Small modular reactors and microreactors are being pitched to commercial and industrial operators as the next frontier of on-site power — always-on, scalable, and free from grid dependency. But with over 100 SMR designs in development and only a handful of commercial contracts signed anywhere in the world, the gap between vendor pitch and operational reality is wide enough to strand a serious capital investment.

This is Energy Decision #21 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

- SMR vs. microreactor sizing thresholds — and why the distinction governs your procurement decision

- The four main reactor technology types and how to rank them by commercial readiness

- Why the SMR financial case rests on a manufacturing thesis, not a nuclear thesis

- HALEU fuel supply risk — the underappreciated constraint that could strand an advanced reactor investment

- How to evaluate vendor financeability and government subsidy dependency

- Operational staffing requirements and total cost of ownership for licensed nuclear facilities

- Deployment signals worth tracking: Eielson AFB, Rolls-Royce contracts, and the DOE pilot program

- The five diligence questions every C&I operator should ask before signing anything

Who this is for: facility executives, operations leaders, and energy decision-makers at large data centers, heavy manufacturing plants, remote industrial sites, and critical infrastructure operations who are evaluating on-site power independence at scale.

If you're trying to figure out whether micro-nuclear or SMR technology is a real near-term option for your facility — or whether you're being sold a pitch deck — this episode is built for you.

Read the full breakdown on Micro-Nuclear and Small Modular Reactors for C&I Power at tac-nrg.com

If you're an Indiana C&I operator actively evaluating a major energy project, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What are SMRs and microreactors?

1:30 – SMR vs. microreactor: sizing thresholds and what they mean for procurement

3:00 – The four reactor technology types ranked by commercial readiness

4:30 – Factory fabrication and why the financial case is a manufacturing bet

6:00 – HALEU fuel supply risk explained

7:30 – Vendor financeability and government subsidy dependency

9:00 – Staffing, operational flexibility, and total cost of ownership

10:30 – Deployment signals to watch and the diligence framework

C&I microgrids are one of the most consequential infrastructure decisions a commercial or industrial operator can make — and one of the most misunderstood.

This is Energy Decision #20 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

What a C&I microgrid actually is and how it differs from a backup generator. Why grid access has become a strategic constraint for new and expanding industrial facilities. How utility interconnection delays of two to five years are driving bridge power adoption. Demand charge arbitrage — how on-site generation during short peak intervals can reduce annual charges by hundreds of thousands of dollars. Battery energy storage systems (BESS) as the backbone of a microgrid's cost and resilience performance. Why diesel generators and synchronous rotating machines still belong in microgrid design. The role of AI-driven controls in predictive maintenance, load forecasting, and real-time dispatch decisions. Grid services revenue — how advanced microgrids generate income through market participation. Energy as a Service (EaaS) as a financing path that transfers operational and financial risk to a third party. Real barriers: interconnection complexity, upfront costs, cybersecurity, and the IEEE 1547 / IEEE 2800 standards gap.

Who this is for: plant managers, facility managers, operations executives, and CFOs at manufacturers, hospitals, data centers, educational institutions, and large commercial facilities who are evaluating whether on-site power generation is the right investment for their operation.

If you're trying to figure out whether a microgrid makes financial and operational sense for your facility — or whether you're already waiting on utility interconnection and need power now — this episode is built for you.

Read the full breakdown on C&I Microgrids at tac-nrg.com

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What is a C&I microgrid?

1:15 – Why grid access is no longer guaranteed for industrial customers

2:30 – The cost of downtime and the automation multiplier

3:45 – Demand charge arbitrage and the peak shaving opportunity

5:00 – Battery energy storage and why diesel generators aren't going anywhere

6:15 – Bridge power as an entry strategy

7:15 – Grid services revenue and Energy as a Service financing

Combined Heat and Power (CHP) and Cogeneration let facilities produce electricity and useful heat from the same fuel input, right at the plant. For the right sites, that can mean double‑digit energy cost reductions and a big boost in resilience during grid outages. For the wrong sites, it can turn into an expensive, under‑used asset. This episode walks through how to tell the difference.

