New York’s Department of Public Service (DPS) issued a straw proposal on April 24, 2014, detailing regulators’ recommendations for comprehensive electric industry reforms. In the report, entitled Reforming the Energy Vision(REV), DPS staff identified an array of regulatory measures that the state adopted in recent years and noted that “[t]he combined reach and effectiveness of [those] measures can be greatly enhanced by a comprehensive plan in the service of a unified vision.”
The New York DSP’s REV, which was issued four days before the Hawaii PUC’s Commission’s Inclinations guidance document (discussed in an earlier post), contains a number of parallels to the reforms proposed in Hawaii. Those parallels include transitioning from the traditional vertically integrated utility model to a model in which the utility manages a more dynamic distribution system that both delivers power to customers and coordinates large amounts of customer-sited distributed energy resources (DERs). The New York DPS calls this proposed entity the Distributed System Platform Provider (DSPP).
This post will discuss the salient features of the Distributed System Platform Provider (DSPP) as envisioned by the New York DSP staff in its REV guidance. Future posts will address other reforms proposed in the REV.
Roles of the DSPP
The New York DPS envisions the DSPP as an entity that will play three primary roles in the future of New York’s electricity system: 1) operating and maintaining the distribution grid; 2) managing markets and tariffs to monetize DER integration; and 3) serving as the interface between retail customers and the transmission grid. The REV notes that “[t]he incumbent distribution utilities are best situated to perform these functions and tasks.”
1) Distribution Grid Operator
The DSPP’s first role, operating and maintaining the distribution grid, is essentially the role played by distribution utilities today, albeit with new energy products, services and technologies incorporated into the system. The REV foresees significant future integration of DER into the distribution grid, and the DSPP will be tasked with accommodating a broad spectrum of resources, which include renewables, microgrids, combined heat and power (CHP), storage, efficiency, demand management and demand response technologies. Integrating those technologies will require DSPPs to use localized, automated systems to balance production and load. The REV provides that DSPPs will be compensated for those investments in modernizing the distribution system infrastructure as part of their revenue requirement.
2) Distribution Market Manager
The DSPP’s second role represents the most significant departure from that of the traditional distribution utility. The New York DPS envisions that the DSPP will manage DER products and services in real time and be responsible for monetizing the value of those products and services. As those products and services are dispatched, the DSPP will be responsible for reconciling those transactions, similar to the role of the Independent System Operator in relation to the transmission grid. The REV notes that the value of those DER products and services will depend on a variety of factors, including “the type of resource (e.g., intermittent, base load, dispatchable), the degree of control over the resource, and the response time of the given resource.”
The New York DPS highlights a number of potential costs and benefits that might arise in the context of DER integration and identifies whether those costs and benefits are currently monetized in the existing market structure. One of the hurdles to creating fully realized DSPPs is identifying the appropriate methods of monetizing costs and benefits. DERs have the potential to benefit the distribution system by providing enhanced reliability, resource diversity, environmental benefits, and economic and social development, but those benefits do not have monetary values attached to them in the current system. Determining how to equitably allocate those costs and benefits to relevant stakeholders is another hurdle to creating DSPPs. Some benefits, such as emissions reductions and societal and economic development, provide value to society at large, but cannot easily be monetized to compensate the DER customers providing those benefits.
3) Interface Between Retail Customers and Transmission Grid
The DSPP’s third role, acting as the intermediary between retail customers and the transmission system, is essentially a responsibility that is transferred from the oversight of the distribution utility to that of the DSPP. While DSPPs will assume most of the same functions that are currently performed by the distribution utilities, the proliferation of DERs will create new opportunities for DSPPs to provide products and services to the transmission system operator.
Implications of New York’s Distribution System Reforms
The New York DPS’ proposed reforms to distribution system operation in the state represent a significant departure from the vertically integrated utility model. While the REV envisions that incumbent utilities will retain ownership and management authority over the distribution grid as DSPPs, the emphasis on the integration of DERs to meet customer demand, rather than centralized generation facilities will remove one of the utilities’ staple rate base investments.
The New York DPS appears sensitive to the impact of its proposed reforms on utilities; the REV may envision diminished utility ownership of generation assets, but it also contemplates new mechanisms to allow utilities to earn their revenue requirements. If New York can navigate the creation of DSPPs and a smooth transition to modern distribution grid, public utility commissions nationwide will almost certainly follow suit.
I blogged recently about proposed federal legislation to promote renewable energy development on public lands. One proposed law, H.R. 596, would open federal lands to competitive leasing for renewable energy development. In a hearing on H.R. 596 before the House Subcommittee on Energy & Mineral Resources, the Bureau of Land Management (BLM) testified that it was using its existing statutory authority to create a competitive leasing rule for certain federal lands. Since then, BLM has issued a proposed rule on the topic (complete with a suitably bureaucratic title): “Competitive Processes, Terms, and Conditions for Leasing Public Lands for Solar and Wind Energy Development and Technical Changes and Corrections.” BLM issued the rule on September 30, and interested parties have until December 1 to submit comments to the agency. This blog post offers a brief summary of the rule and describes some areas of potential concern.
The Proposed Rule in Brief
BLM’s proposed rule would significantly change how the agency makes public lands available for renewable energy development. Until now, BLM has made public lands available using its authority to issue “right of way grants” (ROWs) under the Federal Land Policy and Management Act (FLPMA). Under current BLM rules for ROW grants, the agency can use a competitive process only if two parties file competing applications for the same parcel of land. The proposed rule, in contrast, would give BLM discretion to select parcels of public land and offer them for competitive lease bidding, even before any party has expressed interest.
