MANAGING THE FUTURE OF THE ELECTRICITY GRID: DISTRIBUTED GENERATION AND NET METERING

Richard L. Revesz* and Burcin Unel**

INTRODUCTION ...... 2

I. HISTORY OF THE NET METERING DEBATE ...... 11 A. PURPA and Its Progeny...... 12 B. State Renewable Portfolio Standards ...... 17 C. Net Metering Policies ...... 21 D. Current State Reconsideration of Net Metering Policies ...... 27

II. EVALUATING THE CONTRIBUTIONS OF DISTRIBUTED GENERATION TO THE ELECTRIC GRID ...... 33 A. Benefits of Distributed Generation ...... 33 B. Costs ...... 34

III. CONSIDERING THE SOCIAL BENEFITS OF DISTRIBUTED GENERATION ...... 38 A. Incorporating Climate Change Benefits ...... 40 1. Quantifying Avoided Emissions ...... 41 2. Valuing Avoided Emissions: the Social Cost of Carbon ...... 42 3. Interaction with other Regulatory Approaches ...... 43 B. Other Social Benefits ...... 49 1. Conventional Pollutants ...... 49 2. Other Environmental Benefits ...... 49 3. Social Resiliency Benefits ...... 50

IV. EVALUATING CURRENT PRICING APPROACHES ...... 50 A. Net Metering ...... 50 1. Shortcomings of Having a Bundled Flat Volumetric Rate Underlying Net Metering ...... 53 2. Temporal Variations and Production and Transmission Constraints ...... 55 3. Demand Variations and Distribution Constraints ...... 56 B. Fixed Charges ...... 57

* Lawrence King Professor of Law and Dean Emeritus, New York University School of Law. The generous financial support of the Filomen D’Agostino and Max E. Greenberg Fund at NYU Law School is grateful acknowledged. Paul‐ Gabriel Morales and Nathan Taylor provided exceptional research assistance. ** Senior Economist, Institute of Policy Integrity, New York University School of Law

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C. Caps of Various Kinds: Not Carrying Forward Credits, Percentage Constraints ...... 58

V. TOWARD AN AVOIDED COST/SOCIAL BENEFIT APPROACH TO PRICING ...... 59 A. Identifying the Socially Optimal Approach ...... 59 B. Legal Basis and State Practice ...... 61 1. FERC Regulation and Decisions ...... 61 2. State Approaches to Avoided Cost Rates ...... 64 3. State Approaches to Incorporating Social & Environmental Benefits ...... 67 4. Historical Antecedents ...... 70

VI. THE PROMISE OF TIME‐ AND DEMAND‐VARIANT PRICING ...... 71 A. Valuing Distributed Generation with Time‐ and Demand‐Variant Pricing ...... 74 B. Incorporating Externalities into Dynamic Pricing ...... 77

CONCLUSION ...... 78

INTRODUCTION

“Distributed generation” is a term used to describe electricity that is produced, typically in some quantities, at or near the location where it is used.1 Distributed generation systems can rely on a variety of energy sources, such as solar, wind, fuel cells, and combined heat and power.2 Distributed solar energy is produced by photovoltaic cells, popularly referred to as solar panels, which can be placed on rooftops or mounted on the ground. 3 Over 90% of the current distributed generation in the United States is solar,4 and the number of installations is increasing rapidly.5 For example, in the state of New York, solar generation has grown 300 percent between 2011 and 2014.6

1 Distributed Solar, SOLAR ENERGY INDUS.INDUSTRIES ASS'N, http://www.seia.org/policy/distributed‐solar (last visited Aug. 20, 2015). 2 AM. PUB. POWER ASS'N, DISTRIBUTED GENERATION: AN OVERVIEW OF RECENT POLICY AND MARKET DEVELOPMENTS 3 (2013), available at http://www.publicpower.org/files/PDFs/Distributed%20Generation‐ Nov2013.pdf.http://www.publicpower.org/files/PDFs/Distributed%20Generation‐Nov2013.pdf. 3 Id., at 20. 4 See Id.., at 17‐18. 5 INTERSTATE RENEWABLE ENERGY COUNCIL, TRENDS SHAPING OUR CLEAN ENERGY FUTURE 25 (2014), available at http://www.irecusa.org/2014/10/trends‐shaping‐our‐clean‐energy‐future‐2014/. 6 Press Release, N.Y. State Energy Research and Development Auth., Governor Cuomo Announces Solar Growth of More Than 300 Percent from 2011 to 2014 in New York State (July 6, 2015), http://www.nyserda.ny.gov/About/Newsroom/2015‐Announcements/2015‐07‐06‐Governor‐Announces‐Solar‐ Growth‐of‐More‐than‐300‐Percent.

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Some distributed generation systems are isolated, in that they are not connected to a utility’s power grid, but most are “grid‐tied,” which means that they are connected to the grid.7 Customers with connected distributed generation systems can buy power from their electric utility when they are not producing enough electricity to meet their needs and can also sell power back to the utility company when their systems are producing more electricity than they need.8 This possibility raises the important question of how these customers should be compensated for the electricity they send to the grid.

That question has two critically significant policy implications. First, it plays a key role in determining the economic feasibility of clean electricity relative to electricity produced by fossil fuels. Unlike electricity produced from solar, wind, or hydro sources, electricity produced from fossil fuels gives rise to large quantities of both pollutants that affect public health and of greenhouse gases that lead to climate change.9 Second, distributed generation has benefits for the resiliency of the electric grid, by providing a more diversified portfolio of energy sources than would a scheme that relied exclusively on electricity produced by large power plants.10 The serious electric outage in New York City during Superstorm Sandy, which caused enormous economic dislocations, provides a telling example of the negative consequences of the lack of diversification.11

President Obama’s energy policy initiatives seek to accelerate the nationwide deployment of clean energy, such as solar power.12 For example, the Obama Administration recently announced that it had secured more than $4 billion in private sector commitments through its Clean Energy Investment Initiative aimed at the long‐term investment in clean energy innovation such as smart grid infrastructure and advanced battery solutions.13 Moreover, in August 2015, President Obama announced an additional

7 Today, over ninety‐five percent of solar installations are grid tied. Net Metering, SUNLIGHT ELECTRIC, http://www.sunlightelectric.com/netmetering.php (last visited July, 20, 2014). 8 EDISON ELEC. INST., Policy Brief: Straight Talk About Net Metering 1‐2, available at http://www.eei.org/issuesandpolicy/generation/NetMetering/Documents/Straight%20Talk%20About%20Net%Me tering.pdf (last visited July 20, 2015) [hereinafter Straight Talk]. 9 U.S. EPA, SOURCES OF GREENHOUSE GAS EMISSIONS, http://www.epa.gov/climatechange/ghgemissions/sources/electricity.html (last visited July 29, 2015) (noting coal combustion represents 39% of electricity generation but 77% of CO2 emissions from electricity generation sector). 10 DEVI GLICK, ET AL., ROCKY MOUNTAIN INSTITUTE, RATE DESIGNRATE DESIGN FOR THE DISTRIBUTION EDGEEDGE: ELECTRICITY PRICINGPRICING FOR A DISTRIBUTED RESOURCE FUTURE 16 (2014).) 11 PETER FOX‐PENNER, BRATTLE GROUP, PUBLIC POWER IN THE AGE OF SMART POWER 13 (2014).) 12 See U.S. DEPT. OF ENERGY, SUNSHOT VISION STUDY (2012) available at energy.gov/sites/prod/files/SunShot%20Vision%20Study.pdf. 13 See, e.g., Press Release, White House, Administration Announces New Initiative to Increase Solar Access for All Americans (July 7, 2015), https://www.whitehouse.gov/the‐press‐office/2015/07/07/fact‐sheet‐administration‐ announces‐new‐initiative‐increase‐solar‐access; Press Release, White House, Obama Administration Announces More Than $4 Billion in Private Sector Commitments and Executive Actions to Scale up Investment in Clean Energy

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$1 billion in loan guarantees for distributed generation projects, particularly residential solar projects, and $24 million in new grants for solar research and measures to reduce costs for homeowners looking to install solar panels.14 As a result, creating the right incentives for distributed generation is increasingly important. These incentives are affected by a variety of government policies, such as tax subsidies for renewables15 and tax preferred financing mechanisms that favor fossil fuels.16 This Article focuses on the pricing for distributed generation because it is the incentive that is currently receiving the most attention and scrutiny.17

The most commonly used—though increasingly attacked—approach to setting such a price is by reference to net metering.18 Under this approach, the utility customer’s meter runs forward when the customer needs more power than she produces, and the meter runs backward when she produces more power than she needs and sends the excess power back to the grid.19 At the end of the billing period, the customer is billed at the retail electricity rate – which is the volumetric rate a residential customer pays per kilowatt‐hour (kWh) of electricity usage – for the net power used.20 Thus, in effect, net metering policies pay distributed generation suppliers at the retail rate for their excess generation.21

Innovation (June 15, 2015), https://www.whitehouse.gov/the‐press‐office/2015/06/16/fact‐sheet‐obama‐ administration‐announces‐more‐4‐billion‐private‐sector. 14 Statement & Release, The White House, Fact Sheet: President Obama Announces New Actions to Bring Renewable Energy and Energy Efficiency to Households Across the Country (Aug. 24, 2015), https://www.whitehouse.gov/the‐press‐office/2015/08/24/fact‐sheet‐president‐obama‐announces‐new‐actions‐ bring‐renewable‐energy. Accord President Barack Obama, Remarks at National Clean Energy Summit (Aug. 24, 2014) (“[W]e’re going to make it even easier for individual homeowners to put solar panels on their roof with no upfront cost.”); Gardiner Harris, Obama Flies to the Nevada Desert to Promote Solar Energy, N.Y. TIMES, Aug. 24, 2015, http://www.nytimes.com/2015/08/25/us/obama‐solar‐power‐renewable‐energy.html. 15 See U.S. ENERGY INFO.INFORMATION ADMIN., U.S. DEP’T ENERGY, DIRECT FED. FIN.FEDERAL FINANCIAL INTERVENTIONS &AND SUBSIDIES IN ENERGY IN FISCAL YEAR 2013 (Mar. 2015), available at http://www.eia.gov/analysis/requests/subsidy/pdf/subsidy.pdf. 16 See Felix Mormann & Dan Reicher, Smarter Finance for Cleaner Energy: Open Up Master Limited Partnerships (MLPs) and Real Estate Investment Trusts (REITs) to Renewable Energy Investment (Nov. 2012), available at http://www.brookings.edu/~/media/research/files/papers/2012/11/13%20federalism/13%20clean%20energy%20 investment.pdf; cf.http://www.brookings.edu/~/media/research/files/papers/2012/11/13%20federalism/13%20clean%20energy% 20investment.pdf; cf. also Master Limited Partnerships Parity Act, S. 1656, 114th Cong. (2015) (allowing renewable energy projects to access tax preferred financing mechanisms currently widely used by fossil energy projects). 17 See, e.g., Straight Talk, supra note 8 (laying out electric industry arguments against net metering). 18 Id. See, e.g., Straight Talk, supra note 8 (laying out electric industry arguments against net metering). 19 Id. at 1. Straight Talk, supra note 8, at 1. 20 Id. at 2. 21 NAÏM R. DARGHOUTH, ET AL, LAWRENCE BERKELEY NAT'L LAB., LBNL‐ 183185, NET METERING AND MARKET FEEDBACK LOOPS: EXPLORING THE IMPACT OF RETAIL RATE DESIGN ON DISTRIBUTED PV DEPLOYMENT 1 (2015), available at http://emp.lbl.gov/sites/all/files/lbnl‐183185_0.pdf.

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As of March 2015, forty‐four states and the District of Columbia compensated utility customers for the power that they put into the grid through distributed generation.22 Even though these policies are typically grouped under a common net metering rubric,23 in practice there are significant variations among them.24 Many jurisdictions employ a traditional net metering scheme, under which most purchases from and sales to the grid take place at the same price.25 Some jurisdictions set a separate price for the distributed generation, which means that a customer’s purchases from and sales to the grid are not governed by the same price.26 For example, in some states, utilities credit excess generation at rates that are lower than the retail rates.27 These lower rates are typically based on a utility’s “avoided cost,” which is the cost the utility would have incurred if it had to provide one more unit of electricity itself.28 Similarly, other jurisdictions impose special charges, such as standby charges, on their net

22 The only states that do not offer statewide net metering are Alabama, Idaho, Mississippi, South Dakota, Tennessee, and Texas. Best Practices in State Net Metering Policies and Interconnection Procedures, FREEING THE GRID, 95 (2013), http://www.freeingthegrid.org [hereinafter Best Practices]; see also BENJAMIN INSKEEP, ET AL, N.C. CLEAN ENERGY TECH. CTR., THE 50 STATES OF SOLAR (Feb. 2015) available at http://nccleantech.ncsu.edu/wp‐ content/uploads/The‐50‐States‐of‐Solar_FINAL.pdf2015) available at http://nccleantech.ncsu.edu/wp‐ content/uploads/The‐50‐States‐of‐Solar_FINAL.pdf [hereinafter "50 States Q4 2014"]; N.C. CLEAN ENERGY TECH. CTR., THE 50 STATES OF SOLAR (April 2015), available at http://nccleantech.ncsu.edu/wp‐content/uploads/50‐States‐of‐ Solar‐Issue2‐Q2‐2015‐FINAL3.pdf, [hereinafter "50 States Q1 2015"]. Though not a state‐initiated program, Alabama, Mississippi and Tennessee all offer feed‐in tariff compensation, discussed infra p. 28, through the Tennessee Valley Authority utility. Energy Info. Admin., U.S. Dep’t Energy, Feed‐in Tariffs & Similar Programs (June 4, 2013) [hereinafter EIA, Feed‐in Tariffs & Similar Programs], http://www.eia.gov/electricity/policies/provider_programs.cfm. The city of Austin, Texas, offers compensation through a “value‐of‐solar” program, discussed infra p. 29. News, Austin Energy, New Value of Solar Rate Takes Effect January, (last accessed July 17, 2015), https://austinenergy.com/wps/portal/ae/about/news/press‐ releases/2013/new‐value‐of‐solar‐rate‐takes‐effect‐january/!ut/p/a1/jZBNT4NAEIZ_iweOy04Xq. 23 Two notable exceptions are Austin, TX and the state of Minnesota, both of which at least offer utilities the opportunity to pay a "value of solar" tariff for all power produced by distributed generators. See generally, THOMAS E. HOFF & BEN NORRIS, CLEAN POWER RESEARCH, 2014 VALUE OF SOLAR EXECUTIVE SUMMARY (2013) available at http://www.austintexas.gov/edims/document.cfm?id=202758 [hereinafter "Austin VOST"] (describing Austin's distributed generation valuation scheme); THOMAS E. HOFF & BEN NORRIS, CLEAN POWER RESEARCH; MINNESOTA VALUE OF SOLAR: METHODOLOGY (2014) [hereinafter "Minn. VOST"]; See also, Erin Carson, EnerKnol, Policy Brief, Solar Energy Compensation Arguments Intensify as Utilities Aim to Recover Fixed Costs 2 (Oct. 20, 2014). 24 See generally, Best Practices, supra note 24. 25 See Best Practices, supra note 24 (Listing 36 states as reconciling net excess generation at the retail rate). 26 Id. 27 LAURENCE D. KIRSCH, ET AL., CHRISTENSEN ASS’N ENERGY CONSULTING, LLC, PRICING RETAIL ELEC. IN A DISTRIBUTED ENERGY RESOURCES WORLD 9 (2015), available at http://www.caenergy.com/wp‐content/uploads/2015/01/Pricing‐Retail‐ Electricity‐150106.pdf. 28 As of 2014, Missouri, Nebraska, New Mexico, North Dakota and Rhode Island reconciled excess generation monthly at avoided cost rates. Best Practices, supra, note 21 at 64, 66, 72, 77, 85. Ohio credited net excess generation to customer’s next bill at the utility's unbundled generation rate. Id. at 78. In the past year, a number of states have moved toward reducing the rate paid for net excess generation to avoided cost. See, 50 States Q4 2015, supra note 21, 50 States Q1 2015, supra note 24.

5 metered customers.29 Recently, some jurisdictions have attempted to model the actual value of distributed generation, including full costs and benefits to the grid, health and environmental benefits, and other factors, to allow the price paid to customer‐generators to be a separate "Value‐of‐Solar Tariff (VoST)" rather than either the retail or avoided cost rate.30 The few jurisdictions to attempt this approach have found the "value of solar" higher than the retail rate for grid‐supplied energy produced by burning fossil fuels.31 In this Article, we use the term “net metering” to refer to the practice of compensating distributed generation customers at the retail price, which remains the most common practice.32

But even with respect to such traditional net metering, there are important variations.33 Some states zero out all of a customer’s credits at the end of a billing cycle so that the customers cannot use the credits they earn in one month to offset their net consumption in another month.34 Other states do the same after twelve months, thereby allowing customers to use credits earned in one month to offset consumption within one year.35 The latter practice leads to very low electricity bills for customers that own large photovoltaic systems.36 For example, schools in California use the credits they earn during the summer months to offset their consumption during the school year resulting in very low bills and,

29 See Best Practices, supra note 21, at 72, 93 (describing New Mexico's approval of standby charges potentially high enough to exceed a customer's net excess generation, and Virginia's standby charges once a system exceeds a relatively small size); see also 50 States Q4 2015, supra note 22, at 17 (describing Nevada PUC's recommendation to the legislature to allow utilities to assess standby charges). 30 See, generally, ENERGY INFO. ADMIN., DIRECT FEDERAL FINANCIAL INTERVENTIONS AND SUBSIDIES IN ENERGY IN FISCAL YEAR 2013, supra note 14. See supra note 23. 31 Compare Austin VOST, supra note 25, and Minn. VOST, supra note 25, with Residential Rates, AUSTIN ENERGY, www.rates.autinenergy.comwww.rates.autinenergy.com (last visited July 20, 2015) (showing residential rates significantly below the VOST for most tiers), and NORTHERN STATES POWER COMPANY, MINNESOTA ELECTRIC RATE BOOK – MPUC NO. 2 at 5‐1 (2013). But see John Farrell, Could Minnesota’s “Value of Solar” Make Everyone a Winner?, INST. SELF‐RELIANCE (Mar. 13, 2014), http://www.ilsr.org/minnesotas‐value‐solar‐winner/ (concluding cumulative value of payments over a 25 year period under Minnesota’s value‐of‐solar program would be $3,000 less than under retail rate net metering for equivalent electric production2 at 5‐1 (2013). 32 See FELIX MORMANN & DAN REICHER, BROOKINGS, SMARTER FINANCE FOR CLEANER ENERGY: OPEN UP MASTER LTD. P’SHIPS (MLPS) AND REAL ESTATE INV. TRUSTS (REITS) TO RENEWABLE ENERGY INVESTMENT (Nov. 2012), available at http://www.brookings.edu/~/media/research/files/papers/2012/11/13%20federalism/13%20clean%20energy%20 investment.pdf; cf. Master Limited Partnerships Parity Act, S. 1656, 114th Cong. (2015) (allowing renewable energy projects to access tax preferred financing mechanisms currently widely used by fossil enery projects). See supra note 25. 33 See generally, Best Practices, supra note 24. 34 See, Best Practices, supra note 24, at 73 (noting North Dakota zero’s out consumer generation at the end of each monthly billing cycle). 35 A number of states grant credits back to the utility at the end of a twelve‐month billing period. See, Best Practices, supra note 21, at 30, 44, 46, 41, 64, 76, 86, 91, 95 (describing this practice in Arkansas, Hawaii, Illinois, Kansas, Maine, Missouri, Montana, North and South Carolina, Utah, and Washington). 36 Cherrelle Ei et al., The Economic Effect of Electricity Net‐Metering with Solar PV, 75 ENERGY POLICY 244, 247 (2014).

6 correspondingly, a significant financial impact for the utilities.37 Some states allow customers to keep credits at the end of a billing year but reduce the rate at which they are credited, whereas others allow the customers to rollover the credits indefinitely without imposing any financial penalty.38

Moreover, some states place limits on the amount of electricity for which a customer can get net metering credit. Some states set these limits as a percentage of that customer’s energy consumption the prior year;39 if net metering customers exceed this limit they are considered "merchant generators" and become ineligible for net metering.40 Other states cap the total aggregate capacity eligible for net metering, typically expressing this constraint set as a percentage of a utility’s peak or average energy demands.41 .

Even though net metering has recently moved to the spotlight, it is not a new concept. Idaho, Arizona, and Massachusetts adopted net metering policies in the 1980s.42 By 1998, 21 states had such policies.43 But until recently, the volume of distributed generation initially was relatively low.44 In 2003, fewer than 7000 customers across all states participated in such programs.45 Over the next decade, the installation of residential solar panels, the number of net metered customers, and the volume of

37 Id. Cherrelle Ei et al., The Economic Effect of Electricity Net‐Metering with Solar PV, 75 ENERGY POLICY 244, 47 (2014). 38 Florida, Nebraska, and New Jersey reconcile excess generation at avoided‐cost rates at the end of a twelve‐ month billing period. Best Practices, supra note 24, at 41, 66, 71. Maryland reconciles excess annually at the utility’s wholesale rate. Id. at 57. 39 For example, Pennsylvania has a cap of 110% of prior consumption and Maryland has a 200% limit. COMMONWEALTH OF PA. PUB. UTIL. COMM’N, NET METERING‐ USE OF THIRD PARTY OPERATORS 7‐9, 17105‐3265 (2012). 40 See, e.g., id. 41 Aggregate capacity limits vary widely. Best Practices, supra note 24, at 15‐16. Some states, like Arizona and Colorado, have no limit on total program capacity. Id, at 29, 34. Georgia caps its net metering at only 0.2% of a utility’s peak demand. Id. at 43. Illinois and Indiana have caps of 1% of peak demand, id. at 46‐48, and California and Delaware have caps of 5%. Id at 32, 38. Rather than expressing an aggregate capacity limit as a percentage, Maryland’s aggregate capacity limit is fixed at 1,500 MW. Id. at 54. Similarly, New Hampshire’s aggregate capacity limit is 50 MW, id. at 65‐66, and Nevada’s aggregate capacity limit is 235MW. S.B. 374, 78th Leg. (Nev. 2015). Moreover, instead of limiting aggregate capacity on a per‐utility basis, the aggregate capacity limit in Maryland, New Hampshire, and Nevada are calculated on the number of net metered generators statewide. Best Practices, supra note 24, at 54, 65‐66. S.B. 374, 78th Leg. (Nev. 2015). 42 YIH‐HUEI WAN, NAT’L RENEWABLE ENERGY LAB., NREL/SP‐460‐21651, NET METERING PROGRAMS 3 (1996), available at http://www.nrel.gov/docs/legosti/old/21651.pdf. 43 See HENRY H. ROGERS II, ET AL., THE DATABASE OF STATE INCENTIVES FOR RENEWABLE ENERGY: STATE PROGRAMS AND REGULATORY POLICIES REPORT 3 (1998) available at http://ncsolarcen‐prod.s3.amazonaws.com/wp‐ content/uploads/2015/01/1998‐Rogers‐The‐Database‐of‐State....pdf. 44 J. HEETER, ET AL, NAT'L RENEWABLE ENERGY LABORATORY, 1NREL/TP‐6A20‐61858, STATUS OF NET METERING: ASSESSING THE POTENTIAL TO REACH PROGRAM CAPS (2014). 45 Id.;J. Heeter, et al, Nat'l Renewable Energy Laboratory, 1NREL/TP‐6A20‐61858, Status of Net Metering: Assessing the Potential to Reach Program Caps (2014), see also ENERGY INFO. ADMIN., U.S. DEP’T ENERGYInformation Administration, ELECTRIC POWER SALES, REVENUE, AND ENERGY EFFICIENCY FORM EIA‐861 DETAILED DATA FILESdetailed data files (2014) available at http://www.eia.gov/electricity/data/eia861/.

7 distributed generation grew at a rapid rate.46 By the end of 2014, utilities reported 600,000 residential net metering customers, 170,000 more than at the beginning of the year.47 The significance of this change was magnified by the slow but steady decline in household energy consumption during the same period, which further increased the relative importance of the revenues that utilities lost to net metered customers.48

As a result, utilities began to advocate for reconsideration of state net metering policies, urging state legislatures and public service commissions for special fixed charges for net metering customers and a buy‐back price below the retail price of electricity.49 In addition, many industry trade associations and conservative groups began to challenge net metering policies in different states, publishing issue briefs and calling for legislation designed to make distributed generation less attractive.50 Finally, high‐ profile detractors like Warren Buffett, whose Berkshire Hathaway Energy owns utilities across the United States, have further heightened the salience of the debate.51

46 TRENDS SHAPING OUR CLEAN ENERGY FUTURE, supra note 5, at 25. 47 ENERGY INFO. ADMIN., U.S. DEP’T ENERGY,,Information Administration, MONTHLY ELECTRIC UTILITY SALES AND REVENUE REPORT WITH STATE DISTRIBUTIONS (2014) available at http://www.eia.gov/electricity/data/eia826/ (providing raw data on number of net metering customers by utility each month). 48 See FOX‐PENNER supra, note 11,11 at 2. 49 See, e.g., PETER KIND, EDISON ELEC. INST., DISRUPTIVE CHALLENGES: FINANCIAL IMPLICATIONS AND STRATEGIC RESPONSES TO A CHANGING RETAIL ELECTRIC BUSINESS 18 (2013). See also SOLAR ENERGY INDUS. ASS’N, SOLAR MARKET INSIGHT REPORT: 2014 YEAR IN REVIEW (June 9, 2015). 50 An Institute of the Edison Foundation recently published an issue brief arguing that net metered customers need to pay more for their services in order to avoid cost‐shifting to other customers or other negative repercussions. See, generally, ROBERT BORLICK & LISA WOOD, EDISON FOUND., NET ENERGY METERING: SUBSIDY ISSUES AND REGULATORY SOLUTIONS (2014); The conservative organization American Legislative Exchange Council (ALEC) has also written anti‐net metering model legislation that it has urged states to adopt. Updating Net Metering Policies Resolution, AM. LEGISLATIVE EXCHANGE COUNCIL, http://www.alec.org/model‐legislation/updating‐net‐metering‐policies‐ resolution/ (last visited Aug. 5, 2014). This legislation calls for creation of a fixed grid charge or other mechanism to recover costs from distributed generation customers. Id. 51 For example, In July 2015, NV Energy, a subsidiary of Berkshire Hathaway Energy and the dominant utility in Nevada, petitioned Nevada’s Public Utility Commission to reduce the state’s current net metering rates from 11.6 cents per kilowatt hour to 5.5 cents per kilowatt hour. Application of Nevada Power Company d/b/a NV Energy For Approval of Cost Service Study and Net Metering Tariffs, Public Utilities Commission of Nevada, Docket No. 15‐ 07041, July 31, 2015, available at https://nvenergy.com/renewablesenvironment/solar/docs/NPC_NEM_Volume_1_complete.pdf. See also Sean Whaley, Nevada Power Proposes Trimming Credit for Net Metering, LAS VEGAS REVIEW‐JOURNAL, July 31, 2015, http://www.reviewjournal.com/business/energy/nevada‐power‐proposes‐trimming‐credit‐net‐metering. Similarly, MidAmerican Energy, also subsidiary of Berkshire Hathaway Energy, proposed in 2014 to replace net metering altogether. Brent Gale, Senior Vice President, MidAmerican Energy Holdings Co., Energy in the S.W., July 22, 2014, available at http://s3.amazonaws.com/dive_static/editorial/DG__NEM_Recommendations_‐ _Gale_Berskhire_Hathaway_Energy_‐_2014_Energy_in_the_SW_Conf.pdf.

