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What to expect in the upcoming PJM 2017/18 Demand Response season as well as a 2020/21 BRA preview.

By Dann Price | April 27, 2017

A changing weather landscape may bring early summer heat.
Although the recent La Nina season is officially over, we are experiencing a Mother Nature hangover as the 2017 Spring season has seen above normal temperatures.  As we transition from La Nina to El Nino, we should expect the hotter than normal temperatures to continue through the early part of the summer in the PJM region.  This should give way to cooler than normal late summer temperatures, which is opposite of what we saw during the 2016 summer season.  Warmer temperatures early in the season could yield some emergency issues, especially localized transmission concerns, so be prepared early in the 2017/18 Demand Response (DR) season.

As usual, CPower tends to schedule the PJM mandatory test event early in the summer to ensure customers will have time to be retested in the event they under-perform. CPower customers should be on the lookout for our test event messaging.

Capacity Performance Non-Summer M&V changes take effect in 2017/18.
As part of PJM’s filing to FERC in November 2016, the Non-Summer Measurement and Verification (M&V) methodology for Capacity Performance (CP) has been changed starting with the 2017/18 season.  The new Non-Summer M&V will be a Winter PLC construct.  The Winter PLC will be based on the customer’s highest load value between 6am-9pm during PJM’s 5 Winter Peak Days.  CP Demand Response customers will have separate Summer and Winter PLCs and FSLs for compliance purposes although the load reduction will be the same value for the entire season.

PJM ushers in a new era of Demand Response with the 2020/21 BRA.
In May of 2017 PJM will conduct its annual Base Residual Auction (BRA) for the 2020/21 season.  This year marks the first year that Demand Response can only be Capacity Performance.  Although there will be a mechanism for Summer seasonal DR resources to offer and clear as a CP aggregation, the overwhelming majority of DR that clears the BRA will be pure CP.

Prognosticators are reviewing the auction parameters and making predictions on clearing prices.  Although capacity resources are expected to exit the market under the new CP construct, PJM has also lowered their load forecast, causing many to believe the CP price could clear flat compared to last year.  There is, however, reason to believe that there could be significant premiums in EMAAC and COMED due to limited CP resources and transmission constraints.  One can never predict participant behaviors which is a variable that always makes price prediction an interesting but inexact science.

During the 2020/21 season, many traditional “summer only” DR customers will be forced to participate as annual resources in the CP program at potentially a lesser load drop commitment, while others may leave the market entirely.  CPower would like to work with all DR customers to maximize their participation and find ways to keep them in the program as either CP enrollments or part of a CP aggregation.

To learn more about PJM’s changing market or about how to be better prepared for potential grid instability this summer, contact Dann or any member of the CPower’s PJM Team.

Understanding kW vs kWh (and Meter Data) to Lower Your Utility Bills

By Michael Debelius | March 31, 2017

Many customers as well as my colleagues at CPower often ask me about the benefits of installing reliable metering equipment to access energy data in near real time. I typically respond with a handful of advantages (some listed below), but even before going there I find it useful to explain the full context about why these are important.

No discussion on the topic would be complete without a basic understanding of Demand (measured in kilowatts or kW) versus Consumption (measured in kilowatt hours or kWh). This is key to making the right choices when it comes to reducing energy costs, since electricity use for a commercial/industrial customer is typically billed and metered after taking at least these factors into consideration:

  1. Maximum kilowatt use (or kW demand) during a given period, typically in 15- or 30-minute intervals, and
  2. Total cumulative consumption (in kWh).

So, what’s the big deal between kW vs kWh?

An analogy using traditional light bulbs can help: Consider a single 100W bulb lit for ten hours versus ten 100W bulbs lit simultaneously for one hour. In both scenarios, the total cumulative “consumption” is 1,000 watt-hours (or 1 kWh). In the first case, however, the single light bulb will “demand” 100W or 0.1 kW from the electric supplier. Thus, the utility must have that 0.1 kW ready whenever that bulb is switched on. But note how the second scenario impacts the utility from a “demand” perspective. The electric supplier in this case must be ready to deliver 10x as much ‘capacity’ in response to the demand of the 10 light bulbs burning simultaneously!

Quite simply, here’s the difference. If these two scenarios reflected the behavior of two different customers, and if they were each billed for only their consumption, then both would get the same bill (for 1 kWh of energy used) even though the burden placed on the utility to meet each customer’s energy requirement is very different. Among other reasons, this is primarily why C&I (as opposed to residential) customers are typically metered and billed based on both their hourly “consumption” patterns and their peak “demand” for energy.

