Input:
	Introduction

Since 2009, the Environmental Protection Agency (EPA) has begun to address emissions of greenhouse gases (GHGs) from both mobile and stationary sources, using broad regulatory authority provided by Congress decades ago in the Clean Air Act. Although Congress has never specifically directed EPA to regulate emissions of GHGs, the Clean Air Act as enacted in 1970 and as amended in 1977 and 1990 gave the agency authority to identify air pollutants and promulgate regulations to limit their emission.
From the late 1990s until 2007, EPA and various interested parties debated whether that authority covered greenhouse gases. This debate was settled by the Supreme Court in April 2007, in Massachusetts v. EPA . In a 5-4 decision, the Court found that greenhouse gases are unambiguously air pollutants:
The Clean Air Act's sweeping definition of 'air pollutant' includes ' any air pollution agent or combination of such agents, including any physical, chemical ... substance or matter which is emitted into or otherwise enters the ambient air... (emphasis added). ... Carbon dioxide, methane, nitrous oxide, and hydrofluorocarbons are without a doubt 'physical [and] chemical ... substances[s] which [are] emitted into ... the ambient air.' The statute is unambiguous.
Since the Court's Massachusetts decision, EPA has addressed GHG emissions in a number of steps, among them:
In December 2009, the agency laid the groundwork for regulations by finding that emissions of greenhouse gases may reasonably be anticipated to endanger public health and welfare, and that GHGs from new motor vehicles cause or contribute to that endangerment. In May 2010, the agency promulgated GHG emission standards for model year 2012-2016 cars and light trucks. In January 2011, the agency began requiring permits and the imposition of Best Available Control Technology on new stationary sources (and major modifications of existing sources) that emit more than a threshold amount of GHGs. In September 2011, EPA promulgated GHG emission standards for model year 2014-2018 medium- and heavy-duty trucks. In October 2012, the agency promulgated a second phase of GHG emission standards for cars and light trucks, covering model years 2017-2025.
As extensive as these actions may seem, they have had relatively minor impacts on GHG emissions to date. The rules are prospective, and in most cases have not yet taken effect.
The auto and truck manufacturing industries have been the major focus of the GHG regulations; in both cases, they are eager to improve fuel economy (coincidentally reducing GHG emissions), because the high cost of fuel has affected consumer purchasing decisions over the last five years.
The stationary source permitting requirement has yet to affect most sources. As of early September 2013, EPA and the states have issued only 110 GHG permits to stationary sources since the requirement was implemented in January 2011. (For comparison, EPA estimates that there are more than 6 million stationary sources.) EPA set the emission threshold for requiring permits at a high level, exempting most new sources of GHGs; and few new facilities have been constructed in the recession's aftermath.
Ultimately, if EPA is to reduce the nation's GHG emissions, as the President has committed to do, it will have to issue emission standards for broad categories of existing stationary sources. EPA took the first step toward setting such standards on April 13, 2012, with the proposal of standards for new electric generating units (EGUs). In a June 25, 2013, memorandum to the EPA Administrator, the President directed the agency to re-propose those standards by September 20, 2013, finalize them "in a timely fashion after considering all public comments," and propose guidelines for existing EGUs by June 1, 2014. The re-proposed standards for new sources were announced on September 20, 2013.
As shown in Table 1 , EGUs—principally, coal-fired power plants—are the most significant U.S. source of greenhouse gases, accounting for about one-third of the nation's total emissions. With the principal mobile source categories already subject to GHG regulations, EPA will have addressed the sources of more than half of all U.S. emissions once it promulgates regulations for existing EGUs.

	New Source Performance Standards (NSPS)

To control GHG emissions from stationary sources, EPA intends to use Section 111 of the Clean Air Act, which requires the agency to set New Source Performance Standards (NSPS) when, in the Administrator's judgment, a category of sources causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. As noted, EPA proposed the first such NSPS/GHG standard, for electric generating units, on April 13, 2012, and following extensive public comment, at the President's direction, re-proposed the standard on September 20, 2013. The agency has also committed to the promulgation of NSPS for petroleum refineries, although it is unclear when those standards will be proposed.
Under Section 111, the EPA Administrator is required to set standards for categories of new (or substantially modified) major sources if, in her judgment, they cause or contribute significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. Over the past four decades, EPA Administrators have used this authority to set emission standards for numerous sources of conventional pollutants, such as sulfur dioxide or nitrogen oxides. The standards are to reflect the degree of emission limitation achievable through application of the best "adequately demonstrated" system of emission reduction. The Administrator can take costs, health impacts, environmental impacts, and energy requirements into account in setting the standards; she can distinguish among classes, types, and sizes of sources; and she must review the standards at least every eight years.

		Regulating Existing Sources Under Section 111

In addition to standards for new sources, Section 111 requires that EPA develop guidelines applicable to GHG emissions from existing units whenever it promulgates GHG standards for new sources in a category (Section 111(d)). Using the guidelines, states would be required to develop performance standards for existing sources. These standards could be less stringent than the NSPS, taking into account, among other factors, the remaining useful life of the existing source to which the standard applies. Nevertheless, these standards might have far greater impact than the NSPS, given that existing power plants are the largest U.S. source of GHG emissions.
The authority to control existing sources is particularly important in sectors like the electric utility industry, where old units can continue operating for decades. The average coal-fired power plant in the United States is more than 40 years old. Without the authority to control emissions from such existing facilities, it could be decades before emissions from most power plants would be controlled.
How quickly Section 111(d) standards will be applied to existing sources has been an open question, however. EPA must first propose and promulgate guidelines, following which the states will be given time to develop implementation plans. In the President's June 25 memorandum, he requested that EPA:
(i) issue proposed guidelines for modified, reconstructed, and existing power plants by no later than June 1, 2014;
(ii) issue final guidelines by no later than June 1, 2015; and
(iii) include in the guidelines addressing existing power plants a requirement that states submit to EPA the implementation plans required under section 111(d) of the Clean Air Act by no later than June 30, 2016.
Following approval of the plans, the act envisions case-by-case determinations of emission limits. Thus, it is likely to be several years before existing power plants or other stationary sources are subject to emission limits for GHGs.

	EPA's NSPS Proposals for EGU Greenhouse Gas Emissions

As noted, the President directed EPA in his June 25 memorandum to re-propose the NSPS standards for power plant carbon pollution. To understand what issues the agency has addressed in the re-proposed standards, this report discusses both the 2012 proposal and the September 2013 re-proposal.

		Emission Limits9

The re-proposed standard would set a limit of 1,100 pounds of carbon dioxide (CO 2 ) per megawatt-hour (MWh) of electricity generated for coal-fired EGUs, and a standard of 1,000 or 1,100 lbs/MWh (depending on the size of the unit) for new natural gas-fired plants. The standard is to be measured on a gross output basis; it requires reduction of emissions whether the electricity is used on site (e.g., for the operation of pollution control equipment) or is sold to customers.
The standards can be met by new natural gas combined cycle plants without add-on emission controls. Coal-fired plants, however, would find it impossible to meet the 1,100 lb. standard without controls to capture and store some of the CO 2 they produce. EPA estimates that a supercritical pulverized coal-fired power plant without such controls produces roughly 1,800 lbs. CO 2 /MWh of electricity, so a plant subject to the standard would need to reduce emissions by about 40%.
Carbon capture and storage (CCS) technology that might be used to reduce CO 2 emissions has been the subject of much recent research and demonstration. It poses a number of challenges, not the least of which is the additional energy it consumes. The energy required to run equipment that can remove CO 2 from an emission stream (referred to as the "parasitic load") is currently in the range of 30% on most demonstration projects. In addition, a CCS-equipped unit might incur costs for underground storage of the captured CO 2 (unless it is used for enhanced oil recovery) and possibly significant costs for building and operating a pipeline to transport the CO 2 to the storage location.
To address the concerns of those who maintain that CCS technology is not yet available, or who expect the technology to improve (bringing down costs) as research and demonstration continue, the agency's 2012 proposal included an alternative under which coal-fired facilities would have been allowed to average their emissions over a 30-year period: during the first 10 years, such facilities could have emitted up to 1,800 lbs. CO 2 /MWh; the facility would then have needed to reduce emissions to 600 lbs/MWh for the following 20 years. This option is not included in the September 2013 re-proposal, but the proposal does include two optional compliance periods. Compliance can be measured using a rolling average of emissions for 12-month periods or it can be measured using the rolling average for 84-month periods. If the facility chooses the longer compliance measurement period, it would gain flexibility to exceed the proposed standard over longer periods of time, but it would need to meet a lower standard overall: EPA has proposed somewhere in a range of 1,000 to 1,050 lbs/MWwh for the 84-month standard. The agency requests comments on the appropriate number.
NSPS are different from other Clean Air Act emission standards in that, once a standard is final, it applies to sources that commenced construction after the date of proposal in the Federal Register , rather than taking effect after the date of the final standard's promulgation. EPA has identified only three facilities with construction permits that might be affected by this retroactive application of a final standard: the Wolverine project in Rogers City, MI; a Washington County, GA, project; and a Holcomb, KS, project. The developers of the latter two maintain that they have commenced construction. Assuming this is the case, these sources would not be considered new sources and would not be subject to the NSPS. The status of the third facility, the Wolverine project, is less certain, but EPA is proposing to exempt it from the NSPS, stating:
The EPA has not formulated a view as to the project's status in the development process or as to whether the proposed 1,100 lb CO 2 /MWh standard or some other CO 2 standard of performance would be representative of BSER [Best System of Emission Reduction] for this project, and invites comment on these questions.

