We’re Ready to Take Charge of Your EHV, HV & MV  Electrical Power Engineering  Needs

Most developers engage us at one of four moments, and the earlier the better.

• Before you file. We run pre-application screening — preliminary load flow and short circuit analysis on the candidate POI, review of available headroom, and a realistic view of likely network upgrades. This is the cheapest engineering you will ever buy, because it tells you whether a site is worth a deposit at all.
• At application. We prepare and quality-check the technical exhibits: single-line diagrams, plant configuration, generator and inverter data sheets, PSS®E and PSCAD models, and the reactive capability documentation. Deficient technical data is one of the most common reasons requests are cured or dropped.
• During the study. We independently reproduce the transmission provider’s results, identify constraints that are driving your assigned upgrades, and prepare technically credible comments during the customer engagement window.
• After the study. We take the interconnection facilities defined in your LGIA and design them — substation, POI, protection, metering and telecom — through construction and energization.

Order No. 2023 replaced the old first-come, first-served serial process with a first-ready, first-served cluster process. Projects are studied in groups on a defined calendar rather than one at a time, with firm deadlines and financial penalties on transmission providers that miss them. In broad strokes the cycle runs through a 45-day cluster request window, a 60-day customer engagement window that includes a single group scoping meeting, a cluster study targeted at roughly 150 days, potential restudies triggered by higher-queued withdrawals, and then the facilities study.

The rule also raised the bar on readiness. Interconnection customers must demonstrate 90% site control at the time of request and 100% site control when the facilities study agreement is executed, post commercial readiness and study deposits, and provide a deposit tied to a percentage of estimated network upgrade costs at LGIA execution. Withdrawal penalties escalate the later you exit.

Where projects get hurt: incomplete or non-conforming models that trigger a deficiency notice; unrealistic plant configurations that produce inflated upgrade costs; site control that cannot be evidenced on the transmission provider’s timeline; and, most often, discovering a fatal constraint months after the deposit was already at risk. Our role is to compress those unknowns to the front of the process, when they are still cheap to solve. Confirm the exact windows, deposit amounts and penalty structure in your transmission provider’s FERC-approved tariff — compliance filings differ by region.

Often, yes — but only if the assignment is examined technically rather than accepted at face value. We start by reproducing the study to understand exactly which contingency, thermal limit or voltage violation is driving the cost, and whether your project is genuinely the cause or simply the last request in the cluster to be assigned a shared constraint.

From there the realistic levers include: resizing or re-phasing the project so it falls under a binding threshold; adding or repositioning reactive support to resolve a voltage-driven upgrade at a fraction of the cost of a line rebuild; adopting an energy storage or hybrid configuration that changes the injection profile; accepting a provisional, conditional or surplus interconnection service arrangement; proposing a control scheme or curtailment agreement in place of physical steel; or reallocating cost among cluster participants where the shared-upgrade math is demonstrably wrong.

Not every project can be rescued, and we will tell you plainly when the constraint is structural. But an independent second look before you withdraw is inexpensive relative to a forfeited deposit and a lost site.

The required set depends on voltage class, interconnection agreement and jurisdiction, but a transmission-connected generating facility typically needs most of the following:

• Load flow / power flow — confirms thermal and voltage performance under normal and contingency conditions; drives most network upgrade findings.
• Short circuit and device duty — establishes available fault current and verifies breaker and equipment interrupting ratings.
• Protection coordination and relay setting — ensures selective, dependable clearing of faults and correct coordination with the utility’s scheme.
• Transient stability / dynamic analysis — demonstrates the plant rides through and recovers from system disturbances.
• EMT (electromagnetic transient) analysis — required for most inverter-based plants; captures control interactions that phasor tools cannot.
• Reactive power capability and voltage control — proves compliance with the power factor range and voltage schedule in your agreement.
• Harmonics and power quality — evaluates distortion against IEEE 519 limits; increasingly scrutinized on large inverter-based plants.
• Grounding grid design per IEEE Std 80 — verifies step and touch potentials are within safe limits.
• Arc flash and incident energy per IEEE Std 1584 — required for worker safety, labeling and NFPA 70E compliance.
• Insulation coordination and surge protection — sizes arresters and confirms BIL margins.

