Chapter 3. Co-Located Generation

Introduction

Co-located electric generation involves the deployment of power generation assets directly at or adjacent to a facility with significant electrical demand. This configuration is particularly advantageous for large industrial loads, data centers, and critical infrastructure, where power quality, reliability, and cost control are paramount. By generating electricity on-site, these facilities can reduce exposure to grid disturbances, avoid transmission and distribution losses, and optimize energy procurement strategies. Additionally, co-location enables tighter integration between thermal and electrical systems, particularly in combined heat and power (CHP) applications, improving overall system efficiency.

The enabling technologies for co-located generation are centered around distributed energy resources (DERs) and advanced microgrid control systems. These systems coordinate the operation of on-site assets such as gas turbines, reciprocating engines, solar PV, and battery energy storage systems (BESS), while managing real-time interactions with the utility grid. Microgrid controllers provide autonomous operation during islanding events and facilitate seamless transitions between grid-connected and islanded modes. Integration with energy markets—via demand response, ancillary services, or real-time pricing—requires robust communication protocols, forecasting algorithms, and optimization engines to ensure economic dispatch and regulatory compliance.

From a technology readiness perspective, co-located generation systems have matured significantly, with many components now commercially viable and field proven. Advances in power electronics, control algorithms, and distributed system architectures have improved system stability, scalability, and interoperability. Recent developments in AI-driven energy management systems and predictive maintenance tools are enhancing operational efficiency and reducing downtime. Looking ahead, improvements in long-duration energy storage, nuclear small modular reactors, hydrogen-based generation, and grid-interactive inverters are expected to further expand the capabilities and value proposition of co-located generation.

To support economic evaluation, a Levelized Cost of Energy (LCOE) calculator can be applied to co-located generation systems to provide a consistent basis for comparing technologies with different operating characteristics. The calculator incorporates key inputs such as capital expenditures, fixed and variable operations and maintenance costs, fuel expenses, financing terms, asset lifetimes, and capacity factors to determine a standardized cost-per-megawatt-hour metric. For combined heat and power applications, the LCOE must also consider the value of the heat streams.  By integrating sensitivity analyses for factors such as fuel price volatility, capacity factor variability, and capital cost uncertainty, the tool allows stakeholders to assess a range of scenarios on equal footing. This approach not only supports technology selection, sizing, and control strategy decisions, but also clarifies the trade-offs between higher initial investments and long-term operating costs.

1 Deployment Schedule

The schedule for new on-site generation has advantages and risks compared to trying to acquire new generation from the general grid. Understanding potential roadblocks upfront is crucial for realistic project planning and successful execution.

Successful generation deployment hinges on proactive planning, early engagement with all relevant stakeholders and authorities, meticulous risk management, and a robust understanding of the potential schedule impacts at each phase. Table 3.1 outlines the ideal deployment schedule for co-located generation project, along with approximate time frames and key factors influencing each stage with a total timeframe of 2 to 5 years.

Table 3.1. Approximate Deployment Schedule for Co-Located Generation

Phase /Step	Approximate Time (Months)	Key Schedule Drivers /Potential Delays
1. Development Phase	3-18+ months	Development time frames vary significantly since part of the early-stage work screens for feasibility and may wait on land control, permissions, or risk factors to get resolved.
Feasibility & Siting	1-3	Site availability, initial technical/economic assessment.
Site Control	3 -18	Acquiring legal use of the land through purchase or lease
Environmental Studies	3-18	Scope of studies (e.g., ecological, archaeological, wetlands), public comment periods, need for mitigation.
Interconnection Prelim Study	1-6	Utility response times, initial grid capacity assessment.
DoD Permission	6-18+	Proximity to military installations, national security reviews, specific documentation requirements, multi-agency coordination.
2. Preconstruction Phase	12-36+ months	Often overlaps significantly with Development and Procurement
Detailed Engineering	4-8	Project complexity, vendor data availability, iteration cycles with permitting bodies.
Construction Permitting	3-12	Local jurisdiction variability, completeness of application, public hearings, zoning changes, review times, required design modifications.
Interconnection Agreement	12-30+	Utility queue length, complexity of grid impact studies (System Impact Study, Facilities Study), required grid upgrades, negotiation of agreement terms and costs, utility internal processes. Often the longest single item.
Fire Marshal Permission	3-9	Familiarity of local fire department with co-located generation, adherence to NFPA codes, detailed fire safety plans, emergency response protocol review, specific local code interpretations, potential for required design changes or testing.
Environmental Approvals	3-18	Specific permit requirements (e.g., air, water), regulatory agency review times, public comment periods, new findings from studies.
3. Procurement Phase	6-18+ months	Driven by longest lead-time equipment; can overlap with Preconstruction and Construction
Vendor Quotes & Qualification	2-4	Quotes for materials and services. Due diligence, technical review, financial assessment of suppliers.
Equipment Acquisition	6-48	Global supply chain issues, raw material availability, equipment production queues, manufacturing capacity, shipping logistics, customs.
4. Construction Phase	6-18 months	Project size and complexity, civil works requirements, weather delays, labor agreements (negotiation time upfront, potential for disputes during), coordination of trades, equipment delivery logistics, ongoing construction permitting inspections (failed inspections cause delays).
5. Commissioning Phase	2-6 months	Utility witness requirements, complexity of grid integration, interconnection testing results (re-testing if issues found), performance testing, software and controls integration with existing facility systems, bug fixes, final Fire Marshal inspection and approval to energize.
Total Project Duration	24-60+ months	Note: These are approximate ranges and vary significantly. Overlapping steps are common to compress the overall timeline.

