Renewables Portfolio Standards in the United States: A Status Update - - PowerPoint PPT Presentation

Renewables Portfolio Standards in the United States: A Status Update

Galen Barbose

Lawrence Berkeley National Laboratory

State-Federal RPS Collaborative National Summit on RPS Washington, D.C.

November 6, 2013

This analysis was funded by the National Electricity Delivery Division of the Office of Electricity Delivery and Energy Reliability and by the Solar Energy Technologies Office of the Office of Energy Efficiency and Renewable Energy of the U.S. Department of Energy under Contract No. DE- AC02-05CH11231.

Summary of State RPS Experience-to-Date

• State RPS policies have been a significant driver for renewable

energy growth in the United States and have largely held up against recent political challenges

• Generally high levels of compliance achieved thus far
• Compliance costs have thus far remained relatively modest,

though questions exist about future costs

• Significant solar and other RE capacity is required to meet future

RPS targets, but is well in-line with pace of additions in recent years

• Significant challenges nevertheless exist to meeting future RPS
• bligations (e.g., managing REC price volatility, transmission,

integration, siting)

2

RPS Policies Exist in 29 States and DC

7 More States Have Non-Binding Goals

3

Existing State RPS Policies Apply to 55% of Total U.S. Retail Electricity Sales in 2012

Non-Binding Goal

Source: Berkeley Lab

WI: 10% by 2015 NV: 25% by 2025 TX: 5,880 MW by 2015 PA: 8.5% by 2020 NJ: 22.5% by 2020 CT: 23% by 2020 MA: 11.1% by 2009 +1%/yr ME: 40% by 2017 NM: 20% by 2020 (IOUs) 10% by 2020 (co-ops) CA: 33% by 2020 MN: 25% by 2025 Xcel: 30% by 2020 IA: 105 MW by 1999 MD: 20% by 2022 RI: 16% by 2019 HI: 40% by 2030 AZ: 15% by 2025 NY: 30% by 2015 CO: 30% by 2020 (IOUs) 20% by 2020 (co-ops) 10% by 2020 (munis) MT: 15% by 2015 DE: 25% by 2025 DC: 20% by 2020 WA: 15% by 2020 NH: 24.8% by 2025 OR: 25% by 2025 (large utilities) 5-10% by 2025 (smaller utilities) NC: 12.5% by 2021 (IOUs) 10% by 2018 (co-ops and munis) IL: 25% by 2025

Mandatory RPS

VT: 20% by 2017 ND: 10% by 2015 VA: 15% by 2025 MO: 15% by 2021 OH: 12.5% by 2024 SD: 10% by 2015 UT: 20% by 2025 MI: 10% by 2015 KS: 20% of peak demand by 2020 OK: 15% by 2015 AK: 50% by 2025

Notes: Compliance years are designated by the calendar year in which they begin. Mandatory standards or non-binding goals also exist in US territories (American Samoa, Guam, Puerto Rico, US Virgin Islands)

Enactment of New RPS Policies has Waned, but States Continue to Hone Existing Policies

4

CO (2007) HI (2005) IL (2008) MA (2003) CT (2000) MD (2006) DC (2007) NH (2008) MI (2012) ME (2000) PA (2001) NJ (2001) NY (2006) DE (2007) NC (2010) MO (2011) IA MN (2002) AZ (1999) NV (2001) WI (2000) TX (2002) NM (2002) CA (2003) RI (2007) MT (2008) WA (2012) OR (2011) OH (2009) KS (2011)

1983 1991 1994 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

IA MN AZ MN NM CT NJ CT AZ CA DC HI CO CA MA CO WI NV MN NM CO CA CO DE IL DE CT MD CT NV PA NV CT CT HI ME IL DC NJ MD TX HI DE MA MN MA DE NH MN NJ MD MD NV MD IL NM MT WI ME NJ OR NJ MA NY NV MN RI NY MD OH NJ NC NM WI PA TX

Enactment (above timeline) ( )

Year of First Requirement

Enactment (above timeline) Major Revisions (below timeline)

( )

Year of First Requirement

Major RPS Revisions in 2013

• CO: Raised overall RPS target for rural electric cooperatives from

10% to 20% and created DG set-aside; extended eligibility to GHG- neutral coal mine methane and pyrolysis of MSW

