Senate recently failed to overturn a veto by the Governor of a bill that would have removed the state from the program -- and RGGI, Inc.'s ongoing comprehensive review of the program for the new compliance period. 

In addition, the compliance entities, who are estimated to own 97% of the allowances in circulation, might feel that they have enough allowances already.  In the press release accompanying the monitor report, Maine's Public Utilities Commissioner chalked the low sales of the auction up to reduced emissions across the RGGI region, arguing that the states' investment in energy efficiency have worked.  With lower emissions, fewer allowances are needed.  Since RGGI allows banking, but not borrowing, extra allowances from the 2009-2011 compliance period can be used in the 2012-2014 period, but not the other way around.  As a consequence, the over-allocation of allowances to this early period could make sales of RGGI allowances in the second compliance period sluggish, even without the added political uncertainty.

The interagency task force charged with evaluating barriers to CCS concluded in a report released last year that the chief obstacle for CCS was regulatory uncertainty, since most of our environmental laws do not contemplate such a technology.  The task force recommended that EPA implement regulatory changes such as this hazardous waste clarification. 

But the biggest barrier remains -- without comprehensive climate legislation and a price on carbon, there is no stable framework to encourage investment.  And this barrier is taking its toll.  This uncertainty is why AEP recently shelved plans to build a $668 million CCS retrofit on its Mountaineer coal-fired electric plant in West Virginia.

Although the outlook for CCS projects within the U.S. is thus uncertain, the United Nations' support of the technology could prompt some CCS projects in developing nations.  E&E reports today that a decision to allow CCS projects to be eligible for credits under the Clean Development Mechanism may soon be forthcoming, if technical issues such as monitoring and verifying reductions, and environmental safety and insurance coverage can be resolved.  

Other international organizations are also jumping on the CCS bandwagon.  A recent report by the International Energy Agency's Greenhouse Gas R&D Program touts the potential benefits of combining CCS with biomass facilities, particularly in Asia and Latin America.  The IEA theorizes that because the plant life used to make biomass fuels absorbs CO₂ from the atmosphere, subsequent storage of the CO₂ released from highly efficient biomass processes could actually reduce global atmospheric concentrations of carbon.  It's like how celery has negative calories.

The report asserts that we technically have the potential to annually remove from the atmosphere up to 10 gigatons of CO₂ -- or about 1/3 of annual global emissions -- through the use of biomass integrated gasification combined cycle plants and CCS.  A more economically-feasible implementation of these nascent technologies would still lead to reductions of 3.5 metric gigatons of CO₂ annually.  Notably, even this "feasible" scenario assumes that CO₂ will be priced at 50 euros ($71) per ton, worldwide.  Even in dreams of what could be, the development of CCS still has to face the obstacle of the price on carbon.

The challenged provisions in the 2007 energy law require manufacturers to make new bulbs that use approximately 27% less electricity by 2014. That’s all.  As reported in recent stories, manufacturers rose to the challenge, already putting incandescent bulbs into stores that are 30% more efficient than the traditional models and sell for only slightly more.  Such bulbs will save the average family – including Texans – about $100 per year.  What’s more, the lighting industry supports the new standards.

The recent supposed controversy over an energy efficiency measure that easily passed Congress with wide bipartisan support, was signed into law four years ago by President Bush (yet another Texan), and now bears the support of not only environmentalists and consumer groups but also the regulated industry itself, is more than a bit surprising, even in today's highly partisan Congress.

But not as surprising as what’s going on in Texas itself. In late June, Governor Rick Perry signed into law HB2510, a bill that overrides the federal mandate for incandescent bulbs made and sold in Texas, so long as they have “Made in Texas” clearly stamped on them.   The law requires the attorney general to defend citizens of Texas from prosecution by the federal government for manufacturing or selling such light bulbs in the state. It is difficult to see how the Texas legislation could survive constitutional challenge, though the bill analysis prepared for state legislators states that,  “whatever the outcome, protecting the rights of Texas manufacturers is well worth the constitutional fight.” 

Which begs the question: are there actually any manufacturers of incandescent light bulbs in Texas?  As it turns out, No.  But there are LED light bulb manufacturers.

This sharp drop in the sale of allowances at auction is surprising, particularly given that the last auction, held in March, sold out of allowances for the first time since Auction #8.  The number of participants who qualified to bid at the March and June auctions did not differ much -- 49 and 47, respectively -- but the number of participants who actually submitted bids fell sharply, from 36 to 25.  An even more significant difference is the number of allowances that each of these bidders bought.  For instance, while the top two bidders in March bought over 10 million allowances each, the top bidders in June bought just 2.6 million and 1.9 million respectively. 

