Two weeks ago, I wrote about existing community solar models. One model I discussed involved a utility-sponsored program allowing customers to buy into a community array and receive on-bill credits. According to recent research by the Solar Electric Power Association (SEPA), the utility-sponsored model currently leads the community solar movement. One explanation for this trend may be that utilities are beginning to realize (with a little legislative prodding) that they can get out ahead of a growing community solar movement by initiating the projects on their own. Redefining the role of the utility is certainly at theforefront of many people’s minds throughout the country (including my colleague, Nate Larsen) and investing in and managing community solar may be another manifestation of that trend.
While rural electric cooperatives and municipal utilities are at the front of the utility-led community solar trend, investor-owned utilities (IOUs) follow closely behind. Cooperatives and municipal utilities have much more flexibility because they are locally controlled rather than regulated by the states. The fact that they are leading the community solar development trend suggests that local accountability can drive their decisions even in the absence of policies that fail to favor community solar. But the fact that IOUs are actively initiating community solar projects as well suggests that something beyond accountability is spurring this trend.
Policies favoring community solar are one piece of the puzzle. Last week I wrote about a policy called virtual net metering, which allows customers to receive on-bill credits for remote generation. It is not surprising that virtual net metering is available in every state that has begun to experience a community-solar renaissance. But virtual net metering alone does not seem to encourage these projects. Rather, the most effective drivers of these changes seem to be incentives that make the projects cost effective or mandates that require their development. In fact, Colorado, Maine, Massachusetts, Minnesota, New Hampshire, Vermont, and Washington all have community solar statutes or specific incentives, and the majority of existing and proposed projects are in these states.
These statutes all take slightly different approaches to incentivizing community solar. Some have been more successful than others. Colorado was one of the first states to pass a “community solar garden” statute, which defines a community solar project, explains membership requirements, and outlines how a utility should interact with community solar gardens. Importantly, Colorado’s Renewable Portfolio Standard (RPS) specifically requires IOUs to purchase power from distributed generation projects, and the community solar statute allows up to 20% of the required distributed generation Renewable Energy Credits (RECs) from those projects to come from community projects.
Recently, California established a “shared renewables green tariff” requiring utilities to allow customers to purchase electricity from a utility-operated renewable community project. Like Colorado, California has an aggressive RPS, but this program would offer solar capacity above and beyond its 33% renewable energy by 2020 goal.
Minnesota’s community solar statute requires its major utility, Xcel Energy, to administer a community solar program. Other IOUs have the option, but are not required, to develop community solar programs as well. Notably, Minnesota’s Solar Electricity Standard includes a 1.5% solar carve out, though proposals to include additional community solar incentives died with the original bill.
New England also has its own collection of community solar statutes. Massachusetts was one of the first states to develop an RPS, and it has an aggressive solar program with a solar carve out and a number of available grants and incentives for streamlined permitting and efficiency programs. Vermont has a small-scale renewables incentive program that establishes a per-watt incentive for schools, municipalities, and low-income non-profit housing organizations to install PV systems. Maine has its own Community-based Renewable Energy Pilot Program. Under Maine’s program, participants qualify for a $0.10 per kWh incentive under a long-term contract, and the RECs generated from the project qualify for an additional multiplier making them worth 1.5 times the value of the electricity.
Finally, Washington State offers production incentives of $0.30 to $0.54 per kWh for community projects, but limits eligible projects to 75 kW and restricts their locations. Size and siting limits like this may be feasible for other community solar models (a church, for example, could be around 20 kW) but most existing utility-sponsored projects are larger.
States have taken different approaches to designing and implementing community solar legislation. Although policies like virtual net metering are important to facilitating these projects, it seems that specific mandates or directives have been the most successful in spurring their development. In the states that have adopted these policies, utilities have begun to take the lead on community solar investment. Whether this is a good thing for the community solar movement remains to be seen. To some extent, allowing utilities to take the lead on community solar makes sense in light of the myriad of obstacles that the other models face (for example Securities and Exchange Commission filings requirements and lack of adequate appetite for tax credits). But the downside could be that these programs will not result in the same potential return on investment for participants that the other models could eventually offer with the right regulatory environment and decreasing costs. Maybe there is room for both. But for now, the predominant state trend of engaging utilities in planning community solar projects seems to make sense.
The Hawaii Public Utilities Commission (PUC) issued a guidance document on April 28—Commission’s Inclinations on the Future of Hawaii’s Electric Utilities—which proposed a series of sweeping reforms to the state’s electricity industry. On August 26, the state’s investor-owned utilities, the HECO Companies, responded to a PUC order to file a Power Supply Improvement Plan (PSIP) that sets out the steps the utilities will take to achieve the state’s clean energy goals.