• CT: Increased maximum size threshold for hydroelectric facilities to

qualify for Class I resources, from 5 MW to 30 MW, subject to various limitations

• MD: Created off-shore wind set-aside (2.5% by 2017)
• MN: Created a solar set-aside aside (1.5% by 2020) for IOUs
• MT: Created exemption for utilities serving fewer than 50 customers
• NV: Phases out energy efficiency allowance and multiplier for PV

and places limits on banking of excess RECs

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General Trends in Recent RPS Revisions

• Expanding and revising resource eligibility (waste-to-

energy, hydropower, biomass co-firing, solar thermal)

• Increased stringency of RPS purchase targets
• Adoption of resource-specific set-asides and acceleration
• r increase in targets
• Honing solar set-aside provisions

– Eligibility rules (size, location, etc.) – Solar ACP schedules – Procurement mechanisms (contracting, auctions)

• Efforts to address REC oversupply/volatility and lack of

long-term contracting opportunities in restructured markets

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1 - 2 years 3 – 4 years 5 – 6 years 7 – 8 years 9 – 10 years > 10 years

Colorado Delaware Illinois Kansas Montana California Arizona Michigan New Hampshire Maryland Connecticut Iowa Missouri Hawaii Pennsylvania New Mexico Massachusetts Maine Oregon North Carolina Rhode Island New York Minnesota New Jersey Washington Ohio Washington D.C. Wisconsin Nevada Texas

Experience with State RPS Compliance Obligations Varies Widely and is Growing

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Operational Experience with State RPS Policies (number of major compliance years completed-to-date)

State RPS Policies Appear to Have Motivated Substantial Renewable Capacity Development

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Cumulative and Annual Non-Hydro Renewable Energy Capacity in RPS and Non-RPS States, Nationally

Though not an ideal metric for RPS-impact, 67% (46 GW) of all non-hydro renewable capacity additions from 1998-2012 occurred in states with active/impending RPS compliance obligations

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Nameplate Capacity (MW)

Cumulative Capacity

RPS Non-RPS

2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Nameplate Capacity (MW)

Annual Capacity Additions

RPS Non-RPS

State RPS’ Have Largely Supported Wind, Though Solar Has Become More Prominent

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RPS-Motivated* Renewable Energy Capacity Additions from 1998-2012, by Technology Type

* Renewable additions are counted as “RPS-motivated” if and only if they are located in a state with an RPS policy and commercial operation began no more than one year before the first year of RPS compliance obligations in that state. On an energy (as opposed to capacity) basis, wind energy represents approximately 85%, biomass 8%, solar 4%, and geothermal 3% of cumulative RPS-motivated renewable energy additions from 1998-2012, if estimated based on assumed capacity factors. 88% 1% 3% 8%

Cumulative RPS Capacity Additions (1998-2012)

2,000 4,000 6,000 8,000 10,000 12,000 14,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Nameplate Capacity (MW)

Annual RPS Capacity Additions Geothermal Biomass Solar Wind

Solar and DG Set-Asides Have Become Widespread

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17 states + D.C. have solar or DG set-asides, sometimes combined with credit multipliers; 3 other states only have credit multipliers

11 states created solar/ DG set- asides since 2007:

DE, IL, MA, MD, MO, MN, NC, NH, NM, OH, OR

Differential support for solar/DG provided via long-term contracting programs (CT, DE, NJ, and RI) and via up-front incentives/SREC payments

NV: 1.5% solar by 2025 2.4x multiplier for PV until 2015 PA: 0.5% solar PV by 2020 NJ: 4.1% solar electric by 2027 AZ: 4.5% customer-sited DG by 2025 (half from residential) NY: 878 GWh retail DG by 2015 CO: 3% DG by 2020 for IOUs (half from retail DG) 1% DG by 2020 for coops 3x multiplier for munis/coops for solar installed before July 2015 DC: 2.5% solar by 2023 WA: 2x multiplier for DG NM: 4% solar electric by 2020, 0.6% customer-sited DG by 2020 DE: 3.5% solar by 2025 3x multiplier for solar installed before Jan. 2015 (applies only to solar used for general RPS target) MD: 2% solar by 2020