The proposed rule also attempts to promote renewable energy development in “designated leasing areas” (DLAs) that have strong renewable resources and few conflicting uses. The agency proposes to identify these designated leasing areas through its existing land use planning process, using a “landscape scale approach” that considers a broad variety of factors. Essentially, the agency would weigh the economic efficiency of developing renewable energy in areas with strong resources and good access to energy transmission and markets against potential environmental problems such as habitat degradation. The basic analysis would mirror the method the BLM used to select Solar Energy Zones in the desert Southwest. However, the proposed rule does not actually choose any designated leasing areas. Instead, the proposed rule would leave the designation of leasing areas to the land use planning process, which generally occurs every 10 or 15 years and may take as long as 8 years once begun.
The proposed rule would promote development in designated leasing areas in two main ways. First, the designation of these areas in agency land use plans would involve substantial environmental analysis under the National Environmental Policy Act (NEPA). Development within DLAs could refer (or “tier,” in the environmental law jargon) to this NEPA analysis, saving time and money, whereas development outside DLAs would require longer and costlier NEPA analysis. And second, the proposed rule would offer more favorable terms for projects within DLAs.
A brief summary of leasing under the proposed rule should help clarify how lease terms would be better inside DLAs. BLM proposes that renewable energy developers on public lands would face four basic costs. First, they would have to cover the agency’s costs for processing their bids. Second, they would have to pay rent based on the acreage of public lands they develop. Third, they would have to pay a fee based on a facility’s capacity to generate electricity (approved nameplate MW capacity). Finally, they would have to post a bond to cover costs of restoring public lands once facilities cease operating.
Projects proposed inside designated leasing areas would enjoy greater certainty and lower costs. First, the high bidder for a parcel inside a DLA would automatically receive a lease (as long as it can show the ability to pay for its bid), whereas the high bidder for a parcel outside a DLA would merely be the only party who can apply for a ROW, which BLM would have discretion to grant or deny. Additionally, successful bidders for projects inside DLAs could qualify for an “offset,” or reduction in price, of up to 20%. Offsets would depend on certain qualifications, such as having pre-arranged financing or interconnection agreements. Projects outside DLAs would not qualify for any offsets.
Other costs would also be lower and more predictable for projects inside DLAs. For example, the bonding requirement would be fixed for projects inside DLAs, but that same fixed price would be a minimum requirement for projects outside DLAs. BLM could also alter bonding requirements for projects outside DLAs, even during the lease term. Acreage-based rents would increase only every 10 years for projects inside DLAs, but would increase annually for projects outside DLAs. Finally, the capacity-based fee would phase in over 10 years for projects inside DLAs, but over 3 years for projects outside DLAs, meaning the latter projects would face higher costs more quickly. BLM intends all these differences to direct investment in renewable energy on public lands to the most suitable areas.
Potential Problems with the Proposed Rule
Although BLM’s proposed rule reflects progress toward increased availability of public lands for renewable energy development, the rule has two potentially significant problems. First, the way that it proposes to calculate both rents and fees for renewable energy may be inaccurate. And second, the proposed rule’s attempt to promote development within DLAs relies on a land use planning process that is so complex and contentious that just designating the DLAs could take many years.
The way the proposed rule calculates rents for solar and wind facilities is troubling. Rents are the product of county-based land values multiplied by the amount of each parcel a facility uses. BLM assumes that wind turbines encumber only 10% of a parcel, and (more troublingly) that solar farms encumber 100% of a parcel, excluding all other use. The result of this assumption is that wind energy projects would pay 10% of the acreage-based rent that solar energy projects would pay. This result is troubling in part because it seems to favor wind development, but also because the assumption about solar farms may not be correct. Although solar development does use more surface land than wind development, farms in Great Britain show it is quite possible to produce food and solar power on the same parcel. Moreover, some facilities in Texas use sheep to graze down vegetation that would otherwise obscure solar panels. Finally, some solar farms also operate as bee sanctuaries. These possible uses suggest it may not be appropriate for BLM to assume that solar development excludes all other possible land uses. Finally, co-siting of wind and solar facilities on the same parcel of land is a promising way to generate a more consistent renewable energy supply, but BLM’s proposed rule does not seem to permit this possibility.
BLM’s methodology for calculating capacity-based fees is also somewhat troubling. To reach the capacity fee, BLM would multiply the number of hours in a year by a net capacity factor, a wholesale electricity price, and a rate of return (Fee = hours x capacity factor x wholesale electricity price x rate of return). Several aspects of BLM’s proposed calculation are problematic. First, the capacity factor is based on geography and on the efficiency of different technology types. For example, a high-efficiency solar panel in a sunny location has a higher capacity factor than a low-efficiency panel in a cloudy area. BLM itself acknowledges that “efficiency rates may vary by location for each specific project,” but proposes to use a national average instead of regional or site-specific figures. Seemingly, it would be easy to allow a developer to identify a project’s individual capacity factor, since this is a step a developer would likely take anyway in order to calculate project revenues.
Second, BLM’s valuation of wholesale power prices is problematic. To calculate wholesale power prices, BLM proposes to take the average of wholesale prices from 2008 to 2012 for various western electricity markets. BLM would update this figure only every five years. The problem with this valuation is that wholesale electricity prices have been declining very substantially (by more than 50% according to BLM’s own figures), and are likely to continue to decline due to market pressures from low-cost natural gas and renewable energy. Consequently, BLM’s figure for wholesale power prices is inaccurately high, which in turn makes the capacity fee inaccurately high as well.
