On August 16, 2022, President Biden signed into law the Inflation Reduction Act (“IRA”). Heralded as a “transformative” legislative package, the IRA provides eye-popping incentives to drive clean energy development and related manufacturing and to reduce carbon emissions by almost 1 gigaton by 2030. Tax incentives for new renewable energy generation and energy storage facilities, including standalone storage, could reach $369 billion over the next ten years. In addition, renewable energy tax credits, which have existed for some time, will now be tradable, which will create a new marketplace and ways to monetize these incentives.
Money, however, is only part of the calculus, and arguably not the most significant barrier, when evaluating the viability of projects. The struggle to satisfy environmental and land use permitting prerequisites, and the threat of subsequent litigation, can bog down projects in a seemingly endless cycle of additional study and review, notwithstanding clear statutory and regulatory admonitions against this approach. Furthermore, ten years may sound like a generous amount of time to take advantage of all the IRA has to offer, but time can quickly tick by when siting missteps must be resolved, agencies with overlapping jurisdiction set their own timelines for review, and an assortment of stakeholders air individual grievances.
Fortunately, several statutory, regulatory, and planning changes are underway or have recently been adopted that complement the IRA and increase the likelihood that the federal and state governments will meet imperative renewable energy development goals. To the extent that these efforts are still in their formative stage, developers have an opportunity to shape them to address and resolve past challenges. To the extent that programs are already in place, developers should familiarize themselves with the options and press for other jurisdictions to emulate programs designed to overcome permitting obstacles. The following discussion steps through some of the most recent developments.
Landscape Level Project Planning
Landscape level planning for solar and other renewable energy projects on public lands managed by the Bureau of Land Management (“BLM”) have proven to be an effective, though not infallible, tool for facilitating thoughtful and timely development. Starting with the Final Programmatic Environment Impact Statement for Solar Energy Development in Six Southwestern States (“PEIS”) issued by BLM and the U.S. Department of Energy (“DOE”) in July 2012 (the “Solar PEIS” or “Western Solar Plan” covering Arizona, California, Colorado, Nevada, New Mexico, and Utah) and the Restoration Design Energy Project (“RDEP”) in Arizona in January 2013, and then evolving into the Desert Renewable Energy Conservation Plan (“DRECP”) in California in 2016, landscape level plans compile and analyze existing data to facilitate “smart from the start” siting decisions that balance development mandates and conservation concerns by directing development to particular areas (e.g., Solar Energy Zones (“SEZs”)[i] under the Solar PEIS, Renewable Energy Development Areas (“REDAs”)[ii] under the RDEP, and Development Facilitation Areas (“DFAs”)[iii] under the DRECP). Depending on the level of detail behind the plan, these documents can ease permitting burdens and reduce uncertainty by providing benefits ranging from permitting priority and tiered environmental analysis (e.g., the Solar PEIS and the RDEP), to expedited permitting timelines made possible by adopting pre-approved best practices and programmatic authorizations (including an applicable biological opinion for limited potential take of endangered species, as was done with the DRECP).[iv]
New efforts to refine and grow BLM’s landscape level plans are currently underway. On December 8, 2022[v] BLM issued a notice of intent (“NOI”) announcing a proposal to improve and expand the Solar PEIS to “advance the goals of recent Executive Order 14008 and the Energy Act of 2020” which includes a push “‘to issue permits that, in total, authorize production of not less than 25 gigawatts of electricity from wind, solar and geothermal energy projects by not later than 2025, through management of public lands and administration of Federal laws.’”[vi] Key modifications being considered by BLM include:
- Expanding the Western Solar Plan to include 11 states (adding Idaho, Montana, Oregon, Washington, and Wyoming to the inaugural list of six states)
- Eliminating exclusion criteria that may needlessly constrain development (especially technological constraints that preclude development in locations with slopes greater than five percent and insolation values below 6.5 kWh/m2/day)
- Revising, or removing altogether, the variance process for approving development on lands outside of designated development areas like SEZs and DFAs
- Broadening the definition of a covered “utility-scale” solar energy project to include projects less than 20 megawatts (which are currently excluded and thus developed on a piecemeal basis outside of the plan)
- Supplementing incentives to develop in priority areas like SEZs
In addition, through its separately stated planning criteria, BLM has committed to, among other things, “consider and analyze relevant climate change impacts in its land use plans and associated NEPA documents” and “analyze environmental justice in the programmatic EIS and plan amendments, recognize the special importance of the public lands to local communities, and consider relevant national strategic objectives for renewable energy.”[vii]
Revisiting Unheeded Comments on the 2012 Solar PEIS
Ironically, the solar industry, from the start, identified as problematic many of the issues BLM now seeks to redress. In particular, the industry urged BLM not to exclude lands based on technological factors including slope and insolation. They also pressed BLM to create a more flexible variance process, foreseeing the reality that despite BLM’s best intentions, most development would take place on variance lands.[viii] Within variance areas in particular, companies have struggled to convince certain BLM offices that the Solar PEIS’s long list of “factors to be considered” when evaluating a variance application are not, in fact, criteria that must be met. Some offices have additionally represented that they cannot process variance applications while applications in designated areas are pending.
