Too Much, Too Soon: A Case For Slowing The Rate or Degree Of Withdrawing Federal Regulatory Incentives For Photovoltaic Cells

February 24, 2020 by Roy Jackson

In this exclusive online article, Roy Jackson, a recent Georgetown Law graduate, explains how photovoltaic-solar (“PV”) project costs have decreased in recent decades and how investments in this industry may grow stagnant under both recently enacted and proposed federal policy changes.

I.              Introduction*

For decades, the photovoltaic-solar (“PV”) market has enjoyed many regulatory benefits that encourage the technology’s growth and make it a viable component of the energy infrastructure of the United States. Only in the past ten years, however, has the PV market experienced significant growth as a contributing source to the American energy market. Solar energy consumption has increased from a total of about 21.69 billion kWh in 2008 to more than 227.13 billion kWh in 2017; solar electricity net generation has increased from 1.97 billion kWh in 2008 to 72.35 billion kWh in 2017.[1] Despite the significant increases in consumption and generation, solar energy still only contributes about 1.35% of the United States’ total electricity generation.[2] Thus, while the recent increase is a good sign for solar energy’s viability, sustained growth is necessary for PV to become a significant energy generator.

The increase has been driven largely by PV technology advancing to the point of being sufficiently cost effective in residential, commercial, and utility-scale use. PV’s cost effectiveness derives from the decreasing costs associated with manufacturing, installation, and maintenance as well as from the benefits derived from federal, state, and local regulatory incentives. Recently, however, policymakers have used the growing presence and decreasing costs of PV systems as evidence of the technology’s ability to survive without regulatory incentives or benefits, and have begun to repeal or reduce said policies.[3]

This paper will show that the repeal or reduction of multiple regulatory incentives within such a short timeframe is ill-advised, as the cumulative effect of these changes will likely disrupt the cost stability of PV projects, which will likely chill PV investments by increasing costs and decreasing revenue. As a result, PV’s growth may stall before it becomes a significant energy source. This paper will not argue that policy incentives encouraging PV investments should never be reduced or repealed, only that said changes should come at a rate which respects the rate of improving cost-efficiency of PV technology and of decreasing project costs, thereby mitigating the degree of disruption incurred by repealing the policy incentives. Following this (I) introduction, the paper will discuss: (II) the decreasing costs of PV projects, and the causes of such decreases; (III) the recently-enacted federal policy changes which will harm the PV industry; (IV) the proposed federal policy changes which would further harm the PV solar industry; and (V) the recently-enacted federal policy changes which may benefit the PV industry.

II.            PV Project Costs Have Been Decreasing

A cost-benefit approach is most appropriate when discussing the market value of PV projects. The cost-benefit analysis of the viability and value of PV projects more accurately reflects the market’s treatment of PV projects as investments.[4] Some may argue that it is inappropriate to monetize the environmental effects of renewable energy systems; therefore, a cost-effective analysis would be a more holistic approach to determining the value of PV projects. However, since the cost-benefit analysis more accurately reflects the market’s treatment of PV projects as investments, it will better account for the market incentives that motivate (or fail to motivate) investment in PV projects. Thus, in order to account for and forecast investment trends, this paper applies a cost-benefit analysis to determine PV projects’ value. The changes in costs associated with PV projects consist of (A) the costs of constructing and operating the PV projects themselves, and (B) federal, state, and local policy incentives aimed at lowering, or at least controlling, PV project costs.

A.            PV Project Costs Have Decreased Significantly, But at a Slowing Rate

Overall, PV project costs have declined since 2010.[5] The decreased costs have benefitted residential, commercial, and utility-scale PV systems. Residential system costs ($/Watt) of 5.7 kW system size have dropped from $7.24 in 2010 to $2.80 in 2017; commercial system costs of 200 kW have dropped from $5.36 in 2010 to $1.85 in 2017; and utility-scale system costs of 100 MW have dropped from an average of $5.00 in 2010 to $1.07 in 2017.[6] As such, the overall costs of PV projects have been declining drastically.

However, the most important pricing obstacle for PV systems to overcome is its capacity-weighted average levelized cost of energy (“LCOE”)—defined as the net present value of the unit-cost of electricity over the lifetime of the generating asset—relative to other energy sources.[7] Over the past decade, PV systems’ LCOE has become increasingly competitive, but the average has yet to match industry competitors.[8]  For example, some of the estimated LCOE for new generation resources entering service in 2022 are as follows: 59.1 for PV solar, not including any tax credit benefits, which lower the LCOE; 48.3 for Conventional Combined Cycle Natural Gas; 48.1 for Advanced Combined Cycle Natural Gas; and 48.0 for On-shore Wind, also excluding tax credit benefits.[9] Since PV solar does not use a traditional fuel, and therefore has no fuel costs, PV’s higher LCOE is primarily the result of higher capital and efficiency costs. Therefore, the PV industry must continue driving down capital costs and increasing component efficiency to make its LCOE more competitive with other energy sources.[10]

A PV system’s total capital cost is the sum of the following factors: (1) soft costs, such as permits, overhead, and net profit; (2) install labor; (3) structural and electrical hardware; (4) inverters; and (5) modules. From 2010 to 2016, a sharp decline in hardware costs  served as the primary driver of the decreasing prices. This decline constituted 61% of overall cost reduction. The reduced hardware costs resulted from the industry transforming into an economy of scale. Over the last ten years, the increasing size and number of manufacturing facilities has caused a decrease in the average manufacturer-sale price of PV hardware.[11] The cost of PV modules—the hardware component most affected by the scaling industry—has decreased by 86% between 2010 and 2017. As a result, the upfront costs of installing PV systems have decreased industry-wide.

