Q1: What exactly is “withdrawal capacity,” and how is it different from my interconnection capacity or transformer rating?

Withdrawal capacity is the maximum power your facility can draw from the transmission system in a given hour without causing a criteria violation — thermal, voltage, or stability — anywhere on the monitored network under the applicable contingency set. A transformer rating is a piece of equipment; contractual interconnection capacity is a legal number; withdrawal capacity is the physics number, and it binds. It varies hourly because facility ratings change with season, the surrounding system’s loading changes with demand and dispatch, and the contingency that binds on a summer peak afternoon may be irrelevant on a mild spring night. An 8760 study makes that variation explicit instead of hiding it behind one conservative number.

Q2: Why 8,760 hours? Wouldn’t summer-peak and winter-peak studies suffice?

Peak studies answer the RTO’s question — is the system reliable at its stress points? They cannot answer the developer’s questions: how much energy can the site actually serve across a year, how large must the battery be, and what does curtailment exposure cost? Those are distribution questions. The deficit that sizes your battery’s energy rating may occur nowhere near system peak — a shoulder-season evening with a line out for maintenance is a classic culprit. Only an hourly model exposes deficit duration, frequency, and clustering: the parameters that decide whether a 4-hour battery suffices or a 10-hour system is required, and whether recharge windows exist between events.

Q4: What is an injection study, and when do I need one?

An injection study is the generation-side mirror of the withdrawal analysis: it establishes how much power a resource can inject at its POI, under what service type, with what system impacts — power flow and deliverability at proposed output, short circuit contribution, transient stability, and system-strength screening for inverter-based resources. You need one whenever a resource will export; you need its inverse — the zero-injection demonstration — whenever a resource is designed not to export and that property carries regulatory or financial consequences, as it does in SPP’s HILLGA security calculation. In co-located projects the injection and withdrawal analyses share models, assumptions, and consequences, and are best performed as one coupled study.

Q5: What is Maximum Injection Capability, and why does it matter so much?

MIC is the maximum real power a generating facility may inject at its Point of Interconnection. In SPP’s HILLGA framework it drives three things: the sizing ceiling relative to the supported load, the LLRIS operating envelope, and the financial security obligation, which is computed per MW of MIC. For a non-exporting behind-the-meter configuration, MIC is the difference between a substantial security obligation and none — which is why the zero must be engineered and demonstrated, not merely declared.

Q6: Is the HILLGA security the same thing as the study deposit?

No — and conflating them is a common budgeting error. The study deposit funds the RTO’s study work and is payable to enter the process. The security is a separate financial-assurance obligation computed from injection capability. A zero-injection project may have a strong case that security computes to zero; it should still budget the deposit.

Q7: Can the security really be $0 for a zero-injection project?

The formula computes security per MW of MIC, so a genuine MIC of 0 MW yields $0 by the formula’s own terms. Two qualifications govern whether that arithmetic holds. First, jurisdiction: if the resource interconnects outside SPP’s functional control, BP 7250 §6.3 applies rather than Attachment BB, and the Attachment BB security arguably never attaches. Second, enforceability: if processed under Attachment BB, SPP can fairly ask what makes the zero physical rather than intentional — answered by a protection-backed non-export scheme (reverse-power/directional relaying with defined trip logic), failure-mode analysis, and EMT demonstration. Present it that way, request SPP’s written concurrence, and do not let the pro forma assume zero until the concurrence is in hand.

Q8: How do I know whether my resource is in the Attachment BB (HILLGA) lane or the BP 7250 non-jurisdictional lane?

The test is whose facilities the resource interconnects to. Attachment BB addresses generation interconnecting to the SPP transmission system to serve a HILL. BP 7250 §6.3 addresses generation interconnecting to facilities not under SPP functional control — behind the customer’s meter, on distribution, or on non-OATT transmission-owner facilities. Applications, studies, security, and agreements all differ between lanes, and the determination turns on facts — point of interconnection, ownership, functional control — that should be established before any application is drafted. It is the first task in every co-located engagement we run.

Q9: If my resource is non-jurisdictional, does SPP just ignore it?

No. Non-jurisdictional does not mean invisible. The transmission owner notifies SPP of units of 5 MW or more; an Affected System Study Agreement with SPP may be required; the resource must be specified — including whether a BESS will register as a Market Storage Unit; SPP performs stability analysis under BP 7250 §8 within a 90-day window at the transmission owner’s request; and the resource still appears explicitly in the planning models per the MDAG manual.

Q10: Are the HILL, HILLGA, and related studies sequential or parallel?

One hard gate, then parallel. The executed HILL-Load Connection Study agreement must precede the HILLGA request — the load process leads. Past that gate, the HILLGA SIS, the transmission owner’s Facilities Analysis, and affected-system evaluation share one 90-day window, and BP 7250 stability runs its own clock. The governing constraint in practice is not the framework’s structure but submittal completeness: every clock starts only on complete, validated data, so model and data readiness is the real schedule driver.

Q11: Where does battery charging belong in the load application?

Inside the HILL’s requested MW and ten-year forecast, explicitly, from the first draft. Charging is real withdrawal the delivery point must support, and SPP’s modeling practice treats storage explicitly rather than as a load reduction. Carried openly, the storage-as-load evaluation happens within the HDPS on your assumptions; buried, it resurfaces as a deficiency notice, a forecast inconsistency, or an undersized delivery point discovered at the worst possible time.

Q12: How does a zero-injection planned resource become a Designated Resource under Attachment AX?

