OFAC revokes so-called U-turn authorization for Cuba-related financial transactions
OFAC published a final rule that modifies the Cuban Assets Control Regulations to revoke the so-called "U-turn" authorization.
After nearly 40 years with wide-ranging effects on the US electric utility industry, the Public Utilities Regulatory Policies Act — called “PURPA” — has resurfaced as a prime mover for renewables development in some parts of the country.
This has refocused stakeholders on historically contentious features of the law that have been amplified under recent market conditions.
PURPA has required utilities since 1978 to purchase power from small independent electricity generators at the “avoided cost” the utility would spend to generate the electricity itself. Utility avoided costs are typically based on fossil fuel technologies.
For much of its history, PURPA has been largely insignificant for renewables, which have not been viable at avoided cost pricing (even with tax incentives). For that reason, renewables have mostly been developed under renewable portfolio standard or “RPS” regimes, with renewable energy credits or “RECs” as further uplift on the value of their output. However, the US Energy Information Administration reports that the levelized cost of renewables will soon trend below avoided costs nationally. The cost convergence is more dramatic in regions with high renewable resources. Renewables developers are thus flocking to establish projects as qualifying facilities or “QFs” under PURPA and to enter into avoided cost power purchase agreements, where such contracts are available.
Virtually all net growth in QF generating capacity over the last 10 years has come from renewables (per a Brattle compilation of public data).
Net growth in QF generating capacity over the last five years has come principally from solar. Renewable QFs have comprised about 16% of total wind and solar development over that time.
The entry of renewable QFs has been concentrated in states where PURPA continues fully in force, meaning states not served by competitive wholesale electricity markets. Renewable QFs have come on line even in states with alternative incentive mechanisms, such as RPS regimes. In some cases, this reflects RPS targets that have already been met and thus generate low REC prices. However, even in states where RPS targets remain to be achieved, renewable QFs may still make economic sense, particularly where avoided-cost contracts are more attractive than PPAs won in competition with other lower-cost renewables.
Renewables’ increasing competitiveness has led to perceived oversaturation of renewable QFs in certain utility systems. For example, new QFs constitute 18% of the total current capacity in North Carolina, 26% in Utah, and 24% in Montana.
The concerns include disruption from stepped up volumes of intermittent resources, requirements for new transmission lines and other upgrades, and over-supply of electricity priced at avoided cost formulations higher than market prices. Not least among the utility concerns is that under current conditions of low load growth, new QFs may now be displacing existing assets (by contrast to the original premise of avoided costs).
Recent developments echo perennial debates over PURPA since its inception.
Project developers, purchasing utilities and regulators have negotiated hard over numerous interactive issues. Key among these are 1) QF eligibility criteria, 2) defining avoided costs and 3) equitable PPA terms. As renewable QFs have become more cost competitive, these issues have only become more acute.
Starting with QF eligibility, importantly, QF PPAs are not bound by any “rationing” based on utility demand requirements, but instead by willingness to supply at the stated avoided-cost price.
Over-subscription could be a problem, long before renewables became as competitive as they are today, such as the case of “standard offer 4” contracts in California in the 1980s. As a potential bounding mechanism, states began to experiment with competitive bidding for QFs in the 1990s. Such auctions were superseded by the development of wholesale markets for energy and capacity, which created alternative outlets for generators previously confined to PURPA.
While it may have been manageable to have QFs rationed by price alone when QFs bore some resemblance to utility-avoided generation, this delicate balance has now been disrupted by lower-cost renewable QFs. This has drawn much attention to parsing eligibility criteria, including project size, technology and development status. Competitive bidding is coming into vogue again.
How to define avoided cost has been a perennial problem. The regulators have struggled with administrative methods of estimating and setting long-term avoided costs, which inevitably stray from actual market costs. While these differentials were originally expected to offset each other over time, in practice, actual costs have continually (and dramatically) dropped below long-term avoided costs estimates.
Avoided costs have never been straightforward to calculate, but recent changes in market conditions and the regulatory landscape have made long-run avoided costs much more difficult to compute with an appropriate degree of precision or confidence. Variables such as projected fuel prices, outlooks for peak-demand growth, retirement of existing resources, and future prices for alternative market purchases all factor into complete avoided-cost estimation. These parameters are becoming less certain in an industry evolving toward intermittent and distributed resources, accompanied by new technologies such as storage, and changing regulatory paradigms.
The rapid penetration of renewable QFs themselves makes both the avoided energy and capacity value much more difficult to forecast. These resources shift the supply curve to the right, reducing marginal energy costs. At the same time, while they provide some capacity benefit to the extent available on system peak, they also tend to create a wealth of reserves on the system and they eventually can push the system peak out to hours when they cannot perform. Thus, their long-term avoided costs are anything but static or stable.
