Ramping up Renewables: Leveraging State RPS Programs amid Uncertain Federal Support

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1 Ramping up Renewables: Leveraging State RPS Programs amid Uncertain Federal Support Executive Summary America now generates more kilowatt-hours of renewable energy than any other country in the world. In addition to creating jobs and bettering the environment, zero-fuel cost renewable generation provides a critical hedge against future increases in fossil fuel prices. Having been growing robustly for over a decade, however, renewable energy in America now faces some major headwinds. While federal incentives such as the Production and Investment Tax Credits have bolstered the supply of renewable energy, support for renewable energy demand has come chiefly from states in the form of Renewable Portfolio Standard (RPS) mandates for utilities to procure minimum amounts of electricity from renewables sources. Currently in place in 29 states (and Washington DC), RPS mandates have driven creation of 1/3 of current US non-hydro renewable electricity. Curtailment of federal incentives would leave RPS mandates as the chief medium-term driver of new investment in renewable energy. This paper finds, however, that annual new renewable generating capacity needed to meet RPS mandates through 2030 amounts to 3.25 gigawatts (GW) for 61.5 GW of new generating capacity in total; this level of RPS demand pull is slightly below its average level for and is equal to only roughly 1/3 of total new US renewable generating capacity in 2011 (9 GW) - which was supported on the supply side by federal incentives. Hence, going forward RPS programs will continue to make a valuable but limited contribution to deployment of new renewable generating capacity in the US. Increasing cost-competitiveness with conventional generating capacity and remaining incentives should enable continued deployment of renewables in line with RPS demand pull. Without new or expanded RPS targets, however, RPS-driven demand will level off suggesting that policy support for investment in renewable energy will be stagnating just as America s need for the energy diversity and security benefits of renewable energy is increasing (due to investment in new gas-fired generation and rising exposure to volatile fossil fuel prices). To diversify America s energy mix and hedge against uncertainty in the price of fossil fuels (in particular natural gas), state policymakers can increase long-term support for renewable energy demand. Measures such as strengthening existing RPS targets, procuring more renewable electricity from large-scale projects through reverse auctions 1, and introducing additional incentives such as CLEAN (Clean Local Energy Accessible Now) programs, feed-in tariffs, and performance-based incentive rebates can increase such support for renewable energy. Provided that they protect the energy diversity benefits of distributed generation, policies to broaden interstate trade in Renewable Energy Credits (RECs) may be another option to consider. Sustaining robust deployment of renewables will also require access to capital to support the required level of private investment. Particularly given recent stresses in financial markets, existing tax policies are essential to support new investment in the renewable energy sector. In 1 For more detailed discussion of reverse auction mechanisms (RAMs), see Appendix V. 1

2 the shorter term, those policies include the Production Tax Credit and Investment Tax Credit. 2 Going forward, consideration can be given to how to best coordinate transitional, supplyfocused federal tax incentives with longer-term, demand-focused RPS programs as part of an integrated renewable energy strategy for America. 2 The Production Tax Credit is set to expire at year-end For more discussion, see our companion US PREF paper Clean Energy and Tax Reform. 2

3 Introduction Diversified and hedged energy system Renewable energy in the US has been booming. In 2011 the US generated nearly 5 percent of its electricity from non-hydro renewable sources up from less than 2 percent in Over the last decade the number of states generating more than 5 percent of their electricity from non-hydro renewable sources has quadrupled from five states in 2001 to 20 states in As a result of this growth, in absolute terms the US now leads the world in generation of electricity from non-hydro renewable sources. 4 The US has seen massive increases in both wind power (with annual wind electricity generation increasing 17X since 2001) and solar power (with annual new installed solar PV capacity increasing 20X since 2008). Over just the past five years, deployment of renewable generating technologies has attracted over $100 billion of new investment. 5 Increased US deployment has helped to accelerate dramatic reductions in the cost of solar PV and other renewable generation technologies. 6 Figure 1 Non-hydroelectric renewable share of total net generation by state Source: Energy Information Administration (EIA), 2012 The benefits of deploying renewable energy sources include jobs for American workers 7, a cleaner and healthier environment, and, especially by reducing exposure to volatile fossil fuel prices - a more diverse and secure US energy supply. Key facts about the US power sector make the energy security dimension of renewable energy particularly valuable. America now generates roughly 65% of its electricity from coal and natural gas. 8 Dependence of the US power sector on fossil fuels will continue 3 Non-hydro renewable sources include wind power, solar PV, solar thermal, biomass, and geothermal. US Energy Information Administration (EIA), Electric Power Annual and Electric Power Monthly, March 2012, based on preliminary 2011 data. 4 The US produces about 70% more than Germany, the next largest non-hydro renewable electricity producer. EIA, May Bloomberg New Energy Finance (BNEF), May Among other causes, such cost reductions have come as a result of economies of scale in production and learning-by-doing that facilitates technological progress. 7 See DB Climate Change Advisers paper, Repowering America: Creating Jobs, October 10, 2011, 8 EIA, Form EIA-906, Power Plant Report, March

