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ERCOT’s Capacity Reserve is Dropping. Here’s What Your Business Should Know.

November 30, 2017

The Electric Reliability Council of Texas (ERCOT) and independent market analysts agree on at least one thing: there will be about 4,200 MW less fossil fuel capacity in the Lone Star State in 2018, a decrease that can be attributed to the approved retiring of three coal-fired generation plants–Monticello, Sandow, and Big Brown.

Exactly how the decreased capacity reserves will affect the Texas market is less agreeable, at least for now.

ERCOT maintains a capacity reserve margin target of 13.75% of peak electricity demand so the grid operator may serve electric needs in the case of unexpectedly high demand or levels of generation plant outages.

Analysts like Potomac Economics, an independent market monitor for ERCOT, predict the retiring generation plants in Texas will lead to the grid’s capacity reserves dipping below ERCOT’s margin target.

Potomac’s prediction is at odds with ERCOT’s official forecast for capacity reserves in 2018, at least now.

Last May, ERCOT released its bi-yearly Capacity, Demand, and Reserves (CDR) Report, which projected the grid’s reserve margins to be above 18% until 2022 when the margin falls to 16.8%. The report, however, was published several months before the recently announced coal retirements.

After doing the math and subtracting the capacity associated with the retiring units from the 2017 CDR report’s forecast, a breach of ERCOT’s target reserve margin seems possible.

So ERCOT’s capacity reserve may drop below the 13.75% target. What does that mean?

We’ll likely learn the official answer in mid-December 2017 when ERCOT releases an updated CDR report to address what the loss of capacity from retired generation plants will mean to the grid.

Until then, we can make a few educated guesses on how the Texas market will react to decreased capacity based on the market’s recent history.

In the last 10 years, ERCOT’s reserve margin projections have dropped to single digits 10 times, reaching a recent low of 5.8% in 2012. The market has repeatedly bounced back from low projections. It’s worth noting, however, what happens when ERCOT’s capacity reserves actually fall below the grid operator’s target reserve margin.

That last happened in 2011, which was also the last time ERCOT’s scarcity pricing mechanism was triggered.

Scarcity pricing introduces a price floor and price cap to the market when an electricity supply emergency causes concerns of forced power cuts (called emergency load shedding) throughout Texas. When ERCOT’s reserves hit 2,000 MW as they last did in 2011, scarcity pricing sets an automatic cap at $9,000 per MWh.

Now let’s analyze who benefits from scarcity pricing. The short answer is generators. In an energy-only market like Texas, generators make money when the price of electricity spikes. Over the last several years, demand for electricity in Texas has set numerous peak load records, including new monthly highs in July and August 2017.

Power prices in Texas, however, have remained relatively stable. In fact, ERCOT reported that 2016 saw average wholesale prices in its real-time market hit an all-time low (see chart below).  Increased wind production, which accounted for less than 1% of ERCOT’s power in 2003 rose to 15% in 2016, continues to put downward pressure on prices, as does cheap natural gas supply.

The drop in capacity reserve in 2018 may lead to the kind of price spikes that generators have been waiting for, but generators will not be the only beneficiaries if wholesale prices see a significant rise.

If triggered, scarcity prices will be translated into ERCOT’s day-ahead ancillary services capacity procurements. That could mean financial opportunity for businesses who participate in ERCOT’s Load Resource demand response program, which pays businesses to be on call to curtail their energy use on short notice when the grid is stressed or electricity prices are exceptionally high.

Load Resource, ERCOT’s go-to ancillary service demand response program, already has the potential to pay businesses 2-3 times more than reliability-based demand response programs in Texas like the Emergency Response Service (ERS) program.

If scarcity pricing triggers in 2018, that potential payoff may be a lot bigger in Texas.

Join CPOWER on December 13 and 14 for “ERCOT Demand Response,” a two-part webinar series covering everything you need to know about demand-side energy management in Texas.

Part 1, “ERCOT Fundamentals: DR 101,” introduces you to DR in ERCOT and covers topics ranging from market structure to participating with automation and emergency generators.

Part 2, “Strategies for Maximized Results,” takes your DR knowledge to the next level and shares some important out-of-the-box methods for maximizing your value.