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The hard‐fought debate between utilities and environmentalists, with strongly argued, diametrically opposite positions, has turned net metering into a central battleground in the debate over our nation’s energy future.52 This debate deals with the mirror image of the similarly pitched battle over President Obama’s Clean Power Plan, which limits the greenhouse gas emissions of fossil fuel fired power plants, primarily coal plants.53 Whereas the Clean Power Plan seeks to control the negative effects of fossil fuel fired power plants, primarily coal plants,54 net metering seeks to compensate producers of clean energy.55 Whereas the rhetoric over net metering has not yet reached the fevered intensity of the so‐called “war on coal,”56 which is very much part of the lexicon of the opponents to the Clean Power Plan, inflammatory language is not alien to debates over net metering.57

One goal of this Article is to evaluate the respective arguments. In this connection, we show that each side misses an important part of the problem, and that the competing positions lack nuance and do not provide a good basis for setting desirable policy on how to compensate residential producers of distributed energy.

Our second goal is to place the net metering debate in a broader context. Indeed, net metering reform should be considered alongside another much required reform in electricity policy, which involves the restructuring of retail electricity rates. Currently, almost all residential customers pay a constant per‐kWh energy consumption charge and a fixed customer charge that does not vary with consumption.58 The per‐kWh charges are almost always set to recover most of the system’s costs

52 OFFICE OF ENERGY POLICY & SYS. ANALYSIS, U.S. DEP’T ENERGY, QUADRENNIAL ENERGY REVIEW: ENERGY TRANSMISSION, STORAGE, AND DISTRIB. INFRASTRUCTURE 3‐18 (2015) [hereinafter QER], available at http://energy.gov/sites/prod/files/2015/07/f24/QER%20Full%20Report_TS%26D%20April%202015_0.pdf. 53 THE WHITEHOUSE, CLIMATE CHANGE & PRESIDENT OBAMA’S ACTION PLAN, https://www.whitehouse.gov/climate‐change (last visited July 30, 2015). 54 Id. 55 SOLAR ELEC. POWER ASS’N, Ratemaking, Solar Value and Solar Net Energy Metering—A Primer 25, 28 (2013), https://www.solarelectricpower.org/media/51299/sepa‐nem‐report‐0713‐print.pdf. 56 See RICHARD L. REVESZ & JACK LIENKE, STRUGGLING FOR CLEAN AIR: POWER PLANTS AND THE COAL WARS (forthcoming 2015). 57 Michael T. Burr, Reverse Robin Hood; Declaring War on Non‐Utility PV, PUB. UTIL. FORT. (July 13, 2013) ()(recounting a California debate during which a state senator described net metering as "robbin' the hood," to express his belief that lower income ratepayers were subsidizing wealthier solar owners); Charles E Bayless, Piggybacking on the Grid, PUB. UTIL. FORTNIGHTLY, (July 2015), http://www.fortnightly.com/fortnightly/2015/07/piggybacking‐ gridhttp://www.fortnightly.com/fortnightly/2015/07/piggybacking‐grid (likening net metering to an airline called "Piggyback Air," which travels by surreptitiously bolting its aircraft to the back of those of a competitor, "Sitting Duck Air."); see also, Tell Utilities Solar Won't be Killed (TUSK), DONTKILLSOLAR.COM (last visited, July 14, 2015) ("Monopoly utilities want to extinguish the independent rooftop solar market in America to protect their socialist control of how we get our electricity . . ."). 58 GLICK, ET AL., supra note 10, at 12.

9 including the substantial share of costs that are fixed in addition to the cost of generation electricity.59 Further, even though the cost of energy generation varies significantly by time, consumers pay the same constant per‐kWh rate at all times.60 These mismatches create the possibility of cost shifting among different customer groups when one group lowers its consumption during a particular time period for any reason, whether it is a result of distributed generation, energy efficiency, or personal preference.61 In addition, when utility companies have to depend on the volume of electricity usage to recover their fixed costs, their inherent incentive is to encourage energy use, contrary to society’s energy efficiency and energy conservation goals, and to resist any initiative that would reduce the consumer load such as rooftop solar programs.62 As a result, the resistance of utility companies to distributed generation is partly rooted in the inefficiencies of the current retail electricity rate design.63

To ensure that the most socially desirable policy is achieved, net metering policies should be designed simultaneously with retail electricity rates.64 Aligning the market price of electricity that is used at a particular time and location with the true marginal social cost of production—the private cost of producing one more unit of electricity plus the value of any associated externalities—leads to the market outcome that maximizes social welfare.65 It allows customers to take into account both the environmental consequences of their electricity consumption and the increased costs of energy during certain time periods when making decisions.66

59 WOOD & BORLICK, supra note 52, at 4. 60 AHMAD FARUQUI, ET AL., REGULATORY ASSISTANCE PROJECT, TIME‐VARYING & DYNAMIC RATE DESIGN 9 & n.7 (2012), available at file:///C:/Users/pgm291/Desktop/RAP_FaruquiHledikPalmer_TimeVaryingDynamicRateDesign_2012_JUL_23.pdf. 61 David Schmitt, Net Metering: Getting Beyond the Controversy, 2011 A.B.A. RECENT DEV. PUB. UTIL. COMM. & TRANSP. 417, 425, available at http://www.americanbar.org/content/dam/aba/migrated/2011_build/public_utility/netmetering_getting_beyond __the__controversy.authcheckdam.pdf. 62 Marilyn A. Brown & Sharon Chandler, Governing Confusion: How Statutes, Fiscal Policy, and Regulations Impede Clean Energy Technologies, 19 STAN. L. & POL'Y REV. 472, 485 (2008). 63 Id. 64 E.g., JAMES C. BONBRIGHT, PRINCIPLES OF PUBLIC UTILITY RATES 383‐84 (2nd ed. 1988). 65 Id. See also, e.g., JIM LAZAR, ET AL., REGULATORY ASSISTANCE PROJECT, PRICING DO’S & DON’TS: DESIGNING RETAIL RATES AS IF EFFICIENCY COUNTS (2011), available at file:///C:/Users/pgm291/Desktop/RAP_Lazar_PricingDosandDonts_2011_04.pdf. 66 See JIM LAZAR, REGULATORY ASSISTANCE PROJECT, RATE DESIGN WHERE ADVANCED METERING INFRASTRUCTURE HAS NOT BEEN FULLY DEPLOYED 7 (2013), available at file:///C:/Users/pgm291/Desktop/RAP_Lazar_RateDesignConventionalMeters_2013_APR_8%20(1).pdf. See also Michael, O’Boyle, An Adaptive Approach to Promote System Optimization 5 http://sepa51.org/submissions/submissions/Energy_Innovation_Summary.pdf (last visited July 30, 2015).

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The remainder of this Article is organized as follows. Part I summarizes the history of state net metering policies. Part II considers the contributions of distributed generation to the electric grid. Part III evaluates the social benefits of distributed generation. Part IV argues for a pricing approach that takes proper account of both contributions; this approach differs from net metering and is at odds with the positions on distributed generation of both utilities and environmentalists. Part V shows how decisions concerning net metering are affected by broader questions concerning the retail pricing of electricity.

I HISTORY OF THE NET METERING DEBATE

In 1978, less than one percent of electricity consumed in the United States was generated by solar or wind sources,67 and all but three percent came from utility‐owned, predominantly fossil fuel powered, generation plants.68 Yet, a combination of federal and state initiatives begun in that year would fundamentally restructure U.S. energy policy and usher in enormous growth of moderate‐ and small‐scale renewable sources of electrical generation.69 Federal legislative action in 1978 and succeeding decades altered the then‐prevailing views that monolithic and vertically integrated utilities were the only reliable or efficient means of electrical generation and prompted initial investment in renewable generation technologies.70 At the same time, state measures, importantly Renewable Portfolio Standards, encouraged the development of small‐scale and often residential renewable sources of generation, like rooftop solar panels and backyard wind turbines.71 As a result of both state and federal policy initiatives, net metered distributed generation has evolved into a significant, and growing, source of domestic energy production.72

67 BP p.l.c., Data Workbook – BP Statistical Review of World Energy 2014 (63d ed., June 2014), http://www.bp.com/en/global/corporate/about‐bp/energy‐economics/statistical‐review‐of‐world‐ energy/statistical‐review‐downloads.html. 68 U.S. ENERGY INFO. ADMIN., U.S. DEP’T ENERGY, THE CHANGING STRUCTURE OF THE ELEC. POWER INDUS.: 1970‐1991, at vii (1993), available at http://webapp1.dlib.indiana.edu/virtual_disk_library/index.cgi/4265704/FID3754/pdf/electric/0562.pdf. 69 Jeffrey S. Dennis, Twenty‐Five Years of Electricity Law, Policy, and Regulation: A Look Back, 25 NAT. RESOURCES & ENV'T 33, 33 (2010‐2011). 70 Id. at 34. 71 WARREN LEON, CLEAN ENERGY STATES ALLIANCE, THE STATE OF STATE RENEWABLE PORTFOLIO STANDARDS 5 (2013), http://www.cesa.org/assets/2013‐Files/RPS/State‐of‐State‐RPSs‐Report‐Final‐June‐2013.pdf. 72 Ratemaking, Solar Value and Solar Net Energy Metering—A Primer, supra note, 81, at 1.

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However, as noted in the Introduction, state net metering policies have recently become a focal point of debate among regulators, utility stakeholders, and solar interests.73 This Part discusses the historical influence of federal as well as state policy actions on the electrical generation landscape, and introduces the current state of net metering debates.

A. PURPA and Its Progeny

Since the 1930’s, the Federal Energy Regulatory Commission (FERC) and state public utility commissions have jointly regulated domestic and regional electric markets.74 Traditionally, federal regulators established procedures for wholesale electricity markets and for interstate transmission of electricity; whereas state entities regulated the rates that utilities may charge end‐use consumers.75 Importantly, state regulators also issued permits that granted individual utilities a monopoly franchise to provide service within defined geographic areas.76 Under this monopolistic regulatory framework, the electric industry consisted of monolithic and vertically integrated utilities that owned transmission, distribution, and generation facilities necessary to deliver electricity to end‐use consumers.77 Until the late 1960s, this model appeared to function reasonably well. Vertically integrated utilities consistently met increasing consumer demand while improvements in generation and transmission technology enabled them to do so at decreasing cost.78 However, by the late 1970s, domestic confidence in traditional sources of energy, and the hulking utilities that generated 97% of all electricity, was waning.79 Two decades of rising demand for electricity, growing environmental consciousness, and a parade of energy crises that included the 1973 Oil Embargo and 1977 natural gas shortage all led to calls for comprehensive reexamination of U.S. energy policy.80

73 QER, supra note 78, at 3‐18. 74 THE CHANGING STRUCTURE OF THE ELEC. POWER INDUS.: 1970‐1991, supra note 99, at 112. Prior to FERC’s establishment in 1977, the Federal Power Commission regulated interstate electrical transactions. 75 Dennis, supra note 100, at 34. 76 Dennis, supra note 100, at 34. 77 Dennis, supra note 100, at 33. 78 ROBIN ALLEN ET AL., ELEC. ENERGY MKT. COMPETITION TASK FORCE, REPORT TO CONG. ON COMPETITION IN WHOLESALE & RETAIL MKTS. FOR ELEC. ENERGY 19 (2006) [hereinafter FERC Study],available at http://www.ferc.gov/legal/fed‐sta/ene‐pol‐ act/epact‐final‐rpt.pdf.. See also Sam Kalen, Replacing a National Energy Policy with a National Resource Policy, 19 NAT. RESOURCES & ENV’T 3, at 12‐13 (Winter 2005). 79 FERC Study, at 19–20.. 80 Richard D. Cudahy, PURPA: The Intersection of Competition and Regulatory Policy, 16 ENERGY L.J. 419, 421 (1995).

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In 1978, during the Carter administration, Congress enacted the Public Utilities Regulatory Policies Act (PURPA);81 the first major piece of energy legislation in forty‐three years.82 By offering a series of regulatory and marketplace incentives to non‐utility “qualifying facilities” that satisfied generator size, ownership, and renewable resource stipulations, PURPA marked a departure from the monopolistic utility structure that had been in effect until then.83 In addition to exempting qualifying facilities from federal and state regulations that governed utility finances and organization,84 the Act required incumbent utilities to interconnect qualifying facilities with the utility‐owned grid, thereby ensuring that the new class of energy producers could deliver output to wholesale and retail customers.85 Finally, PURPA also guaranteed qualifying facilities a market to sell electricity by mandating that utilities purchase any qualifying facility’s output at pre‐determined rates.86 The Act capped these rates at the purchasing utility’s “avoided cost”‐‐what the utility would pay to generate comparable electricity itself or to purchase power from a third‐party.87

Notwithstanding the avoided cost price cap, PURPA’s essential guarantee that utilities interconnect and purchase power from qualifying facilities triggered substantial development of non‐ utility, small‐capacity generators.88 Throughout the early 1990s, qualifying facilities accounted for more than half of annual new generation capacity,89 and by 1991 such facilities accounted for 6% of the total electricity generation capacity in the United States.90

Between 1992 and 2005, Congress and federal regulators aggressively expanded PURPA’s support for non‐utility, small‐scale generators seeking to enter wholesale electricity markets.91 First, to accommodate an influx of non‐utility generators that did not meet PURPA’s “qualifying facility” renewable fuel or ownership constraints,92 the Energy Policy Act of 1992 established a class of “exempt

81 Public Utilities Regulatory Policies Act of 1978, Pub. L. No. 95‐617, 92 Stat. 3117 (codified as amended in sections of 15, 16, and 42 U.S.C. (2012)). 82 Dennis, supra note 100, at 33. 83 16 U.S.C. § 796(17)(A)(i)‐(ii) (2012). 84 16 U.S.C. § 824a‐3(e)(1) (2012). 85 16 U.S.C. § 2621(d) (2012). 86 16 U.S.C. § 824a‐3(b), (d) (2012) (noting rates could not exceed the “incremental cost to the electric utility of alternative electric energy”). 87 18 C.F.R. §§ 292.101(b)(6), 292.304(e) (2015). 88 FERC Study, supra note 108, at 21‐22. 89 Jeffrey D. Watkiss & Douglas W. Smith, The Energy Policy Act of 1992‐‐A Watershed for Competition in the Wholesale Power Market, 10 YALE J. ON REG. 447, 454 (1993). 90 FERC Study, supra note 108, at 22. 91 Dennis, supra note 100, at 34. 92 Cudahy, supra note 110, at 6.

13 wholesale generators.”93 Under PURPA alone, non‐utility electricity developers attempting to enter wholesale electricity markets while avoiding financial and structural regulations that applied to utilities had limited alternatives available. These entities could either comply with PURPA’s renewable fuel and ownership restrictions, or resort to contorted and fragmented ownership models that divorced operating control from plant ownership. Such ownership models were generally viewed unfavorably by potential lenders.94 Becoming an exempt wholesale generator offered non‐utilities an attractive alternative.

Like PURPA’s qualifying facilities, exempt wholesale generators were excused from federal regulations applied to utilities and received access, subject to a case‐by‐case FERC determination, to utility‐owned grids.95 However, unlike qualifying facilities, exempt wholesale generators could be utility‐ owned and use any fuel source, and were permitted to charge market‐based rates for electric output rather than the “avoided cost” prices mandated by PURPA.96

Compared to PURPA’s avoided cost rates and the multi‐year purchase contracts between utilities and qualifying facilities, market‐based rates provided incentives for responding to volatile fuel costs or changes in generation expenses.97 In markets where costs of meeting consumer demand were low, the incentive to build qualifying facilities was small.98 In contrast, market‐based rates offered transacting parties flexibility to negotiate prices reflecting the costs of electricity generation and distribution.99 For example, temporary periods of electricity scarcity would lead to higher rates.100 By offering exempt wholesale generators the freedom to stipulate prices for electrical output rather than merely to receive a pre‐arranged price, the Act rewarded efficient generators that produced electricity below avoided cost rates.101 Thus, while regional variation in avoided cost rates produced an uneven

93 Energy Policy Act of 1992, Pub. L. No. 102‐486, §§ 711(a)(a) , 106 Stat. 2776 (codified as amended at 15 U.S.C. § 79 (2012)). 94 Watkiss & Smith, supra note 119, at 465. 95 16 U.S.C. §§ 824j, k (2012). 96 EPAct 1992, §§ 721‐22; MONICA GREER, ELEC. MARGINAL COST PRICING: APPLICATIONS IN ELICITING DEMAND RESPONSES 72 (1st ed. 2012). 97 Joseph T. Kelliher, Pushing the Envelope: Development of Federal Electric Transmission Access Policy, 42 AM. U. L. REV. 543, 589 (1993); Leonard S. Greenberger, The PUHCA: Busting the Trusts, PUB.UTIL.FORT.19, 22 (Mar.15, 1991) (noting the Northeast generally had a dearth of qualifying facilities). 98 Watkiss & Smith, supra note 119, at 453‐54. 99 Dennis, supra note 100, at 36. 100 FERC Study, supra note 108, at 2. 101 Kelliher, supra note 127, at 547.

14 landscape of qualifying facility development, market‐based rates enabled exempt wholesale generators to effectively compete in wholesale markets.102

To complement legislative efforts like PURPA and the Energy Policy Act, which lowered barriers to non‐utility generation, federal regulators also sought to provide incentives for further non‐utility development by opening access to grid transmission lines.103 In the 1990s, the grid was still a monopoly owned by vertically‐integrated utilities.104 Citing pervasive anti‐competitive conduct by utilities, including discriminatory pricing for transmission service against non‐utilities,105 FERC issued a series of orders during the mid‐1990s that transferred significant operating control over transmission grid away from utilities.106 The orders established independent entities to monitor grid access,107 increased transparency over fees utilities charged others to use grid power lines,108 and broadly expanded non‐ utility access to the grid by abandoning FERC’s cumbersome case‐by‐case assessment and adopting universal access.109

Moreover, recognizing that optimal sites for wind and solar generation could be geographically isolated,110 Congress sought to facilitate the development of fossil‐fuel alternative generation by expanding the transmission grid to connect remote sites of wind or solar generation to urban areas

102 FERC Study, supra note 108, at 51; Kelliher, supra note 127, at 590. 103 Alexander K. Obrecht, Energy Policy Act of 2005: Pseudo‐Fed for Transmission Congestion, 7 PITT. J. ENVTL. PUB. HEALTH L. 159, 167 (2012‐2013); FERC Study, supra note 108, at 24. 104 QER, supra note 78, at 3‐4. 105 FERC Study, supra note 108, at 24. 106 Promoting Wholesale Competition Through Open Access Non‐Discriminatory Transmission Services by Public Utilities, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (May 10, 1996) [hereinafter Order No. 888], F.E.R.C. STATS. & REGS. ¶ 31,036 (1996), order on reh’g, Order No. 888‐A, F.E.R.C. STATS. & REGS. ¶ 31,048 (1997), order on reh'g, Order No. 888‐B, 62 Fed. Reg. 64,688 (Dec. 9, 1997), 81 F.E.R.C. ¶ 61,248 (1997), order on reh'g, Order No. 888‐C, 82 F.E.R.C. ¶ 61,046 (1998), aff’d in part sub nom., Transmission Access Policy Study Group v. Fed. Energy Regulatory Comm'n, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom., New York v. Fed. Energy Regulatory Comm'n, 535 U.S. 1 (2002) (authorizing creation of “Independent System Operators (ISOs)); Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 810 (Jan. 6, 2000) [hereinafter Order No. 2000], 89 F.E.R.C. ¶ 61,285, order on reh'g, Order No. 2000‐A, 65 Fed. Reg. 12,088 (Mar. 8, 2000), aff'd sub nom., Pub. Utility Dist. No. 1 v. FERC, 272 F.3d 607 (D.C. Cir. 2001) (authorizing creation of “Regional Transmission Organizations” (RTOs)). 107 Order No. 888; Order No. 2000. 108 Open Access Same‐Time Information System (Formerly Real‐Time Information Networks) and Standards of Conduct, Order No. 889, 61 Fed. Reg. 21,737 (May 10, 1996), F.E.R.C. STATS. & REGS. ¶ 31,035 (1996), order on reh’g, Order No. 889‐A, F.E.R.C. STATS. & REGS. ¶ 31,049 (1997), order on reh’g, Order No. 889‐B, 81 F.E.R.C. ¶ 61,253 (1997) (establishing the Open Access Same‐Time Information System (OASIS) containing day‐to‐day information regarding transmission tariffs). 109 Order No. 888, F.E.R.C. STATS. & REGS. at 31, 655 (establishing universal “comparable transmission services” for third‐parties, requiring owners of transmission grid to offer third‐parties access under comparable terms and conditions as the transmission owner’s own use of the system). 110 Sandeep Vaheesan, Preempting Parochialism and Protectionism in Power, 49 HARV. J. ON LEGIS. 87, 96–98 (2012).

15 where electricity could be delivered to end‐use consumers.111 The Energy Policy Act of 2005 offered incentives for private infrastructure investment and granted the Federal Energy Regulatory Commission (FERC) the authority to supervise the development of intrastate grids, as long as such development influenced the interstate transmission of electricity.112 The 2005 Act also expanded FERC’s authority to police utilities and to pursue civil penalties for manipulative conduct, like discriminatory pricing, in connection with transmission service.113 However, recognizing that previous legislative and regulatory efforts had injected growing competition between non‐utility and utility generators,114 the Act also gave FERC authority to terminate a utility’s obligation to purchase electricity from qualifying facilities.115 Ultimately, PURPA’s purchase obligations were lifted in markets accounting for approximately 29% of qualifying facility generation capacity.116 Since 2005, qualifying facility development has noticeably stagnated. The 2% average annual growth in qualifying facility generation capacity between 2006 and 2013 is a far cry of the 8.6% average annual growth experienced between 2001 and 2005.117

Nonetheless, due in part to federal efforts begun under PURPA, 37% of U.S. electricity by 2013 was generated by non‐utility, independent power producers.118 Equally importantly, PURPA’s small but

111 Jim Rossi, The Trojan Horse of Electric Power Transmission Line Siting Authority, 39 ENVTL. L. 1015, 1029 (2009); NAT’L ELEC. MFRS. ASS’N, NEMA ASSESSMENT OF THE ENERGY POLICY ACT OF 2005, at 7‐11, https://www.nema.org/Policy/Energy/Documents/2005EnergyHandout%20_1_.pdf (last visited July 29, 2015); Judy Chang et al., The Brattle Group, Trends & Benefits of Transmission Investments: Identifying and Analyzing Value, Presented to the CEA Transmission Council, Ottawa, Canada, Sept. 26, 2013, http://www.brattle.com/system/publications/pdfs/000/004/944/original/Trends_and_Benefits_of_Transmission_I nvestments_Chang_Pfeifenberger_Hagerty_CEA_Sep_26_2013.pdf (showing increase in infrastructure investment since 2005). 112 16 U.S.C. § 824p(e) (2012). 11316 U.S.C. § 824v(a) (2012); Charles J. Time Engel III & Brandon E. Reavis, FERC’s Market Manipulation and Enforcement Process 54, (2010), available at http://www.kslaw.com/Library/publication/Financial%20Fraud%20Law%20Report%20engel_reavis.pdf. 114 Dennis, supra note 100, at 35. 115 Energy Policy Act of 2005, Pub. L. No. 109‐58, § 1253, 119 Stat. 594 (codified at 16 U.S.C. § 824a‐3(m) (2012)) [hereinafter EPAct 2005]. However, FERC rules require any utility seeking to terminate a purchase contract with a QFs generating 20MW of power or less to overcome a rebuttable presumption the QF lacks access to wholesale markets and transmission. 18 C.F.R. § 292.309(d)(1) (2014). 116 New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, FERC STATS. & REGS. ¶ 31,233 (2006) [hereinafter Order No. 688], order on reh’g, Order No. 688‐A, FERC STATS. & REGS. ¶ 31,250 (2007), aff’d sub nom. Am. Forest & Paper Ass’n v. FERC, 550 F.3d 1179 (D.C. Cir. 2008); ENERGY INFO. ADMIN., FORM EIA‐860 DETAILED DATA (2013) [hereinafter FORM EIA‐860 2013], http://www.eia.gov/electricity/data/eia860/. 117 FORM EIA‐860 2013, supra note 146. 118 Severin Borenstien & James Bushnell, The U.S. Electricity Indus. After 20 Years of Restructuring 6‐7 (2015) pg. 6‐ 7; ENERGY INFO. ADMIN, U.S. DEP’T ENERGY, ELECTRICITY DATA BROWSER, http://www.eia.gov/electricity/data/browser/#/topic/0?agg=2,0,1&fuel=vvg&geo=g&sec=g&linechart=ELEC.GEN.A LL‐US‐99.A~ELEC.GEN.COW‐US‐99.A~ELEC.GEN.NG‐US‐99.A~ELEC.GEN.NUC‐US‐99.A~ELEC.GEN.HYC‐US‐ 99.A&columnchart=ELEC.GEN.ALL‐US‐99.A~ELEC.GEN.COW‐US‐99.A~ELEC.GEN.NG‐US‐99.A~ELEC.GEN.NUC‐US‐

16 significant shift away from vertically integrated utilities helped recast traditional economies of scale for electricity generators.119 By expanding non‐utility access to the electric grid and encouraging smaller‐ scale generators, PURPA simultaneously lowered market entry barriers for non‐utilities and mitigated any advantage large companies hoped to receive exploiting control over transmission infrastructure and their ability to invest capital in new generation capacity.120 Federal efforts also offered tax incentives for renewable generation and earmarked funds for research and development of smaller electric turbines and distributed energy resources.121 Gone are the days where it was necessary to build a 1,000 MW generating plant in order to exploit economies of scale.122

B. State Renewable Portfolio Standards

A second driver of small‐scale generators and renewable fuel sources has been state policies, particularly “renewable portfolio standards.”123 State renewable portfolio standards require or encourage electricity producers to supply a minimum percentage, or occasionally an absolute amount, of their electricity from renewable sources.124 By 2014, twenty‐nine states and the District of Columbia imposed a renewable portfolio standard, and eight additional states had a non‐binding renewable

99.A~ELEC.GEN.HYC‐US‐99.A&map=ELEC.GEN.ALL‐US‐ 99.A&freq=A&ctype=linechart<ype=pin&rtype=s&pin=&rse=0&maptype=0 (view report “1.3 Net generation by energy source: independent power producers) (last visited July 28, 2015). 119 ENERGY INFO. ADMIN.,U.S. DEP’T ENERGY,THE CHANGING STRUCTURE OF THE ELEC. POWER INDUS. 2000: AN UPDATE 44 (2000) (“No longer is it necessary to build a 1,000‐megawatt generating plant to exploit economies of scale.”). 120 THE CHANGING STRUCTURE OF THE ELEC. POWER INDUS. 2000: AN UPDATE, supra note 149, at 98. 121 Energy Policy Act of 1992 §1914, (establishing the Production Tax Credit for qualifying facilities); Energy Policy Act of 2005 § 921 (earmarking $768 million for fiscal years 2007 through 2009 for “programs of research, development, demonstration, and commercial application on distributed energy resources and systems reliability and efficiency.”). For in‐depth discussion of the statistically significant influence of policy on technological innovation, see Nick Johnstone, et al., Environmental Policy Stringency and Technological Innovation: Evidence from Survey Data and Patent Counts, APPLIED ECONOMICS 44(17), at 2157‐2170 (2012). 122 THE CHANGING STRUCTURE OF THE ELEC. POWER INDUS. 2000: AN UPDATE, supra note 149, at 44. 123 RYAN WISER, ET. AL., LAWRENCE BERKELEY NAT’L LAB., LBNL‐54439, EVALUATING EXPERIENCE WITH RENEWABLE PORTFOLIO STANDARDS IN THE UNITED STATES 1 (2004) [hereinafter WISER, ET AL., EXPERIENCE WITH RENEWABLE PORTFOLIO STANDARDS]. For a broad picture of state RPS policies, see Database of State Incentives for Renewables & Efficiency, Renewable Portfolio Standard Policies, North Carolina Solar Center, http://ncsolarcen‐prod.s3.amazonaws.com/wp‐ content/uploads/2015/01/RPS_map.pdf (last visited July 15, 2015). 124 Brad A. Kopetsky, Comment, Deutschland Uber Alles: Why German Regulations Need to Conquer the Divided U.S. Renewable‐Energy Framework to Save Clean Tech (And the World), 2008 WIS. L. REV.941, 957 (2008).