		EPA's Cost-Benefit Analysis

EPA's Regulatory Impact Analysis (RIA) for the 2012 proposal concluded that "even in the absence of this rule, existing and anticipated economic conditions in the marketplace will lead electricity generators to choose technologies that meet the proposed standards." EPA repeats this conclusion in nearly identical language in the RIA for the September 2013 proposal. The economic conditions referred to include the abundance and low projected cost of natural gas, the many state requirements that increasing amounts of electricity come from renewable sources, and the increasing cost of coal-fired electricity due to higher coal prices and new emission standards for emissions of conventional and toxic air pollutants. These factors combined make it likely that almost all new generation will come from natural gas combined cycle or renewable sources, according to EPA.
In preparing the 2012 NSPS proposal, EPA ran the Integrated Planning Model—a model developed by ICF Inc. that EPA and many industry sources have used to analyze the impacts of regulations since the 1980s—to analyze the sensitivity of the results to various assumptions. (The agency does not appear to have conducted new model runs for the 2013 re-proposal, but it reviewed its analysis using the Energy Information Administration's latest Annual Energy Outlook [AEO2013] and concluded that the 2012 results held.)
The IPM scenarios tested included a high electricity demand scenario, a low gas recovery scenario (which results in higher prices for natural gas), and a scenario combining both assumptions. None of these assumptions caused the model to project construction of new coal-fired capacity. The analyses found that "the price of natural gas would have to increase to approximately $10/mmBtu [million Btu] for coal boilers without CCS to become competitive with combined cycle natural gas units, which is projected to be very unlikely." Similarly, the 2013 RIA states, "It is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011 dollars) that new coal-fired generation without CCS approaches parity with NGCC [Natural Gas Combined Cycle].... " The RIA adds:
For context, a natural gas price level of $10/MMBtu (in 2011 dollars) is higher than any annual natural gas price to the electric power sector since at least 1996, when the EIA data series stops. In addition, the highest projected average annual natural gas price during the analysis period in any of the [EIA's] AEO2013 scenarios cited in this chapter is $6.64/MMBtu in the Low Oil and Gas Resource scenario.
With no new coal plants on the horizon (except for those already under construction or demonstration projects), EPA sees little quantifiable impact from its prospective NSPS promulgation. As the 2013 RIA states:
EPA anticipates that the proposed EGU New Source GHG Standards will result in negligible CO 2 emission changes, energy impacts, benefits or costs for new units constructed by 2020. Likewise, the Agency does not anticipate any notable impacts on the price of electricity or energy supplies. Additionally, for the reasons described above, the proposed rule is not expected to raise any reliability concerns, since reserve margins will not be impacted and the rule does not impose any requirements on existing facilities.
The 2012 RIA argued the case for the rule as a backstop, in case its projections of market conditions were inaccurate:
This NSPS provides legal assurance that any new coal-fired plants must limit CO 2 emissions. Rather than relying solely on changeable energy market conditions to provide low emissions from new power plants in the future, this rule prevents the possible construction of uncontrolled, high-emitting new sources that might continue to emit at high levels for decades, contributing to accumulation of CO 2 in the atmosphere.… In addition, EPA intends this rule to send a clear signal about the future of CCS technology that, in conjunction with other policies such as Department of Energy (DOE) financial assistance, the agency estimates will support development and demonstration of CCS technology from coal-fired plants at commercial scale….
The proposed rule, in EPA's view, will assist in the deployment of CCS technology, by removing regulatory uncertainty that may have hindered its deployment:
The rule will reduce regulatory uncertainty by defining requirements for emission limits for GHG from new fossil fuel-fired EGU sources. In addition, the EPA intends this rule to send a clear signal about the current and future status of CCS technology. Identifying partial implementation of CCS technology as the best system of emission reductions (BSER) for coal-fired power plants promotes further development of CCS, which is important for long-term CO 2 emission reductions.
An example of how the absence of a regulatory requirement has hindered the development of CCS technology is provided in the re-proposed rule's preamble:
In 2011, AEP [American Electric Power] deferred construction of a large-scale CCS retrofit demonstration project on one of their coal-fired power plants because the state's utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to reduce CO 2 emissions. AEP's chairman was explicit on this point, stating in a July 17, 2011 press release announcing the deferral:
"We are placing the project on hold until economic and policy conditions create a viable path forward … We are clearly in a classic 'which comes first?' situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry's share."
Besides addressing regulatory uncertainty, the promulgation of New Source Performance Standards, even if the standards have little or no effect on new sources, serves as the precondition for standards affecting existing units. The latter are described in Section 111(d) of the Clean Air Act as "standards of performance for any existing source ... to which a standard of performance under this section would apply if such existing source were a new source." EPA would have no legislative authority to promulgate such standards if it did not first establish standards for new sources.

	Questions Regarding the Re-proposed Rule

Many in the electric power and coal industries view the proposed and re-proposed standards, if either were finalized, as effectively prohibiting the construction of new coal-fired power plants other than those granted exemptions. Whether carbon capture and storage (CCS) technology has been "adequately demonstrated" is the key question they raise. Other questions involve whether the cost of compliance, assuming CCS is available, and the increased energy required to capture and store carbon should lead the Administrator to propose a less stringent standard. Whether the proposed standard is barred by statutory language that prohibits the Administrator from requiring the installation and operation of any particular emission reduction system is another issue that has been raised.

		Has CCS Been Adequately Demonstrated?

EPA maintains that the components of CCS technology have been demonstrated on numerous facilities. In the preamble to the 2012 proposal, the agency stated, "… at present, CCS is technologically feasible for implementation at new coal-fired power plants and its core components (CO 2 capture, compression, transportation, and storage) have already been implemented at commercial scale." Specifically, the agency said:
Capture of CO 2 from industrial gas streams has occurred since the 1930s using a variety of approaches to separate CO 2 from other gases. Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. Approximately 50 million metric tons of CO 2 are transported each year through 3,600 miles of pipelines. Moreover, a review of the 500 largest CO 2 point sources in the United States shows that 95% are within 50 miles of a possible geologic sequestration site, which would lower transportation costs. With respect to carbon sequestration/storage, there are at least four commercial integrated CCS facilities sequestering CO 2 into deep geologic formations and applying a suite of technologies to monitor and verify that the CO 2 remains sequestered.
Similar statements are made in the re-proposal.
Critics of the agency maintain that even if the components have been demonstrated, there is no plant that captures and stores CO 2 on the scale of a large coal-fired power plant. There are several large power plants currently under development that will demonstrate CCS at commercial scale when completed, but none of these is currently operational, and several planned projects have been abandoned for a variety of reasons.
In the supporting materials for the re-proposed rule, EPA identified five plants that are incorporating CCS on a commercial scale: Southern Company's Kemper County (Mississippi) Energy Facility; SaskPower's Boundary Dam CCS Project in Estevan, Saskatchewan, Canada; Summit Power's Texas Clean Energy Project, near Odessa, Texas; the Hydrogen Energy California Project in Kern County, California; and NRG Energy's post-combustion carbon capture project at the company's W.A. Parish generating station southwest of Houston, Texas. Three of these (the latter three) are still in the planning stages, and the other two (Kemper and Boundary Dam) are still under construction. Both of the latter have experienced large cost overruns.

		Should Cost and/or Energy Considerations Have Led EPA to Propose a Less Stringent Standard?