How to reach equitable PPA terms is another challenge. In the realm of PPAs, FERC has historically interpreted PURPA to require some degree of “certainty with regard to return on investment” in QFs and thus that PPAs “should be long enough to allow QFs reasonable opportunities to attract capital from potential investors.”
FERC has not translated this statutory goal into a specific number of years. In the early implementation of PURPA, it could mean as long as life-of-asset, but that was clearly more than was needed to support financing. It also meant that QF generators often bore little risk despite participating in competitive markets, and they were not dispatched efficiently in relation to other generation sources.
Today, PPA terms form an ever more contested issue. Utilities may seek short-term PPAs pending fixes to the more fundamental issues of QF eligibility and avoided costs. Also, contractual terms sufficient to attract capital have a different profile for renewables than for fossil-fuel QFs. Not least, they are more sensitive to recent events such as passage of the new tax law in 2017 and the imposition of tariffs on imported solar panels.
PURPA was enacted at a time of heavy reliance on imported fuels, high load growth, and utility dominance of the electric power industry. Accordingly, its original mission was to promote energy conservation and encourage deployment of eligible small generators as alternatives to utility resources, where small generators were cost effective.
Among other obligations, the original law and the subsequent FERC regulations required all electric utilities to purchase power produced by QFs at the utility’s full avoided cost of energy and capacity. A QF can be either a cogeneration facility (with no size limit) or a “small power production facility” (with an 80-MW size limit) using biomass, waste, wind, solar or hydro to produce power.
PURPA aims to encourage the development of QFs through the must-purchase requirement for utilities. Among other things, the law provides that QFs have the option to “provide energy or capacity pursuant to a legally enforceable obligation” of the purchasing utility.
The mandate to purchase energy and capacity offered by QFs is coupled with the requirement that purchase prices reflect the utility’s avoided cost, meaning the “incremental cost to the utility of alternative electric energy,” or “the cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small power producer, such utility would generate or purchase from another source.”
By definition, determining avoided cost requires conducting a but-for assessment.
A variety of methodologies have been adopted over the years.
In its simplest form, avoided cost has been determined assuming that a QF displaces the utility’s next planned generating unit (the “proxy unit” approach).
A more sophisticated approach assumes that instead of displacing a particular generating unit, a QF allows the utility to reduce the marginal generation on its system at any given time, saving the cost of building a combustion turbine of the same size as the QF (the “peaker” approach).
The most elaborate approach (the “differential revenue requirement” method) consists of modeling two system-wide scenarios, with and without the QF in question. The difference in revenue requirement is then attributed to the QF’s avoided cost.
Avoided costs have also been determined with reference to fuel indices and, sparingly, in competitive auction processes.
Typically, at the time of instituting PURPA, marginal generation probably would have been defined based on a small combustion turbine similar to most PURPA plants themselves. Therefore, PURPA and the subsequent FERC regulations essentially aimed to ensure a level playing field, enabling the QFs to sell their power to a utility at prices reflecting the utility’s incremental cost of procuring the same power from owned or purchased generation.
In PURPA’s first incarnation through 2005, QF installations grew by more than 8% a year, largely dominated by fossil cogeneration technologies.
The Energy Policy Act of 2005 modified the must-purchase obligation to exempt utilities from entering into new contracts with QFs that have nondiscriminatory access to competitive markets (mainly regions covered by regional transmission organizations, or RTOs) to sell their power. FERC later created a rebuttable presumption in its Order No. 688 that QFs larger than 20 MW have non-discriminatory access to the markets operated by five RTOs: PJM, Midwest ISO, ISO-New England, NYISO and ERCOT. With respect to CAISO and SPP, FERC indicated that these markets did not satisfy all requirements to qualify as providing non-discriminatory access to independent generators since they did not have day-ahead markets as of the time that Order No. 688 was issued. Now both CAISO and SPP are operating day-ahead markets, and hence may qualify as providing fully non-discriminatory access. Therefore, unless determined otherwise, the utilities’ must-purchase obligation has been limited in the RTO regions to smaller QFs of up to 20 MW.
Notwithstanding that PURPA continued to operate per its original terms in non-RTO regions, growth in new QF installations was sharply curtailed after 2005, to less than 1% annually through 2010. Since then, power markets have undergone dramatic changes. In particular, the cost of solar and wind resources has declined toward levels competitive with fossil-fuel generation, leading to renewed growth in renewable QFs after 2010.
Improvements in renewable costs and performance have been dramatic in recent years, for solar in particular. This is, of course, concentrated in regions with abundant renewable resources.