On solar, wind and BESS projects we also commonly perform sub-synchronous oscillation screening, plant-level controller tuning studies, and collector system loss and ampacity analysis.

EMT modeling in PSCAD is now standard practice for inverter-based resources — solar PV, wind and battery storage — in most ISO and RTO territories, and it is frequently required for any plant of meaningful size interconnecting at transmission voltage. Positive-sequence tools such as PSS®E simply cannot represent the fast inner-loop controls of a modern inverter, and it is exactly those controls that produce the sub-synchronous and control interaction phenomena grid operators are now screening for.

Models get rejected for predictable reasons: the OEM-supplied black-box model does not match the actual firmware revision or the settings you intend to deploy; plant controller and inverter models are not integrated so plant-level volt/VAR response is wrong; collector system and transformer impedances are simplified past the point of usefulness; initialization fails or the model will not run to a stable flat start; or the submitted model does not reproduce the behavior claimed in the accompanying report.

We build, integrate, benchmark and validate these models — including reconciling PSCAD behavior against the PSS®E and PowerFactory representations of the same plant — so what you submit survives review the first time. A rejected model does not merely cost a resubmittal fee; in a cluster process it can cost you a study cycle.

IEEE Std 2800-2022 is the industry standard for interconnection and interoperability of inverter-based resources connecting to transmission systems. It sets minimum performance requirements for voltage and frequency ride-through, reactive power capability, active power control, power quality, protection, and modeling and validation. It is not self-executing federal law — it becomes binding on your project when a transmission provider, ISO/RTO or state adopts it into a tariff, interconnection agreement or planning manual, which a growing number have done or are actively moving to do.

Practically, if you are developing a transmission-connected solar, wind or storage plant today, you should assume some form of IEEE 2800-aligned performance requirement will apply and design for it rather than retrofit to it. Demonstrating compliance generally means a combination of equipment certification and datasheets from the inverter OEM, plant-level studies and simulations showing the aggregate plant meets each requirement at the POI, validated EMT and phasor models, and commissioning test evidence.

Keentel performs IEEE 2800 gap assessments, plant-level compliance studies and the supporting model validation, and we can tell you early whether your selected inverter and plant controller can meet the requirement at all — which is a procurement decision, not just an engineering one.

We deliver complete, construction-ready substation and switchyard packages from 4.16 kV up through 500 kV, covering both the physical and electrical scope. A typical full package includes general arrangement and plan and section drawings; equipment layout with clearances per NESC and applicable standards; foundation and structure loading criteria coordinated with the structural engineer; grounding grid design per IEEE Std 80; lightning and direct stroke shielding; raceway, conduit and cable schedules with sizing calculations; AC and DC auxiliary systems including station service and battery/charger sizing; one-line, three-line and relay AC/DC schematic diagrams; wiring and connection diagrams; protection and control panel design with relay settings; SCADA, RTU and communications interfaces; metering and revenue metering design; and a bill of materials with technical specifications for procurement.

We work at whatever stage you need — conceptual and feasibility layouts for budgeting, 30/60/90% design development, issued-for-construction drawings, or as-built reconciliation. We also support factory acceptance testing, field commissioning, and energization sequencing, and we can develop or update a client’s substation design standards so future projects start from a consistent baseline.

An Owner’s Engineer is your independent technical representative — an engineer whose only obligation is to the asset owner. Your EPC contractor is a capable partner, but its commercial incentives are to build to the contract at the lowest cost, on the fastest schedule. Those incentives are not always aligned with the 30-year performance of the asset you will own, or with the technical representations you made to your lenders and offtaker.

As Owner’s Engineer, Keentel typically performs technology and equipment selection support; review of the EPC’s design deliverables against the contract, applicable standards and the interconnection agreement; specification and bid package development; bid evaluation and vendor technical due diligence; energy yield and performance model review; construction monitoring and site inspections; punch list management; witness of factory and field acceptance testing; commissioning oversight; and substantial and final completion certification.

The value is asymmetric. Owner’s engineering usually runs a small fraction of project capex, while a single missed protection setting, undersized transformer or unverified performance test can cost multiples of that in remediation or lost production. Lenders and tax equity investors increasingly expect an independent engineer to be in the room regardless.

