1

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 States1

Abstract

The paper describes the architecture of a regional electric grid extending across nine2

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 multistate 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-cost3 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 EPAset 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; Utah 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 

imported 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 whether 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 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, lowcarbon 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

generation4; 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?

 

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 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 loads5. The respective 

coal-generation capacities are6:

 

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 MW7

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. Neither 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 will be fully closed, in response to state regulatory action, by 

2017. 
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any coal combustion remaining within their borders; and Idaho already is coal-free. Yet all three will remain 

in significant degree9 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 owners10 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 utilities11, 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 underway12 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 plants13, 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 out-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, coal’s estimated share of load in WA will be around 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 above.

12 e.g., regional haze, SO2/Nox, water, particulate, ash waste, mercury, and the downstate transport rule

13 Substantial transmission capacity in Oregon/Washington and from northwest Montana and Canada south and 

westward is used for hydroelectric generation
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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 

states14, 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 Northwest15. 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 capacity16. 

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)

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. 

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 generation (or shares) in MT, WY, UT, 

CO, AZ, and NM. . I

15 Apart from plants largely dedicated to PNW loads, coal 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 130 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 ConCOU’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.
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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)18 and how it may be applied to GHG emissions from existing power plants19, 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. Previously, EPA has applied S 111(d) to plants producing sulfuric 

acid, phosphate fertilizer, aluminum, and paper pulp; and to municipal solid waste landfills.

19 See: NRDC; EDF; Brattle Group, Georgetown Climate Center
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regulators and citizens of the Pacific Northwest and Intermountain West. From a September 2013 EPA 

memorandum20 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 systembased 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 demandside management.”

 

20 See EPA: “Considerations in the Design of a Program to Reduce Carbon Pollution from Existing Power Plants”
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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 ratebased 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 ratebased 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 multistate emissions management structure like an ISO21, or like RGGI22, 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 lowercarbon 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 

 

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 multi-state carbon cap and trade arrangement involving nine states in 

the US Northeast.
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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 states23, 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 necessary24.

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-storage25 (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 

 

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 recovery 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 selected 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 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 alone27). 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) systems of the future28.

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 keyed 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 jobyears 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 shows 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”, NRDC 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 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 

determinations30. 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 ratebased 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 multiplant 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 massbased values. Regulators 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 

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 utility31 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 equitably within the system. EPA would establish 

how reductions would be measured and verified33. 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

 

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, EPA 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 PSE load is), plus wind energy and windintegrating 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) customers34, that supports a leastcost 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 

acknowledge35 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,

 

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.
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 Task 3, allocating compliance costs among states and utility customers through a series of manageablyscaled 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 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.
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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.

Plant Name Plant State Owner

Nameplate 

Capacity MW

Average 

Capacity

Factor (%)

Average 

Age 

(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 Wyoming PAC (100%) 114 77 51 11,773 Y N N

Dave Johnston 3 Wyoming PAC (100%) 114 77 50 11,467 Y Y Y

Naughton 1 Wyoming PAC (100%) 163 83 47 12,257 Y

N 

(Planned) N

Dave Johnston 2 Wyoming PAC (100%) 230 77 46 11,320 Y N N

Naughton 2 Wyoming PAC (100%) 218 83 42 12,204 Y

N 

(Planned) N

Naughton 3 Wyoming PAC (100%) 326 83 39 11,728 Y Y N

Dave Johnston 4 Wyoming PAC (100%) 360 77 38 12,488 Y Y Y

Centralia Complex 

2 Washington TransAlta (100%) 730 70 38 12,173 Y Y Y

Centralia Complex 

1 Washington TransAlta (100%) 730 70 37 12,284 Y Y Y

Jim Bridger 1 Wyoming 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 Wyoming 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 Wyoming 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 Wyoming 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 Wyoming 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

Northwest Utility Coal plant statistics
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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.
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