4 as a result of America s latest dash to gas over half of planned new electricity generating capacity through 2015 is gas-fired. 9 Because fuel accounts for more than 50% of the cost of electricity from coal and gas-fired generation, 10 these investments risk increasing America s vulnerability to fuel-price shocks just as new sources of demand (from the industrial, transportation, and export sectors) threaten to ratchet the price of natural gas upward. By diminishing the need for new fossil generation, deploying low to zero-fuel cost renewable resources provides a hedge against future increases in the price of fossil fuels. 11 Hedging against fossil fuel price shocks is a compelling reason to ensure sustained investment in developing domestic renewable energy sources. 12 Moreover, the decline in the costs of renewable energy technologies continues to enlarge the scope of feasible near-term investment in US renewable energy. Figure 2 Planned Generating Capacity Additions from New Generators by Energy Source, ,000 25,000 26,462 20,000 MW 15,000 10,000 7,280 7,709 5,000 5,150 1,270 0 Coal Natural Gas Nuclear Wind Solar (PV and CSP) Sources: EIA, DBCCA analysis, 2012 Federal and state policies have been instrumental in enabling America to realize the benefits of clean energy. On the supply side, incentives such as the Production Tax Credit, Investment Tax Credit, and 1603 Treasury Cash Grant program have helped to attract capital into the sector. On the demand side, 9 This is largely because the capital costs of new gas-fired combined-cycle units are 30-50% lower than those of new coal-fired units. For comparison of the economics of new gas and coal-fired units, see DB Climate Change Advisers paper, Natural Gas and Renewables: the Coal to Gas and Renewables Switch is on!, October 10, 2011, 10 According to the Lazard Capital Markets June 2012 Levelized Cost of Energy Model 6.0, fuel accounts for 51% of the levelized cost of energy from a coal-fired plant and 66% of the levelized cost of energy from a combined-cycle natural gas plant versus 0% for solar and wind power generating plant. 11 For more detail, see R. Wiser et al., The Hedge Value of Renewable Energy, Lawrence Berkeley National Laboratory, For more detail, see the companion US PREF paper Clean Energy and Tax Reform. 4

5 state-level Renewable Portfolio Standards (RPS) that require utilities to procure minimum percentages of electricity from renewables sources 13 the focus of this paper have provided critical demand pull to promote deployment of new renewable generating capacity even amid sluggish growth in overall power demand. 14 Figure 3 Supply and Demand for Renewable Energy and Relevant Federal/State Policies Clean Energy Manufacturers Clean Energy Developers End Market: Clean Electricity Users Federal Government Programs: 48c Manufacturing Tax Credit EXPIRED at end /05 DOE Loan Guarantee Program EXPIRED in Currently a lack of federal policy support for renewable manufacturers Capital Equipment: (Wind turbines, PV solar cells, etc.) Cash Payment: (Made possible through project financing) Federal Government Programs: Investment Tax Credit for solar, valid through 2016 Production Tax Credit EXPIRES at end-2012 (wind) and end-2013 (other technologies) 1603 Cash Grant EXPIRED at end Soon to be a lack of federal policy support for renewable project developers (esp. wind) Clean Electricity: (Meets RPS demands) Investment Grade Cash Flows: (Provided by PPAs; critical for project financing) Federal & State Government Programs: Renewable Portfolio Standard present in most (29) states (and DC and PR) key tensions between RPS enforcement measures & cost caps Procurement by government entities Other Drivers: Overall economic attractiveness including supplyside policy drivers Federal Initiatives Under Discussion Clean Energy Deployment Administration ( CEDA ) Federal Initiatives Under Consideration: National transmission policy Transmission Federal Initiatives Under Consideration: Clean electricity standards ( CES ) Source: US PREF analysis Success in reaching RPS targets will hinge in part on greater amounts of capital formation and accessibility to private financing. Unfortunately, just as the national benefits of deploying renewable energy are set to increase, policies that have motivated significant levels of capital formation and private investment in renewable energy are set to plateau or decline. Combined with similar cuts to other programs, expiration of the 1603 Treasury cash grant program (at year-end 2011) and scheduled expiration of the Production Tax Credit for wind power (at year-end 2012) will reduce federal spending on renewables from $44 billion in 2009 to $11 billion in This creates substantial uncertainty in the near and medium-term outlook for renewable energy, which threatens continued US market momentum and ability to meet RPS targets. Retrenchment on the federal level will leave RPS mandates in 29 states as the chief medium-term policy driver for new investment in renewable energy. To examine what this means for the growth of renewable energy in the US, this paper proceeds in two sections. Section One introduces RPS policies, 13 Most RPS standards specify a minimum percentage of electricity that must be procured from renewable sources; Texas and Iowa, however, have capacity-based standards that simply require addition of a minimum amount (MW) of renewable generating capacity. For more detail, see the Database of State Incentives for Renewable Energy (DSIRE). 14 For more description of policies affecting the US power market, see Appendix I. 15 For detail on federal spending, see Beyond Boom and Bust: Putting Clean Tech on a Path to Subsidy Independence, Brooking Institution, April