Third, the fact that BLM’s fee is based on installed megawatt capacity rather than on actual delivery of energy seems quite problematic as well. The basic problem is that renewable energy projects on public lands would owe the same fee no matter how much or how little energy they actually produce or sell, meaning that their payment obligation to BLM would not vary along with their revenue streams. A payment obligation based on delivery of energy and priced in dollars per megawatt hour ($/MWh) would provide greater certainty to developers and would more closely approximate fair market value for industrial use of public lands (because it would be based on the actual use, not an assumed average). I see no particular reason that a fee based on $/MWh would be a logistical problem for the agency; the successful federal Production Tax Credit is valued in this manner and does not seem to challenge the IRS. The BLM should consider changing the capacity fee to more accurately reflect projects’ revenue streams.
A far more serious problem, however, has to do with the strong promotion of development in designated leasing areas. Although it is a good idea to promote development where resources are strong and conflicts are minimal, the designation of leasing areas is likely to take so long that this rule is unlikely to provide benefits in the near term. So far, BLM has identified 17 Solar Energy Zones that it would manage as DLAs under the proposed rule, and seemingly has not identified any leasing areas for wind energy. All solar energy zones are in six Southwestern states. Development in these few areas will receive far more favorable terms, but development throughout the rest of the West will have to wait for updates to BLM land use plans, which could take years. To make this rule more effective, BLM should either accelerate its land use planning schedule or separate the designation of leasing areas from the land use planning process to get this rule to have greater effect more quickly.
Incremental Progress, but not a Sea Change
All told, BLM’s proposed rule would likely help promote renewable energy development on public lands, but would not do so very quickly. Moreover, BLM’s proposed rule, because it works within existing statutory limits, cannot achieve the same results as the proposed legislation currently before the U.S. House of Representatives. Most notably, BLM lacks the statutory authority to split revenues from leases among states, counties, and an environmental conservation fund, as H.R. 596 would do. Under BLM’s proposed rule, revenues would flow to the U.S. Treasury instead of being shared among local stakeholders. In sum, BLM’s proposed rule is a good, but imperfect step, and not as strong a policy as that in H.R. 596. Interested parties can find the proposed rule, including instructions for how to submit comments, here.
Austin, Texas and the state of Minnesota recently established Value of Solar Tariffs (VOST) that aims to pay the true “value” that distributed solar power offers to the electricity grid. These policies are somewhat related to Feed-In Tariffs (FITs), which similarly pay a customer at a rate different from the one they would receive under net metering. Under both a VOST and a FIT, the customer must sell all electricity produced to the utility, and the customer must buy all electricity needed from the utility. This is arguably quite different from net metering, under which a customer consumes electricity on-site and purchases additional power from the utility.
But just as net metering faces substantial opposition, VOSTs face serious criticism as well. In fact, one rooftop solar advocacy group, The Alliance for Solar Choice (TASC), believes that the forced sale of power under the VOST scheme is problematic because it may expose the homeowner to unforeseen income tax liability. Concerned about this potential exposure, an Austin homeowner, with the enthusiastic support of TASC, recently filed an Information Letter Request with the Internal Revenue Service (IRS) seeking guidance as to whether electricity sales under a VOST structure are taxable income. TASC and the homeowner have two main concerns. First, payments under a VOST structure expose the homeowner to income tax liability. And second, they may disqualify the owner from taking advantage of certain tax credits available to homeowners provided they consume the vast majority of electricity produced by the panels on-site.
The IRS determination could have implications in several states currently investigating the possibility of adopting some form of VOST, such as California and Oregon. Although VOSTs can incite heated debateover appropriate methodologies, there is some evidence that when done well, VOSTs could be a forward-thinking way to account for the value that solar energy could provide to the grid (including environmental benefits, avoided transmission, and congestion management costs). Some suggest it could even make solar financing easier. I am therefore concerned that the decision to ask the IRS to rule on the status of those sales may be tactically nearsighted. Not only could it impose tax liability on owners of rooftop solar, but it also ignores the underlying reasons a well-crafted VOST could be beneficial to solar proponents in the future.
This myopia takes several forms. First, asking the IRS to offer some guidance on an issue it seemed otherwise content to ignore seems unwise. In fact, this issue looks similar to a Citibank controversy involving frequent flyer miles that the bank issued to customers for opening credit card accounts with the bank. Citibank began sending out 1099 notices and treating the miles as taxable income. Although the definition of taxable income under the Tax Code is broad—“all income from whatever source derived”— the IRS had until that point not treated the points as taxable income. With prodding from Citibank, though, the IRS began treating them as such. Yet, the IRS still treats the points customers receive when they make purchases on their credit card as nontaxable, the difference being that the points connected to actual purchases constitutes a “reimbursement of your membership fees” as part of a reward program (i.e. nontaxable), whereas the one-time point disbursement looks more like income.
Commentators argue that the distinction between those two is contrived. But even if it is, the VOST arguably looks more like the membership reimbursement points than the taxable exchange of points for signing up for a new credit card. The owner of solar panels is required to purchase electricity from the utility under the VOST structure, and the credits she receives on her bill is directly tied to the value she gives to the grid through her solar array’s production. In fact, the VOST scheme is in essence a structure designed to reimburse a homeowner for her solar panels’ contribution to the power grid. If the IRS is willing to treat points received for membership in a credit program as nontaxable, it might be willing to do the same under a VOST.