The 2023 Solar PEIS will consider revising the process for authorizing development in exclusion areas and in variance areas (areas neither approved nor disapproved for development in the 2012 Solar PEIS, but nevertheless “identified as appropriate for solar energy development”[ix]). Specifically, BLM intends to consider “whether the [variance] process should be included in the programmatic EIS or whether the variance procedures would more appropriately be effectuated by other means, such as through regulation or policy.”[x] Embedding the process in the land use plan or a regulation will generally complicate the process for revising these procedures in the future, as the mechanisms for amending such instruments require a lengthy public process. The recently issued Instruction Memoranda (“IM”) specifying the Variance Process for Solar Energy Applications (IM 2023-015),[xi] for example, could only clarify and perhaps streamline the variance process detailed in the 2012 Solar PEIS.[xii] If left entirely to policy documents, however, the process would be vulnerable to the whims of different state offices and evolving inconsistencies.
The timing of this inquiry regarding variance lands is somewhat surprising, given the almost simultaneous publication of IM 2023-015 and the NOI. Earlier this year, BLM also issued an IM on Initial Screening and Prioritization for Solar and Wind Energy Applications and Nominations/Expressions of Interests (IM 2022-027),[xiii] which, in conjunction with IM 2023-015, addressed one of the most vexing issues identified above—clarifying that variance areas can qualify as high priority projects. There are, however, other ways to improve the variance process to ensure that development is not foreclosed on good sites that may have been overlooked in the planning process.
Still other issues preemptively identified in industry comments on the 2012 Solar PEIS do not appear to be on BLM’s radar given the points made in the NOI. Chief among these is the need to consider existing transmission and prospects for development of new transmission when selecting zones. Indeed, transmission concerns are not even mentioned in the Solar Programmatic EIR Planning Criteria.[xiv] Beyond whether sufficient transmission exists or will exist in the abstract, BLM also needs to take into account the reality of the massive queues that have built up in California and other western states where certain developers have already spoken for significant amounts of actual and hypothetical transmission.
Opportunities to Improve Landscape Level Planning
The implementation history of the Western Solar Plan showcases several success stories, but also demonstrates a need for improvements. For example, when BLM held its first competitive auction for prospective projects in the De Tilla Gulch and Los Mogotes East SEZs in Colorado on October 24, 2013,[xv] it did not receive a single bid. At the time, there was speculation that uncertainty about transmission options and/or unresolved mitigation obligations affected confidence in the process.[xvi] A year later, the BLM Nevada State Office held a competitive auction that resulted in the selection of three companies to develop six parcels in the Dry Lake SEZ. Unlike the Colorado attempt, BLM released a Regional Mitigation Strategy for the Dry Lake Solar Energy Zone (BLM Technical Note 444)[xvii] a few months before the June 30, 2014 auction date. This solar regional mitigation strategy (SRMS)[xviii] identified mitigation priorities and options in advance of development, delivering on the promise of the Solar PEIS to de-risk renewable energy projects. Transmission options were also much more obvious. Still, the development of the Dry Lake SEZ was not without its challenges, as the project was subjected to (among other things) a consultation process with the United States Fish and Wildlife Service that lasted over 3 months, delaying construction beyond the promised expedited timelines.[xix]
The newly proposed planning process offers a chance to redress some of the issues encountered in the first iteration and expand opportunities to utilize public lands for solar energy production. To align with the objectives and timelines of the IRA, it is critical that the revised PEIS include features that create certainty in the permitting process and front load decision making as much as possible, in addition to removing artificial barriers to siting decisions already identified in the NOI. At the same time, it is equally important that any new plan(s) do not interfere with sound development proposals not expressly accounted for by including a robust variance program (whether as part of the plan or as a standalone policy) as well as clear provisions addressing the applicable requirements for pre-existing applications (as was seen with the implementation of the DRECP, the permitting of purportedly “grandfathered” projects was significantly delayed to consider plan-compliant alternatives, even though the plan did not apply).[xx]