6 describes their compliance and enforcement mechanisms, and projects RPS-driven demand for new renewable generation and capacity by state (or region) out to Section Two considers ways to cost-effectively amplify the demand pull from RPS programs such as increased RPS targets, bestpractice procurement mechanisms, and complementary supply-side tax incentives. SECTION ONE: CURRENT STATE OF RPS INITIATIVES A Renewable Portfolio Standard (RPS) is a state-level policy intended to increase the generation of electricity from renewable sources. Though no two states have exactly the same RPS program ability to tailor to state-specific conditions is one of the strengths of RPS policies - the core aspect of an RPS program is a mandate that electric utilities within a state must procure a minimum percentage or absolute amount of electricity from renewable sources by a specific date. 17 As of May 2012, 29 states (plus Washington DC) have enacted RPS programs that include such timebound mandates for procurement of renewable electricity (with an additional 7 states having enacted RPS policies that set voluntary goals for renewable electricity procurement). Such programs often include set-asides or carve-outs specifying minimum percentages of electricity to be generated from particular technologies; for example, the figure below illustrates RPS policies in 17 states to include setasides for solar PV. Figure 4 Renewable portfolio standards by state, listing the mandated % of electricity to be procured from renewables and the targeted date WA: 15% by 2020* OR: 25% by 2025 (large utilities)* 5% - 10% by 2025 (smaller utilities) NV: 25% by 2025* CA: 33% by 2020 UT: 20% by 2025* AZ: 15% by 2025 MT: 15% by 2015 ND: 10% by 2015 CO: 20% by 2020 (IOUs) 10% by 2020 (co-ops & large munis)* NM: 20% by 2020 (IOUs) 10% by 2020 (co-ops) MN: 25% by 2025 (Xcel: 30% by 2020) MI: 10% + 1,100 MW by 2015* VT: (1) RE meets any increase in retail sales by 2012; (2) 20% RE & CHP by 2017 SD: 10% by 2015 WI: Varies by utility; 10% by 2015 goal NY: 29% by 2015 IA: 105 MW OH: 25% by 2025 IL: 25% by 2025 WV: 25% by 2025* VA: 15% by 2025* KS: 20% by 2020 MO: 15% by 2021 NC: 12.5% by 2021 (IOUs) OK: 15% by % by 2018 (co-ops & munis) ME: 30% by 2000 New RE: 10% by 2017 NH: 23.8% by 2025 MA: 15% by % annual increase (Class I Renewables) RI: 16% by 2020 CT: 23% by 2020 PA: 18% by 2020 NJ: 22.5% by 2021 MD: 20% by 2022 DE: 20% by 2019* DC: 20% by 2020 PR: 20% by 2035 HI: 40% by 2030 State renewable portfolio standard State renewable portfolio goal Solar water heating eligible TX: 5,880 MW by 2015 Minimum solar or customer -sited requirement Extra credit for solar or customer -sited renewables * Includes separate tier of non-renewable alternative resources 29 states & DC & PR have an RPS 7 states have goals Source: US Database of State Incentives for Renewables and Efficiency, Goldman Sachs 16 These projections draw on data from Bloomberg New Energy Finance (BNEF) and Lawrence Berkeley National Laboratory (LBNL). 17 For more detail on the structure of an RPS regime, see Appendix II. 6

7 Summing across states (and, where necessary, excluding exempted entities), Figure 4 below shows that 50% of the total US electrical load currently has some form of RPS mandate with the RPS-covered share rising to 56% upon full implementation of all RPS standards. Figure 5 Percent of total US electrical load with active RPS mandates Note: Investor-owned utilities (IOUs), publicly-owned utilities (POUs), and energy service providers (ESPs) Source: The State of the States: Update on the Implementation of U.S. Renewable Portfolio Standards, Ryan H. Wiser and Galen Barbose, Lawrence Berkeley National Laboratory, 2011 National Summit on RPS, October 26, RPS as Strong Drivers of the Growth of US Renewable Generation Of the 200,000 gigawatt-hours (GWh) of US non-hydro renewable electricity in 2011, one-third represents new renewable electricity spurred by implementation of RPS mandates ( cumulative RPSdriven new GWh). In other words, this is renewable generation not in existence at the time a given state RPS mandate was passed, but that has since come into existence and is counted toward fulfilling the RPS mandate. Figure 6 below illustrates this portion. The figure below also illustrates cumulative RPS-supported GWh ; this includes generation that was in existence at the time a given state RPS mandate was passed, but whose continued existence has been supported by the need to fulfill the state s RPS mandate. Taking this pre-existing generation into account, cumulative RPS-supported GWh are equal to roughly two-thirds overall non-hydro renewable electricity in 2011 (i.e. 133,000 GWh). 7

8 Figure 6 Impact of RPS programs on growth of US renewable power supply, , , ,000 GWh 100,000 50, Cumulative RE GWh Cumulative RPS-supported GWh Cumulative RPS-driven new GWh Note: Cumulative RE GWh includes generation from wind, solar, biomass, and geothermal, but excludes conventional hydroelectric power. Cumulative RPS-driven new GWh refers to renewable generation not in existence at the time a given state RPS mandate was passed, but that has since come into existence and is counted toward fulfilling the RPS mandate. Cumulative RPS-supported GWh this includes generation that was in existence at the time a given state RPS mandate was passed, but whose continued existence has been supported by the need to fulfill the state s RPS mandate. Source: Lawrence Berkeley National Laboratory, DBCCA analysis, 2012 Given that RPS mandates have supported creation of new renewable electricity generation, they by definition have supported installation of new renewable electric generating capacity. The figure below demonstrates, for , the portion of total US new renewable generating capacity that was needed to meet RPS mandates for that year. From , new RPS-driven capacity averaged 3.5 GW per year while total new renewable capacity additions averaged 9.5 GW per year (in both cases, wind turbines accounted for the majority of new capacity added). Hence, from RPS demand pull accounted for 36% of total additions of new renewable generating capacity in the US; installation of the other 64% (i.e. 6 GW per year) reflects chiefly decreasing capital costs for renewable technologies and the impact of supply-side federal tax incentives such as the Production Tax Credit and Investment Tax Credit This calculation simplifies matters slightly, as some portion of the 6 GW per year reflects new capacity added to meet RPS mandates in future years. That said, willingness of developers to build capacity in advance of RPS obligations reflects in part the economic impact of federal tax incentives. As noted above, developers are eligible for such tax incentives irrespective of whether they are selling power/recs into RPS markets. 8