Last week’s post took a look at the PUC’s vision for the future of utility generation ownership outlined in theCommission’s Inclinations. This post will consider the Commission’s proposal to reform the rate structure to adapt to a future with greater distributed energy resource penetration, and the HECO Companies’ response to that proposal.
House of the Rising Sun
In its Commission’s Inclinations, the PUC laid out a number of potential avenues for reforming the HECO Companies’ rate structures. Some of those reforms were targeted to address the costs that some people believe distributed generation (DG) customers shift onto utility customers.
The majority of DG customers on the HECO Companies’ grid systems are Net Energy Metering (NEM) customers with solar photovoltaic installations. Hawaii’s net metering policy allows those customers to net out the cost of the electricity that they purchase from the utility with the power that they produce. Utilities argue, with some merit, that that arrangement fails to account for the costs associated with operation and maintenance of the electricity grid, and the provision of supplemental power and ancillary services, essentially foisting those costs onto non-DG customers.
The PUC offered three potential reforms to address that perceived cost-shifting issue, including 1) the implementation of an unbundled retail electricity rate structure, 2) capacity-based, fixed-cost based pricing, and 3) a supplemental power supply pricing structure. The mechanics of the suggested reforms vary, but the net effect of each would be to charge DG customers for the services that they consume above and beyond their own generation.
The Commissions’ Inclinations, however, failed to direct the utilities to consider and account for the potential value of distributed generation assets in terms of avoided transmission and distribution system upgrade costs. Any policy that the PUC approves should include a proper valuation, not only of the costs associated with serving DG customers, but also of the benefits that distributed generation provides to the system.
Give Them an Inch…
The rate reforms that the HECO Companies propose in their PSIP go beyond those envisioned by the PUC and will not likely survive review as currently constructed. The utilities propose 1) a $55 monthly charge for all customers, allocating customer service and demand costs; 2) a $16 monthly charge for DG customers, accounting for standby generation and capacity requirements; and 3) a “gross export purchase model,” compensating NEM customers at wholesale rates for the power they contribute to the grid. The cumulative impact of the HECO Companies’ proposed reforms would be to significantly curtail the economic incentive for customers to participate in the NEM program, most likely spelling the end of net metering in the state.
Utilities have similarly sought DG customer surcharges in other states, with limited success. Recently, APS, the largest investor-owned utility in Arizona, petitioned the Arizona Corporation Commission for a net metering surcharge of $8.00 per kilowatt to account for fixed costs. After reviewing the recommendations of the utility, ratepayer advocates, the solar industry and its own staff, the Arizona Commission approved a$0.70 per kilowatt charge on net metering customers’ bills.
The Hawaii PUC is likely to follow the lead of the Arizona Corporation Commission in approving a modest charge for DG customers. Although the Hawaii PUC seemingly opened the door for DG customer charges, it seems unlikely that it will approve charges at levels that would quash the net metering program and disincentivize renewable energy development.
Furthermore, the HECO Companies’ proposed rate reforms might even harm their long-term viability. If the PUC does approve the HECO Companies’ rate reform proposal, the calculus of increased rates for DG customers plus decreased compensation for exported power might make customer grid defection a more appealing proposition. The idea of exponential utility customer defection caused by a decreasing pool of customers being saddled with growing system costs is referred to as the “utility death spiral,” and it represents something of a nightmare scenario for investor-owned utilities. (But that is a topic for another day.)
Charting a New Course
As was the case with the issue discussed in last week’s post—diminishing utility ownership of generation assets—Hawaii represents one of the first states to tackle the issue of DG rate reform. For that reason, the policies that the Hawaii PUC adopts have the potential to influence the decisions of public utility commissions on the mainland.
It is therefore important that the Commission crafts a policy that fairly allocates the costs associated with serving DG customers, while considering the value of the avoided transmission and distribution costs that DG provides. In so doing, the PUC must avoid taking actions that will threaten the economic viability of the state’s utilities, while simultaneously preserving incentives for customers to invest in DG projects. An equitable policy that accomplishes all of those objectives could serve as a model for the rest of the US.
The economic case for renewables continues to become stronger. Solar and wind energy facilities are simultaneously becoming more efficient and less costly. Today, in terms of levelized cost of energy (a problematic measurement), wind energy is less costly than coal or than natural gas with carbon-sequestration technology. Meanwhile, the cost of solar power has been declining precipitously, and trends suggest that the U.S. Department of Energy’s goal of cost-competitive, $1/W solar powershould be attainable. As the costs of renewable energy continue to decline, the purely economic case for developing renewable energy becomes more robust.
