Document ID: EPA-HQ-OAR-2014-0020-0154
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2014-04-16T04:00Z

Clean Air Act Section 111(d) CO2 Reduction Compliance Pathways for the Pacific Northwest and Intermountain West States
                                          
                                          
                                          
                                          
                                          
                                          
                                          
                                          
                                          
                                    Angus Duncan
                      For the Natural Resources Defense Council
                                   March 31, 2014
                                     White Paper
      Clean Air Act Section 111(d) CO2 Reduction Compliance Pathways for the Pacific Northwest and Intermountain West States

      Abstract
      The paper describes the architecture of a regional electric grid extending across nine Intermountain West and Pacific Northwest states, characterized by coal-fired generation on the east and south serving loads across the region including states to the west with few or no coal facilities but with significant loads and energy efficiency opportunities.  This multi-state arrangement argues for an EPA Clean Air Act 111(d) strategy that calculates a Best System of Emissions Reduction (BSER) standard on a regional basis, then disaggregates and allocates reduction obligations to individual states and the emitting generating units therein.  Voluntary State-to-State agreements could then identify least-cost compliance strategies involving single or multiple shared facilities in one or more states. Such strategies might continue full plant operations at the most efficient plants in "producer" states, reduced output from or retirement of less efficient units, and replacement of lost generation with a least-cost portfolio of low-carbon resources in both "producer" and "consumer" states.  The desired outcome is overall regional "system" emissions that are in compliance with an EPA-set emissions standard for the region overall. 

Problem Statement
      The Obama Administration proposes to regulate greenhouse gas (GHG) emissions from existing power plants with the objective of reducing those emissions over time consistent with the nation achieving an overall GHG emissions reduction goal of 17% below 2005 levels by 2020.  The Environmental Protection Agency (EPA) plans to use Section 111(d) of the Clean Air Act (CAA) to develop a rule by mid-2015, and require state compliance plans one year later.  Those plans will either adopt EPA-issued "best system of emissions reduction" (BSER) guidelines, or gain EPA approval of State plans as resulting in equal or greater reductions.
	EPA is likely to afford substantial flexibility to States and plant owners in developing compliance plans, including allowing a "systems-based" approach under which emissions from two or more plants can be aggregated and averaged across the system counted for compliance.  EPA is also considering how new, low-carbon supply- and demand-side replacement resources can count toward compliance [to the extent they displace real emissions within the system subject to compliance requirements].
	Interstate electricity sales will complicate this regulatory structure.  It is not clear what compliance pathways will be workable for states whose utilities import significant quantities of power from coal-fired generation; and for states containing significant coal-fired generation that export to loads in other states.  Reconciling state-by-state compliance plans with this utility architecture  -  which is especially typical in the Pacific Northwest and Intermountain West states  -  will be challenging.
      At its most basic, the task is simply stated: 
            (1) What emissions reduction trajectory for existing thermal power plants serving this region is consistent with the requirements of the Clean Air Act (including cost consequences); and, 
            (2) How will the costs of compliance be allocated among plant owners and power consumers?  
      EPA can perform the calculations to arrive at the first; and utility regulators have tools to achieve the second (not without some wrangling), including in circumstances where plants and loads are distributed among two or more states.  An EPA 111(d) rulemaking process could choose to stop here.
      The harder, third task is not a legal requirement, but it is essential to undertake if the outcome, for the the region, is the appropriate emissions reduction that is also politically achievable:
            (3) What's a least-cost compliance pathway for customers of affected utilities, and for affected states facing community, employment and tax effects of potential plant cutbacks or closures?
	A lower cost pathway would rely on wider portfolio of energy efficiency, renewable resources and integrating resources outside the plant fenceline as replacement resources for reduced or terminated coal-fired generation.  The compliance role for such resources is to replace such generation and its associated emissions.
	EPA's summer 2014 draft rule needs to be written with the flexibility to allow such least-cost pathways, and with a framework that encourages states and utilities to devise and propose them.
	While the CAA does not contain a direct legal obligation to seek a least cost path, there are reasons to do so that should be compelling to all parties.  The first reason is that EPA is obliged to consider cost when setting a performance standard (in effect, the benefits of the regulation must outweigh the costs imposed by the regulation; see "111(d) Regulatory Process," below).  That test is expansive, allowing EPA to include both immediate and downstream societal costs and benefits, not just the transactional costs to the plant owners and their customers.  But it can mean only minor emissions reductions are obtained, especially from technical fixes at the power plants themselves.  In contrast, EPA guidelines that  -  by virtue of their wider choice of allowable compliance paths  -  result in lower costs to plant owners and their power customers, are more likely to invite cooperative efforts among producer states, consumer states and utilities to devise cooperative compliance strategies.  
      The optimum outcome, toward which EPA and those supporting an effective rule must bend their efforts, is the one that achieves material emissions reductions at costs that stay carefully within CAA limitations. 