As yesterday's ClimateWire highlighted, theories about the causes of this surprising drop abound.  My favorite is that companies regulated by RGGI already have most of the allowances they will need to cover their emissions in the compliance period ending in December, and these unsold allowances are primarily due to the excess supply under the RGGI cap.  Other theories cite to New Jersey's recent announcement that it would withdraw from the program by the end of the year as a sign to would-be-buyers that the program is threatened.  But New Jersey's break with RGGI will not be as quick as initially reported.  The official letter from New Jersey's Commissioner of the Department of Environmental Protection outlines that the state will continue to participate in the allowance auctions for calendar year 2011, as it did in the June auction last week, and that regulated power plants in New Jersey are not being relieved of their obligation to hold sufficient allowances to cover their emissions in the initial compliance period, which ends on December 31, 2011. 

Despite Governor Christie’s announcement, official withdrawal from RGGI requires legislative action, namely repeal of the provisions of New Jersey’s Global Warming Solutions Fund Statute that established the cap-and-trade program within the state.  Currently pending before the New Jersey legislature is a bill that would repeal these sections and transfer any remaining money from allowances into the state's general fund.

So what happens now?  Will the nine remaining states reduce their own RGGI allowance budgets in order to recognize the NJ allowances already sold?  Or will they proceed as if New Jersey was never part of the program in the first place, and invalidate the allowances? 

In the press release responding to the announcement, the organization said only that “the participating states will evaluate how New Jersey’s proposed withdrawal might affect New Jersey allowances currently in circulation.”   It will be interesting to see if the New Jersey-based power plants which have been buying allowances along the way at quarterly auctions, in preparation for the end of the 3-year compliance period this December, will demand a refund from the state for their potentially worthless allowances. In addition to the loss of significant RGGI-allowance revenue going forward, this could create a problem for this already cash-strapped state.   

In the last two years, New Jersey took in over $113 million from the sale of allowances in the nine auctions in which it participated. This money was divided up in a number of ways – including the Governor’s recent withdrawal of $65.2 million to balance the current state budget.  New Jersey has also already awarded $29.6 million in allowance proceeds to 12 large scale energy efficiency and renewable energy projects through its Clean Energy Solutions Capital Investment Loan/Grant Program. According to New Jersey's statements through the RGGI website, these programs would create enough renewable energy to meet the demands of more than 19,600 New Jersey households each year, and would avoid 1.7 million tons of CO₂ over the lifetime of the projects.  

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.

 

The TVA operates 59 coal-fired boilers at 11 plants in Alabama, Kentucky and Tennessee, and supplies power to around 9 million people in its service area that spans most of the southeastern US. The settlement involves all 11 plants, and includes an obligation to address 92% of TVA’s coal-fired system between 2011 and 2018 by either installing state of the art pollution controls like SCRs and FGD or repowering with renewable biomass. Another 18 coal-fired units, about 16% of TVA’s coal-fired generating system, totaling 2,700 MW of capacity, will be permanently retired – the largest retirement commitment seen under EPA’s Coal-Fired Power Plan initiative, which has settled 22 such NSR cases so far.  However, Greenwire reports that, even before today's announcement, TVA was already planning to retire about 1,000 MW of coal-fired capacity.

I found the option to repower the units with renewable biomass to be particularly interesting, especially given EPA’s current proposal to continue studying biomass emissions for three years before requiring Clean Air Act permits for greenhouse gas emissions from biomass sources.  In the agreement, “Renewable Biomass” is defined very broadly, with no time-frames or extensive restrictions. Instead, it includes, in part, organic matter that comes from forests or grasslands, as well as residues and byproducts from agriculture, forestry and paper industry. Under the agreement, the repowered units would be deemed “new” emission units, themselves subject to New Source Review and other permitting requirements.

The settlement also includes $10 million in penalties -- $8 million paid to EPA, $1 million paid to Tennessee and $500,000 each paid to Alabama and Kentucky -- as well as $350 million in environmental mitigation projects, including $240 million to be spent on TVA-run energy efficiency projects and $60 million to be divided among Alabama, Kentucky, North Carolina and Tennessee for the states to implement projects of their choosing, so long as they're within the categories specified in the consent decree.

The report identifies five categories of climate risks and opportunities: regulatory risk and opportunity; indirect consequences or business trends; physical impacts; greenhouse gas emissions; and strategic analysis of climate risk and emissions management. Using a system to rank various disclosures within these categories as poor, fair, and good – no company’s practices qualified as “excellent” – the report provides specific examples of what works and what does not.  

