Demand Response Acquisitions May Not Help Large Energy Consumers

Caution

NRG’s 2013 acquisition of ECS is the latest in a series of purchases of pure play Demand Response providers that is helping retail energy providers (REPs) shore up their demand side management offerings.  NRG is following in the footsteps of competitors Constellation Energy Group, which bought CPower; Honeywell International, which purchased Akuacom; and Johnson Controls, which acquired EnergyConnect back in 2011.

Why are these acquisitions important?   One big reason is that the Demand Response market is growing. According to Navigant Research, “The industrial peak load reduction will grow from 26.8 GW in 2013 to reach 62 GW by 2019… and about $1.8 billion will be paid to these customers globally in 2013, increasing to about $4.3 billion in 2019.”  Further, Navigant projects Automated Demand Response (ADR) programs may be an additional $1.7 billion dollar Industry by 2018.

Given the dollars involved, large REPs, whose primary business is providing power to customers, are now also looking to provide Demand Response programs and automation (ADR) services in order to:

  • Attract prospective customers with a differentiated, bundled product offering; and
  • Increase revenue and margin by offering multiple products to existing customers.

Buyer Beware

While this strategy may be beneficial to the vendor and be a convenient “one-stop shopping” experience that delivers incremental value to the customer, it may come at a steep premium.  Often the whole can be less than the sum of the parts, particularly if a customer is unaware of current market trends or does not have access to objective energy experts.

Below are details from a deal I recently brokered, where the customer could have left over half a million dollars on the table with the bundled offer.  The customer in PPL uses 20 million kWh annually with a 2,000kW peak.

Offer from REP

The current REP offered the customer a supply price of $0.068 per kWh for their electricity load on a 3-year agreement.  In turn, the REP would provide Emergency Demand Response services and give the customer 100% of what is earned with participation (the REP normally keeps about 25-30% for managing these programs).   So, to the customer, it looks like the DR piece is a real value.

  • 20,000,000 kWh * $0.068 per kWh  = $4,080,000 million in energy cost over 3 years
  • 2MWs of demand response in PPL = $335,594 in earnings over 3 years

Total cost over 3 years = $3,744,406 ($4,080,000 commodity cost – $335,594 DR benefit)

Second Opinion

The customer decided to seek a second opinion, and by pricing the components separately improved its deal dramatically. Through a competitive pricing mechanism, the customer received offers of $0.58 for supply, and we helped them retain 85% share for DR.

  • 20,000,000 kWh * $0.058 = $3,480,000 in energy cost over 3 years
  • 2MWs of demand response in PPL * .85  = $285,254 in earnings over 3 years

Total cost over 3 years = $3,194,746 ($3,480,000 commodity cost – $285,254 DR benefit)

The resulting difference in cost is $549,660 over a 3 year period.

In this case, the whole was less beneficial than the sum of the parts, a conclusion that would have been difficult for an end-user to tease out on their own.

Conclusion

While we see REPs offering more sophisticated products and services with the acquisition of Demand Response providers, this trend may not benefit customers. It is becoming more important than ever for large energy users to work with expert, objective third-party energy management firms to tease out the underlying value from bundled offers.  Going through a competitive procurement process can help assure your next energy buy is really the best one for your organization.

Micro-Grids and Demand Response: Taking a Holistic Approach

Recently, I was fortunate to speak on a panel hosted by Agrion that discussed “Micro-Grids” and how Demand Response is playing a pivotal role in the proliferation of this potential new smart grid paradigm.

Agrion defines micro-grids as “self-sustaining power networks within the larger grid system that provide a higher level of local reliability than what is provided by the entire power system as a whole.”  For example, a micro-grid could be a large commercial building in NYC that has an ice thermal storage system, solar panels, and a Co-Generation unit and which also participates in various Demand Response programs.

