As Kern County continues to lead California’s evolving energy landscape, Agilitech is proud to be part of the conversation shaping its future.

During Kern Energy Week, Agilitech’s Bo Jones, Renewable Project Developer, joined Mike Umbro of Californians for Energy and Science on KGET Studio 17 to discuss how integrated engineering and construction solutions are helping businesses navigate rising energy demands, improve resilience, and transition toward more sustainable operations.

From solar and battery storage to advanced infrastructure modernization, the message is clear: the future of energy in Kern County is not one-size-fits-all—it’s engineered, integrated, and built for performance.

Agilitech on Studio 17: Local Insight, Real-World Impact

In our Studio 17 segment, we highlighted how energy users across Kern County—from agriculture to industrial operations—are facing a rapidly shifting landscape:

• Increasing grid constraints
• Rising and unpredictable energy costs
• Growing demand for reliability and uptime
• Pressure to adopt cleaner, more sustainable solutions

Agilitech’s approach addresses these challenges head-on by delivering end-to-end solutions—from design and engineering to procurement, construction, and system integration.

This isn’t just about installing equipment. It’s about building energy systems that work smarter, last longer, and adapt faster.

Why Kern County Businesses Are Turning to Integrated Energy Solutions

Kern County has long been a cornerstone of the energy industry. Today, that legacy is expanding into a more diversified and resilient energy mix.

Businesses are increasingly investing in:

Solar + Battery Energy Storage Systems (BESS)

Pairing solar generation with battery storage allows facilities to:

• Reduce peak demand charges
• Maintain operations during outages
• Store and deploy energy strategically

Microgrids for Energy Independence

Microgrids provide localized control, enabling businesses to operate independently from the grid when needed—critical for uptime-sensitive operations.

Infrastructure Modernization

Upgrading legacy systems improves efficiency, safety, and scalability—while preparing facilities for future energy integration.

Agilitech brings these elements together into cohesive, fully integrated systems, eliminating the fragmentation that often slows projects and increases risk.

Built for the Way Kern County Works

Kern County’s industries don’t operate in controlled environments—they operate in real-world conditions:

• High heat
• Remote locations
• Continuous, heavy-duty demand cycles

That’s why Agilitech designs systems with durability, adaptability, and performance at the core.

Our experience across the broader energy sector uniquely positions us to deliver solutions that meet the operational realities of:

• Agriculture
• Oilfield and industrial facilities
• Commercial and manufacturing operations

From Energy Producer to Energy Innovator

Kern County isn’t just participating in the energy transition—it’s helping lead it.

Agilitech is proud to support that evolution by bridging traditional energy expertise with modern renewable and distributed energy solutions.

The result?
A smarter, more resilient energy ecosystem that supports both economic growth and long-term sustainability.

Watch the Studio 17 Feature

Catch our full conversation on KGET Studio 17 and learn how Agilitech is helping local businesses take control of their energy future.

Watch here

Let’s Build What’s Next

Whether you’re exploring solar, battery storage, or a fully integrated energy solution, Agilitech brings the engineering depth and field experience to deliver results—safely, efficiently, and at scale.

Connect with our team to start the conversation.

What CPUC ordered and why it is different this time

The order in plain terms

On February 26, 2026, in IRP proceeding R.25-06-019, the CPUC approved a decision that requires CPUC-jurisdictional load-serving entities (LSEs)—IOUs, CCAs, and ESPs—to procure additional clean resources for 2030–2032 reliability, while simultaneously transmitting updated base and sensitivity portfolios to CAISO for its 2026–2027 Transmission Planning Process (TPP). [7]

Key procurement elements that matter to customers:

The decision requires LSEs to procure 6,000 MW NQC total, delivered as 2,000 MW NQC by June 1, 2030, +2,000 MW by June 1, 2031, and +2,000 MW by June 1, 2032. [8]

Eligible resources must be non-emitting, storage, and/or Renewables Portfolio Standard (RPS)-eligible; fossil generation cannot be used to satisfy the obligation. [9]

At least one-quarter of each LSE’s obligation (collectively 1,500 MW NQC) must come from clean firm and/or long-duration storage by June 1, 2032. Clean firm is defined (via prior decisions) as ≥80% capacity factor and not use-limited, and long-duration storage is defined as 8+ hours at maximum capacity. [10]

The CPUC requires contract tenors of at least 10 years for resources counted toward this order—an important detail for long-term bill impacts and risk allocation in contracts. [11]

Capacity accreditation for compliance is explicitly tied to marginal ELCC studies: the CPUC plans to publish compliance ELCCs for 2030/2031 by July 31, 2026, and for 2032 by December 31, 2027. [12]

The order imports the prior “good faith” and enforcement architecture (including potential penalties and “backstop procurement”), and applies flexible compliance provisions if resources are under contract but delayed, consistent with prior procurement frameworks. [13]

The decision also flags rate-structure implications: IOU procurement under this order is subject to Power Charge Indifference Adjustment (PCIA) vintage treatment tied to the effective date, with related IOU advice letter actions. [14]

What is “new” or “different” in the framing

Load-growth as the central driver, not a generic decarbonization add-on

The CPUC explicitly grounds the procurement in the need to maintain reliability “consistent with forecasted demand growth.” [15] This is not rhetorical: allocation is based on load-forecast-driven metrics (managed peak contribution) rather than a flat statewide target. [16]

