Start: Your production picture

• Tell me briefly about the production timeline and monthly inlet volumes you are forecasting for the next 18 months.
• How many producing wells and tie-in points will feed the proposed gathering over the next 6 and 18 months? Options: 1-5, 6-20, 21-50, 51+
• Who on your team owns the production forecast and will approve revisions during the ramp? Options: Production engineer, Reservoir engineer, VP of production, Operations manager, Other
• Please describe the current inlet gas composition at wellheads, including typical ranges you see for ethane, propane, CO2, and H2S.
• Name the single throughput or forecast miss that, if realized, would make you pause or cancel this project immediately.

Where forecasts hurt the business

• If realized production falls 25% below plan next quarter, which revenue lines or contracts would break first? Options: NGL marketing revenue, Residue gas delivered value, Processing fee shortfalls, Pipeline take-or-pay penalties, Royalty impacts, Other
• Walk me through the last time you had a meaningful forecast miss, what operational steps you took, and how you communicated with processors.
• What single contractual term has actually protected your economics during a production shock in the past? Options: Firm capacity reservation, Uptime SLA with credits, Keep-whole provision, Make-up capacity, Operational flexibility clause, Other
• When forecasts change, what is your typical notice window to the gathering operator and to processors, in days? Options: <7 days, 7-30 days, 31-90 days, >90 days
• How confident are you in the next 12 months that your produced C2+ fraction will stay within current ranges? Options: Very confident, Moderately confident, Low confidence, Unknown

Composition and connectivity, the physical constraints

• Given your inlet composition variability, which constituent most reduces plant recoveries or forces derates? Options: High CO2, High H2S, Heavy liquids loading, High water content, Unexpected inerts or nitrogen
• Provide the typical numeric ranges you observe for ethane, propane, butane and total C2+ either in mole percent or mole fraction.
• In a typical month, how many hours of compressor or gathering constraint do you expect that could limit inlet capacity? Options: None expected, <24 hours, 24-72 hours, >72 hours
• Who on your side is responsible for arranging physical interconnects, custody transfer points, and metering ownership? Options: Midstream operations, Field operations, Third-party gathering owner, Commercial team, Other
• If gas quality excursions exceed plant inlet acceptance, what is your preferred immediate action: curtail, blend, reroute, or hold? Options: Curtail production, Blend with leaner streams, Route to alternate plant, Hold in field storage, Other

NGL economics, who wins and who loses

• What economic threshold for NGL netback or residue gas price would cause you to prefer a keep-whole or fee contract instead of percent of proceeds? Options: Keep-whole preferred, Percent of proceeds preferred, Fee preferred, Hybrid by price band, Depends on term length
• Tell me about the last time gas marketing recommended a different processing contract type and why they made that call.
• Which revenue metric do you watch most closely to evaluate processors, NGL netbacks per bbl, percent recovery delta, or delivered residue gas value? Options: NGL netbacks per bbl, Percent recovery delta, Residue gas delivered value, Fee per MMBtu, Other
• Quantify the sensitivity of your monthly cash flow to a 1 bbl change in total NGL recovery, using dollars per day if you can.
• Do you have minimum acceptable NGL yields or heat content requirements you would require in a commercial agreement today? Options: Yes, documented minimums, No minimums today, Under negotiation

Where operations break and how you respond

• Name the single operational failure that would force you to shut in production immediately and explain why that single point is fatal.
• When an unplanned outage happens, what is the typical top-line revenue impact per day for the asset group tied to this processing decision? Options: <$10,000, $10,000-$50,000, $50,000-$200,000, >$200,000
• Walk me through your escalation path from a field alert to commercial notification, including typical timelines and roles involved.
• Do you maintain formal runbooks and SOPs that an external processor could access during commissioning and abnormal operations? Options: Yes, fully documented and accessible, Partial runbooks available, Not documented, Under development
• State the maximum curtailment percentage you can tolerate for a continuous 30 day period before permanent production decisions are considered. Options: 0%, 1-5%, 6-15%, >15%

The alternatives on your table

• List the external processors, incumbents, or third-party options you are actively evaluating and why each remains under consideration.
• Describe any internal processing proposals your team has advanced and who is championing the internal approach.
• Under what specific conditions would you decide to stay with the incumbent instead of switching to a new processor?
• Rate how much vendor switching risk matters to your board or executive committee, from low to critical. Options: Low, Moderate, High, Critical
• Identify any internal decision makers who must be convinced to move off an internal processing plan, and summarize their main objection.

