New England states have long touted the notion that renewable energy and energy efficiency are not just beneficial but essential to the states’ growth and efforts to combat climate change. Yet, in recent years, several high-profile examples have shown how such societal goals face significant challenges when such projects get underway. While commercial counterparties cannot completely transact away the risk that siting opposition, citizens’ initiatives, or other challenges might thwart a project before it achieves completion, parties have several options to address these risks and reallocate the burdens of operating in this uncertain environment.
There’s a saying in Maine: “You can’t get there from here.” This certainly rings true when it comes to Massachusetts’s multiple attempts over the past decade to bring clean energy from Quebec, first through New Hampshire and then Maine, both of which stalled.
Hydro-Quebec, a Canadian utility generating hydropower and other renewable energy, has for years sought to build a transmission line that could bring electricity to New England markets. The plan was initially unveiled in 2010 by electric distribution company Eversource, and the first iteration (known as Northern Pass, the name given to the joint venture between Hydro-Quebec and Eversource) included a new, approximately 200-mile-long high-voltage transmission line, with towers visible high above the treetops. The new line would have run through the North Country of New Hampshire, interconnect with existing transmission lines in southern New Hampshire, and deliver energy from Hydro-Quebec to the Massachusetts utilities’ grid.
Opponents of Northern Pass pursued a variety of strategies to block the project. They sought conservation easements to block potential routes. They lobbied the state legislature to enact laws prohibiting merchant transmission line projects like Northern Pass from using eminent domain to acquire land unless the project was necessary for electric reliability. And they advocated for Northern Pass to bury the transmission line, rather than build towers that would have dwarfed the trees in the surrounding forests. In response, Northern Pass proposed multiple routes from the Canadian border, each attempting to address opponents’ concerns. In 2015, Northern Pass sought approval to build its transmission line along yet another route: through the White Mountain National Forest (at a cost significantly greater than what was originally proposed and transmitting less power).
While advocates of Northern Pass advertised the project’s capability for bringing more renewable energy into the New England market (indirectly benefiting New Hampshire), local concerns ultimately outweighed whatever benefits the project might have brought to the state. In 2018, the New Hampshire Site Evaluation Committee unanimously denied Northern Pass’s permit application—a decision upheld by the New Hampshire Supreme Court in 2019.
With Northern Pass in New Hampshire no longer an option, Hydro-Quebec sought a new route to bring Canadian hydropower to Massachusetts, this time through Maine. It did so by creating New England Clean Energy Connect (NECEC), a partnership between Hydro-Quebec and Maine utility Central Maine Power. Unlike Northern Pass, NECEC did not need to acquire significant portions of land on which to build the transmission line. The project involved building approximately 50 miles of new utility corridor on an existing right-of-way through western Maine from the Canadian border to an existing utility corridor, where new transmission lines would run parallel to existing lines for approximately 100 miles before interconnecting with a new substation in Lewiston, Maine. As part of a negotiated package, NECEC offered an array of incentives for Maine consumers and ratepayers in addition to the renewable energy contracted by Massachusetts.
Following three public hearings, six evidentiary hearings, and numerous technical conferences, the Maine Public Utilities Commission (Maine PUC) unanimously voted to grant Central Maine Power a certificate of public convenience and necessity (CPCN), which is a gating approval required for any significant transmission projects in Maine for the construction and operation of NECEC. The Maine PUC based its decision on the anticipated reduction in electricity prices for Maine consumers, increased reliability of the transmission and distribution system, and displacement of fossil fuel energy generation with renewables, plus a stipulated Maine benefits package totaling about $250 million.
NextEra Energy Resources (NextEra), an owner of wholesale generation in New England benefiting from the high electricity prices that NECEC would suppress (and a participant in the Massachusetts RFP process that NECEC ultimately won), unsuccessfully appealed the Maine PUC’s decision to the Maine Law Court. NextEra Energy Res., LLC v. Me. Pub. Util. Comm’n, 227 A.3d 1117 (Me. 2020). It then funded in significant part a grassroots campaign to gather signatures for a “resolve” by citizen initiative—a legislative instrument with limited scope and duration that has the force of law but does not directly amend any statute—directing the Maine PUC to reverse its prior findings and decision on NECEC and deny the project’s request for a CPCN. Foreign Company’s Subsidiary Poured Millions into Influencing Maine Ballot Referendum, OpenSecrets (Nov. 3, 2021). Granting a preliminary injunction sought by Central Maine Power’s parent, Maine’s Supreme Judicial Court ruled, under a separation of powers analysis, that the initiative was an unconstitutional attempt by the people to use their legislative authority through a “resolve,” which usurped the Maine PUC’s executive authority to find facts and adjudicate a permit application. Avangrid Networks, Inc. v. Sec’y of State, 237 A.3d 882, 895 (Me. 2020).
