Despite thunderheads rising over anaerobic digestion (AD) and other renewable energy since the Trump Administration took office, there are silver linings. Though the U.S. Environmental Protection Agency’s Clean Power Plan (CPP) eventually may go away along with AD chances to sell carbon dioxide-related reductions to affected utilities, similar opportunities for AD projects likely will remain available.
Three categories of silver linings — environmental credits, tax credits and nutrient credit procurement — offer hope for AD project developers.

Silver Lining #1: Environmental Credits

Executive Orders
Executive Orders (EOs) can’t override existing law; they must be “consistent with law,” as recited by every Trump EO to date. This highlights the limits of actions like EO 13771 (“Reducing Regulation and Controlling Regulatory Costs,” Jan. 30) requiring two rules to be withdrawn for each new rule issued: if the Clean Air Act or Clean Water Act as interpreted by courts requires a rule, it’s not easy to see how that rule may be “withdrawn.” It also highlights the fact that EOs often don’t have immediate effects. They frequently declare goals, beginning processes that may or may not reach announced ends.
These principles apply in spades to the much debated EO 13783 (“Promoting Energy Independence and Economic Growth”) that President Trump signed with a flourish March 28, declaring he would dismantle the CPP, liberate fossil energy resources, reopen federal lands to mineral leases plus fracking, and bring back lost coal miner jobs.
A final rule like the CPP (developed over three years) only can be revoked or modified by the same arduous process required to issue it. Evidence must be collected; a record built; a proposed rule published for public comment; comments responded to; and a final rule developed that is supported by the entire rulemaking record — including the record for the previous rule. Moreover, when an agency attempts to shift course by retracting a regulation, it bears a heavier burden: it must show a court why it changed its mind. That’s an uphill slog which can take years to play out.
EOs In The Courts And The World
The CPP slog may be steeper. Last September the full U.S. Court of Appeals for the DC Circuit heard two days of oral argument on the CPP’s validity. Its 10-judge decision has been awaited since New Year’s. If it affirms the rule, a core rationale for EO-directed EPA review — that the CPP represents “unprecedented federal overreach” — will be undercut. Indeed, as of this writing the Court may proceed to affirm. Numerous states and other CPP supporters have opposed the Administration’s request to “suspend Court decision” while EPA reconsiders, noting that the case was heard 6 months ago, that it involves issues which will shape any agency reconsideration, and that “suspension” on request would amount to an impermissible indefinite injunction.
Even if the March 28 and similar EOs are accepted at face value, EPA Administrator Scott Pruitt may not be around to see them through. It’s no accident that political staff from fellow Oklahoman Sen. Inhofe’s office arrived with Pruitt at EPA. Inhofe is 83; his term ends in 2020. Observers believe Pruitt will declare for that seat, perhaps with Inhofe’s blessing. If so, he will have to start running around mid-2018. This means that even if Inhofe serves out his term, Pruitt would have only 18 months to oversee an agenda taking years to complete. If Inhofe retires early, the window would shrink.
The March 28 EO left undisturbed many programs important to biogas projects. For instance, it did not touch the AgStar program (encouraging AD); EPA’s landfill gas (LFG) emissions rules for municipal solid waste landfills (drivers for renewable electricity generation and compressed LFG vehicle fuels); the Clean Water Act’s thousands of waste-load allocations (drivers for AD and other nonpoint source runoff avoidance); or federal Renewable Fuel Standards (RPSs — drivers for renewable fuels and electric cars charged with power generated from them). Nor did it mention the December 2015 Paris Accords, which have been estimated to require $12 trillion in new global renewable energy investment — more of which would go to China and other nations if the U.S. “opts out.”
States, cities and companies already have begun to backfill against possible U.S. budget and policy retreats. Based largely on job growth and other economic benefits, Ohio and Illinois recently strengthened their RPSs. In late March the governors of California and New York jointly committed to exceed their states’ CPP reduction targets, listing multiple steps taken or underway. Several jurisdictions still plan to adopt “little CPPs.” Washington State has adopted RPS provisions that expressly grant AD and certain other projects double credits — for renewable electricity generation and direct reduction of greenhouse gas emissions. Meanwhile California and the western Climate Trust are pursuing mechanisms to assure such credits a floor price, following guarantees pioneered by the World Bank. And the nine-state Regional Greenhouse Gas Initiative (RGGI) is poised to lower its carbon dioxide emission caps below a 45 percent reduction adopted in 2014. All these steps should increase affected entities’ appetite for cost-effective reduction credits.
At the corporate level, energy hungry companies like Google and Amazon have standardized and signed long-term renewable power purchase agreements (PPAs) for millions of kilowatt-hours, creating templates for projects to bypass low-priced “wholesale rate” utility PPAs. Growing corporate adoption of quantified sustainability criteria by (e.g.) the Fortune 1000 should amplify such measures.
In short, given adverse Congressional reaction, the new Administration’s plan to slash operative EPA funding by over 40 percent — zeroing out (e.g.) climate-related activities, state assistance grants, and Chesapeake Bay restoration funds — seems dead on arrival. (“We make the budget up here,” one senior Republican appropriator tartly remarked.) But even if it isn’t, the prospect of such budget and staff cuts already is generating affirmative nonfederal responses.