The second type of tactical nearsightedness results from TASC’s likely misunderstanding that VOST exchanges do in fact result in taxable income. In support of its position, TASC cites to a memorandum written by the leading tax firm Skadden, Arps, Slate, Meagher & Flom. The memo argues that the VOST structure results in taxable income because the VOST requires a homeowner to sell electricity to the utility in exchange for either cash or an on-bill credit. However, several arguments could reasonably lead to the opposite conclusion. For instance, a tax law doctrine called the “step transaction doctrine” seems to suggest that power exchanges between a customer and a utility should not be viewed as taxable income. In 1989, the United States Supreme Court explained in Commissioner v. Clark, that when a transaction is “integrated” and composed of interdependent components, the analysis of its taxable nature must take into account the “character of the exchange as a whole, and not simply its component parts.” Particularly where the parties are formally obliged to complete each part in a series of steps, this doctrine counsels against treating each as a separate transaction. Because the VOST scheme requires a homeowner to sell her power onto the grid and to purchase electricity from the utility at a different rate, each step of the transaction is both interdependent and obligatory. Taking the entire exchange as a whole, rather than simply as component parts, the transaction does not appear to result in taxable income under the test established in Clark.
Finally, an IRS determination that these exchanges result in taxable income is logically inconsistent with the Federal Energy Regulatory Commission’s (FERC) interpretation of net metering exchanges. Although I see no legal reason that the IRS’s interpretation would have to follow FERC’s, the federal government should avoid taking internally conflicting positions, particularly in an area as crucial as promoting renewable energy. FERC does not treat customer-end electricity flowing onto the grid under net-metering programs as wholesale power sales, so long as the homeowner is not selling excess power onto the grid. A similar exchange where the customer is not sending more power back onto the grid than she consumes should, if at the very least for administrative ease, receive similar treatment under the Tax Code.
Ultimately, an IRS ruling that exchanges under VOST structures do in fact result in taxable income could open up a proverbial Pandora’s box of problems. First, VOST schemes are not perfect, but they do represent an attempt by solar advocates to work with utilities to craft a policy that accurately reflects the value distributed solar power provides to the grid. Subjecting payments under VOSTs to income tax would undermine the financial feasibility of distributed solar. Second, TASC is a proponent of net metering programs because they reimburse the homeowner at retail rate for the power her panels produce. I am not convinced that if VOSTs constitute taxable income, net metering payments would not.
Forcing homeowners with residential PV to pay income taxes on the power their panels produce could create additional and unnecessary financial hurdles and potentially pose significant problems for residential PV customers. For this reason, the IRS should avoid embroiling itself in an already contentious debate and decline to respond to the Information Letter Request at all, thereby avoiding issuing a ruling as to the taxable status of these payments until solar advocates and utilities are prepared to face the consequences.
By Nick Lawton, Staff Attorney The Third and Fourth Circuit Courts of Appeal recently struck down measures in New Jersey and Maryland, respectively, which had aimed to promote in-state electricity generation by essentially setting wholesale electricity rates. The Third Circuit recently decided PPL EnergyPlus v. Solomon in March, while the Fourth Circuit decided PPL Energy Plus v. Nazarian in June. These cases are important to renewable energy because they highlight the fact that federal law constrains state strategies for influencing the energy market. In short, these cases reinforce that states may not set or alter wholesale electricity rates, which in turn suggests that state energy procurement mandates are a better option. This blog post describes the policies New Jersey and Maryland attempted to implement, explains the reasoning the Third and Fourth Circuits used to strike those policies down, and briefly explores what these cases entail for state efforts to promote renewable energy.
The electrical transmission grids in Maryland and New Jersey operate under the management of a Regional Transmission Organization (RTO) called the PJM Interconnection, LLC (PJM). Although “PJM” stands for “Pennsylvania, Jersey, Maryland,” PJM actually manages electricity transmission for a very large area that includes parts of twelve states and the District of Columbia. PJM’s role is to manage what the Third Circuit eloquently described as “a delicate circuitry of interdependence between private entities and public utilities, and between [states] and federally-regulated wholesale energy markets.” Basically, PJM runs markets for electricity and for the capacity to generate electricity on demand. Auctions in these markets determine which generators actually sell energy in the PJM service area.
Like any Regional Transmission Organization or Independent System Operator (ISO), PJM operates its energy and capacity markets under the blessing of the Federal Energy Regulatory Commission (FERC). FERC’s approval for PJM markets is necessary because Congress, in the Federal Power Act, claimed exclusive federal jurisdiction over wholesale electricity sales in interstate commerce. Since the 1990s, FERC has presumed that freely negotiated contracts are “just and reasonable” and therefore legal. FERC has thus in some locations delegated its authority over wholesale ratemaking to RTOs and ISOs, approving rates resulting from the auctions the RTOs and ISOs administer. In sum, Congress claimed exclusive jurisdiction over wholesale power rates, giving FERC jurisdiction over those rates, and FERC in turn allowed independent markets to actually determine wholesale rates. Thus, PJM’s markets, although run by an independent organization, operate under the aegis of federal law.
Although PJM’s markets are designed to send price signals that will promote construction of new power plants where they are most economically efficient, both Maryland and New Jersey found their electricity rates rising and too few power plants being built within their borders. Maryland worried about a “looming capacity shortage,” while New Jersey found that it had “become more reliant on coal-fired power plants” in other states (in conflict with state policies about climate change and renewable energy).