Opponents of NECEC, again funded in significant part by NextEra, sponsored a second citizens’ initiative in late 2020. This referendum proposed to retroactively amend two provisions of Maine law. The first prong of the referendum would have required a two-thirds vote of each chamber of the Maine legislature to approve any lease of public lands for transmission lines. The second prong would have required approval of the legislature for construction of any high-impact electric transmission line in Maine and prohibit high-impact electric transmission lines in a specific geographic region of Maine (which includes NECEC and no other project) retroactive to a date just prior to NECEC commencing construction. The latter change in law specifically added a criterion to the Maine PUC’s standard for awarding a CPCN, which would retroactively block NECEC, even after NECEC had met the criteria that applied at the time when construction began. On November 2, 2021, 59% of Maine voters approved the ballot initiative, effectively halting NECEC.
Following the referendum’s enactment, NECEC sought a preliminary injunction in Maine’s lower court, attempting to prevent the initiative from taking effect. At the time, NECEC had expended approximately $450 million on the project—a little less than half of the total estimated project costs—and had received local, state, and federal permits required for construction. The trial-level court denied NECEC’s request for declaratory judgment and a preliminary injunction, and NECEC appealed the decision to the Maine Supreme Judicial Court.
The Doctrine of Vested Rights sits at the center of NECEC’s challenge to the second referendum. Under Maine law, a party may complete construction of a project where it can show (1) actual physical commencement of some significant and visible construction, (2) that the commencement was undertaken in good faith with the intent to continue construction and carry it through to completion, and (3) that construction had commenced pursuant to a validly issued permit. Sahl v. Town of York, 760 A.2d 266, 269 (Me. 2000). The lower court found that NECEC clearly established the good faith prong of the Vested Rights Doctrine: There was no question that NECEC commenced the project in good faith and intended to carry through to completion. However, the law court determined that NECEC had not satisfied the first and third prongs of the test. Retroactive legislation is permissible in Maine and, at the time NECEC started construction, it did so “under intense risk that a change in the law would have an adverse impact on the success of the Project,” preventing its rights to complete the project from vesting. NECEC Transmission LLC v. Bureau of Parks & Lands, No. BCD-CIV-2021-00058, 2021 WL 6125325, at *12 (Me. B.C.D. Dec. 16, 2021). NECEC argued on appeal that requiring all permits to be final would “cripple infrastructure development” and “major developments would be subject to shifting legal landscapes for an unreasonable length of time” if Maine’s highest court were to adopt the trial court’s finality rule. Appellant’s Brief on Appeal (Feb. 16, 2022) (noting that the appeal periods for certain federal permits extend for six years). The Maine Supreme Judicial Court held on appeal that “NECEC could reasonably rely on the CPCN, and our judgment affirming the CPCN, as valid authorization to begin construction such that its right to proceed according to the CPCN’s terms could vest upon evidence that it undertook significant, visible construction in good faith, according to a schedule that was not created or expedited for the purpose of generating a vested rights claim.” NECEC Transmission LLC v. Bureau of Parks & Lands, 2022 ME 48, ¶ 50, as revised (Sept. 8, 2022). In reaching its decision to remand the case for further proceedings, the court noted that “the possibility of a retroactive change in the law” was not enough to preclude a finding that NECEC had commenced construction in good faith when, at the time construction commenced, there was “no indication” that the citizens’ initiative would bear fruit. Id. at n.17. Even if NECEC ultimately succeeds, development projects must nevertheless contend with a legal landscape in which citizens’ initiatives can impose retroactive requirements halting a project well after construction has commenced.