However, even on a national basis, EIA recently forecast the levelized cost of energy or LCOE for photovoltaic solar (including subsidies) as declining at a pace of approximately 17% per year, to achieve parity with the corresponding levelized avoided costs of energy or LACE by 2022.
For the WECC, SPP and SERC regions, EIA forecast a solar LCOE of $5 to $10 a megawatt hour below the corresponding LACE by 2022.
EIA forecasts a similar pattern for wind, with an LCOE $5 to $15 a megawatt hour below LACE in WECC, SPP and MRO by 2022. If anything, EIA’s outlook is conservative, and PPA rates are being reported at even lower levels.
As of July 2017, the total inventory of existing QFs in the US was approximately 90,000 megawatts, 70,000 megawatts of which remained thermal generation. The 20,000 megawatts of existing renewable QFs largely came on line in the last 10 years.
Roughly 24,000 megawatts of QFs are under development, predominantly solar, in non-RTO regions where PURPA continues in force. These projects are largely concentrated in several states. North Carolina (5,900 MW) and South Carolina (2,300 MW) lead the pack, followed by the western states of Utah (2,400 MW), Oregon (2,900 MW), Colorado (1,400 MW) and Montana (1,500 MW). This geographic concentration is additionally driven by a combination of favorable project economics (costs relative to the avoided cost of energy and capacity), state incentives for new solar generation (RPS carve-out for solar targets, tax credits and property tax exemptions) and, to date, state policies on QF contracting terms.
The issues are playing out in diverse forums.
Individual states are on the front lines, since PURPA leaves much latitude to individual state utility commissions for interpreting and implementing regulations written by FERC. States are grappling independently with criteria for establishing legally enforceable obligations, definitions of avoided cost and minimum PPA terms.
North Carolina, where PURPA’s resurgence has been most pronounced, offers a potential harbinger of development to come. Utilities there have faced dramatic increases in the volume of renewable power they are obligated to buy under PURPA. In the utilities’ view, the pacing of these new contracts has threatened to increase their costs and disrupt their systems. In response, utilities and renewable energy developers agreed jointly to support legislation that resolves the issues for the time being. In July 2017, the Competitive Energy Solutions for North Carolina Act (or HB 589) codified an alternative to PURPA-based implementation to reflect current market realities. Among other things, HB 589 mandates competitive procurement of a fixed amount of renewable capacity over a 45-month period.
Other jurisdictions in affected regions are seeking solutions too. Colorado has effectively folded its utilities’ PURPA obligations into the state’s electric resource planning process, which means QFs participate in a competitive bid process. Regulators in Utah, Montana and Idaho, meanwhile, have sought material reductions in the length of QF PPAs.
These state initiatives remain vulnerable to challenge for not comporting with federally established guidelines. At the federal level, FERC held a technical conference on PURPA in 2016 in which many of the law’s premises were reexamined, including the mandatory purchase obligation and determining avoided costs.
As a result of the conference, FERC invited comments on minimum standards for PURPA purchase contracts and the practice by QF developers of disaggregating projects to remain under the 80-MW size limit under the protection of a one-mile rule that wind turbines and solar arrays that are more than a mile apart are not the same project. Numerous utilities and independent power developers have weighed in, as well as the National Association of Regulatory Commissioners. Comments remain under consideration by FERC.
In the meantime, the legislative wheels are also turning. The House Energy and Commerce Committee held hearings on PURPA reform in September 2017 and January 2018. The January hearing was in response to new legislation introduced in November 2017. H.R. 4476, the PURPA Modernization Act of 2017, calls for waiving a utility’s mandatory purchase obligation if it conducts a competitive resource procurement process under an integrated resource plan (both of which would require approval by state regulators), or if the relevant state commission determines no need for capacity. More generally, the proposed legislation would also limit utilities’ must-purchase obligations to QFs below 2.5 MW in size (down from 20), and seek to address the disaggregation issue identified in the FERC technical conference.
It remains to be seen how persistent the proliferation of renewable QFs will be. Renewable economics suffered marginal setbacks as a result of the recent change in tax law and associated contraction in tax appetite as well as the 30% tariff recently imposed on imported solar panels.
Still, for the time being, renewables have placed a new urgency on resolving old issues raised by PURPA. ¥
OFAC published a final rule that modifies the Cuban Assets Control Regulations to revoke the so-called "U-turn" authorization.
On 5 September 2019, Professor John McMillan AO’s Final Report (Report) on the operation of the Narcotic Drugs Act 1967 (ND Act) was tabled in Parliament. Section 26A of the ND Act required the Minster to cause a review of the operation of the ND Act to be undertaken.