The report also includes an 11-point checklist with recommendations for improving disclosures. The recommendations include integrating consideration of climate risk and opportunity throughout the firm, creating a board-level committee with specific responsibility for climate change risks, and using specific numbers and dollar figures in disclosures to quantify emissions, risks and opportunities whenever possible. 

Of course, the report is not legal advice on what any company should disclose to the SEC, and Ceres has no authority to require companies to follow its suggestions.  Ceres is a network of investors, environmental organizations and other public interest groups with a mission to integrate sustainability into capital markets.  Not surprisingly, the report promotes that agenda, ranking the more specific disclosures higher, and encouraging increased transparency in companies' reports.

Other reports and resources also provide guidance in this area: both general statements of investor expectations such as the Global Framework for Climate Risk Disclosure and the ASTM Standard on Financial Disclosures Attributed to Climate Change; as well as sector-specific rules and guidance like the National Association of Insurance Commissioners’ Insurer Climate Risk Disclosure Survey, and the Global Climate Disclosure Frameworks for the oil and gas, automotive, and electric utility sectors.

The 2020 Plan announces a portfolio of policies in five categories – buildings, electricity, transportation, non-energy emissions, and cross-cutting policies (essentially agency procedures that do not fit into the other categories) – representing the suite of policies that the Patrick-Murray administration is committed to pursuing over the next four years, to work toward the 2020 emissions limit.  Together, the policies could result in as much as a 33% reduction of greenhouse gases below 1990 levels, and set the groundwork for the 80% reductions required by 2050 under the GWSA.  EEA also predicts that these policies will reduce Massachusetts’ reliance on imports of energy and fuels, and create or maintain 42,000 to 48,000 jobs in Massachusetts in 2020.

For a summary of specific points included in the 2020 Plan, keep reading after the jump.
 

Buildings: 9.8% reduction of state-wide GHG emissions by 2020
•    Existing Policies:
o    All Cost-Effective Energy Efficiency: building energy improvements under the GCA, which involves a $2 billion investment from 2010-2012
o    Federal Appliance and Product Standards: DOE has announced accelerated schedule for setting new energy efficiency standards
•    Expanded Policy:
o    Advanced Building Energy Codes: commitment under the GCA to adopt the latest IECC, plus local-option “stretch” code that has been adopted by over 60 municipalities
•    New Policies:
o    Building Energy Rating and Labeling: a pilot program in western Massachusetts to assign residential buildings ratings based on their energy efficiency (equivalent to EPA’s miles-per-gallon rating for cars); DOER is also developing a pilot in eastern Massachusetts to rate commercial buildings
o    “Deep” Energy Efficiency Improvements: pilot programs with utilities making rebates and appropriate training and technical support widely available for significant retrofits for residential buildings
o    Expanding Efficiency Programs to Commercial/Industrial Heating Oil: expanding current electric utility programs to provide funding for heating-related efficiency measures in commercial and industrial buildings using fuel oil for heat
o    Developing a Market for Solar Thermal Water and Space Heating: for both residential and commercial buildings
o    Tree Retention and Planting to Reduce Heating and Cooling Loads: pilot program to provide incentives to plant new trees around existing housing and retain trees in new housing developments

Electricity Supply: 7.7% statewide GHG reduction
•    Existing Policies:
o    Massachusetts Renewable Portfolio Standard (RPS): requiring 15% of electricity supply to come from renewable sources by 2020
o    Regional Greenhouse Gas Initiative: regional cap-and-trade program resulting in 10% reductions in CO2 emissions from large electric generating units
•    Expanded Policy:
o    Clean Energy Imports: building new transmission line(s) for import of Canadian hydro-electric power
•    New Policies:
o    More Stringent EPA Power Plant Rules: EPA plans to implement a variety of regulations that will affect air and water emissions at power plants; this may result in the closure of some of the older, smaller power plants
o    Clean Energy Performance Standard (CPS): would require electricity suppliers to favor lower- and no-emissions sources  