9 Figure 7 Impact of RPS programs on growth of US renewable generating capacity, GW annual new RE capacity annual new RPS-driven RE capacity Note: RE capacity figures includes generation wind, solar, biomass, and geothermal capacity, but excludes conventional hydroelectric capacity. Source: LBNL, DBCCA analysis, 2012 While the totals have been far smaller, RPS carve-outs for solar generation have been similarly strong drivers of the growth in solar generation and installation of new solar generating capacity. RPS-driven Incremental Demand for Renewable Electricity and Generating Capacity to 2030 RPS mandates should be thought of as providing a floor on deployment of new renewable generating capacity. In the absence of a national carbon price or clean energy standard, state-level RPS programs mandating that electric utilities procure minimum percentages of electricity from renewable sources by specific dates - will throughout the rest of the decade remain the chief policy driver of demand for renewable generation. Recognizing this raises questions such as (1) in states with RPS mandates, how much must generation of renewable electricity increase in order to satisfy RPS targets through 2030?; and (2) how much additional generating capacity must be built in order to enable this increase in generation? Mind the Gaps A state s RPS generation gap for a given year will be equal to the difference between its share of renewable generation for that year and the share of renewable generation needed to fulfill its ultimate RPS target. The figure below illustrates that, as of 2010, the size of such gaps varied from one percentage point in Pennsylvania to twenty percentage points in California. As RPS mandates have 9

10 ramped up over the past few years, however, utilities in the majority of states have recorded % compliance with RPS obligations. 19 Figure 8 Renewable generation as a % of retail electricity sales (2010) 33% 25% 24% 23% 20% Renewable generation Targeted renewable generation 13% 17% 10% 16% 15% 13% 12% 10% 5% 5% 9% 5% 2% 9% 9% 9% 8% 3% 1% 1% 0% 2% 10% 9% 8% 7% 1% 1% 3% 12% 9% 7% 6% 5% 8% 7% CA OR MN IL NY NH CT NJ HI NM CO NV UT MD DE DC RI MT WA MA MO AZ NC VA SD VT WI MI ME PA Note: Exemptions or lower mandates for certain utilities (e.g. publicly-owned municipal utilities and co-ops) and credit multipliers for certain classes of generation (i.e. 2X for in-state generation) will in many states reduce the actual RPS target below the figure shown above. As a result, the existing gap between renewable generation and the target level will be smaller than that shown above. Source: EIA, SNL, AWEA, Goldman Sachs Research estimates. Looking forward, the analysis below draws on projections from Bloomberg New Energy Finance (BNEF) and Lawrence Berkeley National Laboratory (LBNL). 20 Taking 2012 as a base year, the figure below depicts estimates from BNEF of the growth in renewable generation required for all states to meet their RPS targets through Since every state RPS program permits utilities to fulfill some portion of RPS obligations via imports of power and Renewable Energy Credits (RECs) from states within the same regional power market, in some cases the figures below aggregate state level estimates up to the level of the Regional Transmission Organization (RTO) or regional tracking system for trading of RECs. For each region contained in the BNEF projections, the table below lists the states with RPS programs within this RTO (excluding any state for which BNEF provides an individual state-level projection). Table 1 States within regional power markets or REC trading zones Region States with binding RPS programs PJM Delaware, Maryland, Michigan, New Jersey, Pennsylvania, and the District of Columbia (North Carolina excluded). ISO-NE Massachusetts, Rhode Island, New Hampshire, Connecticut, and Maine. M-RETS Iowa, Minnesota, Montana, North Dakota, Ohio, and Wisconsin (excludes Illinois). WREGIS Colorado, New Mexico, Oregon, Utah, and Washington (excludes California and Nevada). Source: DBCCA analysis For data on compliance by state in (and obligation for ), see Appendix III. 20 In the aggregate, figures from BNEF and LBNL are comparable to those from the Union of Concerned Scientists. 10

11 Surveying across states suggests that (1) achieving RPS targets through 2030 will require generating roughly 155,000 GWh of new renewable electricity, and (2) the need for new renewable electricity to meet RPS targets is allocated fairly broadly across California, the mid-atlantic, New England, and the Midwest. Figure 9 GWh gaps (as of 2012) incremental renewable electricity generation required for states to meet their RPS targets by ,000 35,000 30,000 25,000 35,843 27, RPS gap = 155,824 GWh 20,000 20,861 19,168 GWh 15,000 15,335 14,594 10,000 5,000-5,855 5,686 4,603 3,959 1, (5,000) (3,814) (10,000) Note: States/regions in green comprise 80% of total. For states with carve-outs just for solar, excludes generation needed to meet solar carve-out targets. PJM is a 13-state Regional Transmission Organization. ISO-NE is the Independent System Operator for New England. MRETS is the Midwest Renewable Energy Tracking System. WREGIS is the Western Renewable Energy Generation Information System. ERCOT is the Electric Reliability Council of Texas. Source: Bloomberg New Energy Finance, DBCCA analysis Solar carve-outs While most required incremental RPS generation can be met by one of several eligible technologies, in many states a portion of RPS mandates are carved out to support generation of electricity from particular technologies. The most common such carve-outs are for generation from solar power and/or from distributed generation (with rooftop solar PV being the most common distributed generation technology). 21 Drawing on data from Lawrence Berkeley National Laboratory, the figure below shows incremental generation needed to meet solar carve-outs in 17 states through 2030; the cumulative figure - 14,000 GWh is roughly equal to total estimated US solar-generated electricity in Just 21 States define such carve-outs differently with some states specifying just solar, others solar electric, others customer-sited distributed generation, and others customer-sited solar PV. 22 Due to additions of new solar electric generating capacity in excess of current-year solar carve-out requirements in years prior to 2012 (e.g. in Colorado and Arizona), the actual addition of new solar generation and generating capacity needed to meet solar carve-out targets through 2030 may be below LBNL projections. Hence, given 11

