Frequently Asked Questions

1. What is the ASE DER Telemetry and Flexible Interconnection Gateway?

It is a ruggedized gateway and data hub platform that connects residential, commercial, and utility-scale Distributed Energy Resources (DERs) directly to utility Distributed Energy Resource Management Systems (DERMS), ADMS, and SCADA platforms. It ensures compliance with various interconnection rules and grid codes.

2. Which utilities and grid programs officially approve ASE as a DER Gateway and Aggregator provider?

ASE is an officially approved aggregator and DER gateway provider for major utilities and regulatory programs, including PG&E (Rule 21 Customer-Owned Telemetry Program), SCE (Rule 21 Customer-Owned Telemetry), and SAPN (South Australia Power Networks for CSIP Australia requirements).

3. What is the key difference between deploying a DER Telemetry Gateway vs. a DER Aggregator?

A DER Telemetry Gateway is installed directly on-site when interconnection rules mandate a direct, physical telemetry link between the site and the utility’s SCADA/DERMS server. A DER Aggregator aggregates data across multiple sites or fleets into a central cloud/edge platform before communicating with the utility, reducing utility cybersecurity risk and lowering per-site connection costs.

4. What protocols are supported for utility and cloud communication?

The platform supports standard grid and cloud protocols, including IEEE 2030.5 (CSIP & CSIP-Aus), DNP3 (IEEE 1815 with Secure Authentication), IEC 60870-5-104, OpenADR, OCPP, ICCP, REST APIs, and Kafka stream integration.

5. How does the gateway maintain grid safety during communication or power loss?

For flexible interconnections, the integrated site controller automatically enforces predefined safe planning limits or default fallback states in the event of a communication drop or site power failure.

6. What is EV Submetering and how does it work?

EV submetering measures the electrical usage specific to electric vehicle charging using a submeter. It distinguishes EV charging consumption from non-EV power usage at your facility. The submeter—either integrated into the charger or installed as a standalone unit—records charging data for billing purposes, enabling utilities to bill EV charging on a dedicated, lower-cost rate tariff.

7. What role does ASE play as an approved MDMA for PG&E?

As an approved Meter Data Management Agency (MDMA) for PG&E, ASE assists commercial and fleet customers by providing monitoring hardware, managing the PG&E submetering application process, setting up billing integrations, and delivering ongoing operational and billing support.

8. Who is eligible for ASE’s EV Submetering MDMA services?

ASE offers EV Submetering MDMA services exclusively to Commercial and Fleet customers in Northern California served by PG&E. ASE does not currently offer MDMA services to residential or multi-family properties.

9. What components make up the EV Submetering package?

The package includes a Metering Edge Gateway Panel paired with approved meters (such as Transdata MAK V, eGauge, or EKM meters), an MDMA software subscription powered by the DER Data Hub, and long-term maintenance subscriptions (available in 5, 10, or 20-year terms).

10. What is the ASE Data Acquisition System (DAS) for DER Fleets?

The ASE DAS is an integrated hardware and software SaaS solution designed to provide real-time monitoring, visualization, and analytics for DER assets—such as solar PV, energy storage systems (BESS), and EV chargers—helping fleet operators optimize asset performance and maximize return on investment.

11. What monitoring features are available in the DAS SaaS platform?

The portal features portfolio dashboards, day-wise generation heatmaps, real-time grid connectivity tracking, weather monitoring, performance benchmarking, gateway health tracking, and automated email alerts.

12. Can the DAS platform export data to third-party enterprise cloud platforms?

Yes. Via the Kalki.io Data Hub middleware, the system offers pre-built connectors to stream operational data directly into AWS (AWS IoT Core, Kinesis, S3, SiteWise) and Microsoft Azure (Azure IoT Hub, Event Hub, Service Bus).

13. What is the DER Aggregator Cloud for Utility Interconnection?

The DER Aggregator Cloud is a centralized SaaS software platform that aggregates real-time data from multiple renewable energy plants and DER sites, providing a single integrated interface to communicate with utility DERMS, ADMS, and SCADA systems.

14. What asset types can be managed using the DER Fleet Aggregator?

The aggregator platform manages a wide variety of Distributed Energy Resources, including solar PV farms, wind turbines, Battery Energy Storage Systems (BESS), and electric vehicle (EV) charging infrastructure.

