The White House Releases Executive Order Aimed at Limiting GHG Emissions from Federal Agencies and Contractors

(Federal GHG regulations) Permanent link

On March 19, 2015, President Obama issued an Executive Order designed to cut the Federal Government’s greenhouse gas (GHG) emissions by 40 percent over the next decade from 2008 levels and increase the share of electricity the Federal Government consumes from renewable sources to 30 percent. The order also takes steps to encourage GHG emissions reductions from government contractors.

According to a White House press release, the Executive Order builds on and expands the energy reduction and environmental requirements of the President’s 2007 Executive Order 13423, which set a wide range of environmental and climate-related goals for federal agencies. For example, Executive Order 13423 set a goal of reducing GHGs by reducing energy intensity by 3 percent annually or 30 percent by 2015 and requiring at least 50 percent of current renewable energy purchases made by the Federal Government to come from new renewable sources, rather than continuing to rely on the same sources. In 2010, President Obama took a further step aimed at reducing the Federal Government’s GHG emissions by announcing a government-wide target to reduce direct GHG emissions by 28 percent by 2020, such as those from fuels and building energy use, and reduce indirect GHG emissions by 13 percent by 2020, such as those from employee commuting and landfill waste.

The new Executive Order titled, “Planning for Sustainability in the Next Decade,” calls for “expanded and updated Federal environmental performance goals with a clear overarching objective of reducing greenhouse gas emissions across Federal operations and the Federal supply chain.”

Direct Agency Emissions

The Order directs Federal agencies to:

  • Ensure 25 percent of their total energy (electric and thermal) consumption is from clean energy sources by 2025;
  • Reduce energy use in Federal buildings by 2.5 percent per year between 2015 and 2025;
  • Reduce per-mile GHG emissions from Federal fleets by 30 percent from 2014 levels by 2025, and increase the percentage of zero emission and plugin hybrid vehicles in Federal fleets; and
  • Reduce water intensity in Federal buildings by 2 percent per year through 2025.

Because renewable energy sources produce fewer, if any GHG emissions, these renewable energy goals are likely to also help the agencies to meet their overall 40 percent reduction targets.

The Order gives the head of each Federal agency 90 days to “propose to the Chair of the Council on Environmental Quality (CEQ) and the Director of the Office of Management and Budget (OMB) percentage reduction targets for agency-wide reductions of scope 1 and 2 and scope 3 greenhouse gas emissions in absolute terms by the end of fiscal year 2025 relative to a fiscal year 2008 baseline.” Scope 1 refers to direct GHG emissions from sources that are owned or controlled by the agency; scope 2 includes direct GHG emissions resulting from the generation of electricity, heat, or steam purchased by an agency; and scope 3 includes GHG emissions from sources not owned or directly controlled by an agency but related to agency activities such as vendor supply chains, delivery and transportation services, and employee travel and commuting.

Supply Chain Emissions

In addition to the 40 percent direct cut to GHG emissions by agencies, the Order contains provisions designed to obtain additional emissions cuts from suppliers in the Federal Government’s supply chain.

The Order gives the Chair of CEQ 30 days to identify and publicly release an inventory of major Federal suppliers, which will include information about whether the supplier has accounted for and publicly disclosed annual scope 1 and 2 GHG data for the previous year, as well as a GHG reductions target (or targets) for 2015 or beyond. The Order instructs the Chair of the CEQ to make these releases annually.

The White House also announced the introduction of a new public score card, presumably designed to meet this requirement by tracking self-reported emissions disclosure and progress for all major Federal suppliers. The score card uses a simple system of green, yellow, and red dots to indicate whether the suppliers have disclosed (green), have committed to disclose (yellow), or have not yet disclosed their emissions (red). The same color system is used to indicate whether the supplier has a current emissions target (green), has set a 2016 target (yellow), or has no emissions target (red). The four of the five companies that received the most in federal contracts in 2014, including Lockheed Martin, Boeing, Raytheon, and Northrop Grumman, each have two green dots, while General Dynamics (ranked as number 3), has not disclosed emissions or set emissions targets. Given the push-back that the Administration has received in its attempts to pass comprehensive climate legislation or new rulemakings aimed at reducing GHG emissions, this appears to be a creative way of attempting to “name and shame” federal contractors into lowering their emissions.

In addition, the Order requires the seven largest Federal procuring agencies to submit plans to implement at least five new procurements annually in which the agency may include contract requirements for vendors or evaluation criteria that consider contractor emissions and GHG management practices.

In conjunction with the release of the executive Order, the Administration hosted a roundtable on March 19th to bring together large Federal suppliers to “discuss the benefits of their GHG reduction targets or to make their first-ever corporate commitments to disclose emissions and set new reduction goals.” The companies attending the roundtable each do more than $1 billion a year in business with the Federal government and collectively account for about $45 billion in Federal contract spending. The White House announcement includes individual commitments by a number of these companies to cut their GHG emissions. The commitments made by these companies are hard to compare against one another, as they use different baseline years and percentage reductions to their emissions. For example, GE promises to reduce GHG emissions by 20 percent from a 2011 baseline by 2020, while Honeywell committed to cut its GHG emissions by 35 percent by 2020 relative to a 2007 baseline.