Now the costs associated with, and decreased by a growing economy of scale make up a much smaller proportion of total project costs. Moreover, such costs are now a much smaller portion of overall project costs due to the establishment of a more scaled economy. As a result, continued scaling gives increasingly diminished returns, which have already become small when compared to other sources of costs that, until now, have not been the focus of project costs and economics. As such, emphasis has shifted from developing an economy of scale for those components already drastically reduced in cost (e.g., hardware costs) to addressing the costs that now make up larger portions of project costs—(1) hardware efficiency, and (2) soft costs.

1.              Hardware Efficiency Has Been a Significant Driver in Declining PV Project Costs

Increasing hardware efficiency has also contributed to the decline of PV project costs. For example, average residential modules have increased from 13.3% efficiency in 2010 to 16.2% efficiency in 2016; and average commercial modules have increased from 13.8% efficiency in 2010 to 17.5% efficiency in 2016.[12] Higher module efficiency reduces the number of modules required to install a system of any given size, which reduces the module costs, other hardware costs, and the labor hours associated with installing the system. Higher module efficiency also reduces the operation and maintenance costs of a PV system by requiring fewer inverters necessary to generate energy.[13] As a result, hardware efficiency has also helped drive down the costs of installing and maintaining a PV system.

2.             Soft Costs Are Becoming More Important Than Hard Costs for PV Projects

Hardware costs have decreased at a rate which has far outpaced the reduction of soft costs—costs such as permitting, inspections, interconnecting, land acquisition, and net profits. The result is that hard costs—hardware and installation—now make up a much smaller proportion of a PV project’s total costs compared to ten years ago. Hard costs are now: 32% of total costs for residential projects, compared to 50% in 2010; 41% of total costs for commercial projects, compared to 67% in 2010; and 59% of total costs for utility-scale projects, compared to 68% in 2010.[14] As hard costs’ proportion relative to total project costs continue to shrink, total-cost benefits derived from lowering hard costs will also decrease. Therefore, while decreasing hardware costs have been the primary driver in decreasing overall PV project costs, their shrinking proportion relative to total costs will mean diminishing returns for future decreases in hardware costs.

While the proportionate costs of hardware relative to PV projects’ total costs have decreased, the proportion of total costs resulting from soft costs have largely increased even though their actual cost has decreased. Soft costs (i.e. non-hardware costs, such as siting and permitting, financing, and installing) have therefore become more important in continuing to drive down PV project costs. Unfortunately, soft costs have decreased at an overall slower rate than hard costs, even with hardware efficiency contributing to decreases in soft costs (e.g., more efficient panels mean fewer that need to be installed to reach a given capacity, meaning less land acquisition, permitting, labor, and maintenance). In fact, soft costs for residential and commercial projects have stagnated between fine margins over the last five years and have cost more in each year following 2013.[15] Utility-scale projects benefit from having much larger project sizes and therefore fewer soft cost applications, processing, and related logistics; despite that fact, these projects have experienced recent resistance in trying to continue to drive down soft costs. As soft costs now reflect the majority portion of total project costs, their stagnation is an important concern to address in continuing to incentivize investments in PV systems so that they continue to grow as a US energy source.

B.             Policy Incentives Significantly Impact Investment Viability of PV Projects by Decreasing Capital Costs

Tight LCOE competition between PV solar systems and other energy sources—especially with the recent inversion of hard costs and soft costs, and the stagnated decline in soft costs—makes the market sensitive to policy incentives (and changes thereto).[16] As an example, the LCOE of forecasted PV projects with tax credit benefits (either from the Investment Tax Credit (“ITC”) or the Production Tax Credit (“PTC”), depending on which the project decides to take) is 37.6, compared to an LCOE of 48.8 without said benefits.[17] Current market sensitivity is such that even the prospective changes to individual policy incentives for PV systems have proven to have a chilling effect on project investments, evidenced by the stagnation of solar installations preceding ITC extensions.[18] Reducing or repealing multiple policy incentives within a narrow timeframe will therefore cause a stronger chilling effect on project investments, which will disrupt the industry’s growth and viability as a competitor in energy generation.