15. How does the DER Fleet Aggregator integrate with wholesale and retail energy markets?

The aggregator middleware interfaces directly with ISO systems, energy market applications, and Virtual Power Plants (VPPs) using REST APIs, Kafka messaging queues, DNP3, ICCP, or automated CSV data exports.

16. What deployment options are available for the DER Aggregator Middleware?

ASE offers flexible deployment options, including a cloud-based Software-as-a-Service (SaaS) subscription model and on-premises software licensing for direct deployment within enterprise or OEM cloud environments.

17. How does the Intel partnership enhance ASE’s Aggregator and Gateway solutions?

Through a technical collaboration with Intel, ASE deploys its DER Gateways on Intel Atom® Processors at the edge and powers high-capacity DER Aggregators using Intel® Xeon® Processors, delivering real-time processing and edge analytics capabilities.

18. What cybersecurity features protect the DER Gateways and Aggregator platform?

The solution includes hardware TPM 2.0 key storage, secure boot, hardened Linux operating systems, application sandboxing, built-in firewalls, SSL/TLS 1.2 encryption, and zero-trust remote access controls.

19. How are software updates and patch integrity verified?

All software releases, system patches, and firmware updates are signed using a manufacturer-specific PKI trust chain (TC1), preventing unauthorized code execution and ensuring system integrity.

20. How do ASE solutions support IEEE 1547.1 compliance at the DER local interface?

ASE edge gateways support all three communication interfaces specified in IEEE 1547-2018 (SunSpec Modbus, DNP3, and IEEE 2030.5). Their CSIP-certified IEEE 2030.5 client capabilities allow utilities to monitor and control on-site smart inverters and Energy Management Systems (EMS) seamlessly.

1. What is the ASE DER Telemetry and Flexible Interconnection Gateway?

It is a ruggedized gateway and secure edge hardware platform that connects residential, commercial, and utility-scale Distributed Energy Resources (DERs) directly to utility Distributed Energy Resource Management Systems (DERMS), ADMS, and SCADA platforms directly or through kalki.io DER Data Hub or 3rd party DER Aggregators. It ensures compliance with various interconnection rules and grid codes.

2. Which utilities and programs officially approve ASE as a DER Gateway provider?

ASE is an officially approved aggregator and DER gateway provider for major utilities, including:

• PG&E (Pacific Gas and Electric) Rule 21 Customer-Owned Telemetry Program
• SCE (Southern California Edison) Rule 21 Customer-Owned Telemetry
• SAPN (South Australia Power Networks) for CSIP Australia requirements

3. What communication protocols are supported for utility and cloud connectivity?

The gateway supports a wide range of industry-standard protocols, including:

• Utility & Interconnection Protocols: IEEE 2030.5 (CSIP & CSIP-Aus profiles), DNP3 (including Secure Authentication), IEC 60870-5-104, OCPP, and OpenADR.
• Field/On-Site Protocols: SunSpec Modbus (100 and 700 series), IEC 61850, OPC UA, MQTT, DLMS, ANSI, and SNMP.
• Cloud Connectivity: Kalki.io Data Hub, AWS, Azure, and Google Cloud integrations via REST/API, Web Services, MQ, or Kafka.

4. What is the difference between deploying a DER Telemetry Gateway vs. a DER Aggregator?

• DER Telemetry Gateway: Deployed directly at the DER site when the interconnection rule requires a direct connection between the site and the utility’s DERMS/SCADA server over protocols like DNP3, IEC 104, OCPP or IEEE 2030.5.
• DER Aggregator: Deployed when the interconnection permits aggregated telemetry or flexible interconnection. It collects data from multiple DER fleets and aggregates it before communicating with the utility, reducing utility cybersecurity risks and lowering costs. DER Aggregators are either deployed on Cloud Servers as a Public Cloud Offering or on Utility Data Centers or Utility Private Cloud to server a specific Utility DERMS integration requirement.

5. What cybersecurity features are built into the DER gateways?

The gateways are secured from the ground up and include:

• Hardware-based security like TPM 2.0 for secure boot and key storage (on specific product variants) and hardened Linux operating systems.
• Secure communication via SSL/TLS 1.2 for IEEE 2030.5 and IEC 62351 standards for TCP and DNP3 secure authentication.
• Manufacturer-specific PKI trust chains for signing software updates and patches, built-in firewalls, access controls, and zero-trust remote device access.