17 portfolio goal.125 If met in their entirety, the binding standards will require over 122.2 GW of renewable energy capacity by 2020, or 181% of existing solar and wind capacity.126

Renewable portfolio standards range from modest to ambitious, with 10% standard in Michigan127 and Wisconsin,128 and a 100% standard in Hawaii.129 Twenty‐two states impose a renewable standard of 15% or greater,130 and six states have a standards greater than 25%.131 More than half of all state renewable portfolio standards also include solar or distributed generation “carve‐out”

125 States with RPS policies are: Arizona, ARIZ. ADMIN. CODE § R14‐2‐1804 (2007); California, CAL. PUB. UTIL. CODE § 399.11 (West 2013); Colorado, COLO. REV. STAT. ANN. §40‐2‐124 (West 2013); Connecticut, CONN. GEN. STAT. §16‐245a (2014); Delaware, DEL. CODE ANN. tit. 26, § 354 (West 2011); District of Columbia, D.C. CODE § 34‐1432 (2015); Hawaii, HAW. REV. STAT. § 269‐92 (2009), amended by 2015 Haw. Sess. Laws 97 (Hawaii has renewable energy targets of 30% by 2020, 40% by 2030, and 75% by 2040); Illinois, 20 ILL. COMP. STAT. ANN. 3855/1‐75 (West 2013); Iowa, IOWA CODE ANN. § 476.43 (West 1983); Maine, ME. REV. STAT. ANN. tit. 35‐A, § 3210 (2012); Maryland, MD. CODE ANN. PUB. UTIL. COS. §7‐703 (West 2013); Massachusetts, 225 MASS. CODE REGS. 14.07 (2014); Michigan, MICH. COMP. LAWS ANN. § 460.1027 (West 2008); Minnesota, MINN. STAT. ANN. § 216B.1691 (West 2014); Missouri, MO. ANN. STAT. § 393.1030 (West 2013); Montana, MONT. CODE ANN. § 69‐3‐2004 (West 2005); Nevada, NEV. REV. STAT. ANN. § 704.7821 (West 2013); New Hampshire, N.H. REV. STAT. ANN. § 362‐F3 (2013); New Jersey, N.J. STAT. ANN. § 48:3‐87 (West 2012); New Mexico, N.M. STAT. ANN. § 62‐16‐4 (West 2014); New York, N.Y. PUB. SERV. LAW § 03‐E‐0188 (McKinney 2004); North Carolina, N.C. GEN. STAT. ANN. § 62‐133.8 (West 2014); Ohio, OHIO REV. CODE ANN. § 4928.64 (West 2014); Oklahoma, OKLA. STAT. ANN. tit. 17, § 801.4 (West 2010); Oregon, OR. REV. STAT. ANN. § 469A.052 (West 2007); Pennsylvania, 73 PA. CONS. STAT. ANN. § 1648.3 (West 2007); Rhode Island, R.I. GEN. LAWS ANN. § 39‐26‐4 (West 2004); Texas, TEX. UTIL. CODE ANN. § 39.904 (West 2007); Washington, WASH. REV. CODE ANN. § 19.285.040 (West 2014); Wisconsin, WIS. STAT. ANN. § 196.378 (West 2014). Nine additional states have renewable portfolio goals, but not explicit requirements. These states are: Indiana, IND. CODE ANN. § 8‐1‐37‐12 (West 2011); Kansas, 2015 Kansas Sess. Laws 75; North Dakota, N.D. CENT. CODE ANN. § 49‐02‐28 (West 2007); South Carolina, S.C. CODE ANN. § 58‐39‐130 (2014); South Dakota, S.D. CODIFIED LAWS § 49‐34A‐101 (2008); Utah, UTAH CODE ANN. § 54‐17‐602 (West 2008); Vermont, VT. STAT. ANN. tit. 30, § 8005 (West 2005); Virginia, VA. CODE ANN. § 56‐585.2 (West 2014). 126 FORREST SMALL, CERES, THE 21ST CENTURY ELEC. UTIL. POSITIONING FOR A LOW‐CARBON FUTURE 16‐17 (2010), available at http://www.ceres.org/resources/reports/the‐21st‐century‐electric‐utility‐positioning‐for‐a‐low‐carbon‐future‐1; ENERGY INFO. ADMIN., U.S. DEP’T ENERGY, TABLE 4.3 EXISTING CAPACITY BY ENERGY SOURCE, DETAILED DATA FILES (2013), available at http://www.eia.gov/electricity/data.cfm#gencapacity. 127 Michigan, MICH. COMP. LAWS ANN. § 460.1027 (West 2008). 128 Wisconsin, WIS. STAT. ANN. § 196.378 (West 2014). 129 Hawaii, HAW. REV. STAT. § 269‐92 (2009), amended by 2015 Haw. Sess. Laws 97 (Hawaii has renewable energy targets of 30% by 2020, 40% by 2030, and 75% by 2040). 130 Jurisdictions with RPS percentage requirements 15% or greater are: California, CAL. PUB. UTIL. CODE § 399.11 (West 2013); Colorado, COLO. REV. STAT. ANN. §40‐2‐124 (West 2013); Connecticut, CONN. GEN. STAT. §16‐245a (2014); Delaware, DEL. CODE ANN. tit. 26, § 354 (West 2011); District of Columbia, D.C. CODE § 34‐1432 (2015); Hawaii, HAW. REV. STAT. § 269‐92 (2009), amended by 2015 Haw. Sess. Laws 97; Maine, ME. REV. STAT. ANN. tit. 35‐A, § 3210 (2012); Maryland, MD. CODE ANN. PUB. UTIL. COS. §7‐703 (West 2013); Massachusetts, 225 MASS. CODE REGS. 14.07 (2014); Minnesota, MINN. STAT. ANN. § 216B.1691 (West 2014); Nevada, NEV. REV. STAT. ANN. § 704.7821 (West 2013); New Hampshire, N.H. REV. STAT. ANN. § 362‐F3 (2013); New Jersey, N.J. STAT. ANN. § 48:3‐87 (West 2012); New Mexico, N.M. STAT. ANN. § 62‐16‐4 (West 2014); New York, N.Y. PUB. SERV. LAW § 03‐E‐0188 (McKinney 2004); Oregon, OR. REV. STAT. ANN. § 469A.052 (West 2007); Pennsylvania, 73 PA. CONS. STAT. ANN. § 1648.3 (West 2007); and Rhode Island, R.I. GEN. LAWS ANN. § 39‐26‐4 (West 2004). 131 Jurisdictions with RPS percentage requirements greater than 25% are: California, CAL. PUB. UTIL. CODE § 399.11 (West 2013); Colorado, COLO. REV. STAT. ANN. §40‐2‐124 (West 2013); Connecticut, CONN. GEN. STAT. §16‐245a (2014); Hawaii, HAW. REV. STAT. § 269‐92 (2009), amended by 2015 Haw. Sess. Laws 97.; Maine, ME. REV. STAT. ANN. tit. 35‐A, § 3210 (2012); New York, N.Y. PUB. SERV. LAW § 03‐E‐0188 (McKinney 2004).

18 provisions.132 These provisions require that a certain percentage of an electrical producer’s supply be generated by a specific source like solar instead of from any renewable source.

In contrast to the stagnating growth characteristic of PURPA’s qualifying facilities over the past decade, renewable portfolio standards have catalyzed enormous expansion of renewable sources of generation, including residential distributed generation.133 Between 1998 and 2013, 61% of new non‐ hydroelectric renewable energy capacity was added in states with renewable portfolio standards.134 Since 2005, renewable portfolio standards are credited with driving between 60% and 80% of all U.S. solar additions outside of California.135

The combination of federal incentives for non‐utility generators and state renewable portfolio standards has triggered enormous development in renewable generation.136 Since 1978, when PURPA first offered incentives for renewable source power producers, electricity generated from renewable sources has increased approximately 200%.137 Excluding hydroelectric sources of generation, growth since 1978 among remaining renewable sources of generation is nearly 8,500%.138 Since 2000 alone, generation from renewable sources has grown at an annual rate nearly twice that of traditional fossil

132 Jurisdictions with specific solar or distributed generation provisions in RPS policies are: Arizona, ARIZ. ADMIN. CODE § R14‐2‐1804 (2007); Delaware, DEL. CODE ANN. tit. 26, § 354 (West 2011); District of Columbia, D.C. CODE § 34‐ 1432 (2015); Illinois, 20 ILL. COMP. STAT. ANN. 3855/1‐75 (West 2013); Maryland, MD. CODE ANN. PUB. UTIL. COS. §7‐703 (West 2013); Massachusetts, 225 MASS. CODE REGS. 14.07 (2014); Michigan, MICH. COMP. LAWS ANN. § 460.1027 (West 2008); Minnesota, MINN. STAT. ANN. § 216B.1691 (West 2014); Missouri, MO. ANN. STAT. § 393.1030 (West 2013); Nevada, NEV. REV. STAT. ANN. § 704.7821 (West 2013); New Hampshire, N.H. REV. STAT. ANN. § 362‐F3 (2013); New Jersey, N.J. STAT. ANN. § 48:3‐87 (West 2012); New Mexico, N.M. STAT. ANN. § 62‐16‐4 (West 2014); New York, N.Y. PUB. SERV. LAW § 03‐E‐0188 (McKinney 2004); North Carolina, N.C. GEN. STAT. ANN. § 62‐133.8 (West 2014); Ohio, OHIO REV. CODE ANN. § 4928.64 (West 2014); Oregon, OR. REV. STAT. ANN. § 469A.052 (West 2007); Pennsylvania, 73 PA. CONS. STAT. ANN. § 1648.3 (West 2007); Texas, TEX. UTIL. CODE ANN. § 39.904 (West 2007); Washington, WASH. REV. CODE ANN. § 19.285.040 (West 2014). 133 WISER, ET AL., EXPERIENCE WITH RENEWABLE PORTFOLIO STANDARDS, supra note 153, at 1. 134 EPA, ENERGY AND EVIRON. GUIDE TO ACTION 5‐1 (2015), http://epa.gov/statelocalclimate/documents/pdf/guide_action_full.pdf. 135 GALEN BARBOSE, LAWRENCE BERKELEY NAT’L LAB., RENEWABLES PORTFOLIO STANDARDS IN THE UNITED STATES: A STATUS UPDATE 6 (2013), available at http://emp.lbl.gov/sites/all/files/2014%20REM.pdf. 136 See D. Steward, et. al., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐7A40‐61029, Effectiveness of State‐Level Policies on Solar Market Development in Different State Contexts, at (2014), available at http://www.nrel.gov/docs/fy14osti/61029.pdf. 137 ENERGY INFO. ADMIN, U.S. DEP’T ENERGY, MONTHLY ENERGY REVIEW, TABLE 7.2a TOTAL ELECTRICITY GENERATION (May 2015), available at http://www.eia.gov/totalenergy/data/monthly/index.cfm#electricity; PURPA fuel sources are solar, wind, hydro, biomass, waste and geothermal. 18 C.F.R. § 292.204 (2010). 138 ENERGY INFO. ADMIN, U.S. DEP’T OF ENERGY, MONTHLY ENERGY REVIEW, TABLE 7.2a TOTAL ELECTRICITY GENERATION (May 2015) [hereinafter EIA Monthly Energy Review, May 2015], available at http://www.eia.gov/totalenergy/data/monthly/index.cfm#electricity. PURPA fuel sources are solar, wind, hydro, biomass, waste and geothermal. 18 C.F.R. § 292.204 (2010).

19 fuel and natural gas sources combined.139 Annual solar generation grew over 3000% since 2000,140 and solar output has doubled every year since 2012.141 Solar has been the fastest growing renewable source of generation since 2000 and that trend is projected to persist through 2040.142

Perhaps one of the most significant consequences of the federal and state initiatives has been the consequent rise in the cost‐effectiveness of solar generation. Direct appropriation for research and development of renewable technologies has helped drive down manufacture costs;143 and rebates or performance‐based incentives for solar generators have historically offset as much as 80% of solar generator installation cost.144 The cost of silicon crystalline cells, which are critical to solar photovoltaic generation, has declined 85% since 2003.145 Since 2006 alone, the total costs to install solar panels have dropped more than 73%.146 While some of the declining cost may be attributable to independent technological advancement, federal and state policies have almost certainly induced the rate and direction of advancement in both the short‐ and long‐term.147

Growing affordability has helped solidify solar generation as an attractive and feasible option for homeowners. Residential solar installations have grown at a 50% annual rate since 2012,148 and by year‐ end 2014, residential solar comprised approximately 17% of total solar capacity.149

139 EIA MONTHLY ENERGY REVIEW, May 2015, supra note 168, at TABLE 7.2a. 140 Id. 141 Id. 142 ENERGY INFO. ADMIN, U.S. DEP’T ENERGY, Annual Energy Outlook 2015 with Projections to 2040, DOE/EIA‐0383, at ES‐7(Apr. 2015), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. 143 See U.S. DEP’T OF ENERGY, SUNSHOT VISION STUDY xix (2012)(noting the Department of Energy study into current state of PV technologies with purpose of reducing PV‐generated electricity 75% by 2020), available at http://www1.eere.energy.gov/solar/pdfs/47927.pdf; GALEN BARBOSE, LAWRENCE BERKELEY NAT’L LAB., TRACKING THE SUN VII 43 (2014), available at http://emp.lbl.gov/sites/all/files/lbnl‐6858e.pdf (concluding state and federal policy initiatives have contributed to declining cost of installed prices for solar photovoltaic); Energy Policy Act Appropriations; Press Release, Energy Dep’t, Energy Dep’t Announces $53 Million to Drive Innovation, Cut Cost of Solar Power (Oct. 22, 2014), http://energy.gov/articles/energy‐department‐announces‐53‐million‐drive‐ innovation‐cut‐cost‐solar‐power (“Due in part to the Energy Department’s long‐term investments and partnerships with private industry…solar PV panels now cost 50% of what they did three years ago.”). 144 Samantha Weaver, Benchmarking the Declining Cost of Solar, SOLAR TODAY, Jan. 27, 2015, http://solartoday.org/2015/01/benchmarking‐the‐declining‐cost‐of‐solar/; see also Kevin Robinson‐Avila, Shadow Over Rooftop Solar, ALBUQUERQUE J., Dec. 29, 2014, http://www.abqjournal.com/518250/biz/rooftop‐solar.html (noting federal and state tax rebates can reduce total cost of residential 6kW system $10,000). 145 Noah Kaufman, Annual Energy Outlook Projections and the Future of Solar Photovoltaic Energy, INSTITUTE FOR POLICY INTEGRITY, Working Paper No. 2014/4, at 2 (2014). 146 SOLAR ENERGY INDUS. ASS’N, SOLAR MARKET INSIGHT REPORT 2014 Q4, http://www.seia.org/research‐resources/solar‐ market‐insight‐report‐2014‐q4 (last visited June 23, 2015). 147 FELIX GROBA & BARBARA BREITSCHOPF, DIW BERLIN, IMPACT OF RENEWABLE ENERGY POLICY AND USE ON INNOVATION 13 (2013), available at http://www.diw.de/documents/publikationen/73/diw_01.c.426553.de/dp1318.pdf. 148 50 States Q1 2015, supra note 24, at 3.

20

C. Net Metering Policies

The most common tool to track electrical output from distributed solar generators and compensate utility owners for output is the billing arrangement known as “net metering.”150 Net metered residential solar customers have a collective capacity of 2.3 GW151 and account for 13% of total solar capacity in the United States.152 Since 2001, net metering policies have been available to utility customers in the majority of states.153 However, state policies differ, often substantially, among jurisdictions.154 Seven distinctions are particularly important.155

First, an important distinction among net metering policies is how states compensate customer‐ sited generation. Thirty‐four net metering jurisdictions credit customers for excess generation at the retail rate.156 Of these, fourteen states plus the District of Columbia credit customer excess generation at the retail rate without expiration.157 In contrast to PURPA’s avoided‐costs rates, which reflect the cost to a utility generating equivalent power or purchasing it from a non‐qualifying facility third‐party, retail rates exactly mirror the price charged by utilities to end‐use consumers for electricity, and thus include delivery costs, administrative expenses, state and local taxes, and utility profits.158 Though only five jurisdictions credit generation exclusively at avoided‐cost based prices,159 many states offer a

149 See PHOTOVOLTAIC POWER SYSTEMS PROGRAMME, ANNUAL REPORT 2014 (2014), available at http://cansia.ca/sites/default/files/iea‐pvps‐ar‐2014.pdf. See also TRENDS SHAPING OUR CLEAN ENERGY FUTURE, supra note 5, at 26. 150 ENERGY INFO. ADMIN., U.S. DEP’T ENERGY, STATE ENERGY DATA SYSTEM TABLE 4.10, NET METERING CUSTOMERS AND CAPACITY BY TECHNOLOGY TYPE, BY END USE SECTOR, 2003 THROUGH 2013 (2013), available at http://www.eia.gov/electricity/annual/ (noting a 53% annual growth rate in NEM customers). See also J. HEETER, ET AL., supra note 46, at 11 , (noting net metering is a statistically significant driver of solar growth). 151 , U.S. ENERGY INFO. ADMIN., FORM EIA‐826 DETAILED DATA (2014), available at http://www.eia.gov/electricity/data/eia826/. 152 See PHOTOVOLTAIC POWER SYSTEMS PROGRAMME, ANNUAL REPORT 2014, supra note 179, at 108. 153 James W. Stoutenborough and Matthew Beverlin, Encouraging Pollution‐Free Energy: The Diffusion of State Net Metering Policies, 89 SOCIAL SCIENCE QUARTERLY 1230, 1232 (2008). See also 50 States Q1 2015, supra note 24, at 8. Under the Energy Policy Act of 2005, every electric utility is required to make a net metering service available to any electric customer. Pub. Law. No. 109–58 § 1251, 119 Stat. 594 (Aug. 8, 2005) (codified at 16 U.S.C. § 2621(d) (2012)) amending Public Utility Regulatory Policies Act of 1978. 154 Alabama, Idaho, Mississippi, South Dakota, Tennessee and Texas all lack a net metering program. Best Practices, supra note 24, at 10. 155 STANTON, supra note 58, at 9. (2013). 156 Id. 157 KIRSCH, ET AL., supra note 29, at 9. 158 YIH‐HUEI WAN & H. JAMES GREEN, NAT’L RENEWABLE ENERGY LAB., NREL/CP‐500‐24527, CURRENT EXPERIENCE WITH NET METERING PROGRAMS 1‐2 (1998), available at http://www.nrel.gov/docs/legosti/old/24527.pdf. 159 As of 2014, Missouri, Nebraska, New Mexico, North Dakota and Rhode Island compensate excess net metered generation at avoided cost rates. Best Practices, supra note 24, at 64, 66, 72, 77, 85.

21 combination of rates.160 In practice, this combination typically credits monthly excess generation that is “carried‐over” to future billing cycles at a retail rate, but credits annual net excess, when utilities and net metered customers “zero‐out” generation and consumption from the past 12 months, at an avoided cost rate.161 The difference between the retail and avoided cost rates may be substantial, as much as $0.10 per kWh or higher.162 In Wisconsin, for example, utility avoided costs rates are $0.03 to $0.04 per‐ kWh, while retail rates range between $0.11 and $0.14 per‐kWh.163 In Kansas, retail rates, which are some of the nation’s highest, can reach $0.19 per‐kWh, while utility buy‐back rates for excess generation can be as low as $0.013 per‐kWh, or just 7% of the retail price.164

A second variation among state net metering policies concerns how distributed generators are treated under state renewable portfolio standards. Specifically, net metering policies diverge with regard to ownership of renewable energy certificates, which function as tradable commodities.165 Owning renewable energy credits is a common means of compliance with state renewable portfolio standards, and all but four states allow utilities to satisfy renewable source mandates through the purchase of third‐party renewable energy credits instead of by direct generation or purchase of renewable electricity.166 The sale of renewable energy certificates offer distributed solar owners a supplemental source of income,167 and in some states the existence (or absence) of these certificates can make distributed solar projects economically attractive (or unappealing).168 Over a twenty‐year period, income from renewable energy certificate transactions can total $6,000 or more for a 4 kW solar

160 KIRSCH, ET AL., supra note 29, at 9. 161 See DSIRE, NET METERING STATE DATABASE, supra note 196. 162 WAN & GREEN, supra note 224, at 1‐2. 163 Kari Lydersen, In Wisconsin, Solar ‘New Math’ Could Equal Big Impacts, MIDWEST ENERGY NEWS (Jan. 16, 2015), http://midwestenergynews.com/2015/01/16/in‐wisconsin‐solar‐new‐math‐could‐equal‐big‐impacts/. 164 Bergey WindPower, Net Metering & Related Utility Issues Frequently Asked Questions, http://bergey.com/wind‐school/net‐metering‐and‐related‐issues (last visited July 28, 2015); see also CALIF. PUB. UTIL. COMM’N, NET ENERGY METERING (NEM), http://www.cpuc.ca.gov/PUC/energy/DistGen/netmetering.htm (last visited July 28, 2015), at (noting utility avoided cost rates may be as little as half of the retail rate). 165 KOLLINS, ET AL., supra note 213, at 40. 166 RYAN WISER & GALEN BARBOSE, LAWRENCE BERKELEY NAT. LAB., LBNL‐154E, RENEWABLES PORTFOLIO STANDARDS IN THE UNITED STATES: A STATUS REPORT WITH DATA THROUGH 2007, 22 (2008), available at http://emp.lbl.gov/sites/all/files/REPORT%20lbnl‐154e‐revised.pdf (noting renewable energy targets in 2006 in the majority of state RPS policies were fully or almost‐fully achieved through application renewable energy certificates). 167 WISER & BARBOSE, supra note 217, at 2 n.3. 168 KOLLINS, ET AL., supra note 213, at 34.

22 generator.169 Twenty‐five states vest initial ownership of renewable energy credits with the net‐ metered customer or third‐party owner, while two states place ownership with the utility.170

A third variation among net metering policies is how long a customer’s excess generation may be “carried‐over” to future billing cycles and used to offset electricity consumption. In all but two jurisdictions – Minnesota and North Dakota – net generation may be “carried over” month‐to‐month, and applied in subsequent billing periods to offset later usage.171 Thirteen jurisdictions offer customers some variation of indefinite carry‐over, though the most common policy is to limit how long excess generation may be applied in subsequent billing periods. 172 A plurality of states, twenty‐two, limit the available carry‐over to 12 months.173 Enabling the carry over of excess generation, even if limited to twelve months, leads to very low electricity bills for customers that own large photovoltaic systems.174 For example, schools in California use the credits they earn during the summer months to offset their consumption during the school year resulting in very low bills and, correspondingly, a significant financial impact for the utilities.175

Fourth, while nearly all jurisdictions place a cap on the maximum size of any individual net‐ metered generator,176 state limits range from relatively small, like the 10 kW ceiling in Georgia, to more generous limits like the 80 MW cap in New Mexico.177 The most common size limit is 25 kW, found in ten states, while twenty‐one jurisdictions restrict the size of individual net‐metered generators to 100 kW or below.178 To give these limits context, the capacity of existing net‐metered generators range, nationally, from 3 kW, common among residential systems, to 10 MW or larger, common among

169 JASON COUGHLIN & KARLYNN CORY, NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A2‐44853, SOLAR PHOTOVOLTAIC FINANCING: RESIDENTIAL SECTOR DEPLOYMENT 12 (2009), available at http://www.nrel.gov/docs/fy09osti/44853.pdf. 170 DSIRE, 3RD PARTY SOLAR PV PURCHASE AGREEMENT, March 2015, available at http://ncsolarcen‐ prod.s3.amazonaws.com/wp‐content/uploads/2015/01/3rd‐Party‐PPA_0302015.pdf. The states that vest ownership of renewable energy credits exclusively with the utility are Kansas, KAN. STAT. ANN. § 66‐1263 (West 2009); and New Mexico, N.M. CODE R. § 17.9.5.570 (2008). 171 Minnesota, MINN. STAT. § 216B.164 (2014) and North Dakota, N.D. CENT. CODE, § 69‐09‐07 (1981), reconcile excess generation monthly. See also DSIRE, NET METERING STATE DATABASE, supra note 196. 172 DSIRE, NET METERING STATE DATABASE, supra note 196. 173 Id. 174 Cherrelle Ei et al., The Economic Effect of Electricity Net‐Metering with Solar PV, 75 ENERGY POLICY 244, 247 (2014). 175 Id. Cherrelle Ei et al., The Economic Effect of Electricity Net‐Metering with Solar PV, 75 ENERGY POLICY 244, 47 (2014). 176 Best Practices, supra note 24, at 15.. 177 GA. CODE ANN. § 46‐3‐50 (2002); N.M. STAT. ANN. § 17‐9‐570 (2008). 178 Best Practices, supra note 24.

23 generators installed on retail businesses.179 Nationally, the average residential solar photovoltaic system has capacity of 6.1kW,180 and the average size of non‐residential distributed solar is 109 kW.181

The constraining impact of state capacity limits for distributed generation can be gleaned by comparing solar penetration in states with high limits against states with low limits. On average, jurisdictions with individual capacity limits of 1 MW or greater have 3.44 watts of installed solar capacity per person; while states with individual capacity limits below 1MW have just 0.74 watts of installed capacity per person.182 Individual system caps may also exclude more cost‐effective projects and the potential advantages captured by larger economies of scale. In this connection, systems larger than 500kW are nearly 20% less expensive per generated kW when compared to systems less than 10kW in size.183

Fifth, twenty‐four jurisdictions have aggregate capacity limits, which constrain the total amount of net metered generation that may be installed in a state or utility service area.184 Typically expressed as a percentage of yearly or historical peak demand for electricity,185 most common aggregate limits fall between 0.2%186 and 9.0%.187 Vermont and Utah’s Rocky Mountain Power Utility have substantially higher limits, 15% and 20%, respectively.188

179 DISTRIBUTED GENERATION: AN OVERVIEW OF RECENT POLICY AND MARKET DEVELOPMENTS, supra note 2, at 3. 180 LARRY SHERWOOD, INTERSTATE RENEWABLE ENERGY COUNCIL, U.S. SOLAR MARKET TRENDS 2013, at 15 (2014), available at http://provisiontechnologies.com/wp‐content/uploads/2014/07/Final‐Solar‐Report‐7‐3‐14‐W‐21.pdf; pg. 15 181 Id. at 16. 182 ELIZABETH DORIS, ET AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A246670, NET METERING POLICY DEVELOPMENT IN MINNESOTA: OVERVIEW OF TRENDS IN NATIONWIDE POLICY DEVELOPMENT & IMPLICATIONS OF INCREASING THE ELIGIBLE SYSTEM SIZE CAP 11 (2009). 183 SHERWOOD, supra note 190, at 4; LORI BIRD ET AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A20‐60613, REGULATORY CONSIDERATIONS ASSOCIATED WITH THE EXPANDED ADOPTION OF DISTRIBUTED SOLAR 13 (2013), available at http://www.nrel.gov/docs/fy14osti/60613.pdf (demonstrating that the smaller the installed generator, the slower the return on investment). 184 See DATABASE OF STATE INCENTIVES FOR RENEWABLES & EFFICIENCY (“DSIRE”), NET METERING STATE DATABASE, http://programs.dsireusa.org/system/program?type=37& (last visited June 20, 2015). 185 Aggregate capacity limits vary widely. Best Practices, supra note 24, at 15‐16. Some states, like Arizona and Colorado, have no limit on total program capacity. Id, at 29, 34. Georgia caps its net metering at only 0.2% of a utility’s peak demand. Id. at 43. Illinois and Indiana have caps of 1% of peak demand, id. at 46‐48, and California and Delaware have caps of 5%. Id at 32, 38. Rather than expressing an aggregate capacity limit as a percentage, Maryland’s aggregate capacity limit is fixed at 1,500 MW. Id. at 54. Similarly, New Hampshire’s aggregate capacity limit is 50 MW, id. at 65‐66, and Nevada’s aggregate capacity limit is 235MW. S.B. 374, 78th Leg. (Nev. 2015). Moreover, instead of limiting aggregate capacity on a per‐utility basis, the aggregate capacity limit in Maryland, New Hampshire, and Nevada are calculated on the number of net metered generators statewide. Best Practices, supra note 24, at 54, 65‐66. S.B. 374, 78th Leg. (Nev. 2015). 186 GA. CODE ANN. § 46‐3‐50 (2002). 187 MASS. GEN. LAWS ANN. ch. 164, § 1G (West 1998). 188 VT. STAT. ANN. tit. 30, § 219a (West 1998); UTAH CODE ANN. § 54‐15‐101 (West 2002).