Why this matters: California institutions are now treating large-load growth as an operational planning reality. CAISO states that the CEC forecast expects data center load in the CAISO balancing area to increase by 1.8 GW by 2030 and 4.9 GW by 2040, and frames large loads (data centers, EV charging, industrial electrification) as drivers of material planning changes. [17]

Timing explicitly linked to federal incentives, and to evolving federal-policy risk

The decision states the procurement is intended (in part) to “pursue any viable projects that can still qualify for Federal tax credits or other incentives,” and the order directs attention to incentive timing as a real system-planning constraint. [18]

Notably, CPUC modeling assumptions in the decision explicitly incorporate federal-policy changes and assume wind and solar tax credits end for projects that fail to commence construction by July 4, 2026, while energy storage and clean-firm technologies retain eligibility through 2032 (with safe-harbor and phase-out concepts referenced). [19] This is a meaningful shift in how procurement urgency can be justified: the state is effectively signaling “build now or lose federal leverage,” especially for wind and solar under those assumed conditions. [20]

Portfolio guardrails aimed at “attributes,” not technology slogans

The 25% clean-firm / long-duration storage requirement mirrors an earlier lesson of California reliability planning: at high levels of solar and 4-hour storage, the system increasingly needs resources that can support reliability beyond narrow evening ramps. [21]

Importantly, the CPUC considered but ultimately removed a cap on storage that was in the proposed decision, explicitly stating it did not want to discourage longer-duration storage beyond 4-hour lithium-ion. [22] This is a subtle but important differentiator: rather than limiting storage volume, the decision pushes the market toward duration and firmness attributes by requiring a floor for LDES/clean firm. [23]

Transmission integration is not just a side memo; it is operationalized

The decision is explicitly bifurcated into “Power Supply” (procurement) and “Power Delivery” (transmission planning), with portfolios transmitted to CAISO for the 2026–2027 TPP. [24] This is aligned with the CPUC–CEC–CAISO 2022 Memorandum of Understanding (MOU) intended to tighten linkages among demand forecasting, resource portfolios, interconnection, procurement, and transmission planning. [25]

The fact sheet underscores that the 2026–2027 base case portfolio looks 15 years ahead and uses the CEC 2024 IEPR forecast, is larger than the prior year’s base case to account for higher load, and includes flexibility for offshore-wind timing (including asking CAISO to allow Humboldt transmission in-service dates to extend to June 1, 2036). [26]

Historical context and the demand outlook behind the order

California has been in “catch-up” procurement mode since the early 2020s

The February 2026 procurement order is best seen as the next step in a multi-cycle procurement trajectory—not an isolated event.

In D.21-06-035 (Mid-Term Reliability, 2021) the CPUC ordered 11,500 MW of new NQC to come online in 2023–2026, driven by reliability concerns, extreme weather risk, and replacement needs for retiring gas units and Diablo Canyon’s planned retirement. [27] Of that 11,500 MW, at least 2,000 MW was required from “long lead-time” resources, including 1,000 MW of long-duration storage (8+ hours) and 1,000 MW of clean firm resources. [27]

In D.23-02-040 (Supplemental MTR, 2023) the CPUC ordered an additional 4,000 MW NQC for 2026–2027, citing updated load forecasting suggesting higher demand, accelerating climate impacts, potential additional fossil retirements not anticipated in 2021, and the likelihood that long lead-time procurements would be delayed beyond 2026. [28]

The February 2026 order explicitly characterizes itself as continuing the “momentum of annual procurement activity” begun under these earlier MTR decisions. [29]

The demand outlook is no longer “flat load with incremental electrification”

Two planning inputs are especially consequential for interpreting the 6 GW decision:

The CPUC’s own 2026–2027 TPP analysis materials show that managed load grows by 157 TWh from 2024 to 2040, with ~80% driven by EVs, building electrification, and data centers, and that by 2040 EVs can represent 23% of total managed load, followed by building electrification (10%) and data centers (8%). [30]

CAISO’s 2026 issue paper frames large-load growth as a core system issue and cites the CEC’s forecast that data center load within CAISO grows 1.8 GW by 2030 and 4.9 GW by 2040, alongside broader electrification loads. [31]

The CEC’s data center forecast work is itself becoming more operationally relevant: CEC staff note plans to disaggregate data center load impacts to busbar to support CAISO transmission planning (a sign that “where load shows up” is becoming as important as “how much load”). [32]

Transmission planning is reacting to load growth, with long lead times baked in

Even before the February 2026 CPUC order, CAISO’s Board-approved 2024–2025 Transmission Plan states that load forecasts associated with building electrification, data center growth, and transportation electrification drive “significant reliability-driven needs,” including an increase in the year-over-year rate of peak demand growth from 0.99% to 1.53% (and in the Greater Bay Area from 1.22% to 2.14%, a >2,000 MW increase in the 2035 peak forecast versus the previous cycle). [33]

CAISO also emphasizes that recommended transmission projects are phased over lead times of up to eight to 10 years, underscoring why “procurement now for 2030–2032” is not necessarily early in California infrastructure terms. [33]

Technical implications that matter to customers

Capacity value is being operationalized through NQC and marginal ELCC

The order is measured in NQC, not nameplate MW, and explicitly ties compliance to marginal ELCC studies scheduled for publication in 2026 and 2027. [34] This matters because marginal ELCC is designed to represent the incremental reliability value of new additions to a system that already contains substantial renewables and storage. [35]

This choice has real portfolio consequences:

The CPUC’s marginal ELCC work used for filing requirements indicates that solar marginal ELCCs remain low across modeled years, while firm resource ELCCs are generally stable at ~85–90%, and storage ELCCs—high in the near term—can decline as storage saturates and critical hours spread. [36]

NREL’s synthesis of capacity-credit practice highlights why this is happening: ELCC (especially marginal ELCC) is meant to quantify the fraction of nameplate capacity that can be relied upon during critical periods, and marginal ELCC can decline as penetration increases—solar is a commonly cited example. [37]

A practical translation for customers: a megawatt is no longer a megawatt. Contracts and investments that only optimize for annual MWh or renewable branding can underperform on reliability value, especially in late-day and seasonal stress conditions.

