A STAT E 0F N E\/ADA Brian Sandoval, Governor

ridep Department of Conservation & 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 of a 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 of potential 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 of a Program to Reduce Carbon Pollution from Existing

Power Plants.

1. What is your experience with programs that reduce CO2emissions in the electric power

sector?

Questions for firther discussion

• What actions are states, utilities, andpower plants taking today that reduce CO2

emissionsfrom the electric power system? How might these he relevant under section

111(d)?

• What systems do states andpower plants have in place to measure and verUj’ CO2

emissions and reductions?

• How do state programs and measures affrct electricity generation and emissions at a

regional level? How are interstate effects accountedfor when measuring the progress

ofa state program? For example, are the multi-state ej,Thcts ofstate renewable

portfolio standards, end-use energy ejjIciency resource standards, emissions

peJy’örmance standards, and emissions budget tradingprograms currently accounted

for by the state, and ifso, how?
Jared B lumenfeld, Regional Administrator

December 9, 2013

Page 2 of 9

a. The Nevada Division of Environmental Protection, Bureau of Air Quality

Planning (NDEP-BAQP), is aware of several programs in which the State of Nevada 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 CO2 emissions, including the

following:

1. Nevada was one of the 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 relevant part:

I. For each provider of electric 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 calendar years 2005 and 2006, not less than 6 percent ofthe total amount of electricity

sold by the provider to its retail customers in this State during that calendar year.

(b) For calendar years 2007 and 2008, not less than 9 percent of the total amount of

electricity sold by the provider to its retail customers in this State during that calendar year.

(c) For calendar years 2009 and 2010, not less than 12 percent of the total amount of

electricity sold by the provider to its retail customers in this State during that calendar year.

(d) For calendar years 2011 and 2012, not less than 15 percent of the total amount of

electricity sold by the provider to its retail customers in this State during that calendar year.

(e) For calendar years 2013 and 2014, not less than 18 percent of the total amount of

electricity sold by the provider to 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 of electricity 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 of electricity 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 of electricity sold by the provider to its retail customers in this State during that

calendar year.

2. In addition to the requirements set forth in subsection 1, the portfolio standard for each

provider must require that:

(a) Of the total amount of electricity that the provider is required to generate, acquire or save

from portfolio energy systems or efficiency measures during each calendar year, not less than:

(1) For calendar years 2009 through 2015, inclusive, 5 percent of that amount must be

generated or acquired from solar renewable energy systems.

(2) For calendar year 2016 and for each calendar year thereafter, 6 percent of that

amount must be generated or acquired from solar renewable energy systems.

(b) Of the total amount of electricity 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 of that amount may

be based on energy efficiency measures;

(2) During each calendar year 2015 to 2019, inclusive, not more than 20 percent of that

amount may be based on energy efficiency measures;

(3) During each calendar year 2020 to 2024, inclusive, not more than 10 percent of that

amount may be based on energy efficiency measures; and
Jared Blumenfeld, Regional Administrator

December 9, 2013

Page 3 of9

2. The Nevada Legislature recently enacted SB 123, which requires the retirement of

850 megawatts (MW) of coal fired power plants in Nevada. 2

(4) For calendar year 2025 and each calendar year thereafter, no portion of that amount

may be based on energy efficiency measures.

If the provider intends to use energy efficiency measures to comply with its portfolio standard

during any calendar year, of the total amount of electricity saved from energy efficiency measures

for which the provider seeks to obtain portfolio energy credits pursuant to this paragraph, at least

50 percent of that amount must be saved from energy efficiency measures installed at service

locations of residential customers of the 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 of emissions 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 replacement plan must provide:

(a) For the retirement or elimination of:

(I) Not less than 300 megawatts of coal-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 of coal-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 of this paragraph, the generating capacity of a 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 pursuant to 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 of electric 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 for the creation of new jobs in this State; and

(III) The best value to customers of the 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 of a portion

of new renewable energy facilities with a generating capacity of 50 megawatts to be owned and

operated by the electric utility, and complete construction of such 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 of Nevada 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 of 38 MWs of

installed capacity in Nevada.

