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# E 0F NE\/ADA Brian Sandoval, Governor 

# ridep Department ofConservation & Natural Resources LeoM Drozdoff PE Director

9VADA Ji’/i5iONF rJv:RONMENTAL PROTECTION DIVISION OF ENVIRONMENTAL PROTECTION Coiteen Cripps PhD Administrator rote.ttng the future fur gunerutIorts

December 9, 2013

Mr. Jared Blumenfeld Regional Administrator OAR-i, USEPA Region IX 75 Hawthorne Street San Francisco, CA 94105

RE: Nevada Comments on USEPA’s “Considerations in the Design ofa Program to Reduce Carbon Pollution from Existing Power Plants,” September 23, 2013

Dear Mr. Blumenfeld:

The Nevada Division of Environmental Protection (NDEP), in consultation with the Public Utilities Commission of Nevada, thanks you for the opportunity to comment on the set of questions circulated by the U.S. Environmental Protection Agency (USEPA) regarding the consideration ofpotential design of a program under section 111(d) for existing power plants. The comments are organized by the questions posed in USEPA’s September 23, 2013 document titled: Considerations in the Design ofa Program to Reduce Carbon Pollutionfrom Existing PowerPlants.

1. Whatis your experience with programs that reduce CO 2 emissions in the electric power sector?
Questions for firtherdiscussion

• Whatactions are states, utilities, andpowerplants taking today thatreduce CO 2 emissionsfrom the electricpower system? How mightthese he relevant under section 111(d)?

• What systems do states andpowerplants have inplace to measure andverUj’ CO 2 emissions andreductions?

• How do stateprograms andmeasures affrct electricitygeneration andemissions at a regional level? How are interstate effects accountedfor when measuringtheprogress ofa stateprogram? For example, are the multi-state ej,Thcts ofstate renewable portfolio standards, end-use energy ejjIciencyresource standards, emissions peJy’örmance standards, andemissions budgettradingprograms currently accounted for by the state, andifso, how?Jared Blumenfeld, Regional Administrator December 9, 2013 Page 2 of9

a. The Nevada Division of Environmental Protection, Bureau of Air Quality Planning (NDEP-BAQP), is aware of several programs in which the State ofNevada and its major electric public utilities, Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy, are taking steps to reduce CO 2 emissions, including the following:

1. Nevada was one ofthe first states to adopt a renewable portfolio standard. The renewable portfolio standard currently requires the utility to generate, acquire or
save 25% of its electricity sold to customers from portfolio energy systems or efficiency measures by 2025.1

1 NRS 704.7821 provides, in relevantpart: I. For each provider ofelectric service, the Commission shall establish a portfolio standard. The portfolio standard must require each provider to generate, acquire or save electricity from portfolio energy systems or efficiency measures in an amount that is: (a) For calendaryears 2005 and 2006, not less than 6 percent ofthe total amount ofelectricity sold by the providerto its retail customers in this State during that calendaryear. (b) For calendar years 2007 and 2008, not less than 9 percent of the total amount of electricity sold by the providerto its retail customers in this State during that calendaryear. (c) For calendar years 2009 and 2010, not less than 12 percent of the total amount of electricity sold by the providerto its retail customers in this State during that calendaryear. (d) For calendar years 2011 and 2012, not less than 15 percent of the total amount of electricity sold by the providerto its retail customers in this State during that calendaryear. (e) For calendar years 2013 and 2014, not less than 18 percent of the total amount of electricity sold by the providerto its retail customers in this State during that calendar year. (f) For calendar years 2015 through 2019, inclusive, not less than 20 percent of the total amount ofelectricity sold by the provider to its retail customers in this State during that calendar year.(g) For calendar years 2020 through 2024, inclusive, not less than 22 percent of the total amount ofelectricity sold by the provider to its retail customers in this State during that calendar year.(h) For calendar year 2025 and for each calendar year thereafter, not less than 25 percent of the total amount ofelectricity sold by the provider to its retail customers in this State during that calendaryear. 2. In addition to the requirements set forth in subsection 1, the portfolio standard for each providermust require that: (a) Ofthe total amount ofelectricity that the provider is required to generate, acquire or save from portfolio energy systems or efficiency measures during each calendaryear, not less than: (1) For calendar years 2009 through 2015, inclusive, 5 percent ofthat amount must be generated or acquired from solarrenewable energy systems. (2) For calendar year 2016 and for each calendar year thereafter, 6 percent of that amount mustbe generated or acquired from solarrenewable energy systems. (b) Ofthe total amount ofelectricity that the provider is required to generate, acquire or save from portfolio energy systems or efficiency measures: (1) During calendar years 2013 and 2014, not more than 25 percent ofthat amount may be based on energy efficiency measures; (2) During each calendar year 2015 to 2019, inclusive, not more than 20 percent ofthat amount may be based on energy efficiency measures; (3) During each calendar year 2020 to 2024, inclusive, not more than 10 percent ofthat amount may be based on energy efficiency measures; andJared Blumenfeld, Regional Administrator December 9, 2013 Page 3 of9