Demand-side energy management in near real time

CPower’s savvy demand response (DR) customers effectively leverage the energy they consume as a facility asset. Our diverse customer base covers mid- to large-sized electricity users in commercial, industrial, government and institutional organizations, including water/wastewater pumping and treatment facilities, colleges and universities, public agencies, office campuses, cold storage, data centers and a wide range of manufacturing facilities, to name just a few.

Many of our most active DR participants nationwide additionally leverage real-time metering for its clear advantages, including more visibility and control over load reductions as well as better overall energy management and sustainability benefits. The image above shows just two of the many views available to users via the CPower App (the graph on top shows 7-day hourly interval consumption while the one below shows demand on an intra-day 1-minute interval chart).

Key reasons to get real-time metering installed at your facility:

  • You can identify unusual or erratic equipment behavior to help avoid catastrophic failure. This is from a recent real-world example: Our team at CPower was working with the operations team for a large commercial real estate and property management firm, and picked up on unusual/erratic daytime usage patterns at one of their facilities. A look at the major systems of the building revealed that a chiller which had been recently serviced was to blame. Further investigation revealed that during a recent service call the chiller had been severely over-charged with refrigerant. Having a near real-time window into their energy usage enabled the facilities personnel to identify the unusual usage pattern, and proactively remedy a potential chiller issue that could have resulted in thousands of dollars in repair costs and possibly escalated their demand charges had it gone unnoticed.
  • Similarly, you may discover unusual, wasteful patterns or aberrations in overall facility energy usage as well as specific areas (e.g., an BAS reset inadvertently switches on all lights in an unoccupied underground parking garage at 2 AM).
  • Simplify on-site event planning (e.g., for K-12 schools or colleges) and/or production line scheduling (for manufacturing) with day-ahead pricing and forecasting at your fingertips.
  • Quickly and accurately substantiate the impact of your energy efficiency initiatives and sustainability programs (and share results with your team and management).
  • Avoid setting a new annual or monthly consumption peak, enabling you to manage demand charges for next year. Click to see more on Peak Demand Management in New England and Texas, for example.
  • Immediately evaluate the efficacy of (and fine tune as needed) new load curtailment strategies.
  • Further leverage your building automation systems and curtailment planning while minimizing impact on occupants (students, staff, employees, tenants, etc.).
  • Facilitate optimized participation in multiple DR programs, including Emergency Capacity, Economic DR, Ancillary Services, and more.
  • In addition to monitoring real-time utility load, several customers (i.e. a manufacturer of water valves and a supplier of military components) also view sub-meter data in the CPower App to provide them with a more granular, process-level picture of the energy usage in their facility.

The Bottom line

Real-time metering ultimately increases your DR earnings and savings to fund additional efficiency initiatives, while complementing your facility’s energy conservation and sustainability efforts. There are no out-of-pocket costs, since fees to install hardware, support software provisioning and enable data measurement & verification (M&V) are typically covered by DR program earnings.

By giving you near real-time visibility and analytics of your energy consumption, enhanced metering techniques provide more earnings and savings via greater control over your DR participation and greater awareness of electricity usage patterns (remember kW vs kWh!)

Surviving New EPA Rules and the Emergency Generator Regulatory Maze

By Ray Berkebile | February 28, 2017

Is your organization one of the thousands of commercial/industrial energy customers that use back-up generators (BUGs)?  Are they used as emergency generators (a.k.a., EGs or gensets) in demand response (DR) programs? If so, 2016 may have felt like an episode of the “Survivor” reality show, except instead of the usual cast of GenX characters and challenges you were unfortunately tasked with surviving a maze of ever-changing genset regulations.

Bad News, Good News:  The past year saw important changes regarding the use of stationary reciprocating internal combustion engines (RICE) that continue to evolve at the federal level as administered by the U.S. Environmental Protection Agency (EPA), which itself is in now in the midst of changes with newly-confirmed administrator Scott Pruitt at the helm. EPA rules provide that BUGs that are intended for emergency use when blackouts occur are exempt from reporting requirements and most emissions regulations.  The bad news is that EPA changes significantly restricted the circumstances where such generators can be compensated for operations while the grid is still up.  The good news is many such generators can achieve “non-emergency” status without equipment upgrades by meeting specific permitting and reporting requirements.