Silver Lining #2: Tax Benefits

Tax Reform Risks
Similar resilience is emerging on the tax side. The prospect of “comprehensive tax reform” cutting corporate rates from 35 percent to around 20 percent has triggered fears that established AD benefits like annual production or lump-sum investment tax credits, along with “regular” accelerated depreciation and 50 percent “bonus depreciation,” will be back to help pay for those cuts.
It’s true that comprehensive tax reform could put these tax benefits at risk. It’s also true that while post-reform tax credits would retain their dollar-for-dollar value in reducing federal taxes, the overall tax credit market might take a hit because businesses’ “tax appetite” (their amount of taxable income after other adjustments) would decline. In addition, the attractiveness of depreciation deductions would be reduced, since fewer deductions may be needed by potential investors facing a 20 percent rather than 35 percent nominal rate.
Nevertheless, comprehensive tax reform seems increasingly unlikely. First, the last time Congress managed this feat was in 1986, when President Reagan cut a deal with Democratic House Speaker Tip O’Neill. That deal involved numerous concessions from each side of the political aisle. It also occurred when Congressional leadership had powerful levers to keep members in line. Neither factor seems to apply today.
Second, it’s difficult to map a reform path after the March collapse of the American Health Care Act (AHCA) legislation. As observers have noted, the House majority’s AHCA was more a tax than a health care bill: it would have generated up to $1 trillion in federal tax savings, largely by removing 14 million enrollees from Medicare by 2019. (Another 10 million eventually would have seen their federal health insurance subsidies disappear.) Those tax savings were a predicate for “reform” reductions in corporate tax rates, which AHCA savings partly would have paid for. AHCA savings also would have permitted passage of tax reform legislation under “reconciliation rules” allowing approval by a 51-49 Senate vote. Now 60 Senate votes seem needed.
Third, to secure 60 Senators, comprehensive tax reform must attract Democrats. But Senate and House Democrats already have committed to protect existing renewable energy tax benefits in exchange for their cooperation. That commitment almost certainly would come to include extending and expanding such credits, given House leaders’ default on their January 2016 promise to address related tax credit extensions. Once that obligation is called in, new extensions will show up at the table.
Thus the “tax reform” bottom line looks much like the one for EOs aimed at environment or energy rules: while both areas remain wild cards, there are deep splits within and beyond current Republican majorities, and protective backstops are being put in place. Partly for this reason, many believe the “tax reform” outcome may be (say) a 5 percent rate cut that the Administration can claim as a win. Even if “reform” is broader, the structure of current tax benefits will stay embedded in the Internal Revenue Code, providing a platform for extensions later on.
Expanded Tax Equity
Significantly, new tax equity entrants ranging from natural gas companies to small family offices have started to break national banks’ dominance of that financing market. It never has made much sense to allow Bank of America plus roughly a dozen cohorts to determine which U.S. projects get financed with favorable tax equity. The recent entrants offer new possibilities for projects that can’t meet big bank investment thresholds and acceptance criteria, or can’t live with the delays and transactions costs involved.
Existing Tax Benefits
Beyond this, AD developers should be aware that tax benefits they may believe “expired” still may be captured. For example, “regular” accelerated depreciation for renewable energy projects has no time limit or “sunset” provision, and 50 percent bonus depreciation did not disappear at the end of 2016 — it’s fully available for qualified property “placed in service” during 2017, then phases down to 40 percent of basis in 2018 and 30 percent in 2019 before expiring in 2020. Nor did production and investment tax credits for biomass-based electricity fully “expire” in 2016. Under “look back” clauses, projects that “began construction” in 2016 still may qualify, if (for instance) they’re completed in the next two to three years (see “Biomass-to-Electricity Tax Credits Extended,” January 2016).