The motives for having these systems and programs in place can vary, but the more popular reasons include an effort to keep energy costs down, reduce a facility’s carbon footprint (be green), and mitigate operational risks by supplying alternative power if there is grid failure.   Regardless of the motivation, the building in my example has systems in place that not only relieves stress on the local grid, but also provides a high level of reliability to their tenants.

As you can no doubt tell, this is a pretty complicated topic, and it lent itself well to good conversation. On the panel, we covered a wide array of topics that included:

  • What are the key drivers behind micro grid development? –  Location, aging infrastructure, type of business, and reliability concerns were among the key points surfaced by panelists and attendees.
  • Obstacles to micro-grid development – Cost of systems, utility cooperation, location, and regulations were among participants’ most common answers.

Finally, the role of Demand Response was discussed.  As many folks know, Demand Response programs pay businesses to reduce energy in response to grid system needs.  Depending on the type of program each facility is enrolled in, this can include emergency, economic, or other types of signals from the ISO/RTO or utility.

What I find interesting is that many of my co-panelists who work at firms offering micro-grid type products are starting to use their systems to leverage Demand Response revenue streams to drive the ROI down on their respective products.  For example, a thermal energy storage unit of 1MW can bid this capacity into the market for a one year period in NYC, which would return about $96k.  A controls company can pre-program a buildings system to participate in Emergency, Economic, and Synchronous Reserve Demand Response programs from the NYISO while also participating in the local Con Edison programs.  This can all be done on a small level while bringing in, potentially, hundreds of thousands of dollars annually.

Which got me thinking.  Here at World Energy, we use a simple equation to look at how we can minimize a customer’s total energy spend:

E = P • Q – i

(Where “E,” the total cost of energy = P (the Price of energy) multiplied by Q (the Quantity of energy used), minus i (available incentives)

Focusing on a customer’s total energy spend is crucial here.  At the conference , we focused on Demand Response (a type of incentive; the “i” in the equation above) as well as on products or technology that would reduce energy use (think “Q”). However, there was very little, if any, conversation around the “P” or price of energy during the discussion.

This is an area in which World Energy truly excels. Which leads to my big takeaway from the panel: there are some excellent opportunities ahead for partnering among the many dynamic and creative companies who have excellent products and want to make “micro-grids” a more common term in the energy field.   By combining expertise across the
E = P • Q – i value chain, I believe we can provide a more holistic and compelling energy management solution at the lowest price points possible.

This is a very exciting time in the energy management field, and I am personally excited to participate in helping grow the emerging micro-grid segment of the industry!

Special Delivery – ReCharge NY Allocations are in! – What to do next?

On Wednesday, April 25, many businesses and non-profits across New York found out how much of the electrical power they use would be provided at a discount rate under the “ReCharge NY” program.  This economic development plan provides a long-term price signal and commitment (via the state-owned utility NYPA) to employers in that the discounted electricity rate extended to participating companies is available for an initial 7 year period.

As with anything in the energy industry, though, it is not that simple.  The allocations provided through NYPA are broken down into two parts:

  • There is an allocation for a specific amount of energy through “Hydro Power,” which comes at a steeply discounted rate (a win for all customers)
  • There is an additional allocation for a specific amount of energy through a “blended discounted rate” that includes Hydro Power + purchase of market power

What does this mean for you? In our view, customers should seriously consider taking the first option, as these rates are better than what companies can get on the open market.   On the second, however, you have options, and are in a unique position to get rates that are possibly better than what is being offered through NYPA.  It is important to understand that you are allowed to choose ONLY the “Hydro Power” rate if desired, as this comes with no strings attached.

Most companies have one month to decide what allocation(s) they will take.   This puts you in a great position to “test” the market and see what prices you can get outside of what is currently being offered to you by NYPA.   By purchasing the balance of the power you will need through a competitive reverse auction, you can have all the largest suppliers in the Northeast bidding against each other to win your business.  A hyper-competitive environment, as provided by the auction process, will give you added price discovery, a fair and transparent mechanism for transacting, and, most likely, favorable prices for your energy needs. If you are interested in getting an objective opinion on the rates World Energy is seeing in the market via our reverse auction processes, give us a call (508) 459-8183 or email us at info@worldenergy.com.

