1. Working with Utilities Sean W. Carr, P.E., PMP®
Co-presenters
James Eckert
Russell Desalvo, P.E.

2. Disclaimer
The following presentation is only intended to provide a general overview of the interconnection processes and rules in the State of Illinois and ComEd service territory. If you are not located in ComEd’s service area, please contact your electric utility for the interconnection processes and rules applicable in your area.

3. Agenda
The objective of today’s presentation is to provide an overview of the interconnection process.
Regulatory rules governing interconnections
Types of interconnection applications
Customer responsibilities
Utility rules, regulations and responsibilities
Technical guidelines for interconnections

4. Why do we need rules for interconnection? To protect the utility grid
Background
Why do we need rules for interconnection?
To protect the utility grid
To protect other customers connected to the Area Electric Power System (EPS)
To provide uniform requirements for all applicants
To provide certainty in rules and regulations for customers seeking to interconnect generation.

5. Background
Why do we need rules and regulations governing interconnection of generation to the utility system?
Analogy:
The electric utility grid is like a super highway with many on and off ramps.

6. Background cont.
If we don’t have rules and regulations governing access to the on and off ramps of the super highway what happens?
There is uncontrolled chaos and others can be impacted by these events!

7. Background cont.
When the rules and regulations work everything moves along in a controlled and predictable manner.

8. Regulatory Background
Prior to 2008, generation interconnection requests were governed by individual utility requirements.
ComEd previously published the “Blue Book” which dictated interconnection requirements for the ComEd system.
In 2008, Illinois Administrative Code Title 83 Parts 446/467 were enacted which provide uniform regulatory requirements for distribution interconnection requests.
The “Blue Book” is still useful for providing details on technical requirements.

9. Reasons for Customer Generation
Our customers may choose to install their own generation for many different reasons. Some of the most common reasons include:
Backup generation
Cogeneration installations
Intentional exporters and/or Independent Power Producers (IPPs)

10. Type of Customer Generation
Backup generation: A customer may decide to install backup generation to mitigate the impact of interruptions of utility service to his or her business or home. Many of these installations are open transition on loss-of-source (think of a homeowner’s garage generator with a manual throwover), and have no impact on the distribution system. Others may be open transition on loss-of-source, and closed transition on return-to-grid.

11. Types of Customer Generation
Cogeneration installations: A customer may elect to install Distributed Generation facility equipment designed to continuously parallel with the utility grid. Examples include combined-cycle cogeneration (for example, where waste heat from the generation prime mover is used for industrial processes or plant heating, or where waste heat from industrial processes is used for power generation), peak shaving (the use of cogeneration to reduce both purchased power and to mitigate peak load charges), and many forms of “green” generation such as photovoltaic (PV) installations and small wind turbine installations. By their nature, these facilities operate as closed transition facilities. While these facilities may, at times, export net power, they are generally not considered to be “significant” net exporters, although larger installations may have that capability if “native” load is significantly less than the generator nameplate capacity.

12. Types of Customer Generation
Intentional exporters and/or Independent Power Producers (IPPs): Distributed generation facilities that intentionally export significant net power to the retail or wholesale markets. Examples include landfill gas generation facilities, medium-scale wind farms (generally less than 50 MW on the 34.5 kV system), and (future) large photovoltaic installations. These tend to be among the larger Distributed Generation facilities connected to the distribution system, are generally capable of islanding significant external load, and may be capable of providing significant fault current.

13. Types of Interconnection Applications
Distribution
Wholesale
ICC Title 83 Part 466/467
Interconnection is 34kV or lower
Size is typically <20MVA
May or not intentionally export power to the utility grid
PJM or Regional Transmission Operator (RTO)
Interconnection may be at distribution or transmission voltages
Size may range from kVA to hundreds of MVA
Typically sell power into wholesale market

14. Section 466.10 Scope ICC Title 83 Part 466
The Illinois Distributed Generation Interconnection Standard applies to generation facilities operated in parallel with an electric public utility distribution company in Illinois and meeting the following criteria:
a) The nameplate capacity of the distributed generation facility is equal to or less than 10 MVA; and
b)  The distributed generation facility is not subject to the interconnection requirements of either the Federal Energy Regulatory Commission (FERC) or the applicable Regional Transmission Organization (RTO) (either Midwest Independent Transmission System Operator, Inc. (MISO) or PJM Interconnection, LLC (PJM)).