PV systems derive policy incentives from a variety of federal, state, and local laws. Naturally, federal laws generally have the widest application, and affect PV investments nationwide. Therefore, significant changes to federal incentives will have far-reaching effects. State and local incentives are restricted to their respective jurisdictions, and offered incentives vary widely between said jurisdictions. As the rate at which project cost decreases continue to slow, as explained above, maintaining stable policy incentives (at all levels) becomes more important for PV projects to close in on and eventually reach LCOE rates competitive with other energy sources. Once LCOE rates are competitive, phasedowns and phaseouts of policy incentives are appropriate provided they are calculated to match further decreases in costs so they do not cause a jump in PV’s LCOE.

III.         Several Recently-Enacted Federal Policy Changes Hurt the PV Solar Industry

In the span of one month, the federal government has enacted two significant changes to the PV industry: (A) on December 22, 2017, President Trump signed a tax bill passed by Congress which maintains the ITC phasedown; and (B) on January 22, 2018, President Trump levied a 30% import tariff on PV cells. While the enactment of one of these two policies would be enough to send at least a minor chill through PV investments, the combined effect of enacting both within such a short timeframe raises upfront project costs and undermines PV’s LCOE-competitiveness, therefore compounding any chilling effect from independently enacting the policy changes.

A.            ITC Phasedown Increases Project Costs

The ITC is arguably the solar industry’s most important policy incentive—a non-refundable tax credit which may decrease the taxpayer’s income tax liability by 30% of the value of a qualifying solar energy property.[19] The Energy Policy Act of 2005 (“EPA”) originally established the 30% ITC for residential, commercial, and utility-scale solar energy projects put into service between the beginning of 2006 and the end of 2007.[20] The Tax Relief and Health Care Act extended the ITC for an additional year—until December 31, 2008.[21] The Emergency Economic Stabilization Act in 2008 extended the credit once more until 2016, eliminated the monetary cap for residential installations, and permitted commercial and utility-scale projects to qualify for the credit even if the company or utility was paying the alternative minimum tax (“AMT”) rate.[22] In 2015, the Consolidated Appropriations Act granted another multi-year extension of the ITC for residential and commercial systems and changed the “placed-in-service” qualification standard to a “commence construction” standard for projects as long as the system is operational by December 31, 2023.[23]

The Omnibus Appropriations Act established a phasedown and a phaseout for the ITC,[24] which has been maintained by the recent tax reform referred to as the Tax Cuts and Jobs Act of 2017.[25] Unless otherwise extended, the phasedown will begin in 2020, which will allow owners of residential and solar systems to credit 26% of the system’s cost against tax liability, which is a decrease from 30%.[26] In 2021, the credit will decrease from 26% to 22% of the system’s cost.[27] From 2022 and onwards, the credit will decrease from 22% to 10% for non-residential solar systems and from 22% to 0% for residential solar systems.[28]

The phasedown (and phaseout for residential systems) of the ITC deals a significant blow to the solar industry, even with the mitigation of an “ITC cliff,” which would be caused by immediate repeal of the entire ITC, by phasing out the tax incentive at a more gradual rate rather than eliminating it outright. The ITC has a significant impact on the LCOE of solar systems, and while the phasedown may mitigate the severity of a “boom-and-bust” cycle, the phasedown will lead to an approximate 30% increase in the average LCOE of residential solar systems and an approximate 20% increase in the average LCOE of commercial and utility-scale solar systems.[29] With PV solar systems fighting for a competitive LCOE, especially as PV costs stagnate, the phasedown of the ITC impedes economic incentives for PV investments by increasing solar systems’ LCOE.

B.             Recent Tariffs on PV Cells Will Increase PV Project Costs[30]

On January 22, 2018, the Trump administration imposed a 30% tariff on PV cells, whether or not assembled into other products, such as modules, panels, and building-integrated materials.[31] The tariff is scheduled to decrease by 5% every year before resting at 15% in 2021 and remain as such until otherwise changed.[32] Imports account for about 80% of the U.S. solar industry’s solar panel products, which ensures that the tariff will have a widespread effect on the hard costs of PV projects. The tariff is estimated to raise solar module costs by $0.10 to $0.12 per watt in its first year,[33] which is expected to cause a $3.00 per milliwatt-hour increase in the LCOE of utility-scale solar. This would widen the LCOE-gap between solar and competitors like natural gas, just as PV solar has neared becoming cost-competitive.[34] Increased costs from the tariffs are projected to reduce new solar construction in the U.S. by about 7.6 GWs over the next five years, which is an 11% decrease from previous projects.[35] As was previously discussed, hard costs have contributed significantly to the overall decrease in the costs of PV projects. The tariffs, which raise hard costs of PV projects by such significant margins, will likely further cripple the solar industry’s ability to compete against other energy sources. The tariff on PV cell imports therefore adds a second element to the changes in policies which hinder the LCOE-competitiveness of solar energy, such as the ITC phasedown described above, by further decreasing project value and increasing the chilling effects of PV systems.