ReCharge NY, but Avoid the Seven-year Itch

As many of you know, the “ReCharge NY” program is replacing the old “Power for Jobs” program that has been in place for many years.  Both of these programs are economic development plans that provide deeply discounted electricity rates to organizations across New York State in hopes of helping them retain and/or hire more workers.  The Power for Jobs program was very successful, but one big problem was that participants were re-allocated these discounts on an annual basis.  This understandably created tension, because participants were never sure if their allocations would be renewed.

The new ReCharge NY program attempts to solve this issue by providing up to 50% of applicants’ power at exceptionally cheap rates (via hydropower), with customers having a one time option of securing the balance of their power at market rate for up to seven years.

Securing the hydropower for up to a seven year period is a no-brainer, in my opinion, and the kind of clear market signal that members of associations like Multiple Intervenors, the Manufacturers Association of Central New York, and the Buffalo-Niagara Partnership have been looking for.  This allows them to budget/plan on a multi-year basis with a fixed price for power on the hydro allocation they are provided by NYPA.  However, what should organizations do about the “market rate” option that NYPA is providing?

This is where customers have options. While participants can accept the hydropower allocation, they will only be given a “one-time opportunity” to take a NYPA market rate or go to market on their own. Which leads to the million dollar question: Is accepting a long-term price by NYPA on “market rate” power really in a customer’s best interest?  Or, put another way, is NYPA going to provide a better price point than organizations can get by going to market themselves?

I think there is good reason to explore the market. If you look at the price of energy over the last seven years, you’ll see that energy prices are considerably lower today than they were back then.  If you had taken even a discounted market rate seven years ago, you might be paying a premium for your energy today.

Alternatively, if budget certainty is your concern, then you may want to consider signing a multi-year agreement – like GSA NY did in a recent auction – but only at the end of a competitive, transparent process where you know you are getting the best price in the market.

Either way, 7 years just seems like too long a time horizon in my opinion.

Bottom line, when you work with World Energy, you will find out what price point to expect through a competitive auction in your region where all suppliers will be invited to compete for your available “market rate” power. We’re hosting a webinar on March 22nd at 2pm to further discuss the “market rate” option for ReCharge NY program applicants and how a competitive auction can yield the best available rates for your organization.  If getting the best available price is your energy goal – please join us!

Need Help Deciphering Changes To the PJM Demand Response Market? You Are Not Alone

I recently led a well-attended webinar for Demand Response participants in the PJM region.  Its intent was to inform people about the implications that are occurring as a result of PJM’s transition to a “capped” or “pure forward capacity” market.  In short, there is only so much capacity available at certain price levels on an annual basis from now on, whereas in the past there was an unlimited amount of Demand Response that could be enrolled in the market and everyone received the same price points.

What I found intriguing was the responses we received for the polling questions on our webinar.  The vast majority (73%) of participants admitted they did not know or were very unsure of how the impending market changes could/would affect the revenue stream they earn through a Curtailment Service Provider (CSP).  Naturally this is why they attended the webinar, but let’s pause and think about this for a second.  There was over 11,000MWs enrolled in the PJM market last year, and the value for each MW was $40,150 in almost all regions.  11,000 x $40,150 =  A lot of money!!! With so much revenue at stake, it is no wonder we had such a high turnout, BUT it also suggests there are not many places that customers can get 3rd party advice or information about these important programs that can be very lucrative to their bottom line.

