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Demand Response


Now What? California Demand Response in a Post-Fossil Fuels World

November 14, 2018

The clock has started ticking down on backup generators in California’s demand response programs. On January 1, 2019, the California Public Utilities Commission’s Demand Response Prohibited Resources decision officially takes effect. The decision (officially Decision 16-09-056) mandates that fossil-fueled resources can no longer be used to provide demand response.

The decision doesn’t remove fossil fuel generators from use for backup or for facility power generation, just from demand response (DR). It’s clear, though, that they face near-certain elimination from the California power landscape in the near future. The historic green energy bill signed by Gov. Jerry Brown on September 10th, 2018, specifically requires that 50 percent of California’s electricity be powered by renewable resources by 2026—seven short years away.

Needless to say, this has some profound implications for the future of distributed energy resources (DERs) and DR in the nation’s most populous state (and the world’s fifth largest economy). California’s “bold path” toward 100 percent zero-carbon electricity by 2045 will take it through uncharted territory potentially full of threats to the reliability of its far-flung electrical grid and the costs of the electricity it provides.

Demand response in California, as elsewhere in the country, has been a valuable tool in managing demand-side energy use, protecting the grid, and funding progressive sustainability initiatives. Generators have been a valuable part of DR, providing additional opportunities to save and earn as part of their commitment to a balanced California grid. But California has long been strict on the use of non-emergency generation for demand response, and the green energy bill tightens restrictions to an outright ban.

With fossil-fuel generators permanently pulled from DR participation in California, then, the question facing participants is, “Now what?” There are no easy answers—in a constantly evolving energy universe like California’s, there never are. That said, CPower recommends a couple of steps you can take to ease your transition into a post-fossil fuel world and continue to save and earn.

No Generators? No Problem.

The 2015 court ruling that vacated the EPA’s rule—referred to in the industry as “the Vacatur”—took effect in 2016 and upended DR participation. Hundreds of fossil-fuel backup generators were withdrawn from DR programs in most of the nation’s wholesale energy markets

One water agency, though, found they could still successfully participate in DR without their generators. Virginia’s Lake Gaston Water Supply Pipeline supplies water to Virginia Beach, the state’s most populous city. The Vacatur forced them to withdraw their diesel-powered generators from their DR program. Without the generator to sustain pumping during curtailment as part of DR, they faced the prospect of not being able to curtail the required power during an event, which meant pulling out of DR completely.

Working with CPower, Lake Gaston’s curtailment service provider since 2010, managers were able to research new methods of DR participation without generators. These measures included a full pump shutdown, something they weren’t sure they could do successfully. After a thorough analysis and review of their operations with CPower, it turned out that they could. Read the full story here.

Back to Basics

Before you mourn kilowatts lost, take a moment and consider if there are kilowatts to be found to replace them. Start by asking yourself, “What’s changed since I received my first demand response check?” The answer might be, “Everything,” or something close to it.

How have your day-to-day operations changed in response to changing market conditions? What upgrades have you made to your lighting, HVAC, IT, security, and communications? Is your physical space smaller or bigger? Have you added locations? What’s the state of your building envelope? Is it sufficiently insulated? Has on-site staffing grown or declined?

These are questions to be answered when you have a knowledgeable energy engineer, like those at CPower, conduct a thorough assessment of your facility. Your new “deep dive” assessment forms the foundation for creating a new curtailment action plan, one that matches your available kilowatts to available demand response and demand-side energy management programs. Chances are you’ll find new kilowatts to replace those lost from removed generators, and possibly more.

Dollars for DERs

Now is the perfect time to think beyond the generator and embrace other dispatchable distributed energy resources, or DERs, for your backup power. Behind-the-meter technology like storage batteries—charged by renewable but intermittent resources like sun and wind as well as grid energy—can be enrolled by CPower in California’s demand response programs (Capacity Bidding Program, Base Interruptible Program, and Demand Response Auction Mechanism aka DRAM) as available generation to help when the grid is stressed. You can combine your DER asset with demand response programs to offset kWs lost from generators.

For example: California State University, Dominguez Hills is one of the most sustainability-focused campuses in the state system. In 2017, CSUDH joined with CPower and Stem, provider of the school’s 1 MW intelligent storage system, to create a combined curtailment and storage program. By stacking these technologies, CSUDH significantly reduced their environmental footprint, provided approximately 400 kW of grid relief, and generated revenue that flows back to the school to fund further sustainability initiatives. For their efforts, CSU was also recognized with the 2018 Smart Energy Decisions Innovation Award for Customer Project/Onsite Renewable Energy.

What’s Next?

As California moves toward 100% zero-carbon energy, it’s safe to say that fossil-fuel generation, on both the micro and macro level, will continue to be phased out. Demand response, however, will continue to have an important role in California’s energy re-imagining. Demand response continues to fulfill its primary role, protecting the grid of the world’s fifth largest economy. Look for thought leaders and decision makers to find new and better ways to integrate renewables and dispatchable renewable energy resources into statewide demand-side energy management programs. And look for CPower to continue to advocate on behalf of our customers to ensure their ability to save and earn while protecting the grid.

Case Study: Rhode Island Hospital’s Journey From The Sidelines To Optimized Demand-Side Energy Management

October 03, 2018

When a new EPA law threatened demand-side energy management at the largest hospital in The Ocean State, CPower answered the call.

The moment he learned what the EPA’s law meant for diesel generators participating in demand-side energy management, Marc Leduc figured he and Rhode Island Hospital had a problem.

