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# 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**2 

# White Paper **Clean Air Act Section 111(d)**  **CO2 Reduction**  **Compliance Pathways for**  **the Pacific Northwest and Intermountain West States**  **1**



## Abstract **The paper describes**  **the architecture of a regional electric grid extending across**  **nine 2**  **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 f** **or 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. Volunt**  **ary State -**  **to -**  **State agreements could**  **then identify least -**  **cost 3**  **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 retire**  **ment 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**  **a re**  **in compliance with an**  **EPA**   ** set** **emissions standard for the region overall .** 

1 This paper was written by Angus Duncan for NRDC, in consultation with these Pacific Northwest and Intermountain West regional organizations: Climate Solutions ; Environment Oregon ; Environment Washington; Idaho Conservation League ; Montana Environmental Information Center; Northwest Energy Coalition; Powder River Basin Resource Council; Renewable Northwest Project ; Sierra Club; Snake River Alliance ; Ut ah Clean Energy; Washington Environmental Council; Western Resource Advocates . 2 AZ, CO, ID, MT, NV, OR, UT, WA, WY all have coal plants serving PNW/IW loads (see also page 4) ; coal - generation is also im ported at times from NM, TX and other states in lesser amounts. 3 “Least - cost” as the term is used in the Northwest Power Act of 1980 to include all costs and benefits, including environmental costs and benefits, whether monetized, quantified or described, and w hether presently internalized or externalized.3 

## 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 overa l l 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 conside ring 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 regulat ory structure. It is not clear what compliance pathways will be workable for s tates whose utilities import significant quantities of power from coal - fired generation4; and for s tates containing significant coal - fired generation that export to loads in oth er states. Reconciling s tate -by - s tate compliance plans with this utility architecture

– which is especially typical in the Pacific Northwest and Interm ountain West states – will be challenging. At its m ost 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) H ow 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 state s. An EPA 111(d) rule making 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 achievab le :

(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?

4 The reverse complication may exist for a state that imports substantial quantities of low - carbon power (e.g., hydro; wind; nuclear) and finds that EPA attributes higher carbon content to it based solely on in - state generation.4

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 resour ces 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 effe ct, 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 choic e of allow able compliance paths

– re sult 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 Se a ttle and Portland metro areas) , while most of the coal - fired generation imported to serve the se 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 5 . The respective coal - generation capacities are 6 :

5 The largest shares of the WY and MT capacities and costs shown are allocated to out - of- state loads, but that share by state will vary with utility ownership share, the location of that utility’s loads, seasonal load variability and market conditions. Some facilities in Colorado, Arizona, New Mexico and Nevada also export to out - of- state loads in this PNW/IW region; and all of the region’s utilities purchase “system power” that may originate in coal or other power plants across the western grid. 6 Plant capacity values may be stated slightly differently in different documents and proceedings.5

Montana 2717 MW Nevada 521 MW 7 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) 8 . Ne ither Oregon nor Washington will then have

7 This is the North Valmy power plant, 50% owned by Idaho Power which imports generation into the PNW. Nevada has one other coal facility

– Reid Gardner Station, 612 MW

– that wil l be fully closed, in response to state regulatory action, by 2017.6 any coal combustion remaining within their borders ; and Idaho already is coal - free . Y et all three will remain in significant degree 9 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 10 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 11 , there are also some 1 3 0 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 unl ikely 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 coll ective benefit. Planning is fur ther complicated by other Clean Air Act regulatory proceedings underway 12 to which different plants have different exposures; and by price pressure from growing new sources of natural gas and declining cost curves for renewab le technologies. Much of the region’s long - distance transmission mileage is dedicated to east- to - west movement of power from these coal plants 13, and the economics of this transmission is substantially intertwined with the