Posted by Corinne Snow at 03/20/2015 3:36 PM

Competing Viewpoints: The Clean Power Plan and Electrical Grid Reliability

(Federal GHG regulations) Permanent link
Late last month, energy policy experts released rival reports that presented dramatically different assessments of the U.S. Environmental Protection Agency’s (“EPA”) proposed Clean Power Plan’s impact on electrical grid reliability. The reports were presented at a conference hosted by the Federal Energy Regulatory Commission (“FERC”) in Washington, D.C., which focused on the Clean Power Plan’s potential impacts to the U.S. electrical grid. The reports highlight ongoing disagreements among stakeholders regarding the technical and economic feasibility of EPA’s controversial proposal to cut carbon emissions from existing power plants.  For an in-depth analysis of the Clean Power Plan, see the special issue of the V&E Climate Change Report. A recent post on one electrical grid operator’s analysis of the proposed economic impacts of the plan can be found here.

The Electric Reliability Coordinating Council’s Report

The first report, “The EPA’s Clean Power Plan: A Clear Threat to Electric Reliability,” was prepared by the Electric Reliability Coordinating Council (“ERCC”). The report criticizes the Clean Power Plan as a threat to the stability of the nation’s power supply. The report contains quotes from comments submitted to EPA’s docket by regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) that administer electrical grids. In addition to concerns about the impact of the Clean Power Plan on grid reliability, their comments question EPA’s core economic and technical assumptions in deriving its best system of emission reduction determination and its state-specific emissions rate targets. The report contends the Clean Power Plan could force the phasing out of baseload power plant faster than market forces would normally demand because the plan imposes changes on the dispatch priority of various power generation resources. Below are some of the key comments included in the report:

The North American Electric Reliability Corporation (“NERC”) believes that anticipated changes in the resource mix and new dispatching protocols required by the Clean Power Plan could strain “essential reliability services,” such as load and resource balance, voltage support, and frequency support. NERC’s argument rests on the assumption that the integration of new generation resources, especially renewable resources with variable generation capacities, makes it difficult to maintain the voltage stability necessary to for bulk power system reliability.

Some RTOs, including the Midcontinent Independent System Operator (“MISO”), the Southwestern Power Pool (“SPP”), and the Electric Reliability Council of Texas (“ERCOT”), suggest that the coal and gas/oil steam unit retirements required by the Clean Power Plan will erode reserve margins to the point that grid operators will be forced to manage high demand situations through emergency operating procedures. Such reliance may increase the probability of a major loss of load event during critical scenarios, such as drought, polar vortex conditions, or times of limited wind resource availability. In addition, these groups contend reserve margins will also be affected by efforts taken to comply with EPA’s new Mercury and Air Toxics Standards (“MATS”) rule, which will be fully effective by 2016. MISO’s analysis of the impact of the MATS found that it will require the retirement of between 10 and 12 gigawatts of coal-fired electric generation capacity, which will put additional strains on planning reserve margins and will likely force the more frequent use of emergency operation procedures.

Other RTOs expressed concerns that a reduction in existing coal or oil-fired electric generating capacity could not be easily replaced by additional natural gas-fired generating capacity as contemplated by the Clean Power Plan. For example, the New York Independent System Operator (“NYISO”) explains that their current system relies on dual-fuel oil/gas steam electric generating units (“EGUs”) to hedge against potential gas supply shortages, and that these systems cannot be easily replaced because of their location within the New York City transmission system. NYISO states that EPA’s building blocks assumes that electrical output from these dual fuel EGUs could be reduced by 99%, but asserts that this reduction cannot be achieved without compromising grid reliability because these units allow for faster dispatch within the existing transmission constraints of New York’s electrical system. 

State entities also expressed concerns about grid reliability. For example, the Arizona Corporation Commission believes that EPA’s assumptions about Arizona’s energy market are inaccurate and would force the retirement of all Arizona coal plants by 2020; however, the report does not describe the alleged faulty assumptions. Nevada officials argue that, in general, the Clean Power Plan’s targets for 2020 to 2029 do not provide enough time for states to develop compliance plans, select resources, complete evaluations, and develop sufficient natural gas transportation infrastructure necessary to ensure a reliable grid. According to the Pennsylvania Public Utility Commission, heat rate improvements for coal-fired plants (Building Block 1) and coal-to-gas switching (Building Block 2) could threaten both the reliability of the state’s electrical grid and the broader, regional economy because they would require energy providers to make dispatch decisions based on environmental factors, rather than economic and grid reliability factors as traditionally mandated by the Federal Power Act.

ERCC asserts that implementation of the Clean Power Plan could result in more “cascading” blackouts and concomitant economic damage. For example, the Northeast blackout of 2003 cost businesses about $13 billion in lost productivity, while direct costs to the San Francisco Bay Area during the California blackouts approached $1 million per minute during the winter of 2001. ERCC also evoked recent extreme weather events, such as winter storm Juno, to reiterate the vulnerability of U.S. power supplies in these situations if grid reserve margins are depleted by EPA’s proposed standards. The comments urge EPA to adopt a reliability “safety valve” that would provide relief and which those involved in reliable operation of the grid can evoke to adjust or postpone some of their emission targets in emergency situations.