2. The NevadaLegislature recently enacted SB 123, which requires the retirement of 850 megawatts (MW) ofcoal firedpowerplants inNevada. 2

(4) For calendar year 2025 and each calendar year thereafter, no portion ofthat amount may be based on energy efficiency measures. Ifthe provider intends to use energy efficiency measures to comply with its portfolio standard during any calendar year, ofthe total amount ofelectricity saved from energy efficiency measures for which the provider seeks to obtain portfolio energy credits pursuant to this paragraph, at least 50 percent ofthat amount must be saved from energy efficiency measures installed at service locations ofresidential customers ofthe provider, unless a different percentage is approved by the Commission.

2 NRS 704.7316 provides: 1. An electric utility shall file with the Commission, as part of the plan required to be submitted pursuant to NRS 704.741, a comprehensive plan for the reduction ofemissions from coal-fired electric generating plants and the replacement of the capacity of such plants with increased capacity from renewable energy facilities and other electric generating plants. 2. The emissions reduction and capacity replacementplan must provide: (a) For the retirement or elimination of: (I) Not less than 300 megawatts ofcoal-fired electric generating capacity on or before December31, 2014; (2) In addition to the generating capacity retired or eliminated pursuant to subparagraph (I), not less than 250 megawatts ofcoal-fired electric generating capacity on or before December 31, 2017; and (3) In addition to the generating capacity retired or eliminated pursuant to subparagraphs (I) and (2), not less than 250 megawatts of coal-fired electric generating capacity on or before December 31, 2019. ‘For the purposes ofthis paragraph, the generating capacity ofa coal-fired electric generating plant must be determined by reference to the most recent resource plan filed by the electric utility pursuant to NRS7O4.741 and accepted by the Commission pursuantto NjS704.75l. (b) For the construction or acquisition of, or contracting for, 350 megawatts of electric generating capacity from renewable energy facilities. The electric utility shall: (1) Issue a request for proposals for 100 megawatts ofelectric generating capacity from
new renewable energy facilities on or before December31, 2014; (2) In addition to the request for proposals issued pursuant to subparagraph (1), issue a request for proposals for 100 megawatts of electric generating capacity from new renewable energy facilities on or before December31, 2015; (3) In addition to the requests for proposals issued pursuant to subparagraphs (1) and (2), issue a request for proposals for 100 megawatts of electric generating capacity from new renewable energy facilities on or before December 31, 2016; (4) Review each proposal received pursuant to subparagraphs (1), (2) and (3) and identify those renewable energy facilities that will provide: (I) The greatest economic benefit to this State; (II) The greatest opportunity forthe creation ofnewjobs in this State; and (III) The best value to customers ofthe electric utility; (5) Negotiate, in good faith, to construct, acquire or contract with the renewable energy facilities identified pursuant to subparagraph (4), and file with the Commission an amendment to the plan each time the utility wishes to construct, acquire or contract with such facilities; and (6) Begin, on or before December 31, 2017, the construction or acquisition ofa portion ofnew renewable energy facilities with a generating capacity of50 megawatts to be owned and operated by the electric utility, and complete construction ofsuch facilities on or before December 3 1, 2021.Jared Blumenfeld, Regional Administrator December 9, 2013 Page4of9

3. The Nevada Legislature enacted the Solar Energy Systems Incentive Program, which requires the Public Utilities Commission ofNevada to set incentive levels and schedules, with a goal of approving solar energy systems totaling at least 250,000 kilowatts of capacity in this State for the period beginning on July 1, 2010, and ending on December 31, 2021. NRS 701B.005 and 701B.010- 701B.290. To date, $160 million has been spent installing a total of38 MWs of installed capacity inNevada. 4. Similarly, Nevada has a Solar Thermal Demonstrations Program, which has the goal of promoting the installation of at least 3,000 solar thermal systems in homes, businesses, schools and other governmental buildings throughout this State by 2019. NRS 701B.300-701B.345. 5. The Wind Energy Systems Demonstration Program Act establishes a goal of installing at least 5 MW ofwind energy systems by 2012. NRS 701B.400-.650. To date, $25 million has been spent installing a total of 9 MWs of installed capacity inNevada. 6. The Waterpower Systems Demonstration Program Act similarly provides for the installation ofat least 5 MW ofwaterpower energy systems in this State by 2016.