The largest hospital in its state, Rhode Island Hospital is the only Level I trauma center for southeastern New England and provides expert staff and equipment in emergency situations 24 hours a day. Round-the-clock electricity consumption is both an operational necessity and a huge expense for the hospital.

For Mr. Leduc, the hospital’s Chief Engineer since 2011, executing an optimized demand-side management strategy has proven the best way to offset what would otherwise be a hefty energy spend.

Rhode Island Hospital generates half of the electricity it consumes with its onsite generation plant, consisting of four steam generators and three diesel generators. Even with such self-sufficiency, the hospital still purchases half its electricity from the grid–as much as 5 MW on a hot summer day–which comes with capacity charges that have been on the rise throughout New England for the last several years.

Enter CPower and demand-side energy management.

Since 2007, Rhode Island Hospital and CPower’s Bill Cratty, a veteran of the energy industry since 1964, have collaborated on a demand-side energy management strategy that allows the hospital to save on electricity costs with peak demand management and earn revenue with demand response.

The hospital’s three diesel generators have played a starring role in its demand-side success.

The Challenge: Upgrading to Compliance
Until the Spring of 2017, Rhode Island Hospital used its diesel generator set to power its facilities when the hospital curtailed its load from the grid as part of a peak demand management program, which lowers the hospital’s capacity tag and results in reduced capacity charges the following year. The hospital also routinely fired up its generators during demand response events, which pay participants for using less energy when the grid is stressed or electricity prices are high.

For Rhode Island Hospital, an optimized demand-side energy management strategy utilizing its diesel generators was essential in offsetting its energy spend.

In 2013, the Environmental Protection Agency enacted the National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines (NESHAP/RICE) to regulate pollutants emitted from stationary diesel engines. Part of those standards allowed for the limited use of backup generators for demand response.

In 2015, the U.S. Court of Appeals for the District of Columbia Circuit overturned the specific rules that allowed backup generators to participate in demand response.

Implemented in May 2016, the Court’s ruling mandates that only backup generators that meet the NESHAP/RICE standards are permitted to be used during emergency demand response dispatches. Two of Rhode Island Hospitals three diesel generators, each supplying 2 MW, were non-compliant and could no longer be used during demand response events.

“It [the law] was a big hit for us,” says Mr. Leduc. “Not only [did we lose] the money we generate from the [demand response] program, but the reduction of the peak load for capacity was probably the biggest hit for us, budget-wise. Capacity charges are right now about 25% of our budget.”

Mr. Leduc looked for answers on how to get back into the market and found them when he talked to CPower and Bill Cratty. Mr. Cratty, already intimately familiar with the hospital’s demand-side strategy, stepped in and immediately set a course by which the hospital could upgrade its emissions controls so their diesel generators could return to participating in demand response.

Having worked with Mr. Cratty since 2007, Mr. Leduc knew he could trust CPower’s ideas and suggestions, believing they would lead to the hospital successfully returning to the market. CPower recommended a company that could handle the upgrading and permitting of Rhode Island Hospital’s diesel generators, which are scheduled to return to full demand response participation by Spring 2019.

Selling up with a Little Help from Friends
According to Mr. Leduc, convincing the hospital’s upper management of the positives related to upgrading their diesel generators was “easy.” CPower’s Bill Cratty armed Mr. Leduc with figures that showed a clear return on investment (ROI), with future earnings from demand response covering the cost of the upgrades with a payback period of six months.

“The money we’re putting in to [the generator upgrade project],” says Mr. Leduc, “is ridiculously small compared to what the payback is.”

Advocacy and Guidance
CPower’s additional role as energy market advocates proved instrumental in helping facilitate Rhode Island Hospital’s generator upgrade project. Ray Berkebile, CPower’s Senior Director of Engineering, has led CPower’s approach to helping customers deal with EPA regulations concerning diesel generators, personally reviewing over 3000 generators from 2015-2017.

Mr. Berkebile met with Rhode Island’s Department of Environmental Protection (DEP) to educate the agency on the benefits up upgrading diesel generators so they may participate in demand-side energy management and help alleviate both grid stress and high electricity prices. Mr. Berkebile was able to demonstrate that properly-permitted diesel generators can have an impact on the grid’s overall balance and health without running for an excessive amount of time.

Toward The Future, Bright with Distributed Energy Resources
Rhode Island hospital’s demand-side energy future is poised to include more than successful peak load management and demand response. With CPower by its side, the hospital is exploring ideas to achieve greater sustainability through distributed energy resources (DERs).

CPower’s Bill Cratty believes hospitals, with their need to be operational 24/7/365, are suited to take advantage of emerging DER technologies. Rhode Island Hospital is currently exploring options for the installation of solar canopies on the hospital’s parking lots, which would add another source of on-site energy generation to the hospital’s current fuel mix. Adding such DER sources contributes to improved sustainability for hospitals that consume power round-the-clock to care for patients and must continue to consume electricity even when the grid is unavailable to deliver it.

With CPower by its side, Rhode Island hospital is set to continue leading the healthcare industry as a shining example of how optimized demand-side energy management offsets energy spend and contributes to increased sustainability.

Download this Case Study (PDF)

Case Study: Lake Gaston Water Supply Pipeline

September 17, 2018

Virginia Beach, VA – Faced with the prospect of losing hundreds of thousands of dollars in demand response revenue, this Virginia Beach site discovered a way to keep the money flowing without interruption.

