Why Today’s Power Demand Is Colliding With Yesterday’s Infrastructure

The electric grid was built to deliver power across a growing economy. It was not built around the scale, concentration, and speed of many of today’s new electricity demands.

For decades, utilities could plan around relatively predictable growth. New residential, commercial, and industrial customers appeared gradually, giving utilities time to reinforce distribution systems, expand substations, procure transformers, and add generation and transmission capacity.

That planning environment has changed.

Between 2005 and 2019, U.S. electricity demand increased by only about 0.1 percent annually. From 2020 through 2025, growth accelerated to approximately 1.7 percent per year. NERC now forecasts North American summer peak demand increasing by more than 224 GW over the next decade, 69 percent more growth than it projected just one year earlier. Data centers and other large loads account for much of that increase.

The challenge is not simply producing more electricity.

Power must still reach a particular project through transmission lines, substations, transformers, feeders, and local service infrastructure. And those systems cannot always expand on the same schedule as the projects depending on them.

For midstream operators, that mismatch can determine when a measurement station, block valve site, communications node, gas analyzer system, or remote monitoring facility becomes operational.

More Generation Does Not Mean Power Is Available Everywhere

Electricity capacity is highly location specific.

A region may have enough generation overall while the substation, feeder, transformer, or transmission corridor serving a particular site lacks the capacity to support another load.

That is why seeing a utility line near a project does not confirm that usable power is available.

A nearby line does not tell the project team:

• How much capacity remains
• Whether the voltage matches the application
• Whether the transformer can support the load
• Whether upstream upgrades are required
• Whether motor starting or peak demand can be accommodated
• Whether service can be established by the required operational date

A project could sit beside an existing feeder while the real constraint is located miles upstream.

The more useful question is not simply:

Is there a power line nearby?

It is:

Can the amount and quality of power this site requires be delivered here when the project needs it?

That turns utility availability from a site assumption into an engineering and scheduling issue.

Grid Infrastructure Moves on a Different Timeline

Modern projects can advance quickly once capital is approved.

Utilities have a different set of dependencies.

A new or upgraded service may require system studies, engineering, permitting, easements, specialized equipment, outage coordination, construction crews, testing, and final energization.

At the transmission level, the timelines become even longer. The Department of Energy reports that federal permitting alone for a new transmission line takes approximately four years on average. FERC’s current long term transmission rules require utilities to evaluate needs using planning horizons of at least 20 years, illustrating how differently major grid infrastructure must be planned compared with an individual commercial project.

Equipment availability can create another delay.

DOE reported in 2026 that demand for distribution transformers had increased 41 percent since 2019. Typical order lead times increased from three to six months in 2019 to one or two years or longer by 2024. Some large transformers used at substations and generating facilities were taking three to four years.

A utility may therefore confirm that service is technically possible while still being unable to provide it within the project schedule.

For project teams, this creates an unusual dependency.

They may understand exactly what must happen without controlling the engineering queue, utility procurement, construction resources, or final delivery date.

Why This Matters to Midstream

Midstream infrastructure has an additional challenge: it must be installed where the pipeline needs it, not where the electric grid is easiest to access.

Pipelines cross rural land, highways, railroads, waterways, and areas far from established electrical infrastructure. Measurement, communications, valves, controls, and monitoring equipment are positioned according to operational requirements.

The utility network may follow a completely different route.

A relatively small load can therefore require a surprisingly complicated utility connection.

A remote block valve or measurement location might require a distribution extension, poles, conductors, a transformer, easements, road or railway crossings, landowner coordination, and utility construction before power ever reaches the equipment.

The amount of electricity consumed does not determine the complexity of obtaining it.

It also does not determine the importance of the load.

A remote terminal unit may consume little electricity while providing visibility into a large section of pipeline. A communications node may support alarms, telemetry, and remote control. A valve actuator may operate infrequently but must have power available when the operator needs it.

PHMSA specifically recognizes SCADA systems as part of how pipeline controllers remotely monitor and control operations, including information such as pressure, flow, and valve position.

For these sites, the value of dependable power is not measured only in kilowatt hours.

It is measured by the operational function that power keeps available.

A Finished Project Is Not Necessarily an Operating Project

Power delays often become most visible near the end of construction.

Civil work may be finished. Equipment may be installed. Piping may be tested. Control panels and communications equipment may be in place.

But without dependable power, the project may still be unable to complete integrated testing, establish communications, verify remote control, operate measurement equipment, or fully commission the site.

That gap creates costs even before delayed revenue is considered.

Temporary generators may require fuel, maintenance, security, and repeated service. Contractors or commissioning specialists may need to return. Equipment may need to be preserved while the site waits. Work may have to be completed out of sequence.

