Data Center onsite power generation, AESO analyst report, and more

According to a JLL Technologies report, data generation by consumers and businesses is set to double over the next five years. This will necessitate a significant expansion in storage capacities of data centers and endpoint devices, from 10.1 ZB in 2023 to an estimated 21 zettabytes by 2027. This growth projects a compound annual growth rate of 18.5% over the five years.

The report further highlights that leading data center operators are making strides in improving efficiency. Cloud, hyperscale, and colocation data centers are now operating at higher efficiency levels compared to traditional enterprise data centers.

A major point of focus is software-defined power. This approach to energy efficiency involves software interacting with electrical systems, facilitating functions like load shedding, load balancing, and server throttling. Based on a 2022 survey by the Uptime Institute, nearly half of data center operators expect these functionalities to significantly enhance data center efficiency in the coming five years.

However, the transition to sustainable energy isn't without challenges. High-performance computing and AI systems are power-hungry, placing considerable stress on data center energy infrastructure. While rooftop solar is a common source of on-site, low-carbon power, its output can fluctuate due to weather conditions, time of day, and seasonality, making consistent and reliable power supply a challenge.

In response to this, data center operators are exploring alternative power-sourcing strategies. These include small modular reactors (SMRs), hydrogen fuel cells, and natural gas.

Andy Cvengros , the managing director of U.S. data center markets at JLL, points out that with power grids nearing their limits and transformers having lead times of over three years, operators need to innovate.

Power purchase agreements are also gaining prominence as a key strategy for operators to fulfill their renewable energy commitments. A notable example is 亚马逊 's implementation of over 100 new solar and wind projects in 2023.

Power-related issues remain the leading cause of outages, as per Uptime's annual global survey. Understanding the causes of such outages, which include on-site power problems, cooling failures, software/IT system errors, and network issues, is crucial for prevention and for directing necessary investment. The survey also points to preventable human errors as a contributing factor in a large percentage of outages.

The most impactful and cost-effective way to reduce outage occurrences, as Uptime frequently maintains, is to improve management, planning, and training. This is supported by their 2022 survey findings, where nearly four in five respondents who had experienced an outage agreed that better management, processes , or configuration could have prevented their most recent impactful outage.

Analyst Report - AESO

Recap of Friday, February 2nd?through Sunday, February 4th

On Friday, prices were notably high in the afternoon and evening, averaging at $239.35/MWh for the day, and $317.45/MWh and $83.14/MWh for on and off-peak hours, respectively. Despite the demand being relatively low due to above-average temperatures, reaching just above 10,700 MW during peak hours, prices were still high. Wind generation decreased below 400 MW in the afternoon from over 1000 MW in the morning. Solar generation, affected by sunny weather in southern Alberta, rose above 750 MW between 10 a.m. and 2 p.m., then dropped after 4 p.m. Genesee #1 (GN1) and Genesee #2 (GN2) coal generators went offline at 09:26 a.m. and 09:29 a.m. while Sheerness #1 (SH1) gas generator came online at noon. The Battle River #4 (BR4) gas generator remained offline the entire day. The AB-SK intertie (path 2) returned to service at 03:12 p.m.

On Saturday, prices were low, averaging at $38.74/MWh, and $38.25/MWh and $39.72/MWh for on and off-peak hours, respectively. The demand was similarly low, peaking just above 10,900 MW. Wind generation rose to over 2,900 MW in the evening. Solar generation was above 150 MW between 10 a.m. and 1 p.m., then dropped after 4 p.m. due to cloudiness in southern Alberta. GN1 and GN2 coal generators returned online at 00:03 a.m. and 09:15 p.m. The BR4 gas generator remained offline all day. High wind generation resulted in prices below $50/MWh for most of the day.

Yesterday, high prices were observed in the evening and night, with a daily average of $162.59/MWh, and $224.24/MWh and $39.27/MWh for on and off-peak hours, respectively. The demand was relatively low due to average seasonal temperatures, peaking just above 10,700 MW. Wind generation gradually fell below 1,000 MW in the morning and then further to below 100 MW in the afternoon. Solar generation peaked above 300 MW between 12 p.m. and 3 p.m., then dropped due to cloudy weather in southern Alberta. GN2 coal generator went offline at 05:04 a.m. BR4 gas generator came online at 09:07 a.m., went offline at 10:57 a.m., and came back online at 02:15 p.m.