The next polling question was even more fascinating (to me anyway), in that 50% of folks stated that the most important factor in selecting a CSP was “revenue splits” (which was followed by “market expertise,” which correlates nicely with the answers in the first polling question).  I think this poll may indicate a change in people’s perception regarding Demand Response services.  In my experience, if this question was asked a couple of years ago the most important factor to customers would have been almost unanimously the “revenue split” option.  However, as time goes on and folks become more comfortable with reducing load for an economic benefit, these results suggest to me that perhaps customers are starting to see more value from these programs.

While it is nice to get a high “split” for participating in, say, an Emergency Load Response Program, the value learned from changing behaviors by reducing energy can be replicated for energy management strategies (which can lower energy costs) and for participation in other Demand Response programs where they can earn even more revenue.  Thus, partnering with a CSP who can provide “market expertise”, “technology” and “breadth of services” (combined 40% in this poll) can benefit a participant much more than enrollment in only one program.

If people don’t understand what’s going on in PJM (and there are millions of dollars at stake) and they are looking for “market expertise,” then maybe there is a market for more than what demand response providers are providing, namely, objective advice – and an effective way to act on it. And that is exactly what we deliver at World Energy.  Learn more by downloading our DR Buyer’s Guide at http://www.worldenergy.com/whitepapers/getting-more-from-dr-a-buyers-guide-for-demand-response/.

Breaking News: FERC’s DR Ruling and What It Means to PJM Program Participants

On November 4th , FERC tentatively accepted docket ER11-3322-000, much of PJM’s proposal that companies participating in Demand Response programs should not be compensated above their Peak Load Contribution (PLC) when utilizing the Guaranteed Load Drop (GLD) methodology with enrollment.  The question is what are the implications for large energy users who are currently enrolled with a Demand Response provider?

Large DR customers not being compensated above PLC using GLD

In effect, this ruling does not affect the revenue you will earn, as you are not being paid above your PLC anyway. However, if you are using the GLD methodology you should make certain you are being compensated off the full value of your load.  We recently  performed an analysis for a company who had over 50MWs enrolled in the market and was entitled to an additional $150,000 in revenue just by inserting specific additional clauses into the agreements they were about to renew.  Another organization that had a similar curtailable load was also entitled to about $150k in additional revenue IF they switched their enrollment methodology from Firm Service Level (FSL) to GLD, which they had the ability to do. Understanding the nuances of these competitive markets can be very lucrative for large energy users, but thankfully this ruling will not directly affect what you earn.

Large DR customers being compensated above their PLC value using GLD

The jury is still out on how this will affect you in the short term. FERC basically stated that they agree with PJM in that companies should not be compensated above their PLC.  However, capacity is acquired 3 years in advance in the PJM marketplace and thus Curtailment Service Providers (CSPs) “may have made commitments based on an assumption that they could count reductions from actual load levels above the PLC as part of their performance.” PJM had proposed compensation at 1.25 times a customer’s PLC, but FERC said they had concerns with this idea and gave PJM 60 days to come back with a more permanent solution that will cover the 2012 – 2015 delivery years.

What this ruling means at this point is that sometime in the future customers will not be compensated above their PLC if they are using the GLD enrollment methodology.  PJM’s initial offer of 1.25 compensation above the PLC would have created a more level playing field for the vast majority of CSPs who had originally decided not to “interpret” how their customers would be compensated in the PJM market. PJM views compensation above the PLC as double counting and is seeking to bring clarity and transparency to the marketplace. The irony to me is that FERC seems to be directing PJM to let a select and very specific few CSPs continue to offer compensation above the PLC, which gives them a competitive advantage over the vast majority of CSPs who are just as capable at offering similar services (and which I discussed in an earlier post: More than meets the eye.)

If PJM comes back with a ruling that in effect allows compensation above the PLC for companies that have been historically doing this, then I predict you will see some of the biggest loads in the PJM marketplace continue to work with the same select handful of  CSPs who have been, and will continue to be, handsomely rewarded for their “creativity” when enrolling customers into the PJM DR market.  Many, many large Demand Response customers are acutely aware of this issue and are waiting on a final ruling before they re-enroll with a CSP.