The Analysis Group’s Report

The second report, “Electric System Reliability and EPA’s Clean Power Plan: Tools and Practices,” prepared by the Analysis Group, an organization that strongly supports the Clean Power Plan, presents a much more optimistic assessment of the plan’s economic impact and technical feasibility. The report addresses comments to EPA submitted by states, utilities, and industry groups that identified elements of the Clean Power Plan that could lead to reliability concerns. The Analysis Group suggests that these groups did not consider provisions in the Clean Power Plan that provide states and industry with flexibility in meeting EPA’s proposed standards. In addition, their report points to several “mitigating factors” that could help stakeholders achieve emissions reductions while maintaining reliability. These include, among other things, retirements of older, less-efficient coal plants due to existing environmental regulations and market trends, various ways to address natural gas pipeline constraints, and evidence that higher levels of variable energy sources (wind and solar) can be effectively managed.

In particular, the Analysis Group report suggests that existing air quality regulations and wholesale power price trends would have forced retirement of less efficient plants and improved the emission rates from the remaining coal plant fleet even if EPA had not proposed the Clean Power Plan. This argument largely echoes EPA’s own statements that market forces and an abundance of natural gas are forcing the retirement of coal-fired electric generating capacity. The report identifies dramatic increases in domestic energy production stemming from the shale gas revolution, changes in fossil fuel prices, and increases in energy efficiency and distributed energy resources as examples of these shifts. The Analysis Group concludes that these forces and other factors like addressing infrastructure needs required by state renewable energy portfolio standards already require grid operators to address dispatch, storage and reliability concerns similar to what they will need to address to implement the Clean Power Plan.

The report also suggests that potential natural gas shortages due to pipeline transmission infrastructure constraints may be relieved in the near-term by reliance on a mix of back-up fuels, increased gas storage, and liquefied natural gas, among other measures. In the long run, the report suggests such constraints can be solved by expanding gas pipeline infrastructure, with many projects already proposed or under construction. What the report ignores, however, are additional factors that can impact the speed with which such projects can move forward. Environmental permitting requirements can significantly impede construction schedules for energy infrastructure projects, like pipelines.

In addition, the report claims that states and groups of states have flexibility under the Clean Power Plan to implement the Clean Power Plan’s “building blocks” in ways that address their particular circumstances, instead of following a one-size-fits-all approach. The Clean Power Plan encourages states and power plant owners to develop market-based approaches to allow emissions trading within and across state lines. One example of such an approach would be to implement emissions trading among plants (within a utility’s fleet inside or across state lines) or within the boundaries of a RTO; a state with generating facilities in multiple RTOs could develop a plan that relies upon different approaches in the different footprints. This would allow states with a larger number of lower-emitting power generation sources, like natural gas plants, or with the ability to widely deploy zero-emission renewable energy sources, to assist states with electrical systems that consist of higher-emitting sources to meet the requirements of the Clean Power Plan. Based on this flexibility, the report asserts that EPA does not need to include a “safety valve” provision, as some industry commenters and FERC regulators have urged.


The fundamental disagreement between these two reports is whether the Clean Power Plan provides sufficient flexibility in terms of the states’ deadlines to meet EPA’s emissions targets and whether the proposed rule offers enough options for operators and regulators to address potential threats to grid reliability. As a coalition of organizations responsible for system reliability, ERCC is understandably cautious about the Clean Power Plan’s ambitious emissions reduction targets. The Analysis Group report seeks to paint the Clean Power Plan in a better light and advocates that the plan contains flexible provisions (for example, allowing trading schemes across states and encouraging development of renewable energy or distributed/decentralized energy systems), and argues that industry has successfully complied with other Clean Air Act emissions standards (such as the NOx SIP call, the Cross-State Air Pollution Rule, and the MATS rule) without sacrificing grid reliability.

Posted by Jordan Rodriguez at 03/19/2014 2:10 PM

New Economic Analysis of EPA’s Clean Power Plan Suggests Regional Plans and Renewables May Ease Overall Burdens

(Renewable Fuel Standards and Biofuels) Permanent link

PJM Interconnection (“PJM”), the nation’s largest grid operator, recently analyzed the economic impacts of the U.S. Environmental Protection Agency’s (“EPA”) Clean Power Plan on electric power generation. The analysis indicates that regional compliance plans could have lower compliance costs than state-specific plans, and that the use of renewables may slow the pace of retirement for fossil-fuel based generating units.

The Clean Power Plan

As described in a previous post, the proposed Clean Power Plan sets guidelines and standards that states must use to develop their compliance plans. The proposal has a June 1, 2016, deadline for states to submit compliance plans. However, states are permitted to engage in regional compliance plans to take advantage of region-wide electric grids already in place under independent system operators (“ISOs”) and regional transmission organizations (“RTOs”) and with multi-state utility systems. Participating in a regional program extends the compliance deadline to June 1, 2017, to allow for coordination among the states.

States must meet the targets set by the Clean Power Plan beginning in 2020 with interim goals declining over time until final targets are reached in 2029. According to PJM’s report, on average the PJM states must reduce their system-wide carbon emission rate by 30 percent from 2005 levels.