Although it maintains that CCS has been adequately demonstrated, EPA stated in 2012, based on DOE estimates, that "using today's commercially available CCS technologies would add around 80 percent to the cost of electricity for a new pulverized coal (PC) plant, and around 35 percent for a new advanced gasification-based (IGCC) plant." The statement was not specific, but presumably referred to the cost of capturing and storing a plant's total CO 2 emissions. The Congressional Budget Office, in a June 2012 report, reached essentially the same conclusion. Since the proposed rule would require capture of only 40% of a coal-fired plant's carbon emissions, the added cost would be lower. The preamble to the proposed rule states that an 1,100 lb./MWh standard would add 20% to the cost of electricity from a supercritical pulverized coal plant, without accounting for revenues from the use of the CO 2 for enhanced oil recovery.
Much of the increased cost results from what is termed a "parasitic" energy load: capturing all of a coal-fired plant's CO 2 emissions, and compressing, transporting, and injecting them underground would use as much as 30% of the electricity that the plant produces. As CBO explained it, a CCS-equipped plant will cost more to build and operate for two main reasons:
The equipment a CCS plant requires to capture and compress CO 2 is large, complex, and expensive; and Capturing and compressing CO 2 consumes a substantial fraction of the plant's total output. Consequently, to produce the same amount of electricity for customers, a plant with CCS capabilities has to be bigger than a plant without them.
Both EPA and the Congressional Budget Office, among others, assume that the cost and energy penalty can be reduced through research, development, and demonstration, and both view EPA regulation as one of the policy tools that could lead to reduced cost by forcing the development of better technology. Experience suggests that such "learning by doing" will lower the cost, but the road to what might be a competitive technology can be a long one, and given the availability of other power sources (such as natural gas, renewables, and nuclear) with lower or no carbon emissions, it is not clear that the electric power industry will be motivated to pursue it.
Legal challenges to EPA's judgment that such a costly technology can be considered "adequately demonstrated" and that the degree of emission reduction required is "achievable" as required by Section 111 would have to be filed in the D.C. Circuit Court of Appeals. D.C. Circuit decisions on NSPS have made clear that while EPA has some discretion in determining what is "adequately demonstrated," that discretion is not unlimited. In 1973, in Essex Chemical Corp. v. Ruckelshaus , the court explained that to be adequately demonstrated, a system must be one "which has been shown to be reasonably reliable, reasonably efficient, and ... [not] exorbitantly costly in an economic or environmental way." In turn, an "achievable" standard is one that is "within the realm of the adequately demonstrated system's efficiency and which, while not at a level that is purely theoretical or experimental, need not necessarily be routinely achieved within the industry prior to its adoption." In Portland Cement Ass'n v. Ruckelshaus the same year, the circuit made clear that "adequately demonstrated" does not confine EPA to presently available technology: "The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on 'crystal ball' inquiry." Much later, in 1999, the D.C. Circuit in Lignite Energy Council v. EPA reiterated the point: "Because it applies only to new sources, we have recognized that section 111 looks toward what may fairly be projected ... , rather than the state of the art at present." Where data are not currently available, the court continued, EPA "may compensate ... through the use of other qualitative methods, including the reasonable extrapolation of a technology's performance to other industries."
Despite the potentially high cost of currently available CCS technology, the agency stated in both its 2012 and 2013 Regulatory Impact Analyses that it does not anticipate that the rule will have any impacts on the price of electricity, employment or labor markets, or the US economy. Other than demonstration projects supported by DOE or other incentives, EPA sees no new coal-fired units incorporating CCS in the next 10 years: given the low cost and projected abundance of natural gas, all new fossil-fueled units are likely to be powered by gas.
EPA's finding of no new, unplanned conventional coal-fired capacity (and therefore, no projected costs or quantified benefits) is robust beyond the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a wide range of alternative potential market, technical, and regulatory scenarios that influence power sector investment decisions.

		Should EPA Promulgate Separate Standards for Coal- and Gas-Fired Units?

Unlike the standard proposed in 2012, the September 2013 re-proposal would set separate standards for coal-fired and gas-fired EGUs. In this regard, the re-proposal is similar to most New Source Performance Standards promulgated previously for conventional pollutants (such as sulfur dioxide) emitted by electric generating units. As EPA noted in the preamble to the 2012 proposal, in setting standards for conventional pollutants or air toxics, it was not appropriate to combine coal-fired and gas-fired units in a single category, because "although coal-fired EGUs have an array of control options for criteria and air toxic air pollutants to choose from, those controls generally do not reduce their … emissions to the level of conventional emissions from natural gas-fired EGUs."
Critics of the 2012 GHG proposal took EPA's statement a step further, stating frequently that combining coal-fired and gas-fired units in a single category, as the 2012 proposal did, was "unprecedented." This is not actually the case: in 1998, EPA promulgated NSPS for emissions of nitrogen oxides (NOx) that imposed a single emission standard on all fossil-fueled EGUs. In Lig nite Energy Council v. U. S. EPA , the D.C. Circuit Court of Appeals squarely addressed the argument that a single fuel-neutral standard was impermissible and rejected that argument, thus upholding EPA's authority to issue a single standard applicable to all fossil-fueled sources.
Nevertheless, EPA reversed course in the 2013 re-proposal, and now proposes to set separate standards for coal-fired and gas-fired units.

		Is the Standard Barred by Statutory Language?

Critics of the proposed 2012 standard maintained that in setting the standard at 1,000 lbs. CO 2 /MWh, EPA would effectively have required coal-fired power plants to add CCS to any new unit. The same argument is likely to be used against the re-proposed standard for coal-fired units. The critics maintain that such a requirement violates Section 111(b)(5) of the Clean Air Act, which states that unless she determines that it is not feasible to prescribe or enforce a standard of performance, the EPA Administrator is not authorized to require a new source "to install and operate any particular technological system of continuous emission reduction to comply with any new source standard of performance."
Whether a court would find that EPA is imposing a "particular technological system" might come down to an interpretation of the term. There are several different technologies for carbon capture under development. Does the fact that they all result in capturing CO 2 make them a "particular technological system"? Or would a court find that the option of switching fuels to lower emissions means that sources can comply with the standard without having to install and operate a particular technological system?

	Guidelines for Existing Power Plants

The potential impacts of the NSPS rule extend beyond new sources, because the agency is obligated under Section 111(d) of the act to promulgate guidelines for existing sources within a category whenever it promulgates GHG standards for new sources. Using these guidelines, states will be required to develop performance standards for existing sources. These could be less stringent than the NSPS—taking into account, among other factors, the remaining useful life of the existing source to which the standard applies. But the standards could have far greater impact than the NSPS, given that existing plants account for one-third of total U.S. GHG emissions.
The average coal-fired power plant is about 40 years old; some are more than 60 years old. The older plants are generally less efficient than newer units, and most operate only a small percentage of the time. Thus, the agency might choose to set a guideline based on a less costly approach than application of CCS to the units' emissions. In presentation slides that the agency has used in stakeholder discussions, emphasis has been placed on improving efficiency as a preferred approach to reducing GHG emissions.
In recent months, considerable attention has been given to a proposal by the Natural Resources Defense Council (NRDC) as to how Section 111(d) guidelines might be structured. Under NRDC's plan, each state would be given an emission "budget" or cap based on the mix of fuels used by EGUs in the state to generate electricity in a base period (2008-2010 in the NRDC proposal). States with more coal-fired generation would receive higher budgets than those with more natural gas or renewable sources. The state budgets would be reduced in phases, with a target reduction of about 26% in GHG emissions overall by 2020, compared to 2005 emission levels—significantly less stringent than the re-proposed standard for new units.
Under this approach, EGUs could comply in a variety of ways: by shifting power dispatch to lower emitting plants (and thus running higher emitting plants less often), by switching fuels, by co-firing lower emitting fuels with coal, by retiring their least efficient plants, by efficiency improvements at existing plants, or by reducing demand. EGUs could average, bank, or trade emission credits; as a result, individual units would have an emissions target, but they could exceed the target if they had sufficient credits obtained from earlier reductions or from other units in the state's electric system. Since the goal would be to reduce emissions overall, rather than in specific states, states might also combine their markets for allowances, giving individual electric generating units and companies additional flexibility.
Whatever their form, a key question regarding the 111(d) guidelines has been when EPA would propose them. In his Climate Action Plan, the President resolved this question, as noted earlier, directing the agency to propose the guidelines by June 1, 2014, finalize them by June 1, 2015, and require the states to submit implementation plans by June 30, 2016. In cases where a state fails to submit a satisfactory plan, Section 111(d) also gives EPA the authority to prescribe and enforce a federal plan.