Storage duration tradeoffs are becoming a system-planning issue, not just a project-design choice

The CPUC’s clean-firm / long-duration requirement is a direct response to an evolving reliability picture where the system’s “critical hours” can expand across both hours and seasons over time. [38] In CPUC modeling, even very long storage (e.g., 100-hour) can see declining marginal ELCC in certain future years due to multi-day energy constraints, charging constraints, and efficiency limitations—suggesting that duration alone is not a silver bullet if the system becomes broadly energy constrained. [36]

This is why the decision avoids a simplistic “cap storage” approach and instead sets an attribute floor while avoiding deterrence of longer-duration designs. [39]

Deliverability and transmission are inseparable from resource procurement

For customers, the “capacity” you pay for only protects you if it can be delivered where and when needed.

The CPUC explicitly transmits portfolios to CAISO for the 2026–2027 TPP, and the decision finds it reasonable to ask CAISO to reserve deliverability for resource categories like geothermal, LDES, out-of-state wind, and offshore wind. [13]

CAISO describes the tight coupling between CPUC portfolios, the CEC forecast, and CAISO transmission planning; it also notes that if a large-load interconnection request arrives after the demand forecast and portfolios are set, transmission owners may submit proposals into the TPP for ISO concurrence, focused on the transmission component of the interconnection. [5]

From a project-risk standpoint, CAISO’s own transmission plan makes clear that many transmission solutions have multi-year lead times (8–10 years for some projects). [33] This duration mismatch—fast-moving load growth versus slow-moving wires—drives a material portion of the “execution risk” customers will experience.

The order preserves regulatory flexibility—useful for the system, but a source of uncertainty for customers

The decision states that resources used for compliance must meet RA eligibility requirements in place at the time they are counted, effectively allowing future RA rule changes to flow through to this procurement order. [16]

This may be prudent system governance, but it is a real contract risk for customers and developers: a resource that looks “compliant” today may see its accredited capacity value or eligibility conditions change later, affecting economics and hedge performance.

Customer risk exposure and the “too little, too late” question

Rate impacts: more than “yes/no,” less than “the order drives everything”

The CPUC argues that planning ahead helps avoid expensive emergency actions and aligns procurement with transmission investments to avoid costly mismatches. [40] Those are credible benefits if the procurement is executed efficiently and if transmission keeps pace.

However, California rate trends are being driven by multiple large forces beyond this single order. The Legislative Analyst’s Office (LAO) reports that California’s residential electricity rates are among the highest in the U.S., and that from 2019–2023 average residential electricity rates rose about 47% statewide (with IOU increases ~48%–67%), driven by factors including wildfire-related costs and decarbonization investments; the LAO also flags growing demand and increasing climate-policy stringency as emerging rate drivers. [41]

For C&I customers, the key implication is: the order may modestly reduce the probability of acute reliability-driven cost spikes (e.g., emergency procurement), but it is unlikely to “shield” customers from rate increases altogether, given the broader cost stack (transmission investment, wildfire mitigation, system modernization, and the costs of firming a higher-renewables grid). [42]

Execution and delivery risk: customers ultimately pay for plans that do not always materialize

The decision itself recognizes stakeholder debate that procurement orders can burden ratepayers, interact with uncertain forecasts, and affect negotiating leverage. [43] It also embeds “good faith” and flexible compliance mechanics (and potential backstop procurement with cost responsibility allocated to customers of non-compliant LSEs), implicitly acknowledging that procurement and delivery risk is not hypothetical. [13]

From a customer-risk lens, this manifests in several ways:

Portfolio underperformance risk. If the market over-deploys resources that look “cheap per MW nameplate” but have low marginal ELCC, the system could still experience tightness in critical hours—even while large amounts of renewable energy are produced and curtailed at other times. The structure of the order (NQC/mELCC) attempts to manage this, but it cannot eliminate it. [2]

Local reliability and deliverability risk. System-wide procurement does not automatically produce capacity in constrained local areas, and transmission timelines can be long. CAISO highlights that forecasting, portfolios, and transmission approvals are coordinated, but significant upgrades remain necessary, with some projects requiring many years to complete. [44]

Regulatory-change risk. Because compliance depends on evolving RA eligibility and future ELCC studies, customers bear the risk that what “counts” today may shift, affecting contract value and cost recovery. [16]

Cost-allocation and “who pays” risk is becoming more explicit under large-load growth

For large-load businesses, the most strategically important risk may be cost allocation—especially transmission-level interconnection and “make-ready” infrastructure.