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 of wind energy systems by 2012. NRS 701B.400-.650.

To date, $25 million has been spent installing a total of 9 MWs of installed

capacity in Nevada.

6. The Waterpower Systems Demonstration Program Act similarly provides for the

installation of at least 5 MW of waterpower energy systems in this State by 2016.

For the purposes of this paragraph, the generating capacity of a 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 of 550 megawatts, which must be constructed or acquired to replace,

in an orderly and structured manner, the coal-fired electric generating capacity retired or

eliminated pursuant 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 of this subsection, an electric utility shall be deemed to own, acquire, retire or

eliminate only its pro rata portion of any electric generating facility that is not wholly owned by

the electric utility and, except as otherwise provided in paragraph (b), “capacity” means an amount

of firm electric generating capacity used by the electric utility for the purpose of preparing 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 or programs necessary to carry out the plan, including, without limitation:

(a) The construction of natural gas pipelines necessary for the operation of any new natural

gas-fired electric generating plants included in the plan;

(b) Entering into contracts for the transportation of natural 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 of any electric generating plants included in the plan.

(Added to NRS by QjjjO74)
Jared Blumenfeld, Regional Administrator

December 9, 2013

Page 5 of 9

NRS 701B.700-701B.880. To date, $1.4 million has been spent installing a total

of 600 kWs of installed capacity in the State.

7. In addition, the Mohave Generating Station, the largest electrical generating

station in Nevada, was decommissioned in 2010.

b. Facilities that emit 25,000 metric tons or more per year of GHGs are required to

annually report their emissions to EPA’s Greenhouse Gas Reporting Program. That includes

nearly all of NV Energy’s generation facilities in Nevada.

c. The Public Utilities Commission of Nevada has authorized the largest electric and

gas utilities serving nearly 95% of the population in the State to expend substantial monies to

implement various demand side management (energy efficiency) programs as follows:

1. Nevada Power Company dib/a NV Energy--$44.550,000 (2013).

2. Sierra Pacific Power Company d/b/a NV Energy--$6,100,000 (2013/electric).

3. Sierra Pacific Power Company 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 CO2emissionsfrom power plants should be included

in the evciluation ofthe “best system ofemission reduction” that is used to determine

the peiförmance level(s) that state plans must achieve? Should the reduction

requirement be source- or system-based?

• How does the amount offlexibility that states are given to include dUjèrent types of

programs in their state plans relate to the “best system ofemissions reduction” that

is used to set the performance barfOr state plans? For example, fstate standards to

improve end-use energy e/jlciency were included in state plans, should EPA consider

potential improvements in end-use energy efficiency in setting the perfOrmance target

fOr states?

• What should be the jOrm and specIcity ofthe performance level(s) in EPA

guidelines? (Rate-based or mass-based? Separate levelsfor each subcategoiy of

sources, or one level jOr the covered sources in the state? A uniform national level or

dJferent levels by state/region based on an established evaluation process?)

• When can etnission reductionsfrom existing power plants be achieved considering

different reduction strategies?

• How should a state, in applying a standard ofpe,formance to any particular source,

consider afitcility ‘s “remaining useful fljè” and other jimctors?

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 currently
Jared B lumenfeld, Regional Administrator

December 9, 2013

Page 6 of 9

in the slow process of recovering from the economic downturn, and Nevada was one of the

hardest hit states. The cost of energy is a key factor in promoting 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 of encouraging states to work cooperatively to achieve reductions

on a regional scale.

b. As set forth above, states should be 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 of the arsenal of tools available to states and

improvements in energy efficiencies should be taken into account in setting performance targets.

That being said, however, it is important that USEPA establish a reasonable 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 that have 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 of performance 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 of geothermal 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 their unique characteristics in order to 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 of an 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 of a facility is a pragmatic 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 of EGUs being retired

will be subject to the NSPS for new generation facilities.
J ared Blumenfeld, Regional Administrator

December 9, 2013

Page 7 of 9

3. What requirements should state plans meet and what flexibility should be provided to

states in developing their plans?