	Congressional Responses

Many in Congress oppose EPA standards for GHG emissions. The House passed two bills in 2011 ( H.R. 1 and H.R. 910 ) that would have prohibited EPA from promulgating GHG emission standards for any source, and it repeated itself in September 2012 with H.R. 3409 , the Stop the War on Coal Act. The Senate did not follow suit.
Legislation to limit or prevent EPA regulatory action is considered possible in the 113 th Congress, and may be given a boost by EPA's re-proposal of the Carbon Pollution Standard.
Enacting such legislation faces hurdles similar to those encountered in the last Congress, however. Although the House could take action to block NSPS regulations, the Senate is less likely to do so. If the House and Senate did act to limit executive branch authority, a bill sent to President Obama would almost certainly be subject to a veto, given the President's recent statements regarding the importance of dealing with climate issues.

	Conclusion

The debate over EPA's proposed carbon pollution standard for new power plants is largely symbolic, and is characterized by exaggeration on both sides.
It is symbolic because this rule by itself will have little impact. Its real significance is that without the promulgation of a rule for new sources, EPA cannot, under the Clean Air Act, proceed to regulate existing sources. It is the standards for those existing plants that may actually reduce the nation's GHG emissions, and in the process, could have significant impacts on coal-fired electricity. It is exaggerated because both EPA and the affected industries describe the rule itself as having far more impact than it will.
If EPA (among many sources) is correct that no new coal-fired power plants (other than demonstration projects) will be built in the foreseeable future even in the absence of the proposed rule, then the rule will have little effect. It will have little impact on the coal industry or the electric power industry in the near term, and it will not cause emission reductions from these industries. Both are adjusting to a new set of economic conditions, in which coal finds it harder to compete with natural gas. Gas is projected by most experts to be cheap and abundant for the foreseeable future. Since the early 1990s, new coal-fired plants have accounted for less than 10% of new power-generating capacity (see Figure 1 ). In these conditions, the electric power industry is likely to continue what it has already been doing for two decades: building gas-fired plants (or relying on renewable sources) when it needs new capacity.
The coal industry is unhappy with this, and has tended to place the blame for its current difficulties on EPA; but, actually, the market is the key factor in coal's recent decline. This market is affected by a number of elements, including the development of new technologies that have revolutionized production of natural gas, by state-level requirements for the use of renewable power sources, by stagnant growth in demand for electricity, and by environmental regulations mandated by Congress in the 1990 Clean Air Act amendments that are only now being implemented.
The net result is that coal is simply not competitive with natural gas in most areas of the country when power producers consider new generation facilities in current and foreseeable conditions. EPA's analysis finds that natural gas would need to triple in price for coal to be competitive with it, even without the potential cost of this rule. Further, the agency concludes, in every year since 1996, the economics of gas have made it a more cost-effective choice when planning new power generation. This rule will tilt the playing field even further against new coal-fired generation, but the field was already tilted far in that direction. To say that the rule will effectively prohibit the construction of new coal-fired power plants, as many in the coal and electric power industries do, is to focus on only one among many factors.
While EPA is essentially correct in saying that this rule will have little effect on industry, the agency seems to exaggerate the benefits of the rule. In her speech at the National Press Club on September 20, EPA Administrator McCarthy maintained that
The standards set the stage for continued public and private investment in technologies like Carbon Capture and Sequestration (CCS). With these investments, technologies will eventually mature and become as common for new power plants as scrubbers have become for well-controlled plants in generation today.
If the standards won't have any cost or impact, because no new coal-fired capacity subject to them will be built, then they will do little to stimulate the development of CCS technology.
The rule does not mean the end of coal mining, or the end of coal-fired power, however. Existing coal-fired plants, which have amortized much of their capital cost, still generate about 40% of the nation's electricity, even with the low price of natural gas and even with the costs of current environmental regulations. Since power plants can last for decades, coal could play an important role in the nation's energy future for decades to come. Furthermore, as many in the utility industry maintain, power producers have an interest in maintaining a diverse mix of fuel sources. Projections regarding the cost of generation a decade or more in the future are uncertain at best: few would have predicted the current glut of natural gas a decade ago. Energy markets are notoriously volatile and difficult to foresee. With that in mind, coal is likely to remain in the mix, in part as an insurance policy against uncertain future conditions, especially at plants that are already in operation and meeting existing standards for other pollutants.
But here the spotlight returns to EPA. The future of coal and coal-fired electricity could be greatly affected by the next carbon pollution standard, the guidelines for existing units. The fight over that rule, which is due to be proposed in June 2014, should place the current debate in its true perspective.

Output:
As President Obama announced initiatives addressing climate change on June 25, 2013, a major focus of attention was the prospect of greenhouse gas (GHG) emission standards for fossil-fueled—mostly coal-fired—electric generating units (EGUs). EGUs (more commonly referred to as power plants) are the largest anthropogenic source of greenhouse gas emissions, accounting for about one-third of total U.S. GHGs. If the country is going to reduce its GHG emissions by significant amounts, as the President has committed to do, emissions from these sources will almost certainly need to be controlled.
The President addressed this issue by directing EPA to re-propose GHG emission standards for new EGUs by September 20, 2013. He also directed the agency to propose guidelines for existing power plants by June 2014, and finalize them a year later.
EPA had already proposed standards for new sources in April 2012, but the public comment period had generated more than 2.5 million comments—the most ever for a proposed EPA rule—and the agency had not yet finalized the rule.
The re-proposed standards were released September 20. They would set an emissions limit of 1,100 pounds of carbon dioxide (CO2) per megawatt-hour (MWh) of electricity generated by new coal-fired EGUs, and a standard of either 1,000 or 1,100 lbs/MWh (depending on size) for new natural gas-fired plants. Coal-fired plants would find it impossible to meet the standard without controls to capture, compress, and store underground about 40% of the CO2 they produce—a technology referred to as carbon capture and storage (CCS).
Under the Clean Air Act, the EPA Administrator has a great deal of flexibility in setting these standards. The statute requires that New Source Performance Standards (NSPS) reflect the degree of emission limitation achievable through application of the best system of emission reduction that has been "adequately demonstrated." The Administrator can take costs, health impacts, environmental impacts, and energy requirements into account in determining what has been adequately demonstrated.
Many in the electric power and coal industries maintain that CCS has not been adequately demonstrated. Given the high cost and energy use of CCS components, they view the re-proposed standards as effectively prohibiting the construction of new coal-fired power plants.
EPA, on the other hand, states that the components of CCS technology have been demonstrated on numerous facilities. Details are provided in the preamble to the proposed rule. Despite this, the agency concludes that no coal-fired EGUs (other than DOE-sponsored or other demonstration projects) will be built in the next 10 years regardless of whether the rule is finalized, and therefore no units will be required to use CCS before EPA must review the standard. Given the projected low cost and abundance of natural gas, all new fossil-fueled units are likely to be powered by gas, according to EPA. The standard proposed for these facilities (combined cycle natural gas units) can be met without add-on emission controls, according to the agency.
Although the September 20 proposal would only affect new EGUs, the potential impacts of the rule's issuance extend beyond these sources, because the agency is obligated under Section 111(d) of the Clean Air Act to promulgate guidelines for existing sources within a category when it promulgates GHG standards for new sources. The President directed EPA to propose such guidelines by June 2014 and to finalize them a year later. Using these guidelines, states will be required to develop performance standards for existing sources. These could be less stringent than the NSPS—taking into account, among other factors, the remaining useful life of the existing source—but the standards could have far greater impact than the NSPS, given that they will affect all existing sources.
Many in Congress oppose GHG emission standards. In the 113th Congress, hearings have been held and several bills to prohibit or limit EPA GHG standards have been introduced. The proposed standards have stirred new interest in congressional action.