CAISO notes that load interconnections are led by utilities, and highlights PG&E’s proposed Electric Rule 30 for transmission-level retail customers; critically, CAISO states the CPUC approved interim implementation with the caveat that customers interconnecting under Rule 30 would cover full initial infrastructure costs while the CPUC evaluates cost causation and allocation. [5] CAISO further notes that differentiated service offerings (including non-firm/curtailable approaches) could accelerate interconnection timelines, but require careful operational and planning integration. [45]

Separately, the February 2026 procurement decision explicitly addresses that IOU procurement under this order will receive PCIA vintage treatment based on the effective date—an important consideration for customers evaluating CCA/direct access pathways and long-term departing-load cost exposure. [14]

Is it “too little, too late”?

The honest answer is: it is sized to one modeled need case, but California is managing a range of plausible futures.

In the procurement-need analysis reflected in the decision, the base scenario shows a planning capacity (PCAP) shortfall rising to roughly 2,300 MW (2030), 4,000 MW (2031), and 5,900 MW (2032); under an “increased data center load” sensitivity, the need modestly rises to about 2,544 MW (2030), 4,306 MW (2031), and 6,295 MW (2032)—which would exceed the ordered 6,000 MW by roughly 295 MW by 2032 in that sensitivity case. [46]

This is the critical nuance: the order is not obviously “too small” based on the base case, but it could be tight if load growth (including data centers) lands high, or if delivery risk causes slippage. [47]

Also, it is not designed to solve near-term (2026–2028) constraints directly—that was the role of the MTR and Supplemental MTR orders. In that sense, the order is “on time” for the early 2030s planning window, but the real question is whether procurement, permitting, interconnection, and transmission execution can keep pace with load growth trajectories that are accelerating now. [48]

Practical actions for large-load and C&I operators through 2032

The CPUC order is directed at LSEs—not directly at end-use customers. But customers are exposed through rates, service timelines, and reliability outcomes. The right playbook is to treat California load growth as a multi-year portfolio management problem—balancing (1) cost, (2) speed to power, (3) reliability/resilience, and (4) regulatory fit.

Comparative option table for C&I executives

The table below is intentionally pragmatic: it compares what C&I customers can do now to mitigate the risks that remain even if the 6 GW order succeeds.

Cost anchors for executive planning (for context, not a quote for any specific project): NREL’s commercial PV benchmarks cited in the ATB report system prices around $1.99/Wdc (2022) and $1.78/Wdc (2023). [53] NREL’s utility-scale battery storage projections cite a 2022 starting point of ~$482/kWh (2022$) for a 4-hour battery system and show a wide projected range by 2030. [54] Microgrid cost varies widely by design and how much existing infrastructure can be leveraged; NREL’s microgrid dataset shows commercial projects tended to be higher-cost on a $/MW basis than some other segments. [51]

Contracting and procurement moves that map directly to the CPUC order

If you are a large-load customer (or expect to become one), the February 2026 order changes the “best practices” for California energy contracting:

Treat capacity attributes as a first-class contract term. Because the CPUC order is explicitly NQC/marginal-ELCC driven (and because marginal ELCC for some resources can remain low), contracts that only emphasize renewable MWh may not hedge the risk you actually care about: tight critical hours. [2]

Demand “deliverability realism.” The CPUC is coordinating resource portfolios with CAISO transmission planning, but transmission projects can take many years, and deliverability is still a binding system constraint. [55] Your contracts should include development milestones, deliverability / interconnection status reporting, and remedies if COD or deliverability assumptions fail.

Scenario-test your load growth case against cost allocation pathways. CAISO’s large-load paper highlights that PG&E’s Rule 30 interim approach places full initial infrastructure cost on the connecting customer while broader cost causation is evaluated. [45] This has direct implications for campus expansions, data center developments, and electrified industrial projects: “utility will build it” may still be true, but “utility will pay for it” is increasingly uncertain.

Mermaid timeline and merit-order decision path through 2032

This timeline highlights two crucial realities embedded in the CPUC decision: (1) the state will continue refining the “capacity value” math through forthcoming ELCC studies, and (2) the procurement deadline is not the same as the infrastructure readiness deadline—transmission and interconnection lead times can be longer than typical corporate planning cycles. [49]

Executive-action checklist

Use this as a practical, board-ready checklist aligned to the risk envelope implied by the order.

Validate your load-growth story with engineering detail. Build a 5–10 year site-by-site forecast, then translate it into “critical hour” exposure (not just annual MWh). [56]

Quantify your “speed to power” risk. Engage the serving utility early to understand whether your project triggers distribution upgrades or transmission-level solutions—and what cost allocation regime could apply (including customer-funded initial infrastructure in some pathways). [5]

Re-contract for capacity attributes, not only renewable energy claims. Prioritize contract structures that explicitly address deliverability/interconnection milestones and that consider how RA eligibility and marginal ELCC can evolve. [57]

Build a demand flexibility layer before you build expensive steel. Demand response, automated shedding/shifting, and controls can be deployed faster than most infrastructure and can reduce the amount of capacity you must “buy.” [56]

Treat resilience as a separate investment thesis. If outage costs are material, microgrids and longer-duration onsite designs may outperform “grid-only” planning—even if they are not the lowest-cost energy option. [58]

Stress-test PCIA and cost-allocation implications of your LSE strategy. The CPUC decision’s explicit PCIA vintage treatment for IOU procurement under this order is a reminder that “who serves you” and “how costs are allocated” can matter as much as the commodity price. [59]

Endnotes and key document links

Endnotes

CPUC February 2026 decision and summary materials: the decision requires 2,000 MW NQC per year (2030–2032), defines the 25% clean-firm/LDES floor, sets 10-year contract requirements, schedules ELCC studies, and ties compliance to evolving RA eligibility. [60]

