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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 i ndividual rows between Lines 58 and 5 44 in EPA’s “Option 1 State - April 2014 Draft RegionalSummary.xlsx” spread sheet, “WECC_AZ” tab, excluding Nava jo Generating Station, which is located on tribal land). Given that the CO2 goals for Ariz ona 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 th e 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 “B ase 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 p eak demand? Since utilities ca nnot 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, Ariz ona 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 informat ion 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 th at 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” spre adsheets), which is the approximate capacity of Palo Verde Generating Station. However, less than 50% of Palo Ve rde 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-own ed) also fall into this categor y. 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 dema nd (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 capac ity additions are contemplated in the WECC Arizona transmission region until 2040. In existing utility resource plans, it is projected that new capac ity will be needed to meet load growth, replace retired assets, and balance more in termittent 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 existi ng combined cycle generation decline over time? With coal retirements in the IPM Option 1 Ca se, why is the existing combined cycl e generation effectively the same in 2025 and 2030 compared to the Base Case?

VIII. EPA stated that (and the output files s how) their modeling demonstrated that Ar izona could meet the proposed interim and final goals with coal operating thr ough 2030. Did that modeling assume a regional CO2 trading or credit system, or2 was Arizona able to comply wit hout any multi-state coordination?

IX. The modeling output files show a carbon credit price of $46/t on 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 shut down 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 imp acts of existing regulati ons 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 infrastru cture 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 retire ment of a coal unit located in a differe nt state, yet which serves AZ, without entering into a full multi-state plan, provid ed 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 existi ng coal generation to “available” natural gas combined cycle (NGCC) generation. Did EPA’s mode ling consider both the inte rstate gas transportation requirements as well as the peak generation capacity available to displace existi ng coal generation?

a. Given the relationship be tween AZ’s winter gas requir ements (usage weighted by re sidential/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 na meplate capacity to account for AZ high summer temperatures?

c. Did EPA’s modeling factor in any federally enforc eable 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 capa city to displace existi ng coal fired generation).

e. Utilities cannot count on these units when contemplating “av ailable” NGCC capacity to dispatch in place of coal generation because the utilities do not ow n 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’ existing3 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 a ssist with peak capacity needs as these units are not designed to opera te in a peaking fashion.

II. How does EPA contemplate treating new ge neration resources that are built to di splace existing coal capacity? Will they fall under the New Source Performance Standard (NSPS) a nd will these new resources be regulated on a standalone basis? Or will these new res ources fall into the Existing Source Perfo rmance 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/reconstr ucted units subject to 111(b) in the plans developed under 111(d)?

IV. Has EPA considered how a presently non-af fected unit that becomes subject to th e 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 establis hing EPA’s proposed goals?

a. If not, will EPA do so prior to the final rule and comm it 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 st ate have that its programs u sed 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, enfo rceable, 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 cr editable, even though the act ual benefits are real.

III. Is participation in a multi-state plan the only way to get cr edit 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 base d plan results in reductions at a unit in another State?

c. The renewable portfolio standards that EPA relies upon in setting the state targ ets 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 applie d 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?4 General Comments

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

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

b. States with growing popula tion will have to achieve greater reductio ns 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 ma king changes to plans. What are EP A’s procedures fo r processing these changes? Will these procedures include tim e 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 pr ogram? If so, what is required to make the deration effective?

BB1 Increase efficiency of existing foss il fuel power plants through equipmen t 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 require d for criteria pollutants absorb energy savings gained from efficiency projects.

c. Were costs associated with additional air pollution contro ls 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 immediat e replacement electricity to prevent brown/black-outs.5 b. The most reliable reserve electric ge nerating units burn fossil fuel resulti ng in increasing and unexpected carbon emissions.

BB4 Increase energy efficiency and energy demand

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

a. Different approaches for reporting under State energy effi ciency standards and under 111(d) State Plans could be duplicative and costly.

b. How will persistence and variables such as the life of me asures be considered and determined if current State M&V standards on this issue differ from EPA standards?

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

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

b. Discount rates for take-back effects?