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RS20425 -- Satellite Television: Historical Information on SHVIA and LOCAL
Updated December 15, 2004

	The Satellite Home Viewer Improvement Act (SHVIA)

The 1999 Satellite Home Viewer Improvement Act (1) (SHVIA) expands on and extends some provisions of the 1988Satellite Home Viewer Act (SHVA), as amended, regarding consumer reception of television signals via satellitedishes. Two major companies, EchoStar and DirecTV (a subsidiary of News Corp.), offer satellite televisionservicestoday through their direct broadcast satellite (DBS) systems. EchoStar's service is called Dish TV. DirecTV'sprogramming is also distributed through the National Rural Telecommunications Cooperative (NRTC) and byPegasusCommunications. Another company, Rainbow DBS (a subsidiary of Cablevision) offers a comparatively smallnumber of satellite channels though a service called Voom. Historical information on SHVA and the issuesCongressfaced in revising it are available in CRS Report 98-942.
The 1999 law, SHVIA, provides consumers greater access to broadcast network television programming via theirsatellite dishes. The original law permitted rebroadcast of distant network signals to consumers wholived outside the"Grade B contour" of broadcast network affiliate stations. The 1999 law continues to permit that activity, but also allows satellite companies to rebroadcast local network signals back into the same localmarket area. They are notrequired to do so, however.
Local versus Distant Network Signals. The distinction between local and distant network signals is important to understanding SHVIA. A local signal is received within a networktelevision affiliate's local area. A distant signal is from elsewhere in the country. If a consumer lives in Denver andisreceiving a signal from a Denver network affiliate, that is a local signal. If a consumer lives in West Virginia andisreceiving a signal from that Denver network affiliate via satellite, it is a distant network signal.
Who May Receive Distant Network Signals. The original SHVA established the "Grade B" (2) contour as thedetermining factor as to whether a particular household was eligible toreceive distant network signals via satellite. Consumers living inside the Grade B contour were not allowed toreceivesuch signals while those outside the contour (in so-called "white areas") were allowed to receive them. Somesatellitecompanies transmitted distant network signals to consumers inside Grade B contours, however, leading to courtchallenges by the networks to try to force the satellite companies to obey the law. Based on decisions by a Miamijudge in 1998, over 2 million consumers reportedly had, or were scheduled to have, distant network signalsterminatedby their satellite companies. EchoStar appealed the decision to the Supreme Court in 2002, which declined to hearthecase.
In the 1999 law, Congress "grandfathered" consumers who had been receiving distant network signals illegally as longas they could not receive a signal of "Grade A" 2 intensity. For new subscribers, however, the originalrules apply. Toreceive distant network signals, new subscribers must not be able to receive a signal of Grade B intensity asdetermined using the Individual Location Longely-Rice (ILLR) method for predicting signal strength establishedbythe Federal Communications Commission (FCC) in February 1999. SHVIA directed the FCC to review whethertheGrade B standard should still be used for the purposes of SHVIA. The FCC concluded it should (FCC-016, ETDocket No. 00-90).
Consumers who believe they are not receiving a Grade A or Grade B signal despite predictive models showing thatthey are may seek a waiver to receive distant network signals via satellite. Consumers must apply to their satellitecompany for the waiver. The satellite company forwards the request to the local network affiliate. There is no timelimit for the satellite company to take that action. Once the request is received, the local affiliate has 30 days todecidewhether or not to grant the waiver. If the waiver is granted, or if no action is taken by the affiliate, the consumermaythen receive distant network signals from the satellite company. If a waiver is denied, consumers may then requestasignal intensity test from their satellite company. The satellite company and the local affiliate are required jointlytochoose someone to conduct the test. The consumer does not bear the cost of the test. Instead, the "loser" pays(eitherthe satellite company or the affiliate), or the satellite company and the affiliate may choose some other method ofpaying the costs as long as the consumer does not pay. Exceptions were made for recreational vehicles (as definedbyDepartment of Housing and Urban Development regulations), commercial trucks (as defined by Department ofTransportation regulations), and for consumers using large "C-band" satellite dishes. The RV or commercial truckcannot be a fixed dwelling.
In summary, the following consumers may receive distant network signals until December 31, 2004, the period forwhich the compulsory license (see below) was extended:
if they do not receive a signal of Grade B intensity from the local affiliate of a particular network;
if their satellite dish is installed on an RV or commercial truck, or
if they had been receiving distant network signals illegally and those signals were terminated orscheduled to be terminated under the 1998 Miami court rulings, and they do not receive a signal ofGrade A intensityfrom the local affiliate of the network.
Consumers using "C-band" dishes are not subject to the five year limitation. They may receive distant network signalsthey were receiving before October 31, 1999 indefinitely.
Who May Receive Local Signals. SHVIA permits DBS companiesto provide "local-into-local" service, where a local broadcast TV signal is transmitted up to the satellite and backdown to consumers in that same "designated market area" (DMA). The law does not require the DBScompanies toprovide this service. There is considerable confusion on this point, stemming, in part, from the fact the lawalsocreated a " must carry " provision. Under must carry, each DBS company must provide all local broadcast stations ina particular market if it provides any local station in that market. This does not mean that DBScompanies must carrylocal broadcast programming throughout the country . Instead, if a DBS provider chooses to provide local broadcastprogramming in a market, it must carry all local TV stations in that market that wish to be carried (with exceptionsforduplicative programing and educational stations). The DBS companies still may choose not to providelocal-into-local service in any particular market.
Cable companies already were subject to must carry rules (depending on the size of the cable system). The must carryprovisions for DBS went into effect on January 1, 2002. (3) The DBS companies oppose the must carry requirement(see below) and unsuccessfully attempted to overturn it in court.
According to their respective websites, as of October 2004, EchoStar offered local-into-local in 152 markets andDirecTV in 106 markets. Both plan to add more markets as additional capacity becomes available. There are 210designated market areas (DMAs) in the United States as identified by Nielsen Media Research, meaning that manysmaller communities do not receive local signals via satellite. DMAs differ in size, so the number of DMAs servedisnot necessarily indicative of the percentage of the population able to receive local-into-local. When EchoStar passedthe 100 DMA mark, it reported that 83% of the population could receive its local-into-local service. DirecTVassertsthat it will provide local-into-local in at least 130 DMAs by the end of 2004, which it says represents 92% of TVhouseholds. Congress passed the LOCAL Act (see below) in 2000 to help ensure that small and rural areas thatcannotobtain local-into-local service from EchoStar or DirecTV can receive local television via other satellite or terrestrialtechnologies.
Compulsory Copyright License. Another issue regarding satellite retransmission of television programming concerns compensation to those who own the copyright on theprogramming. Under both the 1988 and 1999 laws, satellite carriers were given a compulsory copyright license forrestransmitting distant network and superstation signals. That means that the copyright owners must make thatprogramming available to the satellite companies at government-set prices. (4) Without such a license, the satellitecompanies would have to negotiate with each copyright owner individually. The 1999 law extended the compulsorylicense for distant network signals for five years, until December 31, 2004. The 108th Congress isconsidering whetherto extend it further, and whether to change how the prices are set (see CRS Report RS21768 ). For retransmittinglocalsignals, however, Congress gave the satellite companies a royalty-free permanent compulsory copyright license. Cable has a permanent compulsory copyright license. (Copyright compensation is separate from businessarrangements negotiated to obtain retransmission consent, which is explained in footnote 3 below.)
Table 1: Summary of SHVIA Provisions
permits satellite companies to offer local-into-localtelevision service;
makes must-carry requirements effective for satellites on January 1, 2002;
makes syndicated exclusivity, sports blackout, and network nonduplication applicable to satelliteretransmission of nationally distributed superstations, but for network stations, only sports blackout applies and onlyiftechnically feasible and not economically prohibitive;
allows subscribers who do not receive a Grade A intensity signal and whose distant networksignals were terminated or were going to be terminated because of 1998 Miami court rulings to have those signalsrestored or continued until December 31, 2004 ("grandfathering" many of the subscribers affected by the 1998 courtdecision);
retains the Grade B signal intensity standard as the criterion for who may receive distant networksignals;
allows subscribers unable to receive a Grade B signal, as well as recreational vehicles andcommercial trucks that are not fixed dwellings, to receive no more than two distant network signals of eachtelevisionnetwork on a single day;
establishes a process for consumers to seek waivers from local affiliates to receive distantnetwork signals if signal strength is in doubt, at no cost to the consumer;
allows C-band satellite customers to continue receiving distant network signals they werereceiving as of October 31, 1999 indefinitely;
extends the existing satellite copyright compulsory license for distant network and superstationsignals until December 31, 2004 and creates a new compulsory license for local network signals with no sunsetdate;
reduces the rate set in 1997 for copyright royalty payments satellite companies must pay by 45%for distant network signals and 30% for superstation signals (no copyright fees may be charged for localsignals);
eliminates the 90-day waiting period for cable subscribers; and
allows satellite companies to offer a national Public Broadcasting Service (PBS) feed throughJanuary 1, 2002; after that, local PBS stations would have to be carried in markets where local-into-local serviceisprovided.