24

A sixth variation among net metering programs is whether “shared” renewable projects are eligible for participation.189 In contrast to standard net metering, where on‐site generators like owners of rooftop solar panels provide electricity and financial benefit to a single utility customer, shared renewable arrangements allocate electricity or utility reimbursement among multiple customers from a jointly financed or owned generator.190 Shared renewable arrangements are generally categorized as either “virtual” net metering and “community” net metering policies.191 Even though these terms are sometimes used interchangeably, they refer to distinct net metering arrangements.192 Customers participating in virtual net metering, usually residents of multi‐tenant buildings, typically reap benefits of a system installed within, or nearby, the facility and directly connected to the meter of at least one participant.193 On the other hand, participants of community solar arrangements need not be located on the same or even contiguous properties, nor do they need to be directly connected to the renewable system.194

According to the National Renewable Energy Laboratory, only 27% of all residential rooftop area is suitable for hosting an on‐site photovoltaic system.195 Shared solar projects offer access to the environmental and net metering benefits of distributed generation to utility customers who may be unable to host their own generator on‐site, and among low‐income utility customers.196 Today, only 1% of distributed solar is “shared” through either community or virtual net metering programs,197 and only eleven jurisdictions explicitly allow shared net metering;198 though additional states have developed

189 J. HEETER, ET AL., supra note 46, at 8. 190 . INTERSTATE RENEWABLE ENERGY COUNCIL, MODEL RULES FOR SHARED RENEWABLE ENERGY PROGRAMS 5 (2013), available at http://www.growsolar.org/wp‐content/uploads/2014/04/IREC‐Model‐Rules‐for‐Shared‐Renewable‐Energy‐ Programs‐2013.pdf. 191 See ARIZONA STATE UNIV. ENERGY POLICY INNOVATION COUNCIL, COMMUNITY, VIRTUAL & AGGREGATE NET METERING, OH MY! A LOOK AT NET METERING VARIATIONS AROUND THE COUNTRY, INCLUDING ARIZONA (2014), available at https://energypolicy.asu.edu/wp‐content/uploads/2014/01/Community‐Virtual‐and‐Aggregate‐net‐metering‐ brief‐sheet.pdf 192 Id. at 2‐3. 193 Id. 194 Id. 195 PAUL DENHOLM & ROBERT MARGOLIS, NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A0‐44073, SUPPLY CURVES FOR ROOFTOP SOLAR PV‐GENERATED ELECTRICITY FOR THE UNITED STATES 4 (2008), available at http://www.nrel.gov/docs/fy09osti/44073.pdf. 196 Id. 197 SHERWOOD, supra note 190, at 14. 198 See DAVID FELDMAN, ET AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A20‐63892, SHARED SOLAR: CURRENT LANDSCAPE, MARKET POTENTIAL, AND THE IMPACT OF FEDERAL SECURITIES REGULATION app. at 41‐44 (2015), available at http://www.nrel.gov/docs/fy15osti/63892.pdf.

25 community solar projects without specific authorizing legislation.199 If made available nationwide, shared solar could represent as much as 32% of distributed solar market by 2020.200

A seventh and final variation among net metering policies is the permissibility of third‐party ownership of net‐metered generators. In recent years, third‐party ownership of distributed generators emerged as a useful tool to finance installation and maintenance costs associated with rooftop solar.201 Under this ownership model, customers enter a “purchase power agreement” with third parties that agree to pay installation and life‐time expenses of a solar generator. In exchange, the customer agrees to host the generator and to purchase any electricity generated by the system. The use of third‐party ownership arrangements within distributed generation markets has grown substantially since the creation of the federal Incentive Tax Credit under the 2005 Energy Policy Act, which offers up to a 30% offset against a solar generator installation cost.202 Third‐party solar ownership and power purchase agreements are permitted in twenty‐four states and the District of Columbia.203 By 2013, 66% of all domestic residential solar generation, as measured by total capacity, was third‐party owned.204

The differences among net metering policies can significantly affect the attractiveness of distributed generation to utility customers. Over 72% of net metered distributed generation systems are located in states with favorable net metering policies – states that offer greater individual or aggregate capacity limits, longer carry‐over provisions, broader eligibility of community solar projects, and higher reimbursement rates.205 New Jersey provides a powerful illustration of the influence a favorable net metering policy can have on distributed solar installations. New Jersey imposes no limit on the aggregate capacity of net‐metered generators statewide;206 permits unlimited carry‐over of

199 Jocelyn Durkay, Net Metering: Policy Overview and State Legislative Updates, NAT’L CONFERENCE STATE LEGISLATURES (Sept. 26, 2014), http://www.ncsl.org/research/energy/net‐metering‐policy‐overview‐and‐state‐legislative‐ updates.aspx#action. See also, J. HEETER, ET AL., supra note 46, at 7. 200 FELDMAN, ET AL., supra note 209, at 32. 201 Best Practices, supra note 24, at 21. 202 KATHARINE KOLLINS, ET. AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A2‐46723, SOLAR PV PROJECT FINANCING: REGULATORY AND LEGISLATIVE CHALLENGES FOR THIRD‐PARTY PPA SYSTEM OWNERS 2, 22 (2010), available at http://www.nrel.gov/docs/fy10osti/46723.pdf. 203 DSIRE, 3RD PARTY SOLAR PV PURCHASE AGREEMENT, March 2015, available at http://ncsolarcen‐ prod.s3.amazonaws.com/wp‐content/uploads/2015/01/3rd‐Party‐PPA_0302015.pdf. 204 Mike Munsell, Market Share for Leasing Residential Solar to Peak in 2014, GREENTECH MEDIA, June 24, 2014, http://www.greentechmedia.com/articles/read/Market‐Share‐for‐Leasing‐Residential‐Solar‐to‐Peak‐in‐2014. 205 See Best Practices, supra note 24, at 7; cf. JASON B. KEYES & JOSEPH F. WIEDMAN, INTERSTATE RENEWABLE ENERGY COUNCIL, A GENERALIZED APPROACH TO ASSESSING THE RATE IMPACTS OF NET ENERGY METERING 3(2012), available at http://www.solarabcs.org/about/publications/reports/rateimpact/pdfs/rateimpact_full.pdf. 206 Best Practices, supra note 24, at 66–67..

26 excess generation during a twelve‐month period;207 has a renewable portfolio standard with a specific solar energy requirement;208 and offers rebates to individuals that install solar generators.209 Although New Jersey ranks eighteenth in annual sunlight hours, making it theoretically an unlikely candidate for widespread adoption of distributed generation, because of these policies the state nevertheless accounts for 12% of all national net‐metered capacity.210

D. Current State Reconsideration of Net Metering Policies

In response to the growth of solar distributed generation, and subsequent utility alarm over shrinking customer base and revenue attrition,211 states and utilities are reconsidering how net metering programs are designed.212 During the first quarter of 2015 alone, over thirty changes to existing programs were considered across nineteen states and the District of Columbia.213 While most reforms seek to limit the attractiveness of net metering, primarily as a response to utility alarm over declining revenues,214 some reforms are actually expanding net metering in an attempt to encourage further distributed generation development.215

A primary driver behind net metering reform efforts is recovery of utility “fixed costs”— expenses associated with back‐office administration and grid maintenance that are not avoided when consumers self‐generate.216 Traditionally, utilities recover a substantial share of these fixed costs through volumetric rates based on total kilowatt‐hours of electricity customers purchase.217 As a growing number of utility customers turn to on‐site solar generation in order to satisfy or supplement

207 N.J. Admin. Code § 14:8‐4.2 (2008). 208 New Jersey’s renewable portfolio standard required statewide utilities provide, collectively, 305GWh of solar energy in 2011, and will require statewide utilities provide, collectively, over 5,000GWh of solar energy by 2026. SHERWOOD, supra note 190, at 15. 209 Rebates for New Jersey customers totaled $2.4 million in 2012. In that year, 17MW of new solar distributed generation capacity was installed. SHERWOOD, supra note 190, at 15. 210 CURRENT RESULTS, AVERAGE ANNUAL SUNSHINE BY STATE, http://www.currentresults.com/Weather/US/average‐ annual‐state‐sunshine.php (last visited on July 17, 2015); cf. KEYES & WIEDMAN, supra note 234, at 3. 211 JAQUELIN COCHRAN, ET AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A00‐53732, INTEGRATING VARIABLE RENEWABLE ENERGY IN ELEC. POWER MARKETS: BEST PRACTICES FROM INT’L EXPERIENCE 1 (2012), available at http://www.nrel.gov/docs/fy12osti/53732.pdf. 212 KIND, supra note 51, at 3. 213 50 States Q1 2015, supra note 24, at 8. 214 COCHRAN, ET AL., supra note 240, at 1. 215 J. HEETER, ET AL., supra note 46, at 8. 216 Best Practices, supra note 24, at 12. 217 STEVE MITNICK, BUILD ENERGY AM., CHANGING USES OF THE ELECTRIC GRID: RELIABILITY CHALLENGES AND CONCERNS xvi (2015), available at http://www.emrf.net/uploads/3/1/7/1/3171840/emrf_business_models_final_web_version.pdf.

27 electricity usage, fixed costs are subsequently recovered in fewer kWh sales.218 Common net metering reforms can be loosely distinguished between attempts to introduce additional or different means of compensation instead of net metering, like a lower feed‐in tariff, and reforms that restructure parts of net metering policy or impose fees on net metering customers, but leave the core net metering policy in place.

In 2014, utilities in Arizona and Hawaii, and Colorado filed proposals with state regulatory commissions that sought to reduce compensation for new distributed generation customers below the retail rates.219 The same year, the Arkansas legislature proposed a change that would require net metering rates be set for each customer at no greater than the level necessary to ensure total cost recovery for utility grid service.220 In Wisconsin, a regulatory decision that would have reduced net metering credit to avoided cost levels was overturned by a circuit court.221 California’s largest three utilities have each proposed cutting net metering rates from their current level between $0.18 and $0.30 per kilowatt hour to a range between $0.04 and $0.21.222 Moreover, the California utility proposals also called for imposing a floor on monthly utility bills between $10 and $29 per‐month, which would require utility customers to pay the established floor even in months where their bill would fall below that level because of net metering credit.223

A number of states have considered or introduced wholesale changes in how they credit distributed generation. One alternative to net metering, known as a feed‐in‐tariff, is offered in twenty‐ one states,224 and is the most widely used policy for renewable energy outside of the U.S.225 Currently, nearly all feed‐in tariff programs in the United States are offered merely as an alternative to net

218 Id. 219 Arizona: Proposal of Tucson Electric Power Co., No. E‐01933A‐15‐0100 (filed Mar. 2015), available at http://edocket.azcc.gov/Docket/DocketDetailSearch?docketId=18945#docket‐detail‐container1; Proposal of USNS Electric, Inc., No. E‐04204A‐15‐0099 (filed Mar. 25, 2015; proposal withdrawn Apr. 28, 2015), available at http://edocket.azcc.gov/Docket/DocketDetailSearch?docketId=18944#docket‐detail‐container1. Hawaii: No. 2014‐ 0192; Krysti Shallenberger, Colorado utility wades into net‐metering debate, EE NEWS, June 16, 2015, http://www.eenews.net/energywire/stories/1060020274/feed. 220 H.B. 1004, 90th Gen. Assemb., Reg. Sess. (Ark. 2015). 221 Renew Wisconsin v. Pub. Serv. Comm'n, Case No. 2014‐CV‐0000169 (Decision Feb. 2015). 222 Debra Kahn, ‘Net Metering 2.0’ Redraws Familiar Fault Lines, E&E PUBLISHING, Aug. 6, 2015. 223 Id. 224 EIA, Feed‐in Tariffs & Similar Programs, supra note 24. 225 TOBY D. COUTURE, ET AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP=6A2‐44849, A POLICYMAKER’S GUIDE TO FEED‐IN TARIFF POLICY DESIGN 1 (2010), available at http://www.nrel.gov/docs/fy10osti/44849.pdf.

28 metering; leaving individual utility customers the final choice whether to receive credit under net metering or a feed‐in tariff.226

Functionally, feed‐in tariff programs bifurcate a utility customer’s on‐site production from their electricity usage.227 Utility customers participating in feed‐in tariff programs purchase all of their electricity from utilities at normal retail rates and sell all of their output at the offered “feed‐in tariff” rate.228 The offered feed‐in tariff rate is calculated to reflect the cost, to a utility customer of installing and maintaining a distributed generator—plus a small profit on the generated electricity.229 In contrast, net metering allows utility customers to credit their on‐site electricity production toward their bill, which effectively prices power from distributed generation sources at an identical rate to power generated by utilities and delivered to consumers.

A related alternative, known as a “value‐of‐solar” tariff, has been adopted in just two jurisdictions, but is currently pending in a third. In 2014, Minnesota joined the city of Austin, Texas, and notably became the first state, to offer a “value‐of‐solar” tariff.230 Like feed‐in tariff policies, value‐of‐ solar programs require customers purchase all of their electricity from utilities and sell all of their output at a specified rate—the “value‐of‐solar” rate.231 However, in contrast to feed‐in tariffs programs, which attempt to estimate value of solar energy to customers by basing rates on the costs of generation plus a “reasonable” return,232 value‐of‐solar programs estimate the value of solar generation to a utility by basing rates on environmental benefits and mitigated distribution costs in addition to generation costs.233 Generally, because environmental benefits and mitigated distribution costs—particularly costs associated with lost energy due to inefficient grid transmission—can be significant, value‐of‐solar tariffs typically promise distributed solar customers a greater return than feed‐in tariff programs.234 For example, under Minnesota’s preliminary value of solar estimate, as well as a study from the National Renewable Energy Laboratory, environmental and distribution components can represent 24% of the

226 EIA, Feed‐in Tariffs & Similar Programs, supra note 24. The only states that offer only a feed‐in tariff, but not net metering, are Alabama, Mississippi, and Tennessee. Id. The feed‐in tariff offered in these states is sponsored by the Tennessee Valley Authority utility rather than state legislative or policy action. Id. 227 Id. at 6. 228 Id. at 6. 229 MIKE TAYLOR, ET AL., NAT’L RENEWABLE ENERGY LAB., NREL/TP‐6A20‐62361, VALUE OF SOLAR: PROGRAM DESIGN & IMPLEMENTATION CONSIDERATIONS 6 (2015), http://www.nrel.gov/docs/fy15osti/62361.pdf. 230 H.F. 729, 88th Leg., 4th Engrossment, (Minn. 2013); Farrell, supra note 33. 231 TAYLOR, ET AL., supra note 257, at v. 232 TAYLOR, ET AL., supra note 257, at 6. 233 EIA, Feed‐in Tariffs & Similar Programs, supra note 24. 234 EIA, Feed‐in Tariffs & Similar Programs, supra note 24.

29 value‐of‐solar rate.235 Those costs are not reflected in feed‐in tariff rates. At the moment, Minnesota’s value‐of‐solar program is voluntary; meaning utilities may choose whether to credit customers at the value‐of‐solar rate or through traditional net metering.236

On June 30, 2015, Maine lawmakers passed value‐of‐solar legislation over a governor veto.237 Like Minnesota, the proposed value‐of‐solar rate in Maine incorporates a value for “avoided

238 environmental costs;” defined as avoided carbon dioxide (CO2), sulfur dioxide (SO2), and nitrous 239 oxides (NOx) emissions. To value avoided emissions for each pollutant, the Maine state utility commission relied on EPA‐generated estimates of each pollutant’s “social cost.” 240 Maine determined environmental benefits, in the form of these reduced emissions, were equal to $0.083 per‐kWh in 2016. Over the next twenty‐five years, Maine placed the value of “avoided environmental costs” at $0.096 per‐kWh.241

The total value‐of‐solar rate offered to distributed solar customers in Maine—including environmental benefits, avoided generation, transmission, and distribution expenses, and social benefits like avoided fuel price uncertainty—is estimated at $0.182 per‐kWh in 2016 and $0.337 per‐kWh over the next 25 years.242 Although the Maine Distributed Solar Valuation Study includes projections for rates in 2016, there is currently no official start date on which the value‐of‐solar rate would take effect.

The only other value‐of‐solar tariff program in the United States was adopted by Texas utility Austin Energy in 2012.243 Since its inception, the value‐of‐solar rate offered by Austin Energy has been readjusted downward twice, reflecting declining generation costs for natural gas power plants, and the

235 TAYLOR, ET AL., supra note 257, at 22. 236 H.F. 729, Art. 9, subd. 10, 88th Leg., 4th Engrossment, (Minn. 2013). See also Dan Haugen, Minnesota Becomes First State to Set ‘Value of Solar’ Tariff, MIDWEST ENERGY NEWS (Mar. 12, 2014), http://midwestenergynews.com/2014/03/12/minnesota‐becomes‐first‐state‐to‐set‐value‐of‐solar‐tariff/. 237 H.P. 863, 127th Leg., 1st Reg. Sess. (Me.2015); Maine – LD 1263, Am. Energy Leg. Tracker, http://www.aeltracker.org/bill‐details/10169/maine‐2015‐ld‐1263 (last accessed August 5, 2015). 238 MAINE PUB. UTIL. COMM’N, MAINE DISTRIBUTED SOLAR VALUATION STUDY, at 34 (March 1, 2015), available at http://www.nrcm.org/wp‐content/uploads/2015/03/MPUCValueofSolarReport.pdf. 239 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note 266, at 34. 240 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note 266, at 34‐36. 241 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note 266, at 50. 242 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note 266, at 50. 243 News, Austin Energy, New Value of Solar Rate Takes Effect January, (last accessed July 17, 2015), https://austinenergy.com/wps/portal/ae/about/news/press‐releases/2013/new‐value‐of‐solar‐rate‐takes‐effect‐ january/!ut/p/a1/jZBNT4NAEIZ_iweOy04Xq‐ iNokGsSDwUVy5m2gwfSnfJ7rak_nppvKhptXOb5Hneyby85JKXCrdtja7VCrv9Xl68ggjFXQwiTS5FCFESz‐ bT4nFylYkRePkO5Lf5DaRFXkT5PIYkDk70j0wE__n3JxwQJouzmpc9uoa1qtJc9oasZYY6QkuWSwGTgEtFA9tityGmK2Z1 h4YZdMQcvpNlVFW0cuwN1QbNbh8cqWUQjsGGKjJk_I0ZG2uc6‐21Bx4Mw‐DXWtcd‐ Su99uCQ0mjruPxJ8mde_vXWE5z_Bg70_gUcL7ZfL‐THw2y63AXQptHZJ7MRshI!/dl5/d5/L2dBISEvZ0FBIS9nQSEh/

30 current rate is $0.02/kWh lower than when initially offered. Nevertheless, under the offered value‐of‐ solar program, Austin has experienced remarkable growth among residential solar installations, jumping from approximately 6,000kWh annual generation from distributed generators in 2011 to over 20,000kWh by year‐end 2014.244

However, value‐of‐solar programs have generated a number of lingering and unanswered questions. For one, Minnesota has not yet addressed whether its voluntary value‐of‐solar tariff would accommodate third‐party ownership, and third‐party systems are currently excluded from Austin Energy’s policy. Maine has also not addressed whether third‐party owned distributed generation would be eligible for the value‐of‐solar rate.245 Yet, third‐party or utility‐owned units comprise a large and growing portion of distributed solar.246 Furthermore, defining what factors are (or should be) used to calculate the value‐of‐solar rate, and uncertainty over yearly fluctuation in offered rates, both remain open concerns.247

Frequent targets of change are individual and aggregate capacity limits.248 While no state had an aggregate net metering cap greater than 1% before 2005, the average cap as of 2015 is near 4%.249 Fourteen jurisdictions have raised aggregate caps at least once since 2004250 and, according to the National Renewable Energy Laboratory, all but three states – Illinois, Maryland, and Georgia – are on track to reach current aggregate caps by 2018.251

Since 2014 alone, four jurisdictions have adopted measures to increase aggregate caps; Rhode Island notably eliminated its aggregate cap altogether.252 Among the three additional states also implementing higher aggregate caps, Vermont’s 9% cap increase was the largest, while Massachusetts increased its cap the least, a 2% escalation.253 In addition, four jurisdictions have increased individual

244 Farrell, supra note 33. 245 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note 266, at 141. 246 Kristi E. Swartz, Southern Co. goes all in on solar, storage, smart homes, EE NEWS, May 28, 2015, http://www.eenews.net/energywire/stories/1060019211/feed. 247 See Farrell, supra note 33. 248 Id. at 8. 249 Id. at 10. 250 Id. at 8. 251 Id., at 25. 252 Rhode Island Tariff Advice Filing to Amend RIPUC No. 2099, Docket No. 4549 (R.I. Nat'l. Grid 2015) (removed cap for all utilities except for Block Island Power Company and Pascoag Utility District). Other individual cap increases are: New York, Order, Case Nos. 14‐E‐0422 & 14‐E‐0151, (N.Y. Pub. Serv. Comm'n 2014); Massachusetts, H.B. 4385, 188th Leg., (Mass. 2014); and Vermont, H.B. 702, Gen. Assemb. (Vt. 2014). 253 Massachusetts, H.B. 4385, 188th Leg., (Mass. 2014); and Vermont, H.B. 702, Gen. Assemb. (Vt. 2014).

31 capacity limits,254 while only one state, Kansas, reduced its limit.255 Of the jurisdictions increasing individual capacity, the greatest growth came from Montana, which increased its limit from 50 kW to 1 MW.256

Shared renewable projects, particularly community and virtual net metering, remain viable in only a few jurisdictions. However, since 2008, at least twelve jurisdictions considered nineteen policy initiatives relating to community or virtual metering.257 Specifically, California extended virtual metering eligibility from residents of affordable housing units to all multi‐tenant properties;258 while Connecticut and New Hampshire authorized virtual metering for the first time.259 Ten states proposed or adopted measures regarding community metering, with five states authorizing the practice for the first time,260 and four states proposing measures to adopt community metering or increase capacity limits imposed on current projects.261 One state, Colorado, increased the capacity limit posed on existing community net metered projects, from 6 MW to 30 MW.262 Several states do not have individual community metering caps at all. Minnesota, for example, is considering a proposal that would limit aggregate community metered projects to 80 MW.263 Lastly, Austin Energy, a Texas utility that offers a value‐of‐

254 H.B. 1004, 90th Gen. Assemb., Reg. Sess. (Ark. 2015); H.B. 1004, 90th Gen. Assemb., Reg. Sess. (Ark. 2015); S.B. 182, 64th Leg., (Mont. 2015); Second Entry Rehearig, 12‐2050‐EL‐ORD (Ohio Pub. Util. Comm'n 2014). 255 H.B. 2101, 2014 Leg., (Kan. 2014) (reducing limit from 25kW to 15kW for systems built after July 1, 2014, retaining existing levels for current net metering customers). Arkansas bill H.B. 1004 imposed a “limit” on residential NEM customers of 100% of the highest monthly usage in the previous 12 months. H.B. 1004, 90th Gen. Assemb., Reg. Sess. (Ark. 2015). 256 S.B. 182, 64th Leg., (Mont. 2015). 257 See 50 States Q1 2015, supra note 24; Best Practices, supra note 24; 50 States Q4 2014, supra note 24; JIM KENNERLY, NC CLEAN TECH. CTR., RETHINKING STANDBY & FIXED COST CHARGES: REGULATORY & RATE DESIGN PATHWAYS TO DEEPER SOLAR PV COST REDUCTIONS (2014), http://nccleantech.ncsu.edu/wp‐content/uploads/Rethinking‐Standby‐and‐Fixed‐ Cost‐Charges_V2.pdf; Durkay, supra note 210. 258 Cal. Solar Initiative Phase One Modifications, Rulemaking 10‐05‐004 (Calif. Pub. Util. Comm’n May 6, 2010). 259Conn. Gen. Stat. § 16‐244u (2011); Pub. Act. No.13‐298, Gen. Assemb., (July 8, 2013). 260 S.B. 43, 2013 Leg., (Cal. 2013); Final Rulemaking, RM41‐2015‐01 (D.C. Pub. Serv. Comm'n May 8, 2015); S.B. 1050, 28th Leg., (Haw. 2015); Order, Docket No. U‐17752 (Mich. Pub. Serv. Comm'n May 14, 2015); H.F. 729, 88th Leg., 4th Engrossment, (Minn. 2013). 261 S.B. 182, 64th Leg., (Mont. 2015); Tariff Advice Filing, Docket No. 4549, (R.I. Nat'l Grid Feb. 2, 2015); H.B. 702, Gen. Assemb. (Vt. 2014); Press Release, Governor Andrew Cuomo, Governor Cuomo Announces New Clean Energy Initiatives (Dec. 12, 2014), available at http://www3.dps.ny.gov/pscweb/WebFileRoom.nsf/ArticlesByCategory/36F091B6F183D53A85257DAC006A758F/ $File/gov%2012.12.14.pdf?OpenElement. 262 Decision Approving Renewable Energy Standard Compliance Plan & Exceptions to Decision No. R14‐0902, Decision No. C14‐1505, Proceeding No.13A‐0836E (Colo. Pub. Serv. Comm'n Nov. 24, 2014). 263 Comments, Docket No. E002/M‐13‐867, (Minn. Pub. Util. Comm’n Feb. 10, 2015); retrieved at https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={AE9 FC948‐4354‐49EF‐A3CF‐32AD59E11424}&documentTitle=20152‐107208‐01.

32 solar tariff in place of net metering, recently announced plans to introduce a community solar project, the first under an alternative compensation system.264

II EVALUATING THE CONTRIBUTIONS OF DISTRIBUTED GENERATION TO THE ELECTRIC GRID

A. Benefits of Distributed Generation

The clearest benefit of distributed generation is that it “avoids” the cost of the energy that would have had to be generated by a bulk system generator to meet customer demand. Installing a distributed generation system reduces the amount of energy that a customer needs from the grid, and this reduced demand leads to savings in the amount of what it would have cost the bulk system to produce this energy. These avoided costs are driven by the variable costs of the marginal resource that is being displaced, which depends on that resource’s fuel prices, variable operation and maintenance costs, and efficiency.265 Although some utilities question the ability of intermittent distributed generators to cover customer demand reliably enough to produce meaningful reductions in fuel costs,266 a study by Arizona Public Service estimated the utility’s savings from avoided fuel purchases were equivalent to $0.08 per kWh.267 As the national average retail rate is $0.12 per kWh, reduced fuel expenses present a potentially enormous source of savings.268

Distributed generation also provides certain benefits due to its “distributed” nature such as lower line losses because electricity travels shorter distances between the generator and the end user. Thus, a significant portion of distributed generation’s value comes from the location of production.269 To the extent that locally placed distributed generators can satisfy nearby demand, they displace utility expenditures transmitting electricity,270 and maintaining grid capacity and reliability.271 Up to 8% of a

264 Edward Klump, Austin Energy aims to expand solar and storage with community project, EE NEWS, June 5, 2015, http://www.eenews.net/energywire/stories/1060019712/feed. 265 RMI BCA study at 14 266 Navigant Consulting, Distributed Generation Study, for NV Energy, 2010. 267 R.W. Beck, Inc., Distributed Renewable Energy Operating Impacts & Valuation Study, for Arizona Public Service, 2009. 268 Energy Info. Admin., Table 5.6.A. Average Retail Price of Electricity to Ultimate Customers by End‐Use Sector, (Nov. 20, 2013), http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_5_6_a. 269 Jim Lazar, Recognizing the Full Value of Energy Efficiency, RAP 9 (2013). 270 Department of Energy. “The Potential Benefits of Distributed Generation and Rate‐Related Issues that may Impede their Expansion—A Study Pursuant to Section 1817 of the Energy Policy Act Of 2005.” February 2007. http://www.ferc.gov/legal/fed‐sta/exp‐study.pdf.