THE CUSTOMER: LAKE GASTON WATER SUPPLY PIPELINE

The Lake Gaston Water Supply Pipeline, also known simply as Lake Gaston, is at the heart of the economic vitality of the City of Virginia Beach (see our City of Virginia Beach case study). Located west of the city, on the North Carolina border, Lake Gaston employs six vertical-turbine centrifugal pumps, each with a nominal capacity of 10 million gallons per day, to supply Virginia Beach with the 30 million-plus gallons of treated drinking water that its residents consume each day. (The high-capacity pumps give the station the flexibility to increase pumping up to 60 million gallons per day.) The water flows through a 76-mile-long pipeline (which includes six overhead river crossings) from the lake to facilities in nearby Norfolk for treatment.

Since 2010, Lake Gaston has participated in the demand response program offered by CPower through Virginia’s Department of Mines, Minerals and Energy (DMME). This program pays government entities market rates for curtailing their electricity usage during times of high demand on the grid. Participants save on their energy costs and earn revenue that can be reinvested in upgrades, energy efficiency projects, and more. Lake Gaston’s participation has earned them nearly half a million dollars since 2011 (see chart below).

Steven Poe, the city’s Water Master Planner, assumed management of Lake Gaston in 2015. At the time, Lake Gaston had already earned more than $221,000 in DR participation, and Steve understood he could count on a continuing and beneficial revenue stream. Unfortunately, he hadn’t counted on a court ruling that dramatically changed the role of emergency generation in demand response.

THE CHALLENGE: CONFRONTING THE VACATUR

In 2013, the federal Environmental Protection Agency (EPA) issued emission standard exemptions that permitted emergency generators to operate up to 100 hours a year for “emergency demand response.” Lawsuits from environmental groups, state governments, and commercial power generation groups challenged the EPA’s ruling, saying it would hurt air quality and grid reliability. In May, 2015, the United States Court of Appeals for the DC Circuit vacated the 100-hour rule (on procedural grounds). This vacating ruling, dubbed “the Vacatur,” would take effect on May 1, 2016.

The Vacatur threatened to have a disastrous impact on Lake Gaston’s DR participation—and earned revenue. Lake Gaston was designed to pump continuously and could not do so without the use of its diesel engine generator.

The Vacatur left Steve no choice but to withdraw his diesel-powered generator from the DR program. Without it, he not only faced loss of revenue from its participation, but potentially the loss of all DR revenue. If the generator could not be used to sustain pumping during curtailment, then Lake Gaston would not be able to curtail the required power during a called event without jeopardizing Virginia Beach’s water supply. The pumps, then, would also have to be pulled from the program, essentially shutting down the lucrative revenue stream.

Or would they?

Steve felt that the financial benefits of DR participation warranted a closer look for a creative solution. “When we realized we couldn’t curtail anymore with our generator, we didn’t want to miss out on the incentives,” he says.

But to reach their target, they would have to conduct a full shutdown. Could they shut the pumps down—and bring them back up—without damaging both pumps and pipelines? And if they could, would that be enough to continue in DR without damaging their savings and earnings?

 

THE STRATEGY: SHUT ‘EM DOWN

Full shutdowns are rare in nearly all industrial settings, but Lake Gaston had a precedent. In 2014, a 39-ton coal ash spill on one of the lake’s tributaries forced the pump station to shut down for about two months. This was the first extended shutdown of the pump station in its history and caused a great deal of concern. Lake Gaston was designed to maintain a minimum sustainable pumping rate of eight million gallons per day flowing through the pipeline to maintain water quality and prevent issues with start-up. When pumping resumed, Virginia Beach learned that the pipeline was resilient and could recover with minimal effort.

Using that experience, Steve and his team are able to shutdown the major energy consuming equipment at the pump station – including the pumps and industrial HVAC system –  within one and a half hours of being notified of a DR event. They’ve learned that participation without their generator is worth the extra effort of executing full shutdown and start up procedures, which requires monitoring the SCADA system and gradual reduction and startup of pumps to prevent water hammer.

 

THE CPOWERED SOLUTION: DMME + CPOWER DEMAND RESPONSE

Steve and his team had proven that pumps could be shut all the way down and brought all the way back up, on demand, with no damage to pumps and pipelines. He could curtail his assets enough to continue to participate in DR. The question remained, though: Would it be enough? “We were worried,” Steve says, “that if we didn’t cooperate or couldn’t participate in the test or event, there would be a penalty.” That could erase any financial benefit.

Fortunately for Steve, he had Leigh Anne Ratliff, CPower Account Executive, working with him. Leigh Anne has been with DMME since the inception of the joint DR program, and with Lake Gaston since they enrolled in the program in 2010. (She also works extensively with the City of Virginia Beach.) No one is as familiar with the DR program and Lake Gaston’s participation than Leigh Anne.

Leigh Anne told Steve that, because Lake Gaston (and the City of Virginia Beach) participate through DMME’s demand response program, there would be no consequences for not participating in a test or event. “The great thing about the DMME contract with CPower,” Leigh Anne explains, is that you really cannot be penalized. You’ll never owe anything. The worst that can happen is you’ll earn zero dollars for that test or event.”

 

THE RESULT: $400,000+ AND COUNTING

With penalties off the table and a successful pump shutdown protocol established, Steve continued Lake Gaston’s enrollment in the DMME DR program. He has yet to see zero dollars earned.

“We’re committed to saving money and being good stewards of public resources,” Steve says. “CPower is very supportive and encouraging for us to participate, to meet our commitments. When I first stepped into this position and informed my supervisors about the program, we all thought it was just too good to be true. But it has really worked out, and we are happy to continue participation.”