Renewables Deliver More Bang for the Buck
A recent analysis from Mark Lewis at the French investment bank Kepler Chevreux notes that over 20 years, renewable energy will generate more net energy per amount of capital investment than oil. Under this analysis, which takes into account the efficiencies at which both oil and renewables are capable of generating electricity, solar and wind energy each generate many times more energy per dollar invested than oil. According to the study’s author, these renewables will be quite competitive with oil by 2020, and will definitively outcompete oil by 2035: “it is almost impolite to compare the net [energy return on capital invested] with that of renewables by 2035.” This analysis gauges the increasing economic virtues of electric cars, but is of limited relevance for the U.S. electricity sector because the United States does not generally burn oil for electricity.
However, other recent work does suggest that renewables are also becoming increasingly competitive with fossil fuels that the U.S. does burn for electricity. The most recent calculation of the levelized costs of different energy sources from Lazard, a financial advisory firm, reveals that even without any subsidies, wind and utility-scale solar power are cost-competitive with all forms of fossil fuels. The same study reveals that over the last five years, the levelized cost of wind energy has decreased 58%, while over the same period the levelized cost of solar energy has decreased a whopping 78%. Meanwhile, another study from Carbon Tracker suggests that coal is no longer a safe economic bet, in part because of competition from renewable energy. That study notes that as coal prices plunge due to oversupply and a lack of demand, “coal producers are gambling on survival in the hope that prices will somehow recover.” These reports reveal that investing in renewable energy is increasingly a prudent economic choice, even without regard to any environmental benefits.
Increasingly, the investment community is growing to recognize that investing in renewable energy is a sensible economic idea in its own right, regardless of environmental benefits. For example, Goldman Sachsfinds the renewable energy market “incredibly compelling” and has committed to invest $40 billion toward renewable energy projects. Similarly, J.P. Morgan has invested upwards of $3 billion, while UBS Bankanticipates directing significant financing toward distributed solar generation in the near future.
Meanwhile, the Rockefeller Brothers Foundation, a charity worth $860 million, recently announced that it will re-align its investments from fossil fuels toward renewable energy. The Foundation has already ceased investing in coal and tar sands, and is moving toward divestment from all fossil fuels. The New York Times cites Foundation trustee Steven Rockefeller as noting that the move has “both a moral and economic dimension.” Although many organizations, particularly institutions of higher education, have been divesting from fossil fuels, the move by the Rockefeller Brothers Foundation is particularly noteworthy because the Rockefeller family initially made its fortune from oil.
These economic trends suggest that renewable energy will increasingly be able to compete with fossil fuels on purely economic grounds. Regulators of the energy market should pay attention to these developments as they consider the energy mix for the next generation.
This post continues the discussion raised by GEI DirectorMelissa Powers’s post regarding the Fifth Circuit’s recent decision in Exelon Wind v. Nelson. In that decision, a majority of the court ruled that states have discretion to preclude some types of Qualifying Facilities (QFs) from entering into long-term contracts to sell the renewable energy they generate. This holding disregards the plain language of PURPA and the statute’s federal implementing regulations. Moreover, in reaching its decision, the court inappropriately deferred to the Texas Public Utilities Commission (PUC) rather than the Federal Energy Regulatory Commission (FERC).
As Melissa explained, PURPA requires utilities to purchase electricity generated by qualifying renewable energy facilities, and directs FERC to promulgate rules that facilitate this purchase mandate. FERC subsequently issued regulations that give “[e]ach qualifying facility” the option to either 1) sell power on an as-available basis, or 2) “provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term.” While this provision clearly grants “each” QF the option to enter into a legally enforceable obligation, in 2002 the Texas PUC amended its rule implementing FERC’s regulation to allow QFs to only make sales of “firm power” through legally enforceable obligations. QFs generating “non-firm power”—which includes power produced through existing wind energy technologies—may only sell their generation on an as-available basis.
The court’s decision to uphold the Texas PUC rule was largely influenced by the 2005 Power Resources III decision in which the Fifth Circuit held that “a state has broad authority to implement PURPA with respect to the approval of purchase contracts between utilities and [QFs].” Using this quoted language as support, theExelon majority concluded that the PUC’s implementation of PURPA was entitled to deference. In doing so, the court disregarded both the plain language of the FERC regulation and longstanding Supreme Court precedent regarding the level of deference an agency is entitled to receive in interpreting ambiguous regulations.