Execution readiness, the things that gate start

• Identify the single interconnect, permit, or right of way that is missing today and would block execution if not resolved before commissioning.
• List the external systems and endpoints the processor must integrate with, for example SCADA, custody transfer, and commercial settlement feeds, and name who owns each.
• Are APIs or SCADA endpoints available today for remote setpoint changes and automated alarms? Options: Yes, full programmatic access, Read only telemetry, Limited access on request, No APIs or remote access
• Confirm whether you have a single permit manager assigned to approvals and provide their role and contact function.
• Estimate the remaining lead time in weeks to secure final permits, interconnect construction, and third-party metering approvals. Options: <4 weeks, 4-8 weeks, 9-16 weeks, >16 weeks
• Specify the headcount and roles your team will dedicate during commissioning and the first 90 days of operations.

Yes or no, what will make this move fast

• Assuming a short pilot meets agreed recovery and uptime targets, what approvals or conditions would still prevent you from signing a full agreement within one week?
• State the internal timeline your group needs from pilot completion to a go no go decision. Options: Immediate (same week), 1-2 weeks, 2-4 weeks, >4 weeks
• Outline the exact pilot metrics and numeric thresholds for recovery, uptime, and composition stability that would justify a full commitment.
• Share the contract review path, including legal, commercial, and executive signoffs and expected turnaround time.
• Pinpoint any single regulatory or commercial veto that would kill the deal even if technical targets are met.
• Confirm the top three stakeholders you want on the pilot steering committee and their decision authority. Options: Production engineering, Gas marketing, VP midstream, Operations, Legal/commercial, Other

• Solution Experience — Plant Options & NGL Economics

• Confirm your current feed-gas profile and constraints
• You confirm the feed-gas inputs and constraints used in the models are correct and complete.
• Provide the latest well-level feed-gas compositions and 12-month volume forecast in spreadsheet form.
• Quantify what the status quo is costing you
• You confirm the presented plant option and recovery estimates address your production ramp and NGL capture targets.
• Run detailed recovery and NGL economics models for the two selected plant options and deliver a comparative report with sensitivity to ethane and propane prices before the follow-up meeting.
• Show candidate plant options and expected recoveries using your data
• Prepare draft commercial term scenarios (fee, percent-of-proceeds, keep-whole) showing mid, low, and high commodity outcomes and the associated cashflow implications.
• You agree which commercial structure(s) to pursue to align incentives and which additional evidence is required before a decision.
• Identify any internal approval or stakeholder constraints that would affect timetable or contract structure decisions.
• Demonstrate commercial tradeoffs across term structures
• Validate the recommended plan against your priorities
• Agree next evidence and decision milestones

• Solution Experience — Plant Options & NGL Economics
• Solution Experience Deck — Plant Options & NGL Economics
• Solution Brief — Plant Options and NGL Economics

• meeting
• slides
• document

• Operate cryogenic NGL recovery unit
• Provide amine sweetening for CO2/H2S removal
• Dehydrate gas to pipeline specifications
• Fractionate and purify NGL product streams
• Provide NGL storage, loading, and logistics
• Deliver pipeline‑quality residue gas
• Process gas under fee‑based contract
• Process gas under percent‑of‑proceeds contract
• Process gas under keep‑whole contract
• Connect plant to producer gathering system
• Commission plant and support production ramp‑up
• Provide 24/7 plant operations, remote monitoring, and dispatch
• Manage capacity allocation and curtailment
• Perform custody transfer metering and quality certification

Operate cryogenic NGL recovery unit

• Provide the expected average and peak inlet gas flow in million standard cubic feet per day (MMscfd).
• Specify the typical C2 and C3 mole fractions and the C2+ (ethane plus heavier) volume percent in your feed gas.
• Indicate the minimum and maximum inlet pressure and temperature ranges the cryogenic unit must accept (psig and degrees Fahrenheit).
• Select which recovery targets you require from the cryogenic unit for planning purposes. Options: Ethane recovery target ≥95%, Ethane recovery target 90–95%, Ethane recovery target <90%, No minimum recovery target defined
• Identify any feed contaminants (liquid hydrocarbons, heavy ends, solids) or slugging risks that will affect exchanger sizing or separation design.