The Pacific Northwest / Intermountain West Electricity System
	This challenge is especially complicated in the Pacific Northwest and Intermountain West, where a substantial part of the load lies along the I-5 corridor (the Seattle and Portland metro areas), while most of the coal-fired generation imported to serve these loads is located in Montana, Wyoming Nevada and Utah; and most of this generation in at least Montana and Wyoming is committed to out-of-state loads.  The respective coal-generation capacities are:

	Montana	2717 MW
	Nevada	  521 MW
	Oregon	  585 MW
	Utah		5204 MW
	Washington	1460 MW
	Wyoming	4627 MW
	Arizona	414 MW

        
      
      
      
      
      
      
      
      
      
      
      
      
      This difference becomes greater still in 2020 (when coal combustion ends at Boardman and one Centralia plant) and 2025 (the other Centralia plant is retired).  Neither Oregon nor Washington will then have any coal combustion remaining within their borders; and Idaho already is coal-free.   Yet all three will remain in significant degree dependent on imported coal generation to meet loads.
	The largest share of the remaining coal plants in the region is owned by PacifiCorp (PAC), but substantial shares in certain plants are divided up among multiple owners and serve loads in multiple states, complicating decision-making.  The plants also have different useful life designations.  All regional coal plants 40 years and older belong to PAC.  The selection of a baseline from which coal emissions reductions are measured, and the level of reductions required in each state under the rule, will affect plant owners differently, but PAC stands to be most challenged because of the makeup and age of its fleet, and because it operates (generates and serves loads) in multiple states.
	While this discussion centers on the coal assets of investor-owned PNW/IW utilities, there are also some 130 consumer-owned utilities in the PNW and more in the IW.  Most COU's are served from their own resources or from the federal hydropower system through the Bonneville Power Administration or Western Area Power Authority, and are unlikely to be significantly affected by an EPA carbon rule.  In addition there are both merchant coal plants (e.g., Centralia) and coal units owned and operated by other utilities but delivering power into the PNW grid, which will be accounted for in an EPA rulemaking.  To make this already complex subject slightly less complicated, this paper excludes these facilities.  State air regulators will need to deal with them however, and it is possible they could be wrapped into a system compliance strategy to collective benefit.
	Planning is further complicated by other Clean Air Act regulatory proceedings underway to which different plants have different exposures; and by price pressure from growing new sources of natural gas and declining cost curves for renewable technologies.
	Much of the region's long-distance transmission mileage is dedicated to east-to-west movement of power from these coal plants, and the economics of this transmission is substantially intertwined with the destinies of these facilities as well as with any replacement resource strategies for displaced coal generation.  How interstate sales and deliveries of energy are treated with respect to emissions liabilities will be critical to the calculations for each state and utility involved in these transactions, and their effects on utility determination of least-cost replacement resources, future energy contracts, and transmission investments and management of existing assets.
	