15. Interconnection Application Levels
For State-jurisdictional DG interconnection requests, Title 83 part 466 has established four interconnection levels, generally linked to the DG capacity:
Level 1: 10kVA or less, lab-certified inverter-based DG facility
Level 2: 2MVA or less, lab-certified DG facility
Level 3: 10MVA or less, non-exporting
Level 4: 10MVA or less that do not qualify for Levels 1 through 3
Note that there are additional conditions within the statute that may affect the assigned level.

16. ICC Part 467
Section   Scope
The Illinois Large Distributed Generation Interconnection Standard applies to any generation facility operated in parallel with an electric public utility distribution company in Illinois and whose nameplate capacity is greater than 10 MVA (large distributed generation facility), provided that the distributed generation facility is not subject to the interconnection requirements of either the Federal Energy Regulatory Commission (FERC) or the applicable Regional Transmission Organization (RTO) (either Midwest Independent Transmission System Operator, Inc. (MISO) or PJM Interconnection, LLC (PJM).

17. ICC Part 466/467 Application Processes

18. Types of Interconnection Studies
There are three types of interconnection studies with varying levels of detail.
Interconnection Feasibility Study
Interconnection Impact Study
Interconnection Facilities Study

19. Types of interconnection studies
What does the utility consider important when performing interconnection studies for the Area EPS (Electric Power System)
Short circuit equipment duty ratings
Equipment thermal limitations
Voltage regulation
System load flows
Feeder hosting capacity
Flicker and power quality
Power system protection
System impacts/upgrades to accommodate interconnection

20. Types of interconnection studies cont.
Interconnection Feasibility Study
The interconnection feasibility study report must provide the following information:
Identification of any equipment short circuit capability limits exceeded as a result of the interconnection,
Identification of any thermal overload or voltage limit violations resulting from the interconnection and
A description and non-binding estimated cost of facilities required to interconnect the distributed generation facility to EDC's electric distribution system as required under Section (e)(1).

21. Types of Interconnection Studies cont.
Interconnection System Impact Study
The interconnection system impact study report shall provide the following information:
Identification of any equipment short circuit capability limits exceeded as a result of the interconnection,
Identification of any thermal overload or voltage limit violations resulting from the interconnection,
Identification of any instability or inadequately damped response to system disturbances resulting from the interconnection, and
Description and non-binding estimated cost of facilities required to interconnect the distributed generation facility to EDC's electric distribution system and to address the identified short circuit, thermal overload, voltage and instability issues.

22. Types of Interconnection Studies cont.
Interconnection Facilities Study
An interconnection facilities study report shall provide:
a description,
estimated cost of distribution upgrades,
schedule for required facilities to interconnect the distributed generation facility to ComEd's electric distribution system; and
shall address all issues identified in the interconnection system impact study (or identified in this study if the system impact study is combined herein).

23. Customer Responsibilities
What do you need to provide the utility?
Completed interconnection application and fees.
Technical data
Generator nameplate data
One-line diagram
Three-line diagram of instrumentation and relaying

24. Costs for Interconnection
As a regulated utility interconnection rules require that ComEd and any other utility provide open and equal access to all customer who request interconnection.
This requires providing the least-cost option for the interconnection of customer generation.
Regulatory requirements mandate that any customer interconnecting to the utility system are provided with a “good faith” cost estimate of the costs required for ComEd to accommodate the interconnection, but customers are still required to pay the actual costs required for interconnection.

25. Technical Requirements
ComEd technical review and requirements are intended for the protection of the ComEd system only. This does not guarantee adequate protection or performance of customer owned equipment.
ComEd and utilities strive to work with interconnection customers to provide a safe and reliable system. However, ComEd review does not imply either implicit or explicit approval of a customer system. Customer’s should design all system to applicable standards, codes and best engineering practices.

26. Overview of Protection Requirements
Level 1 and Level 2 Applications
Lab certified equipment
Protection is built in and has been tested as an assembly by a NRTL to meet applicable standard as defined in ICC requirements
Lab-certified interconnection equipment: equipment that has been type-tested by a nationally-recognized testing laboratory (NRTL) to requirements set forth in Title 83 part 466 Section (which includes, among other things, verified compliance with UL 1741, IEEE 1547, and the 2008 National Electrical Code). Generally, interconnection protection that has been type tested and certified for a certain class of interconnection installations. A Distributed Generation Facility that meets certain requirements may install lab-certified interconnection equipment which, by law, shall be sufficient interconnection relay protection.