Development

This foundational phase involves identifying the need for co-located generation, assessing its technical and economic feasibility, selecting a suitable site, and developing a conceptual design. One of the earliest and most critical aspects here is environmental studies. If the chosen site is near sensitive ecosystems, wetlands, or historical/cultural sites, extensive studies (such as environmental impact assessments, ecological surveys, or archaeological reviews) become mandatory. These studies can be lengthy, involve public comment periods, and may necessitate design modifications or mitigation measures, leading to significant delays. Simultaneously, initial permitting research is vital to understanding local, state, and federal permitting requirements, including land use, zoning, and safety regulations. Overlooking specific local ordinances can cause rework and delays later in the process. An initial interconnection assessment with the utility is also essential to gauge grid capacity and requirements; unexpected limitations or necessary upgrades can drastically alter the project’s scope and financial viability. Furthermore, if the project is located near military installations or involves airspace considerations, engaging with the Department of Defense (DoD) early for permission or clearances is necessary. This can be a protracted process due to national security concerns and requires specific documentation.

Permitting and Regulatory Approvals

The permitting process involves securing a range of formal approvals, often from multiple agencies.  Depending on the technology used, Environmental permits may include air quality and water discharge authorizations, as well as compliance with the Endangered Species Act (ESA). [1] Any new findings or changes in regulations can extend the permitting timeline. Construction permitting is frequently a major bottleneck, as obtaining approvals from local authorities—such as building, electrical, and civil departments—is typically time-consuming. Requirements vary significantly by jurisdiction, and incomplete applications, unexpected site conditions, or insufficient documentation often result in repeated submissions and frustrating delays.

An archaeological survey, required under Section 106 of the National Historic Preservation Act (NHPA), identifies cultural resources such as artifacts or historic structures prior to construction. These surveys typically take 2 to 5 weeks, but timelines may extend if significant findings are discovered. [2]

A habitat and wildlife survey, conducted under ESA Section 7, assesses ecosystems, vegetation types, and the presence or potential presence of protected or sensitive species within the project area. Depending on factors such as endangered species, seasonal migration, and breeding cycles, these surveys can take anywhere from 6 to 24 months. They are often essential for environmental compliance under federal or state conservation laws.

Air Permits are required for generators producing combustion emissions.  Emissions are subject to stringent regulatory limits that vary by jurisdiction, often defined by federal, state, and local air quality management agencies. In the United States, for example, the Environmental Protection Agency (EPA) classifies diesel engines under emissions Tiers (e.g., Tier 1 through Tier 4 Final) based on their pollutant output, with Tier 4 Final representing the most stringent standards for NOₓ and PM. [3]  Air permits are issued through the State environmental agency, such as the Texas Commission on Environmental Quality (TCEQ). [4] Compliance with these emissions tiers is not optional and must be matched to the plant’s location and permitting requirements.

Before any earth-disturbing activities begin, developers must submit a Stormwater Pollution Prevention Plan (SWPPP) and a Notice of Intent (NOI) to the EPA and relevant state agencies at least 14 days in advance. Preparing these documents typically takes 1 to 3 weeks, depending on site complexity. Jurisdictions with impaired waters or tidal zones may require additional review, adding 2 to 6 weeks. After final stabilization, a Notice of Termination (NOT) must be submitted, which can take up to 4 weeks to complete. The total process generally spans 2 to 4 months. [5]

If fuel storage or delivery infrastructure could impact sensitive areas like streams, wetlands, or aquifer recharge zones, site assessments may be required. For example, under the TCEQ’s Edwards Aquifer Protection Program, activities in recharge, transition, or contributing zones must submit an Edwards Aquifer Protection Plan (EAPP). These plans outline best management practices to prevent contamination, including secondary containment for above-ground storage tanks and spill reporting protocols. Administrative reviews typically take up to 30 days, while technical reviews for complete applications may require up to 90 days. [6] However, timelines can extend to 6–12 months for ecologically complex sites. Additional air permitting requirements under 30 TAC Chapter 116 may also apply, potentially adding 2–4 months to the timeline depending on emission levels and facility type. [7]

Coordination with the State Department of Transportation may also be necessary. Projects must secure permits for oversize/overweight loads, approved haul routes, and traffic control plans. Access roads may require evaluation for heavy equipment, with reviews and approvals generally taking around 30 days depending on load size and route complexity.

For sites near military installations or within restricted zones, Department of Defense (DoD) and Federal Aviation Administration (FAA) review may be required to assess potential impacts on mission readiness, flight paths, or communication systems. This involves submitting detailed site plans and conducting obstruction or electromagnetic interference studies if applicable. Reviews typically take 30 to 60 days but may extend based on proximity to sensitive operations.

Several new policies were enacted in 2025 that give the Department of the Interior (DOI) greater power over projects located on Federal Lands, needing rights-of-way through Federal Lands, located in migratory bird paths, or potentially affecting the nations commerce, infrastructure, or use of resources.  The new 2025 policies were stated by the Presidential Administration to specifically block additional wind and solar projects. [8]

Fire Marshall approvals require early and ongoing coordination with local fire departments. This includes adherence to NFPA codes, submission of detailed fire safety plans, emergency response protocols, and potentially controlled fire testing. Approvals may depend on specific ventilation, suppression, and setback requirements, which could necessitate design changes. Developers must submit site plans showing fire department access routes, hydrant locations—typically within 150 to 200 feet of key equipment—and staging areas for emergency response. Plans must also detail fuel gas infrastructure, including piping, shutoff valves, and separation distances from ignition sources. These are reviewed for compliance with NFPA 850 and local amendments, with approval timelines generally ranging from 30 to 60 days.

