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Arizona Questions Regarding EPA’s Proposal Under 111(d)

September 11, 2014

Questions Regarding EPA’s Modeling

I. In setting the carbon dioxide (CO2) emission rate goals for the state of Arizona, EPA assumed all coal generation in the 

state is replaced by natural gas or other generation by 2020. However, in EPA’s Integrated Planning Modeling (IPM) 

for the state of Arizona, it appears that approximately 1,500 MW of coal generation remains online through 2030 and 

beyond (based on summing appropriate individual rows between Lines 58 and 544 in EPA’s “Option 1 State - April 

2014 Draft RegionalSummary.xlsx” spreadsheet, “WECC_AZ” tab, excluding Navajo Generating Station, which is 

located on tribal land). Given that the CO2 goals for Arizona were established assuming no coal remains online after 

2020, in order to keep 1,500 MW of coal online through 2030, Arizona would have to exceed EPA’s assumptions with 

respect to several of the other building blocks (presumably Building Blocks #3 and 4), or increase reliance on resources 

from outside the state. Is there a location where EPA shows the calculation of CO2 emission rate in the units specified 

in the proposed rule to confirm that Arizona meets both the interim and final goals while keeping 1,500 MW of coal 

online? 

II. EPA’s IPM analysis appears to assume significantly less load growth in Option 1 compared to the Base Case (over 

3,300 MW less – see cells F24 in the “Base Case” and “Option 1” spreadsheets in the “WECC_AZ” tabs). Is EPA 

assuming that such a significant difference is attributable to energy efficiency measures? How does EPA account for the 

fact that not all energy efficiency measures will reduce peak demand? Since utilities cannot force customers to adopt 

energy efficiency measures, how does EPA account for the uncertainty associated with those resources? 

III. EPA’s IPM analysis also appears to assume significant energy and capacity imports into the state of Arizona. 

Specifically, even in the base case, Arizona transitions from being a net exporter of electricity to being a significant net 

importer (Arizona imports over 7,000 MW in 2030 – see cell F19, which is over 20% of the total peak summer demand 

including reserve margins). Can EPA explain what information supports these assumptions? For example, does the 

model identify where Arizona’s imports will come from, and does it account for the changes in existing contracts, rights, 

and/or reservations on transmission lines that would be required by such significant changes in power flow? 

IV. How does IPM account for power plants that are jointly owned? For example, IPM lists approximately 3,900 MW of 

nuclear capacity in Arizona (see line 116 in “Base Case” and “Option 1” spreadsheets), which is the approximate 

capacity of Palo Verde Generating Station. However, less than 50% of Palo Verde is owned by Arizona utilities. The 

remainder is owned by out-of-state entities. Several of the state’s coal-fired power plants and many of the natural gas 

combined cycle power plants (e.g., those that are merchant-owned) also fall into this category. For these resources, the 

portion of capacity that is not owned by Arizona utilities would not be available to serve Arizona. How does IPM 

account for this? 

V. In the WECC Arizona transmission region, why are the IPM base case summer peak demand (MW) imports higher in 

2025 and 2030 where no coal plants are retired as compared to the Option 1 Case? 

VI. Under the IPM Base Case and Option 1 Case, no new capacity additions are contemplated in the WECC Arizona 

transmission region until 2040. In existing utility resource plans, it is projected that new capacity will be needed to meet 

load growth, replace retired assets, and balance more intermittent generation prior to 2040. Can the EPA explain why 

the model does not include any new capacity additions in Arizona before 2040? 

VII. In the WECC Arizona transmission region, why does the existing combined cycle generation decline over time? With 

coal retirements in the IPM Option 1 Case, why is the existing combined cycle generation effectively the same in 2025 

and 2030 compared to the Base Case? 

VIII. EPA stated that (and the output files show) their modeling demonstrated that Arizona could meet the proposed interim 

and final goals with coal operating through 2030. Did that modeling assume a regional CO2 trading or credit system, or 
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was Arizona able to comply without any multi-state coordination? 

IX. The modeling output files show a carbon credit price of $46/ton for Arizona. How did the model generate that credit 

price? Does that imply intrastate or interstate trading? 