For decades, courts have followed a two-step approach to statutory and regulatory interpretation established by the Supreme Court’s Chevron and Auer doctrines. The first step to interpreting the meaning of a statutory or regulatory provision is to determine whether the relevant provision is clear or if the text is ambiguous. If the court concludes the provision is unambiguous, it will state what the provision means. If the regulation is instead open to more than one reasonable interpretation, the court will defer to an agency’s interpretation as long as the agency is authorized to interpret the meaning of the provision and the agency’s interpretation is reasonable and consistent with the text. Under these doctrines, courts should thus defer to a federal agency’s interpretation of its own regulation unless the interpretation is clearly erroneous or inconsistent with the regulation at issue.
To understand the flaws in the majority’s reasoning, it helps to first review the Judge Prado’s well-reasoned dissenting opinion. Applying Step One of the Chevron and Auer doctrines, Judge Prado determined that the plain language of the regulation unambiguously enabled qualifying non-firm power generators to sell power pursuant to legally enforceable obligations. Under the dissent’s reading of the regulatory text, “[e]ach qualifying facility” meant every qualifying facility, and therefore every QF had the option to choose between the two payment structures. Because the plain meaning of the regulatory provision was clear, the Texas PUC’s rule was inconsistent with the federal regulation.
The Exelon majority, however, inexplicably chose to disregard the interpretive framework established by the Supreme Court, and its analysis regarding the meaning of the regulation was disjointed and conflicting. First, the majority concluded that the regulation did not require that all QFs be allowed to form legally enforceable obligations because the regulation did not specifically address whether non-firm energy providers could enter into these agreements. Thus, because the regulation did not explicitly state that “legally enforceable obligations” are available to both firm and non-firm generators, the majority determined that Congress must have intended for state PUCs to decide which QFs could enter into long-term contracts. The majority further decided that interpreting the regulations to allow any QF to choose to either sell power on an as-available basis or through a legally enforceable obligation would render the option to sell power on an as-available basis unnecessary or “superfluous.” Under the majority’s logic, the PUC’s rule was justifiable because FERC could not have intended to give non-firm QFs the freedom to choose between the two pricing structures because these generators would never conceivably select to sell power on an as-available basis.
Judge Prado’s dissent challenged the validity of the majority’s conclusions regarding the meaning of the regulatory text. The dissent argued that the majority’s focus on the term “legally enforceable obligation” was misguided. According to Judge Prado, the relevant provision was the language granting “[e]ach qualifying facility” the option to choose to enter into a legally enforceable obligation. In other words, the meaning of “legally enforceable obligation” was irrelevant; all that mattered was that every QF “shall have the option” to form one.
Under Judge Prado’s reading of the regulation, the plain meaning of the text was clear: every QF must have the opportunity to choose between the two payment options. Because the text was unambiguous, the court was required to give effect to that meaning, and had no reason to continue on to Step Two of the Auerdoctrine, which considers whether an agency interpretation of an ambiguous provision is entitled to deference. The majority, however, conducted a deference analysis, though its reason for doing so and the approach it chose to follow were not in accordance with the Supreme Court’s interpretive doctrines. In doing so, the majority irrationally concluded that it was required to defer to the Texas PUC’s interpretation of the federal regulatory text, and determined that FERC’s interpretation of its own regulation was not entitled to deference because this interpretation was “unambiguously foreclosed by the regulatory text.”
To fully appreciate the shortcomings of the majority’s analysis, it is useful to understand the background surrounding FERC’s interpretation of the regulation at issue. In June 2007, Exelon had filed a complaint with the Texas PUC after the utility, Southwestern Public Service Company, had refused to buy Exelon’s power pursuant to a legally enforceable obligation (as required under FERC’s regulation). In response, the Texas PUC issued an Order declaring that Exelon’s power was not “firm,” and thus Exelon could not create a legally enforceable obligation with the utility. Exelon then filed a request for enforcement with FERC. FERC declined to commence an enforcement action against the Texas PUC, but it did issue a Declaratory Order letter stating that the Texas PUC’s Order was inconsistent with federal regulations. FERC also clarified that under its regulations, a QF is entitled to form a legally enforceable obligation for sales of non-firm power.
Under the Auer doctrine, FERC’s interpretation of its regulation in its Declaratory Order should be entitled to deference. The Fifth Circuit majority, however, determined that FERC’s interpretation was not entitled to deference, because the Power Resource III court had previously held that FERC’s regulation “unambiguously” gave the state authority to establish the requirements for forming a legally enforceable obligation. Under the majority’s rationale, the court was required to defer to the Texas PUC’s assertion that the state agency had properly implemented the federal regulation, even though the federal agency responsible for promulgating and implementing the regulation argued that the PUC’s actions were inconsistent with the regulations.