12 six states (shaded in yellow below) account for over 80% of the new solar generation needed to meet RPS carve-outs through Figure 10 Solar electricity generation needed to meet solar set-aside targets by state, ,000 6,000 5, solar carve-out gap = 14,984 GWh 5,000 4,000 GWh 3,000 2,000 1,962 1,704 1,404 1, NJ IL AZ MD OH PA CO NM DE MA DC NC MO NV NY OR NH Note: States in yellow comprise 80% of total. Addition of solar electricity generation in excess of RPS solar carve-out targets in years prior to 2012 may reduce required incremental solar generation through 2030 below the 14,984 GWh figure above. For states with carve-outs just for solar, amounts shown above are not reflected in the total renewable generation figures shown above. AZ, CO, NM, and NV assumed to meet some portion of required solar generation via concentrating solar power (CSP); all other states assumed to meet 100% of required solar generation through solar PV. Source: Lawrence Berkeley National Laboratory, DBCCA analysis 2012 National impact of RPS programs on generation of electricity from non-hydro renewables To put the above state-level figures in a national context, the figure below illustrates how closing the GWh gaps (inclusive of solar carve-outs) will increase total RPS-supported renewable generation from 3.6% of total US generation in 2012 to 7.9% in 2020 and 9.6% in Hence, over the two decades RPS mandates will enable a substantial but limited increase in generation of electricity from non-hydro renewables. current RPS mandates, the LBNL forecasts set an upper bound on the incremental new solar generation and solar generating capacity that RPS solar carve-outs will support. 23 Note that states with the most aggressive solar carve-out targets will not necessarily be the largest solar markets on a MW basis. While solar carve-outs have played a key role in driving deployment (particularly of solar PV), several other high-impact incentives for example net metering policies and the California Solar Initiative buy down rebate program have been enacted separately from RPS solar carve-outs. That said, a key contribution of solar carve-outs is to help solar PV lower supply chain costs and approach cost- competitiveness in states with unusually low retail electricity rates (e.g. Arizona). 12

13 Figure 11 Closing all RPS gaps increases total RPS-supported demand to 9.3% of total generation by % 4000 TWh % 3.6% % % 92.1% All other US generation Total RPS-supported demand Note: 1 TWh = 1000 GWh. Total RPS-supported demand includes demand to meet solar carve-outs. All other US generation includes non-hydro renewable generation not covered by RPS mandates which in 2012 will be ~2% of total US generation. Source: Bloomberg New Energy Finance, Lawrence Berkeley National Laboratory, EIA, DBCCA analysis 2012 The figure below compares the average annual increase in non-hydro renewable generation required to meet RPS targets through 2030 with the actual annual increase in non-hydro renewable generation in To meet RPS mandates through 2030, the US must increase generation of electricity from nonhydro renewables by 8,657 GWh per year over the next 18 years; this annual increase is equal to just one-third of the total (i.e. RPS-related and non-rps related) increase in generation of electricity from non-hydro renewables in 2011 (27, 820 GWh). The comparison shows that meeting RPS mandates through 2030 requires increasing generation of non-hydro renewable electricity each year by just onethird as much as non-hydro generation increased in Again, the conclusion is that on a national basis - RPS compliance will make only a moderate contribution to the growth of renewable electricity in the US. 13

14 Figure 12 Projected RPS-driven growth of RE and solar generation vs. total new generation in new US non-hydro renewable electricity generation 27,820 avg annual new renewable generation to meet RPS targets, * new solar electricity generation 602 avg annual new solar generation to meet RPS targets, GWh Note: Avg annual new renewable generation to meet RPS targets excludes generation needed to meet solar carve-outs. Source: Bloomberg New Energy Finance, Lawrence Berkeley National Laboratory, EIA, DBCCA analysis 2012 Building the Capacity to Close GWh Gaps Boosting the share of non-hydro renewables to meet RPS targets will require adding new wind, solar, biomass, and geothermal electric generating capacity. Inferring from above that closing America s collective RPS gap as of 2012 will require 155,824 GWh of extra renewable electricity, how many gigawatts (GW) of new capacity will be required to generate this extra electricity will depend on (1) the mix of technologies used to generate new renewable electricity; (2) the average net capacity factor 24 of new generation; (3) the impact of set-asides for particular technologies; and (4) at the level of an individual state or region, how much of each state s RPS gap can be met via imports of electricity from neighboring states. In forecasting required capacity, BNEF assumes a 33% average capacity factor similar to that of a US onshore wind farm (heretofore the dominant renewable generation technology in the US). BNEF also allows for states to meet their RPS requirements via imports of electricity from other states. Below are the BNEF estimates for the required additions of overall RE capacity to meet RPS targets (note that, for states with carve-outs just for solar, the estimates below omit capacity required to meet these solar carve-outs). 24 The net capacity factor of a power plant is the ratio of the actual output of a power plant over a period of time and its potential output if it had operated at full nameplate capacity the entire time. To calculate the capacity factor, take the total amount of energy the plant produced during a period of time and divide by the amount of energy the plant would have produced at full capacity. 14

