Distributed Generation Interconnection Manual

Distributed Generation Interconnection Manual
Distributed Generation Interconnection Manual
Public Utility Commission of Texas
Prepared by:
Distributed Utility Associates
1062 Concannon Blvd.
Livermore, CA 94550
925-447-0604
[email protected]
Endecon Engineering
347 Norris Court
San Ramon, CA 94583
925-552-1330
www.endecon.com
May 1, 2002
U.S. Department of Energy
Office of Energy Efficiency and Renewable Energy
TABLE OF CONTENTS
1. Introduction ................................................................................................... 1-1
2. Safety Requirements..................................................................................... 2-1
2.1. PUCT Rules .............................................................................................. 2-1
2.2. TNRCC Rules ........................................................................................... 2-1
2.3. Local Codes and Standards ...................................................................... 2-2
2.4. National Codes and Standards ................................................................. 2-2
2.4.1. National Fire Protection Association....................................................... 2-2
2.4.2. Institute of Electrical and Electronics Engineers (IEEE) ......................... 2-3
2.4.3. Underwriters Laboratories ...................................................................... 2-4
3. Technical Summary....................................................................................... 3-1
3.1. General ..................................................................................................... 3-1
3.2. Prevention of Interference ......................................................................... 3-1
3.3. Requirements............................................................................................ 3-2
4. TDU Analyses of DG Interconnections.......................................................... 4-1
4.1. Utility Processing of DG Applications ........................................................ 4-1
4.2. DG Interconnection Requirements Review ............................................... 4-7
4.2.1. DG Application Review........................................................................... 4-7
4.2.2. Distribution System Type Review ........................................................... 4-7
4.2.3. Network Secondary Review.................................................................... 4-8
4.2.4. Non-Network Review............................................................................ 4-11
4.2.5. Issues That May Require Additional Review ........................................ 4-13
4.3. Cost/Benefit Impacts of DG..................................................................... 4-14
4.3.1. TDU Benefits and Costs ....................................................................... 4-14
4.3.2. Customer Benefits and Costs ............................................................... 4-19
4.3.3. Other Benefits and Costs ..................................................................... 4-24
4.4. Operational Protocols.............................................................................. 4-27
5. DG Applicant information .............................................................................. 5-1
5.1. DG Applicant Rights and Responsibilities ................................................. 5-1
5.2. TDU Rights and Responsibilities............................................................... 5-2
5.3. Interconnection Process............................................................................ 5-3
5.4. Frequently Asked Questions (FAQs) About DG Interconnections............. 5-4
6. Energy Efficiency and Customer-Owned Resources .................................... 6-1
7. Pre-certification Process ............................................................................... 7-1
8. Interconnection Disputes............................................................................... 8-1
Appendix A1: Definitions ................................................................................. A1-1
Appendix A2: Copy of PUCT’s Rules, Forms and PURA 99 Excerpts ............ A2-1
Appendix A3: Summary of DG Technologies .................................................. A3-1
Appendix A4: Texas Utility Contacts ............................................................... A4-1
Appendix A5: Internet Links ............................................................................ A5-1
Links for Electric Distribution Companies in Texas ......................................... A5-2
Appendix A6: Additional Safety and Performance References ....................... A6-1
Appendix A7: Pre-Certification Requirements ................................................ A7-1
Revisions to the Manual ................................................................................ A7-10
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1. INTRODUCTION
The Public Utility Commission of Texas (PUCT) has prepared this manual to guide
the inclusion of distributed generation into the Texas electric system. It is intended
for use by utility engineers processing distributed generation interconnection
applications, as well as those persons considering or proposing the interconnection
of distributed generation with a transmission and distribution utility (TDU). While
every possible eventuality or circumstance cannot be anticipated, the procedures in
this manual should cover most important issues or problems, including a process for
prompt dispute resolution.
Texas’ Public Utility Regulatory Act (PURA) of 1999 included in the list of customer
rights and safeguards that “A customer is entitled to have access… to on-site
distributed generation…” [§39.101(b)(3)]. This provision led the PUCT in October
1999 to adopt Substantive Rules §25.211 and §25.212 addressing the technical and
procedural aspects of interconnecting distributed generation, developed through a
collaborative process among the members of the TDU and DG communities. This
manual also includes the more recently adopted rules on operational aspects and
environmental treatment of distributed resources.
The Public Utility Commission of Texas wants to encourage the use of distributed
resources. Distributed resources benefit the state by adding more competitive
options, potentially reducing customer energy, improving the asset utilization of TDU
distribution systems, firming up reliability, and improving customers’ power quality.
Texans have the right to use distributed resources for whatever purpose they feel is
beneficial and it is the responsibility of the local distribution utilities to accommodate
and interconnect distributed generation subject to the rules laid out here.
The philosophy used to develop this manual was that distributed resources will and
should be an integral and valued part of the Texas electric supply system. Wherever
possible Texas has simplified the process, contractual relationships and hardware
required to interconnect distributed resources safely and beneficially for all involved
parties.
Joint funding for the preparation of this manual was provided by the U.S.
Department of Energy Office of Energy Efficiency and Renewable Energy and the
Public Utility Commission of Texas.
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2. SAFETY REQUIREMENTS
This section reviews the variety of interconnection-related safety requirements that
the DG designer/installer and the utility must take into consideration. The
requirements are divided by jurisdiction: State (PUCT), local, and national. These
requirements are intended to ensure that DG is designed and installed in a way that
• is not a safety hazard to utility personnel or equipment or to other customers,
• does not disturb other customers or degrade the quality of the distribution
system,
• provides reliable service to the DG owner and the utility.
To make certain that these expectations are met, it is critical that the TDU
understand the characteristics and requirements of the DG and vice versa.
2.1.
PUCT Rules
State regulations regarding the generation, transmission, and distribution of
electricity are set by the Public Utility Commission of Texas (PUCT). The PUCT’s
Web site provides access to all Rules at http://www.puc.state.tx.us under “Rules and
Laws”. Of technical interest to DG are the following:
Substantive Rules - Chapter 25
Applicable to Electric Service Providers
Subchapter A General Provisions
§25.5 * Definitions
Subchapter C Quality of Service
§25.51 Quality of Service.
Division 2. Transmission and Distribution Applicable to All Electric Utilities
§25.211 * Interconnection of On-Site Distributed Generation
§25.212 * Technical Requirements for Interconnection and Parallel Operation Of OnSite Distributed Generation
The specific requirements of §25.211 and §25.212 are covered in subsequent
sections of this manual. These rules detail the operational responsibilities of both
the TDU and the applicant.
The PUCT's rules may, in some cases, be superseded by local requirements or
modified in the future.
2.2.
TNRCC Rules
A distributed generation emissions rulemaking is in progress. This subsection will
be updated after a DG emissions rule is adopted by TNRCC.
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2.3.
Local Codes and Standards
County and city regulations may place additional permit or building code restrictions
or requirements on DG systems. These requirements will primarily affect the DG
installer, but both the installer and the utility should be aware of local codes and
standards that might modify the interconnection requirements specified in the PUCT
Rules.
2.4.
National Codes and Standards
To address safety and power quality issues, national codes and safety organizations
have developed guidelines for equipment manufacture, installation and operation.
The major code and safety organizations that apply to distributed generation are the
National Fire Protection Association (NFPA), Underwriters Laboratories (UL) and
Institute of Electrical and Electronics Engineers (IEEE). Each of these organizations
covers different aspects of the DG interconnection in the context of their
organizational missions, as explained below.
The national laboratories are also actively involved in issues surrounding DG
interconnection.
The Department of Energy’s National Renewable Energy
Laboratory (NREL) in Golden, Colorado and Sandia National Laboratories in
Albuquerque, New Mexico work closely with the NFPA, IEEE and UL on code issues
and are frequently involved in equipment testing. The labs are not responsible for
issuing or enforcing codes, but they do serve as valuable sources of information on
DG and interconnection issues. The following subsections discuss each of these
standards bodies individually, how the codes interact, and how the documents are
being used. A good deal of TDU interconnection work has been done in the
renewables arena, primarily PV. Several of the documents listed are PV-specific, but
in fact, are relevant to any inverter-based technology and touch on issues that apply
to rotating machines as well.
2.4.1. National Fire Protection Association
The National Fire Protection Association publishes NFPA-70, The National Electrical
Code (NEC), and is the foremost organization in the U.S. dealing with electrical
equipment and wiring safety. The scope of the NEC covers all buildings and
property except for electric TDU property, i.e., all equipment on the customer’s side
of the point of common coupling (the meter).
Article 705, Interconnected Electric Power Production Sources, broadly covers DG
interconnection. It reinforces many of the topics covered in the PUCT Rule (e.g.,
“Synchronous generators in a parallel system shall be provided with the necessary
equipment to establish and maintain a synchronous condition”) and adds some
PUCT DG Interconnection Manual 05/01/02
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details, for example, related to disconnect switch requirements.
Article 690, Solar Photovoltaic Systems, mentions interconnection to the grid, but
focuses more on system wiring and descriptions of components. One key
requirement in Article 690 of the NEC is that all equipment interconnecting with the
grid must be listed1. This requirement is unique both within the code (which primarily
encourages rather than requires listed equipment) and within DG. Inverters for a
microturbine or fuel cell (which are not explicitly covered by 690) do not have to be
listed per the code, though it’s nearly always required by electrical inspectors.
The NEC may address fuel cells or utility interconnection issues related to all
inverter-based in the future.
Additional relevant standards are found in NFPA-37, the Standard for the Installation
and Use of Stationary Combustion Engines and Gas Turbines; NFPA-99, the
Standard for Health Care Facilities; and NFPA-110, the Standard for Emergency and
Standby Power Systems.
2.4.2. Institute of Electrical and Electronics Engineers (IEEE)
The standards that electric utilities adopt for their equipment often originate from
IEEE. Standards balloting rules require that a balanced committee of utilities,
manufacturers, users, and general interest groups are involved in the development
of new IEEE standards. This diversity ensures that the standards provide a
consensus of all interested parties. IEEE standards are voluntary, so utilities are not
required to adopt them unless there is a specific Commission or legislative ruling to
that effect.
In the 1980s, the Institute of Electrical and Electronics Engineers (IEEE) published
ANSI/IEEE Std 1001-1988, IEEE Guide for Interfacing Dispersed Storage and
Generation Facilities with Electric Utility Systems. This standard addresses the
basic issues of power quality, equipment protection, and safety. This document has
expired and a new document is under development to take its place. This project,
P1547, Standard for Distributed Resources Interconnected with Electric Power
Systems, was started in 1998 and will be completed 2001.
The recently adopted ANSI/IEEE Std. 929-2000, IEEE Recommended Practice for
Utility Interface of Photovoltaic (PV) Systems, was developed to meet utility
concerns with safety and power quality for PV systems. The intent was that there
1
As defined in NEC Article 100, listed means “equipment, materials, or services included in a list
published by an organization that is acceptable to the authority having jurisdiction and concerned with
evaluation of products or services, that maintains periodic inspection of production of listed equipment
or materials or periodic evaluation of services, and whose listing states that either the equipment,
material, or services meets identified standards or has been tested and found suitable for a specified
purpose.”
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would be no need for additional requirements in developing utility-specific guidelines,
especially for systems of 10 kW or less. The new Std. 929, replacing a 1988 version,
contains a 12-page recommended practice and appendices with detailed
background into issues such as how inverters interface with the utility, islanding, and
distribution transformers.
Another key standard is IEEE 519-1992, IEEE Recommended Practices and
Requirements for Harmonic Control in Electric Power Systems. This guide applies
to all types of static power converters used in industrial and commercial power
systems, and addresses the problems involved in the harmonic control and reactive
compensation of such converters. Limits of disturbances to the AC power
distribution system that affect other equipment and communications are
recommended. Voltage and current harmonics limits—total and single harmonic—
as well as the voltage flicker limits of irritation curves are referenced for both utility
practice and DG requirements.
IEEE standards covering many aspects of utility interconnection and distribution
system design and operation are listed in Appendix A6.