Load growth context and large-load integration: CAISO frames large loads as a planning priority, cites CEC data center growth forecasts, and documents evolving cost-allocation and service models (including Rule 30 interim customer-funded initial infrastructure). [17]

Demand forecast and drivers: CPUC materials attribute large future managed-load growth to EVs, building electrification, and data centers; the CEC’s data center forecast work describes methodology and indicates intent to support busbar-level planning. [61]

Transmission reality: CAISO’s transmission plan documents reliability-driven transmission needs tied to load growth and highlights multi-year lead times for major projects. [33]

Customer bill context: LAO documents rapid historical rate increases and identifies wildfire costs, decarbonization investments, and demand growth as key drivers. [41]

Capacity-credit fundamentals: NREL summarizes why ELCC (especially marginal ELCC) is used to quantify capacity value and why marginal capacity value of resources (notably solar) can decline with penetration. [35]

Mid-term procurement history: CPUC’s 2021 MTR order (11,500 MW NQC) and 2023 Supplemental MTR order (4,000 MW NQC) provide the direct procedural and policy precedent for the 2026 order. [62]

Key document links

CPUC Feb 26, 2026 decision (R.25-06-019):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K398/600398976.PDF

CPUC Fact Sheet (Feb 26, 2026 decision on procurement + transmission planning):
https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2024-2026-irp-cycle-events-and-materials/irp-tpp-decision-fact-sheet.pdf

CPUC news release (March 2, 2026) summarizing the decision:
https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-advances-clean-and-affordable-electricity-with-new-procurement-decision

CAISO Issue Paper: Large Load Considerations (Jan 2026):
https://www.caiso.com/documents/issue-paper-large-load-consideration-jan-20-2026.pdf

CAISO 2024–2025 Transmission Plan (Board-approved):
https://www.caiso.com/documents/iso-board-approved-2024-2025-transmission-plan.pdf

CEC 2025 IEPR Preliminary Data Center Forecast (Oct 2025):
https://www.energy.ca.gov/sites/default/files/2025-11/2025_IEPR_Preliminary_Data_Center_Forecast_ada.pdf

LAO report on California residential electricity rates (Jan 2025):
https://lao.ca.gov/reports/2025/4950/Residential-Electricity-Rates-010725.pdf

Industry coverage (PV Magazine USA; Utility Dive):
https://pv-magazine-usa.com/2026/03/17/seeing-shortage-california-seeks-6-gw-clean-power-capacity/
https://www.utilitydive.com/news/cpuc-california-lses-procure-6-gw-2032/813357/

[1] [7] [34] https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-advances-clean-and-affordable-electricity-with-new-procurement-decision

https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-advances-clean-and-affordable-electricity-with-new-procurement-decision

[2] [3] [11] [12] [13] [14] [16] [18] [19] [20] [22] [23] [29] [39] [43] [46] [47] [49] [52] [55] [57] [59] [60] https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K398/600398976.PDF

https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K398/600398976.PDF

[4] [8] [9] [10] [15] [24] [26] [40] https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2024-2026-irp-cycle-events-and-materials/irp-tpp-decision-fact-sheet.pdf

https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2024-2026-irp-cycle-events-and-materials/irp-tpp-decision-fact-sheet.pdf

[5] [17] [31] [45] https://www.caiso.com/documents/issue-paper-large-load-consideration-jan-20-2026.pdf

https://www.caiso.com/documents/issue-paper-large-load-consideration-jan-20-2026.pdf

[6] [33] [44] https://www.caiso.com/documents/iso-board-approved-2024-2025-transmission-plan.pdf

https://www.caiso.com/documents/iso-board-approved-2024-2025-transmission-plan.pdf

[21] [27] [62] https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/d2106035-mtr-decision-factsheet–07-01-2021.pdf

https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/d2106035-mtr-decision-factsheet–07-01-2021.pdf

[25] https://www.energy.ca.gov/sites/default/files/2023-01/MOU_Dec_2022_CPUC_CEC_ISO_signed_ada.pdf

https://www.energy.ca.gov/sites/default/files/2023-01/MOU_Dec_2022_CPUC_CEC_ISO_signed_ada.pdf

[28] [48] https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF

https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF

[30] [61] https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2024-2026-irp-cycle-events-and-materials/assumptions-for-the-2026-2027-tpp/26-27-tpp-pd-resolve-and-servm-analysis.pdf

https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2024-2026-irp-cycle-events-and-materials/assumptions-for-the-2026-2027-tpp/26-27-tpp-pd-resolve-and-servm-analysis.pdf

[32] https://www.energy.ca.gov/sites/default/files/2025-11/2025_IEPR_Preliminary_Data_Center_Forecast_ada.pdf

https://www.energy.ca.gov/sites/default/files/2025-11/2025_IEPR_Preliminary_Data_Center_Forecast_ada.pdf

[35] [37] Average and Marginal Capacity Credit Values of Renewable Energy and Battery Storage in the United States Power System

https://docs.nrel.gov/docs/fy25osti/89587.pdf

[36] [38] [50] [56] RCPPP Scope Considerations

https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2024-2026-irp-cycle-events-and-materials/reliability-filing-requirements_lses-2024-26_irp-plans_20260210.pdf