15 Figure 13 New renewable capacity needed to meet RPS targets, RPS build = 48 GW GW CA PJM IL ISO-NE MRETS WREGIS NV NY AZ HI KS Note: States/regions in green comprise 80% of total. For states with carve-outs just for solar, excludes generation needed to meet solar carve-out targets. PJM is a 13-state Regional Transmission Organization. ISO-NE is the Independent System Operator for New England. MRETS is the Midwest Renewable Energy Tracking System. WREGIS is the Western Renewable Energy Generation Information System. ERCOT is the Electric Reliability Council of Texas. Source: Bloomberg New Energy Finance, DBCCA analysis Since carve-outs for distributed or solar generation must be met by a specific type of capacity (i.e. solar PV or, in some cases, CSP), the figure below draws on LBNL projections to illustrate required capacity additions to meet solar carve-outs through

16 Figure 14 New solar capacity needed to meet solar set-aside targets, solar carve-out build = 13.5 GW 5 4 GW NJ IL MD AZ OH PA DE CO MA DC NC NM NY MO NV NH OR Note: States in yellow comprise 80% of total. Addition of solar generating capacity in excess of RPS solar carve-out targets in years prior to 2012 may reduce required incremental solar generation through 2030 below the 13.5 GW figure above. Values converted from AC to DC assuming 77% conversion ratio. AZ, CO, NM, and NV assumed to meet some portion of required solar generation via concentrating solar power (CSP); all other states assumed to meet 100% of required solar generation through solar PV. Source: Lawrence Berkeley National Laboratory, DBCCA analysis 2012 National impact of RPS programs on additions of new renewable generating capacity The figure below (1) projects average annual additions of renewable and solar generating capacity needed to meet RPS targets and solar carve-outs from and (2) compares these projections with total new installations of renewable and solar generating capacity in The chief takeaway is that through 2030 RPS mandates will collectively support the addition of only 3.25 GW of new renewable generating capacity per year (with 0.7 GW of this total linked to satisfying solar carve-outs). 25 Compared with figure 6 above, this level of RPS-supported demand represents a decline from the level of RPSsupported demand during The secondary takeaway is that (including new capacity to fulfill solar carve-outs) average annual RPS-supported capacity additions through 2030 equal only onethird of total new renewable capacity added in This suggests that, going forward, RPS programs 25 The 3.25 GW figure reflects the sum of 2.55 GW per year of new renewable generating capacity to meet Tier 1 (i.e. non-technology specific) RPS targets (excluding solar carve-outs), and 0.7 GW per year of new solar generating capacity (mostly solar PV) to meet solar carve-outs. 26 While demand supported by solar carve-outs is projected to continue to grow after 2011, the sum of Tier 1 and solar-specific demand declines after As discussed below, since in many states solar installations have already begun to exceed carve-out minimum levels, for solar the more relevant number may be the level of RPSsupported demand for renewables overall, rather than for solar in particular. 16

17 will make a valuable but limited contribution to deployment of new renewable generating capacity in the US. Figure 15 Projected RPS-driven new additions RE and solar capacity vs. total new additions in Total New US RE Capacity 9.08 avg annual new RE capacity to meet RPS targets, 2012E-2020E* 2.8 avg annual new RE capacity to meet RPS targets, 2021E-2030E* Total New US Capacity (all solar PV) 1.79 avg annual new solar capacity to meet carve-outs, 2012E-2020E 0.82 avg annual new solar capacity to meet carve-outs, 2021E-2030E GW Note: *RE capacity figures exclude capacity needed to meet solar carve-out targets. RE capacity figures assume 33% capacity factor (similar to that of a US onshore wind farm). A portion of new solar capacity to meet carve-outs is projected to come in the form of concentrating solar power, rather than solar PV. Source: Bloomberg New Energy Finance, Lawrence Berkeley National Laboratory, DBCCA analysis Note that a plateau in RPS-driven demand particularly related to solar carve-outs does not mean that investment in such technologies will necessarily cease to grow. Increasing cost-competitiveness with conventional generating capacity combined with remaining incentives will enable continued deployment of renewables in line with RPS demand pull. In the case of solar in particular, continued declines in technology cost plus the continued availability of other incentives in many states (e.g. upfront rebates) suggest that in future years annual new additions of solar capacity will by no means be limited to 0.7 GW per year. That said, maxing out of solar carve-out (and consequent decline in the level of RPSrelated incentives) will in many states particularly those with below-average retail electricity rates deprive solar PV of enabling incentives before the technology has become fully cost-competitive with conventional electricity sources. This suggests that increasing the size of RPS targets (including related solar carve-outs) can ensure that solar PV continues to progress toward grid-competiveness throughout multiple regions of the US. The plateau in RPS-driven demand for renewables overall, however, does suggest that policy support for investment in renewable energy will be stagnating just as America s need for the energy diversity and security benefits of renewable energy are increasing as more new gas plants are built and so exposure to uncertain long term fossil prices will continue. That the plateau in RPS-driven demand will coincide 17