8 If EPA sets a baseline year earlier than 2020, both OR and WA will likely be in compliance with any EPA existing power plant rule, and might even have reduction “credits” to trade to ou t - of- compliance facilities and their owners. Electricity customers in all three “in - compliance” states will still be financially responsible for plants located elsewhere but serving their needs. 9 After 2020, c oal ’s estimated share of load in WA will be a round 15%; in Oregon, around 25% ; and in Idaho, over 35% (per ID 2012 Energy . Plan) 10 e.g., Colstrip/2272 MW ; shares in four units owned variously by Puget Sound Energy, Portland General Electric, Avista, PacifiCorp, Northwestern and PPL Montana. Similarly, 2/3 of Jim Bridger/2318 MW is owned by PacifiCorp and the balance by Idaho Power. 11 E.g., the Investor - Owned Utilities in footnote 9 abo ve . 12 e.g., regional haze, SO2/Nox, water, particulate, ash waste, mercury, and the downs tate transport rule 13 S ubstantial transmission capacity in Oregon/Washington and from northwest Montana and Canada south and westward is used for hydroelectric generation7 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 the se 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 14, with a combined nameplate capacity of 15,528 me gawatts (see attached table) , in part or fully committed to serve loads in the Intermountain West and Pacific Northwest 15 . After coal combu stion ends at the Boardman, Centralia and Carbon facilities, and another plant (Naughton 3) is converted to gas combustion, some 12,968 me gawatts of coal - fired generation will, under current plans, continue to operate. Eight units, all owned by PAC and co mprising 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 an d operator of these facilities. Puget S ound 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 16 . 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 ) 17 . 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

14 PAC has customers in six states: OR, WA, MT, WY, UT and CA. It owns coal generati on (or shares) in MT, WY, UT, CO, AZ, and NM. . I 15 Apart from plants largely dedicated to PNW loads, c oal dependence varies from year to year with each utility and may vary with available hydropower supplies and sales/purchases of system power, some of it coal - generated, from western power markets. 16 There are also over 1 3 0 consumer - owned utilities (COU’s) in the four PNW States (OR, WA, ID, MT) and more in the other producer states; but very little coal - generated electricity is delivered to the PNW ConC OU’s. Some IW COU’s own substantial coal - generating assets, but these COU’s are not considered in this case study. 17 Centralia is a merchant plant privately owned by Trans - Alta Corporation. As such its operations come under FERC regulation but it is not subject to state utility commission rate - of- return regulation. This is also true for the PPL merchant plants in Montana, and for all COU - owned facilities.8

than EPA guidelines. Prevailing federal regulation for these plants include: ozone, SO2/Nox, water, particulate, ash waste, mercury, and the ai r transport rule (for downw ind 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, differe nt rules will apply differently. EPA either approve s 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 consul ted 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 a n especially cha llenging 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 recove ry of d ifferent costs. The for mula s de mand regular review among the utility and the six c ommissions, 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 exist s ; 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 Se ction 111(d) 18 and how it may be applied to GHG emissions from existing power plants 19, which will not be repeated here. But a brief introduction to 111(d) will serve to delineate some of the critical choices facing utilities,

18 The text of Section 111(d) is attached to the Paper. P reviously, EPA has applied S 111(d) to plan ts producing sulfuric acid, phosphate fertilizer, aluminum, and paper pulp; and to municipal solid waste landfills. 19 See: NRDC; EDF; Brattle Group, Georgetown Climate Center9 regulators and citizens of the Pacific Northwest and Intermountain West . From a September 2013 EPA memorandum 20 on the subject (critical terms underlined) : “ [ President Obama’s June 2 5, 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, b y 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. “ S ection 111(d) of the Clean Air Act is broad and allows for collaboration between EPA and states to address po llutants 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 “s ys tem - based approach. ” A source based approach evaluates emission reduction measures that could be taken directl y at the affected sources —in this case, the power plants. A s ys tem 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 impa ct and energy requirements) the Administrator determines has been adequately demonstrated.” “ There are a number of way s to reduce CO 2 

### emissions from existing power plants that might be included in an evaluation of the best sy stem 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 fo ssil generation due to increases in end - use energy efficiency

and demand side management. ”

20 See EPA: “Considerations in the Design of a Program to Reduce Carbon Pollution from Existing Power Plants”10 

## 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 com pliance 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 t o 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 - bas ed value to compare outcomes and ensure compliance.