Set-aside Multiplier

NC: 0.2% solar by 2018 NH: 0.3% solar electric by 2014

Set-aside with multiplier

TX: 2x multiplier for all non-wind OH: 0.5% solar electric by 2024 MA: 456 GWh customer-sited solar PV (no specified target year) MO: 0.3% solar electric by 2021 MI: 3x multiplier for solar OR: 20 MW solar PV by 2020 2x multiplier for PV installed before 2016 IL: 1.5% solar PV by 2025, 1% DG by 2015 (50% <25 kW)

Note: Compliance years are designated by the calendar year in which they begin Source: Berkeley Lab

MN: 1.5% solar by 2020 for IOUs

Solar Share is Notably Greater in Regions with Set-Asides or Strong Solar Resource Potential

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RPS-Motivated* Renewable Energy Capacity Additions from 1998-2012, by Region and Technology Type

*Renewable additions are counted as “RPS-motivated” if and only if they are located in a state with an RPS policy and commercial operation began no more than one year before the first calendar year of RPS compliance obligations in the host state.

4,000 8,000 12,000 16,000 20,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% New England, New York Mid-Atlantic California Non-CA West Texas Midwest Capacity Additions (Nameplate MW) % of Capacity Additions (Nameplate MW)

Solar Geothermal Biomass Wind Total MW (right axis)

Impact of Solar/DG Set-Asides is Growing: Drove ~50% of U.S. PV Additions in 2010-12

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General RPS obligations also driving significant solar additions in California and Southwest

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 200 400 600 800 1,000 1,200 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Percent of U.S. Annual Grid-Connected PV Installations (%) NH MO DC IL DE OH MD NY PA NM NV MA NC CO AZ NJ

Percent of U.S. annual grid-connected PV capacity additions, driven by solar/DG set- asides [right axis] Percent of U.S. annual grid-connected PV capacity additions, excluding California, driven by solar/DG set-asides [right axis]

Annual Grid-Connected PV Installations for Solar/DG Set-Asides (MWac)

Main Tier RPS Targets Largely Achieved; Isolated Struggles Apparent

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Percent of Main Tier RPS Target Met with Renewable Electricity or RECs

(including available credit multipliers and banking, but excluding ACPs and borrowing)

Note: Percentages less than 100% do not necessarily indicate that “full compliance” was not technically achieved, because of ACP compliance options, funding limits, or force majeure events.

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% AZ CA CO CT DC DE HI IA IL KS MA MD ME MI MN MO MT NC NH NJ NM NV NY OH OR PA RI TX WA WI

2009 2010 2011 2012

Achievement of Solar/DG Set-Aside Targets Has Steadily Increased in Most States

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Note: "Percent of Solar/DG Target Met with Solar/DG Electricity or RECs" excludes ACPs but includes applicable credit

• multipliers. In cases where this figure is below 100%, suppliers may not have been technically out of compliance due to solar

ACP compliance options, funding limits, and force majeure provisions.

Percent of Solar/DG Set-Aside Target Met with Solar/DG Electricity or SRECs

(including available credit multipliers and banking, but excluding ACPs and borrowing)

0% 20% 40% 60% 80% 100% 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 AZ CO DC DE IL MA MD MN MO NC NH NJ NM NV NY OH OR PA Percent of Solar/DG Target Met with Solar/DG Electricity or RECs

REC Pricing Reflects Current Supply-Demand Balance; Exhibits Continued Volatility

• Rising Class I REC prices in Northeastern states reflect tightening

supply, while pricing in Mid-Atlantic states remain low

• Sinking SREC prices in recent years (across most markets) show

enduring over-supply

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Main Tier/Class I RECs SRECs

$0 $10 $20 $30 $40 $50 $60 $70 $80

Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13

Trading Month

CT Class I DC Tier I DE Class I IL Wind MA Class I MD Tier I ME New NH Class I NJ Class I OH In-State PA Tier I RI New TX

Avg Monthly REC Price (2012$/MWh)

Sources: Evolution Markets (through 2007) and Spectron (2008 onward). Plotted values are the last trade (if available) or the mid-point of Bid and Offer prices, for the current or nearest future compliance year traded in each month.