	The LOCAL Act: Loan Guarantees, and "Northpoint"

In 1999, the conference version of H.R. 1554 would have created a loan guarantee program to help ensure that subscribers in small and rural markets benefit from the local-into-local provisions even though EchoStarand DirecTV do not plan to offer such service in all areas. The provision was deleted before final passage becauseofobjections by Senator Gramm that the proposal had not been sufficiently debated. Congress subsequently passedthe"Launching Our Communities Access to Local Television Act" (LOCAL) as Title X of the FY2001Commerce-Justice-State Appropriations Act as enacted by the FY2001 District of Columbia Appropriations Act( P.L.106-553 ).
Loan Guarantees. LOCAL created a four-person board, consisting of the Secretaries of Treasury, Agriculture, and Commerce, and the Chairman of the Federal Reserve, or theirdesignees, to select recipients of loan guarantees for up to $1.25 billion in loans (generally, 80% of the loan maybeguaranteed). The loans may be used to build systems to ensure that consumers throughout the country can receivelocal television signals. The Board is to take into account whether a project serves "nonserved" or "underserved"areas and whether it would provide high-speed Internet access. The act is technology neutral in that it does notspecifywhether local TV stations would be provided by satellite, cable, or other transmission media, but places some limitson which cable companies are eligible. The Board's website is http://www.usda.gov/rus/localtvboard/ . The Boardissued regulations for the LOCAL Television Loan Guarantee Program in the December 23, 2003 FederalRegister (pp. 74411-74433). An application period ended April 21, 2004. One application was received. On May 24, theBoard voted 3-1 to return that application because it was incomplete, and then voted unanimously to open another60-day application period. However, the Board rescinded the latter decision on July 6.
The loan guarantee program is administered by the Rural Utilities Service in the Department of Agriculture, whichreceived $280 million in the FY2002 Agriculture appropriations act ( P.L. 107-76 ) for the program. Section 6404ofthe Farm Security and Rural Investment Act ( P.L.107-171 , H.R. 2646 ) allocated $80 million for theprogram from the Commodity Credit Corporation through December 31, 2006. GAO is required to review theprogram annually, and criticized the slow progress of the program in its first such report (GAO-04-134, October2003). Its second report (GAO-05-18R, October 2004) stressed the need for the Board to accurately accumulateandreport administrative costs to meet federal cost accounting requirements and determine what portion must berecovered through fees.
The "Northpoint Provision". LOCAL required the FCC to select an independent entity to conduct tests to determine whether terrestrial systems operating in the same frequency bandas DBS satellites (12.2-12.7 Gigahertz) would cause unacceptable interference to DBS systems. This is often called"the Northpoint provision" because a company called Northpoint Technology, through its Broadwave subsidiary,wants to operate a terrestrial wireless system offering TV programming similar to that provided by DBS, and dataservices. It is seeking a license from the FCC for that terrestrial service, designated MVDDS (Multichannel VideoDistribution and Data Service). Until now, the 12.2-12.7 GHz band has been assigned only to satellites. The FCCchose the MITRE Corporation to conduct the interference tests in 2001, and it concluded that the two systems couldnot co-exist unless the MVDDS systems use a number of mitigating techniques. DBS operators hailed the MITREreport because it concluded that MVDDS would cause interference to their operations. Northpoint hailed the reportbecause it said there were mitigating steps that could be taken.
The FCC decided that MVDDS and DBS could co-exist, but dismissed without prejudice applications by Northpointand two other companies to provide MVDDS (FCC 02-116, ET Docket 98-206), deciding to auction the frequenciesinstead. Northpoint objected to that decision, and chose not to participate in the auction. Other companies did,however, and the auction was completed on January 27, 2004, raising $118.7 million http://hraunfoss.fcc.gov/edocs_public/attachmatch/DOC-243253A1.pdf .
S. 564 , and H.R. 1320 as reported from the Senate Commerce Committee ( S.Rept. 108-168 ), would have eliminated the auction requirement for fixed terrestrial services (such as MVDDS) other thanmobile phones in the 12.2-12.7 GHz band. Similar language was in the Senate-passed version of the FY2004Commerce, Justice, State Appropriations bill (Sec. 626 of S. 1585 ), but not in the final version of the bill(part of the FY2004 Consolidated Appropriations Act, H.R. 2673 , P.L. 108-199 ).

Output: Congress has passed several laws to provide consumers greater access tolocal network television stations, particularly via satellite. The 1988 Satellite Home Viewer Act (SHVA), amendedin1994, was expanded in 1999 with the Satellite Home Viewer Improvement Act (SHVIA). SHVIA allows (notrequires) satellite companies to retransmit a local broadcast network signal back into the same localmarket area fromwhich it originates ("local-into-local"). Concerned that satellite TV companies do not plan to offer local-into-localinall parts of the country, Congress then passed the Launching Our Communities Access to Local Television Act(LOCAL). That act creates a loan guarantee program to help ensure that consumers in small and rural marketsreceivelocal network TV stations via satellite or other technologies. This historical report summarizes SHVIA andLOCAL,and the debate over whether a company called Northpoint should be able to use the same frequencies as satellitestotransmit data and television using terrestrial systems. It does not address the 2004 Satellite Home Viewer Extensionand Reauthorization Act (SHVERA). See CRS Report RS21768 instead. This report will not be updated.


Input:
	Paperwork Reduction: Burden Reduction Goal Unlikely to Be Met

Mr. Chairman and Members of the Committee: We are pleased to be here today to discuss the implementation of the Paperwork Reduction Act of 1995. As you requested, we have reviewed selected aspects of the act’s implementation by the Office of Management and Budget (OMB) and three agencies—the Internal Revenue Service (IRS), the Environmental Protection Agency (EPA), and the Occupational Safety and Health Administration (OSHA). In your request letter, you noted that participants at last year’s White House Conference on Small Business believed these three agencies impose the most significant paperwork burdens on small businesses.
We will focus on three main issues today: (1) changes in paperwork burden governmentwide and in the three selected agencies, (2) OMB’s responsibility to set goals for reducing such burden and whether agencies will achieve the burden reductions envisioned in the act, and (3) actions each of the three agencies have taken since the passage of the act. We will also discuss some measurement issues Congress needs to consider as it assesses agencies’ progress in reducing paperwork burden.

		Background

First, however, a little background information is needed. The Paperwork Reduction Act of 1995 amended and recodified the Paperwork Reduction Act of 1980, as amended. The 1995 act reaffirmed the principles of the original act and gave new responsibilities to OMB and executive branch agencies. Like the original statute, the 1995 act requires agencies to justify any collection of information from the public by establishing the need and intended use of the information, estimating the burden that the collection will impose on the respondents, and showing that the collection is the least burdensome way to gather the information. at the end of the fiscal year, and agency estimates of the burden for the coming fiscal year.
The 1995 act also makes several changes in federal paperwork reduction requirements. For example, it requires OIRA to set goals of at least a 10-percent burden reduction governmentwide for each of fiscal years 1996 and 1997, a 5-percent governmentwide burden reduction in each of the next 4 fiscal years, and annual agency goals that reduce burden to “the maximum practicable” extent. The act also redefines a “collection of information” to include required disclosures of information to third parties and the public, effectively overturning the Supreme Court’s 1990 Dole v. United Steelworkers of America decision. Finally, the 1995 act details new agency responsibilities for the review and control of paperwork. For example, it requires agencies to establish a 60-day public notice and comment period for each proposed collection of information before submitting the proposal to OMB for approval.
OIRA uses the ICB information to assess whether agencies’ burden reduction goals are being met. OIRA classifies changes in burden-hour estimates as caused by either “program changes” or “adjustments.” Program changes are additions or reductions to existing paperwork requirements which are imposed either through new statutory requirements or an agency’s own initiative. Adjustments are changes in burden estimates caused by factors other than changes in the actual paperwork requirements, such as changes in the population responding to a requirement or agency reestimates of the burden associated with a collection of information. OIRA counts both program changes and adjustments when calculating an agency’s burden-hour baseline at the end of each fiscal year. However, OIRA does not count changes that are due to adjustments in determining whether an agency has achieved its burden reduction goal.