6. How does the gateway handle communication failures or power outages at a site?

For flexible interconnections, the integrated site controller ensures that the site automatically shifts to predefined safe planning limits or fallback states in the event of a power loss or communication failure. During communication failure the DER Gateway shall based on Utility interconnection requirements continue to operate on the saved schedules from the Utility ot fall back to planning limits.

7. What hardware and environmental features are included with the gateway?

Standard hardware features typically include:

• NEMA 4 enclosures with wall-mounting options.
• Universal power supplies (85–264 VAC) with optional high-voltage ranges (180–550 VAC).
• Integrated 4G/LTE cellular subscriptions supporting major carriers (AT&T, Verizon, T-Mobile).
• Intel / ARM processor based advanced real-time processing and edge computing.

8. Frequently Asked Questions: PG&E Rule 21 Customer-Owned Telemetry (COT) Checklist & Process

a. What is the PG&E Rule 21 Customer-Owned Telemetry (COT) process?

The COT process enables Distributed Energy Resource (DER) project owners—such as solar PV, energy storage systems (BESS), and microgrids—to deploy utility-approved gateway hardware or aggregator platforms (like ASE/Kalkitech) to stream real-time operational data directly to PG&E’s SCADA/DERMS systems. This satisfies mandatory grid visibility requirements while avoiding expensive, utility-installed traditional SCADA gear.

b. What is the complete checklist for obtaining Permission to Operate (PTO) via COT?

Achieving PTO involves a five-stage checklist across engineering, hardware, and field operations:

Phase 1: Project Scope & Engineering Approval

• Confirm system capacity meets or exceeds the 1 MW COT threshold (Electric Rule 21 Section J.5).
• Select Customer-Owned Telemetry (COT) instead of utility-provided SCADA hardware.
• Select a CSIP-certified IEEE 2030.5 or DNP3 gateway (e.g., ASE/Kalkitech SYNC Gateways).
• Prepare Single-Line Diagrams (SLD) and Network Architecture Diagrams showing gateway placement.
• Submit complete interconnection designs via the PG&E Interconnection Portal for engineering review.

Phase 2: Security & Certificate Provisioning

• Procure SunSpec/Kyrio root-approved PKI digital client certificates.
• Inject private keys and certificates securely into the gateway’s Hardware Security Module (TPM 2.0).
• Establish a reliable cellular communication link (AT&T, Verizon, or T-Mobile) with static IP or VPN support.
• Assemble the telemetry panel, including the NEMA 4 enclosure, power supply, and surge protection.

Phase 3: Field Installation & Local Integration

• Mount the telemetry panel on-site and connect primary AC/DC auxiliary power.
• Establish RS-485 serial or Ethernet communication lines to smart inverters, plant controllers, and meters.
• Configure local polling over Modbus RTU/TCP, DNP3, or IEEE 2030.5.
• Verify local data polling against live physical meter displays and site controllers.

Phase 4: Telemetry Point Mapping & Internal Pre-Testing

• Map all mandatory real-time telemetry points:
  • Active Power (kW) & Reactive Power (kVAR)
  • Line Voltages (V), Line Currents (A), System Frequency (Hz), and Power Factor
  • Battery State of Charge (SOC %) and Charge/Discharge status
  • Main Breaker / Recloser position (Open/Closed/Tripped)
  • Gateway Heartbeat / Communication Health status
  • Remote Active Power Limit / Curtailment control functions
• Perform end-to-end telemetry pre-tests prior to engaging utility engineering.

Phase 5: Point-to-Point Testing & Final PTO Issuance

• Schedule and execute a point-to-point SCADA integration test with PG&E SCADA engineers.
• Verify that real-time telemetry updates and remote curtailment commands execute successfully.
• Complete the PG&E field witness inspection or submit required self-certification documentation.
• Receive official Permission to Operate (PTO) authorization letter from PG&E.

c. Which communication protocol is required for PG&E COT?

Under California Rule 21 and CPUC Resolution E-5038, the default standard for COT is IEEE 2030.5 using the Common Smart Inverter Profile (CSIP). In specific substation-level or legacy transmission interconnections, direct DNP3 (IEEE 1815) over secure networks may also be specified by PG&E.

d. What update frequency does PG&E require for telemetry data points?