Both webinars are FREE and now open for registration.


How to Maximize Demand Response Earnings with California’s DRAM Program

November 21, 2017

For most of the last two decades, demand response in California has been largely procured and operated by the state’s electric utilities.

That trend is changing.

Demand response in California is currently experiencing significant changes as regulators implement measures to expand the state’s pool of energy resources and assimilate these resources with the California Independent System Operator’s (CAISO) markets.

This regulatory reform has created new opportunities in California for demand response programs, which pay businesses for using less energy when the grid is stressed or electricity prices are high.

The Demand Response Auction Mechanism

The Demand Response Auction Mechanism (DRAM) was developed in 2014 under the guidance of the California Public Utility Commission (CPUC) in an effort to harmonize utility-based reliability demand response with CAISO, the state’s grid operator.

In December 2014, the Commission issued D. 14-12-024 which requires the state’s IOUs: Southern California Edison Company (SCE), San Diego Gas & Electric Company (SDG&E) and Pacific Gas and Electric Company (PG&E) to design and implement Demand Response Auction Mechanism (DRAM) pilot programs in 2015 for 2016 capacity (DRAM I or 2015 DRAM) and in 2016 for 2017 capacity (DRAM II or 2017 DRAM). The three utilities recently completed a solicitation for 2018/2019 capacity (DRAM III) procuring over 200 MW of DR resources across the state.

Now in its third year, the program seeks to allow CAISO to add reliable demand response resources to areas of California where electric reliability may be at risk.

DRAM is a pay-as-bid program with three goals:
1)Fully integrate DR resources with the CAISO energy market
2) Test whether third parties can bring these resources to the table without structured utility programs
3) Allow residential resources to participate directly in the CAISO markets

The DRAM program also provides market participation testing from a broader base of distributed energy resources, including behind-the-meter storage. Under DRAM, these resources have the opportunity to behave not just as system capacity, but also as local and flexible resources.

California’s recent actions aim to revise the market’s existing demand response program structure and are an indication that DR has an important role to play in the state’s future.

The best way for an organization to take advantage of the DRAM program and the opportunities available in the California Market is to consult a trusted demand-side energy management company.

Such a company can evaluate an organization’s facilities and determine its curtailment capabilities. Next, they can explain in full the many demand response and demand management programs that are available in the California Market and help determine which offer the particular organization the best chance for curtailment success.

To learn more about how CPower can help your organization earn with the Demand Response Auction Mechanism program, please visit CPowerEnergy.com/dram-california.

To continue learning about how the California grid is changing to meet the needs of the future, read: The Evolution of The California Energy Market: How Demand Response and Demand Management will Play Integral Roles in The Golden State’s Energy Future

Demand response contributes more than just sustainability to K-12 public school system

May 01, 2017

The Virginia Beach City Public School System is on a mission. At the heart of that mission lies a commitment to education, which you’d expect from the largest school division in southeastern Virginia. What you might not expect is how money earned from participating in demand response programs is helping fund the VBCPS’ drive toward academic excellence.

Ranked the fifth best large school division in the entire nation by GreatSchools, Virginia Beach City Public Schools (VBCPS) has earned a reputation for fostering a culture of outstanding academics.

That’s not all the school division has earned lately.

Since 2014, VBCPS has also earned over $250,000 through demand response and demand management. The increased revenue has helped pave the way for a sustainable future of energy efficiency and academic achievement.

Compass to 2020
VBCPS’ Charting the Course initiative was launched in 2015 to set the vision of school division over the next five years. The strategic framework includes four goals – high academic expectations, multiple pathways, social-emotional development, and culture of growth and excellence – and multiple strategies to guide this important work. This focus on excellence at VBCPS extends into their drive towards energy efficiency and sustainability initiatives across their entire K-12 campus system and facilities.

VBCPS understands the importance of conserving resources and protecting our environment. Among the nearly 70,000 students and approximately 15,000 employees are the often unique and innovative conservation efforts that can be found in every office and school in the division. As a testimony to this commitment, they have embraced Demand Response participation with support at all levels of the organization, from the office of the president to the facilities personnel, faculty, and students.