Bit of History – 50-hour Rule No Longer Applies: In early 2016, it was determined that EGs could potentially participate in DR programs under a different rule (referred to as the “50-hour rule”).  A coalition of DR providers including CPower took specific steps to clarify the applicability of the 50-hour rule with EPA as well as explore avenues to address concerns with the prior 100-hour rule as related to EG use for DR:

  1. We funded an extensive legal review on the 50-hour rule which outlined the case for allowing EGs to continue DR participation with this rule as a basis.
  2. We shared our well-documented analysis with EPA, who responded that they were not in agreement.
  3. While we believe the EPA’s interpretation is not aligned with the actual language in the regulation nor the structure of the electricity market, federal agencies such as EPA enjoy the latitude to interpret their regulations in any manner they deem appropriate.
  4. While CPower will continue to try to convince EPA that our well-documented position bears merit, all DR service providers clearly need to comply with EPA’s current interpretation.

Further confounding the situation is that a generator classified as “nonemergency” under federal regulations could be deemed “emergency” under state and/or local regulations. Recent examples include the Rule 222 that applies to permitting in New York; while California is moving from the traditional environmental permitting approach towards utility-based restrictions.

What This Means to You: As a DR participant with EGs, you should always be aware of the nuances defining EG assets that do not meet EPA’s interpretations of local requirements as well as the Federal Non-Emergency standard for DR curtailments. This applies even if your current DR service provider may advise you otherwise (especially regarding the use of EGs via the 50-hour rule). Any reputable vendor certainly should not expose you to any potential EPA violations or penalties. And if you indeed find out that EGs are not permitted for use in DR programs, make sure your service provider has an experienced engineering team who is willing to work with you to achieve the best possible alternative curtailment strategies.

On the Positive Side: Again, the good news is that in many instances, you can still use EGs to participate in DR programs and support grid reliability. A good curtailment service provider or DR aggregator should be able to assist clients with specific steps for permitting and retrofits so their engines can still participate wherever possible. At CPower, we have helped several clients with permitting so their engines can now effectively participate in emergency DR events to support the grid. Some of these services include:

  • Helping clients evaluate generation assets for permitting compliance at both the federal and state/local levels
  • Upgrading engines with aftermarket controls and/or automated DR (ADR) controls
  • Developing recommendations for adding load to optimize use of generators
  • Facilitating engine and generator upgrades (either working with a carefully vetted partner or customer-preferred vendor)

Bottom Line: As capacity costs increase, active DR participation becomes even more compelling and relevant. Changes in EPA regulations have impacted the ability of DR customers like you to use stationary emergency generators as part of your load reduction strategies.  Luckily, you can look to DR service providers to offer valuable “survival tips” that can bring this episode to a stable ending.

“Thanks to accurate guidance from CPower’s engineering team, our engines were successfully permitted for use in demand response by the state’s Department of Environment. Their in-depth knowledge and tenacity throughout the process clearly contributed to enabling our facilities’ continued participation in the 2017 DR performance season.” – Facilities Director at a large New England based manufacturing firm.

CPower takes a leadership role and shaping market transformation while advocating for our customers to help you navigate the regulatory maze and maximize DR program benefits. The result? Increased energy savings and earnings not just from optimized participation in Emergency DR, but also in non-emergency voluntary programs (like price based Economic DR). In some cases, you can also use your engines for peak-shaving to reduce capacity costs while maintaining compliance with environmental regulations.

Do you have a generator? Does it meet State and EPA guidelines? Are you leveraging it as a demand response revenue resource? Check out our Emergency Generator Decision Tree today to ensure you make the right EG permitting and compliance choices moving forward.

Energy Policy 101: How the Movement of Electrons is Regulated

By Bruce Campbell | December 12, 2016

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.

Hot Summer Ends Without Emergency Demand Response Events in PJM

By Dann Price | October 07, 2016

The 2016 PJM summer compliance season which runs from June through September has come to an end without a PJM-initiated emergency demand response (DR) event.  The first six months of the year were already one of the warmest on record. So, for many of us sweating it out across the northeast, it was no surprise that this summer produced several heat waves that pushed system peaks to their highest levels in recent years.  PJM’s top 5 system peaks (see table), reflect the summer’s weather and should be the Five Coincidental Peaks (5CP) that drive customers’ capacity charges through their Peak Load Contribution (PLC).  It is important to note that any load reductions during these hours may reduce your capacity charges for next summer.