Lake Gaston Water Supply Pipeline—Demand Response Earnings
Delivery year kWs submitted  Earnings in $
2010/11 1843  $   99,676.00
2011/12 1557  $   53,311.00
2012/13 1759  $   30,685.00
2013/14 620  $   10,670.00
2014/15 1548  $   27,137.00
2015/16 1661  $   61,267.00
2016/17 1337  $   24,353.75
2017/18 1340  $   44,085.73
2018/19 1258  $   58,536.69
Totals to date 12,923  $ 409,722.17

 

Case Study: City of Virginia Beach

July 11, 2018

Virginia Beach, VirginiaEnergy Manager’s determined pursuit of energy efficiency savings earned the city tens of thousands of dollars in rebates in just a few short years.

THE CUSTOMER: THE CITY OF VIRGINIA BEACH

Located where the Chesapeake Bay meets the Atlantic Ocean, the City of Virginia Beach is anything but a sleepy resort town. It is the most populous city in the Commonwealth of Virginia, and boasts an economy comprising tourism, national and international corporate headquarters, advanced manufacturing, military bases, and agribusiness.

Besides the beach (the longest pleasure beach in the world, according to the Guinness Book of Records), visitors are drawn year-round to Virginia Beach’s many renowned attractions, including:

  • The Virginia Beach Convention Center the nation’s first convention center to earn LEED® Gold certification as an existing building from the U.S. Green Building Council;
  • The Virginia Aquarium & Marine Science Center, which attracts 650,000 visitors a year and hosts more than 10,000 fish, mammals, birds, and reptiles representing more than 300 species from around the world; and
  • The Virginia Beach Boardwalk, three miles of oceanfront access, bike paths, live entertainment, restaurants, shops, and a 12-ton bronze statue of King Neptune.

Keeping the Convention Center, the Aquarium, and 350+ city buildings running in top shape uses a great deal of energy. That means, Virginia Beach is a city that understands the value of world-class demand-side energy management in municipal operations.

THE CHALLENGE: PERMANENT ENERGY (AND COST) REDUCTION

Virginia Beach’s city government serves its citizens and visitors from more than 350 facilities citywide. By 2010, constant increases in energy costs incurred at these facilities had risen to $20 million a year, a total plagued with “lost” buildings and meter reading errors in the hundreds of thousands of dollars.

To address this and other issues, including utility billing, Virginia Beach created the position of Energy Manager and hired Lori Herrick, MBA, LEED Accredited Professional, to lead its energy initiatives and manage municipal energy expenditures. With $5 million from the city, an unexpected $4 million windfall from the U.S. Dept. of Energy, and a mandate to conquer the city’s energy challenges—Ms. Herrick went to work.

THE CPOWERED STRATEGY: FINDING READY KILOWATTS

Energy efficiency (EE) projects result in permanent energy reductions, which the city recognizes as arguably the cheapest, most abundant, and most underutilized resource available to local government. With this in mind, Ms. Herrick sought to find out more about an energy program being offered through DMME, the state’s Division of Mines, Minerals and Energy. The program in question promoted energy performance contracts (EPC) to significantly reduce energy costs through energy efficiency measures that meet a guaranteed level of energy savings.

Ms. Herrick began the process of enrolling city facilities in DMME’s EPC programs, but was soon faced with the complex challenges of identifying what facilities, and how many kilowatts, to enroll. Fortunately, she received another windfall. She was introduced to CPower’s champion of Virginia demand-side energy management, Leigh Anne Ratliff.

Ms. Ratliff has worked with DMME since 2007 to offer integrated demand response services on a performance basis with no set up costs to the state. Demand response programs pay organizations such as government agencies for curtailing, or reducing, their electricity usage during times of high demand. Government entities who participate in demand response both save costs on reduced electricity use and earn revenue for their trouble.

As Ms. Herrick soon found out, CPower has an additional strength: the ability to provide complete measurement & verification (M&V) services for energy efficiency projects, necessary to receive utility rebates and credits. More importantly, CPower has unmatched experience in finding additional kilowatts (kWs) all too easily overlooked in already completed energy efficiency projects—and successfully submitting those kWs for even greater returns on the city’s investments.

CPOWERED SOLUTION: FOLLOW THE DATA (AND FIND THE MONEY)

Because the permanent energy reductions resulting from energy efficiency projects can pay dividends for up to four years after completion, Ms. Herrick and Ms. Ratliff set about the task of unearthing four years’ worth of city files to find buried EE gold – kilowatts that others missed. Looking back, Ms. Herrick says, “We were determined… it was kind of a no-brainer, to go through the files of projects we’ve done and submit the information. We were analyzing these projects to make sure the payback was there… They gave us a lot of data that Leigh Anne could use to calculate our benefit to the grid and then give us a check for it.”

From the outset, Ms. Herrick considered no project too big to tackle, working to help the Virginia Beach Convention Center earn its LEED® Gold certification (see below). She also considered no project too small to enroll, at one point submitting a 7kW project. As Ms. Ratliff explains, “If she had it, she sent it. One building got a credit for $52 in 2017. We’re learning on the cost-benefit element of this, but Lori is always looking further, to get every bit out of it that she can. In that way, she’s revolutionized what people put into energy efficiency.”

SPOTLIGHT: VIRGINIA BEACH CONVENTION CENTER

The Virginia Beach Convention Center (VBCC) is the crown jewel among the city’s facilities. It was the first convention center in the state to receive certification from Virginia Green, the Commonwealth’s voluntary campaign to promote environmentally friendly practices in Virginia’s tourism and hospitality industries. As noted above, it is also the nation’s first convention center to earn LEED® Gold certification as an existing building from the U.S. Green Building Council. These certifications are increasingly important in the competitive convention planning industry, where the VBCC competes nationally. Customer awareness of, and insistence on, “sustainable destinations” plays a greater and greater role in siting conventions.