Before 1999, Maryland and New Jersey could easily have corrected these problems by simply ordering local utilities to build new, clean, local power plants. But in 1999, both states restructured their energy markets, requiring utilities to buy energy on wholesale interstate markets. Restructuring thus basically turned bundled retail electricity service into separate enterprises: wholesale electricity sales (subject to exclusive FERC jurisdiction), wholesale transmission services (also subject to FERC jurisdiction), and retail electricity services (subject to state jurisdiction). Thus, restructured states clearly lost some regulatory authority over electricity prices; how much authority they lost was the key issue before the Third and Fourth Circuits.
Under the Federal Power Act, even after restructuring, states retain authority over retail prices and power procurement. For example, states can continue to regulate the need for new power facilities and retail electricity rates. However, FERC and federal courts have made it clear that states cannot directly set wholesale rates or use retail ratemaking powers to interfere with exclusive federal power over wholesale rates. In the Fourth Circuit’s words, “throw[ing] in its lot with the federal interstate markets … [entailed] a relinquishment of the regulatory autonomy the state[s] had formerly enjoyed with respect to traditional utility monopolies.” Despite these constraints, both Maryland and New Jersey sought to guarantee wholesale prices to desirable power plants. In doing so, they overstepped their jurisdictional reach.
Maryland and New Jersey attempted to work within the complex overlay of federal and state authority in order to promote local electricity generation by creating a “contract for differences” scheme. The basic goal was to help proposed power plants secure financing by guaranteeing a fixed revenue stream. Under these contracts-for-differences, new in-state power plants would still sell power into the PJM markets. If PJM’s auction yielded a price below the contract-for-differences rate, the buyer of the power would pay the power plant the difference. If the auction price was above the fixed contract price, the power plant would pay the difference to the buyers. The result would be that new power plants would always receive the same price for their power, no matter what price PJM’s auctions determined.
The Third and Fourth Circuits concluded that federal law preempted these contract-for-differences schemes. Essentially, the courts reasoned that Congress had intentionally occupied the field of setting wholesale electricity rates and that the contracts-for-differences were basically state attempts to fix wholesale rates. In the Third Circuit’s words, New Jersey “incentivize[d] the construction of new power plants by regulating the rates new electric generators [would] receive” for their output. The Fourth Circuit, meanwhile, held that Maryland “effectively supplant[ed] the rate generated by the [federally regulated] auction with an alternative rate preferred by the state.” Because the states attempted to fix wholesale rates, which is an exclusively federal prerogative, federal law preempted these state efforts.
Both Maryland and New Jersey raised some unsuccessful counterarguments. For example, the courts found irrelevant the states’ argument that independent market operators, rather than federal agencies, were actually setting rates, because federal law created those markets and a federal agency regulates them (although in a laissez-faire style). Similarly, both courts rejected the argument that the contracts-for-differences did not fix wholesale rates because they used a separate transaction from the PJM market. The courts found that “the fact that [the scheme] does not formally upset the terms of a federal transaction is no defense, since the functional results are precisely the same.” Similarly, while finding that states still retain some power to promote local energy generation, the Third Circuit reasoned that what New Jersey had done was not really merely subsidizing local generation, but rather was tinkering with wholesale rates. Ultimately, the courts found the states’ arguments unconvincing, finding, in the Third Circuit’s words, that the states “intruded into an area reserved exclusively for the federal government.” Thus, both Maryland and New Jersey’s efforts to use contracts-for-differences to promote in-state electricity generation have failed.
These holdings from the Third and Fourth Circuits have considerable implications for state efforts to promote renewable energy. Providing a secure revenue stream for new renewable energy generators is one of the most obvious strategies for increasing deployment, but these holdings make clear that courts will strike down state laws that are functionally equivalent to wholesale ratemaking. In some sense, this is not a surprise. FERC clarified in 2010 that states must act within the confines of the federal Public Utilities Regulatory Policy Act (PURPA) when setting wholesale rates that utilities must pay for renewable energy. Generally, PURPA provides a limited exemption from otherwise exclusive federal jurisdiction over wholesale rates, allowing states to require utilities to buy power at rates no higher than their avoided costs (the rates they would otherwise have paid for that power absent a state requirement). However, FERC clarified that federal law does preempt state regulations that go beyond what PURPA authorizes. These cases reinforce that point; in formulating policies to combat climate change and promote renewable energy, states must be careful to work within the constraints that federal laws establish.
A thorough analysis of what state policies would be permissible under federal law is beyond the scope of this blog post. A forthcoming paper by the Green Energy Institute’s Director, Professor Melissa Powers, and my colleague Amelia Schlusser will discuss the significant limits that PURPA imposes on state efforts to establish European-style Feed-In Tariffs and will explore several other regulatory options. This post merely notes that these cases suggest that federal courts will seriously scrutinize state policies that encroach on exclusively federal jurisdiction. In other words, state efforts to set wholesale electricity rates will likely fail.
However, these cases are not a cause for despair for renewable energy advocates or for states that may seek to promote renewable energy. Importantly, the Third and Fourth Circuits both described limits to their holdings, noting that federal law would not preempt a state policy merely because it had an effect on wholesale rates. Noting that basically any regulation of the energy market would likely effect wholesale energy prices, the Third Circuit stated that “the law of supply-and-demand is not the law of preemption.” If federal law preempted all regulations that impacted wholesale rates, “the states might be left with no authority whatsoever to regulate power plants.” The Third Circuit was quite clear: “That is not the law.” The Fourth Circuit, meanwhile, noted that “states plainly retain substantial latitude in directly regulating generation facilities.” Moreover, the court was careful to note that its holding was not about “other state efforts to encourage new generation, such as direct subsidies or tax rebates.”