Provide amine sweetening for CO2/H2S removal

• State the maximum CO2 mole percent and H2S concentration (ppm) in the inlet gas the amine unit must treat.
• Specify required treated gas spec for CO2 and H2S for pipeline receipts or downstream cryogenic performance.
• Select preferred amine solvent or treatment goals if you have them. Options: MDEA or equivalent selective solvent, MEA/DEA style solvent, Physical solvent option, Open to operator recommendation
• Provide any emissions, flare minimization, or solvent regeneration constraints tied to your site permits.
• Identify the owner of amine injection, reclamation, and chemical supply logistics for ongoing operations. Options: You provide chemical supply, We provide chemical supply, Shared cost and logistics to be defined

Dehydrate gas to pipeline specifications

• Provide the pipeline water dew point requirement (for example degrees Fahrenheit at X psig) you must meet after dehydration.
• Specify whether molecular sieve or glycol dehydration is preferred and any inlet water loading (lb/MMscf) constraints. Options: Molecular sieve preferred, Glycol (TEG) preferred, Open to recommendation
• Indicate if dehydration must include water monitoring and auto-alarm integration with your SCADA or the platform integration endpoint. Options: Yes integrate alarms and telemetry, No integration required, Integration optional
• Estimate expected condensate or water hydrocarbon carryover that will require separator or treating capacity (bbl/day).
• Identify who will handle spent desiccant or glycol disposal and any site-specific hazardous waste requirements. Options: You handle disposal, We handle disposal, Third party contractor handles disposal

Fractionate and purify NGL product streams

• List the target product purity specifications you require for each NGL product (ethane, propane, isobutane, normal butane) with concentration thresholds.
• Provide preferred product split and custody packaging (transport via pipeline, truck loadout, rail car) for each fractionated stream. Options: Pipeline NGL header, Truck loadout, Rail loading, Storage only
• Select the desired minimum storage residence time or surge capacity for fractionation to handle batch swings (days or barrels). Options: Less than 1 day, 1–3 days, 3–7 days, More than 7 days
• State the acceptance criteria that will confirm final NGL product purity and composition for acceptance testing (include test method such as ASTM D86 or gas chromatograph cut definitions).

Provide NGL storage, loading, and logistics

• Specify required storage capacity for each product in barrels and preferred minimum and maximum fill levels.
• Indicate preferred loading methods and frequency for off‑take (truck, rail, pipeline shuttle) and any weight or routing limitations at your site. Options: Truck loadout, Rail loading, Pipeline shuttle, Combination
• Identify whether you or we will provide third party logistics coordination and buyer nomination windows for each product. Options: You manage logistics, We manage logistics, Shared coordination
• Provide any product custody or sampling requirements at loadout (composite sampler, manual sample frequency, chain of custody).

Deliver pipeline‑quality residue gas

• Provide the pipeline receipt quality specifications to meet (maximum hydrocarbon dew point, Wobbe index if required, maximum CO2 and H2S).
• Specify the delivery pressure and tie-in point pressure requirement for residue gas handoff to the pipeline network.
• Indicate if you require heating value or BTU tracking on a per-lift basis and how frequently (hourly, daily). Options: Hourly, Every 4 hours, Daily, On request
• Identify expected compressibility or BTU variability drivers (N2 injection, variable condensate yields) that affect pipeline quality control.
• Select who will own interconnect pressure control and pigging responsibilities at the pipeline delivery point. Options: You own pressure control, We own pressure control, Shared arrangement to be defined

Process gas under fee‑based contract

• Choose the fee structure you prefer for the fee‑based option if available (per MMscf, per gallon NGL recovered, tiered). Options: Flat $/MMscf, Variable $/gallon recovered, Tiered pricing by flow band, Custom proposal required
• Provide expected monthly throughput profile for fee calculations and any seasonal variation that affects fees.
• Indicate whether you need a minimum volume commitment and the preferred term length for the fee arrangement. Options: Standard minimum commitment acceptable, Phased ramp to minimum commitment, No minimum commitment requested
• Specify billing cadence and invoicing requirements (monthly in arrears, monthly in advance, consolidated monthly statement). Options: Monthly in arrears, Monthly in advance, Quarterly, Other
• Identify any third party audit, metering verification, or billing dispute process you require for fee settlements.

