PURPA projects become more difficult to finance

PURPA projects become more difficult to finance

October 07, 2019 | By Caileen Gamache in Houston

Independent cogeneration and small renewable energy projects known as “qualifying facilities” or “QFs” may lose key protections from merchant risks that they have relied on to help secure financing for the past 40 years if the Federal Energy Regulatory Commission has its way.

FERC proposed a number of changes in how it implements the Public Utility Regulatory Policies Act of 1978 on September 19. (For background, see “PJM Capacity, Grid Reliability and PURPA” in the August 2019 NewsWire.)

There are six main changes.

FERC would revoke the requirement that utilities offer QFs power purchase agreements with fixed prices.

It would release utilities from any obligation to purchase electricity from small solar and other renewable energy projects that are less than 20 megawatts but greater than
one megawatt in size.

It would reduce the amount of electricity utilities must purchase in states that allow retail customers to choose their electricity suppliers.

It would require developers to prove commercial viability and a financial commitment to construct before a utility is required to sign a PPA.

It would make it easier for people to challenge the QF status of a project. Utilities have no obligation to purchase electricity from any project unless the project is a QF.

Finally, FERC proposes to eliminate a “one-mile rule” that treats wind turbines or other facilities more than one mile apart as separate projects for purposes of the QF size limits. Affiliated projects that are between one and 10 miles apart may lose QF eligibility as a result.

The consequences for the independent power market are numerous.

Fixed prices

The Public Utility Regulatory Policies Act is a 1978 statute that gave birth to the independent power industry in the United States. Congress adopted it after the Arab oil embargo in the 1970s to create a market for electricity from two types of power projects: cogeneration facilities that produce two useful forms of energy — for example, steam and electricity — from a single fuel and small power projects under 80 megawatts in size that use renewable energy or waste fuels.

PURPA requires utilities to buy electricity from eligible projects — QFs — at the “avoided cost” the utility would pay to generate the electricity itself.

State utility regulators determine the avoided costs of utilities in their states.

Under current FERC precedent, a QF can choose whether it wants the utility’s avoided cost rate at the time the purchase obligation is created, or at the time the electricity is delivered. This accommodates different developer preferences. A developer primarily in the business of selling electricity normally selects the avoided cost at the time the commitment is made, because it translates to a PPA with a predictable revenue stream. In contrast, a developer who plans to sell primarily to a host customer, and thus already has a stable revenue stream, may be fine with the rate at the time of delivery to the extent it sells any excess electricity to the local utility during customer outages or other load reductions. The utility payment might even be in addition to continuing payments from the customer, depending upon the terms of the PPA.

FERC is proposing to eliminate the requirement that utilities enter into a PPA with a fixed avoided cost rate established at the outset.

Instead, states would be free to limit the avoided cost rate to a variable rate determined at the time electricity is delivered.

In wholesale markets, FERC suggests this could be the locational marginal price, called the LMP. In other markets, the avoided cost at the time of delivery could be the “competitive prices from liquid market hubs or calculated from a formula based on natural gas price indices and specified heat rates.” In other words, the avoided cost may simply be the price a QF would otherwise receive on a merchant basis. States would have latitude to invent other approaches for determining the avoided cost.

This proposal is probably the most troubling for developers who depend on third-party financing because it will make the revenue stream under PURPA contracts with utilities more unpredictable. There is debate about how important PURPA contracts remain in the current market. (See “PURPA and Solar” in the April 2017 NewsWire and “New Technologies and Old Issues Under PURPA” in the February 2018 NewsWire.)

Nevertheless, if adopted, the FERC proposal could trigger more growth in the financial hedge market by QFs seeking to put a floor under electricity prices to help with financing.

However, it may never become law. It is unreasonable to suggest the spot market price is a utility’s avoided cost required by the statute, because utilities have an obligation to procure electricity to serve load and they do not leave that obligation to market volatility. Although the proposal may be the most widely alarming among developers, it is also probably among the most likely to fail as contrary to law.

Size limit

Congress amended PURPA in 2005 to lighten the obligation for utilities to buy power from QFs above 20 megawatts in organized markets. Congress felt that independent generators in such areas have other options than forcing a utility to buy.

The wholesale purchase obligation does not apply in any area where FERC finds QFs have “nondiscriminatory access to” transmission, interconnection and wholesale energy markets. This includes a “meaningful opportunity” to sell “to buyers other than the utility to which the qualifying facility is interconnected.” QFs that are 20 megawatts or smaller in size enjoy a rebuttable presumption that they lack non-discriminatory access. FERC is now proposing to reduce this presumption for QFs using renewable energy from 20 megawatts to one megawatt.

The decrease would probably have the greatest impact on developers in the commercial and industrial — C&I — solar market. Lenders to such projects have taken comfort from the fact that the local utility has to buy the electricity in the event a C&I customer defaults. The project might still be able to sell into the wholesale market, but that usually requires significantly greater energy market sophistication and resources than selling to the local utility. Typically, the seller would be required to register with the market, post collateral to engage in market activities, make market settlement and scheduling arrangements, and possibly obtain transmission service or related products to hedge against transmission congestion. All of this adds to the risk profile of a project.

The proposal to release utilities from the obligation to purchase power from small solar and other renewable energy projects that are above one megawatt, but less than 20 megawatts, in size is limited to the organized wholesale markets operated by regional transmission organizations and independent system operators, but FERC wants comments on whether to test the concept more broadly.