The moral of the story is that states do retain significant authority to regulate about such matters as the type, location, and environmental impacts of power plants. That being said, when working to promote renewable energy, state laws must be carefully tailored to work within the federal framework. Otherwise, those laws risk being struck down in court. Renewable energy advocates would be wise to pay close attention to federal constraints; failing to follow federal law closely risks wasting the valuable time and effort that goes into designing and advocating for new policies.
By Nate Larsen, Energy Fellow The Green Energy Institute submitted comments to the Hawaii Public Utilities Commission on October 6, 2014, in response to the HECO Companies’ Power Supply Improvement Plans (PSIPs) and Distributed Generation Improvement Plan (DGIP). GEI’s comments dealt specifically with the HECO Companies’ proposals to eliminate or cap participation in Hawaii’s Net Energy Metering program and to assess fixed charges for distributed generation customers.
Eliminating the Net Energy Metering Program
The HECO Companies filed their PSIPs and DGIP with the Hawaii PUC on August 26, 2014. The Companies used that platform to recommend eliminating the state’s Net Energy Metering (NEM) program. In their DGIP, the Companies asserted that “[t]he need to provide retail compensation for DG no longer exists,” arguing that utility-scale PV projects can be built at rates below the retail cost of electricity. The Companies further stated that “the intent of the NEM program at its inception, in combination with federal and state incentives, was to nurture a developing technology and industry, because the cost to self-generate clean renewable energy was prohibitive.” Based on those conclusions, the HECO Companies sought to eliminate or limit the scope of Hawaii’s NEM program.
Citing inequities in cost allocation among customer classes, the Companies first recommended a “Gross Export Purchase” model, which would effectively replace the net-metering regime with a feed-in tariff for DG customers at rates nearer to the wholesale price of electricity. In response to that proposal, GEI noted in our comments that the legislature created the NEM program by statute, and that the Hawaii PUC therefore lacks the authority to abolish the program by adopting the Companies pricing model. We recommended that the Hawaii PUC require the HECO Companies to provide alternative proposals to address those perceived cost allocation issues.
The HECO Companies’ second proposal involved the Hawaii PUC capping participation in the state’s NEM program, which they have the authority to do under the net metering statute. However, in 2008, stakeholders—including the Governor of Hawaii, consumer advocates, and the HECO Companies—signed an energy agreement providing, among other things, that there should be no system-wide caps on net metering. GEI pointed out that even if the Hawaii PUC has the authority to reinstate caps on the NEM program, doing so would conflict with the energy agreement, and thus would constitute bad policy on the part of the PUC.
Assessing Fixed Charges
As I discussed in an earlier post, the HECO Companies also envisioned adopting fixed charges to address some of the cost allocation issues associated with distributed generation. In their PSIPs, the Companies assess the bill impacts of fixed charges in the amounts of $55 for all customers and an additional $16 for DG customers. In our comments, GEI warned the PUC about the potential impacts that fixed charges would have on conservation and customer retention.
First, GEI pointed out that the adoption of fixed charges would lower the volumetric price of power. That reduced cost per kilowatt-hour may then obscure price signals to use less electricity. Second, GEI noted that high fixed charges for DG customers—like those used in the HECO Companies’ PSIPs—could create an economic incentive for customer grid defection. That defection would only serve to heighten cost allocation issues, by reducing the utilities’ customer pools without substantially reducing their operating expenses. GEI then urged the Hawaii PUC to consider all the benefits that DG customers provide to the system in future ratemaking proceedings, including the rate benefits to other utility customers discussed above, as well as avoided transmission and distribution costs, and environmental and societal benefits resulting from the use of carbon-free, clean resources.
Hawaii is the first state to take concrete steps towards a new paradigm in electricity regulation, and has therefore become something of a laboratory for the “Utility 2.0” reforms expected eventually to sweep the country. GEI supports the Hawaii PUC’s efforts to reform the electricity sector to reflect emerging trends; our comments reflect our desire to ensure that those reforms continue to provide customers with the choice to economically install and operate distributed generation systems.
The Hawaii PUC is currently reviewing the HECO Companies’ PSIPs and DGIP, as well as the public comments on those plans, pending further action on the matter.
By Kyra Hill, Energy Fellow Around the nation, independent local groups are beginning to develop community solar projects. Last week, I discussed how exemptions to burdensome securities laws could help facilitate that process. But even with securities exemptions in place, community solar projects can be difficult to organize, design, and finance. Despite these difficulties, some community groups have come together to develop successful community solar projects in various states. Successful projects have several common ingredients that must be put in place (much like the French culinary practice mise-en-place) before they begin production. This post explores those ingredients and offers some suggestions for how community groups, policymakers, and solar advocates can facilitate community-led solar project development.
Ingredient 2: Organize and Engage Community Members
Community advocates should begin by assessing community (and utility) interest in a particular project. Limited community interest should not necessarily counsel against a particular project, but should instead reveal the need for more outreach and education about the project’s social, environmental, and financial benefits. Educational efforts might include holding meetings and community outreach. Electing project leaders and recruiting volunteers with legal or business expertise can diminish project complexity. One group in Maryland, for example, secured pro bono securities and tax assistance from a law firm and a law school clinic. Community members helped one District of Columbia Cooperative raise funds and build a website, and local children even helped with door-to-door sales outreach. Northwest Seed’s guide provides a useful chart identifying community organizations (e.g., schools, homeowner associations, etc.) and community members who could help overcome some technical and financial hurdles. Effective communityengagement and information sharing could appreciably reduce the costs of developing a community-initiated solar project.