Silver Lining #3: Nutrient Credits

The themes above are illustrated by what’s happened since BioCycle last looked at nutrient credit procurement proposals in Maryland and Pennsylvania (“Nutrient Credit Procurement Update,” February 2017).
To recap: the nutrient credit procurement concept seems simple but has large implications. Instead of seeking to restore impaired waters through costly further waste-load allocation reductions from (say) heavily regulated wastewater treatment plants, or from difficult-to-regulate rural septic discharges or urban storm water runoff, states would conduct competitive auctions to acquire sufficient “verified nutrient credit reductions” in any nonpoint source discharges anywhere in-state. Farmers and other potential low-cost credit sellers like AD projects would bid to sell 10-year streams of such credits. The state would directly purchase these credits based on cost and quality factors just as it buys other commodities, offering “advanced Best Management Practice (BMP)” projects and small BMP installers alike a financeable new revenue stream. Private money would have incentives to supercharge weak nutrient credit markets by financing verified credits for assured sale; direct state costs of subsidizing BMPs would be reduced through competing bids. The state could resell purchased credits to affected dischargers for their compliance, or retire them for equivalent environmental progress.
This approach raises significant implementation issues. Beyond how to deal with disruption effects on existing waste-load allocation programs and their stakeholders, these include when a credit will be considered “verified” (one answer: not so late as to preclude upfront project financing) and how to prevent small BMP-based credit sellers from being priced out of competitive bid processes (one answer: allow separate set-aside bids for small sellers’ participation).
Nevertheless, nutrient credit procurement has been accelerated by state budget shortfalls — and by its potential to reduce by over 50 percent the two states’ projected $13 billion costs of subsidizing sufficient nonpoint source BMPs. It has kept moving forward. Trade groups and other states have begun tracking it.
In Pennsylvania a behind-the-scenes push to enact statewide nutrient credit procurement this year now seems underway. Concerns that proposed usage fees for high volume water consumers will not raise enough funds to cover nutrient credit purchases have drawn replies that these fees will generate nearly $250 million/year. Notwithstanding those assurances, recent bills aim to validate use of a previous $400 million state tax-exempt bond issue, authorize similar use of a forthcoming $600 million issue, and allocate additional direct appropriations partly “to establish, with the . . . approval of the [PA Infrastructure Investment Authority], a water quality trading market that includes credits for reductions in nutrient, sediment and storm water.” The bills also state that “this chapter does not prohibit the use of funds allocated … for projects involving the purchase or trading of nutrient credits.” (See PA H.B. 503, introduced Feb. 15, 2017; PA S.B. 394, introduced Feb. 16, 2017) They have been followed by press statements to the effect that “Scarce Funding Raises Pennsylvania’s Interest in Competitive Bidding Alternative” and Pennsylvania “Chesapeake Bay Commission Members Spotlight Need for [State] Clean Water Fund,” signaling more to come.
Maryland still is tweaking draft authorizing legislation but remains committed to a pilot competitive bid process by which it would directly acquire at least $10 million/year of nonpoint source nutrient reduction credits. It has put resources behind that commitment, generating issue papers addressing detailed “Nutrient Credit Purchase Policies and Procedures” while upgrading an automated web platform for credit verification and sales. It plans to make its first credit purchases in FY 2018 (see www.mdnutrienttrading.com).
Such developments could provide AD projects what amount to guaranteed supplemental revenue streams. They’re not silver bullets. They won’t apply everywhere, be available next month, or erase permit or interconnection delays. They remain works in progress, and some states are moving in the opposite direction. But they’ve advanced on a bipartisan basis. So far, they seem to have legs.
Mike Levin, a BioCycle Contributing Editor, is managing member of the virtual law firm Michael H. Levin Law Group, PLLC (Washington DC) and a principal in NLGC, LLC and Carbon Finance Strategies LLC, which respectively focus on capital formation for renewable energy projects and the optimization / development of ground-mounted solar PV facilities. From 1979-1988 he was national Regulatory Reform Director at the U.S. EPA (Washington DC). This article is adapted from a joint presentation with John Marciano III (Akin, Gump, Hauer, Strauss & Feld, Washington DC) at BioCycle EAST COAST17 in April in Ellicott City, MD.