In addition to grassroots initiatives, whether in fact led by the “people” or a corporate competitor, changing whims (and party control) of legislative bodies can thwart renewable development. Recent revisions to Maine’s Net Energy Billing (NEB) program, for example, cast doubt on the viability of solar projects under development. The Maine PUC has allowed the form of net metering known as “net energy billing” for over two decades. In 2016, a conservative state administration and legislature used a combination of regulatory and legislative tools to reduce program eligibility and incentives. In 2019, a subsequently elected legislature (with support from recently elected Governor Mills) enacted a law undoing these changes and significantly expanding Maine’s NEB program. Reforms enacted in 2019 increased maximum facility size from 660 kilowatts to “less than 5 megawatts (MW),” permitted an unlimited number of accounts (up from 10) to net off a given generator, and mandated a crediting program for nonresidential consumers capable of offsetting demand charges and other utility-billed amounts (in addition to offsetting energy consumption).
As revised in 2019, Maine’s NEB program encouraged significant growth in solar developments in the state. Many national and regional developers, and relatively fewer local developers, began solar developments under the program. Large banks and private equity funded portfolios consisting of numerous small projects that morphed over time to fit NEB regulatory requirements regarding size, interconnection timelines, and permitting timelines. At the same time, the Maine PUC and other governmental entities determined that the revised programs would impose significant costs on Maine ratepayers, with the Maine PUC estimating potential costs ranging from $38 to $383 million per year. Utility interconnection queues became overcrowded, and time lines for completing interconnection studies and constructing any needed facilities ballooned (often exceeding three years).
To address cost concerns, the most recent two legislative sessions rewrote the criteria for participation in NEB programs, allowing certain projects with preexisting rights to proceed while placing development restrictions on numerous others based on their development status and progress. In 2021, the legislature enacted new requirements for projects 2 MW and larger, including a series of project milestones tied to specific deadlines and related reporting procedures. The 2021 enactment generally applied to projects that were not yet in commercial operation as of its effective date, meaning the milestones became relevant to projects that had been initially developed without being subject to these requirements. This prompted many project developers to jump through the hoops associated with these new requirements to retain eligibility, while other project developers attempted to downsize their projects to less than 2 MW to avoid triggering these requirements. In 2022, the legislature continued to modify the program, enacting additional eligibility restrictions, milestones, and procedural requirements for NEB projects greater than 1 MW and altering the value of the monetary credit available to participating customers.
The individuals who sit on state PUCs can also have enormous influence on the viability (or lack thereof) of energy initiatives. Recent events in New Hampshire demonstrate the risks of relying on a body of appointed officials when there is no requirement that those political appointees have any background or expertise in energy policy. New Hampshire law “declares that it shall be the energy policy of this state to meet the energy needs of the citizens and businesses of the state at the lowest reasonable cost while providing for the reliability and diversity of energy sources. . . .” N.H. Rev. Stat. Ann. § 378:37. With cost as a driving factor behind the state’s energy policy, it may come as no surprise that, as its Consumer Advocate Don Kreis stated, New Hampshire is “the New England State that is dead last when it comes to energy efficiency.” Update: A Megawatt Mea Culpa from the Consumer Advocate, InDepthNH.org (May 17, 2021).
Every three years, the New Hampshire PUC must approve a triennial energy efficiency plan funded by ratepayers and managed by the state’s utilities. In September 2020, New Hampshire utilities, the Consumer Advocate, and other interest groups submitted an ambitious plan to expand energy efficiency efforts under the “NHSaves” program. The proposal would have funded incentives and provided contractor support for new construction of residential homes, incentives for purchasing and installing ENERGY STAR–certified appliances and other equipment, home weatherizing programs, and comprehensive home improvement/energy-savings programs. It also included funding for programs designed to reduce peak demand and other strategies to educate consumers about their energy consumption and incentivize them to adopt more energy-efficient behaviors or technologies. The proposal came with a ratepayer-funded cost of nearly $400 million.