The VBCC is also a shining example of how state-ofthe-art EE projects can enhance a city’s energy budget as well as its national reputation. Nearly all lighting in the convention center is LED lighting, and the HVAC is controlled through a state-of-the-art Direct Digital Control (DDC) system that incorporates an automated demand response program to control spikes in peak electricity demand. The automation limits any impact to convention-goers and still saves energy dollars.

“Together, we developed a process to systematically go through the building to reduce demand with the least impact on customer events.” – Leigh Anne Ratliff

It’s also a shining example of how the city and CPower Engineering worked together to successfully address one of the biggest challenges facing active convention centers: controlling peak demand electricity and total kilowatt usage. Event load-ins and load-outs at VBCC can be particularly problematic because the bay doors open directly from the loading dock into conditioned exhibit space.

“The Convention Center was a very cool energy project, because people in that space change every day,” Ms. Ratliff explains. “Bay doors are open for hours at a time, a lot of bodies and boxes moving in and out. The open bay doors are a significant source of heating and cooling loss. So how do we control that without disrupting loadins and other convention-goers already onsite?”

The first step was to analyze the status of the bay doors during times of peak demand. The Center’s zoned DDC system, which controls the Center’s HVAC, was programmed to prevent the air conditioning from running in the exhibit halls if the bay doors were open. In addition, the DDC system receives power pulses from the electricity switch gears throughout the day. In the next phase, an automated demand response program was integrated into the DDC system. When the system reads that the Center’s demand is getting ready to peak, it automatically implements one of three phases. Phase 1 changes back-of-house temperatures by one degree. If demand continues to peak, it implements Phase 2, which changes back-of-house temperatures by two degrees, all the way to three degrees at Phase 3. This automated program reduces the demand on VBCC’s chillers, which in turn reduces peak electricity demand.

“Our CPower engineers worked with VBCC’s staff to understand how the bay doors and events taking place in the building impact peak demand and usage,” Ms. Ratliff says. “Together, we developed a process to systematically go through the building to reduce demand with the least impact on customer events.”

With its DDC system program finalized and firmly in place, the Convention Center was able to ease demand on the grid, with near-zero disruption to its customers’ activities. In fact, the Center saved an astonishing 15 percent off their peak during its first year. And since the price of electricity peaks along with demand, this translated into significant cost savings that they otherwise would not have been able to attain.

THE RESULTS: $87,000 AND COUNTING

CPower is instrumental in helping the City of Virginia Beach navigate the complexities of PJM energy efficiency credits and paybacks. CPower submitted the uncovered EE data to PJM and earned the city both savings and revenue. For the delivery years 2017 through 2022, earnings from PJM for the city will reach just over $87,000 (see chart), with the VBCC earning $40,000 alone. And the city’s just getting started. “We just got another big round of funding,” Ms. Herrick says, “so Leigh Anne’s going to be hearing a lot from us.”

LOOKING AHEAD: DEMAND RESPONSE

In November, 2017, the Commonwealth of Virginia retained CPower through 2020 to continue to offer integrated demand response (DR) services to state agencies and departments through DMME. Ms. Herrick worked with Ms. Ratliff to identify five city sites they believe could be the most eligible for DR: Judicial and correctional facilities, the Convention Center, the Aquarium, and the central plant. The Convention Center currently participates in CPower’s DR program and earns revenue. The remaining facilities are undergoing audits to better understand their suitability. “DR involves curtailment, and we have to be careful when and how we curtail,” Ms. Herrick says. “That’s especially true of the aquarium. I want to earn revenue for the city, but we also don’t want to be responsible for a fish fry.” There’s no doubt, though, that Ms. Herrick will find a way to make it work. Above all else, she and the city are determined.

CPower will support their energy goals at every turn, with an energy strategy custom-made to meet their unique requirements.

SAVINGS AND EARNINGS: CITY OF VIRGINIA BEACH/VIRGINIA BEACH CONVENTION CENTER

Projects include lighting and green building. Sites include Aquarium, Boardwalk, Convention Center, library, maintenance garages, recreation centers, fire stations, police stations, EMS administrative and training center, and arts center.

City of Virginia Beach

PROJECTS ESTIMATED DR (kW) FORECASTED GROSS $
2017/2018 14 185.67 $14,820.89
2018/2019 13 173.24 $17,869.86
2019/2020 11 170.24 $9,283.28
2020/2021 7 87.17 $2,434.65
2021/2022 2 38.36 $1,865.51
Total 654.68 $46,274.19

Virginia Beach Convention Center

PROJECTS ESTIMATED DR (kW) FORECASTED GROSS $
2017/2018 2 172.52 $13,781.49
2018/2019 2 172.52 $16,374.31
2019/2020 2 172.52 $9,497.01
2020/2021 1 40.95 $1,143.73
Total 7 558.51 $40,796.54

Combined Totals

PROJECTS ESTIMATED DR (kW) FORECASTED GROSS $
Total 54 1,213.19 $87,069.73

Will Prices Rise With The Temperature In Texas This Summer?

June 14, 2018

As we discussed in our recent blog post about this summer’s potential “perfect Texas storm,” two significant factors projected for the ERCOT (Electric Reliability Council of Texas) energy market could have a noticeable impact on demand response participants: Reduced supply and record peak demand. The resulting clash of supply and demand projections points to the possibility of unexpectedly high prices for those organizations participating in ERCOT’s Load Resources (LR) demand response program.