Process gas under percent‑of‑proceeds contract

• State the percent‑of‑proceeds sharing model you are considering or the economic split bands you expect.
• Provide your NGL marketing preferences for percent‑of‑proceeds: do you want commodity proceeds passed through, or pooled sales managed by the processor? Options: Proceeds passed through to you, Processor markets and pays percentage, Pool with periodic accounting
• Indicate required reporting cadence for realized NGL prices and allocated proceeds (daily, weekly, monthly). Options: Daily, Weekly, Monthly, Quarterly
• Specify any required price reference points or indexation rules for each NGL product (for example Mont Belvieu or regional index).
• Identify required audit rights or transparency measures on marketed volumes and price realizations under percent‑of‑proceeds.

Process gas under keep‑whole contract

• Confirm whether you prefer a keep‑whole structure with a gas quality make‑whole or a volumetric balance make‑whole and provide details. Options: Gas quality make‑whole, Volumetric balance make‑whole, Open to discussion
• Provide calculations or examples of expected make‑whole adjustments based on your feed gas composition and local NGL pricing assumptions.
• Indicate the frequency and mechanism you require for reconciling keep‑whole settlements (monthly statement, third party audit). Options: Monthly statement, Monthly with third party meter verification, Quarterly reconciliation
• Specify who will bear shrinkage, fuel, and flare volumes under the keep‑whole terms as part of the scope boundary. Options: We bear fuel/shrinkage, You bear fuel/shrinkage, Shared per contract
• Identify any minimum NGL pricing floors or collar mechanisms you require to protect against extreme price moves. Options: Price floor required, Price collar required, No floor/collar required

Connect plant to producer gathering system

• Describe the physical tie‑in point location and provide the single‑line diagram (SLD) or piping and instrumentation drawing (P&ID) for the proposed interconnect.
• Specify required inlet tie‑in hydraulic conditions including pressure, allowable drop, and pigging capabilities.
• Indicate who will supply right‑of‑way, metering skid, and final connection spool pieces for the gathering tie‑in. Options: You provide tie‑in materials, We provide tie‑in materials, Shared to be defined
• Select required safety and access protocols at the interconnect (lockout/tagout LOTO, confined space procedures, site orientation). Options: LOTO required, Confined space protocol required, Site orientation required, All of the above
• Provide any expected schedule constraints for tie‑in work windows including seasonal or third party restrictions.

Commission plant and support production ramp‑up

• Provide the desired commissioning milestones and target dates for pre-commissioning, cold commissioning, and hot commissioning.
• Specify the expected producer lift schedule (wells online by date and expected flows) that defines ramp coordination needs.
• Indicate required commissioning deliverables such as punch lists, test reports, and turnover packets for operations. Options: Punch list and test reports, Turnover packets and O&M manuals, All deliverables listed
• Identify who will provide tie‑in permits, hot work permits, and control system handover credentials during commissioning. Options: You provide permits and credentials, We provide permits and credentials, Shared responsibility
• Provide your acceptance criteria for successful production ramp‑up including target throughput and allowable curtailments during the ramp period.

Provide 24/7 plant operations, remote monitoring, and dispatch

• Select the level of staffed operations you require: full on‑site 24/7, remote monitoring with on‑call field crew, or hybrid staffing model. Options: On‑site 24/7 staff, Remote monitoring with on‑call crew, Hybrid staffing
• Specify required SCADA and telemetry endpoints for integration including tag lists, historian access, and alarm routing to the integration endpoint.
• Indicate whether you require operator training and certification packages as part of handover and ongoing operations. Options: Operator training included, Training optional, No training required
• Choose desired escalation paths and maximum response times for critical alarms and unplanned outages. Options: Immediate phone escalation, Email plus phone escalation, Automated pager with 30 minute response
• State the uptime performance threshold and related SLA metric you will accept for operational acceptance and ongoing payments.