The asset can be physically complete while remaining operationally unavailable.

That is why power belongs in early site selection, engineering, scheduling, and commissioning discussions instead of remaining a utility task near the end of the project.

The Grid Is Modernizing, but Projects Still Need a Plan

The grid is not standing still.

Utilities and grid operators are investing in new transmission, substations, storage, controls, advanced conductors, and technologies intended to increase the usable capacity and flexibility of existing infrastructure. FERC’s long term planning reforms are also intended to help transmission providers anticipate future needs earlier.

But modernization will not occur everywhere at the same time.

One project may connect easily while another a few miles away faces additional cost or years of utility work.

That means project teams still need to evaluate the conditions at the actual site.

The power conversation should establish the operating load, startup requirements, voltage, critical equipment, reliability needs, future expansion, required operational date, and the utility work necessary to serve the location.

It should also distinguish between preferred power and required power.

Utility service may remain the preferred long term option.

The project may still need another strategy to reach its operational date.

Where Solarcraft Fits

Solarcraft becomes relevant when utility access does not align with the project’s geography, economics, reliability requirements, or schedule.

Solarcraft engineers remote, stand alone, off grid, hybrid, and UPS power systems around the application’s operating loads and site conditions. Systems can support RTUs, PLCs, SCADA, communications, flow computers, measurement equipment, analyzers, instrumentation, motors, and valve actuators. Power equipment, batteries, controls, automation, and field electronics can also be integrated into rugged enclosures and shelters as one tested system.

That does not mean utility power is the wrong solution.

It means project teams have another path when extending the grid is impractical because of cost or geography, or when waiting for utility service would prevent critical infrastructure from becoming operational.

The grid was built to deliver electricity.

Today’s projects increasingly need certainty about where that electricity will be available and when.

That is the part it was not originally built for.

Key Takeaways

• Electricity demand is growing faster and becoming more concentrated after years of relatively little change.
• Available generation does not guarantee that power can be delivered to a specific project site.
• A nearby utility line does not confirm capacity, voltage, infrastructure requirements, or an energization date.
• Transmission, transformers, permitting, easements, and utility construction can operate on timelines much longer than private project schedules.
• Remote midstream sites may have small electrical loads but still require complicated utility extensions.
• The importance of a midstream load is determined by the operational function it supports, not simply its electricity consumption.
• Evaluating power earlier gives projects more options when utility timing, cost, or geography does not align with the operational schedule.
• Solarcraft provides an engineered alternative when critical infrastructure cannot reasonably wait for traditional utility service.

Ready to Continue the Conversation?

The grid is evolving, but critical infrastructure projects cannot always wait for regional capacity, utility extensions, or long-term system upgrades to arrive.

Continue exploring the Power Without Waiting series to learn how rising demand and changing project risks are influencing the way midstream teams plan for power.

Sources

1. U.S. Energy Information Administration. “Fossil Generation Could Rise With Faster Than Expected Growth in Data Center Power Demand.” March 12, 2026. Provides U.S. electricity demand growth of approximately 0.1 percent annually from 2005 to 2019 and 1.7 percent annually from 2020 to 2025.
2. North American Electric Reliability Corporation. “2025 Long Term Reliability Assessment.” Forecasts more than 224 GW of North American summer peak demand growth over the next decade, 69 percent higher than the prior year’s projection.
3. U.S. Department of Energy, Office of Electricity. “Coordinated Interagency Transmission Authorizations and Permits Program.” Reports that federal permitting for a new transmission line takes approximately four years on average.
4. Federal Energy Regulatory Commission. “Explainer on the Transmission Planning and Cost Allocation Final Rule.” Explains Order No. 1920 and the requirement for long term regional transmission planning using a horizon of at least 20 years.
5. U.S. Department of Energy, Office of Electricity. “Distribution Transformer Webinar.” 2026. Reports a 41 percent increase in distribution transformer demand since 2019 and current lead times of one to two years or longer for distribution transformers and three to four years for some large transformers.
6. Pipeline and Hazardous Materials Safety Administration. “Control Room Management.” Describes the role of SCADA systems in remotely monitoring and controlling pipeline facilities.
7. Solarcraft Inc. “Off Grid Solar Power Systems for Remote Locations.” Describes Solarcraft systems configured around operating loads and site conditions for RTU, PLC, SCADA, measurement, communications, analyzers, motors, valve actuators, and other remote applications.
8. Solarcraft Inc. “Engineered Power & Automation Systems for the Oil & Gas Industry.” Describes Solarcraft’s power, UPS, automation, analyzer, enclosure, integration, and remote power capabilities for upstream and midstream applications.