Critics of the proposal derided the increased energy efficiency charges that would hit ratepayers’ bills, even though such charges make up only a small portion of utility bills in New Hampshire. In addition, the energy efficiency upgrades that would be paid for under NHSaves would benefit all ratepayers in New Hampshire—not just those consumers who receive particular upgrades—because they reduce demand on the system overall. To quantify those savings, in 2019, the NH PUC adopted the Granite State Test, which had been created at its request and “focuses on costs and benefits which accrue to the utility system, while also considering impacts associated with unregulated fuels, water, fossil fuel emissions, and income eligible participants.” NH PUC Order No. 26,322. Yet in 2021, the NH PUC (comprising a different set of politically appointed commissioners) rejected the Granite State Test as “overly dependent upon subjective factors such that any desired outcome could potentially be obtained from its application” and a test that “cannot be expected to be reasonably understood by the general public.” NH PUC Order No. 26,553.
The 2021 NH PUC rejected not just the Granite State Test but also the entire triennial proposal, returning funding for NHSaves to 2020 levels. Numerous stakeholders objected and sought reconsideration of the NH PUC’s decision. The Consumer Advocate appealed the matter to the New Hampshire Supreme Court and advocates lobbied the New Hampshire legislature to override the NH PUC’s decision. In response, the legislature codified specific requirements for energy efficiency programs in the state that, while not as ambitious as the proposal the NH PUC had just rejected, nevertheless presented a significant improvement over the status quo and reiterated that the NH PUC should use the Granite State Test to evaluate the cost effectiveness of energy efficiency proposals. N.H. House Bill 549 (2022).
In the meantime, consumers who had planned to avail themselves of rebates and other initiatives under NHSaves, as well as numerous businesses throughout the state that provide energy efficiency services funded (in whole or in part) by NHSaves, have had to adapt. Contractors who staffed up and invested in additional equipment in anticipation of expanded funding for NHSaves had to contend with reduced demand when consumers who could not afford energy-efficient improvements without the program’s rebates delayed or canceled their projects. And consumers who still went forward with energy efficiency projects did so with higher costs than they had anticipated in reliance on the availability of NHSaves rebates.
Each of these examples, Northern Pass and NECEC, Maine’s NEB program, and NHSaves, shows the risk inherent in undertaking an infrastructure or development project when the legal or regulatory landscape that was in place at the project’s inception turns upside down before its completion. Commercial counterparties have two, potentially parallel, paths they can pursue to mitigate the risks of similar circumstances occurring mid-project: allocate risks among themselves through well-crafted transaction documents and/or advocate to change the law.
Numerous contractual mechanisms are available to shift and allocate risk among the parties. First, the basic deal structure used in most renewable development transactions—sign-then-close—serves to place much of the risk of changed circumstances on the seller or developer and insulate the buyer or lender from that risk. Unless certain specified closing conditions are met, the buyer has no obligation to close (and fund remaining payments). These closing conditions are often highly negotiated and address conditions such as execution of interconnection agreements, issuance of permits, and evidence of clear title to the real estate on which a project will be built. However, by their very nature, closing conditions generally contemplate issues or roadblocks known to the parties at the time the definitive agreement was executed. Consequently, unknown or unforeseeable risks can be difficult to mitigate contractually.
Legal challenges and legislative change can often take years to run their course, so how do parties allocate the risk of a regulatory sea change upending their project mid-development? And when is a potential controversy sufficiently ripe that failure to address it in the definitive agreement will be construed against a party when a fact finder interprets the contract language in a dispute?
To address these potential concerns, parties should pay careful attention to contract provisions that are often ignored as “boilerplate” but have come to play increasingly important roles in the current environment. We highlight four provisions that can be used to shift risk among the parties: material adverse effect, force majeure, change in law, and termination rights.
Material adverse effect (MAE) (also referred to as material adverse change, or MAC) is generally broadly defined as any event, occurrence, fact, condition, or change that is materially adverse to (1) the business, results of operations, condition, or assets of the seller or (2) the ability of the seller to consummate the transactions contemplated by the definitive agreement, subject to certain exclusions. Typical exclusions include (a) conditions generally affecting the industry in which the seller operates and (b) changes in applicable laws. The absence of an MAE is often a condition to closing in a sign-then-close transaction. And in many different types of transactions, the seller must represent and warrant that no MAE has occurred between a specified point in time (often the date parties executed a term sheet or letter of intent, or the date of the seller’s last annual financial statement) and the date the definitive agreement is signed. In a financing arrangement, the occurrence of an MAE can trigger a default.
