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A Federal Energy Regulatory Commission order in mid-April made significant changes in how power plants of more than 20 megawatts in size can connect in the future to the utility grid.
The FERC order is Order No. 845.
Most utilities and grid operators that own or operate parts of the US transmission grid will have to revise their interconnection procedures and amend the form of large generator interconnection agreement or “LGIA” they use.
This includes grid operators like regional transmission organizations — called “RTOs” — and independent system operators — called “ISOs” — as well as individual utilities outside RTO or ISO footprints. There are limited exceptions for state and other government entities. Grid owners or operators that are not subject to FERC regulation because they are not engaged in interstate commerce, but that want reciprocity with the regulated parts of the grid, will also need to comply.
The current process for connecting large power plants to the grid can be slow, unpredictable and costly, and it can ultimately sink a project when material contracts and financing opportunities are contingent on blown development deadlines.
The process is also a challenge at the back end of construction of renewable energy projects, since most such projects in the United States face deadlines to be in service to qualify for federal tax credits, and they cannot be in service before they are interconnected and in a position to get their electricity to market.
Order No. 845 was largely driven by developer complaints about lack of transparency and control over the interconnection process, including “systemic inefficiencies and discriminatory practices” reported by the American Wind Energy Association.
The order will affect the interconnection process for developers in eight key ways.
Under current procedures, project developers generally have the option to build interconnection facilities and network upgrades — and convey them to the grid — only if the grid operator or owner determines it cannot complete construction by the in-service, initial synchronization, and commercial operation dates requested by the developer. The grid operator or owner is required to use “reasonable efforts” to stay on schedule, which is a difficult standard to judge and enforce. With limited exceptions, there is generally scant recourse for costly delays.
Moreover, the project developer is required to pay all actual construction costs the grid incurs, even if they exceed cost estimates. There is little incentive for the grid operator or owner to find least-cost construction options.
Order No. 845 allows a project developer to take over design and construction of the intertie and any stand-alone network upgrades for a project irrespective of the grid operator or owner’s capabilities, provided there are no conflicting state or local prohibitions. This will allow developers to have more control over the timing and costs of interconnection.
Certain elements remain in the grid operator’s court. Network upgrades that are required for multiple projects, rather than those that “stand alone” for the use of a specific project, must be constructed by the grid owner. The grid owner (and, where different, operator) will also retain oversight over the design, procurement and construction activities of any project developer that chooses the option to build.
A new power project is studied and interconnected as if it will operate at full capacity at all times.
The process ignores the reality that most solar facilities do not operate at night, a peaker unit may operate only on certain days at various times of the year, and wind facilities rarely have output equivalent to the aggregate capacity of each wind turbine.
This means the grid can often handle significantly higher levels of capacity than actually used. Order No. 845 frees this trapped resource by requiring grid operators and owners to permit a new project to use the “surplus interconnection service” for itself, an affiliate or for sale to a third party of its choice at the same interconnection point.
The surplus service will be tied to the original project’s LGIA, and the original project may dictate the amount, time and duration, and other details of use of surplus capacity. If the original project’s LGIA is terminated for any reason, then the surplus service will terminate.
If the original power plant is retired from service, then the associated surplus service will expire, with one limited exception to account for unexpected early retirements (in which case the surplus service still must terminate within a year).
This will make financing projects that rely on surplus service tricky, since they will be exposed to risk that the original project will default on obligations under its interconnection agreement or be retired from service.
An obvious opportunity for existing project owners is the addition of energy storage to use excess interconnection service. Tweeting on the heels of the order, Jason Burwen, vice president for policy at the Energy Storage Association, said the co-location of storage with existing power plants could accelerate soon after grid operators and owners adopt these revisions later this year.
Although the total generating capacity at the point of interconnection may increase, the total combined output at the point of interconnection cannot exceed the maximum level allowed under the interconnection agreement for the original project. Grid owners and operators must develop an “expedited process” for transferring surplus interconnection service. This may include, for example, reliability-related studies to confirm that the combination of the original and surplus interconnection does not require new network upgrades. The process must be separate from the interconnection queue. An agreement among the original project, the surplus customer and the grid will be necessary.
As a complement to the ability of projects to use surplus interconnection service, Order No. 845 also allows new projects to request interconnection service at levels below total project capacity.
This will help projects reduce interconnection costs previously incurred for unneeded service.
AWEA commented that this will be especially helpful to large wind projects because collector system losses often result in a situation where the maximum real power output from a project is materially lower than the aggregate capacity of individual turbines.
Another big winner is energy storage, as it may be combined with a variable resource — like a wind or solar project — to extend production time without increasing total capacity. A 40-megawatt solar plus 20-megawatt storage project may be studied at 40 megawatts rather than 60 megawatts, which could streamline studies and reduce overall interconnection time and costs.
Any project that takes advantage of the option to request less-than-full capacity service will be required to develop controls to ensure the project does not export to the grid more output than its service level permits. Grid operators and owners are authorized to adopt enforcement mechanisms, including penalties, for projects that violate these limits. The risk of such penalties will have to be added to diligence checklists.
A project may be able to interconnect under the new rules before the full interconnection process has been completed for the project.
Grid operators and owners will be required to maintain and periodically — at their discretion — update studies to determine the level of capacity that is available for provisional interconnection on the grid. Any project can request provisional interconnection service to use this capacity, but higher-queued projects will have priority.
If updated studies are required to confirm the available maximum provisional interconnection service available for an interested project, then the project will be required to pay for such studies. FERC anticipates the studies will be streamlined, as they will be based in part on the results of other available studies.
This could go a long way to addressing the issues that wind projects will face in late 2020 as they rush toward that deadline to be placed in service to qualify for federal production tax credits at the full rate. Solar developers will face a similar crunch at the end of 2023 to qualify for investment tax credits at the full 30% rate.