33 utility’s total generated output may be lost in‐transit because of inefficient power lines.272 Distributed generators stationed physically closer to end‐users directly curtail these energy losses,273 and may save utilities from yearly spending on distribution system improvements that can run as high as $96.00 for every kW of line capacity added.274

In addition to these immediate benefits, distributed renewables offer long‐term economic cost savings by enabling utility and state entities to defer, or altogether avoid, large capital investments in new fossil‐fuel generators and transmission infrastructure.275 By decreasing the demand for power generation from traditional plants, distributed generation reduces the need for investments to provide additional generating capacity. Further, it reduces the strain on the current capacity when solar generation occurs in times of high demand. While estimates of long‐term cost savings place the value of this benefit as high as $0.02 per‐kWh,276 distributed generation systems must be integrated into the grid planning process for these benefits to be realized.277

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B. Costs

The costs of distributed generation go beyond the costs of installing new meters that can measure the flow of electricity in both directions and ensuring interconnection standards for safe grid integration. Accommodating non‐synchronous generation, variable and unpredictable output, and two‐ way power flows all present challenges, and expenses. The introduction of two‐way power flow into the current grid may adversely affect the grid, leading to increased flow management and voltage regulation

271 Hoke, Anderson, and Paul Komor. (2012). “Maximizing the Benefits of Distributed Photovoltaics.” Electricity Journal, 25(3), 1040‐6190. doi:/10.1016/j.tej.2012.03.005; pgs. 55‐61 272 Daniel S. Shugar, Photovoltaics in the Utility Distribution System: The Evaluation of System and Distributed Benefits, IEEE PHOTOVOLTAIC SPECIALISTS CONFERENCE, Apr. 1990, at 836–843; U.S. Dept. of Energy, The Potential Benefits of Distributed Generation and Rate‐Related Issues that May Impede Their Expansion, 2007. 273 R.W. Beck, Inc., Distributed Renewable Energy Operating Impacts & Valuation Study, for Arizona Public Service, 2009. 274 Jim Lazar, Recognizing the Full Value of Energy Efficiency, RAP 39 (2013). 275 Anderson Hoke, Maximizing the Benefits of Distributed Photovoltaic, 3 Electricity Journal 25, 57 (2012). 276 R.W. Beck, Inc., Distributed Renewable Energy Operating Impacts & Valuation Study, for Arizona Public, Service, 2009. 277 U.S. Dept. of Energy, The Potential Benefits of Distributed Generation and Rate‐Related Issues that May Impede Their Expansion, (2007).

34 costs.278 Unregulated two‐way flow may overload the circuits close to the distributed generator, which might not be able to handle the temporary high flow volume.279 Furthermore, an unexpected reverse energy flow may jeopardize the safety of the utility workers.280

While most distributed generators are connected to the grid, and therefore free to draw electricity or feed in excess generation, they are not integrated into the operation or long‐term planning of the grid’s infrastructure.281 The intrinsically variable output of distributed wind or solar generators can hamper the grid’s reliability and interfere with maintaining efficient the grid’s efficient operation.282

An important advantage of solar generation over conventional fossil‐fuel power plants is the relative inexhaustibility of sunlight. However, that dependence on sunshine inescapably means distributed solar generators are subject to variable and patterned output – greater production occurring seasonally in summer months and diurnally in the early afternoon, but dipping in winter and the evening.283 Consequences of intermittent generation are compounded by inadequate storage options for electricity that is generated but not immediately consumed;284 meaning that even as total electricity production achieves parity with customer monthly usage, the actual need may not correspond with moments of production.285 Instead, whenever distributed generators fail to satisfy on‐site energy demands, net metering customers still draw on conventional grid‐supplied electricity.286 In fact, distributed solar customers may depend on utility‐supplied power to supplement or meet their usage sixteen hours a day (including evening hours when consumption is low).287

278 See ELEC. POWER RESEARCH INST., THE INTEGRATED GRID: REALIZING THE FULL VALUE OF CENTRAL AND DISTRIBUTED ENERGY RESOURCES 14 (2014) available at http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=3002002733. 279 Id. 280 Rebuttal Testimony of Ashley C. Brown on Behalf of Wisconsin Electric Power Company, Wis. P.S.C. Docket No. 05‐UR‐107, REBUTTAL‐WEPCO/WG‐BROWN at 33 (Sept. 12, 2014). 281 The Integrated Grid, Elec. Power Research Inst. 8 (2014) 282 TANTON, supra note, at 4. 283 N. AM. ELEC. RELIABILITY CORP., ACCOMMODATING HIGH LEVELS OF VARIABLE GENERATION, (SPECIAL REPORT) 24 (2009) [hereinafter NERC Report] , available at http://www.nerc.com/files/IVGTF_Report_041609.pdf. 284 Id. at 2. 285 David Raskin, Getting Distributed Generation Right: A Response to ‘Does Disruptive Competition Mean a Death Spiral for Electric Utilities?’, 35 Energy L.J. 263, 266 (2014). 286 TANTON, supra note, at 9. 287 Edison Elec. Inst., cited in Tom Tanton, Reforming Net Metering: Providing a Bright and Equitable Future, Am. Legis. Exch Council 10 (March 2014).

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Moreover, net‐metered customers impose additional strains on electric grid by introducing two‐ way power flows whenever they sell excess generation back to utilities.288 Transmission lines were originally intended to accommodate one‐way delivery of electricity from large‐scale power plants to end‐use consumers. Coping with bidirectional or reverse current, as is necessary to deal with distributed generation, can overload grid circuits or harm utility employees working near power lines.289 In spite of sustained reliance on grid‐delivered electricity and introducing new demands on grid infrastructure, net metered customers are not generally charged additional service charges. In fact, because the retail rate offered in most net metering programs will reimburse distributed generation customers for transmission expenses they do not incur exporting electricity back into the grid, these individuals may only pay for a portion of their actual grid use.290

The inability to store electricity on a large scale requires customer usage be met in real‐time by utility generation.291 This dynamic places significant responsibility on utilities and grid operators to ensure supply and demand are precisely balanced throughout the day.292 Significant mismatches between consumer demand and available power supply – commonly caused by sudden loss of bulk generator output – can cause grid frequency levels to drop,293 damage generator turbines, or if left unchecked, can even lead to blackouts.294 Increased distributed generation penetration may increase such costs related to balancing the supply and the demand in real time.295 Electricity suppliers need to react quickly to changes in electricity production to meet changes in the net electricity demand, and require resources with ramping296 flexibility and the ability to start and stop multiple times per day.297Although some utility‐scale solar power plants have installed frequency control mechanisms,

288 Am. Pub. Power Ass’n, Distrib. Generation: An Overview of Recent policy and Market Devs. 11 (2013) [hereinafter APPA, Recent policy and Market Devs.], available at http://www.publicpower.org/files/PDFs/Distributed%20Generation‐Nov2013.pdf; 289 Am. Pub. Power Ass’n, Distrib. Generation: An Overview of Recent policy and Market Devs. 11 (2013) [hereinafter APPA, Recent policy and Market Devs.], available at http://www.publicpower.org/files/PDFs/Distributed%20Generation‐Nov2013.pdf; 290 TANTON, supra note, at1. 291 Timothy P. Duane, Legal, Technical, and Economic Challenges in Integrating Renewable Power Generation into the Electricity Grid, 4 SAN DIEGO J. CLIMATE & ENERGY L. 1, 8 (2013). 292 Duane, 8. 293 ELA, supra note, at 1. 294 Id. at 1. 295 Fact Sheet, California Independent System Operator, What the Duck Curve Tells us About Managing a Green Grid 3 (2013) available at http://www.caiso.com/documents/flexibleresourceshelprenewables_fastfacts.pdf. 296 Id., at 2. 297 Id., at 4.

36 known as “smart inverters,”298 that can mimic the response of a traditional generator by curtailing or increasing (if possible) photovoltaic output, most residential distributed solar units lack this component part.299 In the absence of such a technological modification, grid managers must ensure traditional bulk‐ generators remain capable of providing the response necessary to prevent negative consequences.300 Such increases in the average operating costs of conventional plants resulting from frequent cycling is expected to increase as the degree of solar penetration increases.301

Another related challenge to integration is that distributed solar units, in contrast to central station power plants, are almost completely weather‐dependent, inherently intermittent, and cannot be intentionally fueled or controlled so that generation on meets consumer need.302 In the absence of reliable and affordable power storage systems, the intermittent and variable nature of solar power requires that electricity providers have adequate back‐up power. Output from distributed solar units can fluctuate as much as 50% within 90 seconds and 70% within just 5 minutes.303 Erratic changes in output makes matching electric generation and customer usage difficult;304 and can require other power plants – often those running on cheap brown coal305 – remain online simply to ensure adequate power is available to meet demand.306 Placing primary or back‐up responsibility for energy coverage on fossil‐fuel power plants can prompt their sustained use even with environmentally preferable sources available; doing little to reduce utility operational costs and forgoing environmental benefits offered by distributed generation.307 In addition to challenges associated with inadequate supply, large influxes of distributed solar energy in grid lines can raise voltage levels above grid capacity or create “reverse power flows” 308

298 ELA, supra note, at 3. 299 SEVERIN BORENSTEIN, THE U.S. ELECTRICITY INDUSTRY AFTER 20 YEARS OF RESTRUCTURING 22 n. 35 (2015). California stands as a notable exception to this rule, updating interconnection requirements for distributed PV units to require installation of smart inverters to provide local voltage and frequency support. CALIF. PUB. UTIL. COMM’N, Interim Decision Adopting Revisions to Electric Tariff Rule 21 for Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company to Require ‘Smart’ Inverters, Decision 14‐12‐035. San Francisco. 300 NERC Report, supra note, at 47. 301 MIT solar study at 186, also brattle utility scale vs residential scale comparative generation costs study 302 BORENSTEIN, supra note, at 22. 303 NERC Report, supra note, at 27. 304 NERC Report, supra note, at ii. 305 How to Lose Half a Trillion Euros, ECONOMIST (Oct. 12, 2013), http://www.economist.com/news/briefing/21587782‐europes‐electricity‐providers‐face‐existential‐threat‐how‐ lose‐half‐trillion‐euros. 306 BORENSTEIN, supra note, at 22. 307 Cochran, Grid Integration, supra note, at 3. 308 THE INTEGRATED GRID, supra note, at 13.

37 that can damage infrastructure.309 Bidirectional power flow may also present a safety hazard if utility employees working near grid lines are unaware distributed generation sources are feeding energy to the lines even though utility power ceased because of an emergency or planned outage.310

Increasing transmission line capacity, coordinating energy distribution across jurisdictions, incorporating advanced forecasting techniques into grid management, installing smart inverters on distributed solar units, and improving ramping capability of conventional generators may all mitigate uncertainties associated with integrating distributed generation systems.311 Because factors relevant to solar‐generation like sunrise, sunset, and solar noon times can be identified with certainty and theoretical production levels can be derived from historical patterns, solar energy is qualitatively more predictable than wind and integration costs, driven upward by intermittent and variable output, are therefore expected to be lower.312 Currently, to satisfy service obligations, incorporate new technologies and integrate distributed generators, the electric utility industry invests $100 billion each year. This price tag is likely to increase as the volume of distributed generation increases.313

III CONSIDERING THE SOCIAL BENEFITS OF DISTRIBUTED GENERATION

The increasing importance of integrating more renewable resource in achieving environmental and climate policy goals, combined with the recent rapid deployment of distributed generation systems warrant an assessment of distributed generation policies from a societal policy perspective. Unless all benefits and costs that accrue to the society as a whole are considered, the resulting policy would not be socially optimal. This means that not only the potential environmental and health benefits of cleaner energy, as the environmental groups advocate, should be taken into account in an ideal policy, but also grid related costs that result from bi‐directional energy flow,314 increased challenges of balancing supply

309 The Future of the Electric Grid, MIT INTERDISCIPLINARY STUDY 17 (2011), available at https://mitei.mit.edu/system/files/Electric_Grid_Full_Report.pdf. 310 APPA, RECENT POLICY AND MARKET DEVS., supra note, at 11. 311 Grid Integration and the Carrying Capacity of the U.S. Grid to Incorporate Variable Renewable Energy, pg. 2; J.Smith, M.Rylander, and W.Sunderman, "The Use of Smart Inverter Controls for Accommodating High‐Penetration Solar PV," in Distributech Conference and Exhibition, San Diego, CA, 2013. 312 IDAHO POWER, SOLAR INTEGRATION STUDY REPORT 16‐17 (2014), available at https://www.idahopower.com/pdfs/AboutUs/PlanningForFuture/solar/SolarIntegrationStudy.pdf 313 Raskin, Getting Distributed Generation Right, at 273. 314 MIT solar study

38 and demand, and intermittency and variability of distributed generation315 have to be considered as the utility groups have suggested.

Using a rate that does not take into account the external societal benefits would lead to too little distributed generation penetration compared to the socially optimal level. Using the retail rate or including monetized environmental and health benefits without taking into account the additional costs that distributed generation imposes on the grid would lead to too high distributed generation penetration compared to the socially optimal level. Thus, for a distributed generation policy to be most beneficial for the society overall, it should use an approach that consistently values all benefits and all costs of distributed generation including all the externalities.

Distributed generation offers a number of environmental and social benefits conferred to the general public.316 Public health and welfare improvements, water conservation efforts, and land preservation all benefit from declining greenhouse gas emissions and reductions in physical infrastructure necessary to support fossil‐fuel electricity generation.317 For example, public health benefits associated with reduced operating time of fossil‐fuel generators can exceed one‐third of a million dollars for each reduced ton of fine partial emissions.318 The National Research Council estimates the cost of adverse health effects attributed specifically to coal‐fired power plant emissions average $0.03 for every kWh of electricity generated.319 Other studies calculate total health or environmental expenses that stem from coal extraction and subsequent electricity generation average as much as $0.27 per‐kWh, and ultimately cost as much as one‐third to one‐half trillion dollars annually.320

[INSERT SOCIAL RESILIENCY BENEFITS]

As these external benefits are not reflected in current retail tariffs, current net metering policies are not sufficient to capture these values. If such benefits are not reflected in distributed generation policies, the realized adoption rates would be less than the socially optimal level. Only by properly internalizing such environmental and health benefits, we can ensure a socially beneficial level of distributed generation deployment.

315 MIT solar study 316 Review of Solar PV benefit and cost, pg. 13 317 Jim Lazar, Recognizing the Full Value of Energy Efficiency, RAP 50 (2013). 318 Office of Air & Reg., EPA, Estimating the Benefit per Ton of Reducing PM2.5 Precursors From 17 Sectors, at 13, Table 5 (2013). 319 National Research Council, Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use (2009). 320 Paul R. Epstein, Full Cost Accounting for the life Cycle of Coal, N.Y. Acad. Sci. ISSN 0077‐8923, at 1 (2011).

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A simple solution for correcting such market failures related to the existence of externalities would be to uniformly price in externalities in all energy resources. While such external benefits – like environmental and health gains associated with lower greenhouse gas emissions, efficient water consumption by power plants, and land‐use preservation – may be difficult to quantify, that does not justify counting these values as zero.321 Methodologies exist to estimate many of the external benefits of distributed energy resources,322 and a socially optimal distributed generation policy should reflect these best‐available monetization methodologies.

A. Incorporating Climate Change Benefits

In the absence of a uniform pricing for emissions, alternative mechanisms have to be considered. When the damages associated with carbon emissions are not included when calculating the cost of generating electricity, the benefits associated with avoided emissions as a result of distributed generation should be included in the remuneration of distributed generation. While several mechanisms are currently in effect to put a carbon price – a price that reflects the marginal damage caused by carbon emissions – into electricity generation, such as the Regional Greenhouse Gas Initiative,323 or to provide incentives for clean energy in other ways than pricing the benefits in, such as renewable portfolio standards,324 these efforts fall short of internalizing the full value of the damages caused by carbon emissions has been limited.325 Given that the current retail rates, even with these policy measures, do not reflect the full value of environmental costs, any compensation method for distributed generation should include an environmental component.

321 Cf. Ctr. for Biological Diversity v. Nat’l Highway Traffic Safety Admin., 538 F.3d 1172, 1200 (9th Cir. 2008) (“NHTSA's reasoning is arbitrary and capricious for several reasons. First, while the record shows that there is a range of values, the value of carbon emissions reduction is certainly not zero.”). 322 For example, a report prepared by Dr. Bruce Tonn at the Oak Ridge National Laboratory, which is expected to be released soon, calculates many non‐energy benefits of an energy conservation program, including health and productivity benefits. See NATIONAL ASSOCIATION OF REGULATORY UTILITY COMMISSIONERS, NARUC 2015 SUMMER COMMITTEE MEETINGS PROGRAM 17 (2015), available at http://summer.narucmeetings.org/2015_ Summer_Program‐Final.pdf. Also http://phys.org/news/2015‐09‐health‐benefits‐renewable‐energy.html http://ei.haas.berkeley.edu/research/papers/WP263.pdf#page=1?utm_source=New+Working+Paper+%23+263&u tm_campaign=WP263&utm_medium=email 323 Insert citation 324 Insert citation 325 Austin, Minnesota, and NYS REV proceedings, Maine

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1. Quantifying Avoided Emissions

The first step in valuing the climate change benefits of distributed generation is to calculate the amount of avoided emissions – the amount that a generator displaced by distributed generation would have emitted in the absence of the energy generated by the distributed generator. In this calculation, it is crucial to note that avoided emissions from distributed generation depend on the type of generator that the distributed generation is displacing, and thus heavily depend on the time and location of the energy generated.326 If solar generation is displacing a generator with low carbon emissions, such as a nuclear plant, the displaced carbon emissions would be low. If solar generation is displacing a coal‐fired plant, the displaced carbon emissions would be high. Similarly, external health benefits of distributed generation that results from lowering congestion vary with location.327

Consequently, any tariff that compensates distributed generation has to be granular enough to be able to account such variation, a missing quality in net metering policies. Thus, the amount of avoided greenhouse gases should be calculated depending on their time and location by looking at the quantity of carbon dioxide emissions that the generator displaced by a distributed generation would have emitted.

Accurately valuing emission benefits is vital to ensure the efficient allocation of resources among different investment alternatives, whether it is for distributed solar generation, other distributed energy resources or traditional utility investments. For example, an energy efficiency program is likely to reduce the bulk demand on average. Thus, calculating the quantity of avoided emissions using an average value would likely to lead to accurate estimates. However, the same is not true when distributed generation is considered. If the generator the distributed solar generation is replacing is dirtier than average, for example a peaker plant, the avoided emissions will be higher. If the temporal dimensions are not taken into account, and all distributed energy resources are rewarded based on the same average quantity of avoided emissions, then the market incentives will lead to more investment in

326 Siler‐Evans paper. For example, as natural gas is the dominant marginal fuel in California, the average carbon dioxide displacement by a solar panel there is lower than in more coal‐intensive states, such as Kansas.326 The environmental and health benefits depend, in part, on the location and timing of distributed generation. According to a study published in the Proceedings of the National Academy of Sciences of the United States of America, “[t]he average solar panel in Nebraska displaces 20% more CO2 than a panel in Arizona, although energy output from the Nebraska panel is 20% less.” Also http://phys.org/news/2015‐09‐health‐benefits‐renewable‐energy.html 327 Erik Johnson’s paper

41 cheaper resource, regardless of whether they are the most beneficial for the society when externalities are taken into account, leading to under‐deployment of distributed generation.

2. Valuing Avoided Emissions: the Social Cost of Carbon

The second step in valuing climate change benefits is to monetize the quantity of avoided emissions based on the estimations of the value of the external cost they impose on the society. For example, for carbon emissions, this monetization should be done by using the Social Cost of Carbon (SCC).328 The SCC is “an estimate of the monetized damages associated with an incremental increase in carbon emissions in a given year.”329

The SCC was developed by an Interagency Working Group comprised of economic and scientific experts from the White House and multiple federal agencies that regularly met to review technical literature, consider public comments, and discuss relevant inputs and assumptions.330 The SCC values were calculated using three widely cited climate economic impact models (known as integrated assessment models). These models were each developed by outside experts, and published and extensively discussed in peer‐reviewed literature.331 The IWG’s Technical Support Document discussed the models, their inputs, and the assumptions, including discount rates, used in generating the SCC estimates.332 The SCC is regularly updated over time to account for changing information and evolving climate effects.333

Both the 2010 and 2013 Technical Support Documents are comprehensive and rigorous in explaining the IWG’s sources of data, assumptions, and analytic methods. The Government Accountability Office recently examined the IWG’s process, and found that it was consensus‐based, relied on academic literature and modeling, disclosed relevant limitations, and was designed to

328 Proper SCC cites 329 INTERAGENCY WORKING GROUP ON SOCIAL COST OF CARBON, UNITED STATES GOVERNMENT, TECHNICAL SUPPORT DOCUMENT: TECHNICAL UPDATE OF THE SOCIAL COST OF CARBON FOR REGULATORY IMPACT ANALYSIS UNDER EXECUTIVE ORDER 12866 (2013), available at https:// www.whitehouse.gov/sites/default/files/omb/inforeg/ social_cost_of_carbon_for_ria_2013_update.pdf. 330 INTERAGENCY WORKING GROUP ON SOCIAL COST OF CARBON, UNITED STATES GOVERNMENT, TECHNICAL SUPPORT DOCUMENT: SOCIAL COST OF CARBON FOR REGULATORY IMPACT ANALYSIS UNDER EXECUTIVE ORDER 12866 at 2‐3 (2010). 331 INTERAGENCY WORKING GROUP ON SOCIAL COST OF CARBON, UNITED STATES GOVERNMENT, TECHNICAL SUPPORT DOCUMENT: SOCIAL COST OF CARBON FOR REGULATORY IMPACT ANALYSIS UNDER EXECUTIVE ORDER 12866 at 5 (2010). 332 Id. at 5‐23. 333 INTERAGENCY WORKING GRP. ON SOC. COST OF CARBON, U.S. GOV'T, RESPONSE TO COMMENTS: SOCIAL COST OF CARBON FOR REGULATORY IMPACT ANALYSIS UNDER EXECUTIVE ORDER 12866 at 2 (2015).

42 incorporate new information via public comments and updated research.334 Additional research has found that the SCC is likely too low because it currently omits a number of types of damages from the analysis, but it is the best available estimate of climate effects,335 and it is regularly updated over time to reflect new information.

The SCC is a standardized number used across multiple regulatory agencies in the federal government, ensuring that all agencies account for climate benefits in a rational and consistent manner.336 Leading states and municipalities, including Minnesota,337 and Maine,338 have also begun using the SCC in their energy‐related benefit‐cost analysis, recognizing that the SCC is the best available estimate of the marginal economic impact of carbon emission reductions.

[Using the best available estimate such as the SCC is the most prudent approach.]

[SCC values do not change locally.]

3. Interaction with other Regulatory Approaches

The variation in state policies regarding distributed generation is not limited to the specifics of net metering policies. As previously mentioned in this Article, there are variations across states in the incentives provided for renewable energy resources and specifically solar panels. North Carolina, for example, gives a 35 percent tax credit for installation of solar panels in addition to the federal tax credit of 30 percent, while Louisiana gives a 50 percent tax credit.339 California, on the other hand, gives direct cash rebates to customers who installed solar panels based on the capacity they installed.340 These disparities further highlight the need for analyzing all other incentive programs for distributed generation, including net metering, simultaneously to ensure that the combination of policy programs are providing the right incentives for distributed generation without over‐ or under‐ compensating it.

334 GOV’T ACCOUNTABILITY OFFICE, REGULATORY IMPACT ANALYSIS: DEVELOPMENT OF SOCIAL COST OF CARBON ESTIMATES (2014). 335 PETER HOWARD, INSTITUTE FOR POLICY INTEGRITY, OMITTED DAMAGES: WHAT'S MISSING FROM THE SOCIAL COST OF CARBON 1 (2014), available at http://policyintegrity.org/publications/detail/omitted‐damages‐whats‐missing‐from‐the‐social‐ cost‐of‐carbon. 336 See Richard L. Revesz, Quantifying Regulatory Benefits, 102 CAL. L. REV. 1423, 1439‐41, 1454‐55 (2014). 337 THOMAS E. HOFF & BEN NORRIS, CLEAN POWER RESEARCH, MINNESOTA VALUE OF SOLAR: METHODOLOGY (2014), available at https://mn.gov/commerce/energy/businesses/energy‐leg‐initiatives/value‐of‐solar‐tariff‐methodology%20.jsp. 338 MAINE PUB. UTIL. COMM'N., MAINE DISTRIBUTED SOLAR VALUATION STUDY 35 n.26 (2015), available at http://www.nrcm.org/wp‐content/uploads/2015/03/MPUCValueofSolarReport.pdf. 339 http://energytransition.de/2015/05/solar‐twice‐as‐expensive‐in‐us‐as‐in‐germany/ 340 Borenstein 2015 Private Net Benefits of Solar PV...

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Furthermore, because the vast majority of electric generators are subject to federal and state environmental laws, improved energy efficiency from distributed generators can lower the cost of utility compliance with these regulations.341 Efficient energy production from distributed solar can limit utility expenditures on permit fees or emission control systems,342 and in states with Renewable Portfolio Standards, distributed solar may be “acquired” by utilities to meet renewable resource standards.343 States may also be a part of a cap‐and‐trade program aimed at pricing emissions, such as the Regional Greenhouse Gas Initiative (RGGI).

The existence of other policies aimed at reducing emissions does not change the value of the external marginal damage caused by emissions. The value of this marginal external damage depends on the monetary value of all the damages caused by a marginal emission. Thus, it is independent of what policies are already in effect. However, the existence of such policies requires a discussion of how much of this damage is already being internalized as a result of these policies. Even though the external damage caused by a marginal increase in emissions is independent of other policies, the optimal pollution control policy going forward depends on them.

If there are other policies in effect that cause fossil‐fuel generators internalize some of the external damage they are causing, the environmental benefit adjustment in remuneration of distributed generation should only include the “uninternalized” damages. For example, a socially optimal distributed generation policy in a RGGI state should start with subtracting the RGGI price from the SCC to derive the value of external damage that has not yet been internalized.344 But, to be accurate, this calculation would need to reflect all existing policies affecting the market, not just RGGI. In addition to policies like RGGI and the Clean Power Plan, which might reduce the magnitude of an optimal subsidy, the analysis would also need to include policies that might increase the magnitude of an optimal subsidy, such as federal subsidies for fossil fuels.345

341 Jim Lazar, Recognizing the Full Value of Energy Efficiency, RAP 29 (2013). 342 Jim Lazar, Recognizing the Full Value of Energy Efficiency, RAP 29 (2013). 343 Jim Lazar, Recognizing the Full Value of Energy Efficiency, RAP 29 (2013). 344 See Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Comments of the N.Y. Dep't of Envtl. Conservation, PSC Case No. 14‐M‐0101, Filing No. 365 (May 1, 2015); see generally RICK HORNBY ET AL, SYNAPSE ENERGY ECONOMICS, INC., AVOIDED ENERGY SUPPLY COSTS IN NEW ENGLAND: 2013 REPORT 4‐1 to 4‐60 (2013), available at publicservice.vermont.gov/sites/psd/files/Topics/Energy_Efficiency/ AESC%20Report%20‐ %20With%20Appendices%20Attached.pdf. 345 See U.S. ENERGY INFO. ADMIN., DIRECT FEDERAL FINANCIAL INTERVENTIONS AND SUBSIDIES IN ENERGY IN FISCAL YEAR 2013 at 11‐14 (2015), available at http://www.eia.gov/analysis/requests/subsidy/pdf/subsidy.pdf.