Dramatis Personae
      	The Power Plants:  There are thirty coal-fired power units at fourteen plant sites across eight states, with a combined nameplate capacity of 15,528 megawatts (see attached table), in part or fully committed to serve loads in the Intermountain West and Pacific Northwest.  After coal combustion ends at the Boardman, Centralia and Carbon facilities, and another plant (Naughton 3) is converted to gas combustion, some 12,968 megawatts of coal-fired generation will, under current plans, continue to operate.  Eight units, all owned by PAC and comprising almost 1400 megawatts , are now 40 years or older and relatively inefficient (with heat rates well above 11,000 BTU/kWh).  Most of the region's older units will require additional pollution controls to comply with the CAA before CO2 emissions come into play, but the extent of their obligations vary with each plant.
      	The Utilities:  Two-thirds of the residual (post-2025) regional coal capacity is owned and operated by PAC, making it by far the largest owner and operator of these facilities.  Puget Sound Energy (PSE) follows with around 8%.  Portland General Electric (PGE), Avista, Idaho Power, Northwestern, Sierra Pacific and PPL share ownership in the balance of the aggregated plant capacity.  Some utility service territories are wholly contained within a state (e.g., PSE, PGE) while others may have territories and customers across two or more states (e.g., PAC; Avista; Idaho Power).   
      	The Air Regulators:  EPA regulates emissions at power plants, generally operating through State air and water quality regulatory agencies and requiring State rules to be equal to or more rigorous than EPA guidelines.  Prevailing federal regulation for these plants include: ozone, SO2/Nox, water, particulate, ash waste, mercury, and the air transport rule (for downwind effects of plant emissions).  Depending on when plants were built or underwent major modification, and whether an owner has systematically installed emissions control systems or was able to defer certain retrofits under "new source" exemptions, different rules will apply differently.  EPA either approves state compliance plans or, if necessary, will develop and impose a federal compliance plan.
      	The Utility Regulators:  Each State has a public utility regulatory commission that authorizes rates of return, customer tariffs, and terms of recovery of capital investment for each investor-owned utility with an assigned service territory.  These commissions also review the resource planning and capital investments made by their regulated utilities, including investments made to comply with Clean Air Act and other regulatory requirements. Utility regulators have no air quality regulatory authority but must address cost allocation resulting from rules set by air regulators, so they are likely to be closely consulted on cost implications of different emissions regulatory approaches.  They oversee cost recovery on utility capital investments; and measurement of energy efficiency gains, a critical task in the process of capturing least-cost emissons reductions.  They also oversee utility Integrated Resource Planning (IRP's) where each utility will need to describe its 111(d) compliance strategy and the effects on its generating facilities and costs.  PacifiCorp has customers in six states, making for an especially challenging utility regulatory task as each regulatory body has authority to make decisions independent of the other five.  The states have over time developed tools for allocating PacifiCorp costs among them, although each may allow or disallow recovery of different costs.  The formulas demand regular review among the utility and the six commissions, to work through disagreements that may advantage or disadvantage one state and the customers therein.  The good news is that much of the necessary allocation methodology and mechanisms exists; the challenge is that allocating the costs and emissions reduction responsibilities from 111(d) compliance can be expected to place new stresses on these arrangements.

The 111(d) Regulatory Process
There are extensive writeups (and differing interpretations) of the contents and meaning of the CAA Section 111(d) and how it may be applied to GHG emissions from existing power plants, which will not be repeated here.  But a brief introduction to 111(d) will serve to delineate some of the critical choices facing utilities, regulators and citizens of the Pacific Northwest and Intermountain West.  From a September 2013 EPA memorandum on the subject (critical terms underlined):  
      "[President Obama's June 25, 2013] Memorandum directs EPA to issue proposed carbon pollution standards and guidelines, as appropriate, for modified and existing power plants by no later than June 1, 2014, and to issue final standards and guidelines, as appropriate, by no later than June 1, 2015. In addition, it directs EPA to include a requirement for state submittal of the implementation plans required under section 111(d) of the Clean Air Act by no later than June 1, 2016.
      Under section 111(d) EPA issues guidelines for states to use in developing plans implementing standards of performance for the affected sources.
      "Section 111(d) of the Clean Air Act is broad and allows for collaboration between EPA and states to address pollutants that endanger the public health and welfare. Moving forward, there are different options available for addressing carbon pollution from existing power plants such as a "source-based approach" and a "system-based approach." A source based approach evaluates emission reduction measures that could be taken directly at the affected sources -- in this case, the power plants. A system-based approach evaluates a broader portfolio of measures including those that could be taken beyond the affected sources but still reduce emissions at the source.
      "EPA believes that its guidelines should identify for sources and states the required level(s) of performance prior to plan submittal. Under section 111:
           "Standard of performance" means "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated."
      "There are a number of ways to reduce CO2 emissions from existing power plants that might be included in an evaluation of the best system of emission reduction (BSER), including:
*             Onsite actions at individual affected section 111(d) sources.
      o                   Supply-side energy efficiency improvements ("heat rate improvements").
      o                   Fuel switching or co-firing of lower-carbon fuel.
*             Shifts in electricity generation among sources regulated under section 111(d) (e.g., shifts
            from higher- to lower-emitting affected fossil units).
*             Offsite actions that reduce or avoid emissions at affected section 111(d) sources.
      o                   Shifts from fossil generation to non-emitting generation.
      o                   Reduction in fossil generation due to increases in end-use energy efficiency and demand-side management."