IV.          Recently-Proposed Federal Policy Changes Would Further Hurt the PV Solar Industry

Amid the already-enacted policy changes that directly target the solar industry, there is also bill proposal H.R.4476, which seeks to revise The Public Utility Regulatory Policy Act (“PURPA”), a policy that has been critical in encouraging investment in PV solar energy systems. Enacted in 1978, PURPA required electric utilities to buy power from other, more efficient energy generators, such as cogeneration plants and “qualified facilities” (“QFs”), as long as the cost was less than or equal to the utility’s “avoided cost”—the marginal cost for a public utility to otherwise produce the power. Since utilities needed to purchase energy from cogeneration plants and QFs before relying on their own generation capacity, the number of cogeneration plants and QFs around the United States increased. Later, the EPA revised several PURPA provisions and had the following effects: (1) prospectively eliminated the power-purchase mandate on public utilities where the QFs have access to competitive markets; (2) repealed the restrictions on utility-owned QFs; (3) required utilities to provide interconnections to transmission grids to customers owning self-generation systems; and (4) mandated state utility commissions and governmental utilities to consider adopting standards for net metering, fuel source diversity, generation efficiency, and smart metering. However, even with the EPA’s changes, PURPA has been a great asset to the growing PV solar industry. But now, recently proposed changes would heavily burden the investment viability of PV projects while the industry must already cope with the already-enacted ITC phasedown and PV-import tariffs. The issue is two-fold: (A) the proposed changes fail to make any changes to account for the changing state-level policy landscape to maintain PV project costs and stability, and (B) the proposed changes instead only increase PV project costs and volatility, with no trade-off.

A.            Federal Changes to PURPA Should Account for State-Level Changes

Before addressing the proposed changes to PURPA, it is important to address the ongoing state-level changes which operate underneath PURPA. The state-level landscape of PURPA-based policies has been undergoing changes which are significant to the PV-solar industry. Since the changes are made at the state level, the solar industry generally responds by seeking out the states with the most favorable investment conditions. Regardless, geographical limits[36] and policy limits[37] restrict viable locations, which justifies accounting[38] for such changes when considering changes to federal policy. The most significant of those changes are: (1) avoided cost rates, (2) term lengths of QF power purchase agreements, and (3) net-metering policies.

1.              Avoided Costs Rates Are Decreasing, Which Decreases Revenue of QFs

Decreasing rates of avoided costs are one factor which may discourage investments in PV systems. PURPA mandates that public utilities purchase energy from QFs at their “avoided cost,” which is the incremental cost to an electric utility of electric energy or capacity which, but for the purchase from the QF, such utility would generate itself or purchase from another source. Since avoided costs—the cost for the utility itself to source energy generation or capacity—generally dictate the returns a QF will receive on supplied energy, their rate has a heavy impact on the economic viability of developing and operating such facilities.[39] Over the past several years, decreases in costs of energy have led to states lowering their set avoided rates.[40] As a result of the lowered avoided rates, the expected revenues of PV systems and QFs decrease, which may mitigate, offset, or even outstrip the benefits of decreasing development and operating costs, which may discourage investments.

2.              Term Lengths of Power Purchase Agreements Are Shortening, Making QFs More Volatile Investments

Shortening term lengths in power purchase agreements between utilities and QFs may further discourage PV investments. While the standard term lengths in power purchase agreements between utilities and QFs was once twenty years, many states have decided to shorten the lengths, varying from fifteen years to as few as two years.[41] Shorter terms allow utilities to adjust contracted purchase rates to more quickly adjust to changing market conditions and prices, however, as a result, the long-term value of PV investments becomes less certain. Shorter-term contracts also increase the capital costs of projects due to increased interest rates, which reflect the more volatile asset, and due to transaction costs associated with more frequent renegotiating and drafting of new contracts. Since PV projects’ costs are incurred almost entirely upfront compared to other electricity generators which incur continuing fuel costs, the increased interest rates have a disproportionate impact on PV generators and their costs. As such, states’ adoption of shorter terms for the power purchase agreements between utilities and QFs may further discourage investments in PV systems.

3.              Net-Metering Policies Are Facing Increased Scrutiny

Net-metering policies incentivize investments in PV systems by allowing owners of said systems to use generated energy otherwise sold to utilities at wholesale rates to offset any energy the system may take from the grid that PV system users otherwise buy at retail price. However, utilities have recently begun to push back against states’ net-metering policies, citing concerns that the policy which benefits solar customers does so at the expense of non-solar customers.[42] As a result, the number of states with net-metering policies has been decreasing since 2015, and many  states with net-metering policies are considering alternative policies.[43] Repealing or reducing net-metering policies further adds operating costs and devalues PV project values because energy surplus cannot be directly used to offset consumption, which otherwise reduces operating costs. Thus, changes in federal policy should also account for recent trends in net-metering policies among states.

B.             Proposed Changes to PURPA Would Increase PV Project Costs and Investment Volatility

The proposed changes to PURPA would increase both project costs and volatility by (1) decreasing prospective QF value by forcing more QFs to compete in Regional Transmission Organization (“RTO”) and Independent System Operators (“ISO”) markets, thereby lowering the rates at which their energy is sold and the certainty that it will be sold; and by (2) increasing regulatory uncertainty and any associated transaction costs by changing the “one-mile rule” into a rebuttable presumption rather than a clear bright-line rule.[44]

1.            Lowering Capacity-Size Thresholds Would Decrease Qualifying Facilities Value, and Increase Their Volatility

When a system gains QF status[45]—granted when a facility demonstrates that its primary energy source is renewable, and its energy production is equal to or less than the set threshold—federal law ensures the facility has (1) the right to sell energy and capacity to a utility, (2) the right to purchase certain services from a utility, e.g., to interconnect to the transmission grid and to purchase of power at just and reasonable rates, and (3) relief from certain regulatory burdens.[46] For a production facility to be a QF under PURPA, its power production capacity must be no greater than 80 MW, even when accounting for other facilities located at the same site.