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The existence of a cap‐and‐trade program also complicates the calculation of the quantity of avoided emissions. A cap‐and‐trade program sets a cap for emission allowances for a given year, and sells allowances to meet that cap. These allowances can be either used for meeting the compliance obligations of emitting entities or can be traded in a secondary market. The existence of a cap creates a mostly vertical supply curve for allowances, with two flat portions: the price floor which would be in effect if the cap is not binding and the cost containment reserve346 which would be added to the supply of allowances if prices rise above a trigger price. If the demand for allowances corresponds to any of these flat portions of the supply curve, the cap‐and‐trade program will essentially function as a carbon tax with reductions in demand for bulk electricity immediately leading to reductions in the number of allowances traded.

However, complications arise when the supply of allowances is binding, that is, when the demand for allowances correspond to the vertical portion of the supply curve. In theory, if this cap is binding, a distributed generator that displaces a fossil‐fuel generator cannot immediately reduce overall emissions. This is because when the emissions cap is binding, any emissions allowance that would have been used to meet the obligations resulting from the displaced energy generation of the fossil‐fuel source would be immediately sold to be used by the next source that could not initially buy allowances.

To be able to quantify avoided emissions that result from distributed generation given a cap‐ and‐trade program with a binding cap, it is helpful to analyze the details of these programs. It is important to keep in mind that in cap‐and‐trade programs allowances for carbon dioxide emissions are traded. Thus, the supply curve corresponds to allowances, and not the emissions. While this may seem like an insignificant distinction, it has a significant impact on how to value the environmental and health benefits of distributed generation. If a distributed generator is reducing the amount of electricity the bulk system needs to generate, then it is stopping a dirtier generator from emitting more carbon dioxide at that instant, and hence, creating an “unused” allowance at that moment, regardless of whether the cap is binding or not. Thus, the relevant questions to ask for the purposes of the benefit‐cost analysis framework are what happens to the allowances that are unused as a result of more distributed generation and how these unused allowances affect the cap.347

346 This may be specific to RGGI 347 RICK HORNBY ET AL, SYNAPSE ENERGY ECONOMICS, INC., AVOIDED ENERGY SUPPLY COSTS IN NEW ENGLAND: 2013 REPORT 4‐11 (2013).

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For this purpose, it is helpful to look at the history of RGGI as an example. Until 2013, not all of the RGGI allowances offered were sold, so the RGGI cap was not binding.348 Following a 2012 Program Review, the RGGI states announced changes to the model rule, and the cap was adjusted downward with further annual reductions of 2.5 % until 2020.349 Since the new rule went into effect in 2013, all of the allowances that were offered have been sold, and the allowance cap has been binding. However, even this did not directly translate to a binding emissions cap given that the RGGI rules have allowed for banking of allowances with no time restrictions.

A large bank of unused allowances has accumulated since the inception of RGGI.350 The number of all allowances in circulation at the end of 2014 was 403 million, 139 million of which were unused. To deal with the unused allowances, RGGI states made further adjustments to the cap in the updated rule to deplete this accumulated surplus by the end of this decade. Between 2014 and 2020, the number of total allowances sold will be reduced by the total number of “banked” allowances during the first and the second control periods (2009‐2012, and 2012‐2013, respectively.) The updated rule includes further provisions that would make it easier for participating states to retire unused allowances at the end of each control period.

This feature of the RGGI scheme has important implications for quantifying the amount of avoided emissions. If, for example, a compliance entity ends up with “unused” allowances as a result of distributed solar generation and expects the reduction in demand to be permanent, this would not only reduce the entity’s demand for allowances in future years, but it would also induce further adjustments to the allowance cap at the end of each control period. So, the RGGI cap in practice is a dynamically decreasing allowance cap rather than a static emissions cap. Hence, there are indeed externality benefits even when RGGI allowance cap is used as a metric to quantify avoided emissions. These unused allowances may delay when the pollution is emitted, if they are eventually used, or they may lead to a reduction in the cap in the future, as the RGGI program dynamically adjusts allowances. Unused allowances will translate to a reduced allowance cap within a maximum of three years if RGGI continues to retire unused allowances after each control period.

This raises the question whether there is a possibility of a very tight allowances market with no or minimal unused allowances, which could lower or eliminate the quantity of additional emission

348 POTOMAC ECONOMICS, ANNUAL REPORT ON THE MARKET FOR RGGI CO2 ALLOWANCES: 2014, at 25 (2015), available at http://www.rggi.org/docs/PressReleases/PR050515_2014‐Annual‐Market‐Monitor‐Report.pdf. 349 Id. at 11. 350 Id. at 7.

46 reductions available under the program. However, in RGGI, this does not seem to be the case. At the end of 2014, entities with compliance obligations held 76 million surplus allowances, which accounted for 56% of the total surplus allowances. The remaining 44% of the surplus allowances were held by investors, who have no compliance obligations. This accounts for 15% of all allowances. These investors participate both in the primary market for allowances by purchasing them directly in auctions, and in the secondary market by selling the allowances directly or other financial derivatives such as futures and options.351 Given the current surplus of allowances, a high level of investor participation is expected to continue over the remainder of the decade.352 Further, given the significant rise of trading volume in the secondary market, both for physical delivery of allowances and futures, 353 and the steady rise in open interest in futures,354 there is no reason to believe that investors will stop participating in the carbon allowances market in the near future even as the cap tightens, ensuring a continued balance of unused allowances.

Even though the availability of unused allowances in a given year is expected to decrease as the number of allowances offered for sale by RGGI decreases by 2.5% each year until 2020, this does not necessarily guarantee an eventual full depletion of unused allowances. While the cap decreases, it is also expected that more of the cleaner resources will be integrated into the system as a result of both more distributed energy resources on the demand side and more technological innovation from the supply side, freeing up more allowances. Thus, to the extent that the percentage of cleaner resources rises faster than 2.5%, there will continue to be sold‐but‐unused allowances, leading to an eventual cap reduction.

Finally, as the demand for dirty generation and hence the demand for carbon allowances decrease over the next decades, the prices of allowances may decrease enough to make the market more attractive for another type of investor: environmental groups who buy allowances—either through initial auctions or in the secondary market—to retire coal plants. These types of transactions have already been happening on smaller scales.355 Given the increasing efforts to battle climate change, it is plausible that these transactions would occur at a much larger scale if the allowance prices decrease

351 Id. at 15. 352 Id. at 24. 353 Id. at 26. 354 Id. at 28. 355 See, e.g., Green Group Buys CO2 Emissions Permits to Retire Them, ENVTL. NEWS SERV., http://www.ens‐ newswire.com/ens/mar2009/2009‐03‐20‐092.html (Mar. 20, 2009).

47 enough. In such circumstances, those allowances will not only remain unused, but they will be retired immediately.

Overall, there are quantifiable benefits due to avoided emissions even in conjunction with a cap‐ and‐trade program. Distributed generation will displace generators from the bulk system, which will lead to unused allowances, and eventually, lower caps. A precise calculation of the quantity of avoided emissions in the presence of a cap‐and‐trade program requires an in‐depth study how distributed affect the number of unused allowances and how those unused allowances impact the cap in detail, taking the values created in the secondary market and the timing of control periods into account. However, it is likely that the results of such a study would not differ significantly from an approximation of avoided emissions based upon the quantity of carbon dioxide emissions that the generator displaced by a distributed generator would have emitted.

The main difference between the two approaches to estimating the quantity of avoided emissions—studying the effect of unused allowances on the cap in detail versus using the quantity of avoided emissions from the displaced generator as a proxy—would stem from the time delay between the “creation” of the unused allowance and the eventual reduction of the cap. Including the avoided emissions using a delayed reduction in the RGGI cap as a metric, however, would undervalue the benefits of distributed generation, as the avoided emissions technically occur at the moment when a distributed generator displaces a fossil‐fuel source. A simple use of displaced emissions due to displaced bulk generators as a metric, on the other hand, may potentially overestimate the quantity of avoided emissions if the cap is binding and the unused allowances are simply being shuffled and used by another source. But that overvaluing is likely to occur when the allowances market is tight enough to not have any significant surplus of unused allowances and the cap is expected to be static for the remainder of the time, and hence the cap on emissions is binding. Given the current dynamics of the RGGI program, the probability of undervaluing the benefits with the former approach is likely greater than the probability of overvaluing the benefits with the latter approach. Further, the latter approach is much simpler. And, finally, given the importance of cleaner energy resources for mitigating climate change and securing a better future for the next generation, it would be prudent to err on the side of overvaluing cleaner energy rather than undervaluing it. Thus, regardless of whether the cap is binding, the avoided emissions should be quantified by calculating the amount of avoided emissions from the marginal generator that the distributed generator displaces at the time when the energy is produced.

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B. Other Social Benefits

1. Conventional Pollutants

In addition to environmental benefits, reduced carbon emissions and reduced local pollutants such as sulfur dioxide, nitrogen oxides, and fine particulate matter provide external health benefits such as improved morbidity and reduced risk of premature mortality.356 A socially optimal approach to compensating distributed generation should include local estimates of the value of these health benefits. EPA has regional values of the damage marginal damage estimates for SO2 and NOx. Unlike the marginal damage estimate of CO2, the marginal damage estimates of these pollutants depend on the region where they are emitted. This variation is a result of the variation in health impacts of these pollutants due to changes in demographic and geographic characteristics of a particular area.357 Thus, if there is a strong reason to believe that the state‐specific values for these pollutants are significantly different than the EPA regional values, each state should conduct its own study to calculate these values. However, such a study would be valuable only if the results are likely to be significantly different than EPA’s estimates.

[INSERT MORE]

2. Other Environmental Benefits

Distributed solar generation can also be an important tool to improve water quality and land degradation issues exacerbated by central‐station power plants.358 Siting conventional generators and transmission and distribution lines necessary to deliver electricity can involve significant degradation of natural lands.359 In contrast, distributed solar is generally roof‐top installed and thus does not consume additional land space.360 Similarly, substituting steam electric or coal‐fired power plants for distributed solar and wind generators can have significant consequences on water conservation.361 Water is integral in hydroelectric generation, cooling systems for thermoelectric plants, and scrubbing pollutants from

356 Nicholas Z. Muller et. al., Measuring the damages of air pollution in the US, 54 J. OF ENVTL. ECON. AND MGMT. 1, 8‐ 13 (2007); Dallas Burtraw et al., Costs and Benefits of Reducing Air Pollutants Related to Acid Rain, 16 CONTEMPORARY ECON. POLICY 379, 397‐399 (1998). 357 EPA Technical support documents, estimating the benefit of PM... 358 Maximizing the Benefits of Distributed Photovoltaics, p. 57 359 Maximizing the Benefits of Distributed Photovoltaics, p. 57 360 A Study Pursuant to Section 1817 of the Energy Policy Act Of 2005, 6‐2 n.42 361 Lazar, Recognizing the Full Value, at 58.

49 flue gases.362 Coal‐fired plants may consume nearly 500 gallons of water for every MWh generated, and steam electric generation requires as much as 4 billion gallons of water per day.363 Water levels are critically low in certain regions of the United States, and competition for water between power, agricultural, industrial, and domestic sectors can make it an expensive commodity.364

3. Social Resiliency Benefits

Other social benefits of distributed generation include reduced financial and security risks, economic development, 365 and other social resiliency benefits such as reduced crime as a result of a lower number of outages. All of these benefits should be quantified and incorporated into the optimal distributed generation tariff. Even though some of these benefits may be difficult to quantify, that does not provide a justification for counting these values as zero.366 Further, a discussion of these benefits now would lay the foundation for their easy incorporation into analyses as more reliable methods and metrics to quantify such benefits develop. Methodologies to estimate many of the non‐energy benefits already exist, 367 and a distributed generation policy should reflect these best‐available monetization methodologies.

[INSERT MORE ABOUT SOCIAL RESILIENCY]

IV EVALUATING CURRENT PRICING APPROACHES

A. Net Metering

At its core, the idea of compensating a product or a service at the prevailing retail price like net metering is not an economically unsound idea. In fact, that is what should happen in perfectly competitive markets. In such markets, there are many buyers and sellers, none with any market power.

362 Lazar, Recognizing the Full Value, at 56. 363 Lazar, Recognizing the Full Value, at 57. 364 Lazar, Recognizing the Full Value, at 57. 365 ROCKY MOUNTAIN INST., supra note Error! Bookmark not defined., at 13. 366 Cite Ricky’s quantifying regulatory benefits paper. 367 For example, a report prepared by Dr. Bruce Tonn at the Oak Ridge National Laboratory, which is expected to be released soon, calculates many non‐energy benefits of an energy conservation program, including health and productivity benefits. See NATIONAL ASSOCIATION OF REGULATORY UTILITY COMMISSIONERS, NARUC 2015 SUMMER COMMITTEE MEETINGS PROGRAM 17 (2015), available at http://summer.narucmeetings.org/2015_ Summer_Program‐Final.pdf.

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Thus, they all buy and sell the product at the same market clearing price. So, if a new firm decides to sell one more unit of the product, the price that it would get in a perfectly competitive market for that unit would be that prevailing market clearing price. Accordingly, the argument that a kWh of electricity produced and sent to the grid by a distributed generator should be compensated at the retail rate is grounded in basic principles of perfectly competitive markets.

In a perfectly competitive market, the market clearing price also equals the production cost of the last unit sold in the market. In other words, it is the cost that would be incurred by another firm that would end up producing that marginal unit in the absence of that new firm. Essentially, the retail price in a perfectly competitive market is also the avoided cost of production. Thus, the seemingly different argument that a distributed generator should be compensated at the avoided cost would actually lead to the same result as net metering in a perfectly competitive market. In other words, if the electricity market was a competitive market with no externalities, net metering – the practice of reimbursing a producer at the prevailing retail price – would be the right policy.

However, the complex structure of electricity markets and the inefficiently designed retail electricity tariff makes the seemingly simple application of this basic economics principle more demanding. While the market determined retail rate in perfectly competitive markets is actually the marginal cost of production, the same is not true for the retail electricity rates. The electricity rates, which are regulated rather than being market determined, also include fixed costs of production. Using such bundled rates to compensate distributed generation means that even though distributed generation does not help avoid any of the fixed costs, it still gets reimbursed for these costs. At the same time, this practice undercompensates distributed generation for other benefits it provides such as reducing grid congestion when the system is close to capacity during peak hours and environmental benefits as most retail rates do not account for those.

The possibility of retail net metering policies excusing some customers from paying their share of grid services have prompted related concerns over cost recovery problems and cost shifting to remaining customers.368 Many fear net metering acts as a socially regressive subsidy for utility customers with distributed generation, who are traditionally more affluent, by placing additional costs

368 STEVE MITNICK, BUILD ENERGY AM., CHANGING USES OF THE ELECTRIC GRID: RELIABILITY CHALLENGES AND CONCERNS, at xvi (2015).

51 on moderate‐ and low‐income utility customers without the resources to afford distributed generators themselves.369

Presently, distributed wind and solar penetrations across much of the United States are sufficiently limited that any cost shifts are relatively small.370 However, in states where distributed generator penetrations are growing or are already substantial, these transfers may be significant. Cost shits among residential ratepayers in Arizona are estimated between $800 and $1,000 a year for every net metering customer,371 and California’s net metering policy could shift as much as $359 million in fixed service costs to non‐net metered consumers by 2020.372 Although Arizona and California may encounter a greater degree of cost shifting than other states due to higher solar penetrations, a 2014 white paper published by the American Public Power Association projected national net metering participation among customers capable of supplying 5% of total load will generate a corresponding 2% rise in average utility rates for non‐net metering customers.373

Net metering supporters have been quick to respond that some amount of cross‐subsidization is inevitable374 – consumers who conserve power and minimize utility overhead effectively offset, and therefore subsidize, customers who waste electricity.375 However, because of expenses associated owning or leasing solar panels and greater incentive among high‐consumption households to pursue distributed generation as a means of lowering utility bills, net metering is often disproportionately concentrated among wealthier customers.376 In 2013, 78% of net California metering households also had annual income higher than the state‐wide median.377 Thus, some observers argue the cost shifting is

369 Id. 370 Raskin, supra note, at 42. 371 APS Application, supra note, at 5. 372 ENERGY DIV., CALIF. PUB. UTIL. COMM’N, CALIF. NET ENERGY METERING RATEPAYER IMPACTS EVALUATION 6 (2013), available at http://www.cpuc.ca.gov/NR/rdonlyres/75573B69‐D5C8‐45D3‐BE22‐3074EAB16D87/0/NEMReport.pdf. 373 AM. PUB. POWER ASS’N, SOLAR PHOTOVOLTAIC POWER: ASSESSING THE BENEFITS & COSTS 5 (2014) [hereinafter APPA, ASSESSING BENEFITS], available at http://publicpower.org/files/PDFs/74%20Solar‐Photovotalic%20Power.pdf. 374 David Schmitt, Net Metering: Getting Beyond the Controversy, 2011 A.B.A. RECENT DEV. PUB. UTIL. COMM. & TRANSP. 417, 425. 375 Id. 376 APS Application, supra note, at 5. 377 Ashley Brown, Valuation of Distributed Solar: A Qualitative View, 27 THE ELEC. J. 27, 47 (2014) [hereinafter Brown, Valuation of Distributed Solar], available at http://www.ksg.harvard.edu/hepg/Papers/2014/12.14/Brown%20%20Valuation%20of%20%20Distributed%20Sola r%20%2011.14.pdf.

52 not simply from customers with rooftop solar to those without, but a uniquely pernicious and regressive cross‐subsidization from less affluent customers to more affluent ones.378

Such cost shifting impacts of net metering vary with the underlying rate design in a particular jurisdiction.379 For example, in California where the retail electricity rates uses an increasing block pricing design, utility interests claim the consequences of cost shifting are exacerbated by the reality that many net metered customers are also high‐usage consumers subject to higher utility rates and, prior to installing on‐site generation, accounted for a sizeable portion of utility revenue.380 In 2013, the top one‐quarter of households by energy consumption accounted for one‐half of utility billings, and the vacuum created by these customers departing the traditional pool of customers can be substantial. 381 In California, prior to installing solar or wind units, net metered customers were charged rates equivalent to 154% of basic cost‐of‐service, but pay rates equivalent to 88% of basic cost‐of‐service afterward.382 Not only are net metered customers the recipients of apparent cross‐subsidization, the households who support that windfall are saddled with recovering revenue losses from a disproportionately significant class of ratepayers. 383

1. Shortcomings of Having a Bundled Flat Volumetric Rate Underlying Net Metering

In many retail electricity markets, the transmission and distribution costs as well as other ancillary services are bundled with generation costs into one single volumetric rate rather than being charged separately. A typical tariff for residential customers has two parts, a fixed monthly service charge and a flat volumetric energy consumption charge. The per‐kWh charges are almost always set to recover most of the fixed costs of transmission and distribution networks in addition to variable costs of generation electricity. Even though transmission, distribution, ancillary services and capacity based non‐ energy fixed costs amount to about 55% of an average electricity bill, fixed charges customers pay represents about only 7% of the average electric bill and are generally designed to recover the operational expenses rather than the fixed system costs. The rest of these fixed non‐energy costs are recovered through the bundled flat volumetric rate.

378 Brown, Valuation of Distributed Solar, supra note, at 47. 379 New NREL paper on this. 380 BORENSTEIN, supra note, at 25. 381 MITNICK, supra note, at xvi. 382 Barraco, supra note, at 383. 383 Barraco, supra note, at 383.

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There lies the main complication of this debate. The retail electricity price is the bundled cost providing retail electricity to end‐customer which is a “composite” good that requires generation of electricity, transmission of energy, and local distribution to end users. Thus, the final electricity consumed by the end user is a different product than the electricity generated by an electricity generator at the source. This essentially means that while the electrons sent to the grid by a distributed generator may be a perfect substitute for the electrons generated by another traditional generator, the electricity produced by distributed generation cannot be a perfect substitute for the final good –the retail electricity – consumed by the end user as the distributed generation does not provide any of the other services required such as distribution and balancing. To the extent that the electricity generated by distributed generation is different from retail electricity, compensating it using retail electricity rates would lead to economic inefficiency.

If there were separate competitive retail markets for generation, distribution, transmission and other necessary services in which end‐users could shop individually for each component of electricity delivery, the resulting retail prices could have been used to reimburse distributed generation separately for the benefits it provided or the costs it avoided in each market, if any. Unfortunately, due to the complex nature of electricity provision and associated high fixed costs such a market structure, and hence such a pricing, is not possible. Instead, retail electricity is provided to end customers by regulated utilities.384 And, retail electricity tariffs, while may vary slightly in design in deregulated states, make use of a flat volumetric per kWh rates as determined by state public utility commissions385 that is intended to cover not only the variable costs of the generation of electricity itself, but also other fixed costs including transmission, and infrastructure expenses.386

This mismatch between the way costs are incurred and the way costs are recovered creates the possibility of cost shifting between different customer groups when one group lowers their consumption for any reason, whether it is a result of distributed generation, energy efficiency, or personal preference. If a group of customers decide conserve energy by running their air conditioners more often, for example, they reduce their volumetric consumption. When a class of customers reduces their volumetric consumption, the revenue generated by volumetric charges is no longer high enough to recover the utility’s costs. If the fixed costs can no longer be recovered from this group of consumers, the utility ends up having to raise the volumetric rate for all the customers to make up for the

384 Insert references, probably MIT Grid study has something on this. 385 Find an overview article, maybe MIT, maybe ferc 386 Tanton, at 5.

54 difference. Thus, with net metering, while customers who own solar panels essentially get credited for the output they produce at the retail rate387 by being billed for a lower “net” volume of electricity, customers without distributed generation systems end up facing with higher rates.

Such a structure creates further perverse incentives for the utilities when it comes to energy conservation. When utility companies have to depend on the volume of electricity usage to recover their fixed costs, their inherent incentive is to resist any policy that could reduce volumetric energy sales, contrary to society’s energy efficiency and energy conservation goals, and to resist any initiative that would reduce the consumer load such as rooftop solar programs. Structuring the retail tariffs in such a way that the utilities do not have to rely on energy sales to recover their fixed costs will help reduce the misalignment of utility incentives with the societal goals and provide a more accommodating environment for all clean energy initiatives.

2. Temporal Variations and Production and Transmission Constraints

Another source of inefficiency in electricity pricing stems from the way retail energy charges are calculated. For almost all the retail customers, the energy charges are calculated based on the average cost of electricity generation during a set billing period.388 Thus, the energy price that these consumers face is a flat rate regardless of when they consume electricity. However, in reality, the cost of generating energy varies significantly by time and location.389 As the demand for electricity is higher at certain “peak” demand times during the day, utilities have to turn on more expensive generators during these periods to be able to meet the demand. Even though electricity generated by these “peaker” plants is costlier, it is still sold to the end user at the same lower average rate.

This flat volumetric rate insulates the consumers from receiving the correct price signals about the true cost of generating energy and adjusting their usage patterns accordingly. As a result, electricity is over‐consumed during the more costly peak periods and under‐consumed during the “off‐peak” periods. As the cost of peak energy generation is averaged into the retail rate that is paid by all the customers, this creates a cross‐subsidy between off‐peak users and peak users.

387 STANTON, supra note , at 10. 388 Alcott, Rethinking real time electricity pricing at 1 389 RMI at 12

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When this variation in costs is not reflected in the retail rates, and the distributed generation is compensated using the same flat volumetric rate at all times and locations as a consequence, net metering policies lead to overcompensating distributed generation during off‐peak times and undercompensating it during peak times. Net‐metered customers who export energy during the peak times and draw on grid power in the evening when utility costs of production are lower effectively exchange a high‐value product for a low‐value one.390 By passing electricity into utility grid for a lower price than utilities would otherwise pay, distributed generators may be undercompensated for their contribution of electricity and thereby subsidize non‐net metered customers.391

3. Demand Variations and Distribution Constraints

A consumer’s contribution to the fixed costs of distribution networks is also dependent on time and location. The maximum demand during peak periods is the main driver of any new distribution system capacity investment.392 A customer’s maximum demand at the moment of highest usage among all customers in a particular location – “coincident peak demand” – is more important than the customers individual peak demand – “non‐coincident peak demand” – as a driver of infrastructure investments. For example, a customer may be using the most electricity early in the morning, but if the circuits at that location are not already loaded at that time her consumption would not prompt new investment. However, if the peak demand on the circuit at that location occurs in the early afternoon, her early afternoon demand might prompt new investment even if it is actually less than her morning demand. If however, the same customer moves a different area with a higher network capacity, even her coincident peak demand may not require new capacity investment.

If distributed generation lowers a customer’s coincident peak demand at a particular location at which the demand is close to the network’s peak capacity, it lowers the need for future distributed capacity investment. This value varies significantly with location. For example, while the capacity deferral value of distributed solar panels are $6/kW‐yr when averaged over Pacific Gas & Electric’s service territory, the capacity value can be as much as $60/kW‐yr when analyzed at a more granular

390 Hoke, Anderson, and Paul Komor. (2012). “Maximizing the Benefits of Distributed Photovoltaics.” Electricity Journal, 25(3), 1040‐6190. doi:/10.1016/j.tej.2012.03.005; pgs. 58 391 STANTON, supra note, at 24. 392 Simshauser at 6, but there are also many other sources, check farruqi, hledik, etc. also rev track 2 footnote 81

56 feeder level.393 As this variation is not reflected in the current retail rates, net metering cannot sufficiently capture the value of distributed generation.

B. Fixed Charges

To allay cost recovery issues associated with net metering,394 utilities across 13 states proposed or adopted over 20 measures. Nearly all of these states considered establishing or increasing fixed service, demand, or capacity charges; though only half considered raising rates specifically for net metered customers.395 On average, proposed measures would increase monthly rates for net metered customers approximately $12, though Idaho and Hawaii were the most aggressive states, each proposing price hikes equivalent to $16/month.396 In addition, three states considered transitioning to feed‐in tariff pricing instead of net metering, though none officially adopted such a plan.397 In Arizona, for example, the state’s largest electric utility requested approval to raise its rates to include a $40‐50 monthly charge for net metered customers,398 but got approved a monthly charge of approximately $5 for an average household system.399

It is important to distinguish an arbitrary increase in fixed charges than possible bill increases that would occur as a result of a properly designed tariff. An un‐nuanced increase in fixed costs would indeed hurt efficiency and the deployment incentives for distributed generation since it moves away from the cost causation principle and reduces a costumer’s bill saving ability.400 Converting distribution expenses into flat service fees can ignore actual variation in delivery costs, which decline when customers are located near generators or are geographically concentrated.401 Simply increasing fixed service charges can therefore transfer cost burdens from rural, higher‐use ratepayers that require

393 Cohen Kauzmann Callway 16 394 FARUQI, 8 (2015). 395 Arizona, California, Connecticut, Georgia, Hawaii, Idaho, Nevada, Utah, Washington, Wisconsin. Green Energy Institute, LEWIS & CLARK LAW SCHOOL, Oct. 1, 2014, https://law.lclark.edu/live/news/28070‐distributed‐generation‐ rate‐reform‐around‐the‐us. 396 Green Energy Institute, supra note. In addition to a fixed service fee of $16/month for distributed generation customers, Hawaii proposed a $55/month service fee for all ratepayers. 397 Green Energy Institute, supra note. Arizona, Hawaii, Minnesota, Texas. 398 Diane Cardwell, Compromise in Arizona Defers a Solar Power Fight, N.Y. TIMES (Nov. 15, 2013), http://www.nytimes.com/2013/11/16/business/energy‐environment/compromise‐in‐arizona‐defers‐a‐solar‐ power‐fight.html?_r=o. 399 In a 3‐to‐2 vote, the commission decided to levy a fixed charge for net metered customers equal to $0.70 per kW of system capacity. The utility saw a silver lining in this decision, despite the substantial reduction in additional charges, because the commission found that there indeed was a cost shift to nonsolar customers. Id. 400 The new Berkeley national lab report. 401 Carl Linvill, Designing Distrib. Generation Tariffs Well, RAP 36 (2013)

57 greater distribution expense, to urban and low‐use ratepayers with lower delivery costs.402 Further, it would prevent distributed generation from capturing the savings related to the generators being closer to the consumers.