18 with scheduled expiration and reduction of key federal incentives makes the potential negative impact on growth of renewables particularly significant. How does an RPS Drive New Supply to Meet the Demand? The above section establishes that meeting RPS mandates through 2030 will require the addition of at least 3.25 GW of new renewable generating capacity per year (with at least 0.7 GW per year of this capacity coming in the form of solar chiefly solar PV generating capacity). Analysis now turns to the question of what mechanisms are available to promote creation of a new supply of renewable generating projects to meet this demand. Means of RPS Compliance Broadly speaking, there are three ways for a utility or unregulated distributor to comply with an RPS mandate: 1. Contract for the specified quantity of renewable electricity 2. In lieu of contracting for the delivery of actual electrons, purchase renewable energy credits (RECs) representing the specified quantity of renewable electricity 3. Purchase neither physical electricity nor RECs, and instead pay a $/MWh Alternative Compliance Payment (ACP) for each MWh needed to meet the RPS target Given their central role as a means of RPS compliance, it is worth examining further how supply and demand for RECs operates. Renewable Energy Credits To varying degrees, 27 states allow utilities and distributors to meet RPS obligations through purchases of Renewable Energy Credits (RECs). A REC is a tradable certificate that represents 1 MWh of qualified renewable energy generation; procuring and retiring a REC can demonstrate compliance with one or more RPS requirements. RECs can be either bundled or unbundled from the underlying renewable electricity. A REC that is packaged together with the underlying electricity in a power purchase agreement (PPA) between a renewable generator and a utility/distributor is considered to be bundled; a REC that is sold separately from the underlying electricity is considered to be unbundled. Whether a developer is compensated implicitly (via a higher PPA price) or explicitly (via offers into the REC market), revenue received from REC sales will supplement revenue received from federal incentives such as the Production Tax Credit and the Investment Tax Credit. A state s Alternative Compliance Payment (ACP) sets a de facto ceiling on the price that its utilities/distributors will be willing to pay for unbundled RECs. For non-technology specific RECs, ACP levels set a generalized ceiling of $50-$65/MWh (considerably lower in some states). High variability in REC prices across states reflects a combination of (1) variation in ACPs; (2) variation in demand for RECs as a means of demonstrating RPS compliance; and (3) various geographic or technology-specific eligibility requirements that limit interstate trade in RECs. As discussed below, if executed properly, minimizing barriers to interstate REC trades represents a highly promising route to lowering the cost of RPS compliance. 18

19 Figure 16 Compliance market (Tier 1) REC prices, Jan 2008 Dec 2011 Source: Spectron Group, 2012 Enforcement and Cost-Control How likely is it that states will meet RPS mandates? What distinguishes mandatory state RPS targets from merely voluntary or aspirational goals is that mandatory targets are (1) codified as legal obligations; and (2) backed by legal mechanisms that serve to encourage compliance. The table below lists the penalties that 12 states with significant RPS programs may levy against utilities whose procurement of renewable generation falls short of prescribed RPS levels. In eight of the states, utilities that in a given year fail to reach quantitative RPS targets incur a cost of $40-$50/MWh for every MWh by which they are short (and a significantly higher cost for every MWh by which they fall short of solar-specific targets); New Jersey, Maryland, and others formalize this cost in the regime of an Alternative Compliance Payment (ACP), while California and Arizona and Oregon empower their Public Utility Commissions (PUCs) to impose the fines. As a means of promoting compliance with RPS targets, however, the per-mwh fines provide roughly equivalent incentives across all four states. The magnitude of the fines is also significant for setting an upper bound on the premium utilities will be willing to pay to procure renewable generation (a topic discussed below). 19

20 Table 2 Compliance and Enforcement Mechanisms in 12 of the States with the Most Significant RPS Mandates Specified Monetary Penalties (2013 values) Additional Penalties that PUC may Impose State ACP $/MWH fine Suspend/Revoke License Additional Fines CA $50/MWh, up to $25MM per utility IL N/A N/A N/A N/A OH $45/MWH NJ $50/MWh x x MN WA $50/MWh x (not to exceed cost of needed RECs) MD $40/MWh x MA x x AZ PUC discretion OR x PUC discretion NC PUC discretion MO x x Note: Ohio, New Jersey, and Maryland also have separate Solar Alternative Compliance Payments (SACP) used specifically for compliance with solar carve-outs in those states. In Massachusetts and New Jersey utilities/distributors can automatically recover the cost of ACP payments in retail rates; Maryland and Oregon allow cost recovery only if the PUC deems ACPs to have been the least-cost compliance option. Ohio does not allow cost-recovery of ACPs. Washington and Arizona only in some cases allows the cost of discretionary penalties to be recovered in retail rates. Missouri and California do not allow automatic recovery of the cost of $/MWh fines. All columns N/A for Illinois because Illinois relies on a state administrative agency to procure renewables on behalf of the state s utilities. Source: DSIRE, Union of Concerned Scientists, LBNL DBCCA analysis 2012 Whereas per-mwh fines have a high probability of being imposed but a limited impact, the additional penalties outlined on the right-side of the above table are the reverse potentially very high-impact, but with an uncertain probability of being imposed. Legislation in New Jersey and Massachusetts empowers the PUCs in these states to penalize chronic RPS violators by prohibiting rate-based recovery of eventual compliance costs, barring a utility from accepting new customers or, in some cases, even suspending or revoking a utility s license to operate. While very forceful if implemented, assessing the bite of these measures is difficult since (1) implementation is at the discretion of the PUC; and (2) few cases have yet occurred to test a PUC s willingness to merit out such stiff penalties. The additional fines listed in the final column of the above table fall somewhere in between the two categories described above: potentially more severe than a $40-$50/MWh fine, but also more likely to be imposed than suspension or revocation of a utility s operating license. Vagueness as to the magnitude of these fines (except in Minnesota, where they cannot exceed the cost of purchasing needed RECs or procuring the needed amount of renewable energy), however - as well as a lack of cases demonstrating PUCs inclination or disinclination to impose them again complicates the task of assessing just how strongly they influence utilities attitude toward RPS compliance. Cost Caps Extending the reasoning that a utility s calculus for RPS compliance will reflect chiefly economic considerations, embedded in RPS legislation is frequently a state s calculus of how much it is willing to 20