Having the right to sell energy and capacity to a utility incentivizes investments in PV projects by giving the QF, provided it qualifies as such, a market for produced energy. However, the EPA revised the right such that utilities do not have a “must-purchase” obligation for solar QFs with both an energy capacity between 20 MW and 80 MW, and with non-discriminatory access to an RTO, ISO, or comparable wholesale markets. [47] The lack of a “must-purchase” obligation and the need to compete in a wholesale market has a negative impact on a system’s return on investment (“ROI”) since it lowers the price at which produced energy will be sold. As a result, the Act incentivized investors to either (1) build 20–80 MW PV systems in regions without an RTO or ISO rather than in a region with one, (2) ensure systems built in RTO/ISO regions have less than 20 MW, or (3) seek out states with laws benefitting solar systems to offset the lack of a federal “must-purchase” obligation.

The proposed bill, H.R.4476, frustrates the growth of the solar industry. The bill proposes lowering the threshold for when the federal “must-purchase” obligation no longer applies from 20 MW threshold to 2.5 MW, thereby requiring systems greater than 2.5 MW (instead of 20 MW) to compete in wholesale markets.[48] In so doing, the proposed change would drive down potential returns on PV-system investments between 2.5 MW and 20 MW, which are the majority of solar QFs,[49] at a time when other policy changes are increasing the upfront costs, and consequently the LCOE, of PV projects. By enacting policies which increase the LCOE of PV systems, and subsequently requiring said systems to compete in wholesale markets, the returns on PV-system investments are both less certain and less valuable. Increased volatility and decreased value compromise investments in PV systems, rendering them less attractive investment assets, and thereby chilling such investments. As such, the proposed change to lower the capacity threshold for exempting QFs from “must-purchase” obligations would compound the chilling of investments already expected from the ITC phasedown and PV-import tariffs alone.

The bill could would cause further harm to the solar industry at a state-by-state level, since it would allow state utility commissions to waive a utility’s “must-purchase” obligations. Allowing state utility commissions to opt out of PURPA’s “must-purchase” obligations, even for QFs below 2.5 MW to whom the obligation would otherwise apply, would devalue investments and increase the volatility of all investments. As such, the proposed bill would negatively affect even systems below the 2.5 MW threshold.

2.              Changing the One-Mile Rule to a Rebuttable Presumption Creates Regulatory Uncertainty

The proposed changes to PURPA would also increase costs associated with PV projects by revising the “one-mile rule.” Currently, the Federal Energy Regulatory Commission (“FERC”), in determining the energy capacity of small power-production facilities seeking QF status, looks at whether (1) the facilities are located within one mile of one another, (2) use the same energy source, and (3) are owned by the same persons, companies, or affiliates.[50] The Commission treats the one-mile condition as a bright-line rule—refusing to consider facilities beyond the one-mile range as a part of the facility from which the one-mile range extends—but the proposed bill would change it into a rebuttable presumption. Changing the rule into a rebuttable presumption will likely increase transaction costs associated with PV projects, since a less clear standard will likely lead to more uncertainty when planning multiple projects and more due diligence or litigation over the matter. Since turning the one-mile bright-line rule into a rebuttable presumption results in a less clear regulatory standard, the change may increase costs of planning and litigating over PV QFs.

V.            The Degree to which Recently-Enacted Federal Policy Change Regarding Energy Storage May Help the PV Solar Industry is Uncertain

While many recent federal policy changes, whether already enacted or proposed, are imposing costs or uncertainty on the PV solar industry, FERC’s recently-issued final rule on electric storage participation in regional markets may benefit the industry, provided the resolution of certain questions and ambiguities favor solar facilities.

As of June 4, 2018, FERC requires each RTO and ISO to revise tariffs to recognize the physical and operational characteristics of energy storage resources and to facilitate their participation in wholesale markets.[51] Facilitating the participation of energy storage resources encourages the installation of large-scale solar-storage facilities, which could help address a large problem associated with standalone PV systems’ variable outputs: the declining marginal value of standalone solar power.[52] By turning a standalone PV system into a solar-plus-storage facility, the facility may sell generated energy directly unto the grid during sunlight hours while also charging the battery to sell additional energy to the grid at other times.[53] As such, FERC’s recent ruling—requiring RTOs and ISOs to revise tariffs to better accommodate energy storage participation in wholesale markets—may benefit the PV-solar industry by allowing them to sell excess generated energy at night, when the solar panels are no longer producing energy.