City code offices require comprehensive plan reviews covering site layout, structural supports, and utility connections. Applicants must demonstrate zoning compliance and submit separate permit applications for civil, mechanical, and electrical disciplines. Review timelines typically range from 3 to 6 weeks, with inspections required at key phases such as grading, utility tie-in, and final commissioning.

Interconnection

The electrical interconnection agreement process with the utility grid is notoriously complex and a significant source of delays. This involves detailed studies (e.g., system impact studies, facilities studies) to determine the effect from the project on the grid and identify necessary upgrades. Utility queues can be multiple years long, and the cost and timeline of required grid upgrades can cost millions of dollars. The unique operational attributes of co-located generation and microgrids are not always well-accounted for in existing interconnection processes, potentially leading to undue burdens. However, most utilities are developing better processes.

The general large generator interconnection process begins with the Pre-Application Stage, where developers assess the technical and economic feasibility of their project and identify potential interconnection points on the grid. Common challenges at this stage include limited access to grid data, high anticipated costs, difficulty securing site control, and regulatory or technical uncertainty.

Next is the Application Stage, where developers submit a Generation Interconnection Request (GIR) to the appropriate grid operator, and receive a queue position that determines the order of processing. Challenges during this phase are that the project developer must submit information for specific equipment in the study, however, the developer cannot lock in that equipment until a procurement agreement is in place, which is waiting on the results of the study.  And, in the lengthy period of time that the study takes place, vendors may have updated offerings, and so in the information that was used in the study is outdated.  So often the project then requires a re-study and further delays the process.

The Study Stage follows, involving a System Impact Study to evaluate the project’s effect on grid reliability and stability, and a Facilities Study to design any necessary grid upgrades. Cost allocation is also determined during this phase. Developers may face challenges such as design or equipment changes triggering restudies, other projects entering the queue affecting outcomes, and upgrade costs exceeding expectations.

During the Interconnection Agreement Stage, parties sign a Study Agreement outlining the scope, schedule, and cost of studies, followed by a Generator Interconnection Agreement (GIA) that formalizes technical, financial, and legal terms. Regulatory or policy changes at this stage can impact project economics or timelines.

The Construction and Testing Stage includes metering and registration with the grid operator, construction of the power plant by the developer, and completion of grid upgrades by the utility. Testing and commissioning ensure the project meets technical standards, followed by regulatory review to verify compliance with the GIA. Once approved, the project reaches its Commercial Operation Date (COD), allowing it to begin feeding electricity into the grid. Delays due to permitting, financing, engineering, procurement, construction (EPC), or supply chain issues are common challenges here.

Finally, in the Commercial Operation Stage, the power plant synchronizes with the grid, begins participating in the electricity market, and submits performance reports and operational plans to the grid operator.

 

Procurement

This phase is dedicated to ordering and securing all necessary equipment and materials for the project. Supply chain issues can severely impact the procurement of critical components. Geopolitical factors, raw material availability, manufacturing capacity, and shipping delays can extend lead times by months or even years, impacting the overall project schedule and cost. It’s crucial to identify and order long-lead time equipment, such as transformers, as early as possible, as they can have lead times exceeding a year or even several years. The process of vendor qualification and ensuring their products meet technical specifications and safety standards can also add considerable time to this phase.

Selecting the right EPC (Engineering, Procurement, and Construction) team is a critical decision in the success of a co-located electric generation project, particularly for large-scale or mission-critical facilities. The EPC partner directly influences the project schedule, cost certainty, and long-term performance of the system. Delays in procurement, permitting, or construction can significantly impact operational timelines and financial returns, making schedule adherence a top priority. Some EPC firms specialize in specific technologies—such as CHP systems, solar-plus-storage, or gas turbine integration—so aligning their core competencies with the project’s technical requirements is essential for optimal outcomes.

Selecting the right team structure is critical based on the project sponsor’s capabilities and goals and there are several contract methodologies for large projects. [9]  Large company sponsors that have well managed expertise in-house for procurement, engineering, project management, quality control, commissioning, and operations can benefit from efficiencies that reduce overall project cost.  Alternatively, a project sponsor may find better value in relying on the expertise of outside partners and turn the project over to a prime EPC to handle the project entirely.  In rapidly changing environments, expertise evolves quickly and is difficult to maintain, so partner selection should prioritize current capabilities over past performance.

Another key consideration is the type of service model offered by a vendor or installer. Some contractors provide full lifecycle support, including operations and maintenance (O&M), while others operate under a “build and leave” model, transferring all responsibilities to the owner post-commissioning. The choice between these models should align with the owner’s internal capabilities and risk tolerance.  A firm with a strong service base can offer long-term reliability and performance guarantees, which are especially valuable for facilities with limited in-house energy management expertise.

When evaluating contractor candidates, it’s important to look beyond price alone. While cost competitiveness is important, it must be weighed against the contractor’s track record for delivering on schedule, their ability to manage complex interconnection and permitting processes, and their experience with similar project scopes. A low-cost bid may come with hidden risks such as change orders, delays, or underperformance. Conversely, a slightly higher-cost contractor with proven reliability and technical depth may deliver better value over the system’s lifecycle.

Ultimately, the ideal partners should demonstrate a strong understanding of co-located generation systems, offer transparent project management practices, and have a verifiable history of delivering similar projects on time and within budget. Owners should prioritize firms that can integrate technical excellence with schedule discipline and offer flexible service models that align with long-term operational goals.