For the purposes ofthis paragraph, the generating capacity ofa renewable energy facility must be determined by the nameplate capacity ofthe facility. (c) For the electric utility to construct or acquire and own electric generating plants with an electric generating capacity of550 megawatts, which must be constructed or acquired to replace, in an orderly and structured manner, the coal-fired electric generating capacity retired or eliminatedpursuant to paragraph (a). (d) If the plan includes the construction or acquisition of one or more natural gas-fired electric generating plants, a strategy for the commercially reasonable physical procurement of fixed-price natural gas by the electric utility. (e) A plan for tracking and specifying the accounting treatment for all costs associated with the decommissioning of the coal-fired electric generating plants identified for retirement or elimination. For the purposes ofthis subsection, an electric utility shall be deemed to own, acquire, retire or eliminate only its pro rata portion ofany electric generating facility that is not wholly owned by the electric utility and, except as otherwise provided in paragraph (b), “capacity” means an amount offirm electric generating capacity used by the electric utility for the purpose ofpreparing a plan filed with the Commission pursuant to NRS 704.7j3 to 7O4754, inclusive. 3. In addition to the requirements for an emissions reduction and capacity replacement plan set forth in subsection 2, the plan may include additional utility facilities, electric generating plants, elements orprograms necessary to carry out the plan, including, without limitation: (a) The construction ofnatural gas pipelines necessary for the operation ofany new natural gas-fired electric generating plants included in the plan; (b) Entering into contracts for the transportation ofnatural gas necessary for the operation of any natural gas-fired electric generating plants included in the plan; and (c) The construction of transmission lines and related infrastructure necessary for the operation or interconnection ofany electric generating plants included in the plan. (Added to NRS by QjjjO74)Jared Blumenfeld, Regional Administrator December 9, 2013 Page 5 of9

NRS 701B.700-701B.880. To date, $1.4 million has been spent installing a total of600 kWs ofinstalled capacity in the State. 7. In addition, the Mohave Generating Station, the largest electrical generating station inNevada, was decommissioned in 2010.

b. Facilities that emit 25,000 metric tons or more per year ofGHGs are required to annually report their emissions to EPA’s Greenhouse Gas Reporting Program. That includes nearly all ofNV Energy’s generation facilities inNevada.

c. The Public Utilities Commission ofNevadahas authorized the largest electric and gas utilities serving nearly 95% ofthe population in the State to expend substantial monies to implement various demand side management (energy efficiency) programs as follows:

1. Nevada Power Company dib/aNV Energy--$44.550,000 (2013). 2. SierraPacific Power Company d/b/aNV Energy--$6,100,000 (2013/electric). 3. Sierra Pacific PowerCompany d/b/aNV Energy--$445,000 (2014/gas). 4. Southwest Gas Corporation--$4,400,000 (2014).

2. How should EPA set the performance standard for state 111(d) plans? Questions /örfiirther discussion

• Which approaches to reducing CO 2 emissionsfrompowerplants shouldbe included in the evciluation ofthe “bestsystem ofemissionreduction” thatis usedto determine thepeiförmance level(s) thatstateplans must achieve? Shouldthe reduction requirementbe source- or system-based?

• How does the amountofflexibility that states are given to include dUjèrenttypes of programs in their stateplans relate to the “bestsystem ofemissions reduction” that is usedto settheperformance barfOr stateplans? For example, 

### fstate standards to improve end-use energy e/jlciency were includedin stateplans, shouldEPA consider potential improvements in end-use energy efficiency in setting theperfOrmance target fOr states?

• What shouldbe thejOrm andspecIcity oftheperformance level(s) in EPA guidelines? (Rate-basedor mass-based? Separate levelsfor each subcategoiy of sources, or one leveljOr the coveredsources in the state?A uniform national level or dJferentlevels by state/region basedon an establishedevaluationprocess?)

• When can etnission reductionsfrom existingpowerplants be achieved considering differentreduction strategies?