		Changes in Paperwork Burden Over Time

Figure 1 shows changes in reported burden-hour estimates governmentwide and at IRS between September 30, 1980, and September 30, 1995—the day before the new act took effect. rose dramatically in 1989, and rose every year since then with the exception of 1993. In each year since fiscal year 1989, IRS’ paperwork burden has accounted for more than three-quarters of the governmentwide total. Increases or decreases in IRS’ total number of burden hours have had a dramatic effect on the governmentwide total. For example, the near tripling of the governmentwide burden-hour estimate during fiscal year 1989 was primarily because IRS changed the way it calculated its information collection burden, which increased its paperwork estimate by about 3.4 billion hours. Because the IRS paperwork burden is such a large portion of the governmentwide total, the success of any governmentwide effort to reduce burden largely depends on reducing the burden imposed by IRS.
Figures 2 and 3 show the changes in the paperwork burden at EPA and OSHA, respectively, during the same 1980 to 1995 period.
Statement  Paperwork Reduction: Burden Reduction Goal Unlikely to Be Met Burden hours (in millions)
Statement  Paperwork Reduction: Burden Reduction Goal Unlikely to Be Met Burden hours (in millions)
EPA’s burden-hour estimate rose sharply in the late 1980s, fell somewhat in 1991 (because third-party information collections were no longer being counted as a result of the Dole decision), and rose again between 1991 and 1995. OSHA’s burden-hour estimate increased gradually through 1987, rose rapidly in 1988, fell back to its previous level by 1990, and decreased slightly until it rose sharply between 1994 and 1995.
Figure 4 shows the month-by-month changes in the governmentwide paperwork burden between September 30, 1994, and March 30, 1996—the period including the date the 1995 act was signed by the President (May 22, 1995) and its effective date (October 1, 1995).
6.90 billion hours on September 30, 1995. IRS increased its burden-hour estimate by more than 147.6 million burden hours (about 3 percent) between August and September; EPA’s estimate went up more than 21 million hours (more than 25 percent) during that month. OSHA’s burden-hour estimate rose most dramatically shortly before the effective date, from about 1.5 million hours on June 30, 1995, to about 208 million hours on September 30, 1995.
Documents we reviewed and officials we talked to indicated that these increases occurred during this period because agencies were trying to get proposed information collections approved before the new act took effect on October 1, 1995. Some of the proposals at OSHA and EPA were third-party and public disclosures that had previously been removed from the agencies’ estimates because of the Dole decision. Other proposals, particularly those at OSHA, were third-party and public disclosures that had been added after the Dole decision. By getting these third-party and other proposed information collections approved before the act’s effective date, agencies were able to avoid the new requirements imposed by the act, including the 60-day public notice and comment period at the agencies. OIRA approved some of these collections of information for less than 1 year so that the agencies would have to clear the collections under the new process during fiscal year 1996.
However, submitting the proposals for review and approval before the act took effect also raised the burden-hour baseline against which the agencies’ paperwork reduction goals would be judged. For example, the increase in OSHA’s burden-hour baseline from about 1.5 million hours to about 208 million hours between June and September 1995 meant that OSHA had to cut more burden hours to achieve a 10 percent reduction (20.8 million hours) than it would have had to cut before the increase (about 150,000 hours).

		Burden Reduction Goals Not Set and Reductions Likely to Fall Short of Act’s Target

One of the key features of the Paperwork Reduction Act of 1995 is the requirement that OIRA set both governmentwide and agency-specific burden reduction goals for fiscal year 1996 and for the next 5 fiscal years. However, as of May 31, 1996, OIRA had not set any such goals. More importantly, information that the agencies submitted to OIRA indicated that the burden reduction target that the act specified for fiscal year 1996 is unlikely to be reached.

			Agencies’ Planned Burden Reduction Goals Will Average 1 Percent

OIRA staff told us that they plan to set the fiscal year 1996 burden reduction goals in a soon-to-be-published ICB. As part of the ICB development process, in September 1995, OIRA asked agencies to project what their burden-hour levels would be at the end of fiscal year 1996. Agencies submitted that information to OIRA between December 1995 and February 1996.
OIRA staff said that they will establish a governmentwide burden reduction goal of 10 percent for fiscal year 1996, as the act requires. They also said that agency goals will reflect the end-of-fiscal year 1996 burden-hour estimates that the agencies provided in their ICB submissions unless changed as a result of OIRA review. According to unpublished information we obtained from OIRA and the agencies, the weighted average of the agencies’ burden reduction projections is about 1 percent. If these projections are accurate, the fiscal year 1996 goal of a 10-percent reduction in governmentwide paperwork burden that the 1995 act calls for will not be accomplished. Figure 5 shows the actual month-to-month governmentwide paperwork estimates from March 1995 to March 1996 and, according to our calculations, what the number of burden hours would have been by the end of fiscal year 1996 if the 10-percent burden reduction goal had been achieved and what the burden-hour total is expected to be on the basis of agencies’ projections.
Statement  Paperwork Reduction: Burden Reduction Goal Unlikely to Be Met Burden hours (in billions) that will not add up to the governmentwide goal of a 10-percent reduction in burden. “individual agency goals negotiated with OIRA may differ depending on the agency’s potential to reduce the paperwork burden such agency imposes on the public. Goals negotiated with some agencies may substantially exceed the Government-wide goal, while those negotiated with other agencies may be substantially less.”

			OIRA Did Not Keep Congress Informed

In addition to setting goals for paperwork reduction, the act requires OIRA to “keep the Congress and congressional committees fully and currently informed of the major activities under this chapter.” However, as of May 31, 1996, the OIRA Administrator had not informed Congress or congressional committees (1) about why OIRA has not established any burden reduction goals to date and (2) that agency projections OIRA received at least 3 months ago indicated that the 10 percent governmentwide paperwork reduction goal called for in the act would not be achieved. Both of these issues appear to us to be “major activities” subject to the act’s requirement that the OIRA Administrator keep Congress fully and currently informed.

			Agencies Contend Statutory Requirements Impede Burden Reduction

Information collection is one method by which agencies carry out their missions, and those missions are established by Congress through legislation. For the past several years, the ICBs have indicated that agencies’ burden-hour estimates increased because of congressionally imposed statutory requirements. For example, the fiscal year 1993 ICB noted that title IV of the Clean Air Act Amendments of 1990 established new permitting requirements for emission sources that produce nitrous oxides, resulting in a 1.8 million hour increase to EPA’s burden-hour estimate. As a result of such requirements, some agencies contend that they are limited in the amount to which they can reduce their paperwork burden. If agencies’ paperwork requirements are truly statutorily mandated, those agencies may not be able to reduce their burden-hour estimates by the amounts envisioned in the 1995 act without changes in the legislation underlying those requirements.
However, neither we nor OIRA have assessed the extent to which the paperwork burden agencies impose is directly a consequence of statutory requirements and, therefore, is out of agencies’ control. Even though a statute may require an agency to take certain actions, the agency may have discretion regarding whether paperwork requirements need to be imposed and, if so, the manner or frequency with which the information is collected. For example, although several statutes require employers to provide training to employees, OSHA may have discretion to determine whether employers need to submit paperwork to demonstrate their compliance with these provisions.

		EPA, IRS, and OSHA Burden Reduction Targets and Actions Differ

As a part of their ICB submissions to OIRA, EPA, IRS, and OSHA each projected what it believed its total number of burden-hours would be as of September 30, 1996. Each agency also took different steps to reduce its paperwork burden.

