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Navigating The Challenges Of America’s Electric Grid

Following nearly two decades of relatively flat and predictable electric load growth across the United States, electric utilities are recalibrating load forecasts and resource planning activities due to an unprecedented increase in large-load investments. Grid operators like the Electric Reliability Council of Texas (ERCOT) are at a critical crossroads, warning that the demand for electricity is outpacing on-demand—or dispatchable—supply.1 Companies that do not effectively navigate this evolving landscape could find themselves in the dark.

The Federal Energy Regulatory Commission (FERC) releases a national 10-year winter electric load growth forecast each year. In 2023, the Commission predicted that 90 gigawatts of additional generation would be required by the year 2033, the equivalent of approximately 90 nuclear generation units. Not only is this an extraordinary level of growth, but the speed of growth is accelerating, with the 2023 forecast representing a 50 percent increase from the prior year’s projection.2 The main culprits? On the demand side, post-Covid reshoring strategies and significant federal incentives programs, such as the Inflation Reduction Act (IRA) and CHIPS and Science Act, are driving unprecedented investment activity in energy-intensive sectors, such as automotive, clean energy technology and semiconductors. Furthermore, data center deployments are quickly scaling beyond the hundreds of megawatts in electrical demand into the low gigawatts, driven by the proliferation of generative AI, cloud computing and machine learning needs across industries. Grid Strategies reports that large-load industries announced or plan to announce approximately $630 billion in domestic investments in the near-term.3 Increasing weather volatility also increases peak energy demand requirements as households and businesses heat and cool their buildings during increasingly common temperature spikes. These larger demand requirements may likely continue for decades as the electrification of America’s automotive fleet continues to add increasing demand to the national grid.

The challenges created by the significant increase in power demand are exacerbated by supply side disruptions. Regulatory requirements and customer preferences are driving a large-scale decommissioning of coal generation assets, which currently produce approximately one-fifth of our nation’s energy, according to the Environmental Protection Agency (EPA).4 The process to secure governmental approval, build and staff new power plants takes years, resulting in lagging generation to meet today’s demand. Natural gas combined cycle plants, which are among the most common power plants coming online today, typically take 30 months to build, as reported by Siemens, yet these projects often face hurdles as they run counter to utilities’ net-zero goals.5 In recent conversations with electric utilities across the United States, Deloitte learned that nuclear generation stations can easily require more than a decade to come online once site selection, regulatory approvals, technology validation, construction and startup testing are complete.6 Take the nation’s first newly constructed nuclear units in more than 30 years—Plant Vogtle Units 3 and 4—as an example. Unit 3 entered commercial operation in July 2023, approximately 15 years after an initial license application was submitted to the United States Nuclear Regulatory Commission. Startup testing continues on Unit 4, with an in-service date anticipated in the second quarter of 2024, according to a recent news released published by Georgia Power.7 Timeline considerations also extend to critical equipment. Substation components like transformers and circuit breakers are subject to three-year wait times, hampering utilities’ ability to quickly increase transmission capacity in critical locations. Collectively, these forces strain utilities’ ability to deliver clean, safe, reliable and affordable energy to the grid.

In this environment of comparative imbalance between electrical supply and demand—with no immediate relief in sight—many utilities are becoming increasingly selective in their support of large-load projects. In response, utilities are reserving sites with transmission capacity for projects that align with economic development goals, implementing demand side management strategies, such as curtailment on heavy power users, and pursuing capital intensive generation and transmission investments, which may eventually increase ratepayer costs.

What are the implications for corporate footprint planners? Location decisions have traditionally been driven by a combination of cost and operating condition factors that enable companies to succeed, including:

  • Competitive one-time and recurring costs
  • Skilled and sustainable talent pipeline
  • Favorable business climate
  • Proximity to suppliers and customers
  • Mitigated risk profile

For energy-intensive users, scalable and reliable utility infrastructure has traditionally been an important driver in the location decision calculus. Up until a few years ago, prospective investors would inquire about electric costs, service timelines and system reliability: What are one-time infrastructure costs? What is the average industrial kWh rate? How long will it take to extend transmission-level service to the site and construct a dedicated substation for the project? What reliability challenges has the system experienced in the past 10 years? Transmission and generation capacity—the ability to produce and move electrons on the grid—was not an imminent concern. Given the developing challenges in the market, increasingly sophisticated due diligence is often now a requirement to ensure that electric service solutions offered by local utilities will satisfy project needs.

Electric solutions are now critical success factors in the location decision—even in the presence of less favorable site attributes or operating conditions. The first question electric providers are often asked by prospective investors emphasizes transmission and generation capacity—in layman’s terms: Can you get sufficient power to our site in accordance with our project timeline?

But it is not just energy-intensive investors who must be prepared to ask electric providers more nuanced and in-depth questions regarding their service capabilities. Executives across all industries must sharpen their energy acumen and understand the many potential implications of the evolving energy landscape on their organizations, including costs, operational risks, renewable energy impacts and others. At a minimum, executives should prioritize understanding how pressures on the electrical system in their current operating locations may impact future decisions to grow and expand.

  1. Sonal Patel, “ERCOT Warns Demand Could Outpace Dispatchable Power This Summer,” POWER magazine, May 4, 2023 ↩︎
  2. North American Electric Reliability Commission, “2023 Long-Term Reliability Assessment,” December 2023. ↩︎
  3. John D. Wilson and Zach Zimmerman, “Addendum: The Era of Flat Power Demand is Over,” Grid Strategies, December 2023. ↩︎
  4. United States Environmental Protection Agency, “Electric Power Sector Basics,” last updated February 7, 2024. ↩︎
  5. Siemens AG, “Completion of world’s largest combined cycle power plants in record time,” July 27, 2018. ↩︎
  6. Deloitte Consulting interviews with electric service providers, Fall 2023. ↩︎
  7. Georgia Power Company, “Vogtle Unit 4 connects to electric grid for the first time,” March 1, 2024. ↩︎

Darin Buelow, Sarah Carnes and Chandler Greene

Darin Buelow is a principal in Deloitte Consulting’s Location Strategy practice and a founding member of the Site Selectors Guild. Sarah Carnes is a senior consultant in the Location Strategy practice at Deloitte Consulting LLP. Chandler Greene is a manager in the Location Strategy practice at Deloitte Consulting LLP.

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Darin Buelow, Sarah Carnes and Chandler Greene

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