The Solar Blindspot: What Pipeline Operators Need to Know About DC Interface

Making a case for early development coordination and evaluation based on practical, established methodology

Our industry has seen this movie before. Thirty years ago, alternating current (AC) interference was not treated as an integrity threat around buried pipelines. Over time, field experience and improved analysis tools changed that thinking. Now, AC interference assessment is a standard, early-on consideration for any pipeline development, and operators must continually manage mitigation according to federal minimum safety standards.

Our industry is on a similar learning curve when it comes to direct current (DC) interference from utility-scale solar farms. The risk is not well understood, the right information is not always exchanged, and projects can advance without any consideration for how a solar facility’s inverters, grounding system, cables, soil, and fault behavior may interact with a pipeline in the vicinity. Not every solar farm poses corrosion risk, but we should no longer assume there is no threat until corrosion damage tells us otherwise.

Why the solar blind spot is concerning

The pace of commercial photovoltaic (PV), or solar, development makes pipeline integrity around solar farms more than a niche issue. The International Renewable Energy Agency reports that renewables accounted for 85.6% of global net power-capacity expansion in 2025, after reaching 92.0% in 2024. Solar added 511 gigawatts (GW) in 2025—about three-quarters of all renewable additions—compared with 159 GW of wind. The United States alone added 34 GW of solar capacity in 2025.^[1]

And the US buildout was already setting records before that. In 2024, developers added 30 GW of utility-scale solar, equal to 61% of new US utility-scale generating capacity that year.^[2] A nationwide Lawrence Berkeley National Laboratory study found median direct-array power densities of 0.35 MWdc per acre for fixed-tilt solar plants and 0.24 MWdc per acre for tracking solar plants. Using just the tracking benchmark, the array footprint for a 200-MWdc solar project would be roughly 830 acres before accounting for the rest of the site.^[3]

Now consider the pipeline infrastructure occupying the same landscape. The Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) regulates 3.3 million miles of US pipelines, which transport 64% of the country’s energy commodities.^[4] As solar projects spread across larger areas and into more energy-producing regions, solar farm–pipeline proximity will become more common. The question is whether the two industries coordinate before construction or discover the interaction after commercial operation.

Leveraging the FEED phase to support project success

To mitigate risks and align a project with your company’s objectives, various engineering phases must be followed to ensure a thorough project plan. The FEED phase defines the technical requirements and anticipated costs of a proposed project—making it vital for FID and, ultimately, positive NPV. 

The potential impact of the FEED phase on your project’s outcome, then, makes it crucial to select the right engineers. Your engineering partner for FEED should bring expertise, experience, and data-driven insights to determine project economics and provide a precise project plan. 

How a solar farm can interact with a buried pipeline

A PV array generates DC electricity. Inverters convert that power to AC for collection and delivery to the grid. Across the facility are inverter pads, bare-copper grounding conductors, electrodes, surge-protection devices, medium- and low-voltage cable routes, junction boxes, and other grounded equipment. Under normal operation or transient conditions, DC current can enter the earth through intended or unintended paths.

Leakage current is not theoretical. Researchers at the National Renewable Energy Laboratory (NREL) have shown that PV system voltage can drive leakage current between solar cells and grounded metal frames and that the behavior varies with temperature, humidity, geometry, voltage, and impurities. That research focused on PV-module performance, not pipelines, so though it does not prove a pipeline will be affected, it does show why solar-related leakage can be dynamic and why a single daytime reading is not enough to characterize a site.^[5]

If a nearby coated steel pipeline becomes part of an unintended current path, the result can be shifts in pipe-to-soil potential, elevated cathodic protection (CP) current density, stray-current corrosion where current discharges from the pipe, or changes that make the pipeline’s true protection level harder to interpret. Buried AC cables and overhead collection or transmission lines can add a separate AC interference component.

We can’t declare every colocation dangerous, however. A 2026 numerical study of one 160-MW solar plant modeled less than a 5-millivolt shift in pipeline DC potential^[6] The study does not give every solar project a clean bill of health for DC interference, but rather makes the more useful point: grounding design, route geometry, soil conditions, current magnitude, parallel length, spacing, coating condition, and operating state determine interference risk.