PJM Analysis

In response to the Clean Power Plan, the Organization of PJM States, Inc., requested that PJM analyze the Plan’s economic impacts.  The Organization is comprised of state utility regulators from the 14 jurisdictions served by PJM: Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

To assess the economic impact of the Clean Power Plan, PJM analyzed 17 distinct scenarios, each run with and without the limits set forth in the Clean Power Plan. These scenarios included various levels and combinations of energy sources in state energy portfolios, ranging from high penetration of renewable resources and energy efficiency and lower natural gas prices to limited renewable resources and energy efficiency, high natural gas prices, a reduction in nuclear generation, and limited entry of new natural gas combined-cycle resources. The stated purpose of the analysis was to determine the potential impact of the EPA’s proposal on PJM’s markets and electric reliability and to inform state and federal decision-makers of such impacts.

Regional versus State-by-State Compliance Production and Implied Changes in Compliance Costs
Regional versus State-by-State Compliance Production and Implied Changes in Compliance Costs
PJM Economic Analysis of the EPA Clean Power Plan Proposal (

One of the most significant conclusions of PJM’s analysis is that when placing a price on carbon dioxide emissions, state-specific compliance plans would have higher compliance costs for PJM states than if they opted for a regional compliance program.

As the analysis explains, this is because individual states within a region are likely to differ in their “available abatement options and resource mix.” For example, State A, which has a large amount of low cost natural gas combined-cycle and a lot of energy efficiency could obtain a “lower CO2 price since the energy efficiency reduces emissions at zero marginal cost (albeit at some level of capital expense), and the low-cost natural gas combined-cycle resources result in low marginal costs of emissions abatement.” As a result, State A may be able to reduce emissions much more cheaply than its neighbor, State B, who has “very little renewable energy or natural gas combined-cycle resources will likely find it much more expensive to redispatch resources” in order to reduce emissions. Instead of making those more costly changes, State B could purchase reductions from State A, allowing both states to take advantage of the fact that State A can reduce emissions in a more cost-effective manner. 

The analysis found an incremental rise in compliance costs of approximately $300 million in 2020 if PJM states opt for the state-specific compliance approach. The report does not break down its findings by individual states, and thus does not clarify the differences in incremental costs that particular states might pay, or explain whether certain states (like the hypothetical State A) might still be better off selecting a state-specific plan. The report does note that “results will vary by state given differing state targets and generation mixes. PJM modeled regional versus individual state compliance only under a mass-based approach.” As discussed in a previous post, the Clean Power Plan gives states the option to use either the rate-based goal or to convert the rate-based goal to a mass-based goal.

Other noteworthy findings from PJM’s modeling scenarios include:

  • As the carbon emission limits decrease over time, higher-emitting resources, such as coal, oil and gas, will increasingly lose their favorable financial position, giving way to lower-emitting resources. Thus, fossil fuel unit retirements will likely occur gradually through the compliance deadline;
  • When utilizing larger amounts of higher-cost, lower carbon emitting resources to achieve emissions targets, states are likely to see an increase in electricity production costs;
  • If natural gas becomes a significant generation source for compliance with state programs, the price of natural gas will likely play a large role in the cost of reducing carbon emissions;
  • Adding more renewable energy sources and energy efficiency and retaining nuclear generation may reduce carbon dioxide prices. This, in turn, could lessen the risk of retirement of fossil fuel power plants because lower carbon dioxide prices means less financial stress on these resources; and
  • State-specific compliance programs, as opposed to a regional program, may increase the amount of fossil-fuel capacity at risk for retirement since some states may see higher carbon dioxide prices if they face compliance alone.

These final two conclusions regarding the risk of retirement for fossil fuel generation units are particularly interesting, given that the United States Government Accountability Office (“GAO”) released a report this past summer finding that power companies now plan to retire a greater percentage of coal-fueled generating capacity and retrofit less capacity with environmental controls than previously believed.  The PJM report suggests that the impact of the Clean Power Plan on plant retirements—at least for fossil fuel generation units—could be lessened through the use of more renewable energy sources and the adoption of regional plans.  For more information about plant retirement, please see this previous post.

Posted by Mike Malfettone and Corinne Snow at 03/11/2015 4:55 PM

Back to FutureGen: Sierra Club Challenges California CCS Project Cited in NSPS

(Federal GHG regulations) Permanent link

Carbon capture and sequestration (CCS) projects funded by the U.S. Department of Energy (“DOE”) continue take one blow after another. Last month, the DOE revoked funding for a FutureGen program carbon capture and sequestration project in Illinois, effectively killing the project. Now, a second FutreGen program CSS project has come under attack, this time from the Sierra Club and local resident associations. On March 3, 2015, the Sierra Club filed a motion to terminate the California Energy Commission’s (CEC) certification proceeding for the Hydrogen Energy California (HECA) coal-fired power plant. HECA is a proposed integrated gasification combined cycle (IGCC) power plant that would convert coal and petroleum coke, a by-product of the oil refining process, into hydrogen energy, and would also produce fertilizer.

Project Background

How the Plant Works

HECA is located in Kern County, California, outside of Bakersfield. The proposed project would generate approximately 300 MW of electricity and produce up to one million tons of fertilizer per year. The site for the proposed IGCC plant is also located in close proximity to the Elk Hills Oil Field, where project proponents hope that CO2 from the syngas vents of the plant can but used for enhanced oil recovery (EOR) operations.