2.4.3. Underwriters Laboratories
Underwriters Laboratories (UL) is a private, not-for-profit organization that has
evaluated products, materials and systems in the interest of public safety since
1894. UL has become the leading safety testing and certification organization in the
U.S., and its label is found on products ranging from toaster ovens to inverters to
some office furniture.
Although UL writes the testing procedures, other organizations may do the actual
testing and certification of specific products. In addition to UL, other testing labs
such as ETL SEMKO (ETL), and the Canadian Standards Association (CSA) are
widely recognized listing agencies for electrical components.
UL Standard 1741, Static Inverters and Charge Controllers for use in Photovoltaic
Power Systems, deals with design requirements and testing procedures for
inverters. UL 1741, published in May 1999, is now being revised comport to IEEE
Std 929-2000, to cover inverters used for sources other than PV and to cover
controllers that might provide similar capabilities for synchronous and induction
machines.
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3. TECHNICAL SUMMARY
3.1.
General
Technical requirements for interconnecting DG to the TDU are defined in §25.212.
This section summarizes those requirements. In general, the applicant’s generation
and interconnection equipment must meet all applicable federal, state and local
codes. Interconnection equipment shall be capable of providing TDU system
protective functions to prevent the generator from energizing a de-energized circuit
owned by the TDU. Use of pre-certified equipment (see Section 7 of this Manual)
will ensure that the minimum required capabilities are met, so the TDU will not need
to review the DG design (other than to ensure that all necessary equipment is
included).
Many of the requirements listed here were developed for non-export systems: those
that do not intentionally send power to the TDU across the point of common
coupling. The non-export condition can be met either implicitly by establishing that
the DG output capacity is less than the applicant’s verifiable minimum load (i.e., the
DG never generates more than the applicant will consume), or explicitly through the
use of a reverse power or under power relay (devices that disconnect the DG from
the TDU if it attempts to export power)2. Systems that export power can place
additional burden on the distribution system, especially a networked secondary, but
may provide benefits as well. The TDU may elect to study these systems or any
application that they feel would present safety or operational hazards to the
distribution system. The results of the study may be a requirement for more
sophisticated protective devices and operating schemes. However, the burden is on
the TDU to justify the need for any additional requirements. The applicant has the
option of complying with the additional requirements, withdrawing the application, or
petitioning the commission for a good cause exception.
3.2.
Prevention of Interference
Many of the requirements established in Rule §25.212 are based on the assumption
of relatively low DG penetration operating from the TDU. Rather than attempting to
regulate voltage and frequency, the DG should follow the voltage and frequency
imposed by the TDU, and should disconnect under abnormal conditions as defined
in Table 3-1 below. Since the DG is not regulating voltage or current, the allowable
operating ranges are relatively wide. The ranges and trip times shown in Table 3-1
take into account the fact that losing any generation (including DG) when the system
voltage or frequency is decreasing can exacerbate generation-related problems.
After tripping due to a voltage or frequency disturbance, the DG may reconnect once
the utility voltage and frequency have returned to the Normal Operating Range and
2
This may be a discrete relay or a function of a controller or inverter. Throughout this document, the
use of the term “reverse power” is intended to include both reverse and under power functions.
PUCT DG Interconnection Manual 05/01/02
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have stabilized for 2 minutes or a shorter time as agreed to by the applicant and
TDU.
Table 3-1: Voltage/Frequency Disturbance Delay & Trip Times
Trip Time[2]
Range
Percentage
<70%
70%-90%
90% - 105%
105% - 110%
>110%
Voltage[1]
<84
84 – 108
108 – 126
126 – 132
>132
Seconds
Cycles
0.166
10 (Delay) & 10 (Trip)
30.0 & 0.166
1800 (Delay) & 10 (Trip)
Normal Operating Range
30.0 & 0.166
1800 (Delay) & 10 (Trip)
0.166
10 (Delay) & 10 (Trip)
Frequency (Hz)
<59.3
59.3 – 60.5
>60.5
[1]
[2]
0.25
15 (Trip)
Normal Operating Range
0.25
15 (Trip)
Voltage shown based on 120V, nominal.
Trip times for voltage excursions were added for completeness by the PUCT Project
No. 22318 Pre-certification Working Group as the intent of 25.212.
As with load, minimum harmonics and flicker standards are defined for DG. These
limits are established in IEEE 519. In summary, this standard, in Chapter 10 for
individual consumers, requires current total demand distortion (TDD) of 5% or less of
the fundamental. The standard, in Chapter 11 requires voltage total harmonic
distortion (THD) of 5% or less and 3% for any single harmonic, measured at the
point of common coupling. Described in Chapter 10 of the standard, flicker, typically
associated with induction generator start-up, may not cause a voltage dip of more
than 3% as indicated on the border lines of irritation curve of the standard.
3.3.
Requirements
Table 3-2 summarizes Texas’ equipment and operational requirements for
interconnecting DG, based on the characteristics of the proposed system. These
requirements are first differentiated by DG paralleling mode and type of connection.
Closed Transition is a mode of operation in which the DG is operated in parallel with
the TDU for brief period of time, only long enough to ensure that the load is
maintained while transitioning from TDU supply to generator, or vice versa. A
manufacturing facility looking for peak shaving, but with power quality-sensitive
processes, might use this type of system. For such systems, defined here as
paralleling for less than 60 cycles (one second), the potential impact on the
distribution system, and thus the interconnection requirements, are minimal.
Requirements for DGs that normally operate for more than 60 cycles—the majority
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of anticipated DG systems—are listed by connection type: single- or three-phase.
Table 3-2: DG Interconnection Requirements
Closed
Transition
SinglePhase
Three-Phase
Capacity
≤10 MW
≤50 kW
≤10 kW
10 kW 500 kW
500 kW 2 MW
2 MW 10 MW
§25.212(g)
§25.212(d)
§25.212(e)(3)(A)
§25.212(e)(3)(B)
§25.212(e)(3)(C)
§25.212(e)(3)(D)
Interrupting devices
(capable of interrupting
maximum available fault
current)
9
9
9
9
9
[4]
Interconnection disconnect
device (manual, lockable,
visible, accessible)
9
9
9
9
9
9
Generator disconnect
device
9
9
9
9
9
9
Over-voltage trip
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
Synchronizing check
(A: Automatic, M: Manual)
A
A/M [1]
A/M [1]
A/M [1]
A
[1]
A
[1]
Ground over-voltage or
over-current trip
[2]
[2]
[2]
[2]
[3]
[3]
[3]
9
9
Feature
PUCT Rule Reference
Under-voltage trip
Over/Under frequency trip
Reverse power sensing
If exporting, power
direction function may be
used to block or delay
under frequency trip
Automatic voltage regulator
[1]
Telemetry/transfer trip
9
Notes:
9– Required feature (blank = not required)
[1] – Required for facilities with stand-alone capability
[2] – May be required by TDU; selection based on grounding system
[3] – Required, unless generator is less than applicant minimum load, to verify non-export
[4] – Systems exporting shall have either redundant or listed devices
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Single-phase systems will primarily be used on residential or small commercial
applications. For closed transition and single-phase DG, Table 3-2 lists the
maximum allowable system size. For three-phase DG, the requirements are further
broken down by DG capacity, with larger systems having more requirements than
smaller systems.
A few additional requirements apply for three-phase generators, by device type:
Synchronous Machines:
• Three phase circuit breakers with electronic or electromechanical control.
• Applicant solely responsible for proper synchronization.
• Excitation response ratio shall not be less than 0.5.
• Excitation system shall conform with ANSI C50.13-1989.
Induction Machines
• May “motor” up to speed if initial voltage drop at the PCC is within the Flicker
limits (§25.212(c)(2)).
Inverters
• Line-commutated inverters do not require synchronizing equipment.
• Self-commutated inverters require synchronizing equipment.
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4. TDU ANALYSES OF DG INTERCONNECTIONS
Introduction
This section is intended to provide a systematic approach for the engineering review
process of a typical interconnection study. It includes the steps that must be taken to
properly account for site-specific concerns and address the technical and procedural
requirements of the Texas interconnection rules §25.211 and §25.212.
The goal of this section is to ensure that TDU interconnection analyses of the
impacts of distributed generation are conducted in a clear, unbiased and consistent
manner, irrespective of the TDU, the DG technology, or the applicant. This section
will give the DG applicant a clear understanding of how the interconnection analysis
will be conducted. It also provides a method to determine whether a DG
configuration and application will pass or fail Texas’ analytical protocols. The
analytical directions in this section should allow all members of Texas’ TDU and DG
communities to use common terms, descriptions and assumptions about the
benefits, costs, and grid impacts of DG, so that any disputes about a specific
interconnection will focus on whether the proper calculations have been made,
rather than whether a specific impact or benefit is legitimate or valid.
However, certain applications may require minor modifications while they are being
reviewed by the TDU. Such minor modifications to a pending application shall not
require that it be considered incomplete and treated as a new or separate
application.
4.1.
Utility Processing of DG Applications
As defined in §25.211, upon receipt of a completed application, the TDU has a
defined period (4 to 6 weeks, defined below) of time in which to process the
application and provide the following:
•
•
•
•
Approval to interconnect
Approval to interconnect with a list of prescribed changes to the DG design
Justification and cost estimate for prescribed changes to TDU system
Application rejection with justification
The PUCT limits when and why a TDU may charge the applicant for the
performance of a service, coordination, or system impact study. In general, any
study performed by the TDU shall follow these rules:
•
•
Study scope shall be based on characteristics of the DG at the proposed
location.
Study shall consider cost incurred and benefits realized as a result of DG
interconnection.
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•
•
•
•
•
TDU shall provide a cost estimate to the DG applicant prior to initiation of
study.
TDU shall make written reports and study results available to the DG
applicant.
TDU may reject application for demonstrable reliability or safety issues but
must work to resolve those issues.
TDU shall advise the DG applicant of potential secondary network-related
problems before charging a study fee.
TDU shall use best reasonable efforts to meet the application processing
schedule, or will notify the DG applicant in writing why it cannot meet the
schedule and provide estimated dates for application processing and
interconnection.
If the proposed site is not on a networked secondary no study fee may be charged to
the applicant if all of the following apply:
•
•
•
•
Proposed DG equipment is pre-certified
Proposed DG capacity is 500kW or less
Proposed DG is designed to export no more than 15% of the total load on
feeder (based on the most recent peak load demand)
Proposed DG will contribute not more than 25% of the maximum potential
short circuit current of the feeder
Certain aspects of secondary network systems create technical difficulties that may
make interconnection more costly to implement. If the proposed site is serviced by a
networked secondary, no study fee may be charged to the applicant if:
•
•
Proposed DG equipment is pre-certified
Aggregate DG, including the proposed system, represents 25% or less of the
total load on the network (based on the most recent peak load demand)
and either
•
Proposed DG has inverter-based protective functions, or
•
Proposed DG rating is less than the local applicant’s verifiable minimum load.
Otherwise, the TDU may charge the DG applicant a fee to offset the costs of the
interconnection study.
The TDU must advise applicants requesting DG
interconnection on secondary networks about the potential problems and costs
before initiating the study.
Note that these provisions do not preclude the TDU from performing a study; they
simply regulate when the TDU can charge the applicant for the cost of the study.
Whether or not a study fee is billable to the applicant, the TDU may reject an
application for demonstrable reliability or safety issues but must work to resolve
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those issues to the mutual satisfaction of the TDU and applicant. The TDU must
make reasonable efforts to interconnect all proposed DG, including the possibility of
switching network-secondary service to a radial feed if practical and if acceptable to
the applicant.
The flow charts in Figures 4-1 and 4-2 show, for non-network and secondary
network systems respectively, how the Rule §25.211 requirements interact and what
the TDU must consider when processing a DG interconnection application. Some of
the decisions are based on location-specific information not available to the DG
applicant at the time of application. It is important that the application be accurate
and complete to eliminate delays in processing. These decision paths result in
either “Approve Application” or “Recommendation”.
Systems meeting the requirements that result in “Approve Application” are
considered simple with little chance of being a hazard to the distribution system,
personnel, or neighboring customers. These systems should not require any
additional studies, thus the utility is not allowed to charge a study fee.