• How shoulda state, in applying a standardofpe,formance to anyparticularsource, consider afitcility ‘s “remaininguseful fljè” andotherjimctors?

a. The NDEP-BAQP believes that “best system of emission reduction” should be defined as broadly as possible to allow states as much flexibility as possible. States are currentlyJared Blumenfeld, Regional Administrator December9, 2013 Page 6 of9

in the slow process of recovering from the economic downturn, and Nevada was one of the hardesthit states. The cost ofenergy is akey factorinpromoting recovery. Therefore, to ensure that Nevada can maintain its energy prices at a reasonable level and to avoid sudden spikes in price, it is imperative that maximum flexibility be provided to the State in effectuating GHG reductions. Source-based reduction requirements will be less flexible, and facilities are already subject to significant source-based requirements to install additional control technologies, such as the Regional Haze Rule. System-based reduction programs will allow for more flexibility and might have the added benefit ofencouraging states to work cooperatively to achieve reductions on aregional scale.

b. As set forth above, states shouldbe granted maximum flexibility in employing the tools that will allow them to achieve meaningful GHG reductions over time. Demand-side management programs should be considered as part ofthe arsenal oftools available to states and improvements in energy efficiencies should be taken into account in setting performance targets. Thatbeing said, however, it is important thatUSEPA establish areasonable baseline from which reductions and improvements in energy efficiencies should be measured. For example, 2005 would be a reasonable base year from which to establish a baseline because it will take into account the economic downtown, the economic recovery, and early measures that states have taken to independently reduce GHG emissions. States thathave actively sought to reduce GHGs through implementation of legislation and regulations should not be penalized for their progressive efforts to reduce GHG emissions to date.

c. The establishment ofperformance levels should be guided by the same principle of providing as much flexibility as possible to states to achieve those levels. One uniform national standard would likely be too rigid. Each state is faced with its own unique challenges in meeting its energy needs and providing transmission from generation facilities to consumers. In Nevada, for example, creating transmission for natural gas has been and will continue to be a challenge given certain Endangered Species Act obstacles that have arisen. On the other hand, Nevada is uniquely situated to be able to take advantage ofgeothermal and solar opportunities that are not available to other states. Whatever performance standard is set must take into account such variability and allow states to utilize theirunique characteristics in orderto meet it.

d. The date by which emission reductions can be achieved will depend largely upon the baseline that USEPA sets from which reductions are measured. As stated previously, the baseline should not be set so as to penalize states for progressive efforts to reduce GHG emissions.

e. The remaining useful life ofan EGU should be taken into account in applying a performance standard because it is required by the Clean Air Act. While not necessarily a control technology, the remaining useful life ofa facility is apragmatic concern that will dictate when emissions will ultimately cease from that facility. States should be allowed to take credit for such emission reductions, especially because units taking the place ofEGUs being retired will be subject to theNSPS for new generation facilities.Jared Blumenfeld, Regional Administrator December 9, 2013 Page 7 of9

3. Whatrequirements should state plans meet and what flexibility should be provided to states in developing theirplans? Questions forfurther discussion

• Whatlevel offlexibilityshouldbeprovidedto states in meetingthe requiredlevel of performancefor affectedEGUs containedin the emissionguidelines?

• Can a stateplan include requirements thatapply to entities other than the afjècted EGUs? For example, must statesplace all ofthe responsibility to meetthe emission perfOrmance requirements on the owners or operators ofaffrctedEGUs, or do states haveflexibilityto take on some (orall,) ofthe responsibility to achieve the required level ofemissionsperformance themselves or assign itto others (e.g., to require an increase in the use ofrenewable energy orrequire end-use energy efficiency improvements, which willresultin emissions reductionsfrom affectedEGUs)?

• Whatcomponents should a stateplan have, andwhat shouldbe the criteriafOr approvability?

• Can a stateplan includeprograms thatrely on a differenttnix ofemission reduction methods than assumedin EPA ‘s analysis ofthe “bestsystem ofemission reduction” thatis usedto setthepeiformance standardfor stateplans?

• Whatshouldbe theprocessfor demonstrating thata stateplan will achieve a level of emissionspet jOrmance comparable to the level ofpe,jOrmance in the EPA emission guidelines?

• Whatenforceability, measurement, andverification issues mightarise, depending on the types ofstate measures andprograms thatstates include in theirplans? For example, what issues are raisedby actions thathave indirecteffects on EGU emissions, such as end-use energy efficiencyresource standards, renewableportfOlio standards, fInancial assistanceprograms to encourage end-use energy efficiency, buildingenergy codes, etc.)?

• Do dUjërent CO 2 reduction methods under dUferentstateplan approaches necessitate dffrrenttitnelinesfOrthe achievement ofemission reductions?