IGCC plants convert feedstocks into hydrogen-rich synthetic gas. HECA’s design involves further cleaning and processing the synthetic gas using an acid gas removal system to separate out CO2 from the gas stream. The facility is projected to capture up to 90% of CO2 emissions, or approximately 2.7 million tons per year. Of that amount, plans are to use 0.3 million tons of CO2 per year for fertilizer production and route the remaining 2.4 million tons to a pipeline for EOR. The current plan is for HECA to commence operations sometime in 2017, with carbon capture beginning in 2019. To date, HECA has been unable to contract with a third party for its CO2 emissions.

The total cost for HECA is projected to exceed $4 billion. The DOE has committed $408 million to the project, a portion of which was issued pursuant to the FutureGen progam. DOE has not yet pulled its support from HECA, but certain Department officials have recently commented that HECA could share the same fate as the FutureGen project in Illinois because DOE FutureGen loans require that all the money from the loan be spent by September 2015.

Sierra Club Challenge

The CEC is the lead California state agency under the California Environmental Quality Act (CEQA) for analyzing the environmental impacts of proposed energy projects. CEQA is a very burdensome state environmental review statute. The CEC has adopted a “certified regulatory program,” under CEQA that provides for an environmental analysis of the project, including an analysis of alternatives and mitigation measures to minimize any significant adverse effect the project may have on the environment, rather than the completion of a full environmental impact report under CEQA. To meets its CEQA obligations, the CEC must certify HECA before the project can proceed.

The Sierra Club’s motion to terminate HECA’s application for certification with the CEC alleges that HECA has failed to “pursue the [project] application with due diligence” as required by applicable regulations. The Sierra Club asserts that, without a CO2 contract, the project is legally and financially infeasible. CEC staff requested information on negotiations related to HECA securing a CO2 contract 18 months ago, but to date, has not received a response. Sierra Club cites HECA’s lack of response and because HECA has failed to secure a contract to sell CO2 from the facility for EOR use in the Elk Hills field as evidence that it has not pursued its application with the CEC with appropriate due diligence.

The motion also states that HECA must have an agreement in place to capture CO2 from the IGCC plant in order to meet state and federal greenhouse gas (GHG) emission requirements. The motion further contends that a CO2 sale contract is necessary for the project to receive “essential federal funding” and that “CO2 sales revenue is a necessary component of the project’s financial viability.”

If HECA Goes Under, What Happens to the NSPS?

Whether or not the Sierra Club’s motion succeeds, the threat of the loss of DOE funding still hangs over HECA’s head. If HECA also dies, the U.S. Environmental Protection Agency (EPA) will find itself on increasingly unstable legal ground with respect to recent GHG rulemakings. As with the Illinois project, EPA cited to HECA in its soon to be finalized New Source Performance Standards (NSPS) for greenhouse gas emissions from fossil fuel-fired power plants as evidence that CCS represents the best system of emission reduction (BSER) for GHG emissions. The federal Clean Air Act requires that a technology must be “adequately demonstrated” for it to qualify as BSER.

Case law provides EPA with some leeway to select an emerging technology as BSER (see Sierra Club v. Costle, 657 F.2d 298, 341, fn. 157 (D.C. Cir. 1981)), but the death of another CCS project before it even commences operation raises serious concerns about the data and reasoning EPA relied in its rulemaking. Putting aside a plain language interpretation of what it means for a technology to be “adequately demonstrated,” BSER determinations must also take into account the cost of achieving emissions reductions, and also the non-air quality health and environmental impacts. EPA pointed to the power industry’s decision to move forward with projects like HECA in the NSPS as evidence that the costs for CCS are reasonable, but as discussed in previous posts, many of the projects cited by EPA have faced repeated construction delays and significant cost-overruns totaling billions of dollars. In addition, CCS projects are energy-intensive, and depending on the location of the project, could require the construction of pipelines that add to the overall environmental impact of a power plant project.

HECA is not the only CCS project EPA points to in the proposed NSPS as evidence that CCS is BSER, but the majority of the projects cited to have all faced significant hurdles. Some sources report that EPA has internally acknowledged that the agency should prepare a fallback position on BSER, especially in light of the lack of successful domestic CCS power plant projects. Potential fallback options include a determination that IGCC without CCS is BSER, but this would result in significantly less reductions in GHG emissions than could be achieved using CCS. Selection of a new control technology as BSER for the GHG NSPS would almost certainly require another round of notice and comment, which would result in the EPA having proposed this NSPS three times. In addition, delays in finalizing the NSPS would also impact EPA’s proposal for GHG emissions from existing power plants and push back the timeline for finalizing that rule.

Posted by Matthew Dobbins at 03/06/2015 1:15 PM

GAO “High-Risk Series” Report Identifies Climate Change as a Key Risk to Government Programs

(Adaptation) Permanent link
In its biennial high-risk series reports, the Government Accountability Office (“GAO”) identifies government programs and operations that are potentially vulnerable to a variety of risks and makes recommendations for mitigating those risks. In 2013, GAO added “Limiting the Federal Government’s Fiscal Exposure by Better Managing Climate Change Risks” to its high-risk list. Last week, GAO released “High-Risk Series: An Update (“2015 Report”). Although the 2015 Report acknowledges some progress in managing climate change risks, it concludes that climate change continues to present significant financial risk to the federal government.