The Recommendation results from a study that may be charged to the applicant,
and may be one of the following:
•
•
•
Approval of the application as is
Description of changes to the proposed DG system or to the distribution
system necessary to approve the application
Rejection of the application due to specified reasons
Figure 4-3 provides a timeline of activities, based primarily on the requirements in
§25.211(m) . Normally, it is anticipated that the application will be submitted,
processed, and an interconnection agreement signed before construction activities
begin. However, the Rules do not require this sequence and a more compressed
schedule is possible. Rule §25.212(h) requires the DG applicant to provide the utility
with two-week notice prior to start-up testing.
However the Rules do not specify
when this must occur or which events must precede the notice. An applicant can
anticipate approval, submit the two weeks notice along with the application and be
prepared for start-up testing immediately upon signing the interconnection
agreement. If utility system modifications are required that are not considered a
substantial capital upgrade, the utility may have to complete those upgrades prior to
the start-up test.
If the utility is unable to complete the modifications prior to commissioning (for
example, if the two week notice is given with the application), they may work out
partial operation or other arrangements with the applicant until such modifications
can be completed. Rule 25.211(m)(4) allows the utility extra time to interconnect the
DG if it can show suitable reasons for needing an extension to the time allowed.
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Figure 4-1: Non-Network Study Chart
Proposed System on
Non-Network Feeder
(References, in parentheses,
indicate the appropriate
section of Rule §25-211.)
(g)
Equipment Precertified? (g-1)
No
Yes
DG ≤ 500 kW?
No
(g-1)
Yes
Export ≤ 15% of
Feeder Load ?
No
(g-1)
Yes
DG ≤ 25% of Max
Short Circuit?
No
(g-1)
Yes
No Study Fee Allowed
Study Fee Allowed
(g-1)
(g-2)
Approve Application
Recommendation
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Figure 4-2: Network Secondary Study Chart
Proposed System on
Network Secondary
(h,i)
(References, in parentheses,
indicate the appropriate
section of Rule §25-211.)
Equipment Precertified? (?)
No
Yes
Aggregate DG ≤
25% of Feeder Load?
No
(h-1, h-2)
Yes
Yes
DG < 20kW,
Inverter based?
No
(i)
Yes
Inverter-based
Protective Function ?
(h-1)
No
DG < customer
minimum load?
No
(h-2)
Yes
No Study Fee Allowed
Study Fee Allowed
(g-2, m-1)
(g-2, m-1)
Approve Application
Recommendation
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Figure 4-3: Application Processing Activities
Submit Application
Incoming Processing
Minimum Engineering Review
Optional Study
Application
Approved
Interconnection
Agreement
Signed 211(e)(5)
Upgrade
Substantial
?
No
Yes
Substantial
Upgrade Contract
211(m)(3)
Upgrade
Distribution
System
2 week notice 212(h)
Allowable Time*
Application
Rejected
Install DG
Upgrade
Required
Commissioning Test
Operate DG
* -- Allowable Time from receipt of completed application to a signed interconnection agreement:
1) Systems using Precertified equipment – 4 weeks (§25.211(m)(1))
2) Systems using Non-precertified equipment – 6 weeks (§25.211(m)(2))
3) Add up to 6 weeks for additional interconnection study time for applications in Network
secondaries where the aggregate DG exceeds 25% of the feeder load. (§25.211(h)(3))
4) If the proposed system will require substantial capital upgrades to the utility system, the utility
shall provide the applicant an estimate of the schedule and applicant’s cost, if any, for the
upgrade. If the applicant desires to proceed with the upgrade, the applicant and the utility will
enter into a contract for the completion of the upgrade. The commissioning test will be
allowed within two weeks following the completion of such upgrades. (§25.211(m)(3)).
5) The TDU shall use best reasonable efforts to interconnect facilities within the time frames
described above. If in a particular instance, the TDU determines that it cannot interconnect a
facility within these time frames, it will notify the applicant in writing. The notification will
identify the reason or reasons interconnection could not be performed in accordance with the
schedule and provide an estimated date for interconnection (§25.211(m)(4)).
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4.2.
DG Interconnection Requirements Review
The discussion below lays out when a TDU is authorized by the PUCT Rules to
charge for a DG Interconnection Study, and provides some guidance as to how a
study should be performed. Rule language does not preclude the TDU from
performing a study at anytime, limiting only when the applicant may be billed for the
study. However, it is expected that as each TDU gains experience with DG on its
system, the TDU will reduce its reliance on studies as well as the level of effort
necessary to perform them.
4.2.1. DG Application Review
The DG applicant should provide all necessary information with the application,
including documentation verifying compliance with the technical requirements of
Rule 25.212. Failure to supply all necessary information is grounds for rejection of
the application.
The following information must be supplied for the application package to be viewed
as complete.
1.
2.
3.
4.
5.
6.
DG generator or inverter nameplate capacity in kilowatts (DGCapacity)
Maximum DG capacity allocated for export in kilowatts (DGExport)
DG Output (voltage, single-phase or three-phase)
DG type (e.g. inverter-based, synchronous, induction)
DG short circuit capability (DGSCmax)
Whether the DG facility meets the Texas pre-certification requirements
(see Section 7 of this Manual)
7. Location of DG (street address, applicant account number)
8. Minimum load of the facility to which the DG is connected.
9. Documentation that the DG facility contains all the minimum protective
functions required in Rule §25.212 (see Table 3-2).
10. Documentation that the appropriate protective functions are either factory
preset to proper values or are capable of being set according to the
parameters set forth in Rule §25.212 (see Table 3-1).
4.2.2. Distribution System Type Review
Once the application package is complete, the TDU should determine whether the
proposed DG installation site is on a secondary network by locating the proposed
facility on its distribution circuit. The answer to this question will impact the type of
review process and study fees and schedules associated with the application.
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Q: Is the proposed DG facility to be located on a networked secondary
distribution system?
If yes, proceed to section 4.2.3: Secondary Network Review.
If no, proceed to section 4.2.4: Non-Network Review.
4.2.3. Network Secondary Review
In a network secondary distribution system, service is redundantly provided through
multiple transformers as opposed to radial systems where there is only one path for
power to flow from the distribution substation to a particular load. The secondaries
of networked transformers are connected together to provide multiple potential paths
for power and thus much higher reliability than an equivalent radial feeder. To keep
power from inappropriately feeding from one transformer back through another
transformer (feeding a fault on the primary side, for example), devices called
network protectors are used to detect such a backfeed and open very quickly (within
a few cycles).
If the aggregate DG output within a networked secondary exceeds the aggregate
load, the excess power will activate one or more network protectors. If such a
situation were allowed, the reliability of the secondary network would be reduced. In
such a circumstance, DG could compromise grid reliability.
Most downtown areas of larger cities have secondary networks (e.g., Austin, Dallas,
Houston and San Antonio). How far those networks extend and where the network
ends and radial distribution begins is a function of the density of the load and a
number of other factors. Facilities in the center of downtown areas are very likely to
be on networks, whereas facilities in suburban and rural areas are almost certain to
be on a radial distribution system.
4.2.3.1.
DG Pre-Certification Review – Secondary Network
If the DG qualifies as pre-certified under Texas' pre-certification requirements (Rule
§25.211(c)(12) and §25.211(k); see section 7 of this manual), the review can
proceed to the DG Capacity Review. If the DG does not qualify as pre-certified, the
TDU is allowed up to six weeks to perform a study that may involve a fee.
4.2.3.2.
DG Capacity Relative to Load – Secondary Network
Secondary networks are used where load is sufficiently dense to justify the added
reliability and added cost of such a system. As a result, the DG facility (or aggregate
DG) could be sizeable before the utility engineer needs to be concerned. For
example, one-megawatt of DG on a 10-megawatt network would be of little concern.
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Conversely, one-megawatt of DG on a three-megawatt network could be of
significant concern.
Rule §25.211(h)(1) and (2) define when the TDU shall approve applications for
interconnection (the TDU may elect to do a study but may not charge a fee). These
are as follows:
•
§25.211(h)(1): Distributed generation facilities that use inverter-based protective
functions with total distributed generation (including the new facility) on the
affected secondary network representing no more than 25% of the total load of
that network.
•
§25.211(h)(2): Other on-site generation facilities whose total generation is less
than the local customer's load (non-export) and with total distributed generation
(including the new facility) on affected secondary network representing no more
than 25% of the total load of that network.
The aggregate DG is determined by summing the nameplate ratings of each of the
DG units within the network. The total load of the network is defined as the
maximum load of the network for the previous 12-month period. This threshold,
expressed in equation form, is the following:
TotalDGCapacitynetwork = TDGCnetwork ≤ 0.25 × TotalLoad network
This is the value at or below which inverter-based DG should not require costly
changes to the utility system in order to accommodate the DG installation. The TDU
shall accept applications, and a study fee may not be charged since it is assumed
that no study is necessary. It is assumed that all inverter-based DG under 20kW is
so small that, irrespective of the 25% threshold, no study is necessary and therefore
the application shall accepted and no study fee may be charged.
4.2.3.3.
Power Export Review
To determine whether or not a distributed generator complies with §25.211(h)(2)
above, it must be determined whether the DG will export power. No export limit was
provided for network systems, meaning that all export systems on network
secondaries may be subject to a study for which a fee may be charged (excluding
inverter-based systems).
A DG system designed for non-export (i.e., it only offsets applicant load without
feeding into the grid) simplifies the review process. Non-export systems will not
adversely impact the secondary network protection schemes and, for systems with
explicit non-export capabilities, the need for additional islanding detection is
eliminated. There are three methods to ensure that power is not exported:
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(1) (Implicit) To ensure no export of power without the use of explicit nonexport protective functions, the capacity of the DG must be no greater
than the customer’s verifiable minimum annual load. Use of additional
anti-islanding functions may be required to ensure worker and equipment
safety.
(2) (Explicit) To ensure power is never exported, a reverse power protective
function must be implemented within the facility. Default setting shall be
0.1% (export) of transformer rating, with a maximum two-second time
delay.
(3) (Explicit) To ensure at least a minimum import of power, an under-power
protective function may be implemented within the facility. Default setting shall
be 5% (import) of DG Gross Nameplate Rating, with maximum two-second time
delay.
Non-inverter-based DG that does not export and meets the 25% threshold should
not require changes to the utility system in order to accommodate the installation.
The serving utility shall accept these applications, and a study fee may not be
charged since it is pre-assumed that no study is necessary. Although the sections of
the Rules addressing studies do not specifically provide options for non-export other
than (1) above, options (2) and (3) are technically equivalent to (1) and do not
require a study fee.
If the DG is not inverter-based and is not less than minimum applicant load, but still
complies with the 25% threshold, a study fee may be charged to the applicant to
determine whether any modifications need to be made. The study can take up to
four weeks.
If the total DG capacity on a particular network exceeds 25% of the total load of the
network, the TDU may halt the application process up to six weeks while performing
a study that may involve a study fee. Such an analysis may require detailed dynamic
modeling of the load/DG/network interaction. Depending on such issues as load
diversity and generator dispatch, the utility may determine that some DG beyond the
25% limit may be acceptable while others may be unacceptable. As such modeling
can be quite costly, the utility must inform the DG applicant of the potential issues
and appropriate study cost before initiating the study. Once the study is complete,
the application processing and the allowable processing time (see Figure 4-3) shall
continue.
4.2.3.4.
Conditions When Service Needs To Be Converted To Radial
As the total DG on a secondary network grows relative to total network load, so does
the likelihood of reverse power flow through one or more network protectors causing
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them to open and interrupt service. In this case, power flow studies may be needed
to determine if it is possible for the network protectors to see reverse power (even
momentarily) from the DG and initiate a trip.
If the power flow study determines that the DG installation could cause unintended
operation of the network protector, one way to mitigate this problem is to switch the
DG facility service to a radial service. If the proposed DG location is close to a
network protector, it might be easy to switch the DG onto a radial feeder, making the
change less costly. If the 25% of network load requirement is not met, the utility
should conduct a power flow study and investigate whether it is necessary to convert
the DG service from network to radial to mitigate the unintended operation of the
network protectors.
