How Data Centers Can Strengthen the Texas Grid with Camus Energy CEO Astrid Atkinson

Astrid Atkinson, CEO and co‑founder of Camus Energy and a former Google reliability engineering leader, joined the Energy Capital Podcast to explain how lessons from cloud/data‑center scale operations can transfer to electricity distribution. Atkinson argues that as Texas sees rapid hyperscaler and industrial load additions, data centers can become a constructive force — offering site flexibility, batteries, or third‑party virtual power plant (VPP) capacity to accelerate interconnections, offset distribution upgrades, and create new revenue streams that flow back to customers. She emphasizes that the urgency from large loads (data centers are time‑constrained, not always budget‑constrained) creates a commercial opening to structure flexibility requirements into interconnection agreements and to develop secondary markets where large buyers bid for distributed flexibility.

A central technical and economic point in the conversation is that most of the value of distributed demand flexibility is not in short‑duration energy or ancillary services but in avoided or deferred T&D capital spend. Camus and AES co‑authored work found roughly three quarters of flexibility value shows up as capital deferral — i.e., delaying transformer, conductor, or substation upgrades across many feeders. That implies typical DR/ancillary payments (which compensate energy or brief system services) capture only a sliver of the system value; unlocking the larger pool requires visibility into distribution assets, new market structures or contracting approaches that pay for avoided CapEx, and regulatory allowances for utilities to recover spending on software and orchestration tools. In Texas, Atkinson notes ERCOT is taking steps — ADER pilot, a recent state‑wide DER monitoring software procurement — which matches her axiom: visibility before control.

On operations and control, Atkinson stresses layered, resilient design: local controllers (household, site) should be able to behave sensibly when disconnected from a central brain, while a distribution system operator (DSO) or utility‑level orchestrator coordinates aggregated flexibility. She cautions against overhyping LLMs for real‑time operations (they hallucinate); instead, the useful “AI” elements are forecasting, pattern recognition, probabilistic system modeling, and small models that fill data gaps. The practical blockers are organizational and regulatory: most utilities run legacy, on‑prem software with limited telemetry into rooftop PV, behind‑the‑meter batteries, EV charging, or C&I backup systems; regulatory rate structures still favor CapEx (rate base returns) over paying for O&M/software that would enable capital efficiency. Co‑ops and munis — vertically integrated, community‑focused entities — can move faster in some cases but are resource constrained and exposed to financial risk in extreme events (Yuri example). Atkinson highlights market design experiments — e.g., data centers bidding to buy down the cost of residential flexibility or paying residential participants directly — as promising ways to convert opportunity costs (delays in getting capacity) into local payments that improve affordability and defray T&D upgrades.

Implications: if policymakers, ERCOT, utilities, and large loads align on (1) deploying distribution visibility and control (software/tooling), (2) piloting market constructs that price distribution deferral value, and (3) embedding flexibility requirements in interconnection and permitting for large loads, Texas could add hyperscaler capacity faster while reducing long‑run rate pressure. The tradeoffs are real — regulatory change, new contracting forms (who pays who and how value is measured), and robust, audited automation to ensure physical equipment (transformers, feeders) stays within safe operating limits — but Atkinson argues these are tractable and urgent given the current pace of load growth.