According to Judge Prado’s dissent, after departing from the plain meaning of the statute, the majority was wrong to refuse to defer to FERC. In other words, had the regulation actually been ambiguous (which, according to the dissent, it was not), the court was obligated to defer to FERC’s reasonable interpretation of its regulation. The majority therefore erred when it rejected FERC’s interpretation, “based on nothing more than the state regulatory authority’s say-so.” “In doing so,” Judge Prado opined, “the majority contravene[d] established principles of interpretation and administrative law and disrupts the scheme that Congress intended,” and improperly upheld a Texas PUC rule that facially conflicts with the federal regulatory requirements.
In conclusion, Judge Prado’s dissent cautioned that the majority’s approach has potentially far-reaching consequences, and will prevent PURPA from achieving its statutory purpose to advance the market for renewable and alternative energy. As Melissa Powers notes, this decision could significantly and negatively impact renewable energy development throughout the country for years to come. The implications and potential ramifications of the majority’s decision are enormous, yet the opinion was the product of flawed legal analyses and questionable logic. The Exelon decision appears more grounded in political ideology than impartial analysis of federal law, and it reflects poorly on the state of our judicial system as a whole. I share Professor Power’s concerns on the far-reaching implications of this decision, and hope the majority’s ruling is overturned through rehearing.
By Melissa Powers, Director of the Green Energy Institute
On September 8, the Fifth Circuit released Exelon Wind v. Nelson, a decision that eviscerates the Public Utilities Regulatory Policies Act (PURPA) in Texas and could have much broader impacts—on both renewable energy development and administrative law—well outside of Texas’s borders. Since 1978, PURPA has served as a critical tool to compel electric utilities to buy power from renewable facilities. PURPA spurred the first wave of investment in renewable energy in the 1970s, and it demonstrated that electricity generation could become a competitive, non-monopolistic enterprise. PURPA also provided the template for other countries to develop feed-in tariffs, which have spurred broad investment in renewables in Germany, Spain, and other countries. Despite its importance, however, utilities have long hated PURPA because it requires them to buy other entities’ power at competitive prices. If the Fifth Circuit decision remains on the books (but I hope Exelon will seek rehearing), it could provide a roadmap for other utilities and states hostile to PURPA to follow. This, in turn, would make independent renewable energy development even harder than it already is.
On its face, PURPA is a relatively simple law designed to promote development of “qualifying facilities,” which include renewable energy facilities with capacities of 80 megawatts (MW) or smaller. Once a qualifying facility is certified, it may compel a utility to 1) connect the qualifying facility’s power to the transmission system, 2) purchase the qualifying facility’s power, and 3) pay “avoided cost rates”—the rates the utility would otherwise pay to produce or purchase power from other sources—for the renewable power. In other words, PURPA created a mandatory market for small renewable energy facilities and guaranteed those facilities competitive rates for their power (at least in markets where wholesale power is relatively expensive).
In practice, PURPA has become more complicated and contentious as renewable energy producers, utilities, states, and the Federal Energy Regulatory Commission (FERC) seek to either implement or undermine PURPA’s mandate. Since PURPA’s inception, utilities and some states have sought to limit the power of PURPA by challenging the status of energy producers as qualifying facilities, by requiring qualifying facilities to pay high costs for transmission access, by keeping avoided cost rates low, and by seeking PURPA’s repeal. On the other side, qualifying facilities, other states, and FERC have sought to protect PURPA’s core requirements. The Exelon decision makes utilities and Texas clear victors in a key battle of the long-running and increasingly heated “PURPA Wars.”
The Legal Decision
In Exelon, wind power qualifying facilities owned by Exelon sought to compel the Texas utility, Southwestern Public Service Company, to buy their power pursuant to a long-term contract (or “legally enforceable obligation” in PURPA-speak). Southwestern refused to buy the power, relying on a Texas rule that allows only qualifying facilities that generate “firm power” to enter into legally enforceable obligations. Exelon challenged this refusal, arguing that federal—not state—regulations controlled the issue, and that federal regulations plainly required the utility to buy the wind power.
Each qualifying facility shall have the option either:
(1) To provide energy as the qualifying facility determines such energy to be available for such purposes, in which case the rates for such purposes shall be based on the purchasing utility’s avoided costs calculated at the time of delivery; or
(2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualifying facility exercised prior to the beginning of the specified term, be based on either:
(i) The avoided costs calculated at the time of delivery; or
(ii) The avoided costs calculated at the time the obligation is incurred.
Exelon argued (and the dissent agreed) that the regulation plainly gives “each” qualifying facility the option to either sell electricity (1) as available or (2) pursuant to a legally enforceable obligation. The choice, moreover, belongs to the qualifying facility and not the utility. The Texas rule, in contrast, only allows “some” qualifying facilities—those that produce firm power—to enter into legally enforceable obligations. It therefore conflicts with the requirement that each (and thus every) qualifying facility have the option of using legally enforceable obligations.