This is the framework’s sharpest open seam, and our answer is an interpretation, clearly labeled: because the resource requests zero firm transmission service, there is no deliverability for the Aggregate Transmission Service Study to evaluate, and the conversion at commercial operation should be administratively simple — carried by the designation filing and registration data. If the resource remains undesignated, the consequence falls on the load’s supply-adequacy accounting: cover with other Designated Resources or remain on provisional service with its curtailment exposure. Any move to full network-resource status with injection rights would create a network interface and exit the non-wires construct entirely. Obtain SPP’s written position on the conversion mechanics before an AX filing strategy hardens.

Q13: How will SPP model my non-exporting BTM battery in the studies?

Explicitly — never netted. Per the MDAG manual, expect an explicit resource at the facility bus in the power flow (delivered as an IDEV), explicit dynamics (DYR records using the standard storage model set with the plant controller in load-following, zero-export mode), and study cases covering both charging and discharging states. The conservative planning default is typically the resource offline or charging — the state that stresses the delivery point hardest — which is why pre-agreeing dispatch assumptions at the scoping call is how you ensure the study evaluates the facility you designed.

Q14: Why do you size batteries in NREL’s SAM instead of a spreadsheet or proprietary tool?

Fidelity, auditability, and automation. SAM’s lithium-ion model captures round-trip efficiency, voltage behavior, temperature, and both calendar and cycle degradation — so the battery that covers year-1 deficits is verified against year-10 capacity, and clustered events are tested against real state-of-charge trajectories rather than energy arithmetic. SAM is free, open-source, and DOE/NREL-maintained, so a lender’s independent engineer can rerun our files — not true of black boxes. And the PySAM interface lets us sweep hundreds of power/energy candidates programmatically and publish the full feasibility frontier rather than a single point. SAM does not do power flow — which is why the transmission layer stays in the planning model and hands SAM the hourly grid limit as a constraint.

Q15: Doesn’t charging the battery consume the same grid headroom the load needs?

Yes — and this is where naive sizing fails. A battery that covers Monday’s deficit is useless Tuesday if there was no headroom to recharge Monday night. In our workflow the 8760 withdrawal series is applied inside SAM as the hourly limit on total facility draw — load plus charging — so the simulation only recharges when and to the extent surplus headroom (or on-site PV) exists, and any sizing candidate that cannot maintain state of charge through clustered deficit sequences shows up as unmet load and is rejected. Recharge feasibility is enforced by construction, not checked as an afterthought.

Q16: Our load is flexible — we can curtail workloads. Does that change the analysis?

It upgrades it from sizing to optimization. Every MW-hour of curtailable load reduces required battery energy one-for-one during deficit hours, at the cost of lost output. With the hourly deficit series in hand, that trade is computable: how many hours per year flexibility would be called, at what depth, and how storage capex compares against curtailment opportunity cost across sizing candidates. In markets with explicit flexible-load frameworks, and in conditional-service constructs that trade speed for curtailment exposure, this analysis is precisely how a developer decides how much firmness to buy versus how much flexibility to sell.

Q17: What model deliverables should a complete co-located submittal include?

One mutually consistent set: IDEV files placing the load and resource in the power flow; DYR dynamics for the resource with the non-export control representation; CMLD and PERC1 dynamic load models for the facility (PERC1 being SPP’s preferred model under BP 7850), encoded to the HILL fault ride-through requirements; and a PSCAD EMT model — recommended at submission because SCRCCT screening failure triggers supplemental EMT studies outside the 90-day window, and because the EMT model is also where the non-export protection scheme is demonstrated as a physical property. Internal consistency across the set matters as much as each model’s quality: SPP’s verification practice compares them against each other.

Q18: How accurate is a Shadow Load Study — will the RTO get the same answer?

We build the SLS to be methodology-aligned and document that alignment element by element: the same class of planning models (obtained through the RTO’s data processes under executed confidentiality agreements), TPL-001-aligned contingency definitions — in SPP, the transmission owners’ own contingency files where available — and criteria drawn from the RTO’s planning documents. Perfect prediction is not the claim; the official study may use a newer model build or updated assumptions. The claim is that surprises shrink from existential to marginal: the shadow study’s binding constraints and order-of-magnitude upgrade exposure are what the official study confirms, and a developer who ran it negotiates details in the study report rather than discovering fundamentals.

Q20: Does this methodology travel beyond SPP?

The tariff names change; the physics does not. The same withdrawal-and-injection stack applies in ERCOT (whose large flexible load framework SPP expressly drew upon for its HILL ride-through requirements), in CAISO and the California utilities’ hosting-capacity and deliverability processes, in PJM and MISO amid their large-load and co-location reforms, and in the tighter Northeastern systems where headroom is scarcest. Our practice spans these markets with large-load and storage engagements from 50 MW to 1 GW, applying the same disciplines everywhere: the RTO’s own models where accessible, TPL-aligned contingencies, system-strength screening, NREL-toolchain storage design, and written-confirmation strategy with the RTO

Injection & Withdrawal Studies Guide for Grid Interconnections

A Coordinated Electric System Interconnection Review—the utility’s deep-dive on technical and cost impacts of your project.

Challenge: Frequent false tripping using conventional electromechanical relays
Solution: SEL-487E integration with multi-terminal differential protection and dynamic inrush restraint
Result: 90% reduction in false trips, saving over $250,000 in downtime

ERCOT enforces all of the above through simulation, which means your model is your compliance case. The bar is now high:

Whole-facility scope. The model must represent everything the IT load, the UPS and power conversion, the cooling plant, the protection and control systems in formats compatible with ERCOT's study platforms (PSS/E, PSCAD, TSAT).
Real control loops, not approximations. Generic textbook representations are unacceptable. The model must capture the actual inner control behavior of your power electronics.
Hardware-validated converter models. For electronic loads, the PSCAD model must be benchmarked against actual hardware testing including voltage ride-through and subsynchronous response. A model assembled from standard PSCAD library blocks fails by definition, because a generic block has never been tested against your vendor's hardware. The good news: validation is a hardware-type test, so results for a given converter product are reusable across every facility that uses it.
Format migration. Facilities that previously submitted the older composite load model (CMLD) format must transition to EPRI's PERC1 format.
Three checkpoints. Models are reviewed before the stability study begins (no model, no study), before each quarterly stability assessment, and for electronic loads one final time before energization, when you must submit as-built models with a documented comparison against the previously studied data and a sworn attestation that the model matches actual field settings. ERCOT's review takes 10 business days, extendable by 20 put it on your critical path.
A living obligation. Change your technology, controls, or relay settings in a way that affects ride-through including converting a crypto mining site to an AI data center — and you've triggered a new interconnection study, even if your megawatts don't change.