Critical Terms for a Regional Compliance Strategy
How the following terms are defined in practice by EPA will be critical to the design of an effective regional compliance strategy.  It should be understood that the definitions are likely to be the subject of legal actions by both regulated parties and other stakeholders.
      	"rate-based / mass-based emissions values":  There are indications EPA is likely to propose a rate-based standard  -  pollutant quantity emitted by a facility per unit of output (lbs/MWh)  -  for application in each state, and apply this at the point of plant emissions.    On a system (state or utility) basis, it is possible for a rate-based value to be converted to a mass-based value (total lbs. GHG emissions within a state, or from a utility system of plants) allocated among plants or accountable parties.  EPA would need to determine the mass-based reduction amounts, then convert back to a rate-based value to compare outcomes and ensure compliance. 
      "source-based approach / system-based approach":  A source-based approach is generally understood as a strategy that controls emissions at a single source, e.g., a single power plant.  While there are often efficiencies that can reduce GHG emissions at the margin, in many cases they may be of limited effectiveness or more costly than available alternatives.  A source-based approach may struggle to bring significant reductions at costs consistent with EPA guidelines.  A system-based approach, on the other hand, may permit a state or utility to aggregate multiple power plants (e.g., all power plants within a state; all power plants within a utility across a state, or across multiple states) within a plan, backing off power production (and emissions) at some plants and averaging these with other plants that continue to operate at higher capacity factors.  A system-based approach might permit a multi-state emissions management structure like an ISO, or like RGGI, to aggregate and average emissions across multiple plants owned by multiple operators.  The advantage of a system-based approach, of course, is that by being selective about which plant operations will be reduced and replaced by lower-carbon options, and which may continue to be operated at higher capacities, facilities can be managed to optimize power operations for CAA compliance at the least cost.
      "Standard of Performance; Best System of Emissions Reduction (BSER)":  EPA is expected to establish a Standard of Performance either for individual plants (source-based) or an aggregation of plants (system-based).  In either case it has an obligation to identify a BSER and issue guidelines for State implementation of the Standard that employs the BSER or another approach that yields equal or better emissions outcomes.  Given the complex and interacting architecture of the power system, it is arguable that a BSER could require a systems-based approach, since a source-based approach is highly likely to result in substantially higher emissions and costs both.
      "State Implementation Plan":  EPA is expected to issue its Standard of Performance and compliance guidelines for States in mid-2015.  States will develop implementation plans for submission to EPA by mid-2016.  For states that fail to submit plans or fail to get them approved, EPA will develop a Federal Implementation Plan and require the state to adopt and execute it.  For a systems-based approach that involves more than one state, it is likely that EPA will require approved implementation plans from all involved states.
      