4.2.4. Non-Network Review
4.2.4.1.
DG Pre-Certification Review – Non-Network
If the DG qualifies as pre-certified under Rule §25.211(c)(12) and §25.211(k), the
non-network review can proceed to the DG Capacity Review. If the DG equipment
is not pre-certified, a study may be performed that can take up to six weeks and
involve a study fee.
4.2.4.2.
DG Capacity Review – Non-Network
If the DG capacity is less than or equal to 500 kW, the review can continue to the
export level review. If the DG capacity, as reported on the completed application,
exceeds the 500 kW threshold, the TDU is allowed up to four weeks to perform a
study that may involve a fee.
4.2.4.3.
Export Level Review – Non-Network
A key question for each DG installation is whether the DG applicant intends to export
generation across the point of common coupling (PCC); and if so, how much. If
power is to be exported across the PCC:
•
DG that exports can cause reverse voltage drops (from the DG towards the
substation). Thus, the TDU may need to study the local distribution system and
determine if adjustments to local voltage regulation schemes are necessary.
•
Protection against the formation of unintended islands becomes more
complicated since the DG will be supporting load beyond the PCC.
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Rule §25.211 (g)(1) provides a threshold to address these concerns, stated as 15%
of the total load on a single radial feeder. Here again, total load is defined as the
maximum load over the previous 12–month period. This threshold, expressed in
equation form, is the following:
DGexport max ≤ 0.15 × FeederLoadmax
This is the value at or below which the DG can export without requiring costly
changes to the TDU system in order to accommodate the DG export. If the system
falls within the export limit, it is assumed that the application of the DG on that
portion of the distribution system will not cause the complications listed above. DG
which exceeds this threshold may be studied to determine whether it could cause
islanding or adverse power flows.
4.2.4.4.
Short Circuit Contribution Review – Non-Network
If the DG passes the export level threshold of 15% of feeder load, the maximum
short circuit current on the radial feeder must be calculated. The TDU will then
calculate the maximum short circuit current contribution at the DG location. Once
this value is determined, multiply that quantity by 0.25 to establish the 25% threshold
for the primary feeder. The DG’s maximum short circuit capability found in the
application must then be converted to the corresponding short circuit current after
transforming to primary voltage. This transformed DG short circuit must be less than
or equal to the 25% threshold. This threshold is expressed through the following
equations:
Assume:
FeederShortCircuit max = FSC max
and:
DGShortCircuit max = MaxDGShortCircuit × DGOutputVo ltage ÷ Pr imaryVoltage
= DGSC max
To comply with this threshold, DGSCmax must be less than or equal to 25% of
FSCmax.:
DGSC max ≤ 0.25 × FSC max
If the DG complies with this threshold, it is assumed that:
• the DG has little impact on the distribution system’s short circuit duty.
• the DG will not adversely affect the fault detection sensitivity of the distribution
system.
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•
the utility’s relay coordination and fuse-saving schemes are not significantly
impacted.
If the DG does not comply with this threshold, the TDU may study the DG application
over four weeks with a study fee. If the DG passes all these thresholds, it will not
require changes to the utility system to accommodate the installation. Such DG will
not require additional studies or equipment to accommodate, and can interconnect
without any study fees.
4.2.5. Issues That May Require Additional Review
Rule §25.211 limits when the utility may charge the DG applicant for performing an
interconnection study. However, it also states that an application may be rejected if
it can “demonstrate specific reliability or safety reasons why the DG should not be
interconnected at the requested site." The utility is then responsible for working with
the applicant “to attempt to resolve such problems to their mutual satisfaction.”
There are special cases that may require the interconnecting utility to take a closer
look to ensure the proposed system satisfies the technical requirements set forth in
Rule §25.212.
4.2.5.1.
DGs That Motor To Speed
Some generators use the utility to bring the generator up to operating speed. Other
generators use the prime mover or do not require high currents to start. In the case
where a DG is using the utility to motor to speed and requires starting currents well
above normal operating currents, it may be necessary to check the resulting voltage
drop to ensure that it passes the flicker requirement of 3% found in §25.212(c)(2).
This threshold of 3% voltage dip is calculated on the primary side of the distribution
transformer. If an installation causes nuisance voltage fluctuations to neighboring
customers after installation, it may be necessary to perform a site assessment of the
voltage fluctuations to verify that it is within the stated standard.
4.2.5.2.
DG on Four-Wire Feeders
If a DG is located on a three-phase four-wire feeder, the DG interconnection should
be reviewed to confirm that it will not cause phase overvoltages in the event that the
feeder is disconnected from the rest of the distribution system. The concern is that a
DG of sufficient size could provide brief phase-to-neutral overvoltages that could
damage customer’s equipment on the local distribution system in the event of a
system outage.
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There are several ways that a DG can be integrated with such a feeder without
potential for causing harmful voltages:
1) If the DG is single-phase connected line-to-neutral, it is incapable of contributing
to phase-to-neutral overvoltages given the over-voltage trip requirements;
2) if the DG is small enough relative to the feeder size (10% of feeder peak load), it
does not contribute enough voltage support to raise the voltage to hazardous
levels; or
3) if the DG has some way of regulating phase-to-neutral voltage, it can ensure that
this will not happen.
If the DG installation does not comply with one of these three options for limiting
voltage overloads, it may require additional study to determine what can be done to
mitigate this issue.
4.3.
Cost/Benefit Impacts of DG
4.3.1. TDU Benefits and Costs
4.3.1.1.
Deferral of Capital Expenditures
As load on a distribution system grows, eventually a point is reached when the load
outgrows the capacity of one or more components of the power system, such as a
transformer or distribution line (feeder). The traditional utility response to this
situation is to install additional capital equipment to relieve the overloading. Not
investing in capacity upgrades increases the risk that system components will fail
under stress, degrading reliability and increasing O&M costs.
A load duration curve is an analysis tool used to depict the amount of time (in
percent) during a year that the load on a system is above a given fraction of its
maximum (peak) value. Typical load duration curves for distribution systems are
shown in Figure 4-4. Since load duration curves are normalized to the peak during
the year, the curve begins at 100% decline steadily to the right, eventually showing
the minimum load point on the right hand edge. At any point in between, a load
duration curve shows the need to serve load relative to the peak demand. For
example, for a typical TDU distribution system with a mix of residential, commercial
and industrial load (the solid curve in Figure 4-4), the total load will exceed 70% of
its peak for only about 10% of the year, or about 900 hours.
The load will exceed 80% of peak for only about 3% of the year, about 260 hours.
While extreme peaks are very infrequent events, the T&D system is designed
specifically to serve peak loads, and thus growth in peak loading determines when
action is needed to prevent system overloads during peaks.
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The dashed curve in Figure 4-4 depicts the load duration characteristics of a feeder
that is primarily residential and commercial with a minimal industrial component, a
characteristic that is increasingly common for many feeder systems in suburban
areas. The load profile of this feeder is characterized by a higher component of air
conditioning load during summer peaks. For this curve, the 70% load level
corresponds to about 2% of the year (175 hours), and the 80% load level to less
than 1% of the year (about 80 hours).
Understanding the duration of loads on a feeder indicates how much distributed
generation could be used for reducing peak demands on the distribution wires, and
how many hours of operation on peak would be needed.
Figure 4-4: Load Duration Curves
Load Duration Curve
100
90
80
Typical Distribution System
Load (% of Max. Peak)
70
Suburban/Non-Industrial Feeder
60
50
40
30
20
10
0
0
10
20
30
40
50
60
70
80
90
100
Time (% of year)
These curves clearly illustrate the potential for DG as a peaking resource to defer or
avoid T&D capital investments. As the load grows past the capacity of the
distribution system to handle the peaks, small amounts of DG operating few hours
per year could “clip” the top of the curve by meeting applicants’ energy needs at the
point of use rather than relying on grid-delivered power. For either of the curves in
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Figure 4-4, and assuming that the peak feeder load is 10 MW, it would appear that 1
MW of distributed generation operating less than 100 hours per year would provide
relief for feeder line loads during times when the feeder is under its most severe
situations.
Capacity costs are quantified in terms of dollars per kilowatt per year ($/kW-yr).
Budgets for capacity upgrades can be translated into capacity costs by dividing the
budget dollars by the capacity in kW that those upgrades provide:
Capacity cost, $/kW-yr =
Budget $
(kW ) * (years)
The benefit is calculated by evaluating the present worth of the kW deferred. A
present worth calculation assumes a certain number of megawatts installed each
year, with costs discounted according to the estimated interest rate and referred
back to the present year.
Benefit, $/year = Present Worth {(kW of DG)*(capacity cost, $/kW-yr)*(# of years)}
Example Calculation
Consider the case in which transmission capacity planned for the next ten years is
1000 MW, at a budget of $200 million. Assume the capacity would be installed in
equal increments of 100 MW each year.
Installing 100 MW of DG this year can defer 100 MW of capacity for one year:
Capacity cost, $/kW-yr = ($200,000,000)/((1,000,000 kW)*(10 years))
= 20 $/kW-yr
Benefit ($) = (100,000 kW)*(20 $/kW-yr)*(1 year)
= $2,000,000
4.3.1.2.
Utilization Of Existing Transmission and Distribution Assets
While section 4.3.1.1. Deferral of Capital Expenditures pertains to financial and/or
capital assets, 4.3.1.2. addresses the utilization of the physical assets in a power
system. If DG is used to serve peak load growth, the load duration curve will
“flatten” out; the existing distribution system will become loaded to a higher
percentage of its maximum capability more of the time, and become more fully
utilized.
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In general, the closer to the load distributed generation can be located, the greater
the asset utilization benefits are possible.
DG located on the distribution
system―whether by the utility, a third party working with the utility, or a customer
placing DG on his premises―can reduce the need for both transmission and
distribution upgrades and will likewise increase the utilization of these assets. A
utility can use this knowledge to conduct a strategic review of its T&D system and
identify key feeders and substations with fast-growing load or poor utilization that
would benefit from DG deployment.
4.3.1.3.
Distribution System Reliability
Distributed generation can have a positive impact on system and local distribution
reliability. For a TDU the primary economic impact of poor reliability is increased
expenditures for emergency maintenance. An analysis of applicant loads and local
reliability data would allow a TDU to identify locations where DG could have the best
impact on reliability improvement. In Texas, TDUs cannot own or operate DG, but
they can work strategically with energy service companies, vendors and customers
to contract for DG in places where reliability enhancement is desired.
Qualitative distributed generation reliability benefits include faster restoration times,
and improved feeder reliability due to reduced stress and overloading of feeder
equipment. Other hard-to quantify benefits include customer good will, customer
retention, and avoided damage claims and/or lawsuits.
4.3.1.4.
Risk Transfer
Regulators have assigned to the TDU the full responsibility for the safe and effective
delivery of power to all customers on its distribution system. It has the responsibility
to design and operate the distribution system to meet voltage and frequency limits
and power quality metrics set by the standard practices in the TDU. The advent of
customer-owned and -operated DG in the system adds complexity and uncertainty
to the operation of the distribution system, and shifts some of the responsibility for
power delivery from the utility to the DG-using customer.
Where a customer has installed DG, the TDU has four options regarding future
nearby wire upgrades:
1) Ignore the presence of the DG unit and invest in wires as if the DG did not exist
(implicitly discounting the unit’s peak load reduction impacts).
2) Include the likelihood that the unit will be on during feeder peak times (implicitly
anticipating that the unit will reduce feeder peak loads).
3) Establish formal agreements and incentives by contract with the DG owner to
encourage DG operations at peak and reduce the TDU’s responsibility for
delivery at peak to that customer.
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4) Account for the existence of any customer-owned DG on the distribution system
by planning to handle the composite, statistical net (of DG) customer loads on
feeders and substations.
Using approach 1), the TDU will continue to plan and finance “lumps” of distribution
capacity to accommodate the expected load growth over a specified planning
horizon. Not only is most of the new capacity not used in the early years of the
upgrade, but if the load does not grow as forecasted, the investment decision
becomes (retrospectively) a poor one. Not accounting for customer DG can lead to
over-investment in unneeded capacity.