Parameter	Detail
System	230 kV / 138 kV transmission corridors, wind and wet-snow icing exposure
Data basis	15 years of minute-resolution forced-outage records + regional weather observations
Core methods	Event grouping, MVA performance curves, time-to-95%-restore, area outage rate curves, fragility modeling, rerun-history benefits, exceedance and log-domain risk metrics
Headline result	≈85% of maximum resilience benefit at 60% of original capital; worst-event restoration window cut from 11 days to 5 in rerun-history terms
Decision supported	Capital portfolio selection; resilience plan filing; post-investment verification framework

System / Topic	Governing Standard(s)	What It Controls
Overall plant electrical distribution	IEEE 141 (Red Book); IEEE 666	Distribution architecture, voltage selection, design of generating station auxiliary service systems
Power system studies	IEEE 399 (Brown Book); IEEE 551	Load flow, symmetrical/asymmetrical short circuit, motor starting methodologies down to the lowest LV panelboard
Protection & coordination	IEEE 242 (Buff Book); IEEE 3004.5; IEEE C37 series	Generator relaying (21, 59N, 87G), time-current coordination, selective clearing between LV and MV tiers
GSU / UAT / SST transformers	IEEE C57.12.00 and C57 family	Transformer ratings, impedance, testing, loading
HV switchyard breakers	IEEE C37.06	AC high-voltage circuit breaker preferred ratings
MV switchgear (13.8 kV)	IEEE C37.20.2; IEEE C37.20.7	Metal-clad construction, compartmentalization, vacuum breakers; arc-resistant design with plenum venting
MV cable	UL 1072; ICEA S-93-639 (NEMA WC 74)	Type MV-105 shielded cable, 133% insulation level for HRG systems
LV switchgear (480 V)	IEEE C37.13; UL 1558	Metal-enclosed LV power circuit breaker switchgear to 635 V, draw-out ACBs with electronic trip units
Motor control centers	UL 845; NEMA ICS 18	LV-MCC construction, MCCB/MCP protection for motors under ~200 HP
Motors	NEMA MG-1	Motor performance, starting characteristics, service factors
DC & battery systems	IEEE 485; IEEE 946	Lead-acid battery sizing (125/250 VDC), DC auxiliary system design
Grounding	IEEE 80; IEEE 142 (Green Book)	Ground grid step/touch potential limits; system grounding including high-resistance grounding
Lightning protection	IEEE 998	Direct-stroke shielding of switchyard and outdoor generator structures
Arc flash & electrical safety	IEEE 1584; NFPA 70E	Incident energy calculation; worker safety boundaries and PPE
Fire protection	NFPA 850	Fire protection and risk management for combustion turbine generating plants
Installation code	NEC (NFPA 70); NESC	Wiring methods inside the plant fence; overhead/outdoor clearances at the switchyard
Interconnection & compliance	FERC LGIP; NERC MOD-025/026/027, PRC-019/024/029, FAC-008	Interconnection process, model validation, protection/ride-through coordination, facility ratings

IFC / Construction Deliverable	Purpose
Stamped IFC packages	Legal basis for construction; P.E. responsible charge
Final relay settings & TCCs	Protection as-installed matches the coordination study
Calculation archive	Owner records; NERC audit evidence trail
Commissioning procedures	Safe, sequenced energization; MOD field testing
Construction support	RFIs, field changes, FAT/SAT witness
As-builts & model handoff	Operating baseline; future study currency

Metric	Outcome
Defects found pre-occupancy	Three topology defects and one settings-mismatch family corrected before load migration; the shared-switchboard defect alone would have invalidated the concurrently-maintainable claim on day one
IST findings	Fourteen additional discrepancies surfaced under scenario testing (control logic, alarm mapping, one generator sequencing fault) — all closed before handover instead of during operations
Black-building test	Passed on second execution; the first attempt exposed the generator sequencing fault under true block load, exactly the failure the compressed plan would never have found
Handover quality	Operations team certified on the actual failure scenarios; corrected EOPs and settings documentation delivered as controlled documents
Business outcome	Occupancy proceeded three weeks behind the original date — against an independent estimate that the uncorrected sequencing fault carried a high probability of a full facility outage within the first year

Part 2 — Frequently Asked Questions: Large Load Interconnection

Contact	Details
Headquarters	400 N Ashley Dr STE 2600, Tampa, FL 33602
Phone	(813) 389-7871
Email	contact@keentelengineering.com
Florida Firm Registration	No. 36853
Additional Offices	Austin, TX • Sacramento, CA • Baltimore, MD

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

ERCOT Interconnection Roles

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

ERCOT Interconnection Roles

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

ERCOT Interconnection Roles

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

ERCOT Interconnection Roles

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

ERCOT Interconnection Roles

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

ERCOT Interconnection Roles

Who	Acronym	Plain-English Role
ERCOT	—	The grid's air traffic controller. It doesn't own power lines or plants; it directs the flow of electricity across most of Texas and referees the admission process for new generators.
Interconnecting Entity	IE	You — the developer or owner trying to connect a new plant (or significantly modify an existing one). You file the application and drive the process.
Resource Entity	RE	The registered owner/operator of the generator once it becomes an official market participant. Often the same company as the IE, wearing a different hat.
Qualified Scheduling Entity	QSE	Your plant's voice on the grid. The QSE handles round-the-clock communications with ERCOT — telemetry, schedules, dispatch instructions. Every generator must have one.
Transmission Service Provider	TSP	The utility that owns the wires and substation you'll connect to. The TSP runs your detailed study, builds the connection facilities, and signs your interconnection contract.
RIOO-IS	—	ERCOT's online portal where the whole process lives — applications, documents, status tracking, and checklists all flow through it.