According to GAO, although many Federal climate-related efforts are underway, a number of overarching strategic challenges persist. For example, in November 2013, the President issued Executive Order 13653 on “Preparing the United States for the Impacts of Climate Change,” in response to which, agencies developed climate change adaptation plans to evaluate the most significant climate change related risks to agency operations and objectives. However, according to the 2015 Report, most of the agencies have yet to implement many aspects of their plans, and it remains unclear how the diverse plans across agencies will relate to one another. The 2015 Report also indicates that many existing efforts fail to clearly define the roles and responsibilities of the various federal, state, local, and private-sector actors involved.

The 2015 Report also states that programs to monitor the effectiveness and sustainability of existing efforts are lacking. For example, public insurers have taken steps to mitigate the fiscal risk to federal insurance programs, such as the National Flood Insurance Program: they have commissioned climate change studies in order to better understand and prepare for the potential impacts of climate change on federal insurance programs; FEMA is working to phase out subsidies for flood insurance that create inaccurate price signals; and FEMA is planning to incorporate some projected effects of climate change, such as sea level rise and erosion into its flood maps.  However, there is no system in place to monitor and verify the effectiveness of these efforts. According to GAO, to create sustainable programs with lasting high-level support, implementing programs to track and monitor progress will be crucial.

In addition to these overarching challenges, the 2015 Report also identifies specific areas requiring improvement, including:  
  1. Federal property and resources.

    The federal government owns and operates thousands of facilities and manages nearly 30 percent of the land in the United States. The 2015 Report notes that these resources are potentially vulnerable to climate change impacts. For example, NASA's real property holdings include more than 5,000 buildings and other structures, many of which are located in coastal areas. According to GAO, such facilities are potentially vulnerable to sea level rise and erosion, among other potential impacts, while other federal land is potentially vulnerable to severe drought and wildfires.  To mitigate risk to federal property and resources, the Report urges the federal government to better incorporate climate change information into infrastructure planning processes and documents, such as technical guidelines and design standards and National Environmental Policy Act (“NEPA”) planning documents. 

    In general, professional associations, rather than federal agencies, develop technical guidelines and design standards to ensure the safety and reliability of infrastructure. These sorts of design standards determine how different elements are incorporated in the planning process and project-level design. However, because they often fail to account for climate change impacts, GAO recommends that agencies, such as the Department of Transportation and the Environmental Protection Agency, work with professional associations to incorporate climate change information into design standards.

    GAO also recommends that the Council on Environmental Quality (“CEQ”) and other relevant actors work to determine how to incorporate climate change considerations into NEPA analysis for proposed federal actions, such as infrastructure projects. On February 18, 2010, CEQ issued draft guidance on incorporating climate change impacts into NEPA analysis. Rather than finalize the guidance, CEQ issued a “Revised Draft Guidance on the Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in NEPA Reviews” in December 2014. The 2015 Report urges CEQ to finalize the guidance so that agencies can begin to consistently consider climate change when implementing NEPA. 

  2. Federal disaster aid.

    According to the 2015 Report, “multiple factors, including increased disaster declarations, climate change effects, and changing development patterns” increase the federal government’s financial exposure in its role as provider of disaster aid. According to the Report, the problem stems in part from difficulty (and inconsistency) in determining which disaster-preparation and -response costs should be borne by federal, state, or local governments, and which costs should be borne by the private sector. Consequently, GAO recommends that FEMA develop a procedure to more accurately assess a jurisdiction’s capacity to respond to a disaster on its own. GAO also recommends that FEMA study past events to improve upon disaster cost estimates going forward.

  3. Federal flood and crop insurance programs.

    The Report highlights the considerable financial risks to the National Flood Insurance Program and the United States Department of Agriculture's Federal Crop Insurance Corporation. The Report suggests that financial risk to the programs stems in part from the fact that the agencies responsible for the programs have not incorporated climate change impacts into their risk-management practices. For example, they have done little to analyze the potential impact of increasingly frequent and severe weather-related events on their programs. As such, GAO emphasizes the need to develop the resources and information needed to better understand and manage the programs’ exposure to climate change, noting for example that projected impacts of climate change, such as sea level rise, need to be incorporated into updated flood maps. 

    Additionally, premium subsidies mean many federal crop insurance policyholders do not receive accurate price signals or bear the true risk of loss associated with weather-related events. This, in turn, could impact farming decisions. GAO recommends that the Secretary of Agriculture direct the federal crop insurance program to work with experts to develop guidance on resilient agricultural practices.

The 2015 Report touches on a broad range of risks posed by climate change. And although the Report makes numerous program-specific recommendations, the 2015 Report repeatedly emphasized the need for: (1) more-effective coordination across agencies and different levels of government, as well as between the public and private sectors; (2) incorporation of climate change data into planning and development processes; and (3) programs to monitor and track progress.

Posted by Lauren Sidner at 02/23/2015 4:15 PM

Does President Obama’s New Flood Risk Management Standard Facilitate Climate Change Adaptation?

