Energy policy development is complicated.   Recall that the electric industry has been regulated for more than 100 years and it remains highly regulated today, even with competitive markets.  Moreover, both the Federal government and States have roles to play in regulation.  Using examples, this article focuses on federal jurisdiction over “wholesale” electricity that flows across state lines and is not sold for direct consumption to end users.  Sales to end users, including authorization of competitive retail suppliers, is the exclusive jurisdiction of the states.

In the U.S., policy at the highest level is established by Acts of Congress and the President.  It is implemented by the executive branch including the Federal Energy Regulatory Commission (FERC) and the Department of Energy (DoE).  This policy establishes a framework for the tariffs that govern the use of the nation’s electric transmission grid.  It is useful to think of this framework as a “top down” process.  The owners and operators of the transmission grid, in turn, submit tariffs that comply with the law and policy to FERC for approval.  The development of tariffs is a “bottom up” process.

Three examples of the biggest orders to come out of FERC during President Obama’s administration include FERC Order 745, which required ISOs and RTOs to pay customer-side capacity resources such as demand response an equivalent value to what power plants and other supply-side resources earn; FERC Order 755, which required ISOs to create programs to reward “fast-responding” resources such as batteries for frequency regulation; and FERC Order 1000, which has set up a new regime for transmission operators and utilities to plan for, and pay for, regional grid investments.

The FERC has been instrumental in creating Regional Transmission Operators (RTOs) through policy decisions.  RTOs and Independent System Operators (ISOs) have largely eliminated the need to set wholesale electricity prices by a fixed tariff and instead allow prices to be established by markets.  The detailed implementation of electric policy is done at the RTO level. FERC’s decisions and orders apply to the tariffs of ISOs and RTOs that run much of the U.S. power grid. About 70 percent of the country is served by ISOs and RTOs, which fall under federal jurisdiction because they cross state lines.

The shift to RTOs has not eliminated the need for regulation of electricity.  Instead it has shifted the regulatory focus from setting prices to setting market rules.  The market rules are embodied in the RTO tariffs.  The FERC is responsible for approving the RTO tariffs.  The RTO tariffs are developed with varying degrees of stakeholder input, depending on the RTO itself.  The basic process follows the steps from stakeholder consideration to RTO and final review and approval by FERC using stakeholder input as shown below:

Each RTO handles stakeholder consideration differently. PJM Interconnection, for example, is the only RTO that is required to accept stakeholder recommendations as determined by a vote – at least on some issues.  Other RTOs simply consider the input of stakeholders and file what they think best.  There is little doubt that PJM has the most robust process. Most issues are addressed through a series of meetings that follow a set process.  The process is not unlike a government legislative body with committees, subcommittees, etc.  Often stakeholders reach consensus and many issues are resolved with no or nominal opposition.

Demand Response Policy Considerations

Perhaps one major exception to consensus pertains to issues involving capacity market design, including Demand Response (DR) participation.  On these issues, stakeholders are typically split between generation owners – including incumbent utilities – and load interests.  This is because any changes that reduce the opportunity for generation participation or revenue leads to reduced income for generators.  Such changes include enabling competitive resources such as DR and reductions in overall capacity requirements.

Conversely, stakeholders representing users of electricity oppose changes that increase costs without a credible probability of improving reliability.  As a result, most controversial issues have competing proposals.  Stakeholder votes are allocated in such a way that a required two-thirds’ supermajority (this applies to PJM) for approval of contested changes is difficult to reach.   A deadlocked stakeholder process allows PJM to file changes that may not have broad stakeholder support.  RTOs are non-profit entities without a commercial stake in market outcomes.  However, as organizations, PJM and other RTOs have an inherent bias toward “reliability” which often results in costly requirements for more resources, especially conventional generation.

Stakeholders that oppose an RTO filing have the opportunity to “protest” the tariff changes at FERC.  FERC need only determine that a filing is “just and reasonable”. While ostensibly the “just and reasonable” standard may include cost considerations, FERC, like PJM and other RTOs, also has a bias toward reliability and often will accept the RTO filing regardless of cost implications.