[41] [42] https://lao.ca.gov/reports/2025/4950/Residential-Electricity-Rates-010725.pdf

https://lao.ca.gov/reports/2025/4950/Residential-Electricity-Rates-010725.pdf

[51] [58] https://docs.nrel.gov/docs/fy19osti/67821.pdf

https://docs.nrel.gov/docs/fy19osti/67821.pdf

[53] https://atb.nrel.gov/electricity/2024/commercial_pv

https://atb.nrel.gov/electricity/2024/commercial_pv

[54] https://docs.nrel.gov/docs/fy23osti/85332.pdf

https://docs.nrel.gov/docs/fy23osti/85332.pdf

2025 in Review: A Market That Moved From Growth to Maturity

The past year has been a defining one for solar, energy storage, and distributed energy systems across the U.S., particularly in California. What was once considered mostly an environmental initiative is now being treated as core strategic infrastructure, shaping how businesses, especially commercial and industrial (C&I) facilities, plan capital investments, manage operating costs, and meet complex regulatory and reliability expectations. Looking back at 2025, several themes are clear: scale accelerated, storage became vital rather than optional, and solar solidified its role as an economic decision, not just an environmental one. These forces are evolving into new trends that leaders should be prepared to navigate in 2026.

Over 72 percent of planned grid additions through 2030 are solar, storage, or microgrid systems, showing how central these technologies have become to national energy planning. Solar and storage are no longer alternative energy; they are the backbone of modern energy infrastructure.

Storage also reached a major milestone:

• The U.S. now has over 104 GW of utility-scale battery capacity, serving industrial parks, campuses, and large energy users
• Commercial + industrial solar + storage capacity grew faster than residential in 2025, reflecting demand for demand-charge management and resilience
• Adoption of microgrids and hybrid energy systems expanded across campuses, manufacturing sites, critical facilities, and campuses with California leading deployment due to resilience requirements
• Manufacturing capacity for solar modules reached 64.8 GW, more than six times the growth seen two years ago, improving supply reliability for business-scale projects

For business and institutional energy users, 2025 wasn’t just about scale, it was about operational impact.

Commercial and industrial facilities increasingly paired solar with storage not only to reduce energy costs, but to manage peak demand charges, support resilience plans, and ensure continuity during grid disturbances.

In California’s challenging grid environment, microgrids and hybrid solar + storage systems moved from pilot projects into mainstream deployment, with facilities including campuses, industrial parks, and critical infrastructure leading adoption.

California’s Role: A Leader and a Learning Lab

California remains the nation’s largest solar market, with more installed capacity than any other state. Its significance goes beyond volume. The state is:

• A test bed for utility rate reform
• A leader in NEM/NBTD policy shifts
• Driving building electrification, microgrid adoption, and load flexibility
• Increasingly incentivizing energy storage as part of system design

Projects in California over the past year have addressed peak pricing dynamics, interconnection complexity, wildfire resilience, grid reliability, local permitting nuances, and corporate ESG priorities.

This has reinforced a key reality for 2026: solar alone is no longer the solution. The combination of solar, storage, smart controls, and microgrid design is becoming standard practice.

What Changed in 2025 That Buyers Should Pay Attention To

Based on our work with facility owners, developers, and operators, five shifts stood out:

1. Energy is now a board-level decision. CFOs and CEOs are increasingly involved in solar, storage, and microgrid planning, not just facility teams.
2. Resilience became operational necessity. Weather events, PSPS shutoffs, and grid constraints made many projects central to business continuity strategies.
3. Procurement conversations became more sophisticated. Buyers now ask about lifecycle costs, upgrade paths, modularity, serviceability, and microgrid integration, going well beyond price-per-watt.
4. Policy incentives became tangible. ITC, Inflation Reduction Act credits, and bonus incentives are now applied in active projects, not just on paper.
5. Domestic supply growth shifted the conversation from availability to performance. With more U.S. manufacturers now producing modules, batteries, and balance-of-system components, the question is no longer simply whether equipment can be sourced. The real differentiator in 2026 will be how well systems are designed, integrated, and supported across their lifecycle, particularly for commercial facilities and industrial microgrids where operational continuity matters.

2026 Outlook: Five Trends That Will Shape the Year Ahead

1. Solar plus storage microgrids as the standard design
   Systems integration is becoming the norm due to peak-shaving economics, demand charge management, backup power, and resiliency applications. Storage adoption is expected to grow significantly in commercial, industrial, and public sectors as early leaders demonstrate success to a growing audience
2. Focus on total project performance
   Buyers evaluate uptime, system integration, software and controls, service and support, and expandability for future load growth such as EVs and process electrification. Holistic design engineering is increasingly preferred over hardware installation alone.
3. Creative financing and deal structuring
   Transferable incentives, PPA variations, and tax credit adders will expand third-party ownership models, municipal and education sector access, and mid-market business participation.
4. EV infrastructure and solar integration
   As fleets electrify and charging infrastructure expands, solar plus storage supports load management, peak demand reduction, and facility planning.
5. California will continue to lead
   Policy updates, grid modernization, and climate-driven resilience will keep California at the forefront, influencing the adoption of microgrid-enabled C&I solar projects nationwide.

Implications for Executives and Decision-Makers

Facility owners, developers, and operators should consider:
• Exposure to rate volatility and demand charges
• Integration of resilience into risk management strategies
• Planning for future load growth, EVs, and electrification
• Sites where storage or microgrid integration could improve project economics
• Capturing ITC and other solar incentives still available to commercial and industrial projects

The most successful organizations approach solar and storage not simply as energy purchases, but as strategic infrastructure investments. As the chart above illustrates, electricity rates for commercial and industrial customers have steadily increased over the past decade, reinforcing the value of proactively managing energy costs. By integrating solar and storage into long-term planning, businesses can not only hedge against rising rates but also enhance resilience, optimize operations, and position themselves for future growth in an evolving energy landscape.