When it came to actual demand response events, however, a different picture unfolded compared to prior years. For instance, the 2013 summer saw system peaks at similar levels and was one of the most active summers for demand response customers ever.  So you may ask: Why were no Emergency DR events called this summer, despite the heat and high system peaks? A few reasons come to mind:

  1. Some of it may be attributed to PJM’s new reliability product, Capacity Performance (CP), which debuted this delivery year and imposes greater availability requirements on generation;
  2. Some of it may be attributed to increased transmission efficiency;
  3. Also, flat or declining system peaks are starting to reflect the impact of energy efficiency regulations (the last system peak demand record was set in 2007); and finally
  4. Pure Luck? After all, the timing of several heat waves passing through the PJM territory coincided during weekends.

Whatever the primary reason(s), PJM Emergency DR customers should take pride in their commitment to be on standby to reduce load when called upon. Your ability to curtail electricity consumption when needed by the grid is a tremendous asset to maintaining system reliability and preventing potential blackouts/brownouts.

This doesn’t mean that PJM may not have a reliability issue beyond the summer as the program year does run through May 2017. Also, while the summer period yields the greatest risk of an emergency event, demand response customers that have committed to curtailments all year should continue to be prepared to perform and reduce load if/when needed to support grid reliability.

Moreover, with the transition to the new CP product, demand response is morphing into a year-round program. Customers can start participating in CP now to get themselves prepared for the coming changes and earn additional capacity revenue in the process. Many forward-thinking facility managers are already thinking about how they may be able to participate beyond the summer and are reviewing effective winter curtailment strategies.

CPower would like to take this time to thank all demand response customers for their commitment to PJM reliability this summer.  CPower customers can always review their load drop test and event performance in the CPower App and should be expecting summer performance reports and payments starting early November.

Last but not least, we always encourage all participants to stay tuned for earnings opportunities in other DR programs available. Many participants augment their demand response earnings from the capacity program via active participation in PJM’s voluntary programs such as (price based) economic demand response and (faster response) ancillary services such as synchronized reserves.

Please feel free to contact Dann or the CPower team if you have any questions. Our engineering team is happy to help you understand the nuances of participating in these programs and assist in optimizing your overall energy savings and earnings year round.

Why Sherlock Holmes Would Have Been a Great Energy Manager

By Kyle Harbaugh | April 04, 2016

Scotland Yard’s ace sleuth may not have intuitively known the finer points of a fixed price, index, or hybrid energy supply contract. He likely didn’t have the foresight to know which energy efficiency project will produce the best return on his investment. And, given that his heyday was about a century before the creation of the free energy markets, Sherlock Holmes probably didn’t have a clue about developing a load reduction strategy to maximize his demand response earnings.

What Sherlock Holmes did understand was the need to gather reliable data before making any important decisions. The same philosophy that worked for tracking villains in the 19th century also works for making energy decisions today. The more you know about your energy consumption, the better your decisions concerning your energy usage will be.

The best place to start gathering data is your utility bill (elementary, my dear energy manager). Your utility bill will give you an indication of how much energy you’ve consumed over the past month. If you have a consumption meter, you will see the total amount of kilowatt hours that have flowed over the entire period, typically a month. Larger customers will have an interval meter, which will measure their consumption in hourly or even 15 minute intervals.

The Smart Meter is essentially a 15-minute interval meter, but has a wireless connection that allows the utility to read it over-the-air. However, many utility smart meter implementations are configured to only read the meter once each day. Smart meters get us closer to real- time data, but not all the way there.

Why is real time data so important to unlocking the mysteries one must solve in creating an optimized energy strategy? In the words of Mr. Holmes, himself, “there is nothing like first-hand evidence.”

Real-time data provides not only evidence for understanding how you currently use energy, but also valuable clues for how you plan on using energy as part of your energy management strategy. Just as Sherlock Holmes used a magnifying glass to examine the details of his surrounding world, so too do you need a tool to monitor your energy usage in real- time.

Enter CPower.

CPower offers a complete demand response solution on your desktop or mobile device that allows you to see your facilities’ energy usage in real-time. The data is captured in one-minute intervals and then sent over a secure transport, which never touches your network. The data is then sent directly to you on your PC or smart phone.

Historical Usage in the CPower app
Energy management at your fingertips: The CPower App gives you the data to make informed energy management decisions.

CPower’s technology gives you the ability to observe rather than merely see and gives you the data you need to make smart decisions about your energy. The best part is that if you are a CPower Demand Response customer, the CPower App and its capabilities are part of the services we provide at no out-of-pocket cost to you.

Real- time energy data is at your fingertips with the CPower App. Take a peek at a video featuring the CPower team behind the technology explaining how the right info at the right time can make all the difference when making energy decisions.

The game is afoot!