I would like to see PJM come out with a ruling that is applicable to all CSPs.

Shaking in Their Boots: How DR Will Change the Competitive Dynamics among ESCOs

If I was a C&I salesperson for an Energy Service company (ESCO), I would be very nervous about the recent acquisitions of demand response providers by my competitors. The combination of revenue that can be earned from participation in Demand Response programs along with the installation of energy efficiency equipment/controls is a potent one that, to date, many ESCOs have either overlooked or have yet to understand. This will give forward-thinking ESCOs a head start and competitive edge that could leave the rest of the field scratching their heads wondering why they are losing multiple multi-million dollar energy service contracts.

Let me explain. Demand Response (DR)  is a service that compensates end users for reducing load in response to grid system needs. In many markets there are multiple DR programs available, the most popular of which are Emergency, Ancillary Services (Reserves) and Economic Demand Response. Historically, niche companies specialized in providing Demand Response services to customers. Yet recent acquisitions of demand response companies by large ESCOs are a signal to the market that DR will no longer be considered a stand-alone product, but instead will be one of multiple energy management tools that large ESCOs will use to compete for Energy Service contracts.

But how powerful a tool will DR become in the proverbial ESCO tool kit? I think we’ll come to see it as a very powerful tool indeed. Consider the following example:

Situation:  A $4-5 Million dollar Energy Efficiency project for a School in PA (PPL utility area):

  • Installation of $1.5M building management system (BMS) for the schools
  • Lighting retrofit of existing T12 lighting system to Super T8 system — $1M
  • Replacement of old inefficient boilers — $800K
  • Installation of variable frequency drives (VFDs) and new energy efficient motors on circulation pumps — $600K
  • Installation of Demand Control Ventilation system in gymnasiums, auditoriums, and cafeterias — $300K
  • 7 ESCOs respond to the RFP
  • Each has similar product offerings
  • ESCO #1 integrates a DR product suite which provides a $470,000 revenue stream most of which is earned over a 3 year period.

Initially, ESCO#1 builds their usual RFP response but NOW sends it to their in-house DR experts. Their DR team determines that, for minimal additional work/cost, the district can use the controls they already want installed to:

  • Reduce 1.5 MW’s of load for Emergency DR = $266k over 3 year contract (typical)
  • 1 MW for Spinning Reserves = $120k over 3 year contract
  • 300kW for Economic DR = $40k over 3 year contract
  • Permanent efficiency can also be bid into PJM’s Permanent Efficiency forward capacity market and return an avg. of $50/kw/Year * 220kW * 4 years = $44k

All of this will be provided “turnkey,” and ESCO#1 can even offer the option to dispatch the loads when they are needed. That way the district does not have to worry about any additional work but can instead focus on running its facilities while still receiving these ongoing annual revenue streams. By integrating DR into its service offering this way, ESCO#1 not only has a competitive edge but can also relieve the district of trying to figure out on their own how to participate in these complex Demand Response markets.

Now here’s where it gets really interesting. In this example, even if other ESCOs have a Demand Response expert on staff, in all likelihood they do not have the rights to sell capacity in the PJM market (capacity is acquired 3 years in advance to registered Curtailment Service Providers). Thus, even if they know how these demand response markets work, they still cannot replicate the savings ESCO#1 can deliver.

What’s the alternative then?  ESCOs can either team up with a Demand Response company – a risky propositions because the ESCOs may not want to charge a premium for their services – or they can try to offer Demand Response services themselves. The problem here, however, is that, as mentioned above, in the Mid-Atlantic they will either have to acquire the capacity through a bi-lateral contract or purchase capacity 3 years in advance and wait until they can offer this to customers.

ESCOs could also purchase niche DR providers (something I expect to see more of over the next 36 months), but this also can be risky – and expensive. A last alternative, and the most practical and actionable one is for ESCOs to monetize a customer’s DR capacity through an open and competitive DR marketplace, such as the World DR Exchange, where Demand Response providers bid in an online forward auction for a customer’s capacity.