This is Energy Decision #19 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

• What Combined Heat and Power (CHP) and cogeneration actually are and how they recover waste heat
• How total system efficiency can reach 60–80% versus roughly 50% for separate grid power and boilers
• Prime mover options: reciprocating engines, combustion turbines, steam turbines, microturbines, and fuel cells
• Why load matching between electric and thermal demand is the single biggest determinant of CHP success
• Core financial metrics: spark spread, heat rate, capacity factor, thermal‑to‑electric ratio, and payback period
• Capital cost ranges, regulatory hurdles, and stranded‑asset risk operators need to see up front
• A worked 5 MW university campus scenario with about a 3.3‑year payback and major resilience value
• A practical decision path for industrial manufacturers, hospitals, universities, data centers, and wastewater plants

Who this is for: plant managers, facility leaders, CFOs, and energy managers at industrial facilities, hospitals, universities, data centers, and wastewater treatment plants asking, “Should we invest in CHP to cut energy cost and improve uptime, or is this a distraction for our site?”

If you’re trying to decide whether to invest in a CHP system to reduce energy costs and enhance operational resilience, this episode is built for you.

Read the full breakdown on Combined Heat and Power (CHP) and Cogeneration at tac-nrg.com

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What CHP actually is and why people care
3:40 – Efficiency math and where the fuel dollars go
8:20 – Prime movers and matching CHP to your facility type
14:10 – Load match, spark spread, and when CHP makes economic sense
19:30 – Risks: capital, fuel, regulation, and stranded asset exposure
23:10 – University campus example and a clear decision framework

Virtual Power Plants are one of the most underused revenue opportunities available to commercial and industrial facilities today — and most operators have no idea their existing equipment already qualifies.

This is Energy Decision #18 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

— What a Virtual Power Plant actually is and how it works as a coordinated grid resource

— Which on-site assets qualify for VPP enrollment: HVAC, batteries, EV charging, industrial mechanical equipment, and plug loads

— The three grid service products a VPP sells — capacity, energy, and ancillary services — and why which ones your assets qualify for determines your compensation

— Why utilities and grid operators pay VPP participants: the Brattle Group cost comparison showing VPPs cost 40% less than a gas peaker plant

— The direct compensation structure versus the indirect bill effects for non-participating facilities

— Named aggregators operating in this market: OhmConnect, SunRun, Leap, Autogrid, Voltus, and Tesla

— The resilience value for facilities where downtime carries direct revenue loss

— How VPP enrollment connects to the regulatory foundation covered in Episode 8 on FERC Order 2222 and DER aggregation

Who this is for: plant managers, facility managers, and operations or finance executives at manufacturing plants, data centers, healthcare facilities, large retail operations, and educational institutions who are leaving direct compensation on the table by not enrolling existing on-site assets in a coordinated grid resource program.

If you're trying to figure out how to strategically participate in a Virtual Power Plant to maximize financial returns and improve energy independence, this episode is built for you.

Read the full breakdown on Virtual Power Plants at tac-nrg.com

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What is a Virtual Power Plant?

1:30 – Which assets in your facility actually qualify

3:00 – The three grid service products: capacity, energy, ancillary services

4:30 – Why utilities pay you — the Brattle Group cost math

5:30 – Direct compensation vs. indirect bill effects

6:30 – Aggregator landscape: who's operating in this market

7:15 – Resilience value for high-downtime-cost facilities

7:45 – How to evaluate VPP enrollment for your operation

Federal energy tax credits — the ITC, PTC, and Section 179D deduction — are among the most powerful financial levers available to commercial and industrial operators planning energy projects, yet most operators leave them on the table because they treat them as a tax department problem rather than a capital planning decision.