Transportation: 7.6% state-wide GHG reduction
•    Existing Policies
o    Federal and California Light Vehicle Efficiency and GHG Standards: federal CAFE standards are being raised for model year 2016, and California is expected to adopt even stricter standards for 2017 and forward.  Massachusetts law requires the Commonwealth to adopt the California standards.
o    Federal GHG Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Vehicles: EPA and US Department of Transportation programs to improve fuel efficiency for model years 2014-2018
o    Federal Renewable Fuel Standard and Regional Low Carbon Fuel Standard: although the exact programs are still developing, federal and Massachusetts law require an increase in the volume of renewable fuels to be used and the average carbon intensity of vehicle fuels to fall by a specific percentage compared to petroleum fuels
o    Sustainable Development Principles: 2007 program to make state investments increase the amount of growth in locations and densities that reduce vehicle miles traveled and GHG emissions, or create other clean energy benefits
•    Expanded Policy:
o    Smart Growth Policy Package: policies to focus on influencing infrastructure investments by state agencies and planning decisions made by local governments to reduce the number and distance of vehicle trips
•    New Policies:
o    Clean Car Consumer Incentives: EPA and MassDOT will conduct a study to examine the best methods for the Commonwealth to provide incentives to consumers to shift their vehicle purchases to more fuel-efficient or lower GHG emitting models
o    Pay As You Drive Auto Insurance Pilot: encouraging insurance companies to offer programs that convert annual premiums into a variable cost based on miles traveled
o    GreenDOT: announced through a policy directive by MassDOT in June 2010 to reduce GHG emissions, promote the healthy transportation modes of walking, bicycling and public transit and supporting smart growth development

Non-Energy Emissions: 2.0% state-wide reduction
•    Expanded Policy:
o    Reducing GHG Emissions from Plastics: by diverting plastics from the waste stream through increased recycling efforts
•    New Policies:
o    Reducing GHG Emissions from Motor Vehicle Air Conditioning: Massachusetts law requires adoption of California’s vehicle emissions standards, which may be expanded include regulations to minimize the global warming potential of refrigerants, increase efficiency, and reduce leaks
o    Stationary Equipment Refrigerant Management: beginning with a voluntary pilot program focused on leak detection and repair for facilities with refrigeration units containing at least 50 pounds of refrigerant
o    Reducing SF6 Emissions from Gas-Insulated Switchgear: a pilot program and possible regulation to minimize leakage of this gas used in electricity transmission and distribution systems

Cross-Cutting Policies: reduction not quantified in 2020 Plan
•    Existing Policy:
o    Green Communities Division of DOER: established under the GCA, this office assists communities qualify for grant funding as Green Communities
•    Expanded Policies:
o    MEPA GHG Policy and Protocol:  adding the requirement for some projects undergoing MEPA review to quantify their GHG emissions and identify measures to avoid, minimize and mitigate such emissions
o    Leading By Example: program established in 2007 to oversee state efforts to reduce carbon emissions across state government buildings and procurement, potentially expanded to include purchasing and managing clean energy
•    New Policies
o    Consideration of GHG Emissions in State Permitting, Licensing and Administrative Approvals: as required by the GWSA, all state agencies, departments, boards, commissions and authorities would take into account GHG emissions and other climate change impacts when issuing permits, licenses or other approvals.  EEA will collaborate with other agencies to develop a plan to implement this requirement in particular agency actions.

 

10)  In the Auction, 24,755,000 allowances from the 2009-2011 compliance period sold for $1.86 each (the floor price);

9)  That amount is only 57% of the 2009-2011 allowances offered for sale, the lowest yield from a current compliance period auction;

8)  38 entities bid on these current compliance period allowances, down from 45 in September and 51 in March;

7)  The generators subject to RGGI compliance and their affiliates (collectively "compliance entities") purchased 97% of the current compliance period allowances sold;

6)  1,172,000 allowances from the second compliance period (2012-2014) were also sold at $1.86 (the floor price);

5)  That amount is 57% of the 2012-2014 allowances offered for sale -- the lowest yield to date for this vintage of allowances -- and 100% of them were bought by just 4 compliance entities;

4)  In the 10 RGGI auctions, taken together, compliance entities have purchased 85% of all allowances sold;

3)  Due to trading on the secondary market, after the 10th auction purchases are settled, compliance entities will hold 95% of all RGGI allowances in circulation;

2)  All together, the 10 RGGI auctions have brought in more than $777.5 million for the 10 RGGI states;

and

1)  The RGGI states have collectively invested about 80% of the RGGI funds in strategic energy programs, most of which involve energy efficiency improvements in homes and businesses.   RGGI has created a website compiling the states' announcements on the success stories from these investments.

The next RGGI auction will be held March 9, 2011.  

The first rule creates a new "Class VI" injection well under EPA's Underground Injection Control Program through the the Safe Drinking Water Act.  Elements of the rule are based on the existing regulatory framework, but tailored to address the unique issues carbon dioxide can create, such as the fact that it floats and moves within subsurface formations, and corrodes its surroundings when combined with water.   Although CCS has been used on a smaller scale for years, such as to facilitate enhanced recovery of oil, the large volumes that are anticipated to be injected as part of a full-scale deployment of the technology present different issues entirely.