Now, let’s get back to our example. Because of its proficiency in Demand Response, ESCO#1 has an additional $470,000 it can play with to offset costs, add additional products, or do whatever it deems necessary to win the business. How can another ESCO compete with this if they cannot offer a similar solution that will drive Demand Response revenue to their customers? Additionally, this is only a $4-$5 million dollar example. The DR figures increase dramatically if the client is bigger and has, let’s say, a $30-$35 million dollar Energy Service Contract which they are bidding out.

And this is just the beginning of an inextricable tie between DR and energy automation. According to Pike Research, “The automated demand response market is poised to grow at 500 percent over the next 10 years. This period of dramatic growth will begin in 2013 and will increase from a $1.4 billion annual market in 2010 to $8.2 billion by 2020 under moderate circumstances.”

At the end of the day, DR is an energy management product that is becoming ubiquitous in the energy management space. Another area of the Energy Management industry that is embracing Demand Response services can be seen in the USGBC’s pilot project surrounding LEED certification. Basically, they have set up a system where participants can earn 1 LEED point for enrollment in a Demand Response program with the intent to roll out this program nationally if it is successful. And, as if all this was not enough, FERC recently issued Executive Order 745 which mandates that ISOs compensate customers for full Locational Marginal Price (LMP) if they enroll in an economic Demand Response program.

Bottom line: If you are an ESCO intending to compete for large energy service contracts, it’s time for you to raise your game in Demand Response.

The Manhattan Session: Talking DR and Energy Management

Yesterday I moderated a Rockefeller Center event hosted by AGRION, a business network for energy development, on “Integrating Demand Response and Energy Management in the C&I Markets.”  Participating in the keynote panel were some of the biggest names in DR and energy management, including Johnson Controls, Schneider Electric, GE, Siemens, EnerNoc, Lockheed Martin and World Energy.  With the continuing evolution of the Demand Response markets and the recent acquisitions of many large “pure play” Demand Response Providers – CPower, Energy Connect, and Akuacom to name a few – the questions posed throughout this forum were certainly fertile ground for conversation!

Here’s what I took away from the discussion.  Everyone agreed that Demand Response and Energy Efficiency are complex topics/products and that further education of their prospective and current customers needs to take place.  Additionally, many of the larger control companies seem to want to provide an “end to end” solution regarding Demand Response services, but I did not recall anyone mentioning any product differentiation or approach to market (though the latter is certainly understandable).  While the integration of DR and EE would intuitively seem to go hand in hand, there is a disconnect in that DR can be integrated quickly, there is no out of pocket costs for enrollment, and customers receive revenue for their participation.  This differs from EE, where capital outlay is necessary and the revenue allocated for these projects needs to be budgeted in advance so implementation normally takes longer.  At the end of the day, both do accomplish the same thing, which is to lower customer’s energy usage through effective energy management practices.  

Two encouraging trends that seem to knit DR and EE much closer though are the OpenADR standard and the newly created LEED point for DR participation.  The future of effective energy management seems bright and it is certainly evolving.  Stay tuned!

PJM, FERC and Demand Response: More than Meets the Eye

The discussions on the changes to the rules regarding how companies are compensated for Demand Response participation in PJM’s Emergency Demand Response program are certainly heating up!  Over the weekend I read the newly released “Open Letter” by three large Demand Response providers in regards to these rule changes, PJM’s response to the “Open Letter” and a Reuters piece by Nichola Groom saying FERC needed more time to consider this issue before making a final ruling – wow!