Telemetry measurements (such as kW, kVAR, Voltage, and Breaker status) are polled continuously over cellular or dedicated IP connections, typically updating every 4 to 15 seconds depending on the communication media and PG&E SCADA polling profiles.

e. Why are PKI digital certificates required for Rule 21 gateways?

IEEE 2030.5 enforces mandatory TLS 1.2 transport security. Hardware gateways must be provisioned with approved Public Key Infrastructure (PKI) certificates (issued by approved CAs like SunSpec/Kyrio) to authenticate encrypted communication between the gateway and PG&E’s DERMS server.

f. What happens if telemetry communication fails between the site and PG&E?

The gateway’s site controller monitors the utility heartbeat signal. If communication drops beyond a specified timeout threshold, the gateway automatically commands the site to drop to a pre-agreed safe operating limit or default autonomous mode until the connection is re-established.

g. How long does the PG&E Point-to-Point SCADA testing phase take?

Once all site hardware is installed, configured, and pre-tested, scheduling and executing the point-to-point test with PG&E SCADA engineers typically takes between 1 to 3 weeks, depending on utility team scheduling availability. ASE does a pre-test before the SCADA test to ensure site readiness and provide the SCADA Form completed for PG&E DERMS /SCADA on-boarding and after which SCADA testing is scheduled.

1. What is the Substation Alarm Manager (SAM)?

The Substation Alarm Manager (SAM) is an industrial, multi-channel substation annunciator and alarm management system designed to monitor, log, and report critical alarms and digital input state changes across power substations, industrial plants, and utility facilities.

2. What primary purpose does SAM serve in substation automation?

SAM provides real-time local visual/audible alarm annunciation and aggregates field alarm points into a centralized data concentrator. It bridges field contact inputs and modern SCADA/HMI platforms over standard utility communication protocols.

3. What are the key hardware configuration options available for SAM?

SAM is available in modular chassis designs that support varying digital input point capacities (ranging from 8 to 64 points or more). It comes with custom-engraved LED window displays, high-visibility visual indicators, and configurable internal pushbuttons for local alarm acknowledge, reset, and test operations.

4. What protocols are supported for SCADA and master station communication?

SAM supports major utility SCADA protocols, including DNP3 (serial and TCP/IP), Modbus RTU/TCP, and IEC 60870-5-104. This enables simultaneous reporting to local RTUs, regional SCADA masters, and enterprise monitoring systems.

5. Which ISA-18.1 annunciator sequence standards are supported?

SAM supports standard ISA-18.1 alarm sequences—such as Sequence A (Automatic Reset), Sequence M (Manual Reset), Sequence R (Ringback), and First-Out Sequences (F1A, F2M, F3A)—allowing operators to immediately identify the root cause of multi-point tripping events.

6. What is “First-Out” alarm indication and how does it work?

First-Out sequencing detects and captures the absolute first input point that tripped in a fast series of cascading faults. SAM highlights the primary fault with a unique flashing pattern or color while displaying subsequent trip events in standard alarm states.

7. How does SAM handle input debouncing and chatter filtering?

Each channel includes configurable software-defined debounce timers and chatter suppression filters. This prevents noisy field contacts, relay contact bounce, or faulty field switches from overwhelming the SCADA system with repetitive false alarms.

8. Can individual alarm points be configured with custom time delays?

Yes. SAM allows independent pick-up and drop-out time delay configurations for every input channel, ensuring that brief voltage transients or normal breaker operation delays do not trigger spurious alarms.

9. What types of field inputs does SAM accept?

SAM accepts wet contacts (voltage-driven) or dry contacts (optically isolated) from field relays, circuit breakers, transformers, and auxiliary switches. It supports a wide range of field input voltages (e.g., 24 VDC, 48 VDC, 125 VDC, or 250 VDC/VAC).

10. What relay output options are available for external signaling?

SAM provides auxiliary relay contacts for common alarm outputs, horn/audible buzzer controls, flashers, and system watchdog/fail-safe relays to trigger local physical sirens or external control circuits.

11. What power supply options are supported by SAM hardware?

SAM features universal power supply modules supporting wide AC/DC input ranges (typically 88–264 VAC / 90–300 VDC or 24/48 VDC options) with built-in surge protection to withstand harsh substation environments.