However, while it is likely that opening the wholesale market to energy storage components will benefit PV solar facilities, the degree to which they may benefit such facilities depends on the determination of two questions. The first question is (A) does an energy storage site, when charged by PV solar, qualify as its own distinct category of QF, or still remain categorized as solar? Whether or not a storage facility is its own distinct category of QF, despite being charged by solar, will affect whether state laws limiting capacity rates of solar facilities will also apply to solar-plus-storage facilities. The second question is (B) does adding energy storage to a QF, thereby increasing the facility’s overall capacity, disqualify the facility as a QF when the added capacity causes the QF to exceed PURPA’s capacity limits? If the added capacity can disqualify the facility as a QF, then facilities may be incentivized to limit or entirely omit installing energy storage on solar QFs to retain their QF status.

A.            Whether Energy Storage Facilities Will Qualify as a Distinct Category is Uncertain

The answer is uncertain to whether an energy storage facility qualifies as a distinct category of QF despite being charged by solar energy. Although neither FERC nor any court has yet rendered a final determination, FERC recently issued a decision not to initiate an enforcement action against the Idaho Public Utilities Commission for classifying Franklin Energy’s energy storage facilities as solar facilities, which are ineligible for the Idaho Commission’s published rate available to non-wind and non-solar QFs of 10 MWs average capacity or less.[54] Both the Idaho Public Utilities Commission and Franklin Energy rely on the Luz[55] requirement of considering an energy storage facility’s primary source of energy, but put forth different contentions. The Idaho Commission contends that it may use the primary source of energy to determine the type of QF since battery storage facilities are not a per se category eligible for QF status, and states have broad authority in implementing PURPA’s terms and conditions. Franklin Energy contends that considering a facility’s primary source of energy is to ensure the facility meets the fuel use requirements for QFs, and that determining the type or status as a QF is subject to FERC’s exclusive jurisdiction.[56] FERC did not attach a declaratory order to its notice of intent not to act, meaning that it has not set forth an official position on the matter.[57] As such, whether an energy storage facility charged by PV solar constitutes a distinct category of QF is uncertain.

B.             Energy Storage Capacity Will Likely Not Disqualify QFs Based on Capacity Factor

Adding energy storage to a facility will probably not disqualify a facility’s QF status if the added capacity causes the facility to exceed capacity limits, but said facility should still file a Form 556 Application for QF Qualification with FERC to be sure. The issue closely parallels that of existing solar thermal facilities with storage components, where FERC has issued Category One Seller status—which requires 500 MW capacity or less—to facilities which, when including energy storage capacity, exceed the 500 MW limit.[58] As long as the energy storage is not used to increase the facility’s capacity (i.e. maximum electric output), but instead used to increase the facility’s capacity factor (i.e. the ratio between plant capacity versus the plant’s actual output over a period of time) by filling in for times when solar energy is not fully available, FERC has granted such statuses.[59] PV sites may use energy storage components in the same manner, where the storage components only add to the facility’s capacity factor. As such, adding energy storage components to a QF should not disqualify the facility as long as the facility uses the storage only to increase its capacity factor and not its capacity outright.

VI.          Conclusion

The hasty repeal and reduction of federal policy incentives for the PV solar industry will shock the markets and increase such systems’ LCOE. The sticker-shock and widened LCOE gap between PV and other generation competitors will deter investments and slow the growth of installation of PV systems. Ideally, either the already-enacted ITC phasedown or the already-levied tariffs on PV cells would be delayed or lessened to permit the industry more time to decrease hard and soft costs so that PV-solar systems’ LCOE remains competitive. If not, then to mitigate the consequences of already-enacted policies which will hurt the PV industry, steps should be taken to prevent additional changes in policy which will further compound the chill in investments which the industry is bound to experience from rising costs due to the phasedown of the ITC and the newly-levied PV cell tariffs. As such, any of the above revisions to PURPA, or any other changes not yet included in the proposed H.R.4476 bill, should either be delayed or include provisions for delay as applied to PV solar QFs. Moreover, the questions and ambiguities regarding the application of FERC’s recent order to incorporate energy storage components to PV solar systems should be resolved in the industry’s favor. Removing the uncertainty of looming policy changes which would further discourage PV-solar investments would at least allow the PV industry to seek investments based on present circumstances without also adding in risks and costs associated with further changes.

* A special thank you to Judge Huey P. Cotton for encouraging me to pursue a career in law and for guiding me along the way, and to Tim Wendling for helping me to decide on this paper’s topic and for giving me direction.

[1] U.S. Energy Info. Admin., February 2018: Monthly Energy Review 159–60 (2018),

[2] See id. at 111.