Expectations for today: Monday, February 5th

Today’s temperatures are expected to be slightly lower than yesterday's, potentially increasing demand. Wind generation is projected to remain below 100 MW for the day. Solar generation is expected to peak above 550 MW between 11 a.m. and 2 p.m., then drop after 4 p.m. due to partly cloudy weather. GN2 coal generator returned online at 03:25 a.m. Intertie imports are forecasted to exceed 400 MW for most of the day. Given these factors, prices are expected to be high in the late afternoon and evening.

Demand Response could have prevented blackouts in North Carolina

The North Carolina Utilities Commission recently released an order detailing the issues Duke Energy Corporation faced maintaining a stable grid during Winter Storm Elliott in December 2022. The storm coincided with unexpected power plant failures, gas pipeline issues, energy imports not arriving, and internal circuit controls failing. It was a close call to a large East Coast power grid failure. The real heroes, the line workers and field personnel, are only mentioned in a footnote.

Despite the crisis, Duke Energy’s fleet of options included almost no demand-side resources. During the storm, Duke Energy Progress (DEP) and Duke Energy Carolinas (DEC) only used 200 megawatts of demand response each, which is small compared to neighboring grid operator PJM which covers 13 states and the District of Columbia.

PJM has more than 30 curtailment service providers (CSPs), and over 2 million commercial and residential customers participate as load management resources. Their total installed load management capacity was 7,699 megawatts in 2022-2023. Over half of these resources could respond within 30 minutes. These CSPs delivered just under 10,000 megawatts of load reduction between 2 and 4pm on December 24. According to PJM's September 2023 Load Management Report, demand response resources performed exceptionally well during Winter Storm Elliott.

PJM's peak load on December 24, 2022 was 136,000 megawatts, according to its report on the event. DEP’s peak load on the morning of December 24 was 14,840 megawatts, and DEC’s peak load around the same time was 21,768 megawatts. DEP had to shed 800 megawatts of load by turning circuits off and on, DEC had to shed 1,000 megawatts. Duke Energy's combined peak load during Winter Storm Elliott is about 27 percent of PJM’s peak load during the storm. If Duke Energy had a proportionate amount of demand response capacity (PJM had 10,000 megawatts), they would have had at least 2,700 megawatts to use. But Duke didn't have this resource and had to shed 1,800 megawatts by turning circuits off and on, cutting power for hours to North Carolina customers. The numbers suggest that demand response could have prevented these blackouts.

In the NCUC's December 22 order, they didn't suggest that Duke Energy develop a more robust demand response program, even though these programs have proven to be cost-effective and reliable. The Commission focused on improving load forecasting, winterizing the fleet, improving gas-electric interdependencies, and required Duke to file reports on everything but demand response.

Distributed demand response can include aggregated battery storage and control of heating loads, water heating, and EV charging. Participants in these programs are compensated for performance, which can help ease the energy burden. Aggregation of these resources has been valuable in areas where grid operators make decisions about dispatchable assets. Winter Storm Elliott showed that aggregated demand response resources are reliable during winter peak demand when fossil resources fail. This reliability should be reflected in how utilities incentivize these resources.

Duke Energy's North Carolina utilities are required to achieve carbon reduction goals established by the state legislature in House Bill 951. Clean Energy Group filed its December 2023 report Distributed Energy Storage: The Missing Piece in North Carolina’s Decarbonization Efforts in the Duke Energy Carbon Plan Integrated Resource Plan comments docket. This report was designed to provide policymakers and advocates with the information they need to maximize the potential of distributed battery storage as a demand response tool. Developing a robust portfolio of demand-side resources in North Carolina is crucial to meeting the challenges of load growth while achieving North Carolina's Carbon Plan goals.

We at Arcus Power Corp are constantly providing insights and critical information in the energy sector. We invite you to go through our website arcuspower.com to learn more or schedule a meeting to get a free demo of our platform.