			Environmental Protection Agency

EPA has its own effort to reduce paperwork that began before the Paperwork Reduction Act of 1995 took effect. EPA has set an internal burden-reduction target and expects to reach that target by the end of this year. Despite these efforts, EPA reported that their burden-hour reductions will be largely offset by increases in statutorily-based information collections.
In March 1995, the EPA Administrator committed to reducing the agency’s January 1, 1995, estimated paperwork burden by 25 percent by June 1996. Initially, EPA estimated that its January 1995 baseline was about 81 million burden hours, so a 25-percent reduction would bring the agency’s total to about 61 million hours. In March of this year, we provided a statement for the record to the House Committee on Small Business indicating that, despite these planned reductions, EPA projected that its burden-hour total would increase to about 117 million hours by September 30, 1996—an increase of about 44 percent from EPA’s January 1995 baseline. projection for September 30, 1996, from 117 million hours to about 100 million hours. EPA officials said their projection was revised because some planned information collections would not be approved by OIRA by the end of the fiscal year and because their original estimate did not include all of the burden-hour reductions that EPA now expects to make by the end of the fiscal year.
Using EPA’s most recent estimates, figure 6 shows EPA’s burden-hour baseline as of January 1, 1995, the 25-percent reduction goal that EPA expects to accomplish by December 31, 1996, and the total number of burden hours that EPA currently projects will be in place as of September 30, 1996. As you can see, despite EPA’s burden-reduction efforts during this period, EPA’s burden-hour estimate at the end of this fiscal year is expected to be about what it was at the start of those efforts. This is because, at the same time EPA has been reducing its January 1995 paperwork inventory, new burden hours have been added to that inventory. According to EPA, those additions are primarily third-party burden hours that are now being counted as a result of the Paperwork Reduction Act of 1995 and new information collections associated with the Clean Air Act Amendments of 1990 and the Residential Lead-Based Paint Hazard Reduction Act of 1992.
Statement  Paperwork Reduction: Burden Reduction Goal Unlikely to Be Met Burden hours (in millions)
Does not include about 9 million hours of third party burden. Does not include about 5 million hours of TRI burden.
5 million hours of burden associated with the Toxic Release Inventory (TRI).
Although EPA’s efforts to reduce burden hours have been almost totally offset by new information collection requirements, EPA’s attempt to reduce its paperwork burden may prevent what would otherwise be a significant increase in the agency’s paperwork burden. As of May 1996, EPA said that it had completed reductions of about 15 million hours and had identified about 8 million more hours of burden for elimination. If these figures are accurate, EPA would need to eliminate the 8 million burden hours it had identified and identify and eliminate about 2 million more hours to reach its goal of reducing its 101 million burden-hour baseline by 25 percent. Without the burden-hour reductions EPA says it has accomplished or has in progress, the agency’s paperwork burden could have increased by 25 percent by the end of the year.
Although EPA’s initiative to reduce the burden it imposes is promising, its burden-reduction claims warrant continued scrutiny. As we reported in our March 1996 statement for the record to the House Small Business Committee, some of EPA’s February 1996 burden reduction estimates were overstated. For example,
EPA initially claimed that a recently adopted TRI reporting option reduced the burden associated with TRI by about 1.2 million hours. However, EPA did not offset this reduction by the additional paperwork burden it created—about 800,000 hours—that would be incurred by those choosing this option. Therefore, the real burden reduction was about 400,000 hours.
EPA estimated that it had reduced the burden associated with its land disposal restrictions program by 1.6 million hours, but its January 1, 1995, baseline indicated that the entire program only accounted for about 800,000 hours. to revise its January 1, 1995, baseline from which the burden-hour reductions are being taken.

			Internal Revenue Service

Reducing burden on the taxpayer is one of the primary goals in IRS’s Business Master Plan, in which the agency identifies a number of burden-reduction actions that it plans to take. In its ICB submission, IRS said that it plans to reduce its measured paperwork burden by about 50 million hours (0.9 percent) during fiscal year 1996 by simplifying forms and instructions, changing reporting thresholds, and moving eligible taxpayers to “E-Z” versions of required forms.
IRS officials said they are limited in the amount to which they can reduce the agency’s paperwork burden because most of IRS’ information collections are statutorily mandated in the tax code. They said that unless changes are made to the substantive requirements in the code, IRS will not be able to substantially reduce its paperwork burden.
IRS officials also said that significant portions of the agency’s efforts to reduce its burden focus on types of burden that are not covered by the Paperwork Reduction Act. For example, they said that a major part of the real paperwork burden on the taxpayer comes from responding to IRS notices, and IRS has a major initiative under way to determine which notices can be eliminated, combined, or simplified. However, they said that notices are not covered by the act because they focus on information collected from a single individual in the course of an investigation or inquiry.

			Occupational Safety and Health Administration

OSHA officials said that they assumed their agency would be responsible for reducing its burden by 10 percent during fiscal year 1996 as its share of the governmentwide goal. In its 1995 ICB submission to the Department of Labor, OSHA said that it would reduce its fiscal year 1995 paperwork burden by 8.7 million hours (about 4 percent) during fiscal year 1996 by dropping a number of certification requirements. Although OSHA has begun the process of eliminating these certification requirements, in the spring of 1996 OSHA officials told us that the process may not be completed in time to eliminate the requirements by the end of the fiscal year.
After submission of its ICB, OSHA officials discovered that they could claim additional burden reductions. OSHA’s Process Safety Management of Highly Hazardous Chemicals Standard is a third-party information collection that the agency added to its burden-hour total in August 1995. At that time, OSHA officials estimated the paperwork requirements associated with the standard at 135 million burden hours. In keeping with a schedule established by the standard when it was issued in 1992, the burden imposed on employers declined in May 1996 because they were no longer required to perform certain recordkeeping functions after that date. OSHA officials said that they initially considered the decline in employer responsibilities an adjustment, which could not be counted toward the agency’s 10 percent burden reduction goal in their ICB submission. However, they said the Department of Labor paperwork clearance official told them the change should be considered a program change, and therefore should be counted as part of OSHA’s paperwork reduction effort. Consequently, OSHA reduced its 135 million burden-hour estimate by 17 million hours—8 percent of OSHA’s total fiscal year 1995 burden.

		Measurement Issues

As Congress exercises oversight in this area, it is important that it keep in mind several measurement issues. As noted previously, OIRA does not count any adjustments (because of reestimates or population changes) that agencies submit with their information collection requests in determining whether an agency has met its paperwork burden reduction goals. Therefore, an agency that initially submits a high estimate and later revises it downward does not get credit from OIRA for the reduction. Conversely, if an agency initially submits a low paperwork estimate and later increases the estimate, OIRA never counts the increase against the agency for goal attainment purposes. In fact, the governmentwide increase of about 1 billion burden hours between 1990 and 1995 was primarily driven by adjustments that never counted against agencies’ goals. OIRA staff told us they were not aware of any evidence that agencies were systematically underestimating the burden associated with their information collections and then revising them upward. interpreting the official burden-hour statistics. Most or all of the burden-hour increase may have actually existed since 1980 when the original Paperwork Reduction Act became effective. If this were the case, the statistics available to policymakers would seriously underestimate the burden actually imposed on the public, and figure 1 would overstate the degree to which paperwork burden actually increased since 1980.
The increase in measured burden as a consequence of the inclusion of third-party and public disclosures in September 1995 was similar to the IRS reestimate; the burden already existed but had just not been previously measured. Likewise, the burden felt by the public does not diminish when an agency recalculates a lower estimate of its paperwork burden without eliminating any existing requirements.
Relatedly, it is important that Congress be aware that certain elements of agencies’ information collection burden are not reflected in some burden-hour estimates. As we mentioned earlier, OIRA does not count about 5 million hours of paperwork burden associated with EPA’s TRI reporting form because the form is not submitted for OIRA approval. IRS’s burden-hour estimates do not include such information collections as notices involving errors, nonfilings, and delinquencies because they are exempted from coverage under the act.
Finally, as we have said in previous reports and testimonies, users of paperwork burden-hour estimates should proceed with great caution. The degree to which such estimates reflect real burden and the factors that cause changes to the burden-hour totals are often unclear. Nevertheless, they are the best indicators of paperwork burden available, and we believe that they can be useful as long as their limitations are borne in mind.
Mr. Chairman, this completes our prepared statement. We would be pleased to answer any questions.
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Output:
Why GAO Did This Study

GAO discussed governmentwide implementation of the Paperwork Reduction Act of 1995, and three federal agencies' actions to implement the act.

What GAO Found

GAO noted that: (1) between 1980 and 1995, reported governmentwide paperwork burden hours increased from about 1.5 billion to 6.9 billion; (2) the Internal Revenue Service (IRS) accounts for most of the federal paperwork burden; (3) IRS accounted for a three-fold increase in 1989 because it changed the way it calculated its information collection burden; (4) governmentwide burden hours increased almost 8 percent in the month before the act's effective date because agencies were trying to get proposed information collection activities approved before that date; (5) as of May 1996, the Office of Management and Budget's Office of Information and Regulatory Affairs had not set burden reduction goals or kept Congress informed about implementation progress; (6) agencies' weighted average burden reduction is likely to be 1 percent for fiscal year (FY) 1996, but the act's FY 1996 reduction goal is 10 percent; (7) agencies believe that statutory mission-related requirements limit their ability to reduce paperwork burdens; and (8) Congress should consider several measurement issues, including counting adjustments toward or against reduction goals, the difference between measured and actual paperwork burdens, and potentially incomplete agency burden estimates.