This is Energy Decision #17 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

- The three federal credit instruments and how they differ: ITC (installation-based), PTC (production-based per kilowatt-hour over 10 years), and 179D (deduction tied to energy cost reduction in commercial buildings)

- Who can claim the 179D deduction in 2025, including building owners and designers working on tax-exempt entity projects

- The 179D per-square-foot deduction math for 2025: $0.58 to $1.16 base, $2.90 to $5.81 with prevailing wage and apprenticeship compliance

- The 25% energy savings threshold and the three qualifying system categories: interior lighting, HVAC and hot water, and building envelope

- Why the prevailing wage and apprenticeship multiplier is a labor procurement decision that must be made before the project is bid

- ASHRAE Standard 90.1 baseline alignment and how the reference year affects your energy savings modeling

- OBBBA construction start and placed-in-service deadlines for solar and wind under Sections 45Y and 48E

- The 1.5 MW AC capacity threshold that determines which beginning-of-construction test you can use

- IRS Form 3468, the five-year in-service requirement, and recapture risk for ITC projects

- How 179D compounds the ROI on LED retrofits and HVAC upgrades already covered in this series

Who this is for: plant managers, facility directors, CFOs, and operations executives at manufacturers, commercial real estate operators, hospitals, schools, and municipal facilities who are evaluating capital energy projects and want to understand how federal tax credits affect project payback and go/no-go decisions.

If you're trying to figure out how to use the ITC, PTC, or 179D deduction to improve the financial case for an energy project you're already planning, this episode is built for you.

Read the full breakdown on Federal Energy Tax Credits (ITC, PTC, 179D) at tac-nrg.com

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What are the federal energy tax credits (ITC, PTC, 179D)?

1:30 – ITC vs. PTC: how the two credit structures differ

3:00 – Who can claim the 179D deduction in 2025

4:15 – 179D per-square-foot math and the 25% energy savings threshold

5:30 – The prevailing wage and apprenticeship multiplier: a 5x difference

6:30 – OBBBA construction start deadlines for solar and wind

7:30 – Documentation requirements and recapture risk under Section 48

Demand charges are one of the most significant and least understood components of a commercial and industrial electricity bill — and for many operators, they represent more than half of what they pay every month.

This is Energy Decision #16 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

Why reducing total energy consumption does not automatically lower your electric bill. The three charge types on every utility bill: fixed charges, energy charges, and demand charges. The difference between kilowatt-hours (kWh) and kilowatts (kW) — and why that distinction controls your costs. How the 15-minute interval measurement window determines your billing demand for the entire month. Why demand charges commonly exceed 50% of a C&I electric bill. Max/non-coincident demand, time-of-use demand, flat, tiered, and daily demand charge structures. How demand ratchets work — and how a single summer peak can determine your winter bills. Load shifting and load staggering as near-term demand management tools. Battery energy storage for peak shaving — when the math works and when it doesn't. The direction utilities are heading: residential demand charges, daily demand structures, and heavier TOU weighting.

Who this is for: plant managers, facility managers, operations executives, and financial leaders at manufacturers, hospitals, schools, municipalities, and large commercial facilities who are trying to understand why their power bill keeps climbing even when they're trying to cut usage.

If you're asking "why did my electric bill go up when I used less power" — this episode is built to answer that question.

Read the full breakdown on demand charges at tac-nrg.com

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – Why using less electricity doesn't always lower your bill

1:30 – What demand charges actually are

2:30 – kWh vs. kW: the distinction that controls your costs

4:00 – How the 15-minute peak sets your monthly billing demand

5:00 – Five types of demand charges you may encounter

6:30 – Demand ratchets: the summer peak that follows you into winter

8:00 – Load shifting, load staggering, and battery storage

9:30 – Where demand charges are headed

11:00 – Recap and questions for your team

12:30 – Energy Decision Blueprint

Cybersecurity for C&I energy systems and industrial control systems is one of the most underestimated operational risks facing manufacturers, hospitals, data centers, and utilities today — and it is getting more urgent, not less.

This is Energy Decision #15 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

Why OT security and IT security are fundamentally different disciplines with an inverted risk hierarchy. The IT/OT convergence problem and how every connected device expands your attack surface. The five structural vulnerabilities of ICS environments every operator needs to understand. HMI exposure data: 13% insecurely connected to the internet, 36% containing at least one publicly exploited vulnerability. Building management systems as an underestimated attack surface in hospitals, data centers, and manufacturing facilities. Advanced persistent threats including Sandworm and Volt Typhoon — and why a quiet network is not necessarily a safe network. The ICS security implementation sequence: asset inventory, exposure management, network segmentation, purpose-built threat detection, and zero trust remote access. Why exposure management is the rational budget allocation model when you cannot patch everything. Frameworks operators should know: the DOE/NIST/NERC Risk Management Process and CRISP. Why annual audits are insufficient and continuous assessment is non-negotiable.