(Adaptation) Permanent link
On January 30, 2015, President Obama issued Executive Order 13960 modifying Executive Order 11988, which was issued in 1977 to govern federal floodplain management. Executive Order 11988 required all federal agencies to take action to reduce the impact of flood loss, minimize the impact of floods on public health, safety, and welfare, and “preserve the natural and beneficial uses of floodplains.” Under Executive Order 11988, Agencies were to evaluate the effects of their potential actions on the floodplain and “consider alternatives to avoid adverse effects and incompatible development” in floodplains. As modified by E.O. 13960, Agencies are to prioritize the use of ecosystem-based approaches when developing alternatives for consideration when an action will impact floodplain management.

Executive Order 11988 required each federal agency relevant authority to issue or amend regulations governing its activities in the floodplain that were consistent with the risk management principles set forth in the Order, and included a specific requirement that agencies with responsibilities for federal real property and facilities in the floodplain ensure that their regulations are “consistent with the intent of those promulgated under the National Flood Insurance Program.” E.O. 13960 adds an additional requirement that these regulations also be consistent with the Federal Flood Risk Management Standard. The Federal Flood Risk Management Standard was “developed to create a national minimum flood risk management standard to ensure that federal actions that are located in or near the floodplain when there are no other practical alternatives last as long as intended by considering risks, changes in climate, and vulnerability.”

Adopting the Federal Flood Risk Management Standard, E.O. 13960 implements its new definition of the floodplain. Previously, the floodplain was defined as the area in which there was a 1% chance of flooding in any given year (the 100-year floodplain or “base flood”). Under the approach of the Federal Flood Risk Management Standard, flood elevation can be determined by (1) use of best available data, including expected future changes in flooding based on climate science; (2) freeboard (base flood elevation plus 2 feet in most areas or 3 feet in critical areas); or (3) the 500 year flood elevation. The Flood Risk Management Standard states that the “climate-informed science approach is preferred.” E.O. 13960 adopts these three approaches and any other methods that may be identified in an update to the Flood Risk Management Standard as acceptable options to determine the extent of the floodplain itself, but does not establish the clear preference for a climate-informed approach that is expressed in the Flood Risk Management Standard.

E.O. 13960 further requires that before agencies take any actions to implement its new standards they solicit additional input from stakeholders. Specifically, the executive order directs FEMA to publish a revised draft of the Floodplain Management Guidelines for public comment. E.O. 13960 also contemplates an ongoing process to revise federal floodplain management policies, directing the Water Resources Council to issue further amendments to the Floodplain Management Guidelines “as warranted.”

While E.O. 13960 will increase the scope of the floodplain, it is not yet clear what impact this action alone will have on climate change adaptation. E.O. 13960 does not contain the same clear preference for a climate-science based approach to defining the floodplain that is found in the Federal Flood Risk Management Standard, meaning that the actual incorporation of sea level rise risks into agency regulations and planning processes will be left to the implementation policies and regulations adopted by the individual agencies. Importantly, E.O. 13960 does establish a preference for agencies to consider natural and ecosystem-based approaches to managing flood risk. Such alternatives could provide important opportunities to preserve coastal habitats that provide flood protection—such as wetlands—in their current locations and may provide incentives to accommodate these habitats as sea levels rise by creating space for them to migrate landward. However, there is nothing in the executive order itself that would require such measures nor can the executive order prohibit additional development in vulnerable floodplains.

Ultimately, while E.O. 13960 is important in that it explicitly recognizes the role that climate change may play in enhancing future flood risks, the President does not have the legal authority to mandate that federal agencies stop supporting all activities in floodplains. In fact, there are several statutory authorities, including FEMA’s authority under the National Flood Insurance Program that require federal agencies to provide assistance in flood plains. Therefore, the extent to which E.O. 13960 results in actual climate change adaptation measures will depend upon how the relevant agencies choose to implement it in their own regulations, including the forthcoming revisions to the Floodplain Management Guidelines.

Posted by Margaret Peloso at 02/17/2015 3:54 PM

Using the Social Cost of Carbon to Measure the Impact of Federal Actions

(Federal GHG regulations) Permanent link

As discussed in a previous post, the Council on Environmental Quality (CEQ) recently released new Draft Guidance on Considering Climate Change in NEPA Reviews. The guidance suggested that the social cost of carbon (SCC) could play a role in assessing a project’s Greenhouse Gas (GHG) emissions in a NEPA cost-benefit analysis. This post explains the federal government’s current use of SCC, and identifies some potential issues with its application.

What is the social cost of carbon?

Since the 1990s, environmental economists have been trying to develop a way to quantify the impact of GHG emissions in present economic terms. The SCC has emerged as a potential tool for doing just that. Competing SCC models attempt to quantify the incremental climate impact that the modelers think will result from a unit of carbon dioxide (CO2) emissions so that an economic value can be assigned to the emissions. The value is then used as a point of comparison for actions action that reduce CO2 emissions. A number of competing models exist, each of which makes different predictions about future interactions between human behavior and the climate. These models tend to include predictions regarding changes in net agricultural productivity, human health, property damages from increased flood risk, and the value of ecosystem services due to climate change. The models attempt to calculate impacts over the next several hundred years, and then to apply a discount rate in order to determine what the future impact means in current economic terms.