Every large energy project every AI data center, every co-located battery, every on-site generation campus ultimately stands or falls on two numbers that no one hands you:

How much power can this site withdraw from the grid — hour by hour, across a real year of system conditions?

And how much power can it inject or, just as importantly, can it prove it will inject nothing at all?

The first number sizes your load, your battery, and your business case. The second determines your interconnection pathway, your study scope, and in SPP’s new HILLGA framework your financial security obligation. Together they define the operating envelope of the modern powered site, and getting either one wrong is the difference between a project that energizes on schedule and one that discovers, a deposit and six months later, what its point of interconnection can actually support.

Keentel Engineering performs both analyses as one integrated practice: withdrawal studies Shadow Load Studies, 8,760-hour grid-headroom modeling, and BESS sizing in NREL’s System Advisor Model and injection studies generation-side system impact analysis, Maximum Injection Capability engineering, system-strength screening, and the protection-backed zero-injection demonstrations that the newest frameworks demand. This guide explains both, how they couple in co-located configurations, how they map onto SPP’s HILL and HILLGA processes (including the frontier questions the six-month-old framework has not yet settled), and how to get authoritative answers from SPP itself. Twenty detailed FAQs follow.

Withdrawal capacity is not your transformer rating, not your contractual service level, and not a constant. It is the maximum MW your facility can draw in a given hour without causing a thermal, voltage, or stability violation somewhere on the monitored network under the applicable contingency set and it moves with seasonal ratings, regional load, dispatch, and outages. A rigorous withdrawal study resolves it in three layers:

Layer 1 The Shadow Load Study (SLS)

Before applying, replicate the analyses the RTO and transmission owner will perform on your application, with the same class of models and methodology: AC power flow with thermal and voltage screening, a NERC TPL-001-aligned contingency framework (in SPP, the transmission owners’ own contingency files where available), short circuit review, and system-strength screening — in SPP, consistent with the SCRCCT criteria (SCR/WSCR/CSCR ≥ 6.0; CCT ≥ 0.15 s). The output is foresight: the expected study result, the binding constraints, the indicative upgrade exposure, and the maximum supportable withdrawal by season — known before deposits are paid and study clocks start.

Layer 2 The 8760 model

Grid capability is a distribution, not a number. We build a representative-state matrix season × system load level × outage condition × dispatch pattern, typically 20–40 states solve the withdrawal limit for each state with automated bisection in the planning model, then classify every one of the year’s 8,760 hours into its state using multi-year historical system load, ratings calendars, outage seasonality, and weather. The result: an hourly withdrawal-capacity time series with every hour traceable to its governing constraint, plus duration curves and the statistic that drives everything downstream the deficit hours, when grid capability falls short of the facility’s demand.

Layer 3 BESS sizing in SAM

The deficit structure converts to storage design inside NREL’s System Advisor Model the DOE’s free, open-source platform whose lithium-ion battery model uniquely captures calendar and cycle degradation, temperature, and voltage behavior.

Our workflow applies the 8760 series as SAM’s hourly grid-import limit, the facility’s demand as the load profile, and on-site PV from site weather data then sweeps battery power/energy candidates via PySAM to find the minimum-size frontier achieving zero unmet load or the client’s reliability target. Critically, recharge feasibility is enforced by construction: the battery may only charge within remaining hourly headroom, so any candidate that cannot sustain state of charge through clustered deficit events is rejected automatically. Weather-year ensembles yield probabilistic (P50/P90-style) sizing; loading the applicable utility rate structure yields dispatch economics in the same run. The deliverable is a document a lender’s independent engineer can download the tool and rerun.

Every generation or storage resource faces the mirror-image analysis. An injection study answers: how much power can this resource push into the grid, under what service type, with what system impacts — and what does that answer cost?

For exporting resources, the injection study is the classic generation interconnection discipline: power flow and deliverability analysis at the proposed output, short circuit contribution, transient stability, and — decisive for inverter-based resources — system-strength screening, because a converter injecting into a weak grid is where control instability, sub-synchronous oscillation, and ride-through failures live.

In SPP’s HILLGA pathway, the injection analysis runs through a 90-day System Impact Study evaluating steady-state performance, transient stability, short circuit ratio, and the same SCRCCT screen as the load side — with supplemental EMT studies outside the 90-day window if the screen fails, which is why a submission-ready PSCAD model is the single best schedule insurance a project can buy.

The number that governs everything is Maximum Injection Capability (MIC) — the maximum real power the facility may inject at the Point of Interconnection. In HILLGA, MIC drives the sizing ceiling (the supported load’s MW times the higher of 110% plus the seasonal Planning Reserve Margin, or 125%), frames the Load Limited Resource Interconnection Service envelope, and — most consequentially — drives the financial security obligation, computed per MW of MIC.

For non-exporting resources, the injection study inverts: the engineering task becomes proving the zero. A behind-the-meter battery designed never to export has, in principle, an MIC of 0 MW — and by the security formula’s own arithmetic, zero MIC computes to zero security. But a declared zero is an argument; a protection-backed zero is a fact.