Using approach 2), the utility will defer its own capital investment due to the capital
investment of the customer in the distributed generation unit. In essence the TDU
has chosen to “lean” on the customer’s DG. Note that the logic would be the same
in the case of the TDU requesting load reductions by some of the customers on the
feeder and trusting that the load reductions will be available during the distribution
system peak.
But the utility is also assuming that the DG will operate during critical peak times as
designed, for example with high availability and good power quality. If either of
these operational assumptions is false, especially during severe peak feeder load
periods the utility will have to shed customer load, risk physical damage to the wires,
or risk experiencing electrical parameters outside of normal specifications. In this
sense the utility has increased its risk in exchange for the right to lean on the
customer DG.
Assuming that the customer owning the DG has not been compensated for the
“leaning rights,” the customer is under no obligation to the TDU for failing to operate
the DG in the way anticipated by the TDU. Using approach 3), in which the utility
and the customer have signed a performance contract, the customer’s
compensation should be impacted by his failure to supply those services. A utility
that designs and builds to accommodate installed DG should also have contractual
assurance that the customer’s load is shed first if the DG is tripped off-line.
The magnitude of the savings from relying on customer-owned and -operated DG to
defer TDU investments can be substantial, essentially equivalent to a permanent
deferral of all anticipated reinforcements, including land acquisition, new substation
equipment, etc.
Approach 4) uses the measured loads on feeders for planning purposes, unadjusted
for known DG on the distribution feeder. Only a modest amount of risk is placed on
the TDU in this case. The DGs on the feeder are seen essentially as load reduction
and are smoothed out statistically. If multiple DGs are in place, their unreliability is
probably smoothed out also.
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An important case of very large benefit to the TDU is relying on the customer DG to
hedge the risk of planning for uncertain “block” loads. These are loads that
represent a significant quantum increase in feeder load in a single year, such as a
commercial or industrial facility coming on-line. If the load is delayed or fails to
materialize as planned, any investments the utility may have made in wires
upgrades to accommodate the load will become negative financial impacts. Using
DG to hedge such load growth uncertainty can be very valuable.
4.3.1.5.
TDU Costs of Accommodating DG
The TDU’s accommodation of customer DG will have some adverse impacts on the
TDU:
•
The TDU pays for needed hardware upgrades (e.g., DG-compatible breakers,
reverse power relays, sensors, instrumentation, communication devices and/or
meters) to the distribution system to accommodate DG (to the extent that the
costs for such upgrades are allocated to the TDU and not the customers).
•
To the extent that the TDU relies on the DG to support the grid, the TDU
assumes additional risk, since the DG may not be as reliable as the wires
investments it displaced or deferred.
•
The TDU must pay for some engineering staff time and study costs.
•
The TDU must provide training to its staff to anticipate and understand the
implications of customer-owned and -operated DG.
However, most of these costs are no different than the costs of planning, owning
and operating a T&D system with full risk and responsibility for high-reliability electric
distribution service.
4.3.2. Customer Benefits and Costs
4.3.2.1.
Bill Reduction: Avoided Energy Costs and Demand Charges
A customer’s bill consists of two categories of charges ― energy and demand.
Energy is the commodity purchased from the utility or retail electric provider (REP),
and is measured in kilowatt-hours (kWh). The price per kWh charged may be higher
the more energy is used; e.g., one price can be charged for up to (say) 1,000 kWh,
and a higher price for every kWh above that threshold. Energy can also be more
expensive during certain times, such as system peaks; this is called time-of-use
(TOU) pricing.
Peaking energy prices can be high at certain times in today’s market. When system
peaks occur, if supplies are tight, spot energy prices can skyrocket, although they
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may be subject to caps by regulation or ISO rules. DG can represent insurance
against risk of high energy prices and a means of energy price management.
Demand charges (for commercial and industrial customers) are fixed monthly
charges based on the highest instantaneous load the customer may have during the
month, although the specific terms may vary under different customer contracts or
tariffs. For example, if the customer’s peak load is 10 kW, even if it’s only for one
hour, he is charged a monthly fee based on that 10 kW. Thus, by producing power
at peak times, a DG can help a customer reduce both energy and demand charges.
Peak periods may total a relatively few hours per month, but may represent a
significant percentage of a customer’s total bill.
In order to justify using a DG in baseload operation, a careful analysis of the
customer’s processes and economics is needed. Low-cost fuel must be available,
allowing the customer to produce power for a lower cost than the REP would charge.
DGs suitable for baseload use tend to be more efficient and require generally lower
O&M than peaking units. Using combined heat and power (CHP, also known as
cogeneration, in which the customer produces electric energy from a DG but also
utilizes waste heat from the generator for industrial processes, space or water
heating, or other uses) typically increases overall economic efficiency substantially,
increasing the probability that baseload DG operation will be economic for the
customer.
Calculation of the estimated cost savings from a DG is relatively straightforward. A
review of the energy consumption and demand charges recorded on the customer’s
recent billing statements will reveal how much energy is used during which time
periods, and what the costs are. DG size is matched to the peak load reduction
desired, or the full customer load if baseload operation is desired, and hours of
operation are determined. Total monthly costs are computed, consisting of all fixed
and variable costs of running the DG in the desired mode plus energy and demand
charges for whatever portion of customer requirements are not met by the DG. The
cost of the DG itself must also be included, using suitable financial parameters. The
difference between the no-DG situation and the with-DG case is the projected cost
savings of using the DG.
The cost of energy, whether purchased from the utility or generated on-site, is the
product of power (in kW) times the number of hours of operation times the cost per
kilowatt-hour:
Energy cost = (kW)*(hours)*($/kWh)
Both power level and energy cost are variable with time. Typically, energy costs are
computed on an hourly basis, summing the results to a monthly total. Energy cost
savings due to DG use would be computed by first calculating total energy costs the
customer would have paid absent the DG, and subtracting the total energy costs
paid with the DG.
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The demand charge from the utility is the product of the customer’s peak power
demand during the month (in kW) times the monthly charge per kW of peak demand:
Demand charge, per month = (peak kW)*($/kW/month)
The demand charge savings due to using a DG for peak reduction is the product of
the customer’s peak power demand reduction (equal to the size of the DG) times the
charge per kilowatt-hour:
Demand charge savings, per month = (kW of DG)*($/kW/month)
Example Calculation
Consider the case where:
• The utility charges 3¢/kWh off-peak, and 12¢/kWh on-peak.
• Utility demand charges are $10/kW/month.
• The customer’s load is 2000 kW during peak periods, for 6 hours/day, 20
days per month; all other times the load is 1000 kW.
• The customer owns a 1000 kW gas turbine that operates at a cost of
6¢/kWh, inclusive of fuel and all O&M.
The customer operates the gas turbine to cut load during peak periods; the
customer generates 1000 kW and buys 1000 kW from the utility. (Off-peak utility
usage won’t change, since it’s cheaper to buy than generate during off-peak.)
For peak periods, on a per-month basis:
Energy cost, no DG = (2000 kW)*(6 hrs/day)*(20 days/month)*(12 ¢/kWh)
= $28,800/month
Energy cost, with DG = (1000 kW)*(6 hrs/day)*(20 days/month)*(12 ¢/kWh) +
(1000 kW)*(6 hrs/day)*(20 days/month)*(6 ¢/kWh)
= ($14,400 + $7,200) per month
=$21,600 per month
Energy cost savings = $28,800 – $21,600 per month
=$7,200 per month
Demand charge savings = (1000 kW)*(10 $/kW/month)
= $10,000 per month
The customer’s total savings = $17,200 per month
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4.3.2.2.
On-Site Reliability
To serve critical loads during sustained TDU outages, a customer would use a DG
capable of being started up in a matter of minutes, and operated for the duration of
the outage. The cost of purchasing, maintaining and operating a DG for reliability
enhancement would need to be cost-justified based on the expected number and
duration of TDU outages and the estimated costs of those outages to the customer.
The customer’s “value of service” (VOS) will vary according to a customer’s
individual situation, and may be subjective to some degree. Residential customers
experience inconvenience, but usually do not suffer significant economic losses for
most outages, which normally last only a few minutes to a few hours. Research3 has
determined that residential VOS is valued in the vicinity of $1/kWh.
For commercial and industrial customers, the VOS can be much greater, depending
on the process that is interrupted. Product and equipment can be damaged,
revenue lost, and labor forces idled until power is restored. Research has estimated
the VOS for these customer classes to be in the range of $10 to $70 per kWh [Ibid.].
Note: Operating a DG to serve customer load when the TDU supply is interrupted
requires “islanded” operation, i.e., there is no live connection between the customer
and the TDU at the point of common coupling, and the DG operates only to serve
local load. Interconnection rules will specify the protection equipment that must be
installed to prevent the DG from reconnecting with the TDU until such time as TDU
service is restored.
Assuming that the costs to a DG owner are proportional to the length of the outage,
the value of service interruptions on a yearly basis can be calculated from the
following equation:
Benefit, $/year = (kW of load)*((SAIDI, min/yr)/60)*(VOS, $/kWh)
where: SAIDI for the feeder supplying the customer=system average interruption
duration index (minutes/year)
Alternatively, there may be fixed costs associated with an outage, regardless of the
length of the outage. In this case, the value is the fixed cost times the number of
times per year the interruption occurs:
Benefit, $/year = (SAIFI, outages/yr)*(FC, $/outage)
where: SAIFI for the feeder supplying the customer = system average interruption
frequency index (outages/year)
FC = fixed costs associated with a customer outage ($/outage)
3
Pupp, Roger and Woo, C.-K.: Costs of Service Disruptions to Electricity Customers, The Analysis
Group, Inc., January 1991.
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The total benefit to the customer may be a combination of these two values.
Example Calculation
Consider the case where:
Customer load = 1000 kW
SAIDI = 90 min/year
SAIFI = 1.25 outages/year
VOS = $50/kWh
FC = $5,000
For this situation, installing a DG that is capable of providing standby service
provides the DG owner an estimated yearly reliability benefit of:
Benefit, $/year = (1000 kW)*((90 min/yr)/60)* (50 $/kWh)
+ (1.25 outages/yr)*(5000 $/outage)
= ($75,000 + $6,250) per year
=$81,250 per year
4.3.2.3.
Power Quality Improvement
Power quality is related to reliability in some ways, and the potential solutions can be
similar to those for reliability. In general, power quality problems tend to be short in
duration and small in magnitude, but frequent or constant in occurrence. They may
include voltage sags or spikes, switching transients, harmonics (frequencies other
than 60 Hz), noise, and momentary outages (less than 5 minutes, according to the
definition in the IEEE Reliability Standard 1366; there is no similar standard for
power quality).
Customers can experience many of the same consequences from poor power
quality (PQ) as they would from poor reliability. For many industrial and commercial
customers a momentary outage is just as bad as a sustained outage, since
production processes or electronic equipment and records may be disrupted in
either case. If so, benefits may be computed according to the same value of service
principles as described in the previous section on reliability.
Resolving power quality issues can be difficult, since the problems may have their
origin in the TDU system, the customer’s own equipment, the equipment of other
customers on the feeder, or an interaction between any combination of these parties’
systems. The proliferation of solid-state electronics, in customer equipment as well
as TDU equipment, is frequently the source of many PQ anomalies.
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Since many PQ symptoms are low-energy or short-term phenomena, distributed
storage (e.g., batteries or flywheels) linked to the customer’s most sensitive loads
may be an economic solution, relative to the expense and effort of implementing a
DG system. A power conditioning system (power electronics-based converter
system) or an isolation transformer may be economical alternatives as well.
Whatever system is used, the basic approach is to interpose the system between
the customer and the TDU, so as to filter or smooth out PQ anomalies.
4.3.3. Other Benefits and Costs
This category of benefits and costs arising from installation and operation of DG
cannot, at this time, be directly allocated to any particular stakeholder or participant
in the Texas market. Before electric industry restructuring occurred, these impacts
would have been included in an integrated utility’s analysis of total benefit and cost
impacts of DG. In the current ongoing evolution of industry restructuring, it may be
worthwhile to analyze these impacts and evaluate how they may be allocated in the
future.