A Systems-Based Strategy for the Pacific Northwest/Intermountain West
	Given the dispersed nature of the regional electricity system, and the geographical separation of generation and loads across nine states, EPA's rule-writing options are complicated.  While generation and load are spread across what is truly a regional electrical system, there is no regional transmission authority or independent system operator (e.g., CAISO or PJM).  A region-wide, multi-state pact like a RGGI is unlikely given the limited time for developing state compliance submissions to EPA, and the highly divergent views among the PNW and IW states on the threshold question whether GHG reductions are even necessary.
	Still, options exist for a least-cost system-based approach that the states and utilities may see in their best interests, albeit for different reasons.  
	When devising a least-cost reduction strategy, bear in mind that there are three categories of costs to be evaluated:
   1.          Cost of emissions reduction retrofits at plants subject to compliance, if proposed.  These may be as costly as carbon-capture-and-storage (CCS), or as relatively modest as efficiency improvements in plant and transmission operations.
   2.          Cost of replacement resource for the reduced or terminated output of a power plant subject to the regulation.  Resources may include generation (e.g.  wind or other renewable resources, baseload gas turbine, peaking/integrating gas turbine), storage (e.g., utility-scale batteries, underground compressed air storage), and demand-side resources (e.g., energy efficiency, and demand-response integrating resources such as electric vehicle batteries).  Generally, energy efficiency has been the region's lowest cost resource, but it is unlikely to be the only resource selected to replace coal combustion.  Capturing energy efficiency in one state and using it to reduce plant operations and emissions in another state will require some deft agreement-writing and EPA oversight flexibility, or the development of a tradable allowance system.
   3.          Cost to communities of impacts attributable to reduction in coal plant operations or plant shutdown.  These may include lost jobs (and related multiplier effects on local businesses), and lost tax revenues.
      Of course there are real and potential offsetting benefits that may be realized under a well-designed compliance approach.  States that are net importers of coal-generated power, like ID, OR and WA, should see a reduction in dollars exported out of state to pay for those imports (e.g., over $300mm annually in fuel and operations costs alone for OR alone).  Substituting efficiency and renewable generating resources for coal generation will result in new jobs, additional environmental benefits, potentially lower electricity costs long-term (as hydropower has delivered over the last century) and an accelerated transition to the more flexible and distributed power (and electric vehicle transportation) systems of the future.
      There are many possible combinations of state compliance plans and utility actions, within a single state's boundaries or involving more than one state.  The most often discussed may be summarized as follows:
      1. Plant-by-plant emissions reduction:  EPA may simply begin by allocating emissions reductions (or maximum allowed emissions) for each power plant subject to regulation.  Enforcement at the plant would be direct and straightforward, but limited options for such direct reductions are likely to result in higher costs and therefore lower reductions.
         
      2. State-by-State emissions reduction:  For each state, EPA could aggregate rate-based, plant-specific reductions, convert to a mass-based value, and allow (or require) a State to propose a strategy for achieving the indicated reductions.  The State could then develop with in-state plant owners a strategy for allocating reductions among the plants according to a least-cost or other methodology (that includes replacement resources and their associated emissions).  .For the PNW, this approach leaves unclear the relationships between producer and consumer states.  On the one hand, customers in consumer states would have an obligation to pay for replacement costs, but limited access to the emissions reduction levels and the resource replacement assumptions used by the air regulators in the producer states as the basis for setting emissions reduction levels and compliance determinations.  On the other hand, the producer states may have difficulty accessing lower cost efficiency resources for a replacement strategy since loads (and thus efficiency opportunities) would be in another state not bound by EPA to perform.  Together, a producer state and a consumer state can jointly shape a single least-cost strategy to which each contributes, and for which the range and extent of compliance options is wider than would be available to either alone.
         
      3. Regional Agreement:  A regional agreement for the PNW states might be similar to RGGI.  It could involve power plants and customer loads across the nine state area.  It could convert EPA rate-based values  -  calculated assuming, as a BSER, an efficient regional system acting to capture maximum obtainable reductions -- to an aggregate regional mass-based value.  The States could then use an allocation agreement or allowance system to assign reduction (and resource replacement) responsibilities.  For compliance, reductions would be totaled and disaggregated among the states, who would then report separately to EPA.  So long as the total reductions matched EPA's requirements, the states would be in compliance.  Issues with this approach include:  the short time period between when an EPA rule is published and when state compliance plans need to be in place, including any such regional arrangements; institutional and political differences among the nine states; absence of a regional ISO or other institution that could help manage transactions.
         