Such different behavior from different states also accentuates the need for a comprehensive framework in distributed generation. Haphazardly imposing a fixed charge on net metered customers without any disregard for cost causation would not lead to economically desirable outcomes within each state, but such variations in state energy policies also have national consequences for energy policy. An arbitrary variation across states in how distributed generation is compensated – a variation without any basis in state specific benefits and costs – leads to an inefficient variation in the penetration of distributed generation across states that is not based on its actual benefits and costs, leading to inefficient allocation of resources.

C. Caps of Various Kinds: Not Carrying Forward Credits, Percentage Constraints

Currently, state policies on net metering caps vary significantly.403 Utilities in four states have already reached the cap, while four more states are projected that some states will reach their caps by 2018 necessitating action.404 Such caps are generally imposed to limit a utility’s exposure to risk related to cost recovery in the presence of net metering.

An arbitrary cap out on net metering, however, is essentially trying to fix the inefficiencies caused by net metering by another inefficient policy. While it is true that net metering policies increases a utility’s risk of recovering its costs, the way to solve that problem should be to identify and solve the underlying reasons for this increased risk rather than trying to suppress the symptom. To the extent that a utility cannot recover its expenses with the prevailing retail rates, a cap could is necessary to ensure that the grid can be maintained. However, given that a proper tariff design would alleviate any cost recovery concerns, an arbitrary net metering cap would lead to further inefficiency and under‐ deployment of distributed generation.

402 JIM LAZAR, RATE DESIGN WHERE ADVANCED METERING INFRASTRUCTURE HAS NOT BEEN FULLY DEPLOYED, RAP 61 (2013). 403 http://www.nrel.gov/docs/fy14osti/61858.pdf summary at v. 404 Id.

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V TOWARD AN AVOIDED COST/SOCIAL BENEFIT APPROACH TO PRICING

While the policy debate on net metering is extensive, with many issue briefs published by advocates on both sides of the debate, the academic guidance on net metering has been limited in comparison. Recent related literature mostly focuses on understanding the drivers of adoption of solar panels,405 impacts on customers,406 and impacts on utilities.407 Several studies have done a comparative analysis of different remuneration policies aimed at distributed generation,408 and discussed efficient signals for investment in distributed generation.409

Theoretical guidance in economics literature on how to optimally design policies aimed at distributed generation is sparse. Yamamoto (2012) shows that under certain conditions different feed‐ in‐tariffs are likely to lead to higher social welfare than net metering. Brown and Sappington (2015) show that if regulators lack the ability to set a different rate for distributed generation than the retail rate and, thus, are required to use net metering, it leads to lower overall social welfare and has distributional consequences. They further show that a socially optimal distributed generation policy should account for externalities and hence can vary substantially with the prevailing generation mix.410

While the articles in the economics literature analyze different settings and focus on different aspects of distributed generation policies, there are two main themes: the socially optimal distributed generation policy depends on a variety of parameters that may vary significantly from state to state, and it should account for the externalities. Thus, a “one‐size‐fits‐all” policy such as net metering which does not allow for variations is not an economically desirable policy.

A. Identifying the Socially Optimal Approach

As more states start undertaking initiatives to evaluate net metering and reform it if they deem necessary, it is important to establish a socially desirable framework that can be used consistently in different states or in discussions of different distributed energy resources, not just distributed solar generation. For such a framework, the first step is to establish a comprehensive catalogue of all

405 Duke et al 2005, Payne et al 2001, http://emp.lbl.gov/publications/net‐metering‐and‐market‐f 406 Darghouth et al 2014, Cai et al, Borenstein 2015 407 Eid et al 2014 408 Couture and Gagnon 2010, Pouillikas 2013 409 Vogel 2009 410 Brown & Sappington 2015 at 22

59 potential costs and benefits and the resulting trade‐offs associated with distributed generation. There is already significant scholarship – and academic debate – underway about how to determine the exact benefits of distributed energy resources. Some studies have attempted to quantify the effects of specific types of distributed energy resources such as distributed solar generation while others have focused on putting together a comprehensive approach to performing benefit cost analysis for distributed energy resources.411 Several jurisdictions (both inside and outside of the U.S.) have also attempted to evaluate costs and benefits of tariffs for specific types of distributed energy resources.412

While some benefit‐cost analyses are being undertaken by several states in response to net metering debates, at least two important points that are not currently in focus should be underlined. First, it is important to note unless these analyses provide a comprehensive overview of the trade‐offs associated with distributed generation, they would not lead to socially optimal policies. For example, while positive externalities related to avoided emissions should be taken into account, a proper benefit‐ cost analysis should also reflect the concerns about health effects of a full rollout of advanced meters or related concerns about privacy, as well as concerns about increased vulnerability to cyber terrorism.413 Or, the increased risks related to bi‐directional flow should be balanced against the resiliency benefits that distributed generation brings. The benefits stemming from sending zero variable cost energy to the grid has to be balanced against the losses in efficiency from losing out on economies of scale of larger scale generators. Similarly, while distributed generation can help reduce the strain on systems at or near capacity and thus should be rewarded for avoided capacity investments accordingly, traditional utilities which are required to provide back‐up power to these intermittent resources414 should also be rewarded accordingly.

411 Advanced Energy Economy Institute and Synapse Energy Economics, Inc., Benefit‐Cost Analysis for Distributed Energy Resources (Sep. 22, 2014); Rocky Mountain Institute, A Review of Solar PV Benefit & Cost Studies (2nd Edition) (Sep. 2013). 412 See, e.g., Austin Energy & Clean Power Research, Designing Austin Energy’s Solar Tariff Using a Distributed PV Value Calculator (Mar. 2011); Naim R. Darghouth, Galen Barbose & Ryan Wiser, The Impact of Rate Design and Net Metering on the Bill Savings from Distributed PV for Residential Customers in California, 39 Energy Policy 5243, 5253 (2011); The Vote Solar Initiative & Crossborder Energy, Evaluating the Benefits and Costs of Net Energy Metering in California (Jan. 2013); California Public Utilities Commission & Energy + Environmental Economics (E3), California Net Energy Metering Ratepayer Impacts Evaluation (Oct. 28, 2013); Minnesota Department of Commerce, Division of Energy Resources & Clean Power Research, Minnesota Value of Solar: Methodology (Apr. 1, 2014). 413 Cite news articles on these 414 JOskow comparing the costs of intermittent and dispatchable eletciricty generating technologies. Give an idea of the size of the cost of intermittency

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Second, the categories of benefits and costs of distributed generation that are not reflected in the retail tariffs should be included in a socially optimal distributed generation tariff. Economic theory guides to use compensate distributed generation using a net avoided private and external cost approach. While net metering is aimed to accomplish this goal by compensating distributed generation using the prevailing retail prices, it falls short given the inefficient design of current retail electricity tariffs. Therefore, an “Avoided Cost/Social Benefit” approach that compensates distributed generation for the net costs that the bulk system no longer have to incur as a result of lower demand and for the net social benefits it causes is needed until a comprehensive retail rate reform can take place.

B. Legal Basis and State Practice

1. FERC Regulation and Decisions

Traditionally, FERC regulation has been limited to wholesale and interstate transactions between utilities. 415 In contrast to FERC, individual state public utility commissions have traditionally monitored the retail rates charged by utilities of end‐use consumers, intrastate utility activity, and avoided cost rates; including whether or not to include the environmental and social benefits of distributed generation in avoided cost calculations.416 In practice, however, the division of regulation is not so definite, and FERC policy has proven a significant determinant of state regulatory action.417

Notably, until recently FERC explicitly prohibited the inclusion of “externality” adders in avoided cost rates.418 Externality adders are monetary sums intended to capture non‐market consequences of electric generation; like a decline in environmental degradation, increase in public health due to a

415 Federal Power Act, 16 U.S.C. § 824(a) (2012). 416 See Pub. Util. Regulatory Policy Act, 16 U.S.C. § 824a‐3(f) (2012) (placing ultimate responsibility for establishing avoided cost rates for qualifying facility power with state public utility commissions);Sun Edison LLC, 129 F.E.R.C. ¶ 61,146, at 61620‐21 (2009) (“[T]he Commission does not assert jurisdiction when the end‐use customer . . . receives a credit against its retail power purchases from the selling utility.”). But see Sun Edison LLC, 129 F.E.R.C. ¶ 61,146, at 61620 (“Only if the end‐use customer participating in the net metering program produces more energy than it needs of the applicable billing period, and thus is considered to have made a net sale of energy to a utility of over the applicable billing period, has the Commission asserted jurisdiction.”); Federal Power Act, 16 U.S.C. § 824d (2012) (granting FERC jurisdiction to set wholesale rates that are “just and reasonable” and “not unduly discriminatory”). 417 417 AMY ABEL & JON SHIMABUKURO, CONG. RESEARCH SERV., RS20146, ELECTRICITY RESTRUCTURING BILLS: A COMPARISON OF PURPA PROVISIONS 1 (1999). 418 Southern California Edison. 70 F.E.R.C. ¶ 61,215 (1995), aff'd on rehearing, 71 F.E.R.C. ¶ 61,269 (1995).

61 reduction in pollutant emissions, or an increase in national energy security due to a greater diversity among electricity generators.419

In a 1995 case before FERC, the federal agency specifically prohibited inclusion of externalities in avoided cost rates.420 FERC reasoned that because environmental externalities did not manifest as “real costs that would be incurred by utilities,” they were outside the ambit of ‘avoided’ costs.421 However, FERC did make clear that once non‐market benefits were “monetized” by state or federal policy initiatives and internalized in utility costs, the previously off‐limit considerations like the environmental consequences of generation could be incorporated into avoided cost rates.422 Environmental benefits may be “monetized” in a number of ways—by state policies that require pollutant filtration or mitigation devices, renewable fuel mandates, and emission tax regimes that impose additional compliance costs on traditional fossil‐fuel generators.423 For example, in the very same 1995 decision that formally excluded external benefits in avoided cost rates, FERC noted, that states may choose to “account for environmental costs” of electricity generation by “imposing a tax on fossil generators.”424 In other words, state policy makers could, by levying a tax on fossil‐fuel generators, increase the costs fossil‐fuel generators incur generating electricity, and therefore might “avoid” by purchasing energy from qualifying facilities.

Likewise, statutory or regulatory directives that imposed equipment compliance costs on fossil‐ fuel generators may be incorporated into avoided cost rates. For example, although the Clean Air Act’s requirement that all high‐sulfur coal power plants install flue‐gas desulfurization devises, known as scrubbers, predated PURPA and the 1995 FERC Order in Southern California Edison, the cost of installing these “scrubbers” on new generators may be considered by states calculating the expenses a utility might “avoid.”425 Ultimately, however, under its 1995 Southern California Edison Order, FERC declared that states wishing to include non‐market benefits in avoided cost rates could do so through broad policy measures, like changes to state tax code laws or equipment compliance costs, but could not do so

419 Id. at ¶ 62,080. See also Rudy Perkins, Electricity Deregulation, Environmental Externalities, and the Limitations of Price, 39 B.C. L. REV. 993, 994 (1998). 420 Southern California Edison Co., 71 F.E.R.C. ¶ 61,269, at 62, 080 (1995). 421 Id. 422 Id. 423 SCOTT HEMPLING ET AL., Nat’l Renewable Energy Lab., NREL/TP‐6A2‐47408, RENEWABLE ENERGY PRICES IN STATE‐LEVEL FEED‐IN TARIFFS: FEDERAL LAW CONSTRAINTS AND POSSIBLE SOLUTIONS 9 (2010), available at http://www.nrel.gov/docs/fy10osti/47408.pdf. 424 S. California Edison Co., 71 F.E.R.C. ¶ 61,269, 62,080 (June 2, 1995). 425 Clean Air Act § 404(a)(19) (1977), (codified at 42 U.S.C. § 7651b (2012)).

62 merely by selecting an avoided cost rate‐setting methodology that favored environmentally preferable fuel sources.426

Yet, in 2010 FERC reversed course and substantially overruled Southern California Edison’s broad prohibition against the inclusion of environmental benefits in avoided cost rates. 427 In California Public Utilities Commission, FERC articulated that avoided cost rates could permissibly differentiate between “various [qualifying facility] technologies on the basis of the supply characteristics of the different technologies.”428 FERC reasoned that certain policies, like mandates that a portion of utility electricity be supplied by solar photovoltaic generators, should permissibly enable state utility commissions to tailor avoided cost rates for power generated specifically by generators that complied with the policy, like solar photovoltaic generators, while still remaining within PURPA’s avoided cost limitations. 429 Since utilities are ordinarily precluded from using other sources of generation to meet specific procurement mandates,430 they could not “avoid” costs associated with those sources by turning to less expensive means of generation.431

Although FERC noted that low‐ and zero‐emission qualifying facilities could help utilities avoid certain compliance costs, like the need to purchase pollution emission credits, and could therefore be incorporated into avoided cost rates,432 FERC stopped shy of endorsing the technology‐specific rates because of the actual environmental benefits of renewable generation. Instead, FERC approved the technology‐specific rates out of deference to individual state policy decisions; stating that “states have

426S. California Edison Co. San Diego Gas & Elec. Co., 71 F.E.R.C. ¶ 61,269, 62,080 (June 2, 1995) (“[A] state may impose a tax or other charge on all generation produced by a particular fuel. . . . A state, however, may not set avoided cost rates . . . by imposing environmental adders or substractors that are not based on real costs that would be incurred by utilities.”); MICHAEL J. ZUCCHET, DEP’T OF ENERGY, RENEWABLE ENERGY ANNUAL 1995: RENEWABLE RESOURCE ELECTRICITY IN THE CHANGING REGULATORY ENVIRONMENT xxviii (1995). 427 Calif. Pub. Utilities Comm'n , 133 F.E.R.C. ¶ 61,059(Oct. 21, 2010). 428 Cal. Pub. Utilities Comm'n, 133 F.E.R.C. ¶ 61,059, at ¶ 4 (Oct. 21, 2010). The same 2010 FERC order also noted the physical location of a qualifying facility could offer savings by decreasing costs of electricity transmission. Savings are primarily achieved by qualifying facilities, located near end‐use consumers, could cut down on energy losses due to inherently inefficient transmission grid, or displace utility need for additional transmission line construction, avoided cost rates could incorporate the associated savings. 133 F.E.R.C. ¶ 61,059, at ¶ 31. 429 Kaylie E. Klein, Bypassing Roadblocks to Renewable Energy: Understanding Electricity Law and the Legal Tools Available to Advance Clean Energy, 92 OR. L. REV. 235, 258 (2013). 430 CAROLYN ELEFANT, REVIVING PURPA’S PURPOSE: THE LIMITS OF EXISTING STATE AVOIDED COST RATEMAKING METHODOLOGIES IN SUPPORTING ALTERNATIVE ENERGY DEVELOPMENT AND A PROPOSED PATH FOR REFORM 9 (2011), available at http://www.recycled‐energy.com/images/uploads/Reviving‐PURPA.pdf. 431 ELEFANT, supra note, at 9. 432 Calif. Pub. Utilities Comm'n,, Order Granting Clarification, 133 F.E.R.C. 61,059 at ¶ 31.

63 the authority to dictate generation resources from which utilities may procure electric energy.”433 Nevertheless, the decision in California Public Utilities Commission has opened the door to avoided cost rates that incorporate characteristics of a qualifying facility in addition to accounting for the costs of utility generation.

2. State Approaches to Avoided Cost Rates

Between PURPA’s qualifying facility rates, net metering, feed‐in tariffs, and renewable energy credits, every state provides some means of compensating distributed generators for electrical output.434 Although some state net metering programs are based on avoided cost rates, PURPA’s qualifying facility rates are the only compensation method based entirely on avoided costs.435

Under PURPA’s mandatory purchase obligation, the rate paid for distributed generation output may not exceed a utility’s avoided cost. Although FERC continues to define the parameters of what attributes may be included as an “avoided” costs—most recently in the California Public Utilities Commission decision discussed above436 —under PURPA, determining the avoided cost rate is otherwise left to individual state utility commissions.437 Perhaps unsurprisingly, since 1978 states have developed

433 Calif. Pub. Utilities Comm'n, 134 F.E.R.C. ¶ 61,044, 61,160 (Jan. 20, 2011). But see Calif. Pub. Utilities Comm'n , 133 F.E.R.C. ¶ 61,059(Oct. 21, 2010) (“[I]f the environmental costs ‘are real costs that would be incurred by utilities,’ then they ‘may be accounted for in a determination of avoided cost rates.’”) (quoting So. Cal. Edison, 71 F.E.R.C. ¶ 61,269 at 62,080.) 434 Compare DSIRE, NET METERING, http://ncsolarcen‐prod.s3.amazonaws.com/wp‐content/uploads/2015/04/Net‐ Metering‐Policies.pdf (March 2015), with DSIRE, RENEWABLE PORTFOLIO STANDARD POLICIES, http://ncsolarcen‐ prod.s3.amazonaws.com/wp‐content/uploads/2014/11/Renewable‐Portfolio‐Standards.pdf (June 2015), and U.S. ENERGY INFO. ADMIN., U.S. DEP’T ENERGY, FEED‐IN TARIFFS AND SIMILAR PROGRAMS, http://www.eia.gov/electricity/policies/provider_programs.cfm) (last updated June 4, 2014). 435 18 C.F.R. §§ 292.101(b)(6), 292.304(e) (2015). Feed‐in tariffs are are governed by the Federal Power Act and subject only to a general dictate that they be “just and reasonable” and not “unduly discriminatory” against any particular source of generation. Federal Power Act §§ 205‐06, 16 U.S.C. § 824(a) (2012), 16 U.S. Code § 824d(2015). Renewable energy credits are priced according to market‐driven spot rates. U.S. DEP’T OF ENERGY, ENERGY EFFICIENCY & RENEWABLE ENERGY, RENEWABLE ENERGY CERTIFICATES (RECs), http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=5 (last updated April 2015). Because Renewable Portfolio Standards impose compliance costs on utilities, the price of renewable energy credits do indirectly track a utility’s avoided cost of compliance and typically demand a higher price in so‐called “compliance markets,” those states with portfolio standards. Id. 436 See supra Part V.B.1. 437 ELEFANT, supra note, at 13.

64 a wide variety of idiosyncratic methods to calculate these rates.438 Generally however, avoided cost rate setting methodologies may be loosely grouped under two approaches.439

The first and most common approach employed by states compares the generation cost of a non‐renewable “proxy” generator with the generation cost of a qualifying facility attempting to sell its output.440 Here, the avoided cost rate is merely the difference in generation cost between the qualifying facility and the “proxy” generator.441 However, because distributed or qualifying facility generation offsets different utility generators depending on a utility’s generation portfolio, time of year, and even time of day, the proxy method can produce rates that vary frequently and are largely driven by a utility’s choice of “proxy” power plant.442 While some states have sought to combat rate variance by establishing a “hypothetical proxy,” utilities have lobbed complaints that generation costs associated with hypothetical proxies exceed the cost of a utility’s actual proxy unit.443

The second approach models a given utility’s “revenue requirement,” the total revenue a given utility must collect in order to cover its own generation costs, with and without qualifying facility power.444 The two models are then compared to determine the avoided cost rate. For the purpose of the comparison, qualifying facility power is treated as free—the utility receives electricity without

438 ELEFANT, supra note, at 11. 439 A rarely used third approach is employed in a few jurisdictions where the aggregate supply of electricity from qualifying facilities consistently outstrips aggregate ability of utilities to absorb qualifying facility power. This approach pits qualifying facilities against one another in competitive bidding wars, whereby the state utility commission awards a purchase contract to the qualifying facility willing to accept the lowest bid. MAKING THE SEQUEL, supra note, at 13. Competitive bidding is employed in Georgia, North Carolina and Montana for qualifying facilities larger than a specified size. Petition of Biomass Gas & Electric, 2004 GA PUC LEXIS 43 (2005); Biennial Determination of Avoided Cost Rates for Electric Utility Purchases from Qualifying Facilities, 2007 NC PUC LEXIS 1786; Northwestern Energy's Application for Approval of Avoided Cost Tariff For New Qualifying Facilities (2010 Mont. PUC LEXIS 31). 440 ELEFANT, supra note, at 17. See also J. HEETER ET AL., Nat’l Renewable Energy Lab., NREL/TP‐6A20‐61042, A SURVEY OF STATE‐LEVEL COST AND BENEFIT ESTIMATES OF RENEWABLE PORTFOLIO STANDARDS 5‐7 (2014). A variation of the “proxy” approach is the “peaker” method, which compares the generation costs of a qualifying facility with the marginal, or most expensive generation source available for dispatch during the life of the purchase contract. ELEFANT, supra note, at 18. 441 ELEFANT, supra note, at 17. See also J. HEETER ET AL., Nat’l Renewable Energy Lab., NREL/TP‐6A20‐61042, A SURVEY OF STATE‐LEVEL COST AND BENEFIT ESTIMATES OF RENEWABLE PORTFOLIO STANDARDS 5‐7 (2014). 442 ELEFANT, supra note, at 17. See also J. HEETER ET AL., Nat’l Renewable Energy Lab., NREL/TP‐6A20‐61042, A SURVEY OF STATE‐LEVEL COST AND BENEFIT ESTIMATES OF RENEWABLE PORTFOLIO STANDARDS 5‐7 (2014). 443 MAKING THE SEQUEL, supra note, at 17. 444 ELEFANT, supra note, at 19.

65 having to pay for generating it—and thus any utility receiving qualifying facility power has a lower revenue requirement.445 The difference between the two models is the utility’s avoided cost.446

Avoided cost rates are also at the center of the current policy debate over net metering occurring in different states. While the overwhelming majority of states credit net metering customers at the retail rate, at least three states instead credit monthly excess at the avoided cost level.447 Moreover, since the start of 2014, at least six states have considered proposals to reduce the rate paid for excess generation from distributed generators from retail rates to avoided cost rates.448 Utilities in Arizona, Hawaii, and Colorado all have proposals pending before state utility commissions to reduce rates,449 while Arkansas’s proposed change to reduce rates for excess generation is pending before the state legislature.450 In Wisconsin, a state utility commission decision that would have allowed utilities to reduce net metering rates for excess generation to avoided cost levels was overturned by a state circuit court.451 In Ohio, the Public Utilities Commission of Ohio recently decided that customers with distributed generation systems are entitled to the “full value” of electricity they sent to the grid, which they define as generation and capacity charges.452 The state commission further ruled the utilities have to pay for the excess electricity sent to the grid even when the customers chose to receive power from one of the retail suppliers instead of the utility itself.453 This ruling – which arguably reinforces the misalignment between utility incentives and societal incentives for further distributed generation entry – is currently being challenged by the utilities before the Ohio Supreme Court.454

445 MAKING THE SEQUEL, supra note, at 10. 446 MAKING THE SEQUEL, supra note, at 10. 447 States that credit net metering customers at the avoided cost rate are: Missouri, MO. CODE REGS. ANN. Electric Utilities, 20, § 240‐20.65 (2012); Nebraska, NEB. REV. STAT.§ 70‐2002 (2009); 69 NEB. ADMIN. CODE §69‐09‐07 (2015); Utah, UTAH CODE ANN. § 54‐15‐104 (West 2015). In Wisconsin, non‐renewable generators are credit for excess generation at the avoided cost rate. Final Decision and Order, Wis. Pub. Serv. Comm’n, Docket No. 05‐EP‐6 (Sept. 18, 1992). 448 NC CLEAN ENERGY TECH. CNTR., THE 50 STATES OF SOLAR 8 (2015), available at http://nccleantech.ncsu.edu/wp‐ content/uploads/50‐States‐of‐Solar‐Issue2‐Q2‐2015‐FINAL3.pdf. 449 Proposal of Tucson Electric Power Co., No. E‐01933A‐15‐0100 (filed Mar. 2015), available at http://edocket.azcc.gov/Docket/DocketDetailSearch?docketId=18945#docket‐detail‐container1; Proposal of USNS Electric, Inc., No. E‐04204A‐15‐0099 (filed Mar. 25, 2015; proposal withdrawn Apr. 28, 2015), available at http://edocket.azcc.gov/Docket/DocketDetailSearch?docketId=18944#docket‐detail‐container1. Hawaii: No. 2014‐ 0192; Krysti Shallenberger, Colorado utility wades into net‐metering debate, EE NEWS, June 16, 2015, http://www.eenews.net/energywire/stories/1060020274/feed. 450 H.B. 1004, 90th Gen. Assemb., Reg. Sess. (Ark. 2015). 451 Renew Wisconsin v. Pub. Serv. Comm'n, Case No. 2014CV000169 (Decision Feb. 2015). 452 http://midwestenergynews.com/2014/08/04/ohio‐utilities‐fight‐net‐metering‐rules/ 453 http://midwestenergynews.com/2014/10/15/utility‐challenges‐net‐metering‐plan‐in‐ohio‐supreme‐court/ 454 http://midwestenergynews.com/2015/05/18/net‐metering‐going‐under‐the‐microscope‐in‐ohio/

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3. State Approaches to Incorporating Social and Environmental Benefits

Although avoided cost rates largely do not account for non‐market benefits, a number of state utility commissions as well as utilities have undertaken efforts to include social and environmental benefits in other compensation structures. 455

As of 2006, fifteen states advanced a general commitment, or gave state utility commissions specific authority, to account for environmental considerations in the oversight of in‐state utilities.456 In Maryland for example, the state public utility code broadly directs the state utility commission to “consider the public safety, the economy of the State, the conservation of natural resources, and the preservation of environmental quality” in all aspects of utility oversight.457 New Hampshire458 and Iowa459 state codes provide more rate‐specific direction; both explicitly commanding the state public utility commission to consider environmental consequences when setting rates. Similarly, the California state code directs rates incorporate pricing elements that reflect state policies intended to curtail pollutant emissions.460 Bolstered by the so‐called “greenhouse gas adder,” rates in California are $0.016

455 See, e.g., Ferrey, supra note, at 14 (“In the shift to on‐site distributed generation, QFs and self‐generation both have the potential to dramatically lessen the emission of criteria pollutants. The continued deployment of both technologies promises to limit the emission of pollutants and their attendant environmental costs, as compared to conventional generation.”); ELEFANT, supra note, at 32 (“Over 20 years ago, Florida approved inclusion of a standard offer contract language that recognizes emissions cost savings of renewables.”). 456 Michael Dworkin et al., Revisiting the Environmental Duties of Public Utility Commissions, 7 VT. J. ENVTL. L. 1, app. 8 (2006). States include: Alaska, Public Utilities Commissions Act, ALASKA STAT. § 42.05.141(7)(c) (2004); Connecticut, Public Utility Environmental Standards Act, CONN. GEN. STAT. ANN. §§ 16‐50g to 16‐50aa (West 1998); Florida, FLA. STAT.. ANN. § 366.81 (1999); Illinois, 220 ILL. COMP. STAT. ANN. 5/1‐102(b) (West 1997); Iowa, IOWA CODE ANN. § 476.41 (West 1999); Maine, ME. REV. STAT. ANN. tit. 35‐A, § 3302 (1988 & Supp. 2005); Maryland, MD. CODE ANN., PUB. UTIL. COS. § 2‐113 (LexisNexis 2000); Mississippi, MISS. CODE ANN. 77‐3‐ 2(1)(d)(e) (West 2005); New Jersey, N.J. STAT. ANN. 48:2‐23 (West 1998); New York, . N.Y. PUB. SERV. LAW § 5(2) (McKinney 2000); North Carolina, N.C. GEN. STAT. § 62‐2(5) (2000); Rhode Island, R.I. GEN. LAWS § 39‐1‐1(a)(3), (c) (1997); Utah, UTAH CODE ANN. 54‐1‐1(3)(b)(ix) (2000); West Virginia, W. VA. CODE ANN. § 24‐1‐1(a), (a)(5) (LexisNexis 2004); and Wisconsin, WIS. STAT. ANN. § 196.025(1) (West 2004). 457 MD. CODE ANN., PUB. UTIL. COS. § 2‐113 (LexisNexis 2000) (emphasis added). 458 New Hampshire, N.H. REV. STAT. ANN. § 362‐A:8(b)(4) (A state statute entitled “Payment Obligation; Public Utilities” dictates“[t]he commission shall, in all decisions affecting [rates for] qualifying small power producers and qualifying cogenerators, consider . . . Potential environmental and health‐related impacts.”). 459 Iowa, IOWA CODE ANN. § 476.43.3(e) (West) (“The board may adopt individual utility or uniform statewide facility rates. The board shall consider . . . External factors, including but not limited to, environmental and economic factors.”). Section 476.44(a) exempts utilities form the rate structure when purchasing, “at any one time, more than . . . one hundred five megawatts of power from alternative energy production facilities”. IOWA CODE ANN. § 476.44.2(a) (West). 460 CAL. PUB. UTIL. CODE § 399.20(d)(1), (2) (West) (“The tariff shall provide for payment for every kilowatthour of electricity purchased from an electric generation facility . . shall include all current and anticipated environmental compliance costs [including] mitigation of emissions of greenhouse gases and air pollution offsets associated with the operation of new generating facilities in the local air pollution control or air quality management district where the electric generation facility is located.”).