 

Kern County continues to stand at the center of California’s evolving energy landscape, and this year’s Kern EDC Energy Summit reinforced how pivotal the region will be in meeting the state’s future power needs. The Utilities Panel, featuring leaders from Southern California Edison (SCE), SoCalGas, and Pacific Gas and Electric Company (PG&E), offered a clear look at the challenges and opportunities ahead. Their insights point to a future defined by rapid infrastructure deployment, diversified clean energy resources, and proactive collaboration with commercial and industrial customers.

Agilitech was onsite to capture the perspectives shaping tomorrow’s energy environment. The following are the major themes and takeaways that will influence how businesses plan, invest, and operate in the coming decade.

Doubling the Speed of Grid Infrastructure Buildout

SCE highlighted one of its core priorities: accelerating the pace of grid capacity expansion. The utility is focused on improving power capacity density and deploying compact, using prefabricated substations that require only a fraction of the footprint and installation time of traditional infrastructure.

This acceleration is essential to support the surge in electrification, data center growth, and industrial development across California. SCE also emphasized the importance of leveraging customer side assets to better utilize existing infrastructure while maintaining affordability, with tools like Demand Response programs for EV charging stations.

For businesses, this signals a future where proactive planning and early coordination with utilities will be key to securing adequate power capacity.

Kern County’s Leadership in Renewable Gas and Future Hydrogen

SoCalGas underscored a point of regional importance: most of California’s renewable natural gas is produced in Kern County through biogas facilities across the San Joaquin Valley, such as CalBio and their dairy farm renewable gas plant.

Expanding this success will require open access, common carrier pipeline infrastructure that allows renewable gas and future hydrogen to move more freely throughout the state. SoCalGas shared that the technology to integrate hydrogen safely and effectively already exists, and the utility is working with regulators and policymakers to position Kern County as a hub for hydrogen enabled solutions.

For local businesses, this creates opportunities not only in clean fuel procurement but also in participating in emerging clean gas markets.

Nuclear Power and Large Hydro as Affordability Anchors

PG&E delivered one of the strongest messages of the panel. Diablo Canyon continues to generate 10 percent of the state’s electricity and remains California’s largest clean energy producer. Its output flows directly into Kern County through the Midway Substation, providing hundreds of millions of dollars in customer savings by supplying round the clock, carbon free baseload power.

With predicted load growth of more than 10 gigawatts by 2035 and 20 gigawatts by 2045, PG&E stressed the need for policies that support a diverse mix of clean energy resources, including nuclear and large hydro. This diversity is essential to maintaining affordability as the state electrifies transportation, manufacturing, and other sectors.

Planning Ahead with Customers

SCE also shared a meaningful shift in its customer engagement strategy. The utility no longer waits for businesses to submit load requests after development decisions have already been made. Instead, SCE now operates a dedicated team focused on early communication with customers and communities so they can plan infrastructure proactively.

This approach is particularly relevant for industries driving major new loads, including data centers. SCE noted that it is encouraging operators to consider distributing demand across multiple smaller sites to reduce strain on any single substation.

For Agilitech clients, this reinforces the importance of early utility communication in project planning and long term operational strategy.

Agilitech’s Take: A Call to Action for Business Leaders

PG&E closed the panel with a direct message to the business community: engage in the energy conversation. The utility encouraged leaders to advocate for common sense first energy policy, support diversified clean energy development, and gain firsthand understanding of grid infrastructure needs by visiting operating facilities.

Agilitech Renewable Project Developer, Bo Jones, echoed this message, emphasizing that Kern County’s future success depends on strengthening the conditions that allow utilities and private enterprises to build energy capacity at scale. Advocating for policy alignment, participating in industry dialogue, and supporting a mix of generation technologies are essential steps for businesses that want to drive competitive advantage through energy resilience.

What This Means for Businesses in Kern County

One theme came through clearly. The future of energy in California will require unprecedented collaboration. Utilities are investing. Policymakers are evaluating major shifts. Technologies are advancing quickly. Businesses that stay informed and engaged will be best positioned to manage risk, secure reliable power, and capitalize on opportunities created by this transformation.

At Agilitech, we are committed to helping businesses navigate complexity with clarity. Whether through custom solar and storage systems, microgrid strategies, energy planning, or EPC services, our focus remains consistent. We are dedicated to Powering Possibilities for clients across Kern County and beyond.

If your organization is evaluating its energy strategy in the face of growing grid pressures and policy complexity, let’s talk about how to Power Possibilities—custom solar + storage systems, microgrids, EPC services—all designed for commercial and industrial success in Kern County and beyond.

California’s energy landscape is changing—and not always for the better. Grid instability, driven by extreme weather, aging infrastructure, wildfire prevention shutoffs, and rising demand, has made power reliability one of the most pressing concerns for businesses.

For companies that depend on uninterrupted operations, the cost of a power outage isn’t just an inconvenience—it’s lost productivity, revenue, and customer trust. That’s where microgrid technology comes in.

At Agilitech, microgrids are more than a trend. They offer a transformative solution for California’s commercial and industrial sectors.

What is a Microgrid?