BLM has committed to hold two virtual and 12 in-person, public scoping meetings on the proposal to update the Solar PEIS (one in-person meeting will be held in each state affected as well as Washington, D.C.). It has also committed to accept comments until February 6, 2023, or 15 days after the last public scoping meeting, whichever is later. Only three meetings have been scheduled so far, but the latest one to date is set for February 13, 2023, so at a minimum the comment period will run until February 28, 2023.[xxi]
Coordinated and Streamlined, Multiple-Agency Permitting Processes
In locations where authorizations from multiple federal, state, and local permitting agencies might be required for a single project, a coordinated and/or consolidated approach to permitting can avoid unnecessary delays due to a number of factors, including resource constraints and politics. One of the first programs of this type made available to renewable energy projects (and still available today) was the “FAST-41” program, established by Title 41 of the Fixing America’s Surface Transportation Act (“FAST Act”).[xxii] FAST-41 established a voluntary program for large, complex infrastructure projects that included “a new governance structure, set of procedures, and funding authorities to improve the Federal environmental review and authorization process for covered infrastructure projects.”[xxiii] Among other things, the program offers clear processing timelines (and holds agencies accountable for meeting those timelines) and reduces the statute of limitations for challenging project authorizations from six years to two. Qualifying, non-tribal solar projects must, among other things, be subject to review under the National Environmental Policy Act (“NEPA”)[xxiv] and either “[b]e likely to require a total investment of more than $200,000,000” or be “of a size and complexity that makes it . . . likely to benefit from enhanced oversight and coordination . . . .”[xxv] The governing Federal Permitting Improvement Steering Council (“FPISC” or “Permitting Council”) is also authorized to require reimbursement for the reasonable costs of conducting environmental reviews and authorizations for covered projects;[xxvi] however, regulations proposing a $200,000 initiation fee[xxvii] did not garner sufficient support.
Taking coordinated permitting one step further, the State of California recently enacted an opt-in program for the permitting of renewable energy projects and related manufacturing and infrastructure developments that largely consolidates distributed permitting authorities in one agency—the California Energy Commission (“CEC”). Assembly Bill 205[xxviii] (“AB 205”), signed into law on June 30, 2022, emulates previous efforts by the state to streamline permitting and better contain the uncertainty associated with project litigation risk. Specifically, AB 205 expanded the CEC’s “one-stop” siting and permitting authority under the Warren-Alquist Act beyond 50+ megawatt (“MW”) thermal power plants by creating a new siting certification process for, among other things: solar photovoltaic (“PV”) and onshore wind projects capable of generating 50 or more MW; energy storage facilities with at least 200 MW hours of capacity; energy storage, wind system, and solar PV system manufacturing or assembly facilities requiring a capital investment of at least $250 million; and transmission lines from the wind, solar, or storage facilities.
Similar to the FAST-41 program, AB 205 requires an expedited timeline for “actions or proceedings brought to attack, review, set aside, void, or annul the certification of an environmental impact report or the issuance of the certification for any site and related facility . . . , including any potential appeals to the court of appeal or the Supreme Court . . . .”[xxix] More specifically, by December 31, 2023, the Judicial Council must adopt a rule of court outlining the procedures to ensure that, to the extent feasible, such matters are resolved within 270 days of filing the certified administrative record. AB 205 also sets limits on the timeline for environmental review (270 days after an application is deemed complete, subject to limited extensions) and requires a plan for timely consultation with other relevant permitting agencies. But unlike FAST-41, AB 205 supplants most other permitting agencies by establishing that the CEC’s project certification is the only permit/approval required, except for certain approvals by the California State Lands Commission, the California Coastal Commission (“CCC”), the San Francisco Bay Conservation and Development Commission (“BCDC”), the California State Water Resources Control Board (“SWRCB”) or the applicable regional water quality control boards, local air quality management districts, and the California Department of Toxic Substances Control (“DTSC”). In other words, the CEC will assume responsibility for evaluating the need for incidental take permits and lake and streambed alteration agreements, typically within the purview of the California Department of Fish and Wildlife, and for a variety of other approvals, including those required by local land use and zoning laws.