4.3.3.1.
Line Losses
When transmitting electric energy through TDU transmission and distribution
systems, the impedance (electrical resistance) of wires and transformers causes
resistive or “I2R” losses, where I is the current in the line in amperes (A) and R is its
resistance, in ohms (Ω). These losses are typically on the order of 4 to 7% systemwide; that is, about that much of the total energy generated is lost in transit from
generation sources to loads. This energy must be generated or purchased, just like
any other energy the TDU requires.
DG can reduce line losses by providing more of the supply locally, rather than
through transmission and distribution lines. This benefit is more likely to be
quantified on radial distribution lines than on networked distribution or transmission
lines. The reduction in line loading due to a distributed generator can be directly
seen on a distribution feeder, whereas the impact on a network is spread over
multiple lines.
If the system or TDU-specific average losses are known, then the average line loss
reduction can be calculated as a simple percentage of the DG capacity. In Texas,
this kind of data would need to be compiled from a combination of transmission data
(from the ISO), FERC filed data or other sources. If, for example, an average T&D
line loss figure is 7% (this is comparable to other T&D utilities nationwide), then
approximately 1.075 MW of energy input into the T&D system is required to serve
1.0 MW of actual load. Therefore, every 1 MW of DG can be considered to result in
an average benefit of 75 kW of avoided line losses during the time it operates. This
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approach takes advantage of known system characteristics to attribute total line loss
savings to a specified DG amount.
This reduction also has implications for capacity requirements. A 7.5% reduction in
energy losses from DG use at the point of customer load translates into that much
less generation, transmission and distribution capacity that would otherwise have to
be built to generate and transport that energy.
4.3.3.2.
Reserve Margin
Reserve margin is the amount of capacity cushion (denominated in MW) a power
region requires to be available to serve as a safety margin at extremely high load
times. This extra capacity allows the system generation controllers or operators to
dispatch plants with an additional surety that the system will not collapse if an
outage of a single transmission line or generating plant occurs. The reserve margin
takes into account the instantaneous status of all available generation and
transmission assets.
At this time, DG is not sufficiently proven or prevalent in the electric system to
warrant explicit and separate inclusion in reserve margin calculations. Once there is
a significant amount of DG installed and exporting into the Texas electric grid, and
concomitant experience with operating DG, future DG can be included in reserve
margin calculations. For now, customer load served by on-site DG is included in
calculations of reserve margin requirements, while the DG is not counted as a
generation resource.
Most system peak loads occur in only a relatively few hours per year (<300 or so).
Reserve margin plants do not usually have high efficiency or low emissions due to
their very low capacity factor. Customer units, such as standby generators which
are configured for remote dispatch on demand, might be excellent candidates for
consideration as reserve margin status and benefits. However, the PUCT will
include DG capacity in calculations of installed generation capacity for purposes of
market share calculations.
Small increments of DG can be added as the load grows, sized to accommodate the
amount of load that exceeds the capacity limit. This contrasts with typical capacity
additions that are usually large, “lumpy” capital investments. DG can therefore be
more cost-effective, flexible, and a less risky way to meet load growth.
If DG is connected to the transmission system it can displace the need for
incremental generation capacity, and may reduce transmission line losses.
Reserve margin capacity costs are quantified in terms of dollars per kilowatt per year
($/kW-yr), and can apply to generation and/or transmission capacity. The benefit
due to DG installation is calculated by evaluating the present worth of the kW
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deferred. A present worth calculation assumes a certain number of megawatts
installed each year, referred back to the present year.
Benefit ($) = Present Worth {(# of kW)*( $/kW-yr)*(# of years)}
Example Calculation
Consider the case in which generation capacity planned for the next ten years is
1000 MW, at a budget of $500 million. Assume the capacity would be installed in
equal increments of 100 MW each year.
Installing 100 MW of DG this year can defer 100 MW of capacity for one year:
Capacity cost, $/kW-yr = ($500,000,000)/((1,000,000 kW)*(10 years))
= 50 $/kW-yr
Benefit ($) = (100,000 kW)*(50 $/kW-yr)*(1 year)
= $5,000,000
4.3.3.3.
Ancillary Services
Ancillary services comprise a number of valuable electrical attributes that are
required for the safe, reliable and efficient operation of a power system. Typically
provided by large central plants for reasons of economy and simplicity of operation,
several types of ancillary services can also be provided by distributed generators. In
fact, given that many DG technologies are nearly as efficient as new central
generation, they may actually be more efficient in delivering ancillary service,
especially when locational advantages are figured into the equation (as with line
losses). It is anticipated that there will be markets for ancillary services just as there
are for bulk generation; the buyer(s) of the services might be the generators, QSEs
or the ISO. Identification of beneficiaries and development of economic accounting
tools for ancillary services are key unresolved issues of utility restructuring.
Logistically, ancillary services could be procured from DGs that are directly
controlled and dispatched by a QSE or the ISO; that is, the DGs would have
communication and control equipment installed so that they could be monitored and
dispatched. Alternatively, the ISO could contract with DGs to operate at certain
times and with specified performance requirements, with economic penalties for
non-performance.
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Examples of ancillary services include:
Volt/var Control
DG can be used in lieu of capacitors or other devices to provide the reactive power
(kvar) needed to improve or control voltage profiles on distribution feeders, and to
generally improve overall system voltage. Capacity values of $/kvar should be
readily available from the TDU for each voltage level in the system, representing the
equipment cost of capacitors that the TDU would purchase for voltage correction.
Improvement in system voltage profile contributes to increased stability margin as
well, since the system is less susceptible to voltage collapse during contingencies.
Reliability Must Run (RMR)
DGs are located and operated in specific areas and for specific times to relieve
transmission constraints.
Spinning Reserve
The DG operates at reduced load, but ready to pick up additional load if another
generator (or generators) in a specified area are forced out of service.
Load Frequency Control
The DG acts as a “swing bus”: it adjusts its output to compensate for normal
variations in customer load, in order to keep system frequency constant.
Load Following
The DG “tracks” a particular load, i.e., it adjusts its output so that the load has
minimal effect on the rest of the system.
Scheduling And Unit Commitment
Large generating plants can be uneconomical to use for cycling duty or for reliabilitymust-run applications where the capacity needs are small or the number of hours of
operation are few. Using DGs can be more economical than committing a large
plant for these purposes.
Black Start Capability
After a TDU outage, a DG can bring up local loads (forming a “micro-grid”) and
eventually re-synchronize with the grid, lessening the difficulty of system restoration.
4.4.
Operational Protocols
The PUCT is working with the ERCOT ISO to develop operational protocols for DG
interconnection to parallel the technical protocols laid out in the Rule and the
Standard DG Interconnection Agreement. These protocols will cover matters such
as how to schedule DG deliveries from the generator to the TDU to the ISO (i.e.,
inadvertent energy versus dynamic scheduling), appropriate scheduling fees, and
the like. These decisions will ultimately be documented in an operational section of
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the Standard DG Interconnection Agreement, and will be discussed in this manual
when the policy decisions have been made.
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5. DG APPLICANT INFORMATION
Introduction
The Public Utility Commission of Texas (PUCT) has endeavored to make it easy for
customers to interconnect their distributed generation (DG) projects with the local TDU’s
electric distribution system. The interconnection rules developed by the PUCT are
intended to set forth the rights and responsibilities of both DG applicant and TDU.
The discussion below pertains to “distributed generation,” which is limited to ten (10)
MW at the point of interconnection, and the “utility distribution system” to which the DG
is interconnected is at a voltage of less than 60 kV.
Existing provisions of PURA address the issue of Exempt Wholesale Generators
(EWGs) and the tariffs that apply to them. Wholesale generators are in the business of
selling their power on the open market, to whomever wants to buy it. They are
registered with the PUCT and the Federal Energy Regulatory Commission (FERC) as
competitive players in the market, are generally exempt from regulation, and are able to
connect with the TDU transmission system (i.e., at ≥ the 60 kV level) at rates described
in the published tariffs (see PURA Sections §35.004, §35.005, §35.006 and §35.007,
and within ERCOT, PUCT Substantive Rules §25.191, §25.192, and §25.195). It is
anticipated that the vast majority of customers wishing to interconnect DG systems at
the distribution level will not fall into this category, and will in fact desire to connect at
the distribution level. Any applicant that is an Exempt Wholesale Generator should
clearly disclose such status on the application.
Texas law prohibits distribution companies (TDUs) and retail electric providers from
owning or operating distributed generation facilities. TDUs are allowed to contract for
DG from customers and other entities in instances where such DG services may
provide cost-effective benefits to the distribution system. The DG ownership and
structure options are described in Table 5-1.
5.1.
DG Applicant Rights and Responsibilities
A DG applicant has the right to interconnect DG projects with the electric utility system,
and electric utilities are obligated to interconnect the DG project (see PUCT Substantive
Rule §25.211(d)), subject to the requirements set forth in this Manual. A DG applicant
has the right to expect expeditious processing of the application by the host TDU, and to
receive supporting data from the TDU for any studies or additional equipment required
for interconnection. A DG applicant does not have the right to expect payment from the
TDU for energy generated by the customer’s DG project; it is the responsibility of the
DG owner to market the energy produced from the DG facility. The DG owner has the
right to sell the energy, through a Qualified Scheduling Entity (QSE), to any power
generation company or retail electric provider that agrees to buy it, after January 1,
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2002.
Table 5-1: DG Ownership and Structural Options
Customer Ownership
• Self-generation DG and storage
• Cost-effective EE, storage
• ESCO provision of DG, EE
• DG for grid export
TDU Contracting
(in lieu of ownership)
• T&D supplements
• DG location support - EE, DG dispatch
• Customer partnership DG, EE, storage (cofunding possibilities)
TDU Rebates & Incentives
• EE incentives
• TDU or ISO purchase (demand-responsive
bidding, interruptible rates, LM)
TDU Out-Sourcing
• Aggregation of demand reduction, DG
• ESCO/DG vendor places and operates DG
where wireco needs it
• Third-party EE programs
A DG applicant has the responsibility to pay for the reasonable costs of system studies.
A customer has the responsibility to make full disclosure of the DG project and its
operation to the TDU. A DG applicant also has the responsibility of ensuring that the
DG project meets all applicable national, state, and local construction and safety codes
(see §25.211(b)); that operation of DG does not cause undesirable effects on other
customers (see §25.211(c)); and that the necessary protection equipment is installed
and operated to protect both its equipment and the TDU’s system. If the DG applicant
does not fulfill these obligations, the host TDU need not interconnect, or it may
disconnect, the DG project.
5.2.
TDU Rights and Responsibilities
A TDU must respond to applications for interconnection expeditiously, within the time
periods specified in this Manual. A TDU has the right and responsibility to safeguard its
system, other customers, and the general public, subject to the PUCT’s rules, and must
show good cause why a DG application that satisfies the PUCT’s requirements should
not be interconnected to its system. A TDU does not have the right to unilaterally refuse
to connect a DG project. A TDU is under no obligation to purchase the energy from a
customer’s DG. A TDU is, however, required to assess and recognize the benefits of
adding DG to the distribution system during the application process (see PUCT Rule
§25.211(g)(1)(C)).
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A TDU is paid to link generation to customers and to deliver power between points; it
does not matter whether that power comes from central station generation at a remote
location or from DG at the customer’s site. All distribution users shall bear the costs of
interconnecting the DG, including distribution upgrades as needed. The TDUs recover
the costs of grid construction and maintenance through base rates.
If the TDU believes that although a specific DG application meets the PUCT’s technical
requirements for system safety and reliability, but the costs of reconfiguring the TDU
system to accommodate the new DG unit appear excessive, the TDU may seek
guidance from the PUCT before approving or denying the DG application. The TDU
should contact the PUC’s Electric Division staff at 512-936-7340 or by e-mail at
[email protected]
5.3.
Interconnection Process
The interconnection process consists of the following steps:
1. Filing of an application by the DG applicant with the TDU
2. TDU review of the application
3. Response specifying the requirements for further study, if needed, and the
technical requirements to interconnect
4. Approval of an agreement between the DG applicant and the TDU
5. Connection, testing and operation of the DG project
The interconnection process has been designed to specify the appropriate level of
review and the associated technical and equipment requirements for each DG project.