21 invest to increase the generation of electricity from renewable resources. The two middle columns of the table below enumerate cost caps that, in eight of the twelve states, constrain the total dollar amounts to be spent on RPS compliance. Note that these caps apply to the incremental cost of complying with an RPS target that is, the cost of purchasing required renewable MWhs (or RECs) over and above the cost of purchasing an equivalent amount of non-renewable energy. 27 Such caps can apply either to costs for consumers or to retailers (as noted above, an ACP or prescribed per-mwh fine serves as a de facto cap on how much a retailer will spend on incremental RPS compliance). Seven states in the table below specify the precise level a cost cap should take (whether as a $/MWh amount, a per-account amount, or a percentage of the total electric bill); Arizona, on the other hand, leaves it to the discretion of its PUC to determine whether ratepayer surcharges in support of RPS compliance are just and reasonable. In all cases, however, these caps impose some threshold on the amount to be spent on renewable energy. Table 3 Cost-Containment Policies in 12 of the States with the Most Significant RPS Mandates Consumer Distributor State Ratepayer Surcharge de facto Cost Cap CA N/A N/A N/A Delay/Escape Clauses IL 2.015% of 2007 retail If annual cost cap is met or exceeded rate OH $45/MWh Caps compliance costs at 3% premium above cost of non-renewable electricity NJ $50/MWh MN WA MD MA ACP PUC discretion for two-year delay If incremental compliance costs exceed 4% of utility s annual retail revenue requirement If cost of purchasing non-solar Tier 1 RECs exceeds 8% of utility s annual electricity sale revenues in MD* AZ PUC discretion PUC discretion OR If incremental compliance costs exceed 4% of utility s annual retail revenue requirement NC $12.00/account Ratepayer surcharge cap; and PUC discretion MO 1% of average retail rate Note: All columns N/A for California because SB 2 (1X2), signed by California s governor in April 2011, eliminated the state s existing cost caps; new cost-containment mechanisms are in development and have not yet been enacted. In Maryland, there is a delay/escape clause for compliance with the state s solar carve-out if the cost of purchasing solar RECs exceeds 1% of utility s annual electricity sale revenues in MD. Source: DSIRE, LBNL, Union of Concerned Scientists, DBCCA analysis While states define incremental in different ways, there is some uniformity across states. Washington state s RPS statute, for example, defines the incremental cost of an eligible renewable resource is determined by calculating the difference between the levelized delivered cost of the eligible renewable resource, regardless of ownership, compared to the levelized delivered cost of an equivalent amount of reasonably available substitute resources that do not qualify as eligible renewable resources, where the resources being compared have the same contract length or facility life. 21

22 Cost-cap proceedings are currently underway (or set to begin shortly) in Ohio, New Mexico, Colorado and Arizona. While most observers expect existing RPS targets and compliance deadlines to emerge from these proceedings largely intact, they illustrate that achievement of RPS targets in contingent on staying within prescribed economic constraints. Delay/Escape Clauses By limiting the annual or marginal cost of RPS compliance, a cost cap may reduce the amount of renewable generation that a state procures in a given year - potentially delaying achievement of annual RPS targets. Illinois, North Carolina, and Missouri explicitly provide that, if a utility s actual or projected cost of meeting annual RPS targets exceeds the state cost cap (e.g. $12.00/residential account in North Carolina, or 2.015% of the 2007 residential rate in Illinois), the state PUC may lower the utility s annual RPS target to the level necessary to stay within the cost cap. While capping costs for the retailer rather than the consumer, Maryland, Oregon, Washington, and Ohio similarly empower their PUCs to reduce annual RPS obligations if compliance costs exceed prescribed thresholds. In Maryland the relevant threshold is a percentage of the cost of a state s annual electricity sale revenues in the state (e.g. 8% in 2013). Finally, while not prescribing specific thresholds, Minnesota and Arizona empower their PUCs to temporarily suspend RBS obligations should the cost of compliance exceed a just and reasonable level. The cost caps described above set an upper limit on the incremental cost of new renewable electricity to meet RPS targets. While examining the likelihood that every individual cost cap will prove binding is beyond the scope of this paper, 28 in general the costs of new renewable electricity are sufficiently below the caps embedded in RPS mandates that most states are highly likely to meet their RPS obligations and deadlines out to Evidence in support of this judgment comes from the success that several states wind-rich states (i.e. Texas, Iowa, Oregon) have had in either meeting their end-state RPS targets or complying with such targets well ahead of mandated deadlines. As declines in the cost of solar technologies broaden another means for cost-effective RPS compliance (already in wide use in California and other western states), the likelihood that states will meeting existing RPS targets without delay or interference only increases. SECTION TWO: WAYS TO MAKE RPS PROGRAMS MORE EFFECTIVE This paper has so far sought to establish that (1) in the aggregate, RPS mandates through 2030 will support 3.25 GW of new renewable generating capacity per year a valuable but limited amount; and (2) that given the incremental costs of RPS compliance and the mechanisms promoting compliance such mandates are highly likely to be fulfilled. To help America realize the full long-term economic, environmental and energy security benefits of renewable energy as well as the more immediate benefits of a vital US renewables industry there are multiple ways to ramp up and sustain support for renewable energy demand. Four promising measures to consider include: stronger RPS targets, best-practice procurement mechanisms, support for transmission development, and, potentially, broader interstate REC trading. 28 Given the broad latitude that many states accord to their PUCs in determining exactly what these levels are, this suggests that the robustness of a given RPS target depends largely on (1) the cost competitiveness of the state s renewable resources; and (2) how willing the state s PUC is to integrate RPS compliance into its traditional leastcost mandate. For more detail on potential outcomes for an RPS program, see Appendix IV. 22