The credible demonstration is an engineered non-export scheme — reverse-power and directional relaying with defined trip logic — subjected to failure-mode analysis and demonstrated in the EMT model operating correctly through disturbances, then presented to SPP with a request for written concurrence on the security treatment. This zero-injection demonstration is itself an injection study, and it is fast becoming one of the most requested analyses in our practice.

In a co-located site data center load plus behind-the-meter battery and generation — injection and withdrawal are not separate questions. They are one envelope:

Charging is withdrawal. The battery’s charging demand draws through the same POI as the servers, must fit inside the same hourly headroom, and belongs inside the load’s requested MW and ten-year forecast from the first draft. Bury it, and it resurfaces as a deficiency notice or an undersized delivery point.
Discharge is withdrawal relief, not injection — in a non-exporting design, the battery serves load behind the meter, reducing grid draw without ever crossing the POI outbound. The protection scheme is what keeps that statement true through every disturbance and failure mode.
The sizing analyses feed each other. The withdrawal study’s deficit hours size the battery; the battery’s charging profile reshapes the withdrawal requirement; the on-site generation’s output shifts both. This is why we run the coupled analysis as one model set with one team, rather than a load study and a generation study that meet for the first time in the RTO’s review.

For a jurisdictionally clean result, one determination precedes everything: which lane the resource is in. Generation interconnecting to the SPP transmission system to serve a HILL runs through HILLGA (Attachment BB).

Generation interconnecting to facilities outside SPP’s functional control — behind the fence, on distribution, on non-OATT facilities — runs through Business Practice 7250 §6.3 instead: transmission owner notification for units ≥5 MW, potential Affected System Study Agreements, resource specification (including whether a BESS registers as a Market Storage Unit), and SPP stability analysis under BP 7250 §8. Security, studies, agreements, and timelines all fork on this determination, which is why it is the first task in every co-located engagement we run.

A High Impact Large Load is any new or expanding single-site facility with peak demand ≥10 MW at ≤69 kV or ≥50 MW above 69 kV. The load side runs through the HILL Delivery Point Study (HDPS) — 90 days from a complete, validated submittal, covering thermal, voltage, short circuit, RMS dynamic performance against SPP’s Disturbance Performance Requirements, and SCRCCT screening — entered under Attachment AQ (sufficient Designated Resources) or Attachment AX (the Provisional Load Process, pairing the load with planned generation under provisional service).

The load models must satisfy Business Practice 7850, under which PERC1 is SPP’s preferred load model, and the facility must demonstrate compliance with SPP’s HILL Fault Ride-Through Requirements — constant-current disturbance behavior, recovery to ≥90% of pre-disturbance consumption within one second of voltage recovery, and ride-through of up to six reclose attempts in 90 seconds among them.

The generation side runs through HILLGA (Attachment BB): the 90-day SIS, the two-substation siting geometry, the 110%+PRM/125% sizing ceiling, LLRIS service, a five-year interconnection agreement, and a Consolidated Planning Process filing as the long-term exit.

The framework is fast — and it is six months old. Which brings us to the questions it has not yet answered.

On unsettled questions we distinguish what the documents say, our engineering interpretation, and what should be confirmed with SPP in writing. Four questions dominate current co-located planning:

1. Does the per-MW security apply to a zero-injection project?

The formula runs on MIC; a protection-enforced MIC of 0 MW computes to $0 by its own terms. Above the arithmetic sit two layers: if the resource is in the BP 7250 non-jurisdictional lane, the Attachment BB security arguably never attaches at all — and if it is processed under Attachment BB, expect SPP to probe enforceability, which is exactly what the protection-backed, EMT-demonstrated non-export scheme answers. Either way, the study deposit is a separate obligation and applies regardless. Obtain SPP’s written concurrence before the pro forma assumes zero.

2. Are the HILL, HILLGA/affected-system, and storage-as-load studies sequential or parallel?

One hard gate only: the executed HILL-Load Connection Study agreement precedes the HILLGA request. Past it, the HILLGA SIS, the transmission owner’s Facilities Analysis, and affected-system work share the 90-day window, and BP 7250 §8 stability runs its own clock — all parallel. Carry BESS charging inside the HILL MW from day one so the storage-as-load evaluation rides within the HDPS.

3. How does a zero-injection planned resource convert to a Designated Resource under Attachment AX?

The sharpest gap in the framework: the Aggregate Transmission Service Study presumes a network interface, and a zero-injection BTM resource has none. Our read: designation at commercial operation should be administratively simple precisely because zero firm transmission service is requested — no deliverability to study. If undesignated, the consequence is supply-adequacy accounting on the load side (cover with other Designated Resources or remain provisional). A conversion to full network-resource status with injection rights would create a network interface and exit the non-wires construct entirely. These are interpretations; get SPP’s written position before an AX filing hardens around them.

4. How does SPP model a non-exporting BTM resource?

Explicitly — never netted from load. SPP’s MDAG modeling manual requires energy storage and distributed resources to appear as explicit records: an IDEV placing the resource at the facility bus, DYR dynamics using the standard storage model set with the plant controller in load-following zero-export mode, studied in both charging and discharging states. The conservative planning default is typically the resource offline or charging — the state that stresses the delivery point hardest — so pre-agree dispatch assumptions at the scoping call.

Frontier questions are settled by asking SPP correctly, in writing, through the channel its staff actually work: the Request Management System (RMS).

The mechanics that first-timers learn the hard way: confidentiality agreements are executed at the individual level — one CD or NCD form per person, attached to the access ticket; Model on Demand is reserved for stakeholders in the annual model build, and the consultant’s path is the posted MDAG-series models (power flow, short circuit, dynamics) and planning contingency data on the secure file share which SPP staff will confirm carry the same information; and specificity wins a ticket stating purpose, study area, exact data sets, with the right NDAs attached, gets processed.