As of 2025, several Engineering, Procurement, and Construction (EPC) firms are recognized as leaders in delivering co-located electric generation projects, particularly for large-scale industrial and commercial loads. There are many companies known for their expertise in integrating distributed energy resources, microgrid systems, and grid-interactive technologies. These firms are often selected for their ability to manage complex, multi-technology projects and their familiarity with regulatory, interconnection, and market participation requirements.

Construction & Start-Up

This phase marks the beginning of physical construction for the co-located generation facility, starting with site preparation, progressing through component installation and concluding with commissioning and commercial operation. For large-scale projects, especially those in locations with strong labor unions, labor agreements—such as Project Labor Agreements (PLAs)—can significantly influence the schedule. PLAs help ensure a stable, skilled workforce and minimize labor disputes, but negotiating them can add complexity and time upfront. In their absence, workforce availability issues or disputes may arise during construction, potentially causing delays.

Throughout construction, regular inspections by local authorities—including building, electrical, and fire officials—are required.  A final inspection by the Fire Marshal is required to confirm that all fire safety systems are installed and functioning according to approved plans before the system can be energized.  Failed inspections due to non-compliance or unforeseen site conditions can halt progress until issues are resolved.

Every large project finds the need for changes during construction from challenges such as adverse weather, unexpected ground conditions, engineering omissions, equipment or logistical delays, or even adjustments to project objectives.  Projects managed with an efficient process for making Change Orders to all of the major contracts will prevent major delays.  Change Orders that are structured to preserve the financial solidity of the project without taking advantage of vendors and contractors ensures faster resolutions and quality continuity of work.

Software and controls integration is critical to ensure the generator control system communicates effectively with the facility’s energy management system and utility protocols.  Projects implementing software, especially newly developed software, after the plant is built without prior testing can expect up to a year in delays to work out bugs and get the system tuned in.  Testing and tuning software on a digital twin, or software in the loop, in parallel with the construction schedule speeds up the process for integrating the software into the constructed system.

After construction is complete, commissioning begins with rigorous testing of all systems and components to ensure proper operation and seamless integration with both the facility’s infrastructure and the grid. Utility interconnection testing verifies grid synchronization, safety protocols, and operational compliance. Any issues discovered may require re-testing or adjustments, extending the commissioning period. Performance testing confirms that the system meets specified guarantees such as capacity, efficiency, and response time.

2 Operational Capabilities

When evaluating co-located generation technologies for large-scale or mission-critical applications, operational characteristics are as important as capital cost and efficiency. The ability of a system to respond dynamically to load changes, integrate with other energy assets, and maintain grid stability can significantly impact both reliability and economic performance. This section outlines the key operational capabilities that engineers should assess when selecting a co-located generation system.

Dispatchability and Flexibility

Dispatchability refers to the system’s ability to generate power on demand, a critical feature for facilities with variable loads, especially those difficult to schedule. Technologies such as gas turbines and reciprocating engines offer high dispatchability, while others based on steam turbines (coal, nuclear, geothermal, natural gas combined cycle) may be better suited for baseload applications.  Because renewables are not able to meet demand if the solar or wind resource is not available, they are not classified as dispatchable.  Energy Storage systems present a unique situation because they can be dispatchable when charged, but if planned poorly and they are not charged when needed, they cannot be dispatched.

Flexibility encompasses the system’s range of operation to modulate output up and down in response to real-time demand or market signals.  Systems with wide turndown ratios and fast response times are better equipped to operate as non-grid connected back-up, participate in demand response programs, and complement intermittent renewables.  Inverter based systems are the most flexible with near 99% range operability, reciprocating machines can have a 75 to 95% operating range, while nuclear generally has the most limited operating range.  Generator technologies with limited flexibility (turndown) need to have another technology in the system so that the whole range of load demand can be covered.

Start Times and Ramp Rates

Start time is another critical parameter, especially for backup or peaking applications. Reciprocating engines typically offer the desired fast start capabilities (minutes), compared to steam-based systems that require several hours from a cold-start.  Generators that are slow to startup need to have another generation technology (such as the grid, or battery back-up) to power the load demand until the slower generator can get started.

Ramp rate, or the speed at which a system can increase or decrease output, is essential for load-following and grid support.  Fast ramping technologies are better suited for dynamic operating environments and can help mitigate the variability of renewable energy sources.  Generators with ramp rates slower than the rate at which the load changes will need a second generator technology to perform the dynamic balancing, such as the grid, or BESS.

Grid Stability and Power Quality

Rotating machinery such as gas or steam turbines and reciprocating engines inherently provide mechanical inertia, which contributes to frequency stability in both islanded and grid-connected modes. Inertia is particularly valuable in microgrid applications or weak grid environments, where frequency deviations can lead to instability or equipment damage. In contrast, inverter-based resources (e.g., fuel cells or battery systems) lack physical inertia but can emulate it to a degree through advanced control algorithms. The choice of technology should align with the stability requirements of the overall electrical system.

On-site power plants and electric generators supporting large loads often face challenges related to power quality as discussed in a previous chapter, making correction equipment essential for reliable and efficient operation. One key issue is power factor, which measures how effectively electrical power is being converted into useful work. Poor power factor, often caused by inductive loads like motors and transformers, leads to increased current flow, energy losses, and higher utility charges. Power factor correction equipment, such as capacitor banks or synchronous condensers, helps mitigate these issues by improving the alignment between voltage and current. Additionally, harmonics—distortions in the electrical waveform caused by non-linear loads like variable frequency drives and rectifiers—can lead to overheating, equipment malfunction, and interference with communication lines. Harmonic filtering devices, including passive and active filters, are crucial for maintaining waveform integrity and protecting sensitive equipment.