[3] See, e.g., Scott Pruitt, Adm’r, U.S. Envtl. Prot. Agency, Address to the Kentucky Farm Bureau at Mahan Farms in Paris, Kentucky (Oct. 9, 2017), quoted in Timothy Cama, EPA Chief: I’d “do away with” wind, solar tax credits, The Hill (Oct. 9, 2017 03:42 PM), (stating that EPA Administrator Pruitt “would do away with these incentives that we give to wind and solar … [and] let them stand on their own . . . .”); Nichola Groom, Expiring U.S. Solar Subsidy Spurs Rush for Panels, REUTERS, July 19, 2019, https:// expiring-u-s-solar-subsidy-spurs-rush-for-panelsidUSKCN1UE0CO. Rob Nikolewski, Solar’s 30% Tax Credit for Installations Starts to Fall After this Year, THE SAN DIEGO UNIONTRIBUNE (Apr. 27, 2019, 8:00 AM),

[4] See, e.g., Ernst & Young, Capturing the Sun: The Economics of Solar Investment 6-7 (2016),$FILE/EY-capturing-the-sun-the-economics-of-solar-investment.pdf (discussing PV solar as private-markets investment asset).

[5] See Ran Fu et al., Nat’l Renewable Energy Lab., U.S. Solar Photovoltaic System Cost Benchmark: Q1 2017, at vi (2017),

[6] Id.

[7] U.S. Energy Info. Admin., Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2017 1–3 (2017),

[8] Id. at 5, 8.

[9] Id. at 5.

[10] Id. at 1.

[11] Alan C. Goodrich et al., Assessing the Drivers of Regional Trends in Solar Photovoltaic Manufacturing, Energy & Envtl. Sci., 2811 (2013),

[12] Ran Fu et al., supra note 5, at 4.

[13] Matt Campbell, The Drivers of the Levelized Cost of Electricity for Utility-Scale Photovoltaics, Sunpower Corp. 20 (2011),

[14] See Ran Fu et al., supra note 5, at 21-22, 23-25, 29-30, 31-33, 39, 41-43.

[15] See id., at 31-33.

[16] Joshua Kneifel et al., Energy and Economic Implications of Solar Photovoltaic Performance Degredation, 1203 Nat’l Inst. of Standards & Tech. (Special Issue) 1–2, 22–23 (2016),; Y Zhang & SJ Smith, Pac. Nw. Nat’l Lab., Long-Term Modeling of Solar Energy: Analysis of Concentrating Solar Power (CSP) and PV Technologies 1 (2008),

[17] U.S. Energy Info. Admin., Levelized Cost, supra note 7, at 10.

[18] See, e.g., Solar Energy Industries Ass’n, Solar Industry Data, (last visited Oct. 27, 2019) (showing stagnating U.S. solar installations in 2014 and 2015 before the ITC was extended, and a boom in investments in 2016 after the ITC was extended).

[19] See  I.R.C. §§ 25D, 48 (West 2018).

[20] Energy Policy Act of 2005, Pub. L. No. 109-58, 26 I.R.C. § 48 (West 2005) (prior to subsequent amendments).

[21] Tax Relief and Health Care Act of 2006, Pub. L. No. 109-432, §§ 202-07, 26 I.R.C. § 48 (West 2006) (prior to subsequent amendments).

[22] Emergency Economic Stabilization Act of 2008, Pub. L. No. 110-343, § 103(a), 26 I.R.C. § 48 (West 2008) (prior to subsequent amendments).

[23] Consolidated Appropriations Act, Pub. L. No. 114-113, 129 Stat. 2242, 3036-40, 26 I.R.C. § 48 (West 2015) (prior to subsequent amendments).

[24] Id.

[25] An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018, Pub. L. No. 115-97, 26 U.S.C. § 48 (2017).

[26] See 26 U.S.C. § 48(a)(6)(A)(i)(2018).

[27] 26 U.S.C. § 48(a)(6)(A)(ii)(2018).

[28] 26 U.S.C. § 25D(g)-(h)(2018).

[29] See Stephen Comello & Stefan Reichelstein, The U.S. Investment Tax Credit for Solar Energy: Alternatives to the Anticipated 2017 Step-Down, 55 Renewable & Sustainable Energy Rev. 591, 596–97 (2015). The amount which would have previously been refunded to the taxpayer through the ITC will be reduced or eliminated, depending on whether the system is non-residential, which therefore increases the project’s capital costs by the amount which is no longer credited to the taxpayer. Id. at 596. The increase in capital costs will affect the project’s LCOE by roughly the same amount, barring low-cost operating and maintenance costs, since solar has no fuel costs.

[30] It should be noted that this section will not include an analysis of the potential increased costs resulting from tariffs on steel and aluminum, since the current administration has yet to resolve and is still negotiating which countries will be exempt and which will not be, rendering speculation too uncertain.

[31] Proclamation No. 9693, 83 Fed. Reg. 3541 (Jan. 25, 2018).

[32] Id.

[33] Julia Pyper, Trump Administration Issues 30% Solar Panel Import Tariff, Greentech Media (Jan. 22, 2018),

[34] Lucas Bifera, To Offset Tariffs, US Solar Market Looks to Financial Innovations, S&P Global Market Intelligence (Feb. 12, 2018, 12:29 PM),

[35] Julia Pyper, New Tariffs to Curb US Solar Installations by 11% Through 2022, Greentech Media (Jan. 23, 2018),

[36] Investors in PV solar seek out geographical areas where solar visibility is optimal on a daily and on an annual basis.