Who this is for: plant managers, facility managers, operations executives, and C-suite leaders at manufacturers, hospitals, data centers, utilities, and critical infrastructure operations who are responsible for ICS environments and need to understand how to protect them without taking their operations offline.

If you are trying to figure out how to effectively implement and maintain cybersecurity measures that protect your energy systems and ICS from evolving threats while staying within budget and keeping operations running, this episode is built for you.

Read the full breakdown on cybersecurity for C&I energy systems and https://tac-nrg.com

If you are an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What is the difference between IT security and OT security?

1:30 – Why ICS environments became vulnerable: the collapse of the air gap

2:30 – The five structural vulnerabilities of industrial control systems

4:30 – HMI and building management system exposure: the numbers you need to know

6:00 – Advanced persistent threats: Sandworm, Volt Typhoon, and pre-positioning

7:00 – The ICS security implementation sequence

9:00 – Exposure management vs. vulnerability management: how to prioritize on a constrained budget

11:00 – Frameworks: the DOE/NIST/NERC Risk Management Process and CRISP

12:30 – Questions for your team and the bottom line

Battery Energy Storage Systems (BESS) for C&I peak shaving and resilience are among the most discussed — and most mismodeled — capital investments in commercial and industrial energy today. This is Energy Decision #23 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:

What a BESS system actually does for a C&I facility: peak demand charge reduction and backup power resilience. How utility-administered storage programs like NYSEG's Energy Storage Solutions program work — enrollment, event dispatch, and payment structure — and why the specific NYSEG figures are from a residential/small-business tariff that C&I operators should use as a structural reference, not a rate assumption. The two-layer capital stack: NYSERDA upfront rebates ($200/kWh standard, up to $400/kWh in Disadvantaged Communities for residential/small-commercial — larger C&I projects use a separate NYSERDA block structure) and NYSEG performance payments. Exactly how event performance and seasonal average compensation are calculated, with the worked $50-per-kW example. Where utility program revenue ranks in a C&I BESS pro forma — and why over-weighting it is a common and costly mistake. Hardware enrollment gating: why the battery you buy determines which programs you can access. Regulatory risk in ratepayer-funded programs and what it means for a 10-year financial model. How BESS connects to peak shaving strategy (Episode 11) and DER aggregation under FERC Order 2222 (Episode 8).

Who this is for: plant managers, facility managers, and operations or finance executives at factories, hospitals, logistics hubs, large commercial buildings, and schools who are evaluating whether a BESS investment will actually deliver the payback a vendor is promising.

If you're trying to figure out whether investing in a BESS for peak shaving and resilience is a cost-effective solution for your facility — and whether utility incentives actually move the needle — this episode is built for you.

Read the full breakdown on Battery Energy Storage Systems for C&I Peak Shaving and Resilience at tac-nrg.com/battery-energy-storage-systems-bess-c-and-i.

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tac-nrg.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

0:00 – What is a BESS and what does it do for a C&I facility?

1:30 – Peak shaving and demand charge reduction explained

3:00 – How the NYSEG Energy Storage Solutions program works

4:30 – NYSERDA rebates and the two-layer capital stack

6:00 – How event performance and seasonal compensation are calculated

7:30 – Where utility incentive revenue ranks in a BESS pro forma

9:00 – Hardware enrollment gating: battery brand determines program access

10:00 – Regulatory risk in ratepayer-funded programs

11:00 – Questions to ask before you sign a BESS proposal

Variable Frequency Drives (VFDs) are one of the most powerful tools operators have to cut energy use in motor‑driven systems and reduce mechanical stress on pumps and fans. This episode explains what a VFD actually does, where the cube‑law savings come from, and how to tell if a given motor or pump in your facility is a good candidate.