12. Is dual power supply redundancy supported?

Yes. Specific SAM chassis configurations support dual, hot-swappable redundant power supplies to ensure uninterrupted operation in critical transmission and distribution substations.

13. What precision time synchronization methods does SAM support?

SAM supports IRIG-B (unmodulated/TTL), NTP (Network Time Protocol), and DNP3 time synchronization to maintain millisecond-accurate time stamping for Sequence of Events (SOE) recording.

14. What is the resolution of SAM’s Sequence of Events (SOE) recorder?

SAM records field state transitions with a 1-millisecond time resolution, ensuring precise chronological logging of system disturbances and protective relay trips.

15. How much non-volatile event storage is available on SAM?

SAM contains high-capacity non-volatile flash memory capable of storing thousands of time-stamped events locally. Event logs remain intact even during a total station blackout or loss of primary power.

16. How do operators download or review historical event logs?

Operators can download time-stamped SOE event logs via the front-panel USB/serial maintenance port, over the Ethernet web management portal, or automatically poll logs via DNP3/Modbus SCADA file transfer commands.

17. How is SAM configured and maintained?

System configuration is performed using ASE’s intuitive Windows-based configuration software or via a web-based browser interface. Users can define input legends, assign ISA sequences, set baud rates, and map SCADA registers offline or live via Ethernet.

18. Does SAM support remote web-based monitoring?

Yes. SAM features an embedded web server that allows authorized operators to view live alarm window states, acknowledge active alarms remotely, review real-time event logs, and inspect system diagnostics over a web browser.

19. What cybersecurity features are incorporated into SAM?

SAM includes multi-level user authentication (Role-Based Access Control), HTTPS secure web sessions, SSH configuration channels, and IP firewall white-listing to prevent unauthorized access to substation control networks.

20. How does SAM integrate with ASE’s suite of protocol software tools?

SAM integrates seamlessly with the ASE2000 Test Set and SPT-PC SCADA Data Gateway, allowing field engineers to verify protocol mappings, test DNP3/Modbus telemetry lines, and simulate substation master-station communications during commissioning.

1. What is EV Submetering and how does it work?

EV submetering measures the electrical usage specific to electric vehicle charging using a submeter. It distinguishes your EV charging consumption from non-EV power usage at your facility. The submeter—either integrated into the EV charging station or installed as a standalone unit—records charging data for billing purposes, allowing utility companies to bill EV charging on a separate, optimized rate tariff.

2. What role does ASE play as an MDMA?

As an approved Meter Data Management Agency (MDMA) for PG&E, ASE assists commercial and fleet customers in setting up EV submetering systems. ASE provides monitoring hardware, manages the PG&E submetering application process, sets up billing integration, and delivers ongoing operational and billing support in coordination with PG&E.

3. Who is eligible for ASE’s EV Submetering MDMA services?

ASE currently offers EV Submetering MDMA services exclusively to Commercial and Fleet customers in Northern California served by PG&E. ASE does not currently offer MDMA services to residential or multi-family customers.

4. What hardware and software components are included in the solution?

The ASE EV Submetering solution includes:

• Hardware: Metering Edge Gateway Panel paired with approved submeters (such as Transdata MAK V, eGauge, or EKM meters).
• Software: An MDMA software subscription powered by ASE’s DER Data Hub Platform.
• Submetering Support: Site setup, PG&E onboarding, and long-term maintenance subscriptions (5, 10, or 20 years).

5. What protocols and cloud platforms are supported by the DER Data Hub Platform?

The underlying DER Data Hub Platform supports standard utility protocols and cloud integrations, including:

• Interconnection & Smart Charging Protocols: IEEE 2030.5, DNP3, SunSpec Modbus, OpenADR, and OCPP.
• Cloud Platforms & Data Pipeline Options: AWS, Azure, Google Cloud, REST API, and Kafka.

6. What ongoing support and maintenance services does ASE provide?

ASE provides end-to-end management, which includes:

• Onboarding and configuration for PG&E’s submetering system.
• Billing support and ongoing coordination with PG&E.
• Security updates, including protocol, firmware, OS, and vulnerability patches.
• Access to a central management portal for continuous monitoring, maintenance, and system upgrades.