FERC Decisions and the Appeals Process

FERC decisions can be appealed to the federal courts on the basis non-compliance with the governing law, or an “arbitrary and capricious” decision.  Appeals Courts avoid ruling on the substance of a FERC ruling because this can place the Court in the position of creating laws and regulations.  Appeals Court decisions can be appealed to the Supreme Court as occurred in the high-profile case of FERC Order 745.  In particular, owners of conventional generation (the petitioners) opposed the Order because the treatment of demand response threatened their revenues and they took FERC to court.  The case hinged primarily on the issue of state versus federal jurisdiction (was the Order consistent with the Federal Power Act’s provisions designating retail rate setting as the exclusive jurisdiction of the states?).

In a major victory for the DR industry, the U.S. Supreme Court upheld FERC Order 745 via a 6-2 decision in January 2016, reversing a lower court opinion that found that it violated states’ jurisdiction over retail energy pricing, and dealing a blow to the utility group that brought the original lawsuit. DR providers and environmental groups supported FERC Order 745, noting that it has opened markets that have brought significant new demand-side capacity to the country’s grid operators for use in controlling the wholesale grid. Order 745 also helped reduce the need for fossil fuel-fired power and lowered overall electricity costs for consumers. But the underlying legal question behind the lawsuit — the bounds between federal and state jurisdiction over energy markets — could be modified by Acts of Congress.

You can see why the process of defining energy policy can be extremely complicated in practice. CPower takes a leadership role in shaping market transformation and regulatory reform, while working hard to maximize program benefits for our customers. It’s imperative that our Market Development team constantly stays abreast about regulatory processes as thought leaders in the DR community. These efforts enable us to provide services that take the complexity out of DR participation within the context of changing program rules, while optimizing your energy savings and earnings. This will become increasingly critical as energy markets continue to transform in the near future.

In 1992, I co-authored a chapter for the second edition of the Energy Management Handbook titled “Energy Management Control Systems.” In it I described, among other ideas and practices, the importance of software to facilitate the ongoing success of an efficient energy management control system (EMCS).

We’ve seen a host of innovation in the energy industry during the 25 years since I originally published this chapter, but the principles I introduced remain sound.

Today the combination of automated building controls and up-to-date software can lead to an organization earning significant revenue through demand response participation. The key to optimizing demand response and maximizing your earnings comes down to maintaining your building management system so it can become an efficient tool for demand response.

Building usage and programming logic should evolve in lockstep.
Commercial building usage and environments continuously change throughout their lifetime. Activities, processes, schedules, space configuration and populations vary from time to time. When Building Management Systems (BMS) are first installed, the software programing logic (i.e. control sequencing, set points, etc.) is configured for building usage at that time.

It is essential that programming logic be kept current with any changes in a building’s use and environment. Failure to do so can result in control sequences and set points being over ridden, which negates the benefits envisioned by the intended energy management strategies.

Certain components of a building management system require regular maintenance.
Occupancy schedules need to be managed on a day-to-day basis at buildings that have sporadic after-hours occupancy, i.e. schedule a specific zone to be occupied for specific hours on a specific day. HVAC control sequences, set points, and zonal environmental control need to be periodically adjusted to adapt to changing usage and conditions.

Crucial components are often overlooked.
BMS maintenance agreements are a discretionary cost. These agreements typically focus on system hardware, which is perceived to be more impactful on the budget than software maintenance.

However, inefficient energy management can have a significantly greater impact on the budget. Vendors provide training for in-house staff on minimal software maintenance, such as—for example—changing set points and scheduling after-hours events, during initial installation.

This maintenance feature disappears when trained staff move on; however, changes to control sequencing require the use of vendor software engineers which require additional expenditures. Building staff are alert to hardware maintenance needs but tend not to recognize when software maintenance is needed.

A well-maintained building management system is advantageous for optimized demand response.
Demand response can be implemented with minimal disruption to building environmental conditions and usage when BMS programming logic is maintained current, whereas building conditions and usage in a building with a poorly maintained system can become uncomfortable causing disruption to building activity when responding to demand response events.

Demand response payments provide a source of funding for incorporating demand response sequencing and software maintenance in the BMS vendor’s ongoing maintenance agreement. CPower can advise on demand response control logic specific to each ISO.

Maintaining BMS software current not only ensures energy savings intended when the system was first installed but also provides a solid platform to reap substantial energy cost offsets afforded by participating in demand response. CPower can work with building managers to optimize the financial benefits that can accrue from participating in demand response by interfacing with the BMS to automate demand response event action and enhance performance with minimal impact on building environment.

Contact us and to find out if your building’s BMS is in need of an update, or to learn how you can earn revenue with demand response optimized through optimization.