Admittedly, however, the enhanced benefits offered by the AB 205 program come at a steep cost. To qualify, developers must satisfy skilled construction workforce requirements; enter into mutual benefit agreements with “community-based organizations,” including social justice advocates, local government entities, and California Native American tribes; and pay a fee of $250,000 plus $500 per MW of gross generating capacity or per MW of gross energy storage capacity, as applicable, subject to a total cap of $750,000, plus an annual maintenance fee of $25,000 while the facility retains its certification.[xxx] Furthermore, although the CEC recently adopted emergency regulations to further define the application process and procedures for project review,[xxxi] stakeholders have identified several outstanding questions that will need to be resolved as the first projects make their way through the program.
Not every solar project is complex or controversial enough to require the formality of a streamlined process, but many are. Almost two decades into aggressive permitting and development of solar on a large scale in western states, areas blessed with superior insolation and ample land resources have erected a variety of barriers in response to being saddled with a disproportionate share of development burdens. In these contexts, solutions like the one offered by AB 205 can re-balance the process and keep permitting on track. Developers need to ensure that they fully understand the costs and benefits of participation and make an informed decision as to whether the program fits their project’s needs.
Making More Land Available for Projects
Programmatic solutions, like landscape level planning and consolidated permitting, present a comprehensive solution to overcome many obstacles at once. But sometimes the obstacles to development are very specific and rooted in the particular policies of a given jurisdiction. Spotting and addressing narrow, but regularly occurring, issues is another critical step in efforts to facilitate more approvals. One example of creative thinking on this front comes from California, where the Legislature recently re-enacted provisions that make it easier to transition unproductive and underproductive agricultural land to solar uses.
By way of background, the California Land Conservation Act of 1965 (“Williamson Act”) incentivizes conservation of agricultural land and open space by offering tax incentives in exchange for voluntary restrictive land use contracts that ensure the long-term maintenance of agricultural preserves.[xxxii] To ensure that the significant tax incentives offered under the Act are not thoughtlessly exploited for temporary gain, the Act imposes a restrictive process for cancelling or backing out of a contract. “A Williamson Act contract obligates the landowner to maintain the land as agricultural for 10 or more years . . . and each year the contract renews for an additional year, so that the use restrictions are always in place for the next nine to 10 years.”[xxxiii] When the landowner determines that the property subject to a contract might be put to better use in a non-agricultural capacity, the contracting party can elect to affirmatively not renew a contract, in which case the deferred property taxes will slowly phase back in until the contract terminates at the end its current contract term (typically, 10 years).[xxxiv] Alternatively, a city or county may cancel a contract after finding “either that the cancellation is consistent with the purpose of the Williamson Act, or that the cancellation is in the public interest.”[xxxv] A third and final option would be to put the property to a new use that is consistent with the Act and the terms of a particular contract. Such uses include use of the property for recreational purposes or as open space in accordance with Section 8 of Article XIII of the California Constitution—but not for renewable energy development.[xxxvi]
Senate Bill 1489,[xxxvii] signed into law on September 18, 2022, authorizes the parties to a Williamson Act contract to mutually agree to rescind the contract and replace it with a solar-use easement. A solar-use easement is “any right or interest acquired by a county or city, in perpetuity, for a term of years, or annually self-renewing . . . , in a parcel or parcels determined by the Department of Conservation . . . to be eligible, where the deed or other instrument granting the right or interest imposes restrictions that, through limitation of future use, will effectively restrict the use of the land to photovoltaic solar facilities . . . and any other incidental or subordinate [uses].”[xxxviii] Eligible properties include those where the DOC has determined soil quality, hydrological conditions, or other relevant factors now limit the land’s agricultural value. The landowner still must pay a rescission fee, but it is significantly reduced and the lengthy, uncertain and public process otherwise required to cancel such agreements does not apply.