The rule provides guidance on some, but not all, of the areas highlighted as in need of further support in the August report of the Interagency Task Force on CCS.  For instance, the rule outlines characteristics for siting CCS wells, requirements for construction and operations, automatic shutoff systems.  It also provides a recommended 50-year monitoring program post-injection as well as clarifying financial responsibility requirements for emergencies, site closure and cleanup.  The rule also provides considerations for transitioning Class II permits for existing enhanced recovery wells to Class VI, based primarily on whether the primary purpose is assisting with the recovery of oil or long-term storage of the CO₂ itself.

The second rule finalizes the requirements for CCS ventures under the mandatory greenhouse gas reporting rule (Subparts RR and UU of 40 CFR Part 98).  The rule requires permit holders to create a plan to monitor, report and verify the amount of CO₂ sequestered, using a mass-balance approach, and could lay the groundwork for those captured tons to become valuable offsets under future policies.  The reporting requirement begins in 2011.

RGGI's initial aim was to cut CO₂ emissions from large power plants in the 10-state region to 10% below 2005 levels by 2018.  This plan involved two stages: one with the cap stabilized at 180 million tons CO_2e from 2009-2014, and the second, from 2015-2018, with a cap declining by 2.5% each year.   However, in the two years that the program has been in action, emissions have already declined to 33% below 2005-levels.   Although the decline has been commonly attributed to the economic downturn, NYSERDA found that fuel switching by power suppliers from coal and petroleum to natural gas (cheaper than it was in 2005) has in fact had the greatest impact, contributing 31.2% of the decline. 

At a meeting on November 12, RGGI, stakeholders gathered to hear briefings on projections for future emissions, why the carbon footprint was overestimated thus far, and what changes need to be made to RGGI going forward.  Consultant IGF International reported that although emissions in the region are predicted to grow steadily into the future, they will stay well below RGGI's initial reduction target through 2030, even without additional reductions caused by the energy efficiency and renewable energy programs funded by RGGI itself.  Their data suggests that the RGGI cap would have to be tightened from 10% reductions by 2018 to 22% or higher, for the cap-and-trade system to have any impact at all. 

The RGGI member states are currently involved in evaluating the program, and could make changes to the cap, as well as the rest of the program, before the second compliance phase begins in 2012. It will be interesting to see what decisions they make over the next year.

Under the GHG Protocol, emissions attributable to a company are divided into 3 scopes: Scope 1) direct emissions from sources it owns or controls (like factory smokestacks and company-owned cars); Scope 2) emissions attributable to the electricity, heat and cooling the company consumes; and Scope 3) everything else.  Scope 3 includes both upstream activities like services and products purchased by the company; downstream activities such as the emissions from the consumer’s use and disposal of the company’s product; and related activities such as the leased building, investments, and even emissions from employees’ commuting and business travel. Not unsurprisingly, given the breadth of sources that can be included, Scope 3 emissions are the largest source of emissions for most companies and thus represent the largest opportunity for greenhouse gas reductions.

The previous GHG protocols, issued in 2004 and 2005, focused on Scopes 1 and 2, but highlighted the need for an additional protocol for Scope 3, which was “optional” for reporters.  Although some took on the challenge, Scope 3 emissions are the hardest for companies to reliably measure.

The point of the protocol is to make such measurements more reliable.  As the Corporate Value Chain report highlights, a comprehensive approach to corporate GHG emissions measurement, management and reporting that incorporates all 3 scopes of emissions would enable companies to focus on the most cost-effective or largest opportunities to reduce emissions within the full value chain, and lead to more sustainable decisions. The authors caution, however, that even with a Scope 3 standard, the protocols are not designed to support comparisons between companies’ emissions. They will aid, however, in simplifying and reducing the costs of taking on a Scope 3 inventory, and increasing consistency and transparency in GHG accounting and reporting.

The Product Standard report provides a generalized framework to support the company in quantifying and reporting the GHGs generated during a product's life cycle (regardless of what the product might be). The goal of the standard is to assist companies in making informed choices about the products they manufacture, sell, purchase and use.  Although the authors caution that the standard is not intended to support GHG accounting for the purposes of offsets (from reductions) or carbon neutrality, the protocol will aid in making reliable emissions-related information about a product available in the public domain -- such as the New Zealand wine that reports its own carbon footprint on the bottle.  Although primarily a sales gimmick at this point, as more information becomes available, consumers can make more informed and sustainable choices as well.

Comments on the draft protocol may be submitted through the GHG Protocol website here.