The majority, however, upheld the Texas rule based on a previous Fifth Circuit decision that gave the Texas PUC the authority to interpret “legally enforceable obligation,” a term not defined under FERC Rules. Thus, although the regulation requires “each qualifying producer” to have an option to sell renewable power through a legally enforceable obligation, the court decided the Texas PUC could eviscerate that requirement by defining “legally enforceable obligation” to exclude any qualifying facilities that produce non-firm power. As my colleague, Amelia Schlusser, argues, the Fifth Circuit’s ruling is full of legal flaws. And if it stands, it could seriously hurt renewable energy development.
The Implications for Renewables
The Exelon decision could have significant and harmful effects on renewable energy development in Texas and, perhaps, beyond. Within Texas, new wind and solar power developers could lose their access to capital if they cannot demonstrate they will be able to negotiate long-term contracts with utilities. Facilities that are operational in Texas but that lack an existing PURPA contract (like the wind farms at issue in Exelon) will have to sell their power on an as-available basis and likely have to accept low spot-market prices for their electricity. Perhaps worse, the decision could signal to other states how they can design their own PURPA-evading rules and may lead to other appellate courts following the Fifth Circuit’s questionable reasoning. Thus, not only will the Exelon ruling affect wind farms in Texas, it could affect the renewables industry across the country.
For new wind and solar developers, the Exelon decision has made Texas a very risky environment for investment. Renewable facilities already face the risk of intermittency and difficulty getting access to capital, but PURPA tried to mitigate those risks by guaranteeing access to the market and stable prices through long-term contracts. Without these long-term contracts, new developers will have a hard time convincing their investors that they can recover their sunk costs and become profitable. Other policies that could potentially mitigate the impacts of this decision, moreover, are not reliable replacements for the stability of PURPA long-term contracts. Past wind development in Texas has outpaced the state’s Renewable Portfolio Standard, driving down demand, and Congress’s failure to enact a stable long-term Production Tax Credit has dried up tax equity investment. While solar power development in the state has expanded in recent years, it seems likely that the PURPA limitation will hurt the solar market, as Texas has no net metering laws or RPS carve-outs specifically designed to support solar development. The future for new renewables seems bleak indeed.
The broader implications of Exelon are what really trouble me, though. Unlike many other states, Texas has actually done a great deal to build up its renewable energy infrastructure, and it has more than 12,000 MW of wind power capacity as it stands. Yet, even in Texas, resistance to PURPA has led to an evisceration of its key requirements. What will happen outside of Texas, when other utilities and states decide to follow the Texas PUC’s lead and “interpret” legally enforceable obligations so as to prevent long-term contracts for renewables? That prospect, perhaps more than anything else, makes me hope that Exelon will seek rehearing of the court’s poorly decided opinion.
In my last blog posts, I argued that due to its potentially far-reaching benefits, community solar should become an important component of a renewable energy-based electricity grid and identified some already existing models. However, the ultimate feasibility of community solar, from both a financial and a legal standpoint, depends on certain policies. One policy that is likely to prove crucial to widespread deployment of community renewable projects is virtual net metering.
Under a system called net metering, customers connect their own residential power (usually residential PV, but also small wind turbines) to their utility’s electricity distribution system. Any electricity the customer’s system produces offsets the amount of power the customer receives from her utility. At the end of the month, the utility bills the customer for the net amount of power that she consumes. If the customers’ energy system produces more electricity than she receives from the utility, states generally allow the customer to roll over credits into the next billing cycle. (States then have various ways of dealing with the excess credits at the end of the year. In Oregon, PGE and PacifiCorp customers’ excess credit accumulation gets credited to utility customers enrolled in a low-income assistance program.) Currently 44 states and utilities in Idaho and Texas and the District of Columbia have net metering policies in place.
Ten states and the District of Columbia have adopted a version of this policy called virtual or community net metering that is particularly important for the expansion of community-scale renewable energy. Through virtual net metering, customers who own or lease generation away from their homes (such as in a community array) can still receive a direct credit on their utility bills. Without this policy in place, customers are limited to community renewable energy projects that are either utility-sponsored or that take a form other than direct bill credit. Oregon’s net metering law does not allow for virtual net metering, and therefore PGE and PacifiCorp customers are unable to receive direct bill credits on any generation they own or lease in a community solar project.
Direct bill credits are an important component of these programs because they offer tangible benefits directly tied to energy consumption. In their model rules, the Interstate Renewable Energy Council (IREC) advocates bill credits as opposed to outright payment because, according to IREC, they avoid complicated securities issues and do not result in taxable income. Most importantly, though, bill credits can motivate consumers to alter their behavior to offset as much of their consumption as possible.