67 higher for each kilowatt hour of renewable electricity purchased by a utility; a 16.6% increase in the rate when compared to the price without the GHG Adder.461

Another common means of compensating distributed generators for the environmental benefits of renewable generation is through renewable portfolio standards. Twenty‐nine states and the District of Columbia have adopted renewable portfolio standards,462 and every state with a renewable portfolio standard has also adopted renewable energy credits. Renewable energy credits are the tradable commodities that reflect environmental attributes of renewable electricity but may be sold independently of the electricity itself.463 Renewable energy credits can command between $22 and $480 per‐MWh.464

In addition, and as noted above, three jurisdictions – Austin, Texas,465 Minnesota,466 and Maine467 – have implemented a “value‐of‐solar” tariff for distributed solar generation; which compensates net metered generators at a rate that incorporates the cost of electrical generation and distribution incurred by a utility, plus external benefits like environmental consequences and increased reliability of electricity supply.468 For example, the rate in Maine incorporates a value for “avoided

469 environmental costs,” which is defined as avoided carbon dioxide (CO2), sulfur dioxide (SO2), and 470 nitrous oxides (NOx) emissions.

461 CALIF. PUB. UTIL. COMM’N., Market Price Referent (MPR), 2011 MPR Documents, http://www.cpuc.ca.gov/PUC/energy/Renewables/mpr, (Click on “2011 MPR Model” which loads an excel data sheet. Next, click on the “Control” tab, and set “Project Start Date” to year 2015. Relevant data is found in cell G7 and G11). 462 See infra note 155 and accompanying text. 463 TODD JONES ET AL., CENTER FOR RESOURCE SOLUTIONS, THE LEGAL BASIS FOR RENEWABLE ENERGY CERTIFICATES 3, app. 12 (2015). 464 JOHN FARRELL, INST. FOR LOCAL SELF RELIANCE, Minnesota’s Value of Solar Can a Northern State’s New Solar Policy Defuse Distributed Generation Battles? 16 (2014), available at http://ilsr.org/wp‐content/uploads/2014/04/MN‐ Value‐of‐Solar‐from‐ILSR.pdf. 465 In 2012. News, Austin Energy, New Value of Solar Rate Takes Effect January, (last accessed August 20, 2015), https://austinenergy.com/wps/portal/ae/about/news/press‐releases/2013/new‐value‐of‐solar‐rate‐takes‐effect‐ january/!ut/p/a1/jZBNT4NAEIZ_iweOy04Xq‐ iNokGsSDwUVy5m2gwfSnfJ7rak_nppvKhptXOb5Hneyby85JKXCrdtja7VCrv9Xl68ggjFXQwiTS5FCFESz‐ bT4nFylYkRePkO5Lf5DaRFXkT5PIYkDk70j0wE__n3JxwQJouzmpc9uoa1qtJc9oasZYY6QkuWSwGTgEtFA9tityGmK2Z1 h4YZdMQcvpNlVFW0cuwN1QbNbh8cqWUQjsGGKjJk_I0ZG2uc6‐21Bx4Mw‐DXWtcd‐ Su99uCQ0mjruPxJ8mde_vXWE5z_Bg70_gUcL7ZfL‐THw2y63AXQptHZJ7MRshI!/dl5/d5/L2dBISEvZ0FBIS9nQSEh/. 466 In 2014. H.R. 729, 88th Leg., 4th Engrossment, (Minn. 2013). 467 In 2015. H.P. 863, 127th Leg., 1st Reg. Sess. (Me. 2015). 468 TAYLOR, ET AL., supra note, at 62. 469 MAINE PUB. UTIL. COMM’N, MAINE DISTRIBUTED SOLAR VALUATION STUDY, at 34 (March 1, 2015), available at http://www.nrcm.org/wp‐content/uploads/2015/03/MPUCValueofSolarReport.pdf. 470 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note 266, at 34.

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The total value‐of‐solar rate offered to distributed solar customers in Maine—including environmental benefits, avoided generation, transmission, and distribution expenses, and social benefits like avoided fuel price uncertainty—is estimated at $0.182 per kWh in 2016 and $0.337 per kWh over the next 25 years.471 The value of solar rate offered in Austin, Texas in 2015 is $0.113 per kWh,472 approximately $0.12 per kWh in Minnesota.473 To compare, the current net metering rate is $0.118 per kWh in Maine,474 and averages $0.101 per kWh nationally.475

Finally, environmental benefits are included with some regularity in state energy efficiency studies. Energy efficiency studies are intended to test whether the benefits of a particular energy consuming appliance or program outweigh the costs associated with that appliance or program.476 These studies may be used to build support for state or utility programs intended to reduce overall electricity consumption by substituting certain technology for more advanced equipment capable of producing the same end‐use service.477 Energy efficiency programs include the well‐known ENERGY STAR program, high‐efficiency appliances, efficient lighting programs, and efficient building certifcations.478 Because increased efficiency of end‐use energy consuming devices will alleviate some

471 MAINE DISTRIBUTED SOLAR VALUATION STUDY, supra note, at 50. 472 CITY OF AUSTIN ELECTRIC RATE SCHEDULES, https://austinenergy.com/wps/wcm/connect/c6c8ad20‐ee8f‐4d89‐be36‐ 2d6f7433edbd/ResidentialSolar.pdf?MOD=AJPERES&projectid=2492f86b‐3966‐4c22‐8be3‐ b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐ b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐ b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐ b97d4dea7d4a&projectid=2492f86b‐3966‐4c22‐8be3‐b97d4dea7d4a&projectid=efa9a0b8‐09b5‐4650‐8b9e‐ 469db95da734&projectid=efa9a0b8‐09b5‐4650‐8b9e‐469db95da734&projectid=efa9a0b8‐09b5‐4650‐8b9e‐ 469db95da734&projectid=efa9a0b8‐09b5‐4650‐8b9e‐469db95da734&projectid=efa9a0b8‐09b5‐4650‐8b9e‐ 469db95da734&projectid=efa9a0b8‐09b5‐4650‐8b9e‐469db95da734&projectid=efa9a0b8‐09b5‐4650‐8b9e‐ 469db95da734 (last visited August 20, 2015). 473 Frank Jossi, Minnesota Regulators Side With Utility In Value‐of‐Solar Case, MIDWEST ENERGY NEWS, Aug. 7, 2014, http://midwestenergynews.com/2014/08/07/minnesota‐regulators‐side‐with‐utility‐in‐value‐of‐solar‐case/. 474 U.S. ENERGY INFO. ADMIN., U.S. DEP’T ENERGY, STATE ELECTRICITY PROFILES, http://www.eia.gov/electricity/state/ (last visited August 20, 2015). 475 U.S. ENERGY INFO. ADMIN., U.S. DEP’T ENERGY, UNITED STATES ELECTRICITY PROFILE 2013, TABLE 1, 2013 SUMMARY STATISTICS, http://www.eia.gov/electricity/state/unitedstates/ (last visited August 20, 2015). 476 CAL. PUB. UTIL. COMM’N, ADDRESSING NON‐ENERGY BENEFITS IN THE COST‐EFFECTIVENESS FRAMEWORK 1, available at http://www.cpuc.ca.gov/NR/rdonlyres/BA1A54CF‐AA89‐4B80‐BD90‐0A4D32D11238/0/AddressingNEBsFinal.pdf (last visited Aug. 25, 2015). 477 Energy Efficiency, U.S. EPA, http://www.epa.gov/statelocalclimate/state/topics/energy‐efficiency.html (last visited Aug. 25, 2015). Energy Efficiency, Glossary, U.S. EPA, http://www.eia.gov/tools/glossary/index.cfm?id=E (last visited Aug. 25, 2015). 478 Energy Efficiency, U.S. EPA, http://www.epa.gov/statelocalclimate/state/topics/energy‐efficiency.html (last visited Aug. 25, 2015).

69 need to generate, transmit, and distribute electricity, energy efficiency programs can result in significant cost savings.479

Nationwide, 44 states and the District of Columbia have a formal energy efficiency program.480 According to a 2012 survey conducted by the American Council for an Energy‐Efficient Economy, of these 45 jurisdictions, at least fourteen states and the District of Columbia determine the cost‐ effectiveness of an active or proposed energy efficiency program using a “Societal Cost Test” that incorporates environmental benefits that flow from greater energy efficiency.481 Eight of these jurisdictions calculate a specific value for reduced emissions, while the rest use a more general “environmental adder” to reflect environmental benefits.482

4. Historical Antecedents

The current debate on net metering, when analyzed in a broader energy policy context, is just another step towards patching up the holes in energy policy one‐by‐one as they come along without any consideration of the “bigger picture.” Similar debates on how to value a particular resource that bring environmentalists against utility companies happened previously in energy efficiency or demand response483 contexts, and will happen again in the near future when battery storage systems become more widespread or new behind‐the‐meter technologies become available.

The energy crisis in 1970s sparked broad efforts to encourage energy conservation by promoting energy efficiency and demand side measures.484 The central point of debate during this period, just like in net metering now, was what should the “price” paid by utilities for energy conservation given the additional system benefits of energy conservation such as deferred capacity investments be, and how much conservation should be “purchased.” Similar to the net metering debate, arguments for cost‐ recovery, possibility of cost shifting between customers, and the possibility of overinvesting in cost‐

479 TIM WOOLF ET AL., ENERGY EFFICIENCY COST‐EFFECTIVENESS SCREENING 12–13 (2012). 480 MARTIN KUSHLER ET AL., A NATIONAL SURVEY OF STATE POLICIES & PRACTICES FOR THE EVALUATION OF RATEPAYER‐FUNDED ENERGY EFFICIENCY PROGRAMS 3 (2012), available at http://aceee.org/sites/default/files/publications/researchreports/u122.pdf. 481 MARTIN KUSHLER ET AL., supra note, at app. 59. The Societal Cost Test “includes the costs and benefits experienced by all members of society,” including externalities and reduced emissions. WOOLF ET AL., supra note, at 22. 482 KUSHLER ET AL., supra note, at 32. 483 Insert summary of pricing arguments from FERC case 484 See David N. Carvalho, Energy Conservation through the State Public Utility Commissions, 3 HARV. ENVTL. L. REV. 160, 172‐85 (1979) (describing early efforts to promote conservation the federal and state levels); ALLIANCE TO SAVE ENERGY, UTILITY PROMOTION OF INVESTMENT IN ENERGY EFFICIENCY: ENGINEERING, LEGAL, AND ECONOMIC ANALYSIS 339‐343(1983) (hereinafter [Alliance to Save Energy]).

70 ineffective programs were discussed.485 And, again, similar to net metering debate, environmental groups advocated for energy efficiency based on non‐system benefits such as reducing emissions.486

Many states have already expanded their screening tests to consider a fuller range of externalities in their benefit‐cost analyses. For example, Vermont and the District of Columbia include social benefits for energy efficiency projects using a percentage adder.487 Rhode Island monetizes various externalities, including health and safety benefits, improved comfort (thermal and noise reduction), property value benefits, and other societal impacts in its project assessments.488 Massachusetts, the highest ranking state for energy efficiency according to ACEEE,489 also applies an expansive cost test for energy efficiency and has considered adopting a similar test for resiliency. The state’s test uses a societal discount rate and monetizes various health, safety, and environmental benefits in its analyses490 —both hallmarks of benefit‐cost methodology.491 These practices of forward‐ thinking states demonstrate that it is appropriate and possible to monetize many non‐energy benefits.

VI THE PROMISE OF TIME‐ AND DEMAND‐VARIANT PRICING

An “Avoided Cost/Social Benefit” approach to compensating distributed generation is only a stop‐gap measure until a comprehensive retail electricity reform can take place. Cost recovery and cost shifting problems are unintended consequences of retail rate designs, and should not be blamed on net metering polices. The first‐best solution to the problems caused by net metering is to correct the inefficiencies of the retail rates. As distributed generation and other similar resources are becoming a

485 Sources from Nathan’s memo 486 See Alliance to Save Energy, supra note 484, at 351‐352. Illinois Commerce Commission on its Own Motion: Proceeding to Adopt a Comprehensive Energy Plan, 1989 Ill. PUC LEXIS 366, at *61‐62; Cavanagh, supra note Error! Bookmark not defined., at 335‐36 n.106. 487 TIM WOOLF ET AL, SYNAPSE ENERGY ECONOMICS, INC., ENERGY EFFICIENCY COST‐EFFECTIVENESS SCREENING IN THE NORTHEAST AND MID‐ATLANTIC STATES 46, 57‐58 (Oct. 2013) available at http://www.neep.org/sites/default/files/resources/EMV_Forum_C‐E‐ Testing_Report_Synapse_2013%2010%2002%20Final.pdf. 488 TIM WOOLF ET AL, SYNAPSE ENERGY ECONOMICS, INC., ENERGY EFFICIENCY COST‐EFFECTIVENESS SCREENING IN THE NORTHEAST AND MID‐ATLANTIC STATES 46, 57‐58 (Oct. 2013) available at http://www.neep.org/sites/default/files/resources/EMV_Forum_C‐E‐ Testing_Report_Synapse_2013%2010%2002%20Final.pdf. 489 See Executive Summary, 2014 State Energy Efficiency Scorecard, AM. COUNCIL FOR AN ENERGY‐EFFICIENT ECON. 4, http://aceee.org/files/pdf/summary/u1408‐summary.pdf (last visited Aug. 20, 2015). 490 WOOLF ET AL., supra note 488 at 43; ELIZABETH DAYKIN, ET AL., PICKING A STANDARD: IMPLICATIONS OF DIFFERING TRC REQUIREMENTS, THE CADMUS GROUP 2 (Dec. 15, 2010). 491 See generally, OFFICE OF MGMT. & BUDGET. CIRCULAR A‐4 at 33 (2004).

71 key component of the nation’s energy policy and utility business models are changing as a result, reforming the retail tariff structures is becoming a policy imperative to achieve efficiency gains both in the retail electricity markets and the distributed energy resources market.

Current tariff designs are essentially trying to use one flat volumetric price per kWh to recover costs that are incurred in non‐volumetric ways. This economically inefficient practice is leading to perverse incentives when it comes to renewable energy resources and hurting successful integration of distributed generation when and where it is most valued. One of the most important reasons for having to use such volumetric rates was related to the lack of technology that can measure and record time‐ variant consumption, but such technological barriers are falling as advanced metering infrastructure becomes cheaper and more prevalent across the United States.492

The economic literature on tariff design is long and rich,493 and an extensive review of this literature is beyond the scope of this Article. However, there is value to summarizing the well‐accepted principles of public utility rate‐making initially laid out by James Bonbright.494 Ideally, tariffs should be effective in yielding the required revenues, they should be fair in allocating the costs among customers should avoid undue discrimination, they should promote both static efficiency by discouraging wasteful use and dynamic efficiency by encouraging innovation and responding to changing demand and supply patterns, they should reflect all present future private and social costs of providing electricity, they should provide revenue stability for the utilities and rate stability for the customers, and finally, they should be simple, understandable, and free from controversies as to proper interpretation.495

The efficiency problems created by the interaction of net metering policies and inadequate retail rate designs are preventable if regulators moved towards more sophisticated rate designs that followed Bonbright’s principles more closely. Such rate designs should be unbundled – with each component such as generation, distribution and transmission valued and priced separately – and more cost‐reflective496 so that costs are recovered in a fashion that is similar to the way they are incurred based on the unit of their drivers. For example, energy generation costs which are based on the volume of energy sold should be recovered using volumetric charges, and the fixed system costs that do not vary with the amount or the time of energy consumption should be recovered using fixed charges. If the

492 http://www.ferc.gov/legal/staff‐reports/2014/demand‐response.pdf 493 Simshauser has a brief history review, so does Faruqi 2015 494 Bonbright 1961 principles of public utility rates & 1988 Bonbright et al 495 Id. 496 Faruqi, global movement towards cost reflective tariffs

72 highest electricity capacity a customer needs at a particular time period is driving the need for further infrastructure investment, charges that are specific to that time period based on the customer’s maximum demand – coincident peak demand charges – should be imposed. To ensure that existing network costs are recovered fairly a charge based on connected load should be imposed. To avoid cross‐ subsidizations volumetric energy charges should reflect the variation in locational and temporal changes in the cost of energy generation, transmission, and distribution.

New cost‐reflective retail tariff rate structures that provide customers proper price signals that reflect the actual costs underlying the provision of electricity, including the associated externalities outlined in the benefit‐cost framework, will improve economic efficiency in several ways. First, it will ensure that when customers make their decisions about electricity consumption, they will be taking into account the true costs of electricity at that particular time and location, and hence the observed market outcome will be a socially desirable one. Second, it will ensure that market price is actually signaling the true value of electricity to the society and will guide investments to where they would be most valuable to the society.497 And finally, cost‐reflective tariffs that allow for valuation of several different dimensions of benefits would provide versatile compensation tools that could reduce inefficiencies caused by attempting to integrate new and cleaner energy resources into the existing grid while relying on today’s limited tariff designs.

The implementation of such a tariff structure would be easy if we were building a system and corresponding tariffs from scratch. However, while an ideal tariff structure has to be guided by economic theory, it also has to adapt to the realities of the current system. Any significant tariff change cannot be implemented overnight with any disregard for the stakeholders who stand to lose initially. For example, while such tariffs would decrease the need for capacity investments in the future, those benefits are accrued in the future whereas the bill increases are borne immediately by today’s customers. Or, a move from a low fixed charge – high volumetric charge type rate structure to a higher fixed charge – lower volumetric charge type of rate structure would initially hurt low users of electricity, who are presumably also lower income customers. The possibility of such transitional equity problems should be recognized, and policy solutions aimed at these problems should be discussed as part of a reform.

Keeping volumetric rates artificially low is not the solution to such equity concerns regarding vulnerable low‐income energy customers. After all, similar concerns exist for many other essential goods

497 Borenstein 2015, arguments about how rate design can greatly influence incentives for residential solar

73 such as food or health insurance. Instead of distorting the prices of many basic food items, food stamps are given to low‐income customers to partially cover their food spending. Instead of regulating health insurance premiums, subsidies are given to lower‐income consumers to defray the cost buying health insurance. Such practice is not limited to big‐scale federal policies, either. Even utilities themselves have special programs to help low‐income consumers.498 Similarly, looking at the evolution of tariffs in the telecommunications sector, and analyzing the various tariffs geared at customers with different profiles, would provide valuable insights for the electricity sector.

It is important to keep in mind that social welfare is maximized when the market price equals to the marginal private and social cost.499 Once such price is established so that the maximum possible net benefits can be realized, distributing this net value among different groups of stakeholders is best done with direct transfer programs that have specific policy goals such as crediting low‐income customers with fixed amounts on their energy bills. Distorting the prices for everyone with the sole goal of protecting low‐income customers, may indeed be hurting them as overall economic efficiency is impaired.

A. Valuing Distributed Generation with Time‐ and Demand‐Variant Pricing

Using a cost‐reflective tariff would not only improve overall system efficiency, but it would also improve the value of distributed generation for several reasons. First, a bundled flat volumetric rate insulates both the consumers and producers from receiving the correct price signals about the true societal cost of generating energy. This prevents the consumers from adjusting their usage based on the actual cost of electricity. More importantly, a flat rate prevents prices to be interpreted as efficient investment signals. Correct price signals ensure an efficient allocation of resources by directing distributed generation investments to where they are needed the most. If distributed generators are getting the same compensation for the energy they export to the grid at all times even though the cost of electricity is higher at certain times, they do not have any incentives to guide their investments towards peak demand times. If, on the other hand, the retail prices reflected such variations, and consequently net metering policies compensated distributed generators at a higher price when it is costlier to generate electricity, more distributed generation would be installed to take advantage of these higher returns, leading to investments decisions that are most beneficial for the society overall.

498 Con Ed low income reduced rate. Find similar programs. 499 Any intro economics book.

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Second, using a flat volumetric rate undercompensates distributed generation for other benefits it provides such as reducing grid congestion when the system is close to capacity during peak hours. Consumers’ maximum demand during system peak periods is the main driver of any new system capacity investment,500 hence distributed generation systems that help customers reduce their maximum demand during these times periods have more value to the society that cannot be captured by flat volumetric rates.

Third, a flat volumetric rate creates perverse incentives for customers during the installation phase. As net metered customers are compensated using the same flat rate regardless of what time they send energy to the grid, their inherent incentive is to install solar panels with the goal of maximizing their total production rather than overall system benefits. These incentives lead to most of the solar panels being installed facing south to maximize production.501 If, instead, the rates reflected overall systems benefits and hence customers were provided incentives to install the solar panels west, the production would be maximized during the peak demand period between 2:00 p.m. and 8:00 p.m., providing more value to the system overall by curbing the need to dispatch more expensive peaker plants.502

Finally, the amount of displaced greenhouse gas emissions as a result of distributed generation also depends on time and location. The amount of this change depends on the emissions rate of the generator that is on the margin when the distributed generator sends electricity to the grid. Once again, using a flat volumetric that does not granularly reflect the changes in the external costs of electricity generation preventing the realization of the full value of distributed generation.

If the tariffs are more cost‐reflective so that the volumetric component no longer reflects the bundled fixed costs, and reflects only the volumetric costs of providing energy at a particular location and time, then reimbursing distributed generation using this rate would not affect the recovery of utility’s fixed network costs and lead to shifting. If distribution network charges are calculated according to such cost‐causation principles and were imposed so as to capture each user’s contribution to total system costs, overall system efficiency would be improved, even when net metering is used. Such tariffs would improve a utility’s ability to recover its costs related to distribution of energy while rewarding distributed generation to the extent that it helps delays future distribution capacity expansions.

500 Simshauser at 6, but there are also many other sources, check farruqi, hledik, etc. 501 http://blog.opower.com/2014/12/solar‐homes‐utilities‐love/ 502 http://www.utilitydive.com/news/how‐california‐is‐incentivizing‐solar‐to‐solve‐the‐duck‐curve/317437/ Cite the report http://www.eenews.net/assets/2015/07/10/document_ew_01.pdf

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A maximum demand charge that is properly designed, unlike an unnuanced fixed charge, provides strong incentives for customers to reduce their kW demands, especially during distribution system peak periods, and hence giving customers more incentives to install distributed generation systems.503 Since capital investments to expand or maintain utility infrastructure are driven by the utility’s obligation to meet maximum consumer demand at all times, demand charges are intended to align consumer payments with the cost they impose on utilities.504 Hence, if these peak periods are set according to the actual distribution system peaks, customers will have the proper incentives to install their solar panels where they are needed the most.

For example, take a distribution network tariff in which network costs are recovered using a two‐part tariff that includes a basic fixed charge for connected load505 and a per kilowatt based coincident demand charge that is based on a customer’s maximum demand during the distribution network’s peak period. Individual connected load charges allow the already incurred basic network costs to be socialized fairly across different customer classes based on the amount they contribute to the system costs.506 A maximum demand charge that is coincident with distribution network peak at a particular location would allow the costs of system expansion to be imposed on the customers that drive such an expansion as the maximum demand during peak periods is the main driver of any new system capacity investment.507 If distributed generation lowers a customer’s peak demand at a particular location, and hence lowers her contribution to the need for future capacity investment, she will benefit in the form of lower demand charges.508 If a customer’s distributed generation consistently lowers her demand at all times so that her need for connected load is lower at all times, she benefits in the form of lower connected load charges.

Having the right price signals would ensure an efficient allocation of resources by directing distributed energy resources investments to where they are needed the most. It is important to realize that not all distributed energy resources are created equal and they can be used to serve different purposes. Encouraging solar panels to be installed in specific areas that are closer to requiring capacity can provide ten times more capacity value compared the installations averaged across a whole service

503 Faruqi Hledik, SRP at 19 504 INST. ELEC. INNOVATION, NET ENERGY METERING: SUBSIDY ISSUES AND REGUALTORY SOLUTIONS 4 (2014). 505 Faruqi presentation 506 Cite perez‐arriaga MIT papers 507 Simshauser at 6, but there are also many other sources, check farruqi, hledik, etc. also rev track 2 footnote 81 508 Cite Borenstein 2015 about locational capacity benefits

76 territory.509 While solar panels may be more valuable when installed near areas where demand peaks during the day, investing in wind turbines may be more valuable in areas where the demand is late peaking as that is when wind production also peaks.510 Some distributed energy resources may not provide desired benefits in certain areas511 so reallocating funds to more effective resources in those areas may be necessary to achieve clean and reliably energy goals in the least‐cost manner. Only by using a comprehensive framework that can recognize such granular variations in valuations, we can move beyond narrow and short sighted debates on specific programs that may result in inefficiently favoring one low‐carbon resource over another and start the debate on how to utilize all distributed energy resources to their fullest extent possible.

B. Incorporating Externalities into Dynamic Pricing

Environmental and health benefits of distributed generation systems are among the most important reasons by they are at the center of clean energy policy initiatives. Such external benefits that are not always fully or even partially reflected in today’s tariff structures, has to be recognized and internalized in any tariff design that is aimed at maximizing net social benefits.

Internalization of externalities in retail rates is crucial to the success of clean energy policies, especially when dynamic tariffs are used. Using time‐ and demand‐variant pricing does not automatically resolve environmental or health concerns related to emissions. It is important to note that while dynamic tariffs provide more incentives for distributed generation deployment and thus result in a decrease in the energy demanded from the bulk system, unless the externalities are internalized in retail rates, dynamic rates may also cause in consumers without distributed generation systems to shift their loads to periods where dirtier plants are on the margin. Understanding these two effects is crucial in preventing an inadvertent raise in overall emissions.

As the peaker plants are often less efficient and dirtier,512 overall emissions decrease when distributed generation reduces the need for the electricity generated from such plants. However, if

509 Cohen Kauzman Callaway 2015 at 16 510 http://pubs.aeaweb.org/doi/pdfplus/10.1257/pol.5.4.107 511 http://www.nytimes.com/2015/06/24/business/combating‐climate‐change‐with‐science‐rather‐than‐ hope.html?_r=1 512 http://www.scientificamerican.com/article/power‐plant‐greenhouse‐gas/, http://energystorage.org/energy‐ storage/technology‐applications/flexible‐peaking‐resource http://www.storagealliance.org/sites/default/files/Presentations/Energy%20Storage%20Cost%20Effectiveness%20 2013‐09‐23%20FINAL.pdf

77 time‐varying rates shift consumption to other periods, calculating the net effects requires a more careful analysis. If the load is shifted from a period when an inefficient oil‐fired plant is on the margin to a period when a more efficient gas‐fired unit is on the margin, the overall greenhouse gas emissions would decrease. If, however, the load is shifted to a period when the cheaper coal‐fired base load plants are on the margin, overall carbon emissions may increase even if this shift lowers overall energy generation costs. Thus, any tariff underlying net metering should include externalities at a granular enough level to be able to account such temporal variation.

If the temporal dimensions are not taken into account while calculating environmental and health benefits, and all distributed energy resources are rewarded based on the same average quantity of avoided emissions, then the market incentives will lead to more investment in cheaper distributed energy resources, regardless of whether they are the most beneficial for the society when externalities are taken into account.

CONCLUSION

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