The Opportunity
VBCPS has been participating in the PJM Emergency Capacity DR and Energy Efficiency programs with CPower since 2013. They participate through the State Contract E194-1378 administered by the Department of Mines Minerals and Energy (DMME), which has joined forces with CPower to bring enhanced Demand Response services to Virginia.
VBCPS has 85 schools, 13 of which were registered in 2016 to participate in the Emergency DR program. The peak load of the 13 school campuses is 9.6MW of which they curtail 8MW when called upon to reduce load during times of grid emergencies. Since 2014, their efforts have brought in earnings of over $250,000, which they have used to fund additional efficiency projects to support campus-wide sustainability goals.

Consistent Success
VBCPS staff at each participating school takes ownership of their Demand Response participation and have consistently over-performed each season thanks to:

  • Excellent cross-functional preparation and pre-season on-boarding with their facilities personnel and the CPower team
  • End-to-end communications/notifications exercise and load drop test conducted by CPower allows the VBCPS team to identify potential issues (if any) and take actions to fix them
  • Effective curtailment planning strategies to optimize load reductions with minimal impact on campus staff and students
  • Complete buy-in, approvals and support from the VBCPS school division management
  • VBCPS facilities team has sharp focus on setting up a detailed process for participation based on each school’s timecards and student schedules/events
  • Team expectations clearly; communications plan includes command central (radio, email, telephone, text) with notifications as early as possible
    Regular meetings and clear internal communications (via newsletters, posters etc.)
  • Team expectations clearly; communications plan includes command central (radio, email, telephone, text) with notifications as early as possible
  • Regular meetings and clear internal communications (via newsletters, posters etc.)
  • Every year pre-season, the VBCPS team proactively updates their Demand Response informational guide and set of procedures
  • With a total of 8 staff in Central Command and 30 across the other schools; they maintain 2-3 trained staff per school, with 1 person handling a specific event at each school and the rest at back -up in the case of vacations/illness. Moreover, experienced staff members act as mentors/trainers for others that are new to the program.

Challenges and Lessons Learned
Some initial challenges included managing data from multiple utility meters as well as different building automation systems (BAS). However, the methods used above with site-specific planning allowed VBCPS to overcome the hurdles. Some sites have an Easy Button and use an automated approach while some utilize a more detailed hands-on approach.
In the end, clear communications and reliable equipment/metering are key factors for consistent performance. For instance, there was an emergency event called at the end of the season in 2013, where VBCPS delivered per their commitments even though school was fully in session. The schools also got the added benefit of earning energy payments from that event.

Forward-Thinking towards a Sustainable Future
Additionally, in 2014 the team pioneered the State of Virginia Energy Efficiency effort with lighting upgrades across the division footprint. They embraced the energy efficiency program, connecting CPower with their contractors to get the required information of qualified projects, and ultimately will earn close to $100,000 for their efforts.

Looking to the future, VBCPS has consistently added load reductions to their commitment to support grid reliability. They have added 8 more schools with an additional 2.8 MW of curtailable load to participate in the 2017 PJM performance season program, and are also exploring the PJM Economic DR program. Four new lighting upgrades from the spring of 2017 were submitted to the PJM Energy Efficiency program. The team at VBCPS are a powerful asset to demand response. By providing their operating procedures as a starting point to other participants, they have served as mentors for other schools – providing encouragement to their peers so they feel confident to take advantage of the program and optimize energy earnings and savings at other K12s across the Commonwealth.

Contact Leigh Anne Ratliff or anyone on CPower’s PJM team at www.CPowerEnergy.com/markets/pjm-interconnection-contact

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

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

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

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.

Managing Rising Costs Amidst the Alphabet Soup of NY Energy Initiatives

January 30, 2017

If you’re a mid- to large-sized energy user in New York, you’ve likely come across a veritable alphabet soup of acronyms: REV, CES, DR, DER…the list goes on. Many of you who run commercial and industrial (C&I) businesses know that you can actively leverage Demand Response (DR) programs and earn revenue by curtailing load when called upon to do so during emergencies to support grid reliability. Granted, some years have been more rewarding than others since capacity prices ebb and flow in New York just like in other energy markets. Of course, capacity prices have risen substantially since 2012, resulting in increased earnings from DR participation in New York. So what can DR participants across New York expect in 2017 and beyond?