      4. Bilateral or Multilateral State-to-State Agreements:  An alternative to trying to assemble a regional approach up front, that could capture much of the least-cost value of collective regional action, might be a series of bilateral State-to State agreements developed around a single plant or multi-plant facility.  As above, EPA would calculate a BSER value for the region, develop plant-specific rate-based values, and provide the methodology for converting to plant- or unit-specific mass-based values.  Regulators in the producer and consumer states, together with the unit's owner, could negotiate a strategy for that unit's compliance that might include both complementary arrangements with other plants and owners and/or reductions in plant operations coupled with development of lower-carbon replacement resources.  Such bilateral agreements could work off a common model agreement that is replicable state to state, and that subsequently could be rolled up into more comprehensive multi-plant agreements (and, logically, a voluntary regional agreement over time).  

Example:  A PNW/IW Multi-lateral Compliance Agreement
      For illustrative purposes, the following describes how one such multi-lateral arrangement might be structured to involve three parties collectively seeking to devise a least cost compliance strategy:  (a) a "producer state" with 111(d) compliance responsibilities (e.g., MT; WY); (b) a "consumer state" (e.g., OR, WA); and, (c) a utility with a power plant in the first state and much of its load in the second.  Thus . . .
      	Step One:  After consultation  -  and optimally -- EPA develops a BSER based on obtaining emissions reductions from the PNW utility system considered as a single system involving nine states, then disaggregates the required reductions by state and plant unit.  Some states are primarily consumer states (OR; WA; ID), some primarily producer states (MT;WY), and some (UT) mixed.   This analysis assumes that, once a BSER is established, it is to all parties' advantage to seek a least-cost compliance solution and that costs can be allocated equitably within the system.  EPA would establish how reductions would be measured and verified.  EPA would then invite but not obligate states and utilities to find cooperative means to achieve the reductions, develop replacement resource plans, and allocate costs.  The states and utilities could use the system modeled by EPA in setting the trajectory, or select an alternative strategy  -  including options that traded emissions reductions among utilities and within or across state lines  -  so long as the overall regional reduction trajectory is realized.
      	Step Two  -  Example A:  Two states enter into a bilateral agreement that involves a producer state and a consumer state, linking the plant(s) and loads of a utility that owns and operates plants in the producer state.  Thus, WA and MT enter into an agreement, to which Puget Sound Energy (PSE) is party as the implementing utility, by which PSE's share of allowable emissions at the Colstrip powerplant (four generating units) is set consistent with the EPA rule (and proportionate to PSE's share of the required Colstrip reduction).  The lost resource is replaced with a least-cost combination of load-center energy efficiency measures (in WA, where the PSE load is), plus wind energy and wind-integrating resurces/storage in WA, MT or elsewhere.  If other utilities that also have shares of the Colstrip units also propose to reduce plant output (or close one or more units of the facility), Montana may seek to negotiate agreements with all involved states and utilities to ensure that a substantial share of the replacement resource is sited in Montana to offset employment and tax revenue losses, and resulting community impacts, as well as use otherwise-orphaned east-to-west transmission assets.
      	Step Two  -  Example B:  For a utility such as PacifiCorp (PAC), with multiple plants across two or more states, a system least-cost pathway may involve backing down or shutting down the least efficient plants and continuing to operate the most efficient, across state boundaries.  If this results in disproportionate reductions in one state (e.g., the least efficient plants are disproportionately in one state), an emissions liability sharing agreement could be negotiated among two producer states (MT; WY) and, a consumer state (OR), allocating costs across utility (PAC) customers, that supports a least-cost resource replacement  strategy.  
      Step Three:  Compliance plans, emissions reduction allocations and cost allocations are reported by each plant owner (or partial owner) to its state air and utility regulators.  State air regulators validate the emissions reductions achieved (or proposed to be achieved) in each state, and report to EPA which reaggregates and compares to its adopted trajectory (BSER.  Utility regulators would review and acknowledge the proposed replacement resource plans consistent with existing practices.   Cost allocations among the states would be handled, as now, in separate proceedings.  
In each of these cases, EPA has calculated system emissions reductions across a system, then disaggregated these emissions reductions and allocated them by state. The states and utilities are then enabled to find least-cost compliance solutions that permit and encourage, but do not require, re-aggregation into "systems" through a series of manageably-sized, mostly trilateral agreements (two states, one utility-owned power plant) that allow costs of resource replacement and local impacts to be negotiated among the direct parties.  
   The three tasks set out at the beginning of this paper have been addressed: 
*       Task 1, setting the BSER emission outcomes, by EPA; 
*       Task 2, identifying and negotiating a system-based least-cost compliance strategy;  and, 
*       Task 3, allocating compliance costs among states and utility customers through a series of manageably-scaled agreements ("manageable" in comparison to negotiating a single regional agreement).
	If the utilities and states fail in any case to arrive at an agreement for any one plant, EPA has the authority and obligation to devise a Federal Implementation Plan to address this failure in the state where the plant is located.  
	Two or more such agreements could subsequently be rolled up into a larger PNW/IW regional operating agreement if the parties were to identify benefits from such a consolidation.  Alternately a regional or westwide voluntary reduction "credits" trading mechanism might be deployed to widen the market for least-cost emissions reductions among plants and states; or states might elect to affiliate with California's AB 32 trading system or the Northeast states RGGI trading mechanism. 