What current regulations address—and what they don’t

Pipeline operators already have responsibilities to analyze, monitor, and mitigatestray-current interference as necessary. For onshore gas transmission pipelines, the PHMSA Mega Rule requires a continuing program to minimize detrimental effects and calls for interference “surveys” when monitoring indicates a significant increase or when new potential sources are introduced.^[7] For natural gas and hazardous-liquid pipelines, it requires a program to identify, test for, and minimize detrimental interference currents.^[8]

ISO 21857:2021 provides general principles for evaluating and minimizing external corrosion caused by both AC and DC electrical interference on buried or immersed pipelines.^[9] The current ISO 15589-1 standard covers the design, commissioning, operation, inspection, and maintenance of CP systems for onshore pipelines.^[10] These are the right foundations, but none addresses solar-farm interference directly—and we can’t apply them as-is to a solar site, the simplest reason being that solar sites don’t generate power 24/7/365. Furthermore, there is no single solar-farm setback distance or universal current value that can be used as with electrical power infrastructure.

On the solar side, developers are responsible for meeting extensive requirements related to electrical safety, fire protection, siting, and grid interconnection. Electrical and fire codes govern how the facility is designed and operated, while interconnection rules examine its effect on grid reliability and establish project readiness and study requirements. What these frameworks do not require is an evaluation of how the solar facility’s DC collection and grounding systems may interact with a nearby pipeline.

And here is the blind spot. Each side—solar and pipeline—is working through its own design and regulatory requirements without studying the shared soil between them.

A practical way to close the blind spot

Good news, though: we don’t need to invent a completely new integrity discipline. We need to apply proven interference and CP methods to the solar configuration in front of us. A defensible evaluation should include the following:

• Map what is actually there. Confirm the pipeline alignment and identify solar panels, inverter locations, grounding grids and electrodes, bare conductors, surge-protection devices, AC and DC cable trenches, junction or bonding boxes, and any areas of parallel routing.
• Characterize the soil. Use multidepth soil-resistivity measurements, including the four-pin Wenner method where appropriate, at depths and locations that represent the pipeline and the solar grounding system. Extend the assessment beyond the immediate point of closest approach so the current path is not viewed too narrowly.
• Establish a baseline before energization. Collect pipe-to-soil potentials, IR-free data, coupon current or polarization data, and other relevant CP measurements before the solar facility changes the electrical environment. Where the schedule allows, three to six months provides a stronger baseline than a brief snapshot.
• Monitor both systems on the same clock. Use continuous, time-synchronized logging so pipeline behavior can be compared with inverter output, peak generation, weather, seasons, switching, and fault events. Coupons, remote monitoring units, and ultrasonic metal-loss coupons can help distinguish a real interference pattern from normal variation.
• Evaluate DC and AC together. Review whether observed deviations are repeatable, whether they correlate with solar operation, and whether they affect cathodic-protection effectiveness. The conclusion should come from converging evidence, not one isolated number.

When interference is confirmed, mitigation should fit the mechanism. Options can include reviewing electrical isolation and bonding, modifying or adding CP systems, installing new anode groundbeds, adding monitoring points, adjusting grounding or routing when the project stage still allows it, and verifying performance over the long term. The documentation matters too: survey data, soil-resistivity results, risk calculations, monitoring drawings, observed effects, mitigation records, and follow-up surveys should stay together.

Earlier coordination or later retrofit

The least expensive point to solve this problem is before solar-farm construction. Once grading is complete, cable trenches are closed, grounding is installed, and the solar facility is energized, the practical options become narrower and more disruptive. Early coordination gives both sides more flexibility.

For solar developers, that means identifying pipeline operators early and sharing the electrical one-line, site layout, inverter data, grounding design, cable routes, and fault-current information needed for a meaningful review. For pipeline operators, it means establishing baseline data before energization instead of waiting for annual CP readings to show that something has changed. For owners and project teams, it means making interference evaluation a design and commissioning gate, not an afterthought.