Modern inverters used in solar, wind, and battery energy storage systems (BESS) are increasingly capable of providing advanced power quality support, including power factor correction and harmonic filtering, thanks to their fast-switching capabilities and intelligent control algorithms. These inverters can dynamically adjust reactive power output and actively suppress harmonic distortions, reducing the need for traditional correction equipment. However, despite these technological advancements, utilities have been slow to fully embrace and integrate these capabilities into grid operations. Regulatory inertia, legacy grid standards, and concerns over inverter interoperability often lead utilities to mandate the installation of external devices such as STATCOMs (Static Synchronous Compensators) and capacitor banks to meet power quality requirements. This conservative approach can increase project costs and complexity, even when modern inverter-based solutions could provide equivalent or superior performance. Accelerating utility acceptance of inverter-based correction could streamline grid modernization and enhance the flexibility of distributed energy resources.  Together, these correction systems enhance energy efficiency, reduce operational costs, and ensure compliance with grid standards, making them indispensable for modern power infrastructure.

Synchronization and Control

Synchronization capability—the ability to match voltage, frequency, and phase with the grid or other generators—is essential for seamless integration and parallel operation. Systems with robust synchronization controls can more easily transition between islanded and grid-connected modes, enhancing resilience. Additionally, compatibility with microgrid controllers, SCADA systems, and energy management platforms is crucial for coordinated operation, especially in facilities with multiple DERs. Engineers should evaluate the communication protocols, control interfaces, and automation features of each technology to ensure smooth integration and long-term operability.

Parasitic Loads and Degradation

Parasitic load — the internal energy consumption of the generation system — directly affects net output and system efficiency. Technologies with high auxiliary loads (e.g., for pumps, compressors, or control systems) may reduce the effective capacity available to the facility.

In summary, selecting a co-generation technology requires a holistic assessment of operational characteristics in addition to efficiency and cost. Dispatchability, flexibility, parasitic load, start-up behavior, ramping capability, inertia contribution, and synchronization features all play a role in determining the suitability of a system for a given application. A well-matched technology will not only meet the energy needs of the facility but also enhance reliability, grid interaction, and economic performance.

3 Service Reliability

Reliability is a cornerstone of any co-located generation system, particularly for facilities where power continuity is mission critical. When selecting a generation technology, engineers must evaluate not only the inherent reliability of the equipment but also the broader system architecture and external risk factors that could impact performance. A comprehensive reliability assessment includes metrics such as Mean Time Between Failures (MTBF), system availability, maintenance requirements, and redundancy strategies.

Availability and Failures

Mean Time Between Failures (MTBF) is a key indicator of component reliability and should be considered for major subsystems such as prime movers, generators, distribution, control systems, and auxiliary equipment.  It should also be considered for the system as a whole to understand the magnitude of the effect if a single piece of equipment fails.  For example, a single boiler feed pump or a single gas compressor could bring down a much large system if it were to fail. Technologies like reciprocating engines and gas turbines typically have well-documented MTBF values based on extensive operational data. Availability, defined as the percentage of time a system is operational and capable of delivering power, is influenced by both MTBF and the duration of maintenance or repair events. Systems with high availability often feature modular designs, hot-swappable components, and predictive maintenance capabilities. Maintenance intervals, service complexity, and the availability of spare parts and technical support should also be factored into the selection process.

Redundant and Resilient Architecture

Redundancy is a critical strategy for enhancing system reliability, especially in applications where downtime is unacceptable. N+1 or 2N configurations—where one or more units are installed beyond the minimum required capacity—can ensure continued operation during maintenance or failure events. Engineers should consider whether the co-located generation system supports parallel operation, load sharing, and automatic failover. In microgrid environments, integrating co-located fueled generation with other distributed energy resources (e.g., batteries or solar PV) can provide additional layers of redundancy and operational flexibility.

External Risks

Reliability is also affected by external risks, including weather events and dependencies on supporting infrastructure. For example, gas-fired co-located generation systems rely on a continuous supply of natural gas, which may be vulnerable to pipeline disruptions or curtailments during extreme weather. Similarly, cooling systems may be impacted by ambient temperature extremes or water availability. Facilities in hurricane-prone or wildfire-prone regions must consider the physical hardening of equipment and the ability to operate in islanded mode during grid outages. Site-specific risk assessments should inform technology selection, siting, and protective measures.

Ultimately, selecting a co-located generation technology with high reliability requires a systems-level approach. Engineers should evaluate not only the reliability of individual components but also how the system behaves under fault conditions, how quickly it can recover, and how it integrates with the facility’s broader energy infrastructure. Tools such as Failure Modes and Effects Analysis (FMEA), reliability block diagrams, and probabilistic risk assessments can support informed decision-making. A well-designed co-located generation system will not only meet performance targets under normal conditions but also maintain critical operations during adverse events.

4 Environmental Sustainability

As environmental regulations tighten and corporate sustainability goals become more ambitious, the environmental footprint of co-located generation technologies is a critical factor in technology selection. Beyond energy efficiency and cost, engineers must evaluate emissions, resource consumption, waste generation, and end-of-life impacts to ensure that the chosen system aligns with both regulatory requirements and long-term sustainability objectives.