First, a bit of context on REV and CES:

In 2012, Hurricane Sandy hit the East Coast, causing devastation and leaving millions without power.  Shortly thereafter, working with the New York governor’s office, New York Power Authority and other state agencies, the Public Service Commission (PSC) launched the landmark Reforming the Energy Vision regulatory proceeding. Now commonly referred to as REV, its goal is to make the power system cleaner, resilient and more affordable. Regulators aim to transform traditional utilities into platform providers — entities that facilitate the deployment of distributed energy resources (DERs) and use them instead of traditional infrastructure.  And Demand Response is poised to continue to play a vital role as this initiative evolves.

In simplest terms, the Clean Energy Standard (CES) mandates New York to acquire 50% of its energy from clean resources by 2030. As part of this, it seeks to further that goal by providing zero-emission credits (ZEC) to support upstate nuclear plants that were in danger of closing. In late 2016, the PSC fended off numerous challenges to its adoption of the CES and its subsidy for nuclear power generators. Keep an eye on this space, however, as the PSC’s order doesn’t mean this is finalized (as of this writing in Feb 2017, two court challenges remain pending). Generators and some environmental advocates said the ZEC program — which critics say will cost over $7 billion over its 12-year lifespan — goes beyond the authority granted to the PSC by state law.

Impact on your bottom line:

In the near term at least, REV and CES, while noble causes, are going to lead to increased fixed costs (~$4/MWh) on mid- to large-sized energy consumers.  This scenario, however, also presents additional opportunities and specific actions you can take today to offset these costs:

  • Increased DR participation especially in new distribution utility programs, and
  • Capacity tag management.

New DR Programs: Both the NYISO and New York Electric Utilities offer demand response programs that pay businesses like yours for using less energy when the grid is stressed. Many commercial and industrial businesses in New York aren’t aware of the new summer-only local utility programs available to them via an authorized DR services provider. These programs offer another revenue stream in addition to the NYISO DR program that they may have been enrolled in for years. In 2016 for example, the New York Public Service Commission mandated that local utilities provide a Commercial System Relief Program (CSRP) throughout their entire service territory as part of a statewide effort to develop a new regulatory framework which includes incentives to leverage the deployment of distributed energy resources such as demand response.

Capacity Tag Management: Additionally, there are demand management services that can help significantly lower your capacity charge which make up 20-40% of the total supply portion on your monthly utility bill. The capacity charge is based on your individual capacity tag which, in New York, is determined by your facility’s usage when the NYISO sets its single annual peak hourly demand across the whole system. CPower sends an advanced day ahead demand management notification to reduce your usage when it is likely the NYISO will hit its hourly peak demand, thus reducing your capacity tag and capacity charges for the following year.

In the end, it’s all about implementing smarter techniques to manage your overall energy spend. The NYREV was launched 3+ years ago but it’s more relevant now than ever to survive as a large C&I energy user, as it will certainly change how energy is transacted in the future. At CPower, our job is to stay abreast of these developments and keep you informed about their potential impact. To get started, check out the various programs available in NY and informational videos to learn more on how you can offset rising energy costs in 2017 and beyond.

White Paper: The New England Electric Power Market

January 23, 2017

In the New England electric power market, sharply rising capacity costs and energy volatility in the New England power market will increase your electricity costs despite relatively low fuel prices and flat usage trends. This white paper explores the underlying reasons, and goes on to explain specific actions commercial and industrial customers can take to mitigate these cost increases.

ISO New England (ISO-NE) is responsible for keeping electricity flowing across the six-state New England region: Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. In so doing, ISO-NE’s core mission is system reliability.

To ensure reliability ISO-NE oversees the day-to-day operation of New England’s electric power generation and transmission system to keep the energy that generators supply to the grid in near-perfect balance with consumers’ energy demand. To ensure the system maintains adequate generating and transmission capacity to serve current and future needs ISO-NE manages a comprehensive regional pwoer system planning process and the region’s competitive wholesale electricity markets.

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