27. Overview of Protection Requirements cont.
What does the utility consider important in determining requirements to protect the Area EPS (Electric Power System)?
Protection from customer generation during faulted and open circuit conditions.
Protection during system disturbances causing frequency or voltage deviations.
Anti-islanding protection (back-feed of other customer loads during loss of utility source)
Security and reliability of the customer protective relaying scheme.

28. Overview of Protection Requirements cont.
What protection methods are employed to provide protection of Area EPS:
Current-Used to provide protection against fault and overload conditions
Voltage-Used to provide protection against faults and other abnormal normal system conditions.
Frequency-Used to provide protection against load swings and other abnormal system conditions.
Impedance-Used to provide distance protection of lines
Power-Used to detection abnormal power flows
Communications-Used to add security to protective relay elements and schemes.

29. Relevant ANSI/IEEE Devices (typically used)
2: Timer
21: Distance Relay
25: Synchronizing Relay or Synchronism Check
27: Under Voltage
32: Reverse Power Relay
50FD: Phase Instantaneous Overcurrent Fault Detector
51: Time Overcurrent
51G: Ground Time Overcurrent
51N: Neutral Overcurrent
51V: Voltage Restrained/Controlled Time Overcurrent
59: Overvoltage
59G: Zero-Sequence Overvoltage (detects phase-ground faults)
67 Directional Overcurrent
79: Reclosing
81O: Over-frequency
81U: Under-frequency
86: Lock Out Relay (LOR)
87: Current Differential

30. Other protection considerations
The utility may have specific requirements for transformer or grounding connections which can impact system design and protection.
ComEd typically requires that transformer connections to the EPS be delta connected.
This eliminates third harmonics and zero sequence currents which may impact relay sensitivity.
Other utilities may require wye connected transformers.

31. Other protection considerations cont.
ComEd and utilities will typical provide customer with a Relay Functional Requirement Specification (RFRS)
The RFRS contains protective relay functions that must be implemented in as a part of the customer interconnection requirements
The utility will specify the requirements however the customer is solely responsible for their design and implementation
The utility will review, but does not approve customer protection settings and schemes.

32. Other protection considerations cont.
Utility protection requirements will vary depending on the size and type of interconnection.
Transmission level interconnections require more complex protection.
Typically communications enhanced protection
Redundant system protection
High speed protection schemes
SCADA data
Distribution level interconnections typically require less complex protection schemes
34kV system is considered sub-transmission and typically relayed using Dev. 21 distance protection
Typically follow IEEE Std

33. Other protection consideration cont.
ComEd and other utilities require that customer relay protection needs to be secure, yet capable of reliably responding to abnormal system conditions.
Customer relay protection needs to be able to distinguish between load and fault currents at low magnitude levels
Dev 67 and Dev. 51V may not be able to reliably distinguish between these two.
Dev 21. provides more security and can be blinded to not trip for loading issues.
Customer relay protection settings should be designed to coordinate with utility system protection settings
This includes time delays to coordinate with back-up protection

34. Other protection considerations cont.
Communications based protection schemes can enhance security by preventing over tripping of customer relays.
Control power for relays and tripping interrupting devices should be designed to trip prior to loss.
All protection systems need to be tested and commissioned.
ComEd and other utilities typically require that customers perform “witness” testing prior to final approval for interconnection.

35. Witness Testing Guidelines
ComEd and other utilities will typically require that customer’s perform witness testing to functionally demonstrate that all ComEd or utility protective device functions have been implemented and operate as designed and intended.
Customer is responsible for performing the testing and the utility will provide verification.
Customer must employ a competent testing agent capable of performing the required testing.
Customer will need to provide documentation that the installation has been inspected and approved by the AHJ were applicable.
Upon completion of witness testing the utility will certify that the installation meets the certificate of compliance for interconnection.

36. Conclusions
ComEd is required to follow regulatory rules for interconnection applications.
If you are a ComEd customer, contact ComEd to provide specific interconnection requirements in initial design and development phase.
Regulatory requirements mandate that all applicants have equal and open access.
ComEd is required to provide the lowest feasible cost option for interconnection.
Customer’s are responsible for all costs associated with the interconnection.
Customer’s are responsible for ensuring adequate design and protection of customer equipment.

37. Thank you for your time and attention! Questions?