Consider how the MAE exclusions might apply in the case of a solar development transaction: If a change in applicable law is not an MAE and the state legislature amends the law to prohibit additional solar developments’ participation in a program like NEB, no MAE would have occurred, even if the change was material and adverse to the business of the seller. In this scenario, the “no MAE” closing condition could still be satisfied and the buyer would be required to close on solar projects even though the new law prohibits the seller from completing or operating the projects. To address this potential risk, the buyer should consider adding an exclusion to the exclusion, such that changes in laws materially impairing a buyer’s ability to participate in NEB or group net metering programs would be an MAE.
Force majeure provisions present another opportunity for parties to allocate the risk of unforeseen circumstances outside of their control after an agreement is signed. In broad strokes, the occurrence of a force majeure event relieves a party from their obligation to timely perform. Depending on how it is drafted, the provision can also prevent or delay the imposition of penalties for delay. Typically, force majeure is defined to include events beyond the control of the parties, such as natural disasters, epidemics or pandemics, labor stoppages, supply shortages, and governmental actions. As with MAE definitions, parties should carefully consider what sorts of impediments to completion exist for their particular project and negotiate up front whether a possibility on the horizon should relieve one party or the other of their ability to perform. For example, if you know that a particular stakeholder group is vocally opposed to your project, who should bear the risk of protests halting construction? Should vandalism or terrorism be included or excluded from the definition of force majeure? Similarly, does the “act of God” need to make performance impossible or just impracticable or commercially unreasonable?
In addition, when a change in law is imminent—for example, when it is public knowledge that a state legislature is considering bills to dramatically expand or curtail particular types of development—parties should consider including express provisions specifying what happens if applicable laws change in certain ways. Options include postponing signing any agreements until the law is enacted (and potentially renegotiating the entire deal at that point), providing for a specific remedy if an expected change occurs, as well as providing for a generic remedy in case unforeseen changes arise. Alternatively, parties can stay silent on the potential change and assume the risk that the change will cause their deal to fall apart.
Material adverse effect, force majeure, and changes in law (and many other circumstances) can trigger termination rights favoring one party or another. Termination rights can be piecemeal (e.g., the right to terminate one of many projects in a portfolio that the buyer has contracted to acquire) or all-encompassing, terminating the seller’s or lender’s obligation to consummate the entire transaction. As an intermediary step, parties could also negotiate reductions in the purchase price or availability under a credit line, which offers lesser protections to the buyer or lender but allows the seller or developer to continue operations without losing their source of funding entirely. Alternatively, a seller may want to allow the buyer to terminate, but only if the buyer pays a termination fee structured to compensate the seller for their efforts up to that point. Ultimately, the viability of any of these contractual protections depends on the negotiating leverage of each party. A buyer eager to close on projects may be willing to make accommodations where the seller has other potential purchasers waiting in the wings while, conversely, a seller desperate for an infusion of cash may accept terms weighted in favor of the buyer.
Parties should also consider legislative advocacy as another option to address the risks of operating in this evolving environment. Legislative advocacy can be both proactive and reactive. For example, the opponents of Northern Pass (mentioned above) pursued defensive legislation that prohibited the developer from using eminent domain to acquire property rights for the transmission line. More recently, advocates of energy efficiency programs persuaded the New Hampshire legislature to enact new laws requiring the NH PUC to approve broader energy efficiency programs than the Commission had previously wanted.
Parties should not forget the importance of strong, clear PUC oversight in creating renewable energy program staying power. Energy policy should be set with stability and the public interest in mind—not by unqualified regulators or legislators acting on political whim. When comprised of qualified, knowledgeable commissioners, a PUC allows individuals with the necessary expertise to work out technical issues while keeping impacts just and reasonable. To some extent, PUC oversight can also mitigate political whiplash when administrations change. But this requires that each administration appoint qualified individuals to serve on the PUC in the first place. The appointment of qualified PUC commissioners should be part of parties’ advocacy agenda.
While opponents of renewable energy projects have used various approaches to block development, understanding these approaches allows commercial parties to anticipate and potentially contract around the uncertainty in this environment. By paying attention to the “boilerplate” in their transaction documents and undertaking legislative advocacy as needed, commercial counterparties can mitigate the risks inherent in doing business in an area where the legal landscape remains in flux.