Questions for further discussion

• What level offlexibility should be provided to states in meeting the required level of

performance for affected EGUs contained in the emission guidelines?

• Can a state plan include requirements that apply to entities other than the afjècted

EGUs? For example, must states place all ofthe responsibility to meet the emission

perfOrmance requirements on the owners or operators ofaffrcted EGUs, or do states

have flexibility to take on some (or all,) ofthe responsibility to achieve the required

level ofemissions performance themselves or assign it to others (e.g., to require an

increase in the use ofrenewable energy or require end-use energy efficiency

improvements, which will result in emissions reductionsfrom affected EG Us)?

• What components should a state plan have, and what should be the criteriafOr

approvability?

• Can a state plan include programs that rely on a different tnix ofemission reduction

methods than assumed in EPA ‘s analysis ofthe “best system ofemission reduction”

that is used to set the peiformance standardfor state plans?

• What should be the processfor demonstrating that a state plan will achieve a level of

emissions petjOrmance comparable to the level ofpe,jOrmance in the EPA emission

guidelines?

• What enforceability, measurement, and verification issues might arise, depending on

the types ofstate measures and programs that states include in their plans? For

example, what issues are raised by actions that have indirect effects on EGU

emissions, such as end-use energy efficiency resource standards, renewable portfOlio

standards, fInancial assistance programs to encourage end-use energy efficiency,

building energy codes, etc.)?

• Do dUjërent CO2reduction methods under dUferent state plan approaches necessitate

dffrrent titnelinesfOr the achievement ofemission reductions?

• What issues arise from the fact that operation andplanning ofthe electricity system is

0/len regional, but CAA section 111 ‘d,) callsfor state plans? How should interstate

issues be cttidressea where actions in one state may affect EGU emissions in another

State? For example, where actions have interstate impacts, which state would receive

credit fOr the emission reductions in its state plan? Could EPA provide fOr

coordinated submittal ofstate plans that demonstrate performance on a regional

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 of each state may necessitate different timelines by which

the state may meet the performance standards.
Jared Blumenfeld, Regional Administrator

December 9, 2013

Page 8 of9

b. In Nevada, it would be incorrect to state that all of the responsibility for meeting

the performance standards could be placed on the EGUs. For example, the public utility which

operates a significant portion of the EGUs in Nevada is subject to oversight by the Public

Utilities Commission of Nevada. 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 of understanding 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” pursuant to 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 of achieving such reduction and any nonair quality health and environmental

impact and energy requirements” as provided in the definition of standard of performance”

under CAA § 11 1(a)(1). A list of possible flexible compliance mechanisms could include, but is

not limited, to tnechanisms such as exemptions for reliability relief due to natural disasters for

commitments to retire the EGU within a specified time frame; for units smaller than a specified

number of megawatts; 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, cogeneration processes, and solar

thermal energy to improve operation and efficiency. Carbon sequestration in Nevada is probably

not viable at this time given Nevadas 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 of a 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 sulfur hexafluoride 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 of forested areas and biomass for avoided emissions and GHG storage.
Jared Blumenfeld, Regional Administrator

December 9, 2013

Page 9 of 9

Finally, states should receive credit for other Clean Air Act programs, such as regional

haze, that have a co-benefit of reducing GHGs.

4. What can EPA do to facilitate state plan development and implementation?

Questions for further discussion

• What types and amount ofguidance and implementation support should be provided

to states?

• Are there benefitsfor coordination among neighboring states in the development and

submittal ofstate plans? Should EPA facilitate the coordination ofmulti-state plan

submittals?

• Would certain types ofmeasures that might be included in state plans increase the

needfor coordination among states?

• Are there model rules that EPA could develop that would assist states, and what

would those 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 of multi-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). If you 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 of Air 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 of Environmental Protection

Rob Bamford, Chief Bureau of Air Pollution Control

Sii

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