Attachment A:  Clean Air Act Section 111(d)
(d)	Standards of performance for existing sources; remaining useful life of source
      (1) The Administrator shall prescribe regulations which shall establish a procedure similar to that provided by section 7410 of this title under which each State shall submit to the Administrator a plan which
      (A) establishes standards of performance for any existing source for any air pollutant 
                  (i) for which air quality criteria have not been issued or which is not included on a list published under section 7408(a) of this title or emitted from a source category which is regulated under section 7412 of this title but
                  (ii) to whch a standard of performance under this section would apply if such an existing source were a new source, and
            (B) provides for the implementation and enforcement of such standards of performance.  Regulations of the Administrator under this paragraph shall permit the State in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.
	(2) The Administrator shall have the same authority -- 

            (A) to prescribe a plan for a State in cases where the State fails to submit a satisfactory plan as he would have under section 7410 (c) of this title in the case of failure to submit an implementation plan, and
                     
            (B) to enforce the provisions of such plan in cases where the State fails to enforce them as he would have under sections 7413 and 7414 of this title with respect to an implementation plan.
                     
      In promulgating a standard of performance under a plan prescribed under this paragraph, the Administrator shall take into consideration, among other factors, remaining useful lives of the sources in the category of sources to which such standard applies.

Attachment B:  PNW Regional Coal Plants

From "The War on Coal" BPA memo January 25, 2011; note that average age is calculated to 2011, and that emissions control data are out of date.  These are units that deliver from Intermountain states to utility loads in the four Northwest states; other coal-fired generation may serve local loads .  Notes: (a) the 521 MW North Valmy facility in Nevada, not in this table, is 50% owned by Idaho Power which imports the power to its Idaho loads; (b)  Idaho Power also owns one-third of the Jim Bridger units and 10% of Boardman; (c) PGE now owns 80% of Boardman, not the 100% shown in the table. 

Attachment C:  Ten Criteria for EPA 111(d) Existing Plant Carbon Rule
   * Should collectively reduce emissions by more than 25-30 percent below current levels (2012) by 2020 (this is equivalent to 35-40% below 2005 levels)* and make further reductions thereafter.

   * Require that emission reductions in state plans must be measurable, verifiable and enforceable. 

   * Should require that state plans include enforceable requirements for each individual covered source that collectively achieve the state target.

   * Should cover all fossil fuel sources that generate electricity for the grid and are currently required to report their emissions. 

   * Should recognize for compliance all measures that quantifiably reduce emissions from the covered sources, including energy efficiency and renewable energy. 

   * The stringency of the performance standards set in EPA's guideline must reflect the full set of measures that can be used to comply. 

   * Should provide for approval of alternative state plans if they result in total carbon dioxide emissions from the power sector that are no higher than allowed by the performance standard in the guideline.

   * States may adopt plans that are more stringent than the EPA guideline.  

   * So that states would have adequate notice of what the federal plan would be, EPA should propose a standby Federal Plan by June 2015 and promulgate it by June 2016 for states that choose not to submit an acceptable State Plan by that deadline. 

   * Should be reviewed and updated at least every eight years along with the new source standard. 

   * 35-40% below 2005 levels = 25-30% below 2012 emission levels = 500-600 million metric tons below 2012 levels = 850-950 million metric tons below 2005 levels.