A microgrid is a localized energy system that can operate independently—or in parallel with—the traditional grid. Today’s microgrids integrates multiple energy resources, typically including:

• Solar generation to harness renewable power
• Battery storage to capture and deploy energy when needed
• Backup generation (such as natural gas or diesel) for mission-critical applications
• Energy Management Software (EMS) for real-time monitoring and load balancing

In short: a microgrid puts power back in your hands, giving you flexibility, resilience, and control.

If you’re a business leader in California facing unmanageable power costs, you are not alone. Many of our clients struggle to reclaim control of their operating costs when they first come to us for help.

What does it cost?

This is the biggest concern our clients share, but to their surprise, Microgrids after often much cheaper than staying on the grid. Every client’s needs are unique and Agilitech designs custom systems to optimize for maximum client value. If we can’t save you serious money, we tell you that upfront.

Institutional-grade financing services, previously only available to utility solar projects are part of our offering. We provide full project development and bankability reports and have a robust pipeline of capital standing by to help. There’s almost no project we can’t get off the ground.

 

Why Microgrids Matter in California

California is uniquely positioned to benefit from microgrid adoption:

• Wildfire-related Public Safety Power Shutoffs (PSPS): Businesses are left in the dark, sometimes for days at a time.
• Extreme heat events: Strain on the grid leads to rolling blackouts.
• High and volatile utility rates: Already among the highest in the nation, rates continue to climb.
• Sustainability mandates: Businesses are under increasing pressure to reduce carbon footprints.

In this environment, energy independence isn’t a luxury—it’s a competitive necessity.

 

The Business Case for Microgrids

Beyond resilience, microgrids create tangible financial advantages:

• Eliminate downtime: Every hour of lost power can cost thousands—or even millions—for manufacturers, farmers, hosptials, food processors, and other industrial applications.
• Utility savings: Microgrids optimize when and how you use energy, cutting peak demand charges.
• Return on investment: Projects regularly demonstrate 28%+ internal rate of return (IRR), with payback periods of just a few years. Agilitech clients average a 3.5 year payback period and amass millions in lifetime savings.
• Long-term stability: Hedge against unpredictable utility price increases by producing and managing your own energy.

 

Agilitech’s Role in California’s Energy Transition

As a full-service Engineering, Procurement, and Construction (EPC) partner, Agilitech brings utility-scale and over 20 years of expertise to the commercial and industrial (C&I) space. Unlike solar installers with limited capabilities, we design, engineer, and construct complete, integrated systems that align with your business goals.

Our approach includes:

• Customized design: Rooftop, carport canopy, and ground-mount arrays tailored to your site.
• Creative financing partnerships: Connecting clients with a suite of vetted caital partners for no-down-payment financing or power purchase agreements on systems of all sizes.
• Long-term reliability: Tier 1 equipment, O&M service, and a 10-year workmanship warranty backed by a company that’s been in business since 2002.

 

Looking Ahead: Microgrids as a Pillar of California’s Future

California is charting a path toward decarbonization and grid modernization. Microgrids play a central role—not only in ensuring reliability during disruptions but also in enabling the transition to a cleaner, smarter, and more resilient energy system.

For businesses, the question isn’t whether to pursue energy idependence—it’s when. Microgrids provide a proactive solution that protects your business today while positioning it for long-term resilience and sustainability.

Looking Ahead

Microgrids represent the next frontier of energy independence in California. By combining solar, storage, and smart control systems into an integrated self-sustaining system, they deliver resilience, cost control, and sustainability—all in one solution.

At Agilitech, we’re proud to be at the forefront of this shift, helping businesses across California build the energy systems of the future.

Ready to explore what a microgrid could mean for your business? Contact us to start the conversation.

Powering the Future: Agilitech’s Commitment to Energy Transformation

For over 20 years, Agilitech has been a trusted partner to Kern County’s energy producers, delivering innovative engineering solutions that drive efficiency, enhance sustainability, and ensure reliable operations. As the industry evolves, we are proud to support companies in their energy transformation—helping them adopt new technologies, reduce their carbon footprint, and maintain operational excellence.

Engineering Solutions for a Changing Industry

At Agilitech, we provide tailored engineering, construction, automation, panel fabrication services designed to help energy producers optimize their performance and stay competitive. From custom electrical systems to advanced automation and laser scanning, our solutions empower clients to increase efficiency, streamline operations, and meet evolving industry standards.

“We’ve spent more than two decades collaborating with Kern County’s energy leaders to deliver innovative, adaptable solutions. Our goal is to help companies successfully navigate today’s challenges while preparing for the future of energy.”
— Martin Alonzo, President & CEO

Supporting Energy Transformation

The energy landscape is shifting, with traditional oil and gas producers increasingly exploring renewable energy sources and greener technologies. Agilitech plays a vital role in this transformation by providing cutting-edge engineering expertise that helps clients integrate solar, battery storage, hydrogen, and biogas solutions into their operations.

Our comprehensive services—including turnkey electrical systems, maintenance, and regulatory support—enable energy producers to embrace new opportunities while maintaining safety, reliability, and compliance.

Rooted in Kern County, Focused on the Future

As a company deeply rooted in Kern County’s energy sector, Agilitech remains committed to driving local growth and innovation. By combining engineering excellence with a client-centered approach, we help energy producers adapt, thrive, and lead the charge toward a more sustainable future.

Watch the Interview:
Don’t miss Martin Alonzo’s exclusive interview on Studio 17 during Energy Week on March 18th. Learn how Agilitech is helping Kern County’s energy producers power possibilities, embrace innovation, and transform the future of energy.