The strategic use is the written technical inquiry: frame the concrete configuration, pose the specific questions (the security treatment of a protection-backed zero MIC; the designation mechanics of a zero-firm-service resource), and request SPP’s position in writing. A written SPP answer obtained before filing is worth more than any consultant’s opinion — including ours — and converting every load-bearing interpretation into a confirmed position before strategy hardens is standing practice in our engagements.

Withdrawal side

Shadow Load Study report (binding constraints, seasonal withdrawal limits, upgrade exposure, SCRCCT indication and supplemental-study risk); methodology alignment memo mapping every analysis to its RTO/TO counterpart; the 8760 withdrawal-capacity series with hour-level constraint traceability, duration curves, and deficit statistics; SAM-based BESS sizing with the feasibility frontier, weather and phasing sensitivities, degradation-aware end-of-life performance, and dispatch economics; and, for portfolios, a normalized multi-site comparison matrix for capital allocation.

Injection side

generation-side system impact analysis; MIC engineering and the protection-backed zero-injection demonstration (relay scheme definition, failure-mode analysis, EMT proof); system-strength screening; and the written-concurrence strategy for security treatment.

The model set, as one consistent package

IDEV files; DYR dynamics with the non-export plant controller; CMLD and PERC1 load models encoded to SPP’s fault ride-through requirements per BP 7850; and a supplemental-stage-ready PSCAD EMT model — because SPP’s verification practice compares the models against each other, and internal consistency matters as much as individual quality.

Through the process

jurisdictional lane determination, application preparation (including SPP’s online forms and the Additional HILL Characteristics Form), RMS inquiry strategy, scoping-call support, and comment-cycle coordination through agreement execution — all under the responsible charge of a licensed Professional Engineer.