[37] The EPA amended PURPA such that utilities in areas under the provision of an RTO or an ISO are exempted from PURPA’s mandatory purchase obligations. Thus, the absence of such an obligation may discourage PV-solar investors from building in such areas due to lower and less secure rates.

[38] It is important to emphasize that this paper accounts for the below-mentioned state-level changes, without arguing for or against such changes, since the changes inform the industry’s landscape and their inclusion provides a more comprehensive basis on which to shape federal policy.

[39] See Manussawee Sukunta, North Carolina has more PURPAqualifying Solar Facilities than Any Other State, U.S. Energy Info. Admin. (Aug. 23, 2016),

[40] See, e.g., Competitive Energy Solutions for NC, S.L. 2017-192 (2017) (ordering North Carolina utilities to recalculate avoided-cost rates to account for the declining costs of natural gas); Peter Maloney, New North Carolina Regulatory Order Trims PURPA Avoided Cost Rates, Utility Dive (Oct. 18, 2017),

[41] See, e.g., Krysti Shallenberger, Utah Regulators Slim Down PURPA Contracts to 15 Years, Utility Dive (Jan. 8, 2016),; Robert Walton, Idaho Regulators Reduce PURPA Contracts from 20 to 2 Years, Utility Dive (Aug. 25, 2015), Contra Herman K. Trabish, North Carolina Regulators Reject Proposals to Change Utility-Scale Solar Regulations, Utility Dive (Jan. 2, 2015),

[42] See, e.g., Benjamin Inskeep et al., North Carolina Clean Energy Tech. Center, The 50 States of Solar 10–18 (Feb. 2016),; Hiroko Tabuchi, Rooftop Solar Dims Under Pressure from Utility Lobbyists, NY Times (July 8, 2017),

[43] Best Practices in State Net Metering Policies and Interconnection Procedures, (last accessed March 25, 2018) (easy-to-use chronological map of net metering policy in the U.S.).

[44] The “one-mile rule” references FERC’s refusal to aggregate the capacity of generating facilities that are located further than one-mile from each other, amongst other factors. Further discussion of the “one-mile rule” is found later in this paper.

[45] A generating facility attains qualifying facility status by certification with FERC. Qualifying facilities either (1) meet the definition of a small power production facility under 16 U.S.C. § 796(17) or (2) are cogeneration facilities that meet all of the requirements of 18 C.F.R. §§ 292.203(b) and 292.205 for operation, efficiency, and use of energy output.

[46] 18 C.F.R. §§ 292.304 to 292.305 (2019); 18 C.F.R. §§ 292.601 to 292.602 (2019).

[47] New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, 71 Fed. Reg. 64,342 (Nov. 1, 2006).

[48] PURPA Modernization Act of 2017, H.R. 4476, 115th Cong. § 3 (2017); see also Peter Maloney, Is PURPA Done? New Bill Takes Aim at Law’s Mandatory Purchase Obligation, Utility Dive (Feb. 12, 2018),

[49] See Major Solar Projects List, Solar Energy Industries Ass’n, (last updated Oct. 2019).


[50] PURPA Modernization Act of 2017, Hearing on H.R. 4476 et al. Before the Subcomm. on Energy of the H. Comm. on Energy and Commerce, 115th Cong. (2018) (statement of James Danly, Gen. Couns., FERC), available at

[51] Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 83 Fed. Reg. 9580, 9582 (Mar. 6, 2018) (to be codified at 18 C.F.R. 35), available at; see. Luz Dev. and Fin. Corp., 51 FERC ¶ 61,078 (1990) (rejecting the view that battery storage facilities are per se eligible for QF status without considering the ultimate source of energy generation) (“Luz”).

[52] Nat’l Renewable Energy Lab., Energy Storage: Possibilities for Expanding Electric Grid Flexibility 5–7 (2016),

[53] Julian Spector, First Solar Made Good on Its Promise to Break Out Gas Peakers With Solar and Batteries, Greentech Media (Feb. 13, 2018),

[54] Franklin Energy Storage One, LLC, 162 FERC ¶ 61,110 (2018).

[55] Luz, supra note 51; Spector, supra note 53.

[56] Franklin Energy Storage One, LLC, Fed. Energy Reg. Comm’n Docket No. EL18-50-000, 7–10 (Dec. 14, 2017) (Petition for Declaratory Order and Petition for Enforcement).

[57] Id.; see, e.g., FLS Energy, Inc., 157 FERC ¶ 61,211, 4 (2016) (Notice of Intent Not to Act and Declaratory Order, explaining that FERC has the discretion to express its position on the matters addressed in a case by issuing a declaratory order).

[58] See e.g., Mojave Solar LLC, Fed. Energy Reg. Comm’n Docket No. ER15-00860-000 (June 2, 2015) (Delegated Letter Order for MBR Electric Tariff, illustrating where FERC issued Category One Seller status to Mojave Solar LLC with the condition that the facility, together with Arizona Solar One LLC, would not use its thermal storage capacity to exceed the 500 MW limit).

[59] Id.