This is part of the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:
• Why electric motor‑driven systems often account for more than half of a facility’s electricity use
• What a VFD is in practical terms and how it sits between the grid and the motor
• The pump and fan affinity laws and why running at 80% speed can cut power to ~51%
• High‑value applications: centrifugal pumps, fans, compressors, cooling towers, air handlers, and wastewater systems
• Reliability benefits: eliminating water hammer, reducing inrush current, and lowering pressure stress on older piping
• Advanced features: integrated PID control, Dynamic V/f mode, common DC bus for regenerative power, and near‑unity power factor
• Limitations: when a VFD on a constant‑load motor increases consumption, inverter‑duty motor requirements, and harmonic issues
• A worked 60 hp fan example showing over $10,000/year in savings and a ~17‑month payback

Who this is for: plant managers, maintenance managers, operators, and energy managers in industrial manufacturing, water and wastewater treatment, commercial HVAC, and mining operations who are asking “how much energy does a VFD save” or “when does a VFD not make sense.”

If you're trying to decide whether to invest in Variable Frequency Drives to optimize your motor and pump operations for energy savings and equipment life, this episode is built for you.

Read the full breakdown on Variable Frequency Drives (VFDs) at tacticalenergygroup.com/variable-frequency-drives-vfds.

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tacticalenergygroup.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

Timestamps:
0:00 – Why motors are your largest hidden energy lever
3:15 – What a VFD actually is and how it controls speed
7:20 – The cube law: why slowing down saves so much power
11:40 – Where VFDs fit and where they do not
16:30 – Reliability, water hammer, and inrush current
20:15 – Advanced features, pitfalls, and 17‑month payback math
24:30 – Decision framework and questions for your team

LED Lighting Retrofits and Advanced Lighting Controls are one of the fastest ways for commercial and industrial facilities to cut hard operating costs by reducing lighting energy and slashing maintenance work. This episode walks through the retrofit pathways, the real ROI math, and how to decide whether you should do a simple lamp swap or a full fixture and controls upgrade.

This is Energy Decision #12 in the complete C&I energy management series from Tactical Energy Group. 100 decisions. Every one that matters.

In this episode, Daniel Burke covers:
• What an LED retrofit actually is and the differences between Type A lamp replacement, Type B ballast bypass, and Type C full fixture replacement
• Why LED luminaires are 75–90% more efficient and last 5–10 times longer than traditional fluorescent and HID fixtures
• How advanced lighting controls like dimming, high‑end trim, occupancy and vacancy sensing, daylight harvesting, and scheduling stack additional savings on top of the retrofit
• The role of Networked Lighting Controls (NLC) and Luminaire‑Level Lighting Controls (LLLC) in existing buildings
• FEMP and DLC efficiency and quality standards, including luminous efficacy benchmarks for troffers, linear ambient, and high‑bay/low‑bay fixtures
• A worked ROI example: $35,000 project cost, $19,360 annual savings, 1.81‑year simple payback, and 10‑year ROI north of 400%
• Utility rebates, Section 179D tax deductions up to $5 per square foot, and Lighting‑as‑a‑Service and performance contract options
• How to plan and phase installation to minimize disruption in warehouses, plants, schools, hospitals, and offices

Who this is for: facility managers, plant managers, operations leaders, and energy managers in commercial facilities, industrial plants, warehouses, educational institutions, and healthcare facilities who are asking “LED retrofit payback period commercial building” or “how to calculate energy savings LED replacement.”

If you're trying to decide whether your facility should invest in LED lighting retrofits and advanced controls to optimize energy spend and operational efficiency, this episode is built for you.

Read the full breakdown on LED Lighting Retrofits and Advanced Lighting Controls at tacticalenergygroup.com/led-lighting-retrofits-and-advanced-lighting-controls.

If you're an Indiana C&I operator actively evaluating this decision, get your free Energy Decision Blueprint at blueprint.tac-nrg.com.

Visit tacticalenergygroup.com for more practical tools and the Energy Decision Blueprint for qualified Indiana C&I operators.

Timestamps:
0:00 – Why LED retrofits are on every facility manager’s capital list
3:10 – What an LED retrofit actually is (Type A, B, C, hybrid)
7:25 – Where the money comes from: energy and maintenance
11:40 – Controls: dimming, high‑end trim, occupancy, daylight, scheduling, LLLC
17:20 – FEMP, DLC, and how to spec the right products
21:30 – ROI, rebates, 179D, and financing options
25:15 – Implementation risks, maintenance mindset, and decision framework