Q1: What exactly is “withdrawal capacity,” and how is it different from my interconnection capacity or transformer rating?
Withdrawal capacity is the maximum power your facility can draw from the transmission system in a given hour without causing a criteria violation — thermal, voltage, or stability — anywhere on the monitored network under the applicable contingency set. A transformer rating is a piece of equipment; contractual interconnection capacity is a legal number; withdrawal capacity is the physics number, and it binds. It varies hourly because facility ratings change with season, the surrounding system’s loading changes with demand and dispatch, and the contingency that binds on a summer peak afternoon may be irrelevant on a mild spring night. An 8760 study makes that variation explicit instead of hiding it behind one conservative number.
Q2: Why 8,760 hours? Wouldn’t summer-peak and winter-peak studies suffice?
Peak studies answer the RTO’s question — is the system reliable at its stress points? They cannot answer the developer’s questions: how much energy can the site actually serve across a year, how large must the battery be, and what does curtailment exposure cost? Those are distribution questions. The deficit that sizes your battery’s energy rating may occur nowhere near system peak — a shoulder-season evening with a line out for maintenance is a classic culprit. Only an hourly model exposes deficit duration, frequency, and clustering: the parameters that decide whether a 4-hour battery suffices or a 10-hour system is required, and whether recharge windows exist between events.
Q3: How is the 8760 series actually built — do you run 8,760 power flow studies?
Not naively. We define a representative-state matrix — season × system load level × outage condition × dispatch pattern, typically 20–40 states — solve each state’s maximum withdrawal with an automated bisection search in the planning model across the full contingency set, then classify each of the year’s 8,760 hours into a state using multi-year historical hourly load, seasonal ratings calendars, outage seasonality, and weather. Every hourly value is traceable to its state and binding constraint, and the classifier is validated statistically against the historical record. Full discrete-hour AC contingency simulation is available as extended scope, but for siting, application, and BESS-sizing decisions the representative-state method delivers the required fidelity at a fraction of the cost.
Q4: What is an injection study, and when do I need one?
An injection study is the generation-side mirror of the withdrawal analysis: it establishes how much power a resource can inject at its POI, under what service type, with what system impacts — power flow and deliverability at proposed output, short circuit contribution, transient stability, and system-strength screening for inverter-based resources. You need one whenever a resource will export; you need its inverse — the zero-injection demonstration — whenever a resource is designed not to export and that property carries regulatory or financial consequences, as it does in SPP’s HILLGA security calculation. In co-located projects the injection and withdrawal analyses share models, assumptions, and consequences, and are best performed as one coupled study.
Q5: What is Maximum Injection Capability, and why does it matter so much?
MIC is the maximum real power a generating facility may inject at its Point of Interconnection. In SPP’s HILLGA framework it drives three things: the sizing ceiling relative to the supported load, the LLRIS operating envelope, and the financial security obligation, which is computed per MW of MIC. For a non-exporting behind-the-meter configuration, MIC is the difference between a substantial security obligation and none — which is why the zero must be engineered and demonstrated, not merely declared.
Q6: Is the HILLGA security the same thing as the study deposit?
No — and conflating them is a common budgeting error. The study deposit funds the RTO’s study work and is payable to enter the process. The security is a separate financial-assurance obligation computed from injection capability. A zero-injection project may have a strong case that security computes to zero; it should still budget the deposit.
Q7: Can the security really be $0 for a zero-injection project?
The formula computes security per MW of MIC, so a genuine MIC of 0 MW yields $0 by the formula’s own terms. Two qualifications govern whether that arithmetic holds. First, jurisdiction: if the resource interconnects outside SPP’s functional control, BP 7250 §6.3 applies rather than Attachment BB, and the Attachment BB security arguably never attaches. Second, enforceability: if processed under Attachment BB, SPP can fairly ask what makes the zero physical rather than intentional — answered by a protection-backed non-export scheme (reverse-power/directional relaying with defined trip logic), failure-mode analysis, and EMT demonstration. Present it that way, request SPP’s written concurrence, and do not let the pro forma assume zero until the concurrence is in hand.
Q8: How do I know whether my resource is in the Attachment BB (HILLGA) lane or the BP 7250 non-jurisdictional lane?
The test is whose facilities the resource interconnects to. Attachment BB addresses generation interconnecting to the SPP transmission system to serve a HILL. BP 7250 §6.3 addresses generation interconnecting to facilities not under SPP functional control — behind the customer’s meter, on distribution, or on non-OATT transmission-owner facilities. Applications, studies, security, and agreements all differ between lanes, and the determination turns on facts — point of interconnection, ownership, functional control — that should be established before any application is drafted. It is the first task in every co-located engagement we run.
Q9: If my resource is non-jurisdictional, does SPP just ignore it?
No. Non-jurisdictional does not mean invisible. The transmission owner notifies SPP of units of 5 MW or more; an Affected System Study Agreement with SPP may be required; the resource must be specified — including whether a BESS will register as a Market Storage Unit; SPP performs stability analysis under BP 7250 §8 within a 90-day window at the transmission owner’s request; and the resource still appears explicitly in the planning models per the MDAG manual.
Q10: Are the HILL, HILLGA, and related studies sequential or parallel?
One hard gate, then parallel. The executed HILL-Load Connection Study agreement must precede the HILLGA request — the load process leads. Past that gate, the HILLGA SIS, the transmission owner’s Facilities Analysis, and affected-system evaluation share one 90-day window, and BP 7250 stability runs its own clock. The governing constraint in practice is not the framework’s structure but submittal completeness: every clock starts only on complete, validated data, so model and data readiness is the real schedule driver.
Q11: Where does battery charging belong in the load application?
Inside the HILL’s requested MW and ten-year forecast, explicitly, from the first draft. Charging is real withdrawal the delivery point must support, and SPP’s modeling practice treats storage explicitly rather than as a load reduction. Carried openly, the storage-as-load evaluation happens within the HDPS on your assumptions; buried, it resurfaces as a deficiency notice, a forecast inconsistency, or an undersized delivery point discovered at the worst possible time.
Q12: How does a zero-injection planned resource become a Designated Resource under Attachment AX?
This is the framework’s sharpest open seam, and our answer is an interpretation, clearly labeled: because the resource requests zero firm transmission service, there is no deliverability for the Aggregate Transmission Service Study to evaluate, and the conversion at commercial operation should be administratively simple — carried by the designation filing and registration data. If the resource remains undesignated, the consequence falls on the load’s supply-adequacy accounting: cover with other Designated Resources or remain on provisional service with its curtailment exposure. Any move to full network-resource status with injection rights would create a network interface and exit the non-wires construct entirely. Obtain SPP’s written position on the conversion mechanics before an AX filing strategy hardens.
Q13: How will SPP model my non-exporting BTM battery in the studies?
Explicitly — never netted. Per the MDAG manual, expect an explicit resource at the facility bus in the power flow (delivered as an IDEV), explicit dynamics (DYR records using the standard storage model set with the plant controller in load-following, zero-export mode), and study cases covering both charging and discharging states. The conservative planning default is typically the resource offline or charging — the state that stresses the delivery point hardest — which is why pre-agreeing dispatch assumptions at the scoping call is how you ensure the study evaluates the facility you designed.
Q14: Why do you size batteries in NREL’s SAM instead of a spreadsheet or proprietary tool?
Fidelity, auditability, and automation. SAM’s lithium-ion model captures round-trip efficiency, voltage behavior, temperature, and both calendar and cycle degradation — so the battery that covers year-1 deficits is verified against year-10 capacity, and clustered events are tested against real state-of-charge trajectories rather than energy arithmetic. SAM is free, open-source, and DOE/NREL-maintained, so a lender’s independent engineer can rerun our files — not true of black boxes. And the PySAM interface lets us sweep hundreds of power/energy candidates programmatically and publish the full feasibility frontier rather than a single point. SAM does not do power flow — which is why the transmission layer stays in the planning model and hands SAM the hourly grid limit as a constraint.
Q15: Doesn’t charging the battery consume the same grid headroom the load needs?
Yes — and this is where naive sizing fails. A battery that covers Monday’s deficit is useless Tuesday if there was no headroom to recharge Monday night. In our workflow the 8760 withdrawal series is applied inside SAM as the hourly limit on total facility draw — load plus charging — so the simulation only recharges when and to the extent surplus headroom (or on-site PV) exists, and any sizing candidate that cannot maintain state of charge through clustered deficit sequences shows up as unmet load and is rejected. Recharge feasibility is enforced by construction, not checked as an afterthought.
Q16: Our load is flexible — we can curtail workloads. Does that change the analysis?
It upgrades it from sizing to optimization. Every MW-hour of curtailable load reduces required battery energy one-for-one during deficit hours, at the cost of lost output. With the hourly deficit series in hand, that trade is computable: how many hours per year flexibility would be called, at what depth, and how storage capex compares against curtailment opportunity cost across sizing candidates. In markets with explicit flexible-load frameworks, and in conditional-service constructs that trade speed for curtailment exposure, this analysis is precisely how a developer decides how much firmness to buy versus how much flexibility to sell.
Q17: What model deliverables should a complete co-located submittal include?
One mutually consistent set: IDEV files placing the load and resource in the power flow; DYR dynamics for the resource with the non-export control representation; CMLD and PERC1 dynamic load models for the facility (PERC1 being SPP’s preferred model under BP 7850), encoded to the HILL fault ride-through requirements; and a PSCAD EMT model — recommended at submission because SCRCCT screening failure triggers supplemental EMT studies outside the 90-day window, and because the EMT model is also where the non-export protection scheme is demonstrated as a physical property. Internal consistency across the set matters as much as each model’s quality: SPP’s verification practice compares them against each other.
Q18: How accurate is a Shadow Load Study — will the RTO get the same answer?
We build the SLS to be methodology-aligned and document that alignment element by element: the same class of planning models (obtained through the RTO’s data processes under executed confidentiality agreements), TPL-001-aligned contingency definitions — in SPP, the transmission owners’ own contingency files where available — and criteria drawn from the RTO’s planning documents. Perfect prediction is not the claim; the official study may use a newer model build or updated assumptions. The claim is that surprises shrink from existential to marginal: the shadow study’s binding constraints and order-of-magnitude upgrade exposure are what the official study confirms, and a developer who ran it negotiates details in the study report rather than discovering fundamentals.
Q19: How do I actually get data and written answers from SPP?
Through the Request Management System — SPP’s ticketing portal and the working front door to its staff. Route technical questions via the Engineering Planning quick pick; request model access with the individual-level confidentiality agreements CEII requires (one CD or NCD form per person, attached to the ticket). Know the landscape: Model on Demand is reserved for stakeholders in the annual model build, and the consultant’s path is the posted MDAG-series models and planning contingency data on the secure file share, which carry the same information. For frontier questions, submit a concise written technical inquiry — the concrete configuration, the specific questions, a request for SPP’s position in writing. Specific, properly-papered requests get processed; vague ones stall. Drafting inquiries that get clean answers is a craft worth borrowing.
Q20: Does this methodology travel beyond SPP?
The tariff names change; the physics does not. The same withdrawal-and-injection stack applies in ERCOT (whose large flexible load framework SPP expressly drew upon for its HILL ride-through requirements), in CAISO and the California utilities’ hosting-capacity and deliverability processes, in PJM and MISO amid their large-load and co-location reforms, and in the tighter Northeastern systems where headroom is scarcest. Our practice spans these markets with large-load and storage engagements from 50 MW to 1 GW, applying the same disciplines everywhere: the RTO’s own models where accessible, TPL-aligned contingencies, system-strength screening, NREL-toolchain storage design, and written-confirmation strategy with the RTO