$0 $100 $200 $300 $400 $500 $600 $700 $800

Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13

• Avg. Monthly SREC Price ($2012/MWh)

Trading Month

DC DE MA MD NC NH NJ OH PA Sources: Spectron, SRECTrade, Flett Exchange, PJM-GATS, and NJ Clean Energy Program. Depending on the source used, plotted values are either the mid-point of monthly average bid and offer prices, the average monthly closing price, or the weighted average price of all RECs transacted in the month, and generally refer to SREC prices for the current or nearest future compliance year traded in each month.

Rate Impacts of State RPS Policies Have Thus Far Been Generally ‘Modest’ (<2%)

• Simplified approach

ignores some ratepayer costs (e.g., integration) and benefits (e.g., wholesale electricity price suppression)

• Limited/mixed data for

states dominated by bundled contracts

• Rate impacts vary with

target levels, REC prices, presence of set- asides

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Translating REC prices or other available data on net incremental costs into retail rate impacts yields the results shown below

Future compliance costs will be impacted by increasing RPS targets, changes to fed. tax incentives, and trajectories

• f RE costs and natural gas prices (among other factors)
• 1%

0% 1% 2% 3% 4% 5%

CT DC DE IL MA MD ME NH NJ OH PA RI TX AZ CO MI NC NY OR WI REC Purchases and ACPs Other Methods*

Estimated Rate Impact of State RPS Policies* (% of average retail electricity rate)

2010 2011 2012

* Other Methods for estimating rate impacts include utility-reported incremental costs (OR), RPS tariff rider collections (AZ, CO, MI, NC), approved budget (NY), and PUC analysis (WI). States omitted if data

• n incremental RPS compliance costs are unavailable (CA, IA, HI, KS, MN, MO, MT, NM, NV, TX, WA).

Rate Impacts of Solar/DG Set-Asides Vary and Were Tempered by SREC Price Declines in 2012

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The rate impacts of solar/DG set-asides can be estimated using SREC prices or data on incentive program expenditures

• Rate impacts vary with

target levels and SREC prices

• Incentive programs tend

to “front-load” set-aside costs

• Rate impacts in 2012

fell in many states due to decline in SREC prices, in spite of increasing targets

0% 1% 2% 3% 4%

DC DE MA MD NH NJ OH PA AZ NY MO SREC Purchases and SACPs Solar/DG Incentive Program

Estimated Rate Impact of Solar/DG Set-Asides* (% of average retail electricity rate)

2010 2011 2012

*States omitted from the figure if data on incremental costs of solar/DG set-aside are unavailable (CO, IL, MN, NC, NM, NV, OR).

Set-Aside targets are still in the early phases of ramping up; will increase by a factor of 5 by 2020

Solar/DG Set-Asides Represent a Large Share of Total RPS Rate Impacts in Some States

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Average RPS rate impacts over 2010-2012 can be segmented into Solar/DG Set-Aside and Non-Solar/DG Set-Aside impacts Overall RPS rate impacts may increasingly be driven by solar/DG set-aside costs as targets rise

0% 1% 2% 3% 4% 5%

DC DE MA MD NH NJ OH PA AZ NY SREC Purchases and SACPs Solar/DG Incentive Program

Estimated Rate Impact of State RPS Policies* (% of average retail electricity rate, 2010-2012)

Solar/DG Set-Aside Non-Solar/DG Set-Aside

* Results are based on average rate impacts over the 2010-2012 period, using however many years of compliance data are available. States omitted from the figure if data on incremental costs are unavailable (CO, IL, MN, MO, NC, NM, NV, OR).

Most States Have Capped Rate Impacts Well Below 10% (13 States Below 5%)

19 No explicit cap on incremental compliance costs in 9 states (AZ, CA, IA, KS, HI, MN, NV, PA, WI), though KS caps gross revenue requirements and CA is currently developing its cost containment mechanism

Many states’ cost containment mechanisms can be translated into an estimated maximum increase in retail rates

0% 5% 10% 15% NJ RI MA DC NH CT MD ME OR WA NM MI TX DE OH NY CO NC IL MO MT

Maximum Incremental RPS Compliance Costs (Percentage Increase in Average Retail Rates)

Effective Cost Cap (Max Retail Rate Increase) Historical Compliance Costs (Most-Recent Year)