States with retail choice

FERC is proposing to release utilities from any purchase obligation in states that allow retail competition.

In these “retail choice” states (comprised largely of northeastern states with a few outliers, and notably Texas), utilities’ obligations to purchase would be reduced to the same extent as their obligation to serve load is reduced by competitive energy suppliers.

If the utility has an obligation to provide electricity in the event a customer cannot obtain retail service — in other words, act as a “provider of last resort” — any PURPA contract the utility is required to sign would not have to run longer than the period it must act as a provider of last resort. Provider-of-last-resort requirements are often limited to one-year commitments.

Proving commercial viability

FERC is proposing to require QFs to demonstrate “commercial viability” and show a “financial commitment to construct” before a utility is required to sign a PPA with the project.

Each state would establish its own “objective and reasonable” criteria for evaluating whether the requirement is satisfied. FERC proposed examples of things developers might have to prove to show commercial viability, such as demonstrating site control, securing permits, filing an interconnection request, and “other similar, objective, reasonable criteria” that are not “unreasonably difficult.”

This could be a serious impediment to project development. It is normally economically imprudent for a developer to incur significant costs before closing on the financing and, in many instances, nearly impossible to obtain financing without a signed power contract.

One-mile rule

With limited exception, a renewable QF can be no larger than 80 megawatts in size, and smaller projects benefit from additional regulatory benefits.

A QF’s capacity is measured in the aggregate by combining renewable generating equipment such as geothermal turbines or solar arrays with any affiliated generation that uses the same fuel source located at the same “site.” Congress authorized FERC to determine what constitutes a “site.”

Existing FERC precedent establishes a bright-line “one-mile” rule. Assets within one mile of each other are treated as on the same site.

Utilities have complained for a long time that this one-mile rule is arbitrary and allows developers to abuse the QF regulations by strategically siting components of a single large project in a manner that allows each component to have status as a separate QF.

In response, FERC is proposing to fuzz the bright-line test by establishing a “rebuttable presumption” that QFs located between one and 10 miles apart are separate facilities.

Factors that might be considered in establishing whether assets should be aggregated include shared infrastructure, real estate ownership and access rights, interconnection agreements and shared interconnection facilities and whether the assets are owned by affiliated companies or controlled, operated or maintained by the same person, share financing, were placed in service or obtained offtake agreements within a year of each other, and whether the projects share engineering or procurement contracts. FERC wants comment on what additional factors should be considered.

As proposed, the change would only apply to new projects and any existing projects that have to recertify as QFs.

This last point is critical, because the obligation to recertify is triggered by changes in upstream ownership, as well as various other changes. If this rule is adopted, then QFs that depend upon the one-mile rule will need to think strategically before undertaking any changes that could require recertification. Power contracts signed under duress of PURPA usually require the project to maintain QF status.

The rule change might also affect distributed generation developers that rely upon the one-mile rule to claim they are exempted from QF filing requirements. This is a common practice in the rooftop solar market.

A project cannot be a QF unless and until it self certifies or applies for authorization from FERC if it is greater than one megawatt in size. The one megawatt is measured by aggregating with affiliated facilities at the same site. While it was relatively easy for companies to determine the total capacity of distributed generation projects located within one mile, the 10-mile radius will be more challenging (and, therefore, more challenging to prove regulatory compliance to potential portfolio lenders).

FERC has authority to determine what is a “site” under the plain language of the statute. Of all the new proposals, this one probably has the highest chance of being implemented.

Challenging QF status

There are two ways currently to become a QF. One is by making a formal FERC application. The other is by self-certifying.

A self-certification is effective upon filing.

Anyone who wants to challenge a self-certification must file a request for a declaratory order and pay a filing fee (currently $28,990).

Historically, this has meant that only very interested parties challenge QF self-certifications, such as the utility subject to the duty to sign a power contract.

FERC is proposing to make challenges easier by allowing protests (without payment of filing fees) to be submitted by any interested person within 30 days after a self-certification. Protesters would be required to cite a specific regulatory provision that the QF fails to satisfy. FERC would issue an order within 90 days after the protest is filed, subject to a possible extension of up to another 60 days.

The QF status would still be effective upon filing, but easing the burden to challenge the filing creates greater risk that the QF status will be revoked. If adopted, lenders will probably want to see QF self-certifications filed at least 180 days before energization to accommodate this new review period.

What next?

The proposals were issued by FERC in a 2-to-1 vote, with the lone Democrat saying in dissent that the proposed changes would “gut” PURPA. PURPA is a federal statute, and FERC only has authority to implement the statute as directed by Congress.

The plain language of PURPA directs FERC to issue rules “necessary to encourage cogeneration and small power production.” Given that one of the three FERC commissioners has already determined the new proposals are contrary to this directive, any final rules can be expected to be challenged in rehearing and on appeal to federal courts.

Congress may be incentivized by the attention to revise PURPA. It may be months to years before the final outcome and industry impact is known. Even if none of the proposals is ultimately adopted, FERC has created regulatory uncertainty that will have an immediate effect on project development and financing.

We expect that any rule changes will honor existing PURPA contracts for the duration of their terms, but their individual provisions will need to be examined closely. Some QF PPAs include the ability of utility buyers to terminate the contract in the event of a regulatory change to the purchase obligation or if the seller is no longer a QF.