“ s ource -based approach / s ystem -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 GH G 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, b acking 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 21 , or like R GGI 22, 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 ; B est S ystem of E missions 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

21 Independent System Operator, refers to an agency managing electrical system and grid operations in a state or region that has substantial private wholesale power suppliers 22 Regional Greenhouse Gas Initiative, an operating mu lti - state carbon cap and trade arrangement involving nine states in the US Northeast.11

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 s tate 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 23, 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 limi ted 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 24 . S till, 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 25 (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, undergroun d compressed air stora ge), and demand - side resources (e.g., energy efficiency, and demand - response 23 See Footnote 2. 24 The option of joining an existing aggregation like RGGI, or California’s AB 32 cap - and - trade, present their own complexities; this is especially so given the interdependence of PNW/IW consumer and producer states, possibly requiring that most or all agree to such an affiliation. The option of rolling up state - to - state agreements into a larger regional aggregation likely would remain viable and could be accessed, post - EPA rule, by willing state governments. 25 CCS is most likely to be a cost - effective emissions reduction strategy in limited applications at power plants where the carbon dioxide can be piped to nearby oil fields and used to increase oil r ecovery in older well fields.12

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 sel ected to replace coal combustion26 . 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 all owance 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., ove r $ 300 mm annually in fuel and operations costs alone for OR alone 27 ). Substituting efficiency and renewable generating resources for coal generation will result in new jobs, additional environmental benefits, potentially lower electricity costs longterm ( as hydropower has delivered over the last century) and an accelerated transition to the more flexible and distributed power (and electric vehicle transportation) system s of the future 28 . 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 reduction29 : 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.

26 For example, generating power plants are needed across the system to maintain voltage support and other power quality conditions within the transmission system. Note: energy efficiency capture in OR and WA is already keye d to a cost - effectiveness test involving combined cycle gas generation, likely the same test that would be applied in gauging efficiency replacement resources available for reduced coal combustion. 27 per communication from Phil Carver, Oregon DOE, based on utility filings described in FERC Form 1 for 2012. 28 per Synapse Energy Economics Inc., quoted from NRDC Issue Brief “Less Carbon, More Jobs, Lower Bills”, July 2013.; shows Oregon adding 1900 job - years and lowering the average utility bill by $0.65/month; and Montana adding 3600 job years while lowering the average utility bill by $1.25/month (added jobs largely in energy efficiency). NRDC’s 2014 update of the analysis reflects declining real costs of renewable generating technologies and of gas, and sho ws still greater reductions with accompanying greater benefits, at lower compliance costs (“Cleaner and Cheaper: Using the Clean Air Act to Sharply Reduce Carbon Pollution of Existing Power Plants, Delivering Health, Environmental and Economic Benefits”, N RDC 2014). 29 A “plant” may be a single coal burning power generation unit, or it may be a facility containing two or more such units (e.g., the Colstrip facility has four generating units that can each operate independently of the others, and that has its own shared ownership.13

2. State -by - State emissi ons 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- sta te 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 30 . 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 va lues

– 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 (an d 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 complian ce. 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 state s; 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 de veloped around a single plant or multi plant facili ty . 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. Re gulators in the producer and consumer states, together with the unit’s owner, 30 Actual resource replacement decisions would be made by the utility involved, overseen by the utlity regulators in the consumer states.14

could negotiate a strategy for that unit’s compliance that might include both complementary arrangement s 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). 

## Exa **mple: A PNW/IW**  **Multi -**  **lateral Compliance Agreement** For illustrative purposes, the following de scribes 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 31 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 unit32 . 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 e quitably within the system. EPA would establish how reductions would be measured and verified 33 . EPA would then invite but not obligate states and utilities to find cooperative means to achieve the reductions, develop replacement resource plans, and alloc ate 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 ove rall regional reduction trajectory is realized. Step Two – Example A : Two states enter into a bilateral agreement that involve s a producer state and a consumer state , linking the plant ( s ) and loads of a utility that own s and operates plants in the produc er 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

31 . . . or two or more utilities sharing ownership of the same power plant, with customers in different service territories (and potentially, more than one consumer state) 32 EPA could also calculate a BSER based on a different “system” -- e.g., of generating units within a state, or within a utility

– then set emissions performance standards based on that system analysis. 33 E.g., EPA could establish an overall multi - state/system GHG emissions limit on a mass basis, then convert this to an intensity -basis for each plant. For compliance measurement, E PA could convert plant intensity values, averaged, back into a mass - basis value and compare to the multi - state BSER value.15