The intent is for small, low-impact DG projects to be reviewed quickly, the technical and
equipment requirements to be only as complex and expensive as required for safe
operation, and fees paid by the customer to be fair and justified. The larger the project
and the more complex the interconnection scheme, the higher the costs, both for
studying the interconnection scheme and for the necessary electrical equipment to
interconnect.
For example, consider the simplest case, with the following attributes: A customer
wishes to connect a pre-certified DG system smaller than 500 kW. A pre-certified
system is a known collection of components that has been tested and certified either by
the TDU or by a qualified third party (see PUCT rules §25.211(c)(12), §25.211(k), and
Section 4 of this Manual). The line to which interconnection is desired is a radial feeder
circuit, i.e., there is only one path from the interconnect point to the TDU’s distribution
substation (this is the most common situation). The DG will export either no power to
the TDU system at all, or less than 15% of the total load on the feeder. Also, it will add
no more than 25% of the short-circuit current on the feeder, as determined by the TDU’s
review of the application.
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In this example, no further interconnection study is required and the TDU may not
charge for one, and the equipment requirements are minimal and pre-specified for this
case (PUCT Rule §25.212(d, e)). The TDU is required to interconnect the DG within
four weeks of receipt of customer’s application.
In all other cases, a TDU may need to conduct an interconnection study, and may
charge the customer for the costs of the study. For example, a DG system that is not
pre-certified must be evaluated to ensure that the system will operate safely on the
TDU’s system. Larger DG systems can have significant impacts on the TDU system,
and this is the reason that a comparison of the DG size to the load on the existing
system is important. An estimate of the study costs must be provided to the customer
before the TDU performs the study. The study must be completed by the TDU in four
weeks for a radial connection, and six weeks for a network connection. Written results
must be presented to the customer, detailing the findings and including an estimate of
capital upgrades required, if any. These capital upgrades are the responsibility of the
customer, who must enter into a contract with the TDU to implement them. Section 4 of
this Manual gives a detailed explanation of this application process.
Connecting to a networked feeder system (one in which there are multiple paths from
the interconnect point to the distribution substation) poses more difficult questions of
equipment and system protection, requiring more detailed technical analysis. The study
may take no longer than six weeks, and a written report of TDU’s findings must be
supplied to the customer. Moreover, the TDU must take into account the benefits
realized from the DG project in addition to the costs incurred by it (see PUCT Rule
§25.211(g)(1)(C)).
In the case of a proposed network connection, additional guidelines apply. Inverterbased DG systems, and all DG systems that do not export power to the grid, will be
approved without further study, unless the total distributed generation on the feeder,
including the new facility, is more than 25% of total load on the network. Total load is
defined as the sum of all customer loads on the feeder. If the new DG application would
push total DG on the feeder over this 25% load limit, then the proposed DG facility will
be subject to interconnection studies that must be completed within six weeks.
A TDU can reject a DG project on a networked system if it can demonstrate valid
technical or safety reasons for denying the interconnection, but the TDU must make
good-faith efforts to resolve the issue with the customer. TDUs must make reasonable
efforts to accommodate DG projects that propose to export power on a networked
system. Such reasonable efforts should include alternate methods of interconnection
such as converting to radial service, if practical.
5.4.
Frequently Asked Questions (FAQs) About DG Interconnections
The detailed guidelines and requirements for interconnecting DG are set forth in
§25.211 and §25.212 of the PUCT’s rules, attached to this Manual. The following are
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frequently asked questions (FAQs) that address the basic aspects of getting a DG
project interconnected with the TDU. Consult the PUCT’s rules for any topics not
covered here. If you still have questions, call the PUCT’s Customer Protection Division
at 1-888-782-8477.
Q. What should I do first?
A. Collect as much information as you can on the DG system you intend to install. This
would include size, manufacturer, model, fuel, and electrical characteristics. Obtain
the application form and fill it out, describing the technical and business aspects of
your proposed project. The application should then be filed with the host TDU with
whose system you wish to interconnect.
Q. How can I find out whom to contact in the TDU about interconnecting my DG
unit?
A. Rule 25.211(l) requires that each TDU must designate a person or persons who will
serve as the TDU’s contact for all matters relating to DG interconnection. Contacts
as of November 1, 2000 are listed in Appendix A4. The TDU must provide
convenient access through its Internet site to the names, telephone numbers,
mailing addresses and e-mail addresses for its DG contact persons.
Q. What happens after my Application is filed?
A. The TDU will have its engineering staff evaluate your Application to decide whether
a pre-interconnection study is necessary. A lot depends on the specifics of your DG
project: how big it is, whether you will export to the grid, whether the interconnection
will be on a radial or a networked feeder, and so forth. Generally, the bigger the DG
and the more complex the TDU feeder situation is, the more study is required by the
TDU to determine the proper interconnection scheme and protective equipment that
may be needed. The TDU will tell you whether you can interconnect right away, or
whether a study is required.
Q. Are pre-interconnection studies always required?
A. No. If your DG system has been pre-certified (see §25.211(k)), is under 500 kW, will
not export an amount of power more than 15% of the total load on the feeder, and
the TDU determines it will not add more than 25% to the short-circuit potential on the
feeder, no study should be required. In addition, protective equipment will be
minimal and prespecified, and interconnection fees will be the minimum amount.
Q. If a study is needed, how much time will it take?
A. For connection to a radial TDU feeder, the PUCT’s rules require that the TDU
complete the study in four weeks. For connection to a network system, the technical
issues are more complex and the TDU has six weeks to complete the study. Most
distribution systems are radial construction, but networked systems do exist in some
areas, particularly in city centers.
Q. How much will it cost me to connect?
A. Each TDU has filed study fees for various ranges of DG capacity rating.
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Interconnection cost depends upon the size and characteristics of the DG unit you
choose to interconnect, how you intend to operate it (e.g., exporting energy into the
grid, as opposed to using all the energy on-site), whether the connection will be to a
radial or networked distribution system, and whether the unit will use pre-certified
equipment or not.
Q. What if the TDU doesn’t want to connect my DG project?
A. You have the right to connect to the TDU’s system, and the TDU is obligated to
connect you, with certain provisions: you must follow the procedures described in
this manual; and your DG facility must meet the technical requirements of §25.212 of
the PUCT’s rules. The TDU would have to document the technical or business
reasons for not granting your Application as filed, and is obligated to work with you
to resolve the situation to your mutual satisfaction.
Q. After I’m connected, can the TDU disconnect me without my consent?
A. The TDU can disconnect you only if: you have no interconnection agreement with
the TDU, or your agreement has expired or has been terminated; you have not
complied with the technical requirements of PUCT Substantive Rule §25.212; there
is a system emergency that requires disconnection; or maintenance or other
construction work on the TDU system requires it. Rule §25.212 spells out the
requirements for notice of disconnection and reconnection under such
circumstances.
Q. How are disputes resolved if the TDU and I disagree on what’s required?
A. Complaints relating to interconnection disputes are to be handled in an expeditious
manner, as provided by PUCT Rule §22.242. Complaints shall first be presented
informally, by telephone or letter, to the Electric Division, which shall attempt to
resolve complaints within 20 business days of the date of receipt of the complaint.
In certain cases (see Rule §22.242) the informal complaint process may be
bypassed and formal complaints filed directly with the Commission. The Electric
Division can be contacted at 512-936-7340, Fax: 512-936-7361, or in writing at
PUCT – Electric Division, Attention: Ed Ethridge, at the same address as below.
Unresolved complaints shall be presented to the PUCT at the next available Open
Meeting.
PUCT - Customer Protection Division
P. O. Box 13326
Austin, TX 78711-3326
1-888-782-8477
in Austin: 512-936-7120
TTY: 1-800-735-2988
Fax: 1-512-936-7003
E-mail: [email protected]
Web: http://www.puc.state.tx.us/ocp/complaints/complaint.cfm
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6. ENERGY EFFICIENCY AND CUSTOMER-OWNED RESOURCES
In Texas, as per Substantive Rule §25.181, renewable energy technologies installed for
self-generation which do not export to the grid are classified as energy efficiency
technologies rather than as DG units.
Substantive Rule §25.181(c)(25) defines renewable demand side management (DSM)
technologies as equipment that uses renewable energy resources to reduce a
customer’s net purchases of energy (kWh) and/or electrical demand (kW).
Rule §25.181(h)(4) provides that renewable energy technologies installed for selfgeneration do not disqualify a DG installation from receiving incentive payments or
compensation under standard offer or market incentive programs. See also Rule
§25.181(1)(2)(L), which specifically states that renewable DSM technologies are
allowed under standard offer programs for energy efficiency.
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7. PRE-CERTIFICATION PROCESS
Refer to Appendix A7 for the commission-approved Distributed Generation Precertification Requirements. The document explains what is meant by pre-certification
and the required tests by a nationally recognized testing laboratory (NRTL). Also, the
document describes optional tests and tests that must be performed for which there is
no standard to be met. References are made to the DG Rules, 25.211 and 25.212,
which are included in Appendix A2.
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8. INTERCONNECTION DISPUTES
PUCT Rule §22.242 provides that all complaints about utilities be presented to the office
of Customer Protection Division for informal resolution within 35 days. The CPD may
be contacted at the phone numbers and address given below. In certain cases the
informal complaint process may be bypassed (see the Rule for specifics) and formal
complaints filed directly with the Commission. Unresolved informal complaints and all
formal complaints shall be presented to the PUCT at the next available Open Meeting.
Rule §25.211 amends this procedure in the case of interconnection disputes. Informal
complaints are to be presented to the Electric Division, which shall attempt to resolve
complaints within 20 business days of the date of receipt of the complaint. The Electric
Division can be contacted at 512-936-7366, Fax: 512-936-7361, or in writing at PUCT –
Electric Division, Attention: Tony Marciano, at the same address as below.
Unresolved complaints shall be presented to the PUCT at the next available Open
Meeting.
PUCT - Customer Protection Division
P. O. Box 13326
Austin, TX 78711-3326
1-888-782-8477
in Austin: 512-936-7120
TTY: 1-800-735-2988
Fax: 1-512-936-7003
E-mail: [email protected]
Web: http://www.puc.state.tx.us/ocp/complaints/complaint.cfm
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Appendix A1: Definitions
The following words, terms and acronyms, when used in this Manual shall have the
following meanings, unless the context clearly indicates otherwise [Rule §25.211(c);
refer to IEEE Standard 100 for certain terms]:
Applicant — A customer or entity who intends to apply or has applied to an electric
utility for interconnection.
Application for Interconnection and Parallel Operation with the Utility System (or
Application) — The standard form of application for interconnection of distributed
generation projects approved by the Commission.
Closed Transition — A mode of operation in which the DG is operated in parallel with
the distribution system for a brief period of time, to ensure that the load is maintained
while from the utility (TDU) to the generator or vice versa.
Commission — The Public Utility Commission of Texas (PUCT).
Company — An electric utility operating a distribution system.
Customer — Any entity interconnected to the company's utility system for the purpose
of receiving or exporting electric power from or to the company's utility system.
DG — Distributed generation; see also On-Site Distributed Generation.
Distribution Feeder — An electric line operated at voltages below 60 kV that serves to
deliver power from a utility substation or other supply point to customers.
Electric Utility — A person or river authority that owns or operates equipment or
facilities to produce, generate, transmit, distribute, sell or furnish electricity for
compensation in the state of Texas; excluded from this definition are municipal
corporations, power generation companies, exempt wholesale generators, power
marketers, electric cooperatives and retail electric providers [PURA §31.002(6)].
Electric Reliability Council of Texas (ERCOT) — The area in Texas served by
electric utilities, municipally owned utilities, and electric cooperatives that is not
synchronously connected with electric utilities outside the state [PURA §31.002(5)].
Exempt Wholesale Generator (EWG) — A person who is engaged directly or
indirectly, through one or more affiliates, exclusively in the business of owning or
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operating a facility for generating electric energy and selling electric energy at
wholesale.