Priority Concern #1:  Timing ‐ EPA’s proposed emission rate goals for the State of Arizona would require the State to

achieve at least 77 percent of the 2030 goal by 2020.

I. Can EPA briefly explain how it envisions the state might apply “remaining useful life” during the plan 

development phase? Does EPA view the concept as limited to analyzing costs under Building Block 1 or can the 

state look more broadly at overall impacts from Building Blocks 1-4 and the impact on source utilization versus 

design life (e.g., if goal suggests shutdown in 2020, does the “remaining useful life” concept provide a basis for 

extending the operating period to reduce costs to a state-determined reasonable amount)? 

II. Did EPA’s goal consider the time and cost impacts of existing regulations on new infrastructure? 

a. AZ likely to need new natural gas plants and associated infrastructure by 2020 to comply with interim goals. 

b. Siting, permitting, and constructing this new infrastructure will be difficult over such a short timeframe. 

c. New gas pipeline and transmission line infrastructure will be subject to requirements like NSR or the National 

Environmental Policy Act (NEPA). 

II. Can AZ’s plan include credit for the retirement of a coal unit located in a different state, yet which serves AZ, without 

entering into a full multi-state plan, provided the state where the retiring unit is located does not also account for that 

retirement (no double counting)? 

Priority Concern #2:  Achievability ‐ The assumptions used to develop EPA’s proposed emission rate goals for Arizona

would require a substantial shift in generation from coal‐fired generation to gas‐fired generation.

I. In applying Building Block 2 (BB2), EPA shifted all existing coal generation to “available” natural gas combined 

cycle (NGCC) generation. Did EPA’s modeling consider both the interstate gas transportation requirements as well as 

the peak generation capacity available to displace existing coal generation? 

a. Given the relationship between AZ’s winter gas requirements (usage weighted by residential/commercial heating) 

and summer gas requirements (usage weighted by power generation), did EPA’s modeling consider the pipeline 

infrastructure impacts of base loaded combined cycle generators during the winter gas season? 

b. Did EPA’s modeling factor in summer derates on nameplate capacity to account for AZ high summer 

temperatures? 

c. Did EPA’s modeling factor in any federally enforceable emission permit limits on allowable usage? 

d. Did EPA’s modeling factor in existing purchase power agreements that are tied to existing AZ merchant owned 

combined cycle units? (Thus reducing the available capacity to displace existing coal fired generation). 

e. Utilities cannot count on these units when contemplating “available” NGCC capacity to dispatch in place of coal 

generation because the utilities do not own or operate them. Federal laws require fossil-fuel fired capacity to be 

held in reserve to ensure reliability of the grid when renewable energy like solar and wind is unavailable, or if 

there is catastrophic failure of a base load unit. 

f. If a State can demonstrate that certain NGCC capacity is not available, can that reduced capacity be accounted for 

under BB2 in setting the state goal? 

g. Did EPA’s modeling consider intrastate transmission limitations, including load serving entities’ existing 
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transmission scheduling rights in its coal redispatch assumptions. If so, how? 

h. Did EPA consider reliability impacts from coal-fired unit retirements associated with increasing NGCC annual 

capacity utilization? Coal units would be unavailable to assist with peak capacity needs as these units are not 

designed to operate in a peaking fashion. 

II. How does EPA contemplate treating new generation resources that are built to displace existing coal capacity? Will 

they fall under the New Source Performance Standard (NSPS) and will these new resources be regulated on a standalone basis? Or will these new resources fall into the Existing Source Performance Standard (ESPS) category with 

their output being included along with the existing state generation resources? 

III. Does EPA believe it has legal authority to allow states to include new/modified/reconstructed units subject to 111(b) 

in the plans developed under 111(d)? 

IV. Has EPA considered how a presently non-affected unit that becomes subject to the rule (e.g., due to an increase in 

utilization above the capacity factor threshold) will affect compliance with the State goal? 

Priority Concern #4:  The EPA proposal does not appear to provide clear direction on the measurement, verification

and enforceability of building blocks 3 and 4.