As we noted last November, ERCOT approved the retiring of three coal-fired generation plants, reducing available generation capacity by about 4,200 MW. In its Final Summer 2018 Seasonal Assessment of Resource Adequacy(SARA), ERCOT projects the Summer 2018 total generation capacity available to be 78,184 MWs, resulting in a capacity reserve margin of roughly 11%. That’s well below its capacity reserve margin target of 13.75% of peak electricity demand.

In a slow economy, reduced supply might not be a problem. But that’s not the case in Texas. The economy is booming in the Lone Star State—in fact, it’s currently the fastest growing economy in the nation. That’s good news for Texans, but not-so-good news for Texans looking forward to a summer of uninterrupted electric supply and the state’s historically low energy prices.

Here’s why. ERCOT predicts “record-breaking peak demand usage” for this summer—72,756 MW. According to the SARA report, that’s more than 1,600 MWs higher than the all-time peak demand record of 71,110 MW set in August 2016.

ERCOT recognizes that this tight margin—a mere 5,428 MWs—might be cutting it too close for comfort. With an eye to grid reliability, it says it could find it necessary to deploy Ancillary Services—Load Response, or LR—and Emergency Response Service (ERS) demand response capacity “to maintain sufficient operating reserves.”

The law of supply and demand usually looks something like this:

Low supply + High demand = High prices

With that in mind, will we see record high prices this summer? The forward ERCOT energy market certainly seems to think so. Projected wholesale energy prices in ERCOT for August 2018 have more than doubled since the 4,200 MWs of generation announced it planned to retire in early 2018.

While the price customers receive for participating in LR is different than the energy price they pay when using energy, there is generally a correlation in that when energy prices rise in ERCOT, LR prices also rise. This is due to the structure of the ERCOT market where lower reserves available typically results in higher energy and LR prices.

As we’ve laid out above, we can expect lower reserves available in ERCOT this summer and therefore higher energy prices than we have historically seen.

While it remains to be seen if this summer will ultimately result in record high LR prices, we can already see in the above chart that there has been an increase in LR prices since the 4,200 MWs of generation retired in early 2018. Will this trend continue? That largely depends on the weather and generation availability this summer, but a great way to offset the increase in energy prices is through participation in LR which allows you to proactively gain revenue from your energy usage.

Join CPower on Tuesday, June 26, for the third in our ERCOT Webinar Series, “The Perfect Texas Storm: Low Reserves, High Prices, and Record Peak Demand for Summer 2018.” Join CPower’s Texas experts Mike Hourihan and Joe Hayden as they tackle the topics that will impact demand response customers this summer.

The webinar is free and now open for registration.

“The Perfect Texas Storm: Low Reserves, High Prices, and Record Peak Demand for Summer 2018”

Date: June 26, 2018

Time: 10:00-11:00 a.m. Central Time

REGISTER NOW

Are You Ready For This Summer’s Perfect Texas Storm?

In October 1991, Hurricane Grace formed near Bermuda and began moving north. At the same time, a massive low-pressure system moved south from Canada. They converged in the North Atlantic, creating a deadly, cataclysmic weather event that was dubbed “the perfect storm,” later immortalized in the film of that name starring George Clooney.

No such weather event (or related George Clooney appearance) is currently predicted for Texas this summer. However, two significant man-made forces are currently converging in the ERCOT (Electric Reliability Council of Texas) energy market: Reduced supply and projected record peak demand. The resulting “perfect storm, Lone Star-style” of clashing supply and peak demand projections has led ERCOT to ask those involved in demand response (as well as generators and transmission owners) to focus on maximizing performance.

Let’s take a look at these two big factors impacting ERCOT this summer. First, supply. In Texas, the name of the game is reliability. To ensure a reliable grid, ERCOT prefers to maintain a capacity reserve margin target of 13.75% of peak electricity demand. These reserves enable them to serve electricity needs in case of unexpectedly high demand or levels of unanticipated outages from generation plants.

As we noted last November, ERCOT approved the retiring of three coal-fired generation plants, reducing available capacity reserves by about 4,200 MW. In its Final Summer 2018 Seasonal Assessment of Resource Adequacy (SARA), ERCOT projects total summer capacity to be 78,184 MWs, and the Summer 2018 planning reserve capacity to be 5,428 MWs, or roughly 11% reserve margin. That’s well below its capacity reserve margin target of 13.75% for peak electricity demand.

Second, demand. Texas currently boasts the nation’s fastest growing economy. Its growth is driven, as Forbes reported in May, by a resurgence in oil and gas drilling in the panhandle as well as growth in manufacturing that outpaced national growth rates in that sector. ERCOT’s SARA report acknowledges that this growing economy will continue to drive demand for electrical power, going as high as 84,814 MWs by 2023.

In fact, ERCOT predicts “record-breaking peak demand usage” for this summer—72,756 MWs. According to the SARA report, that’s more than 1,600 MWs higher than the all-time peak demand record of 71,110 MW set in August 2016.

So—72,756 MWs of demand. 78,184 MWs of capacity, 5,428 MWs of reserve planning capacity… frankly, that’s cutting it pretty close. Maybe tooclose. In fact, ERCOT thinks these tight reserves could trigger the need to deploy Emergency Response Service (ERS) demand response capacity, “to maintain sufficient operating reserves.”

If this happens, it increases the potentialforreal-time emergency events in order to maintain the grid’s reliability. How does this affect ERS participants?