The business case is straightforward. The Association for Material Performance and Protection (AMPP) estimates that corrosion-related monitoring, replacement, and maintenance costs total about $7 billion annually for US gathering and transmission pipelines, plus another $5 billion for gas distribution, based on industry studies. Those figures are not solar-specific, but they show the scale of what operators already spend managing corrosion. Adding an uncharacterized electrical interaction to that system is not a smart risk. ^[11]

Making solar part of the integrity conversation

Solar generation is expanding, and our pipeline network will remain essential to the country’s energy system. These assets can coexist safely. But coexistence is an engineering outcome, not an assumption.

At Audubon Companies, we are digging into custom site analysis and custom integrity solutions such as CP planning and construction, operator by operator and asset by asset. Are we helping our clients get compliant with regulations faster? Yes, but we’re also looking beyond compliance to the actual solutions that increase reliability and decrease risk. Our work for the largest private use network (PUN) in Texas is a prime example—read the story here.

As an industry, we shouldn’t look back 20 years from now and realize we repeated the AC interference learning curve with solar. The survey methods, monitoring tools, standards, and mitigation approaches are there to get ahead of it. What we need now is communication, better site data, and the willingness to ask one simple question before the switch is flipped: What is happening to the pipeline underneath?

About the author

Bryan Louque, PE, is Vice President of Pipeline Integrity at Audubon Companies. He has more than 35 years of pipeline-industry cathodic protection, integrity management, and regulatory compliance experience. He is currently certified as an AMPP Cathodic Protection and Corrosion Specialist. He works with operators to evaluate corrosion threats, cathodic protection performance, electrical interference, and practical mitigation strategies for critical pipeline infrastructure.

About Audubon

Founded in 1997, Audubon Companies LLC provides EPC, consulting, fabrication, and operations and maintenance services to energy and industrial operators across the globe. We bring agile, collaborative project solutions—dedicated in every phase to safety, quality, and results. For our clients and communities, Audubon designs, builds, and sustains what matters.

Sources for citation

[1] IRENA, Renewable Capacity Highlights 2025 (updated July 2026)

Reports 692 GW of renewable additions in 2025, including 511 GW solar and 159 GW wind; renewables were 85.6% of total global capacity expansion in 2025 versus 92.0% in 2024; the United States added 34.0 GW solar in 2025.

[2] U.S. EIA, Solar and battery storage to lead new U.S. generating capacity additions in 2025

Reports that 30 GW of utility-scale solar was added in 2024, accounting for 61% of that year’s U.S. utility-scale capacity additions.

[3] Lawrence Berkeley National Laboratory, Land Requirements for Utility-Scale PV

Provides 2019 median direct-array power-density benchmarks of 0.35 MWdc/acre for fixed-tilt and 0.24 MWdc/acre for tracking plants. The 200-MWdc/830-acre example in the article is an explicit calculation from the tracking benchmark.

[4] PHMSA, Advancing the Safe Transportation of Energy and Hazardous Materials

PHMSA’s current by-the-numbers summary lists 3.3 million miles of regulated pipelines and 64% of U.S. energy commodities transported by pipeline.

[5] NREL et al., Electrochemical Mechanisms of Leakage-Current in Photovoltaic Modules

Peer-reviewed open-access research on PV leakage-current pathways and the influence of temperature, humidity, geometry, voltage, and impurities.

[6] Li et al., Research on the Impact of PV Power Generation Systems on Pipeline AC and DC Interference

160-MW modeled case: less than 5 mV DC potential shift; maximum AC current density of 67 A/m2.

[7] 49 CFR 192.473 – External corrosion control: Interference currents

Gas-transmission interference-survey and mitigation requirements.

[8] 49 CFR 195.577 – What must I do to alleviate interference currents?

Hazardous-liquid requirements to identify, test for, and minimize stray currents.

[9] ISO 21857:2021 – Prevention of corrosion on pipeline systems influenced by stray currents

AC/DC stray-current corrosion evaluation and mitigation principles.

[10] ISO 15589-1:2026 – Cathodic protection of on-land pipeline transportation systems

Current cathodic-protection standard for on-land pipelines.

[11] AMPP, Pipelines and Underground Systems

Corrosion-cost context: $7B gathering/transmission; $5B gas distribution.