I. In establishing the goals, it appears that EPA accepted state renewable and energy efficiency goals, although it 

“regionalized” them for some purposes. Did EPA conduct an “enforceability” review of these state goals before 

accepting them in establishing EPA’s proposed goals? 

a. If not, will EPA do so prior to the final rule and commit to only including those measures that are deemed 

acceptable in establishing the state goals? 

b. If EPA does not feel it can commit, what assurance does the state have that its programs used to establish the goal – 

and hence the binding state target – will be accepted? 

II. Is EPA considering applying Clean Air Act §110 requirements for surplus, enforceable, creditable and permanent 

emissions reductions? 

a. Existing renewable energy (including distributed generation) and energy efficiency standards may not meet 

standards. 

b. Existing local ordinances are unlikely to meet standards. 

c. Existing energy efficiency programs may not be creditable, even though the actual benefits are real. 

III. Is participation in a multi-state plan the only way to get credit for reductions attributable to out-of-state resources? 

a. Would EPA allow for a hybrid plan that incorporates state agreements to handle specific issues, such as 

renewable energy credits (RECs)? 

b. If not, which State gets credit if an AZ utility-portfolio based plan results in reductions at a unit in another State? 

c. The renewable portfolio standards that EPA relies upon in setting the state targets currently allows for utilities to 

count renewable generation located in another State if the RECs are owned by a utility and its customers. 

d. If EPA does not allow for out-of-state RECs to be applied in determining compliance with AZ’s emission goal, 

will the EPA revise the target to likewise remove these RECs from the goal determination under BB3? 

   
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General Comments

I. Will EPA consider population shifts in setting the interim and final goals? 

a. States with declining population (Northeast) can comply with the goals while shifting burden to growing states. 

b. States with growing population will have to achieve greater reductions to accommodate growing population. 

c. Exclusion of growth precludes the availability of a mass-based approach for growing states. 

II. EPA’s proposal contemplates States making changes to plans. What are EPA’s procedures for processing these 

changes? Will these procedures include time requirements for EPA review and approval? 

a. How will the state credit new renewable generation or energy efficiency measures in the state plan if they are not 

included in the original plan? 

III. Can a unit be derated to less than 73 MW to exit the program? If so, what is required to make the deration 

effective? 

BB1 Increase efficiency of existing fossil fuel power plants through equipment upgrades and process improvements. 

I. Did EPA determine whether 111(d) will subject efficiency improvement changes to NSR permitting? 

a. NSR permits will delay implementation of efficiency gains. 

b. Additional air pollution controls required for criteria pollutants absorb energy savings gained from efficiency 

projects. 

c. Were costs associated with additional air pollution controls required as a result of NSR permitting considered in 

the economic analysis? 

II. How did EPA consider transmission loss, and would EPA give credit for efficiency improvements in transmission? 

BB2 Expand use of low-emitting power sources, such as natural gas 

I. Why did EPA use the name plate capacity instead of net capacity for each affected unit? 

a. Name plate can be as much as 20% higher than actual capacity, overstating available reductions. 

II. Did EPA consider existing energy policies and regulations when setting the goal? 

a. Would a State Plan take priority over bilateral contracts between a buyer of power in one State and a seller of 

power in another? If so, how and under what authority? 

BB3 Use more zero- and low-emitting power sources, such as solar, wind and nuclear power 

I. It appears that EPA’s goal is to preserve the 6% of nuclear energy that is “at risk.” What methods does EPA 

anticipate States must use to demonstrate compliance? 

II. Has EPA considered including a force majeure provision to accommodate the sudden and unavoidable shut down of a 

low- or zero-carbon emitting electric generating unit? 

a. Grid reliability requirements will mandate nearly immediate replacement electricity to prevent brown/black-outs. 
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b. The most reliable reserve electric generating units burn fossil fuel resulting in increasing and unexpected carbon 

emissions. 

BB4 Increase energy efficiency and energy demand 

I. Will there be a standardized Measurement and Verification (M&V) approach for counting savings? 

a. Different approaches for reporting under State energy efficiency standards and under 111(d) State Plans could be 

duplicative and costly. 

b. How will persistence and variables such as the life of measures be considered and determined if current State 

M&V standards on this issue differ from EPA standards? 

II. What ‘discount rates’ or other adjustments does EPA expect to be applied to savings? 

a. Net to gross issues to account for free riders and program spillover? 

b. Discount rates for take-back effects?