The rules and language being used in these articles can be confusing and hard to decipher if you do not work in these markets on a regular basis. The bottom line here is that PJM is in charge of administering wholesale electricity markets in an impartial manner and must provide grid reliability.  One way they do this is through the creation of Demand Response programs.  If you look at any other ISO/RTO throughout the country, they all have some form of Demand Response programs in place to help them manage their capacity challenges.  One common thread to all of the Demand Response programs that are being utilized is the fact that they continually evolve

What do I mean by this?   Again, these markets and the available Demand Response programs are complex, so the initial rules created often do not operate as intended.  Examples of this abound:  recently the NYISO changed their baseline analysis for their own Emergency Demand Response programs (ICAP/SCR) to better measure the reduction levels from customers, and in Texas we are seeing efforts to expand the EILS Demand Response program due to issues surrounding participants’ unexpected fulfillment of capacity obligations that arose as a result of the February 2nd and 3rd rolling blackouts.  Thus, adjustments have to be made to try and make these programs operate as effectively and efficiently as possible.

These program “changes” often have many ramifications for Demand Response providers who enroll customers into Demand Response programs. The bottom line in this case is that PJM is looking to mandate that each customer is compensated for the amount of load they reduce on an individual basis whereas, currently, Demand Response providers can aggregate the load they have under management for many of their customers and bid it into these capacity markets on a portfolio basis. Demand Response providers’ contention seems to be that as long as they deliver “x” amount of MWs when called upon, it should not matter if one customer “underperforms” and another customer “over performs,” as long as they deliver the intended and promised load reduction goal.  

The problem here is that if each customer is measured and compensated on an individual basis, Demand Response providers can lose a lot of revenue, because, in my opinion, the current baseline analysis being utilized by PJM is flawed and some customers are not being compensated for the load they can actually reduce when called upon.  The current ruling does not address this “baseline analysis flaw” whatsoever, but instead focuses on closing a “loophole” in how Demand Response providers bid their customers into the market.  The outcome of this is that Demand Response providers will lose revenue even though they can deliver the intended load they have under management.  

I think if we want clarity in these markets there is a need to address the baseline methodology before/during any ruling comes out that changes how Demand Response providers bid their customers into the capacity market.  Although it makes sense that PJM would want to measure and compensate each facility on an individual performance basis, I do not think the order in which this is being done is the way to go.  The ultimate goal is to have clear, transparent market rules with an even playing field for everyone, and the markets are naturally evolving in this direction.  

I think we need to adjust how this is being done by first addressing the baseline methodology rule and then addressing how Demand Response Providers bid their customers loads into the markets.  If we go this route, and assuming a new baseline methodology captures what each facility can really shed when called upon, then Demand Response providers will earn revenue for the nominated MW’s they bring to market, and PJM will be able to measure sites on an individual basis.   

This could make this issue less contentious and close the loophole that is creating unintended advantages for some Demand Response providers, as I explained recently here.

Demand Response: Evening the Playing Field in PJM

Just about every day I read an opinion on the controversy regarding PJM’s attempt to change the GLD enrollment methodology that curtailment service providers (CSPs) are currently utilizing to enroll customers into their Emergency Demand Response program (aka RPM program). The ramifications from any change could have many potentially profound consequences on the marketplace, such as decreasing the revenues earned and lowering the kW nominations.

Regardless of how you feel on this matter, one likely outcome of any ruling is going to be a more uniform enrollment methodology which will create a level playing field in which all Demand Response Providers can compete.  Currently there is a loophole in the GLD enrollment methodology that allows the largest CSPs in the PJM territory to leverage the size of their portfolio to enroll some of the biggest and thus most lucrative clients in the region. This “advantage” is about to be terminated and is one of main reasons why there is so much resistance to this change.                        

In PJM, a customer who wants to enroll in a Demand Response program must first find out what their Peak Load Contribution (PLC) is from their local utility company.  The PLC is the average amount of electricity the customer was using for the five hours during which the grid “peaked” the previous summer.  The customer’s PLC is used as a baseline to help determine how much load the company can shed in a Demand Response program.  The PLC is also meant to serve as the maximum amount of load a customer can bid into a Demand Response program if they agree to shut down operations when asked to curtail.