In 1993, President Clinton issued Executive Order 12866, which requires federal agencies, to the extent permitted by law, “to assess both the costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs.” By 2008, federal agencies had begun using SCC as part of their cost-benefit analysis. Originally, these agencies relied on differing models and estimates to assess SCC. These estimates ranged anywhere from approximately $0-150/ton CO2. In 2010, the Interagency Working Group (IWG) released a report which created a uniform SCC value for federal agencies to use. The stated purpose of the SCC value was to “incorporate the social benefits from reducing carbon dioxide emissions into cost-benefit analyses of regulatory actions that have small, or ‘marginal,’ impacts on cumulative global emissions.”

The report included four different values for SCC. These values resulted from IWG’s attempt to aggregate three different models, known as DICE, FUND, and PAGE. The first three values in the report differ based on whether a 2.5, 3, or 5 percent discount rate was used in the calculation. A discount rate is used to determine net present value of future benefits and costs. As the Office of Management and Budget (OMB) has explained, “this discounting reflects the time value of money. Benefits and costs are worth more if they are experienced sooner.” The idea of discounting is based in economics: we assume that people put more value on a benefit they receive today, than an identical benefit that they will not receive until the distant future. Guidance from OMB instructs agencies to discount “[a]ll future benefits and costs, including nonmonetized benefits and costs.” The fourth value in the IWG report “represents the 95th percentile SCC estimate across all three models at a 3 percent discount rate, is included to represent higher-than-expected impacts from temperature change further out in the tails of the SCC distribution.” In 2010, these calculations resulted in SCC estimates of $7, $26, $42 and $81/ton CO2 (in 2007 dollars) for 2020. The IWG reached these figures by amalgamating the results of three different SCC models, each of which includes different assumptions and damage calculations.

The IWG revised its report in 2013, increasing the SCC estimates for 2020 to $12, $43, $65, and $129/ton CO2 (in 2007 dollars). For practical purposes, this means federal agencies are valuing the SCC at about $37/ton CO2 for 2015, which is based on a 3 percent discount rate. According to a recent GAO report, these 2013 figures raised public interest because they were approximately 50 percent higher than the 2010 estimates. The new report also has sparked a debate about the use of SCC values to analyze the effects of regulatory action. Unsurprisingly, critics on both sides have argued that the current IWG values are either too high or too low to accurately reflect GHG impacts.

Limitations in current SCC estimates

The possible problems with incorporating SCC into a cost-benefit analysis of federal actions include:

Should the analysis use a global or domestic value?

The SCC values can be calculated based on global or domestic impacts. Global impacts result in a much larger cost per unit of GHG. For example, the Department of Transportation (DOT) was simultaneously using both a domestic SCC value of $2/ton CO2 and a global SCC value of $33/ton CO2 for 2007 emission reductions. Under the current IWG approach, federal agencies are using a global value. Those supporting the use of a global value argue that the global value better captures the total costs of emissions. As EPA has explained, GHGs do not remain locally concentrated; instead they disperse uniformly into the atmosphere. The domestic SCC value, on the other hand, has the benefit of being more readily used in a cost-benefit analysis of a particular action, because the other costs and benefits of an agency action are often more limited in geographic scope.

What discount rate should apply?

The Office of Budget Management (OBM) has concluded that agencies should provide estimates of net benefits using both 3 percent and 7 percent discount rates for regulatory analysis, with 7 percent as the default position. By contrast, the IWG used smaller discount rates of 2.5, 3, and 5 to reach its SCC figures. This appears to fly in the face of OBM’s guidance. As OBM has explained, “[t]he further in the future the benefits and costs are expected to occur, the more they should be discounted.” Because the SCC is trying to quantify impacts over such a vast time period, even a small change in the discount rate can have a large impact on the present value of GHG emissions. According to estimates in a recent presentation by the American Enterprise Institute, at a 7 percent discount rate the SCC becomes small or even negative.

Are the SCC models adequately capturing all of the possible costs?

Environmental groups like the NRDC argue that the current models underestimate the full costs of the ecosystem damage that could result from GHG emissions. Critics like the NRDC argue that the models give preference to damages which are easy to quantify, but leave out many “intangible” harms to the environment, such as an alleged loss of biodiversity.

Can multiple models be fairly aggregated into a single SCC value?

The IWG’s SCC values are the result of aggregating three different models that all rely on very different assumptions about the future. The Electric Power Research Institute (EPRI) reports that fundamental differences in modeling make it hard to compare and aggregate these three approaches. EPRI concluded that the IWG’s SCC estimates “are difficult to interpret, discuss, and evaluate in terms of the societal risks they do and do not represent, and how well they reflect current scientific knowledge, because little is known about the disaggregated modeling.”

The SCC provides an analytical framework to consider the costs and benefits of regulatory actions that impact GHG emissions. As these various criticisms of the IWG’s SCC values suggest, however, we may not yet have an accurate way to assess those impacts in present economic terms.

Posted by Corinne Snow at 02/13/2015 4:23 PM

Disclaimer & Legal Notice | ©1999- Vinson & Elkins LLP Attorney Advertising