Emissions and Air Quality Impacts

One of the most scrutinized aspects of any generation technology is its emissions profile. Combustion-based systems—such as gas turbines, reciprocating engines, and CHP units—emit nitrogen oxides (NOₓ), carbon monoxide (CO), particulate matter (PM), volatile organic compounds (VOCs), and greenhouse gases (GHGs) such as CO₂.  Facilities located in non-attainment areas—regions that do not meet National Ambient Air Quality Standards (NAAQS)—are typically subject to more restrictive emissions limits and may require Best Available Control Technology (BACT) or Lowest Achievable Emission Rate (LAER) standards. This can significantly influence technology selection, as some systems may require additional emissions control equipment such as selective catalytic reduction (SCR), oxidation catalysts, or particulate filters to meet local requirements. In contrast, facilities in attainment areas may have more flexibility in technology choice, though long-term regulatory trends suggest a continued tightening of emissions thresholds across the board.

Technologies such as fuel cells, solar PV, and battery storage offer near-zero local emissions and are often favored in urban or environmentally sensitive areas where air quality is a major concern. However, even these systems may have upstream emissions associated with fuel production or manufacturing, which should be considered in a full lifecycle assessment. Engineers must work closely with environmental consultants and permitting authorities early in the project development process to ensure that the selected technology can meet all applicable emissions standards without compromising project viability.

Water Use and Thermal Discharges

Water consumption is another key environmental consideration, particularly in regions facing water scarcity. Steam-based systems and some CHP configurations require significant water for cooling and steam generation, which can strain local water supplies and introduce thermal pollution risks. Dry cooling technologies and closed-loop systems can mitigate these impacts but may reduce efficiency. Technologies such as fuel cells and solar PV typically have minimal water requirements, offering a distinct advantage in arid environments or where water use permits are difficult to obtain.

Hazardous Materials and Waste Management

The generation and handling of hazardous materials—such as lubricants, coolants, and chemical catalysts—pose operational and environmental risks. Systems that rely on combustion or chemical processes may produce hazardous byproducts that require specialized disposal. Battery-based systems, while emission-free during operation, involve materials such as lithium, cobalt, and electrolytes that must be carefully managed throughout their lifecycle. Engineers should assess the availability of safe disposal or recycling pathways and ensure compliance with local and federal hazardous waste regulations.

End-of-Life and Recyclability

Sustainability extends beyond operational impacts to include the end-of-life phase of the technology. Systems designed with modular, recyclable components reduce the environmental burden of decommissioning and can support circular economy goals. For example, many metals used in turbines and engines can be recovered and reused, while solar panels and batteries are increasingly supported by dedicated recycling programs. Technologies with long service lives, upgradeable components, and established recycling infrastructure offer a more sustainable long-term profile.

Holistic Sustainability Assessment

A comprehensive sustainability assessment should consider the full lifecycle of the technology—from raw material extraction and manufacturing to operation, maintenance, and decommissioning. Tools such as Life Cycle Assessment (LCA) and Environmental Product Declarations (EPDs) can provide quantitative comparisons across technologies. In addition, alignment with environmental certifications (e.g., LEED, ISO 14001) and ESG reporting frameworks may influence technology selection, particularly for organizations with public sustainability commitments.

In summary, selecting a co-located generation technology requires a multidimensional view of environmental and sustainability impacts. Emissions, water use, hazardous waste, and end-of-life considerations must be balanced with performance and economic factors to ensure that the system supports both operational goals and environmental stewardship.

5 Site Feasibility

The physical and social context of a co-located generation project plays a critical role in determining its feasibility and long-term success. While technical performance and economic viability are essential, the appropriateness of the technology for the specific site—and its acceptance by the surrounding community—can significantly influence permitting, construction timelines, and operational continuity. Engineers must consider spatial constraints, environmental context, and public perception when selecting a generation technology for a given location.

Proximity to Energy Resources and Infrastructure

Off-grid on-site power generation can be installed virtually anywhere, while grid-connected systems are limited to locations with access to existing electrical infrastructure.  Thermal combustion technologies require proximity to infrastructure for delivering the fuel.  Renewable energy systems are restricted to locations where there is a good solar, wind, or geothermal heat resource.

Power Density and Land Use Efficiency

Power density, typically measured in megawatts per acre (MW/acre), is a key factor in determining whether a technology is suitable for a given site. High-density technologies such as gas turbines, reciprocating engines, and fuel cells can deliver substantial output from a compact footprint, making them ideal for urban or space-constrained environments. In contrast, solar PV and wind systems require significantly more land area per megawatt, which may limit their applicability in dense industrial zones or near critical infrastructure. Engineers must evaluate not only the available land but also zoning restrictions, easements, and proximity to load centers when assessing site suitability.

Aesthetics and Visual Impact

The visual profile of a generation system can influence community acceptance, especially in areas with residential or commercial neighbors. Technologies with low vertical profiles and enclosed housings—such as containerized CHP units or fuel cells—tend to have minimal aesthetic impact. Conversely, tall exhaust stacks, cooling towers, wind turbines, or large solar arrays may raise concerns about visual intrusion or property value impacts. Incorporating architectural screening, landscaping, or building-integrated designs can help mitigate these concerns and improve public perception.

Noise and Acoustic Considerations

Noise emissions are a common source of community opposition, particularly for combustion-based systems with moving parts or high-velocity exhaust. Reciprocating engines and gas turbines can generate significant noise during operation, requiring the use of acoustic enclosures, silencers, and vibration isolation systems. Engineers should conduct site-specific noise modeling to ensure compliance with local ordinances and to minimize disturbance to nearby residents or businesses. Technologies such as fuel cells and battery storage offer near-silent operation, making them attractive for noise-sensitive environments.