Ingredient 3: Conduct Feasibility Analysis and Begin Project Development
The feasibility analysis and site assessment process includes identifying where the best solar resources are located, assessing which solar modules and setup works best for that site, and ensuring the project’s financial viability. There are a number of modeling tools available to facilitate this process, and as technology continues to improve, these assessments should become easier.
The project development phase is time-consuming and complex. The Maryland group spent almost two years working through this process. It includes navigating applicable regulations and permit requirements (such as electrical permits, building permits, and potentially even permits to maintain solar access), establishing a business or ownership structure, developing a financing plan, negotiating power arrangements and interconnection agreements, and obtaining bids from installers. Each of these components requires either professional or local government assessment, and is therefore likely to be costly, lengthy or both.
Here, too, information sharing and identifying best practices could help to reduce financial burdens. Recognizing that the hurdles to developing a community solar project stem from the project development process, some groups attempt to make projects replicable by sharing information to help ease burdens for future efforts. But because many of these projects remain site- and project-specific—and therefore require individual negotiations, financial disclosures, and permits—information dissemination can only go so far. Changes at the policy level could drive down non-hardware costs and streamline the permitting process. (See my colleague Nick Lawton’s report on decreasing these so-called “soft costs.”) Technological changes and increased familiarity with these projects will also ease their development.
Even though utility-led community solar projects can be easier to develop, finance, and design, community-initiated projects are cropping up in several states. Community-led projects are attractive because they engage members in renewable energy production while providing local economic benefit. Successful projects take the time to consult available resources, engage community members, and create viable business plans. Developers can facilitate this process by sharing information and best practices. Solar advocates can galvanize community members around these projects. Finally, policymakers can play an important role by helping to decrease soft costs and eliminating administrative burdens. With the right combination and preparation of ingredients, community-initiated solar projects can play an important role in promoting widespread renewable energy adoption.
Wind energy is an increasingly cost-effective source of electricity. According to Lazard’s Levelized Cost of Energy Analysis version 8.0, the levelized cost of unsubsidized wind energy currently ranges from $37 to $81 per megawatt hour (MWh). When the calculation includes federal tax incentives, levelized costs fall to between $14 and $67 per MWh. In contrast, the levelized cost of natural gas combined cycle technologies ranges from $61 to $87 per MWh, while the cost of coal ranges from $66 to $151 per MWh. On a levelized cost basis, therefore, wind energy is currently cost competitive with conventional fossil fuel resources.
However, the intermittent nature of wind energy presents challenges for integrating this resource onto the grid. Grid operators face significant uncertainty regarding the availability of wind energy, which varies significantly from hour-to-hour and day-to-day. This variability forces grid operators to make rapid adjustments to accommodate load increases and decreases that fluctuate with weather conditions. Operators must keep other generating resources on reserve to provide back-up power for low-wind periods, which can add significant cost on a per-MWh basis.
Idaho Power Company recently developed a new forecasting tool that allows grid operators to more cost-effectively integrate variable wind energy onto the grid. This Renewables Integration Tool, or RIT, consists of a number of models and databases that forecast hourly and daily wind conditions and project the amount of wind energy the utility can procure on an hourly basis. The RIT incorporates data on weather conditions, turbine performance, and supply and demand conditions within Idaho Power’s service territory, and allows the utility to better predict wind energy availability from 72 to 180 hours into the future.
During the first quarter of 2014, Idaho Power determined that the RIT was 26% to 32% more accurate than the utility’s previous forecasting methods. This increased forecasting accuracy has enabled the utility to reduce grid integration and operating costs by $287,000 over a three-month period. While these cost savings are significant, Idaho Power notes that the accuracy of the RIT’s forecasts vary during periods of unpredictable weather, and plans to continue refining the software to further improve the utility’s ability to integrate wind energy onto the system.
While the electrical sector still has a long way to go to fully integrate intermittent renewable energy generation onto the grid, better forecasting methods such as Idaho Power’s RIT enable utilities to integrate additional renewable resources at a lower cost to consumers. These reduced integration costs in turn increase the value of renewable energy. Other utilities should follow in Idaho Power’s footsteps to develop customized forecasting tools to facilitate integrating variable renewable energy resources onto the grid.
Fickle federal policies are sending conflicting signals to renewable energy developers. On the one hand, the federal government seems to recognize the critical role that U.S. public lands could and should play in siting the most efficient, productive renewable energy facilities. For example, as I reported a few weeks ago, Congress is considering a bill that would expand leasing opportunities for renewable energy development on federal lands. Similarly, the Bureau of Land Management (BLM) has been working with various stakeholder groups to plan for optimal siting of solar power in the desert Southwest. But on the other hand, short-lived federal tax policies designed to spur renewable energy in fact deprive the industry of the certainty needed for steady market growth and drive an unsteady, boom-and-bust cycle of development.
The federal Production Tax Credit (PTC) is the cardinal example of fickle federal policy. Although renewable energy advocates and industry strongly support the PTC, which provides an inflation-adjusted payment for renewable energy delivered to the grid, Congress has allowed the PTC to lapse five times since its initial passage in 1992. The PTC expired most recently at the end of 2013, and although some members of theHouse and Senate support its resurrection, Congress seems unlikely to act any time soon. The likely consequence is a severe reduction in investment in wind and other renewable energy, as the following graph from the American Wind Energy Association illustrates:
For a detailed discussion of the PTC’s history, functioning, and proposals for its extension or modification, please see Sustainable Energy Subsidies, by the Green Energy Institute’s director, Professor Melissa Powers.