• What issues arisefrom thefactthatoperation andplanning ofthe electricitysystem is 0/len regional, but CAA section 111 ‘d,) callsfor stateplans? How shouldinterstate issues be cttidressea where actions in one state may affectEGUemissions in another
State? For example, where actions have interstate impacts, which state wouldreceive creditfOrthe emission reductions in its stateplan? CouldEPAprovidefOr coordinatedsubmittal ofstateplans that demonstrateperformance on aregional basis?

a. Because no two states are alike, maximum flexibility should be afforded to each state to utilize various tools and methodologies that meet GHG emission reductions requirements while taking into account the unique circumstances of the state’s energy infrastructure and economy. The unique circumstances ofeach state may necessitate different timelines by which the state may meetthe performance standards.Jared Blumenfeld, Regional Administrator December9, 2013 Page 8 of9

b. In Nevada, it would be incorrect to state that all ofthe responsibility for meeting the performance standards could be placed on the EGUs. For example, the public utility which operates a significant portion ofthe EGUs in Nevada is subject to oversight by the Public Utilities Commission ofNevada. The public utility can only take the measures that are approved in its triennial resource plan, which may only be approved after taking into account the effect of such measures on ratepayers. The State Legislature, however, has the authority to require increased renewable energy usage. In fact, the Nevada Legislature has been proactive in mandating an aggressive renewable portfolio standard, and Nevada should be able to take credit for such forward-looking action in a 111(d) plan.

c. It is difficult to define what components a state plan should have at this point in time, without the benefit ofunderstanding how USEPA will define best system of emission reduction” under the Clean Air Act. States should have maximum flexibility to address reductions in their plans, including standards of performance that provide for “less stringent standards or longer compliance schedules” pursuantto the criteria set forth in 40 CFR 

### § 60.24(1). In addition, states have the right to use flexible compliance mechanisms when they “tak[e] into account the cost ofachieving such reduction and any nonair quality health and environmental impact and energy requirements” as provided in the definition of standard ofperformance” under CAA 

### § 11 1(a)(1). A list ofpossible flexible compliance mechanisms could include, but is not limited, to tnechanisms such as exemptions for reliability reliefdue to natural disasters for commitments to retire the EGU within a specified time frame; for units smaller than a specified number ofmegawatts; for simple-cycle combustion turbines and limited-use units; for start-up. shutdown and malfunctions.

In addition, unit-specific approaches could include multi-year averaging; credit for natural gas co-firing or fuel switching, co-firing biomass fuels, cogenerationprocesses, and solar thermal energy to improve operation and efficiency. Carbon sequestration inNevada is probably not viable at this time givenNevadas geology. Averaging measures could also be employed. These might include averaging of coal units, averaging of coal units with lower emitting sources, and/or averaging of intracompany units that may lie both within and outside ofa state. Trading of carbon dioxide credits should be considered. EGUs should be allowed to receive credits for early utility actions that reduced GHG emissions and/or for offsite reductions, such as landfill methane or sulfurhexafluoride from operations.
Demand side management programs and energy efficiency programs should also be allowed as part of the state’s plan. In addition, USEPA should consider utility-sponsored management offorested areas and biomass for avoided emissions and GHG storage.Jared Blumenfeld, Regional Administrator December 9, 2013 Page 9 of9 Finally, states should receive credit for other Clean Air Act programs, such as regional haze, that have a co-benefit ofreducing GHGs.

4. What can EPA do to facilitate state plan development and implementation?
Questions for further discussion

• Whattypes andamountofguidance andimplementation supportshouldbeprovided to states?

• Are there benefitsfor coordination amongneighboringstates in the development and submittal ofstateplans? ShouldEPAfacilitate the coordination ofmulti-stateplan submittals?

• Wouldcertain types ofmeasures thatmight be includedin stateplans increase the needfor coordination among states?

• Are there modelrules thatEPA coulddevelop thatwouldassiststates, andwhat wouldthose rules cover?

USEPA has made clear that guidance is nonbinding. For clarity and to allow maximum participation by stakeholders, implementation support should be done by rulemaking rather than guidance.

GHG emission reductions may take place on a regional basis, such as cap-and-trade programs. Planning might also require detailed modeling and data analysis on a regional scale, similar to what was done for the Regional Haze program. It might be helpful for USEPA to facilitate coordination ofmulti-state plan submittals.
Regional electric reliability issues resulting from any such programs should also be coordinated with the Federal Energy Regulatory Commission.

The NDEP appreciates the opportunity to be involved in USEPA’s development of a GHG program for existing power plants under section 111(d). Ifyou have any questions about the NDEP’s comments or require additional clarification, feel free to contact me at (775) 687- 9495.

asmine K. Mehta Chief, Bureau ofAir Quality Planning

cc: Deborah Jordan, Director, EPA R9 Air Division Amy Zimpfer, Associate Director, EPA R9 Air Division David Noble, Commissioner, Nevada Public Utilities Commission
ec: Colleen Cripps, Administrator, Nevada Division ofEnvironmental Protection Rob Bamford, Chief Bureau ofAir Pollution Control Sii

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