Perceived Harm and Public Perception

Beyond measurable impacts, community acceptance is often shaped by perceived risks whether they are technically justified or not. Concerns may include air pollution, fire hazards, electromagnetic fields, or the use of hazardous materials. Transparent communication, public engagement, and third-party environmental assessments can help address these concerns and build trust. Technologies with a strong track record of safe operation and minimal environmental impact are generally more acceptable to the public, especially when paired with visible sustainability benefits such as reduced emissions or renewable integration.

In summary, selecting a co-located generation technology requires careful consideration of both the physical characteristics of the site and the social dynamics of the surrounding community. Power density, aesthetics, noise, and perceived harm all influence the appropriateness of a technology for a given location. By proactively addressing these factors, engineers can reduce permitting risk, enhance community support, and ensure the long-term viability of the project.

6 Evolving Policy

Policy Volatility

Policy and regulatory environments play a pivotal role in shaping the feasibility, cost, and long-term viability of co-located generation projects. While technical and economic factors are often the primary focus during technology selection, overlooking policy risks can lead to costly delays, stranded assets, or compliance failures. Engineers and project developers must understand the regulatory landscape, incentive structures, and potential sources of opposition that could impact project execution and operation.

For example, the Electric Reliability Council of Texas (ERCOT) has established specific rules for microgrids under the designation of “Private Use Networks” (PUNs). [10] These microgrids, sometimes referred to as “Energy Parks,” [11] are motivated by the desire for increased reliability, reduced transmission charges, avoidance of congestion and curtailment, and access to environmental credits for compliance purposes.

Co-located generation systems are subject to a wide array of regulations at the federal, state, and local levels. These may include air and water quality standards, emissions limits, interconnection rules, and land use restrictions. Navigating this regulatory matrix requires early engagement with permitting authorities and a clear understanding of applicable codes and standards. In some jurisdictions, specific technologies—such as internal combustion engines or biomass systems—may face heightened scrutiny or outright restrictions due to environmental or public health concerns. Delays in obtaining permits or changes in regulatory interpretation can significantly impact project timelines and costs.

Multiple agencies may have the authority to delay or deny project approval, including environmental protection agencies, utility commissions, zoning boards, and fire marshals. Each agency may apply different criteria and timelines, and their decisions may be influenced by public input or political pressure. For example, a local air quality management district may impose stricter emissions limits than federal standards, or a utility may resist interconnection of behind-the-meter generation due to grid stability concerns. Identifying all relevant stakeholders and understanding their approval processes is essential for risk mitigation.

Imported equipment—such as turbines, inverters, or battery systems—may be subject to tariffs or trade restrictions that affect project cost and supply chain reliability. Additionally, local building and electrical codes may impose design constraints that influence technology selection, such as noise limits, fire safety standards, or structural requirements. Compliance with evolving codes (e.g., NFPA 855 for energy storage or ASHRAE standards for CHP systems) must be factored into system design and procurement strategies.

Incentives

Government incentives—such as investment tax credits (ITCs), production tax credits (PTCs), renewable energy credits (RECs), and grant programs—can dramatically improve the economics of co-located generation projects. However, these incentives are often subject to political cycles and budgetary constraints, making them inherently volatile. A project that relies heavily on a specific subsidy may become financially unviable if that policy is reduced or repealed. Engineers should conduct sensitivity analyses to assess the impact of incentive changes and consider technologies that remain viable under multiple policy scenarios.

Political Risk

Public sentiment and political dynamics can also influence project success. Community opposition, driven by concerns over emissions, noise, or land use, can delay or derail projects—even those that meet all technical and regulatory requirements. Conversely, strong public or political support can accelerate permitting and unlock additional funding opportunities. Technologies perceived as clean, quiet, and safe—such as fuel cells or solar-plus-storage—tend to face fewer barriers, while combustion-based systems may require more extensive outreach and mitigation planning depending on the current political position of the locality, state, or federal administration.

In summary, policy risks are multifaceted and dynamic, encompassing regulatory constraints, incentive volatility, permitting complexity, and public perception. Successful co-located generation projects require proactive policy analysis, stakeholder engagement, and flexible design strategies that can adapt to changing regulatory and political conditions.

7 Cost of Capacity & Energy

Selecting a co-located generation technology requires a rigorous financial analysis that balances capital investment, operating costs, and long-term economic performance. While technical feasibility and environmental impact are critical, the financial viability of a project ultimately determines whether it will be funded, built, and sustained. Engineers and project developers must evaluate both upfront and lifecycle costs, as well as the project’s ability to attract financing under various ownership and market structures.

Capital and Operating Expenses

Capital expenditures (CAPEX) include the cost of equipment, installation, interconnection, permitting, and commissioning. These costs vary widely by technology: for example, reciprocating engines and gas turbines typically have lower CAPEX per installed megawatt than fuel cells or solar-plus-storage systems but may require more complex integration. Operating expenses (OPEX) include fuel, maintenance, labor, insurance, and compliance costs. Technologies with high fuel consumption or intensive maintenance schedules—such as combustion-based systems—may have lower upfront costs but higher long-term OPEX. Conversely, systems like solar PV or battery storage have minimal fuel costs but may require significant CAPEX and periodic component replacement.

Fuel costs are a major driver of OPEX and can introduce significant volatility into project economics. Natural gas prices, for example, are subject to regional supply dynamics, seasonal demand, and geopolitical factors. Projects that rely on fossil fuels must account for potential price fluctuations, carbon pricing, and supply disruptions. Renewable-based systems or those with hybrid configurations (e.g., solar + CHP) can mitigate fuel cost exposure and improve cost predictability. Engineers should model multiple fuel price scenarios to assess financial resilience and identify opportunities for fuel hedging or diversification.