Yet virtual net metering has not been widely embraced because net metering has been heavily criticized by utilities since its inception. Utilities argue that under net metering, net-metered customers end up paying less than their fair share for the services the utility provides by managing the energy they send back onto the grid, and by providing backup power and safety services. The utilities argue that this dynamic effectively forces customers who do not have their own renewable energy systems to shoulder the cost.
While this argument has some superficial appeal, at least one recent study conducted by a consulting group in conjunction with the California Public Utilities Commission suggested that this alleged unjust cost shift is much more nuanced that it appears. In fact, in some circumstances, increased penetration of distributed resources could result in an overall reduction in cost of service to all customers, though the analysis is highly dependent on rate design (particularly rate class.)
The availability of virtual net metering seems to be an important policy for encouraging community renewable energy programs. But crafting utility and customer compensation to better reflect the benefits and drawbacks of adding more community net-metered systems to the grid will be a critical step to overcoming utility aversion. Including limitations such as geographic or capacity caps can be an important first step. Assigning a more accurate value to utility services, and compensating customers for the benefits their system provides (e.g. avoided transmission and generation) may be necessary in order to design successful and politically viable virtual net metering programs.
Some states have already begun considering the value of solar more carefully. For example, Minnesota recently developed a “value of solar” tariff that utilities may voluntarily apply in lieu of the retail rate when compensating customers for their solar electricity. Though placing a monetary value on social and environmental externalities is a significant step forward, not everyone is happy with the idea of pitting value of solar tariffs against net metering. It seems that a building better valuation methods into the existing net metering structure is a practical first step towards expanding opportunities for community solar. Over time, technological improvements and experience can inform even better alternatives.
Three U.S. cities—Burlington, VT, Greensburg, KS, and Beaverton, OR— are proving that the transition to a 100% renewable power grid is achievable in the near term.
Burlington, Vermont recently announced that it is now able to generate or purchase renewable energy to meet all of its energy demand. The city will obtain roughly one third of its energy from a large biomass facility, one third from wind energy contracts, and the final third from a newly purchased hydroelectric facility. Moreover, the Burlington Electric Department maintains that the transition to a fully renewable power grid will not cause any rate increases, but instead will lead to cost savings over the long term.
Finally, Beaverton, Oregon announced this year that it would purchase sufficient renewable energy offsets to meet all its power needs. For all city activities, including running public buildings, streetlights, and the water supply, Beaverton purchases credits for renewable energy from Portland General Electric (PGE). Of course, these purchases do not mean that the city actually consumes only renewable energy. In the words of Cindy Dolezel, the manager of Beaverton’s Sustainability Division: “This does not mean the actual electrons from a wind turbine are going directly into city facilities. It means that our commitment and financial support is making the electrons available to the electricity grid in an amount equivalent to the electricity we use for the city’s operational needs.” Nonetheless, these purchases led to Beaverton being among the only cities to receive PGE’s Platinum Clean Wind Award, and the city deserves recognition for its remarkable investment in renewable energy.
These progress these cities have made is remarkable and praiseworthy, but also raises important questions about what it means to make the transition to 100% renewable power. Burlington obtains a third of its ostensibly renewable energy from a large biomass facility, but critics contend that biomass is not really a clean form of energy and in fact emits more CO2 per MWh than coal. Meanwhile, Beaverton purchases clean energy credits but does not necessarily receive renewable energy as a result. Critics of such arrangements note that “[i]t isn’t reasonable to say that purchasing a [credit] is equivalent to not polluting.” On the other hand, renewable energy credits also have significant benefits, including giving monetary value to the environmental virtues of clean energy and allowing economically efficient investment in renewable facilities. Of course, a full analysis of the merits of biomass energy or renewable energy credits is beyond the scope of this blog post; this post merely notes that when one delves beyond headlines, interesting questions about the nature and merits of different renewable energy strategies emerge.
Greensburg’s progress raises perhaps the most interesting question of all: What is the best driver for transition to renewable energy? Greensburg began to pivot toward renewable energy after a cataclysmic tornado that nearly obliterated the city. And although those tornadoes are not likely directly linked to climate change, the changing climate poses another cataclysmic threat on a much larger scale. We should not wait for climate change to become a catastrophe before we transition to a renewable energy grid. Rather than reacting to disasters, governments at all levels should favor renewable energy for entirely pragmatic reasons. For example, Burlington and Greensburg demonstrate that renewable energy can reduce energy bills. And as the costs of renewables continue to plunge, the economic case for a transition to a renewable energy grid only becomes more robust. The World Future Council recently issued a report describing what policy makers can do to attain a 100% renewable energy future. Burlington, Vermont, Greensburg Kansas, and Beaverton, Oregon are blazing a trail toward a renewable energy future. Communities across the nation and around the world should take action too.