Reviving the solar-use easement option to expand the use of Williamson Act properties eliminates significant procedural obstacles to solar development on large swaths of land that increasingly may no longer be suitable for agricultural uses in California. SB 1489 is thus one example of how legislative bodies can assess and redress unique circumstances that could needlessly interfere with and delay renewable energy development in a particular jurisdiction.
Outlook for 2023
With new tools in hand and under development, and significant financial incentives on the table for near term projects, 2023 could lay the groundwork for meaningful strides in renewable energy development. There will of course be new and unforeseen challenges. Among these, the Department of the Interior (including BLM) will need to grapple with provisions of the IRA that tie onshore renewable energy development to conventional (oil and gas) leasing.[xxxix] But with thoughtful planning, even these issues can be overcome.
[iv] Although the Solar PEIS also included a programmatic biological opinion, it was drafted in a way that still required project-specific take authorizations. See infra, fn. 19 (discussing the project-specific biological opinion for the Dry Lake SEZ).
[vi] 87 Fed. Reg. at 75,285 (quoting 43 U.S.C. § 3004(b)).
[viii] 87 Fed. Reg. at 75,286 (“[S]ince implementation of the Western Solar Plan, the majority of authorized solar developments on public land have occurred in variance areas, not SEZs”). Although in the aggregate, the 285,000 acres made available for development within SEZs sounds like a lot, those acres were allocated to over a dozen zones and included pending project applications. With a median size of only 5,873 acres, most SEZs could support only one or two utility-scale projects. Accounting for pending applications, the 5,717 developable acres in the Imperial East SEZ in California offered only 1,770 acres available for new development.
[x] 87 Fed. Reg. at 75,286.
[xii] Final Solar PEIS at 2-43 to 2-56.
[xix] USFWS, FINAL- Project-level Formal Consultations for Four Solar Energy Projects in the Dry Lake Solar Energy Zone, Clark County, Nevada (May 1, 2015), https://eplanning.blm.gov/public_projects/nepa/42099/58952/64098/Appendix_C_Biological_Opinion.pdf (“Dry Lake SEZ BiOp”); see also Karl Cates, Seth Feaster, Dennis Wamsted, Federal Land Agency Lags on Solar Development Approvals Across Southwest U.S., IEEFA (June 2020), p. 11 https://ieefa.org/wp-content/uploads/2020/06/Federal-Land-Agency-Lags-on-Solar-Development-Approvals-Across-SW-US_June-2020.pdf (IEEFA Report).
[xxii] Pub. L. 114-94, secs. 41001 et seq. (Dec. 4, 2015), codified at 42 U.S.C. §§ 4370m et seq.
[xxiv] 42 U.S.C. §§ 4321-4347.
[xxvi] 42 U.S.C. § 4370m-8(a).
[xxix] Cal. Public Resources Code, § 25545.13, subd. (c).
[xxx] Cal. Public Resources Code, §§ 25545.3.3; 25545.10, 25806. Whether intended or not, these requirements strike a balance between the removal of local permitting authority and expedited judicial review by preemptively addressing the concerns of stakeholders that frequently oppose or struggle to accept renewable projects. In this way, the program is self-validating and could be emulated in other contexts.
[xxxii] Cal. Govt. Code, §§ 51200 et seq.
[xxxiii]Save Panoche Valley v. San Benito County (2013) 217 Cal.App.4th 503, 516, quoting Friends of East Willits Valley v. County of Mendocino (2002) 101 Cal.App.4th 191.
[xxxiv] Id., citing Cal. Gov. Code, § 51245.
[xxxv] Id., citing Cal. Gov. Code, § 51282, subds. (a)(1)-(2).
[xxxvi] See Cal. Gov. Code, § 51201, subd. (d); 51252.
[xxxviii] Cal. Gov. Code, § 51190, subd. (c).
[xxxix] To grant a right-of-way for wind or solar development on federal lands, the Department of the Interior must have conducted an onshore lease sale within 120 days and the Department furthermore cannot issue a right-of-way for solar or wind development unless the number of acres offered for onshore oil and gas lease sales during the prior year equals or exceeds the lesser of (i) 2,000,000 acres or (ii) 50% of the acreage for which expressions of interest (“EOI”) have been submitted. The accounting to ensure compliance alone is so complicated that it warranted its own IM. (Implementation of Section 50265 in the Inflation Reduction Act for Expressions of Interest for Oil and Gas Lease Sales (IM 2023-006).)