Grid operators and owners will have to come up with forms of “provisional large generator interconnection agreements” for use with projects receiving provisional interconnection service while the projects are still going through the full interconnection process.
Projects must assume all risk related to changes between the provisional service and the permanent service, including cost responsibility for upgrades, interconnection facilities, system protection facilities and output limits that arise during the full study process. If a project can manage such risks, then provisional service will allow the project to start earning revenue earlier than would otherwise be possible.
Developers must make significant decisions about project location, size, technology, interconnection points and development timing when submitting an interconnection request.
Although grid practices vary in different parts of the country, these decisions often must be made without the benefit of data necessary to appreciate how the request will be evaluated. A design change with minor commercial impact could significantly affect the interconnection process and costs. And when a project developer is surprised by unexpectedly high costs, there is little evidence available to confirm accuracy or appropriateness so that the developer can push back.
Order No. 845 directs each grid operator to maintain on its OASIS site or a password-protected website the following: base power flow, short circuit and stability databases, including all underlying assumptions, and contingency list, network models and underlying assumptions reasonably representing those used during the most recent interconnection study and representing current system conditions, and a list of all generation and transmission projects. The grid can require confidentiality agreements for commercially sensitive information or critical energy infrastructure information.
Standards for what information must be available should help “level the playing field” for developers in different regions.
They will help developers in regions where information is historically limited make more informed decisions and help keep projects that are not viable from entering the queue, and reduce the number of queue withdrawals, the need for re-studies and other compensating measures. This, in turn, should make the interconnection queue process more streamlined for the benefit of both developers and grid operators.
FERC currently requires grid operators and owners to identify the unbuilt interconnection facilities and network upgrades that they are assuming will have been completed by the in-service date a new project is requesting.
If these “contingent facilities” are not, in fact, timely completed, it could delay a project and necessitate re-studies and cause significant cost increases.
Under Order No. 845, the grid operator must divulge its method for identifying contingent facilities, and explain why each specific contingent facility was identified and how it will affect the new project seeking interconnection.
This information must be provided at the close of the system impact study phase. Upon request, the grid operator must also provide the project developer with an estimate of interconnection costs and in-service dates for each contingent facility, provided the information is readily available and not commercially sensitive.
This proposal was widely supported and is expected to allow developers to better assess risk to proposed new projects and allow them to make earlier, more informed decisions about whether to withdraw from the interconnection queue.
FERC declined to impose a standard method for identifying contingent facilities, declaring that “it is not clear a single method would apply across different queue types and footprints,” but it left open the possibility that harmonization may be appropriate in the future.
FERC broadened how it defines “generating facility” to include a battery or other storage device. The term now includes “a device for the production and/or storage for later injection of electricity.”
This should make interconnection easier for standalone storage facilities and also make it easier to add batteries to existing or new power plants.
Many grid operators already permit owners of storage facilities to request interconnection service as a generation resource. FERC previously adopted a similar definition in its small generator interconnection agreement and procedures that applies to facilities as large as 20 megawatts in size in Order No. 792 in 2013.
The latest revision for larger facilities provides parity among grid operators and project sizes by allowing storage to connect to the grid using the same large generator interconnection procedures as traditional power plants.
FERC clarified that this does not mean that an energy storage facility must only operate as a generating resource and reaffirmed prior findings that energy storage may function as a transmission asset.
Grid operators assess proposed changes to pending interconnection requests to determine whether the changes are a “material modification,” meaning whether they would materially affect the cost or timing of projects later in the interconnection queue.
If a proposed change is a material modification, then the project developer must either forgo the change or forfeit its queue position and start over.
The analysis is susceptible to discretion. FERC determined proposed changes in project technology are particularly vulnerable to inconsistent evaluation.
In an effort to promote transparency and efficiency, and encourage technological innovation, Order No. 845 directs grid operators to adopt a “technological change procedure” for assessing whether proposed technology changes to pending interconnection requests are a material modification of the original request.
The procedures must describe how a developer should prepare and submit a technological change request. FERC explained that the developer must demonstrate that the technological change will result in electrical performance that is “equal to or better than” the performance prior to the change, meaning that the change will not degrade the electrical characteristics of the generating equipment. The developer must also show that the change will not increase the requested interconnection service and that it will not cause any reliability concerns by demonstrating it would not affect the short-circuit capability limit, steady-state thermal and voltage limits, or dynamic system stability and response of the grid.
The procedures must also specify conditions under which the request would require studies. If a study is required, then the project developer will be required to post a deposit and pay for the study. The default deposit is $10,000, but grid operators may propose alternative amounts. The grid operator must complete any necessary studies as soon as practical, but not later than 30 days after the developer submits a proposed change.
Grid operators must also provide lists of “permissible technological advancements” that are not material modifications by definition.
The lists are not expected to include changes in generation technology or fuel type because these alter electrical characteristics in such a manner as to require studies in most cases to determine whether they are material.
Order No. 845 is effective on July 23, 2018.
With limited exceptions, grid operators are required to submit compliance filings that either revise their tariffs to comply with the order or make a showing their tariffs are consistent with or superior to the order’s requirements.
The current compliance deadline is August 7, 2018, but extensions to as late as November 5, 2018 have been requested.
Several grid operators or owners asked FERC for clarification and a rehearing of the order. These requests remain pending. Judging by past practice, FERC will probably grant a rehearing and may tweak certain compliance requirements, while reaffirming the broad concepts and the overall order.
These measures could make the difference between small and medium businesses closing permanently, or being able to ride out the COVID–19 storm.
The COVID-19 pandemic has prompted US lawmakers to act by passing a historic economic stimulus program for businesses.