Manage capacity allocation and curtailment

• Provide your preferred capacity reservation method: firm reservation with minimum, seasonal allocation, or best‑efforts allocation. Options: Firm reservation with minimum, Seasonal allocation, Best efforts allocation
• Specify curtailment priority rules you require (pro rata, highest fee priority, contract seniority) when inlet exceeds plant capability. Options: Pro rata, Highest fee priority, Contract seniority, Custom rule

• Gas Processing Master Agreement (GPA)
• Statement of Work (SOW)
• Service Level Agreement (SLA)
• Capacity Reservation Agreement
• Commercial Terms Exhibit (Fee Schedule & Allocation)
• NGL Marketing and Proceeds Allocation Agreement
• Measurement, Allocation & Custody Transfer Agreement
• Operational Handover & Commissioning Acceptance
• Change Order and Capacity Amendment Procedure
• Termination, Curtailment & Priority Rights Schedule
• Credit Support & Security Agreement
• Environmental & Permitting Compliance Addendum (conditional)

• Post-Go-Live Health Check
• First Performance Measurement
• Acceptance Gate Review
• Quarterly Operational Review

• Refresh contingency limits and cutover sequencing documentation to reflect recent learnings.
• Produce a curtailment root-cause log covering each event and proposed permanent mitigations.
• Prepare a settlement variance report showing volume and price differences for the prior reporting period.
• Restate acceptance criteria and numeric targets
• Produce a documented pass or fail for each acceptance criterion recorded in Solution Scope.
• Capture a formal acceptance decision with a named signatory for passed criteria or agree an enforceable remediation plan for failed criteria.
• Document next steps and any contract or billing triggers linked to the acceptance outcome.
• Publish the acceptance record with pass/fail outcomes and store it in the journey workspace.
• If remediation is required, open remediation tickets with deadlines and escalation contacts.
• Prepare the post-acceptance operational handover package if acceptance is achieved.
• Quarterly performance trends and variance analysis
• Confirm whether quarterly ethane recovery and unplanned downtime meet Solution Scope targets or require further action.
• Close or extend remediation items with clear deadlines and measurable success criteria.
• Agree the prioritized optimization actions for the next quarter and their expected metric impact.
• Update the optimization backlog and schedule field tests for recovery improvements.
• Reconcile any remaining NGL settlement discrepancies and issue adjustments as required.
• Re-confirm acceptance criteria and owners
• All critical deployment handover items verified or assigned remediation with target dates.
• SCADA telemetry and handover values confirmed as available and accurate for monitoring.
• Immediate blockers prioritized and remediation owners documented.
• Publish the updated startup parameter checklist and distribute to the operations team.
• Log and prioritize any open interconnect or permit defects and assign remediation target dates.
• Tune SCADA alarm thresholds and confirm telemetry feed stability before the first measurement meeting.
• Present first-period performance vs Solution Scope targets
• Establish whether inlet utilization and ethane recovery are trending toward the Solution Scope targets and quantify the gap.
• Identify the primary root causes for any shortfalls and commit to a set of corrective actions with dates.
• Document any settlement variances requiring accounting or marketing follow-up before acceptance.
• Run a laboratory verification audit of measured NGL recovery calculations to validate recovery rate inputs.
• Schedule compressor and turboexpander tuning and document expected change in recovery and throughput.
• Deployment and interconnect validation
• Incident and curtailment log review
• Root-cause analysis for metric gaps
• Present measured outcomes against each criterion
• Early operational signals and anomalies
• Incident and curtailment review
• Document pass or fail per criterion
• NGL settlements and marketing performance
• Initial NGL settlements and volume reconciliation
• Capture formal acceptance and named signatory
• Optimization actions status update
• Open issues and remediation plan
• Risks, compliance, and contingency limits review
• Agree remediation plan for any failed criteria
• Confirm next checkpoint and communications cadence
• Agree corrective actions and acceptance timeline