ERS pays organizations like yours for using less energy when the grid is stressed and electricity prices are high. There are two types of ERS programs: ERS 10 and ERS 30, which pay businesses for being available to curtail their electricity load within 10 and 30 minutes respectively. The request to curtail is a referred to as a “called event”.

In the aftermath of the SARA report’s release, our ERCOT office heard from a number of customers who were concerned about the potential for real-time extended events. They feared disruptions to operations and the potential negative impact these disruptions could have on their customers and their bottom line. But how likely are we to see calls to curtail in ERS?

Looking at historical data, not very likely. Called events in ERS are rare. Between 2008 and 2017, a total of three events have been called. In the last eight years, we have seen no events at all. Over the past ten years, capacity shortage events above and beyond annual tests have averaged 0.3 per year in ERS 10, and 0.2 per year in ERS 30. As far as frequency goes, over the last 10 years the most that the ERS program has seen in one year is… two.

Based on the numbers, then, the odds are good that you won’t have to endure many, if any, curtailment requests. We’re confident that you should still be able to participate as in years past, and continue to earn revenue for your availability.

That said, CPower recommends the following steps to maximize your performance in ERS this summer.

Check your plan. Businesses and organizations change, expand, contract, evolve, and are seldom the same year over year. The curtailment plan you first developed with CPower’s engineers may no longer be the best fit for your current electricity usage and operations. Contact CPower and set up a review of your plan. An up-to-date curtailment plan is the best path to success in demand response. (You may even find some additional kWs to enroll that weren’t there before.)

Automate your DR. Automation is required for ERS 10 participation, but it’s still optional in ERS 30. Having even one or two steps on your curtailment process automated can make the difference between performing and underperforming. Make sure you discuss automation opportunities, including incorporating CPower’s Link API, when you review your curtailment plan.

Test your generators—at full load. If you’re counting on your back-up generators to provide you with needed energy during your curtailment events, make sure they can handle the load. Too many generators undergo their monthly and weekly test running off load, for fear of wearing their generators out. The problem is, generators are designed to run at their stated rating, every time. In fact, testing at less than full load can ruin an engine in as little as 50 hours of accumulated running time. Ask CPower’s engineers to review your current onsite generation process as part of your curtailment plan review.

While you’re at it, set up some time to assess your generators for enrollment in demand response. Properly permitted, onsite generation is source of additional revenue. Talk with CPower about your options.

CPower is here to help you through what could be a long, hot summer in the Lone Star State. ERCOT expects everyone, including demand response participants, to give the grid maximized performance for the benefit of all. CPower is here to help you do just that.

Join CPower on Tuesday, June 26, for the third in our ERCOT Webinar Series, “The Perfect Texas Storm: Low Reserves, High Prices, and Record Peak Demand for Summer 2018.” Join CPower’s Texas experts Mike Hourihan and Joe Hayden as they tackle the topics that will impact demand response customers this summer.

The webinar is free and now open for registration.

“The Perfect Texas Storm: Low Reserves, High Prices, and Record Peak Demand for Summer 2018”

Date: June 26, 2018

Time: 10:00-11:00 a.m. Central Time

REGISTER NOW

Myths… Busted! PJM’s Capacity Performance Soars to New Heights– and Confirms Its Revenue Potential for You

June 05, 2018

Big news came out of the PJM Interconnection’s Base Residual Auction (BRA), for the 2021/22 delivery year, two weeks ago. Contrary to what most industry experts and trade journalists had predicted, PJM’s Capacity Performance (CP) emergency demand response program did not fail. In fact, we saw offered and cleared Demand Response megawatts (MWs) increase drastically, the highest volume of Energy Efficiency to ever clear a BRA, and prices came soaring back up, shocking prognosticators everywhere.

Although this may all be contrary to the opinions of the majority in the energy industry, it is right in line with what I highlighted in my white paper from October, 2017, “PJM Capacity Performance is Here. Don’t Believe the Myths.” In it, I outlined three “myths” that were clinging to PJM’s CP-only demand response program and shot each one down. Seven months later, the market has proven us right.

It would be impolite to say, “I told you so.” So instead I’ll show you. Here are the three myths that I discussed, and how the results Wednesday’s auction proved each of them wrong.

Myth #1: Demand Response has declined over the last six years.

I called this a “pernicious myth that can prevent organizations from opening a rewarding and potentially substantial revenue source.” The idea was cleared capacity was declining, which meant demand response is declining. Not so, I said. There’s a big difference between cleared capacity and enrolled capacity, and while cleared may have seen recent declines, enrolled was remaining steady and strong, which means DR overall remains strong and will continue to be.

Flash forward to Wednesday. The amount of Demand Response that cleared the BRA was 11,125.8 MW. Not only is that about 3,300 MW more than last year’s BRA (the first for CP-only). It is the highest amount of cleared DR in a BRA since the 2016/17 BRA five years ago. Now it remains to be seen if 11,125.8 MW of DR is enrolled in the 21/22 DY, but it’s well within reason to expect ~9,500 MW to be enrolled, which would maintain the amount of participating DR flat YoY.

Myth #2: New CP requirements make it difficult to participate in DR.

In my white paper I stated that although grid reliability is PJM’s number one focus (and rightfully so), and the new CP requirements imposed on Demand Response customers appear daunting (with higher noncompliance penalties and much longer requirements to perform), the impact on DR should be negligible. The implementation of CP to help prevent PJM from entering into emergency situations should mean less of a need for emergency resources such as Demand Response.