The problem has arisen out of what some would see as a flaw in how the kW reduction is measured in this program.  Under current rules, a CSP can use a GLD methodology to show how much load their customers reduce against their PLC.  With the GLD methodology a customer actively reduces load to a predetermined amount.  For example:  PLC (60,000) – GLD 60,000 kW = payment for reduction of full 60000 kW’s.  Makes sense, right?  It does, but like every baseline methodology there is room for improvement as it does not capture the full reduction capabilities of all customers.

For example, some customers’ energy usage may normally be much higher than what their calculated PLCs actually are. This can happen for a variety of reasons, like less production the previous year, the system peak occurred late in the day when production was ramping down at a plant, or a plant was offline for maintenance for one of the five days when the PLC was calculated.  If any or these things were to occur, the 60,000 kW example above could really be able to shed 80,000 kW but would be forced to only earn revenue off the PLC of 60,000 kWs. This is a substantial loss of revenue for a client of this size and can be seen as counterproductive in that the intent of the program is to compensate end users for providing relief to the grid.

The purpose of establishing a baseline methodology like the one mentioned above is to provide a uniform process that that CSPs can use to enroll customers into their Demand Response programs. This is supposed to ensure that everyone follows the same rules and earns the same amount of revenue for the load they curtail.  Further, these rules are also supposed to provide an even playing field in which CSPs compete to enroll customers. That was the intent anyway….

This issue in conjunction with the fact that a select few very large CSPs have “interpreted” the GLD enrollment methodology to mean they are allowed to aggregate their customers’ loads to hit compliance goals (i.e., 10 customers must have a combined 100MW’s of load when called upon vs. each facility having to shed 10MW’s separately). This has led to an unintended “loophole” that is allowing these select few large CSPs to leverage the size of their portfolios to take advantage of market rules and gain an unfair competitive advantage.  Even worse, the amount of load these select few CSPs represent in the market has allowed them to enroll the largest, and thus the most lucrative, potential DR customers in this region!

An example to put this in context:

  • Demand Response Provider #1 has 1,000MW’s enrolled using the GLD methodology
  • Demand Response Provider #2 has 150 MW’s enrolled using the GLD methodology
  • They are both competing for a very large customer who has a PLC of 60MW’s
  • However, the customer can really reduce 80MW’s when called upon

Each Demand Response provider has to cover the amount of load they are representing in the marketplace with the GLD methodology. In this example it is 1000MW’s for one DRP vs. 150MW’s for another DRP.  As the rules currently stand, it does not matter how each DRP gets to their respective numbers as long as their customers shed this amount in aggregate.  Thus a DRP who enrolls customers using the GLD methodology can manage their customers on a portfolio basis.

This is where the advantage goes to the DRP #1. DRP #1 can pay the 60MW customer for the full 80MW they can shed even though the PJM ISO will not compensate the DRP above the customer’s PLC of 60MW’s.  Why?  They do this because this large customer can act as an insurance policy.  If DRP #1’s customers fail to reduce some load, the large DRP will make up for this shortfall with over-performance.  DRP #2 does not have as much load to manage as DRP #1 and does not need an extra 20MW’s of “over performance” for their portfolio.  Thus, they do not need and cannot compensate this large customer for the extra 20MW’s.  Further, DRP#1 can offer the customer a much lower % share.  Here’s the math:

DRP#1 offers 75% split of 80MWs valued at $41,500/MW  = $2,490,000

DRP#2 offers 95% split of 60MW’s valued at $41,500/MW = $2,241,000

This is a difference of $249,000 * 3 year agreement = $747,000 difference.  

To keep things simple, basically what PJM is attempting to do is put a 125% cap on how much load a DRP can bid over the PLC when using the GLD enrollment methodology.  This may not solve the baseline enrollment problem completely but it certainly makes the rules black and white so that all CSPs can compete on an even basis