The federal Investment Tax Credit (ITC), which has allowed recovery of 30% of a solar energy system’s cost since 2008, now faces a similarly uncertain future. Unless Congress acts, the ITC will diminish severely at the end of 2016. Large commercial projects will see the credit plunge to only 10% of a project’s cost, while residential projects will no longer enjoy any credit at all. Again, although some members of Congress are attempting to extend the ITC, its fate remains profoundly uncertain. This coming blow risks disrupting the solar industry’s recent trend of record-breaking growth.
In fact, uncertainty over the expiration of the ITC is already impacting solar development. A developerrecently withdrew plans for a proposed utility-scale concentrating solar plant in California. Although the developer did not officially attribute the project’s cancellation to the expiring ITC, David Danelski at The Press Enterprise reports that one of the developer’s vice presidents as doubting the project could be completed in time to take advantage of the tax credit before it expires. Mr. Danelski also cites a source from the Solar Electric Power Association, as noting that guaranteed receipt of the ITC is critical for financing solar projects.
When I discussed community solar models and obstacles, I mentioned that the requirements for securities registrations can be a significant obstacle. However, the obstacles are not insurmountable. Recent legislative and executive actions inOregon, Vermont, and at the federal level illustrate how involvement and advocacy from solar advocates can improve burdensome laws and regulations.
Why Community Solar is a Security
The definition of a security includes membership in a profit-sharing agreement. Any community solar model that involves financial investment with the expectation of some return on that investment (or even potentially on-bill credits or other benefits) will likely qualify as a security. Why does this matter? The Securities and Exchange Commission (SEC) requires those offering securities to make certain filings and disclosures in order to provide adequate information to potential investors. Securities registration and disclosure requirements have virtues and vices. On the one hand, they protect against fraud by providing necessary information about investment opportunities to potential investors. But on the other hand, the costs (time, money, and paperwork) can be extremely burdensome for small, community-based projects.
SB 1520: Oregon’s Securities Exemption
When Oregonians for Renewable Energy Progress (OREP), a renewable energy advocacy group in Oregon, attempted to help form a solar cooperative in Corvallis, they quickly ran up against a costly and time-consuming securities filings process. Although federal law exempts wholly in-state offerings from registration and disclosure requirements, states have their own processes (called “blue sky laws”) that involve their own fees, paperwork, and disclosure requirements. But state blue sky laws can also provide exemptions for certain types of securities. For example, Oregon’s statute provides exemptions for certain types of cooperatives. Through the efforts of community members and OREP, the Oregon State Legislature passed Senate Bill 1520adding solar cooperatives to the listed of cooperatives exempted from the state securities filings requirements.
Yet, this picture is neither complete nor completely rosy. The amendment to the existing exemption allows theDepartment of Consumer and Business Services (DCBS) to essentially impose any restrictions or additional requirements it deems necessary to protect unwary investors from suspect solar scams. It remains to be seen whether these restrictions will relieve much, if any, of the major securities filings obstacles. DCBS has yet to issue its final rules, though the proposed version went through a notice and comment process. (See GEI’s comments on these proposed rules.)
Importantly, the Oregon exemption is limited to community renewable cooperatives, likely because it fit squarely within an existing exemption. In order to incentivize a broader scope of potential community solar models, though, other structures may need similar exemptions.
Vermont’s “SUN” Exemption
Vermont’s “Vermont Solar/Utilility No-Action” (charismatically abbreviated “SUN”) community solar exemption gets right what Oregon’s statute does not. Rather than exempt only solar cooperatives and impose a blanket set of restrictions on them, the SUN exemption recognizes that different groups of investors deserve different levels of consumer protection. The SUN exemption breaks down the potential groups into four sub-categories, each comprising a different set of potential investors. For example, a potential group of investors expecting to enter into long-term agreements without a termination right rightly deserves a substantial amount of information before making a decision. The SUN act therefore places significant disclosure requirements and advertising restrictions on the “Financing Exemption” group. On the other hand, a small group of neighbors, friends, or family (e.g. cooperative) wanting to invest in a community solar project may need less protection. Vermont’s “de minimis” exemption therefore provides such a group with a blanket, self-executing exemption that requires no disclosures.
Vermont is a state with a significant amount of support for, and investment in, renewable energy. If this relatively new exemption proves successful in spurring more community solar development there, its well-crafted model should serve as an example for other states.
The Proposed Federal Crowdfunding Exemption
Exemptions occur at the federal level as well. Recently, the SEC proposed rules that would flesh out securities requirements for crowdfunding under the Jumpstart Our Business Startups (“JOBS”) Act. Crowdfunding, as I discussed in Part 2 of my community solar blog series, has emerged as a potential way to fund community solar projects through small online donations or investments. Though the rules are not yet finalized, they will likely attempt to strike a balance between providing adequate investor protection and easing the burden on startups that operate through the crowdfunding mechanism. Potential ways of doing this include requiring certain disclosures to potential investors and imposing restrictions on available funding platforms.
Providing adequate investor protections while fostering the development of community solar projects is a difficult balance to strike. The regulations and statutes discussed above at the very least make attempts at doing both, with varying degrees of success. Perhaps once the community solar concept gains more traction, regulators and lawmakers will be less weary of questionable investment schemes and more willing to require less costly disclosure processes. Ideally, the SEC and states should craft exemptions similar to Vermont’s, recognizing that not all community solar models are cut from the same cloth. Until then, though, those seeking to form community solar entities will likely have to continue navigating the gnarly weeds of securities filings requirements and exemption regulations.