It appears that Demand Response customers are adjusting their mindsets from thinking that they can—or only want to—participate in summer-only emergency programs, to understanding that they do have the ability to be year-round resources. And Curtailment Services Providers now believe that they can support a Capacity Performance DR offering and feel there are sufficient customers that can comply and meet their RPM Commitments. This is evident in that over 2,000 MW more DR was offered into the 21/22 BRA than the 20/21 BRA. The DR industry is becoming more comfortable with the Capacity Performance program.

Myth #3: 100% CP means PJM is moving away from DR.

The RPM is an auction-based model that PJM uses to meet forward demand, and it does so by clearing sufficient capacity needed for reliability at the cheapest cost to load. PJM recognizes and understands the value that Demand Response resources bring to the market. The 21/22 BRA cleared at much higher prices across the RTO than nearly everyone projected. And although the prevailing thought is that many capacity resources adjusted and increased their offer prices, which caused prices to spike and PJM to clear Demand Response and Energy Efficiency resources in their place, nonetheless the need for these resources has been proven.

Despite what you may have been told, Demand Response is not back, folks. It never really went away. At CPower we expect the market and the programs to continue to change. It’s what we’ve always seen and are always prepared to see. And we will continue to adapt every step of the way while finding new ways to help customers reduce their costs and generate revenues to strengthen their energy management strategies.

Green Buildings Attract Happy Tenants and Bring Green Earnings to the Commercial Real Estate Industry

May 25, 2018

The following is an excerpt from “Monetizing Energy Assets in the Commercial Real Estate Industry: A Complete Guide for Earning Revenue with demand-side energy management” by CPower:

For the past several years, the economic and policy climate of North America has created an impetus for green and sustainable energy-efficient buildings. The commercial real estate (CRE) industry has contributed to this momentum.

Keeping the supreme goal of providing a great tenant experience at the forefront of their operations, commercial real estate facility managers and executives are increasing their focus on energy management plans rooted in a sustainable building philosophy based on cost-effectiveness and energy-optimization.

The CRE industry’s current push toward a more efficient and sustainable future comes at a serendipitous time when energy markets around the country are working to integrate distributed energy resources (DERs) onto their energy grids in an attempt to diversify their fuel mixes.

Right now and for the foreseeable future, grid operators and electric utilities in each of the nation’s six deregulated energy markets have created a wealth of incentive programs to encourage commercial and industrial organizations to help integrate their grids with distributed energy.

CRE organizations with distributed resources at their facilities like backup generators, solar photovoltaic cells, fuel cells, energy storage and more are therefore in a position to reap significant financial benefits by working with a properly licensed company that can help them monetize their existing energy assets.

 

The Importance of Tenant Experience

No two commercial buildings are alike and every commercial real estate organization is unique. One trait CRE organization’s share, however, is the unwavering desire to provide a great experience for their tenants.

More and more commercial real estate companies are realizing that sound demand-side energy management–the practice of modifying consumer demand for energy–can play an integral part in providing a great tenant experience.

Without satisfied tenants, of course, the CRE industry wouldn’t exist. That’s why every measure a CRE organization explores concerning energy management should be examined through the tenant-experience lens.

 

Demand for Green Buildings

Utility costs related to energy, water, and waste have a significant impact on a CRE organization’s profits. For decades, CRE organizations have sought to reduce these impacts by making their buildings more efficient and (if at all possible) environmentally friendly.

Green buildings–those which are environmentally responsible and resource-efficient–are estimated to consume 30-50% less energy than non-green buildings. Green buildings also use an average of 40% less water, emit 30-40% less carbon-dioxide, and produce 70% less solid waste.

 

Green Buildings, Happy Tenants

In the last several years, CRE organizations across North America have recognized the direct correlation between green buildings and tenant attraction.

The increasing popularity of green leases, which include an up-front establishment of sustainability goals and allocation of implementation responsibilities between the owner and the tenant, is proof that the notion of sustainability is a value shared between CRE organizations and the tenants they serve.

Since the Great Recession, many tenants’ business performance has been and continues to be evaluated by customers and investors looking at aspects beyond the strictly-financial. Tenants want to tell the story of their operating in a green building that actively pursues sustainability efforts with a positive effect on the community and the environment.

CRE organizations who oblige will not only provide a superior tenant experience, they’ll also be in a position to monetize their efforts through demand-side energy management.

 

Energy Assets in the CRE Industry

CRE Organizations that have made their buildings more energy efficient–whether by lighting upgrades, HVAC improvement, or any other measure, may be eligible to earn money for the permanent reduction of their electric demand.

They may already possess energy assets like back-up generators, energy storage, solar generation, and more that can also earn revenue through demand-side energy management.

 

Getting started

When selecting a company to guide your demand-side energy management, it’s important to consider the company’s scope of demand-side expertise. Do they serve the markets where your properties reside? Does the company specialize in one type of demand-side energy management, or is it equally skilled in a wide range of energy asset monetization practices?

Most importantly, a demand-side energy management partner should earn your trust in every aspect of the relationship your organizations share.

Demand-side energy management is not a one-size-fits-all exercise. No two buildings are alike and every CRE organization is unique in its complexities.

Like your business, your demand-side energy management strategy should evolve and refine over time, forever in pursuit of perfection as energy markets continue to change and your needs as an organization evolve.

Visit https://cpowerenergymanagement.com/commercial-reit-lp to learn more about CPower’s extensive experience in the commercial real estate industry, including how Tishman Speyer Commercial Real Estate earned more than $1.4 million through demand-side management with CPower as their guide.

To read the entirety of “Monetizing Energy Assets in the Commercial Real Estate Industry: A Complete Guide for Earning Revenue with demand-side energy management” click HERE.