Estimated Retail Rate Increase

Future RPS Requirements are Sizable, But Well Within Recent RE Growth Rates

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• 94 GW of “New RE”

required by 2035, if full compliance is achieved

• Equates to roughly

3-5 GW/yr through 2020 and 2-3 GW through 2035

• By comparison, RPS-

driven RE additions have ranged from 6-13 GW/yr in all but

• ne year since 2008

* New RE is defined based on state-specific distinctions between new vs. existing, or based on the year in which the RPS was enacted; it does not represent new renewables relative to current supply

5 10 15 20 25 30

IA RI ME NH DC MT DE HI NV WI CT NM MI KS NC MO OR NY AZ MD PA WA CO MA OH MN TX NJ IL CA

New Renewable Capacity by 2035 (Nameplate GW)

0% 5% 10% 15% 20% 25% 30% 35%

IA NC TX MI PA WI NY MO AZ ME DC MT OH WA KS MD NV RI CO NH NM CT OR DE NJ IL CA MN MA HI

New Renewable Generation by 2035 (Percent of Statewide Retail Sales)

Solar Market Growth is on Pace to Meet Future Solar/DG Set-Aside Requirements

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2,000 4,000 6,000 8,000 10,000 200 400 600 800 1,000 1,200 2010 2015 2020 2025 2030 2035 NJ IL AZ MD PA OH CO NM MA DE DC NC NY NV MO NH OR Required Annual Capacity Additions (left axis) Cumulative Capacity Required (right axis)

Cumulative Solar Capacity (MWac) Annual Solar Capacity Additions (MWac)

• Cumulative capacity requirement grows to 9,300 MW by 2035
• Required average annual solar capacity additions of 700 MW/yr through

2020, tapering off thereafter

• By comparison, set-aside PV additions reached 1,200 MW in 2012

The Future Role and Impact of State RPS Programs Will Depend On…

 The outcome of ongoing and future legislative and legal challenges  Whether cost caps become binding  The ever-present possibility of federal energy legislation  How policymakers re-tune RPS’ in response to changing market conditions  Continued efforts to address challenges associated with volatile REC prices and limited availability of long-term contracts in restructured retail electricity markets  How other related policy issues and barriers affecting RE deployment are addressed (transmission, integration, siting, net metering, etc.)

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Thank You! For further information:

LBNL RPS publications and resources:

rps.lbl.gov

LBNL renewable energy publications:

http://emp.lbl.gov/research-areas/renewable-energy

Contact information:

Galen Barbose, glbarbose@lbl.gov, 510-495-2593 Ryan Wiser, rhwiser@lbl.gov, 510-486-5474

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Political and Legal Challenges to RPS Policies Have Been Mounting

• Legislation to repeal, reduce, delay, or freeze RPS targets

introduced in many states over the past several years

– American Legislative Exchange Council (ALEC) developed model legislation to repeal state RPS laws – None of those bills have thus far passed

• Other legislation has sought revisions that would “weaken”

RPS policies (e.g., by expanding eligibility for large/existing hydro)

• Legal issues also raised in court cases & regulatory proceedings

– Commerce Clause issues, often tied to geographic eligibility rules (MA, MI, CO, CA, MO, MN) – Challenges to the jurisdictional authority of the PUC to enact an RPS (AZ)

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Given Uncertainly in Future Costs, Cost Caps of Various Designs are Common

1) ACP with automatic cost recovery: MA, ME, NH, NJ, RI 2) ACP with possible cost recovery: DC, DE, MD, OR 3) Retail rate / revenue requirement cap: CO, KS, IL, MD, MO, NM, OH, OR, WA 4) Renewable energy contract price cap: MT, NM 5) Per-customer cost cap: MI, NC, NM 6) Renewable energy fund cap: NY 7) Financial penalty may serve as cost cap: CT, HI, OH, PA, TX

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Emerging cost-containment issues

• Standardizing definitions and methodologies

– How to define net costs (Costs/benefits to whom? What benefits to “net” out? What costs to count?) – Data availability and transparency – Calculating incremental costs with bundled RE contracts

• Drivers for RPS costs going forward

– Growth in RPS targets (set-aside targets especially) – RE technology costs – Gas prices

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