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 P S E load is ), plus wind energy and wind integrating resurces/ st orage 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 agreement s 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 em issions liability sharing agreement could be negotiated among two producer states (MT; WY) and, a consumer state (OR) , al locating costs across utility (PAC) customers 34, 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 wo uld review and acknowledge 35 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 red uctions 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 tri lateral 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,

34 Note that PAC has power plants but no customer loads in MT, CO and AZ. 35 “Acknowledge” refers to a finding by a utility regulatory commission that does not guarantee recovery of costs of an action in a utility’s retail rates, but finds the action to be reasonable at the time. This action is taken as a way of “approving” of proposed actions in a utility intergrated resource plan.16

 Task 3, allocating compliance costs among states and utility custom ers 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.17 

## 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 regulati ons 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) f or 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 perform ance 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.18 

## Attachment B: PNW Regional Coal Plants

From “The War on Coal” BPA memo January 25, 201 1; 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 . Not es : (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. **Plant Name Plant State**  **Owner Nameplate**  **Capacity MW Av**  **erage**

**Capacity Factor (%)**  **Av erage** 

**Ag e**  **(Years) Average** 

**Heat Rate (Btu/kWh)**  **Particulate**

**Control SO2** 

**Control NOx** 

**Control Carbon (UT) 1**  Utah PAC (100%) 75 79 56 11,439 Y N N **Carbon (UT) 2** Utah PAC (100%) 114 79 53 11,516 Y N N **Dave Johnston 1** Wyom ing PAC (100%) 114 77 51 11,773 Y N N **Dave Johnston 3** Wyom ing PAC (100%) 114 77 50 11,467 Y Y Y **Naughton 1** Wyom ing PAC (100%) 163 83 47 12,257 Y N (Planned) N **Dave Johnston 2** Wyom ing PAC (100%) 230 77 46 11,320 Y N N **Naughton 2** Wyom ing PAC (100%) 218 83 42 12,204 Y N (Planned) N **Naughton 3** Wyom ing PAC (100%) 326 83 39 11,728 Y Y N **Dave Johnston 4** Wyom ing PAC (100%) 360 77 38 12,488 Y Y Y **Centralia Complex 2**  Wa shington TransAlta (100%) 730 70 38 12,173 Y Y Y **Centralia Complex 1**  Wa shington TransAlta (100%) 730 70 37 12,284 Y Y Y **Jim Bridger 1** Wyom ing PAC (66.55%) 578 74 36 10,447 Y Y N **Huntington (UT) 1** Utah PAC (100%) 498 76 36 10,228 Y Y N **Jim Bridger 2** Wyom ing PAC (66.55%) 578 74 35 10,983 Y Y N **Colstrip 1** Montana PSE (50%) 358 76 35 11,656 Y Y Y **Jim Bridger 3** Wyom ing PAC (66.55%) 578 74 34 12,137 Y Y N **Colstrip 2** Montana PSE (50%) 358 76 34 11,998 Y Y N **Huntington (UT) 2** Utah PAC (100%) 498 76 33 11,760 Y Y N **Wyodak** Wyom ing PAC (80%) 362 85 32 13,677 Y Y N **Hunter 1** Utah PAC (85.8%) 488 74 32 10,757 Y Y N **Jim Bridger 4** Wyom ing PAC (66.55%) 584 74 31 12,101 Y Y N **Hunter 2** Utah PAC (85.8%) 488 74 30 10,856 Y Y N **Boardman (OR)** Oregon PGE (100%) 601 74 30 10,217 Y N (Planned for 2014) N (Planned

for 2011) **Hunter 3** Utah PAC (85.8%) 496 74 27 10,550 Y Y N **Cholla 4** Arizona PAC (100%) 414 72 29 10,616 Y Y N **Craig (CO) 1** Colorado PAC (19.29%) 446 83 31 11,026 Y Y Y **Craig (CO) 2** Colorado PAC (19.29%) 446 83 30 10,688 Y Y Y **Colstrip 3** Montana PSE (25%) PAC (10%) 778 76 27 12,878 Y Y N **Colstrip 4** Montana PSE (25%) PAC (10%) 778 76 24 12,878 Y Y N **Northw est Utility** 

**Coal plant statistics**19 

## 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 emission s 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 alternativ e 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 wou ld 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 th at deadline.

 Should be reviewed and update d 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 .20