We support renewable and storage assets across the full lifecycle. On the electrical side that includes DC and AC collector system design and optimization, string and combiner layout, inverter and MV transformer sizing and placement, cable ampacity and voltage drop analysis, collector substation and POI design, plant controller and SCADA architecture, and the balance-of-plant MEP scope — auxiliary power, lighting, grounding, fire alarm, HVAC for equipment enclosures and control buildings.

For battery energy storage specifically, we address the issues that distinguish BESS from PV: augmentation and capacity fade planning, round-trip efficiency and auxiliary load accounting, thermal management and enclosure power, NFPA 855 and UL 9540A considerations in coordination with the fire protection engineer, protection of a bidirectional resource, and controls for the specific value streams the asset is contracted to provide.

On the analysis side we run the interconnection and compliance studies these plants need — EMT and stability, reactive capability at the POI across the operating range, harmonics, ride-through verification, and grounding and arc flash for the collector and substation equipment. We also perform independent review of energy yield models and support commissioning and capacity testing.

Very possibly, and this is the compliance issue catching the most owners off guard right now. Historically many inverter-based plants sat below the Bulk Electric System registration thresholds and carried no mandatory reliability obligations. Following FERC Order No. 901, NERC has been implementing an initiative to identify and register previously unregistered inverter-based resources that materially affect the Bulk Power System.

The screening criterion generally applied is an aggregate nameplate capacity of 20 MVA or more delivered to a common point of connection at 60 kV or above. A 100 MW plant interconnected at transmission voltage sits well inside that. Newly registered entities are brought in as Generator Owner and Generator Operator functions, with Reliability Standard obligations phasing in on a published compliance date schedule that NERC updates periodically.

The practical consequence is that plants designed and built with no compliance program now need one — protection system maintenance programs, facility ratings, model verification, disturbance monitoring, ride-through documentation and evidence retention. Keentel performs applicability assessments, builds the compliance program from scratch, and produces the technical evidence. Confirm your specific status and dates with your Regional Entity, as thresholds and schedules continue to be refined.

“693” refers to the FERC order that made NERC’s Operations and Planning Reliability Standards mandatory and enforceable. For a generation asset owner, the practical scope spans the PRC family (protection system maintenance and testing, misoperations, coordination, disturbance monitoring, ride-through), FAC (facility ratings, connection requirements, system operating limits), MOD (generator model verification and data reporting), VAR (voltage and reactive control), and portions of COM, EOP, PER and TPL. Non-compliance carries real financial penalties, but the more common cost is the disruption of an audit finding and mitigation plan on an operating asset.

Our support model has four parts. First, applicability and gap analysis — what actually applies to your registered functions, and where you stand today. Second, remediation — the underlying engineering that the standards require, including relay maintenance programs, facility ratings calculations, MOD-025/026/027 model verification testing, PRC-019 and PRC-024/029 coordination and ride-through studies, and PRC-002 disturbance monitoring design. Third, evidence — building RSAW responses and the documented, dated, retrievable proof auditors expect, not just correct engineering. Fourth, audit support — mock audits, Align portal submissions, live participation during the audit, and mitigation plan development if a finding lands.

Start with a no-cost consultation. Tell us the project — technology, size, POI voltage, interconnecting utility or ISO, queue position and current status — and we will tell you candidly what engineering it needs, in what order, and where the schedule and cost risks sit. That conversation is useful to you whether or not you engage us.

Commercially, we structure work three ways depending on how defined the scope is: fixed-fee for well-defined deliverables such as a specific study or a substation design package; time-and-materials for advisory, owner’s engineering and open-ended support; and retainer or master service agreements for developers with a portfolio, which is usually the most economical route for repeat work. Fees depend on voltage class, project complexity and jurisdiction rather than a published rate card, so we quote per scope.

Timelines vary with scope: a focused study can turn in a few weeks, a full substation design package typically runs several months through IFC, and compliance and owner’s engineering engagements track the life of the project. To scope accurately we generally need your single-line diagram or site plan, POI details and voltage, equipment datasheets or a shortlist, your interconnection agreement or study reports if issued, and your target milestone dates.