There are already approximately 80 existing community solar projects in ten states. As I explained in my last post, the term “community solar” loosely refers to a project that takes advantage of economies of scale by siting a solar array in one centralized location and allowing a number of local participants to benefit from the energy produced. But there are some major differences that distinguish these projects from one another. This post will highlight four existing community solar models and point out some of the elements that distinguish each project.
The “Adopt-A-Solar Panel” Structure
The simplest community solar model is one in which each investor, such as a local home or business, owns an individual panel in a larger array and receives credits on energy bills. For example, investors in this form of community solar can purchase their own panels located in a collective solar array and receive a credit directly on their energy bill. The Clean Energy Collective (CEC) prides itself on having set up the “first community solar garden,”that operates under this model. Notably, CEC’s model also establishes long-term contracts that set payment rates up front, thus hedging against future electricity rate increases. CEC is currently working on 33 projects in Colorado, Vermont, Massachusetts, New Mexico, Minnesota and Wisconsin. Next week’s blog post will explain how one policy, virtual net metering, makes these states particularly hospitable to CEC’s model.
The Solar Co-op
Another model allows participants to become members of a consumer-owned cooperative. Under this structure, the cooperative owns a solar array that a third party maintains and operates. Members then receive any benefit of their ownership through year-end dividends, or they might elect to put surplus earnings towards developing more solar projects. Cooperatives work well in other contexts where community members similarly seek to come together to form a democratic, member-owned, non-profit organization (such as my local food coop or REI.)
In the solar power context, the cooperative structure may be less appealing to investors than the other models because the return on investment would likely be minimal. Moreover, certain tax and securitiesrequirements present significant start-up obstacles. However, the success of one Washington cooperative solar share program, called Tangerine Power, offers some hope that even without the right policies in place, the cooperative structure could be a useful starting point for community solar in states where regulatory and financial hurdles make other options impracticable.
The Community-Oriented Utility
Some community solar projects are owned by utilities. In California, the Sacramento Municipal Utility District (SMUD) has a successful “Solar Shares” program that allows customers to purchase solar power from a centrally located array on a monthly basis. This structure is attractive to customers who are interested in purchasing their power on an incremental basis. The SMUD program, like the CEC model, credits the customer on his or her utility bill at the end of the month. Unlike the CEC model, the customer does not own the panels under this model. But the minimal upfront cost to customers and the relative financial and managerial expertise of utilities can make this structure attractive.
The utility-owned model is attractive to progressive municipal utilities like SMUD, but Investor-Owned Utilities (IOUs) could also play a role in greater community solar deployment. In fact, New York’s Central Hudson Gas & Electric recently issued a proposal in response to the state’s call for utility reform that involves building and managing community solar farms ranging in size from 1 to 3 MW. The power generated at those farms would be available to customers on a subscription basis at a fixed rate, much like SMUD’s program.
Utility-owned community solar sounds to some community-scale solar advocates like an oxymoron. On the other hand, incentivizing utilities to invest in solar projects whose electricity and other benefits (mostly) inure to surrounding communities could be a way to achieve forward-thinking compromise.
Crowd-funded Solar: You and 3,000 of your closest friends
A new community solar model challenges the definition of “community” that the other models embrace by expanding it to include online investors. Traditional community solar projects have focused on drawing investment from, and delivering benefits to, a group of neighbors. But a burgeoning funding model involves crowdsourcing, which may sound familiar to those who have donated to a Kickstarter or Indigogocampaign. Companies like the Oakland-based Mosaic connect borrowers with investors who provide upfront capital. Mosaic’s investors earn approximately a 4.5 % return on their investment once the array is producing and selling energy. Investors, who can contribute as little as $25 to support the project, are projected to earn back their investment in about 9 years. So far, Mosaic has sponsored 12 projects in three states, including an affordable housing project in California that sold all its shares in only eight hours.
Crowdfunding has proven successful in supporting everything from films to food carts. Even the Securities and Exchange Commission (SEC) seems to see its value in helping small projects get off the ground, having issued proposed rules exempting crowdfunding from certain securities registration requirements. The interest in companies like Mosaic suggests that crowdfunding could be successful in the community solar context too.
All of these models face regulatory, administrative, and financial hurdles. Moreover, inhospitable state renewable energy policies make some models either legally or practically impossible to set up in some states. Next week’s post will discuss some of the existing obstacles in Oregon and will offer some suggestions for how the state can better facilitate community solar development.