The ability to finance a co-located generation project depends on the perceived risk and return profile. Technologies with proven performance, predictable cash flows, and favorable regulatory treatment are more likely to attract debt and equity financing. Projects that qualify for tax incentives, power purchase agreements (PPAs), or utility programs may benefit from lower financing costs. Ownership structure—whether utility-owned, third-party financed, or customer-owned—also affects capital availability, depreciation, tax and risk allocation. Financial models should reflect the cost of capital, depreciation schedules, tax liabilities and potential revenue streams from grid services or energy market participation.

Levelized Cost of Capacity and Levelized Cost of Energy

Two critical metrics for comparing technologies are Levelized Cost of Capacity and Levelized Cost of Energy:

• Levelized Cost of Capacity (LCOC) ($/MW/year) reflects the fixed cost of maintaining a given capacity over a year, normalized by expected energy output. It is particularly useful for evaluating back-up, standby or peaking assets where utilization may be low but availability is critical.
• Levelized Cost of Energy (LCOE) ($/MWh) represents the total lifecycle cost of generating electricity, including CAPEX, OPEX, fuel, and financing, divided by the total energy produced over the system’s lifetime. It provides a comprehensive measure of cost competitiveness across technologies and is essential for comparing baseload, intermediate, and variable generation options.

Both metrics should be calculated using consistent assumptions about system life, capacity factor, discount rate, and escalation factors. Sensitivity analyses can help identify cost drivers and inform technology selection under different economic and operational scenarios. This work includes the Levelized Cost of Capacity as a means for evaluating back-up or stand-by power that would be considered necessary for reliability, and it includes the LCOE calculation to qualify a system’s economic feasibility as a primary power supply.

The most comprehensive model for evaluating the cost of electric power is a time series analysis, which captures the dynamic nature of power consumption and pricing over time. Unlike static metrics such as average cost or levelized cost of energy, a time series approach accounts for fluctuations in fuel prices, load demand, generator performance, and market conditions every hour of a year. It enables a detailed examination of cost behavior during normal operations, low-cost periods, high-cost spikes, and contingency events such as weather outages or fuel supply disruptions. This method provides a nuanced understanding of both typical and extreme scenarios, helping decision-makers assess financial risk, plan for resilience, and optimize operational strategies. By incorporating temporal variability, time series analysis offers a realistic and data-driven foundation for evaluating the true cost of power from generation sources.  This work includes analysis performed with a time series model in the later chapter on Hybrid solutions.

References

[1] U.S. Environmental Protection Agency, “Getting Coverage under EPA’s Construction General Permit / Waivers,” U.S. Environmental Protection Agency, 12 April 2025. [Online]. Available: https://www.epa.gov/npdes/getting-coverage-under-epas-construction-general-permit-waivers. [Accessed 12 June 2025].

[2] A. C. o. H. Preservation, “Section 106 Archaeology Guidance,” Advisory Council on Historic Preservation, 1 January 2009. [Online]. Available: https://www.achp.gov/sites/default/files/guidance/2017-02/ACHP%20ARCHAEOLOGY%20GUIDANCE.pdf. [Accessed 12 6 2025].

[3] U.S. Environmental Protection Agency, “Operating Permits Issued under Title V of the Clean Air Act”, U.S. EPA [Online] https://www.epa.gov/title-v-operating-permits. [Accessed 9 October 2025].

[4] Texas Commission on Environmental Quality, “Air Quality Standard Permit for Electric Generating Units,” Texas Commission on Environmental Quality, May 2024. [Online]. Available: https://www.tceq.texas.gov/permitting/air/newsourcereview/combustion/egu_sp.html. [Accessed 4 June 2025].

[5] U.S. Environmental Protection Agency, “Submitting a Notice of Intent (NOI), Notice of Termination (NOT), or Low Erosivity Waiver (LEW) under the Construction General Permit,” U.S. Environmental Protection Agency, 8 April 2025. [Online]. Available: https://www.epa.gov/npdes/submitting-notice-intent-noi-notice-termination-not-or-low-erosivity-waiver-lew-under. [Accessed 12 June 2025].

[6] Texas Commission on Environmental Quality, “e‑App: Edwards Aquifer Protection Program Application,” Texas Commission on Environmental Quality, 12 5 2025. [Online]. Available: https://www.tceq.texas.gov/permitting/eapp. [Accessed 13 6 2025].

[7] Texas Commission on Environmental Quality, “Edwards Aquifer: Application and Review Process,” Texas Commission on Environmental Quality, 12 May 2025. [Online]. Available: https://www.tceq.texas.gov/permitting/eapp/review.html. [Accessed 11 June 2025].

[8] A. Wortzel, B. Cowan, J. Kaplowitz, et. al., “Renewables in the Crosshairs: DOI and DOT Announce Numerous New Anti-Wind and Solar Orders and Policies”, Publication by Troutman Pepper Locke Firm, 4 August 2025, [Online] https://www.environmentallawandpolicy.com/2025/08/renewables-in-the-crosshairs-doi-and-dot-announce-numerous-new-anti-wind-and-solar-orders-and-policies/, [Accessed 9 October 2025].

[9] “An Owner’s Guide to Project Delivery Methods”, White Paper by Construction Management Association of America (CMMA), 2012.

[10] Electric Reliability Council of Texas, “ERCOT Nodal Protocol, Section 2.1,” Electric Reliability Council of Texas, Austin, 2024.

[11] A. Levitt, J. Pfeifenberger and A. Mohan, “Accelerating the Integration of New Co-located Generation and Loads,” The Brattle Group, Boston, 2025.