In 1995, Sandip (Sonny) R. Patel earned his Electrical Engineering degree from the University of Illinois, specializing in Electrical Engineering . But degrees don’t build legacies—action does. For three decades, he’s been shaping the future of engineering, not just as a licensed Professional Engineer across multiple states (Florida, California, New York, West Virginia, and Minnesota), but as a doer. A builder. A leader. Not just an engineer. A Licensed Electrical Contractor in Florida with an Unlimited EC license. Not just an executive. The founder and CEO of KEENTEL LLC—where expertise meets execution. Three decades. Multiple states. Endless impact.

8760 withdrawal study showing hourly grid headroom, facility demand, deficit hours, and BESS sizing

Part 2 — Frequently Asked Questions: Large Load Interconnection

Injection & Withdrawal Studies for the Grid-Constrained Era: The Complete Guide to 8760 Headroom Modeling, Zero-Injection Design, and SPP’s HILL/HILLGA Frontier

Part 1: The Withdrawal Study Knowing Your Grid Headroom Before the RTO Does

Layer 1 The Shadow Load Study (SLS)

Layer 2 The 8760 model

Layer 3 BESS sizing in SAM

Part 2: The Injection Study The Other Half of the Envelope

Part 3: Where the Two Studies Couple The Co-Located Configuration

Part 4: The SPP Framework in Brief — HILL, HILLGA, and the 90-Day Machine﻿

Part 5: The Frontier Questions — Our Read, Clearly Labeled﻿

1. Does the per-MW security apply to a zero-injection project?

2. Are the HILL, HILLGA/affected-system, and storage-as-load studies sequential or parallel?

3. How does a zero-injection planned resource convert to a Designated Resource under Attachment AX?

4. How does SPP model a non-exporting BTM resource?

Part 6: Getting Authoritative Answers SPP’s RMS, Used Well

Part 7: What Keentel Delivers

Withdrawal side

Injection side

The model set, as one consistent package

Through the process

Technical FAQ

Q1: What exactly is “withdrawal capacity,” and how is it different from my interconnection capacity or transformer rating?

Q2: Why 8,760 hours? Wouldn’t summer-peak and winter-peak studies suffice?

Q3: How is the 8760 series actually built — do you run 8,760 power flow studies?

Q4: What is an injection study, and when do I need one?

Q5: What is Maximum Injection Capability, and why does it matter so much?

Q6: Is the HILLGA security the same thing as the study deposit?

Q7: Can the security really be $0 for a zero-injection project?

Q8: How do I know whether my resource is in the Attachment BB (HILLGA) lane or the BP 7250 non-jurisdictional lane?

Q9: If my resource is non-jurisdictional, does SPP just ignore it?

Q10: Are the HILL, HILLGA, and related studies sequential or parallel?

Q11: Where does battery charging belong in the load application?

Q12: How does a zero-injection planned resource become a Designated Resource under Attachment AX?

Q13: How will SPP model my non-exporting BTM battery in the studies?

Q14: Why do you size batteries in NREL’s SAM instead of a spreadsheet or proprietary tool?

Q15: Doesn’t charging the battery consume the same grid headroom the load needs?

Q16: Our load is flexible — we can curtail workloads. Does that change the analysis?

Q17: What model deliverables should a complete co-located submittal include?

Q18: How accurate is a Shadow Load Study — will the RTO get the same answer?

Q19: How do I actually get data and written answers from SPP?

Q20: Does this methodology travel beyond SPP?

Work With Keentel Engineering﻿

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Sonny Patel P.E. EC

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Part 4: The SPP Framework in Brief — HILL, HILLGA, and the 90-Day Machine

Part 5: The Frontier Questions — Our Read, Clearly Labeled

Work With Keentel Engineering