An EWG must register with the Commission [PURA §35.032 and
Substantive Rule 25.109] and with the FERC under 15 U.S.C. §79z-5a.
Facility — An electrical generating installation consisting of one or more on-site
distributed generation units. The total capacity of a facility's individual on-site distributed
generation units may exceed 10 MW; however, no more than 10 MW of a facility's
capacity will be interconnected at any point in time at the point of common coupling
under this section.
IEEE — The Institute of Electrical and Electronics Engineers.
Independent System Operator (ISO) — An entity, administered by ERCOT,
supervising the collective facilities of a power region; the ISO is charged with
nondiscriminatory coordination of market transactions, systemwide transmission
planning, and network reliability [PURA §31.002(9)].
Interconnection — The physical connection of distributed generation to the utility
system in accordance with the requirements of this section so that parallel operation
can occur.
Interconnection Agreement — The standard form of agreement, which has been
approved by the Commission. The interconnection agreement sets forth the contractual
conditions under which a utility and a customer agree that one or more facilities may be
interconnected with the utility's distribution system.
Inverter — A machine, device or system that changes direct-current power to
alternating-current power [IEEE Std. 100].
Inverter-based Protective Function — A function of an inverter system, carried out
using hardware and software, that is designed to prevent unsafe operating conditions
from occurring before, during, and after the interconnection of an inverter-based static
power converter unit with a utility system.
For purposes of this definition, unsafe
operating conditions are conditions that, if left uncorrected, would result in harm to
personnel, damage to equipment, unacceptable system instability or operation outside
legally established parameters affecting the quality of service to other customers
connected to the utility system.
kV — kilovolt, an amount of voltage equal to one thousand volts.
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kW — kilowatt, an amount of power equal to one thousand watts.
MW — megawatt, an amount of power equal to one million watts.
Network Service — Network service consists of two or more utility primary distribution
feeder sources electrically tied together on the secondary (or low voltage) side to form
one power source for one or more customers. The service is designed to maintain
service to the customers even after the loss of one of these primary distribution feeder
sources.
On-Site Distributed Generation (or Distributed Generation) — An electrical
generating facility located at a customer's point of delivery (point of common coupling)
of 10 MW or less and connected at a voltage less than 60 kV, which may be connected
in parallel operation to the utility system. May include energy storage technologies as
well as conventional generation technologies.
Parallel Operation — The operation of on-site distributed generation by a customer
while the customer is connected to the utility's distribution system.
Point Of Common Coupling (PCC) — The point where the electrical conductors of the
utility's distribution system are connected to the customer's conductors and where any
transfer of electric power between the customer and the utility system takes place, such
as switchgear near the meter [IEEE Std. 100].
Power Generation Company (PGC) — A person that generates electricity to be sold at
wholesale. A PGC does not own a transmission or distribution system and does not
have a prescribed service area, although it may be affiliated with an electric utility that
does [PURA §31.002(10)].
Pre-certified Equipment — A specific generating and protective equipment system or
systems that have been certified as meeting the applicable parts of this section relating
to safety and reliability by an entity approved by the commission.
Pre-interconnection Study — A study or studies that may be undertaken by a utility in
response to its receipt of a completed application for interconnection and parallel
operation with the utility system. Pre-interconnection studies may include, but are not
limited to, service studies, coordination studies and utility system impact studies.
PURA — The Public Utility Regulatory Act of 1999 (Texas).
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QSE — Qualified scheduling entity. A QSE is responsible for submitting Balanced
Schedules for transmission capacity for all entities for which it serves as a scheduling
agent.
The QSE is responsible for payment of settlement charges as set forth in
Section 9 of the ERCOT Protocols Document.
Each QSE shall maintain a 24-7
scheduling center for the purposes of communicating with the ISO for scheduling and
Real Time operational purposes and is required to install and maintain communications
and telemetry capability as prescribed by ERCOT.
Radial Service — Radial service consists of one utility primary distribution feeder
source forming a single power source for one or more customers.
Retail Electric Provider (REP) — A person that sells electric energy to retail customers
in Texas. A retail electric provider may not own or operate generation assets [PURA
§31.002(17)].
Stabilized — A utility system is considered stabilized when, following a disturbance, the
system returns to the normal range of voltage and frequency for a duration of two
minutes or a shorter time as mutually agreed to by the utility and customer.
Switchgear — An enclosed metal assembly containing components for switching,
protecting, monitoring and controlling electric power systems [IEEE Std. 100].
Tariff For Interconnection And Parallel Operation Of Distributed Generation —
The Commission-approved tariff for interconnection and parallel operation of distributed
generation including the application for interconnection and parallel operation of DG and
pre-interconnection study fee schedule.
Transmission and Distribution Utility (TDU) — A person or river authority that owns
or operates equipment or facilities to transmit or distribute electricity for compensation in
Texas, except for facilities necessary to interconnect a generation facility with the
transmission or distribution network, a facility not dedicated to public use, or a facility
otherwise excluded from the definition of "electric utility" under this section, in a
qualifying power region certified under PURA §39.152, but does not include a
municipally owned utility or an electric cooperative [PURA §31.002(19)].
Total Load — The sum of all customer loads on a distribution feeder.
Unit — A power generator.
Utility System — A utility's distribution system below 60 kV to which the generation
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equipment is interconnected.
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Appendix A2: Copy of PUCT’s Rules, Forms and PURA 99
Excerpts
PUCT Rules §25.211 and §25.212
§25.211.
Interconnection of On-Site Distributed Generation (DG).
(a)
Application. Unless the context clearly indicates otherwise, in this section and §25.212 of this title
(relating to Technical Requirements for Interconnection and Parallel Operation of On-Site Distributed
Generation) the term "electric utility" applies to all electric utilities as defined in the Public Utility
Regulatory Act (PURA) §31.002 that own and operate a distribution system in Texas. This section shall
not apply to an electric utility subject to PURA §39.102(c) until the expiration of the utility's rate freeze
period.
(b)
Purpose. The purpose of this section is to clearly state the terms and conditions that govern the
interconnection and parallel operation of on-site distributed generation in order to implement PURA
§39.101(b)(3), which entitles all Texas electric customers to access to on-site distributed generation, to
provide cost savings and reliability benefits to customers, to establish technical requirements that will
promote the safe and reliable parallel operation of on-site distributed generation resources, to enhance both
the reliability of electric service and economic efficiency in the production and consumption of electricity,
and to promote the use of distributed resources in order to provide electric system benefits during periods
of capacity constraints. Sales of power by a distributed generator in the wholesale market are subject to the
provisions of this title relating to open-access comparable transmission service for electric utilities in the
Electric Reliability Council of Texas (ERCOT).
(c)
Definitions. The following words and terms when used in this section and §25.212 of this title shall have
the following meanings, unless the context clearly indicates otherwise:
(1) Application for interconnection and parallel operation with the utility system or application —
The standard form of application approved by the commission.
(2) Banking — A method of accounting for energy produced by a customer for export into the
distribution system. The host control area accepts energy from the customer to meet its own energy
needs during a five- to 30-day period, credits this energy to the customer's account, and subsequently
produces and, in the five- to 30-day period immediately following acceptance of the energy, disburses
the energy accrued under the customer's account to the receiving control area specified by the
customer. Disbursement of the accrued energy shall follow a pre-arranged schedule mutually
acceptable to the host control area, the receiving control area, and the DG customer. Such schedule
shall attempt to keep the host control area neutral with respect to the market value of the energy
transferred on behalf of the exporting customer.
(3) Company — An electric utility operating a distribution system.
(4) Customer — Any entity interconnected to the company's utility system for the purpose of receiving
or exporting electric power from or to the company's utility system.
(5) Facility — An electrical generating installation consisting of one or more on-site distributed
generation units. The total capacity of a facility's individual on-site distributed generation units may
exceed ten megawatts (MW); however, no more than ten MW of a facility's capacity will be
interconnected at any point in time at the point of common coupling under this section.
(6) Interconnection — The physical connection of distributed generation to the utility system in
accordance with the requirements of this section so that parallel operation can occur.
(7) Interconnection agreement — The standard form of agreement, which has been approved by the
commission. The interconnection agreement sets forth the contractual conditions under which a
company and a customer agree that one or more facilities may be interconnected with the company's
utility system.
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§25.211(c) continued
(8)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
(17)
(18)
(d)
Inverter-based protective function — A function of an inverter system, carried out using hardware
and software, that is designed to prevent unsafe operating conditions from occurring before, during,
and after the interconnection of an inverter-based static power converter unit with a utility system.
For purposes of this definition, unsafe operating conditions are conditions that, if left uncorrected,
would result in harm to personnel, damage to equipment, unacceptable system instability or operation
outside legally established parameters affecting the quality of service to other customers connected to
the utility system.
Network service — Network service consists of two or more utility primary distribution feeder
sources electrically tied together on the secondary (or low voltage) side to form one power source for
one or more customers. The service is designed to maintain service to the customers even after the
loss of one of these primary distribution feeder sources.
On-site distributed generation (or distributed generation) — An electrical generating facility
located at a customer's point of delivery (point of common coupling) of ten megawatts (MW) or less
and connected at a voltage less than 60 kilovolts (kV) which may be connected in parallel operation
to the utility system.
Parallel operation — The operation of on-site distributed generation by a customer while the
customer is connected to the company's utility system.
Point of common coupling — The point where the electrical conductors of the company utility
system are connected to the customer's conductors and where any transfer of electric power between
the customer and the utility system takes place, such as switchgear near the meter.
Pre-certified equipment — A specific generating and protective equipment system or systems that
have been certified as meeting the applicable parts of this section relating to safety and reliability by
an entity approved by the commission.
Pre-interconnection study — A study or studies that may be undertaken by a company in response
to its receipt of a completed application for interconnection and parallel operation with the utility
system. Pre-interconnection studies may include, but are not limited to, service studies, coordination
studies and utility system impact studies.
Stabilized — A company utility system is considered stabilized when, following a disturbance, the
system returns to the normal range of voltage and frequency for a duration of two minutes or a shorter
time as mutually agreed to by the company and customer.
Tariff for interconnection and parallel operation of distributed generation — The commissionapproved tariff for interconnection and parallel operation of distributed generation including the
application for interconnection and parallel operation of DG and pre-interconnection study fee
schedule.
Unit — A power generator.
Utility system — A company's distribution system below 60 kV to which the generation equipment is
interconnected.
Terms of Service.
(1) Banking. A company operating in ERCOT shall make banking services available to any customer
upon the customer's request. This obligation continues until the ERCOT Independent System
Operator begins operating ERCOT as a single control area.
(2) Distribution line charge. No distribution line charge shall be assessed to a customer for exporting
energy to the utility system.
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§25.211(d) continued
(3)
(4)
(5)
(6)
(7)
(e)
Interconnection operations and maintenance costs. No charge for operation and maintenance of a
utility system's facilities shall be assessed against a customer for exporting energy to the utility
system.
Scheduling fees. A one-time scheduling fee for each banking period may be assessed for the
disbursement of banked energy. No other scheduling fees may be assessed against an exporting DG
customer.
Transmission charges. No transmission charges shall be assessed to a customer for exporting
energy. For purposes of this paragraph, the term transmission charges means transmission access and
line charges, transformation charges, and transmission line loss charges.
Contract reformation. All interconnection contracts shall be conformed to meet the requirements of
this section within 60 days of adoption.
Tariffs. No later than 30 days after the effective date of this section as amended, each electric utility
shall file a tariff or tariffs for interconnection and parallel operation of distributed generation,
including tariffs for banking and scheduling fees, in conformance with the provisions of this section.
This provision does not require a utility that filed an interconnection study fee tariff prior to the
effective date of this rule as amended to refile such tariff. The utility may file a new tariff or a
modification of an existing tariff. Such tariffs shall ensure that back-up, supplemental, and
maintenance power is available to all customers and customer classes that desire such service until
January 1, 2002. Any modifications of existing tariffs or offerings of new tariffs relating to this
subsection shall be consistent with the commission-approved form. Concurrent with the tariff filing
in this section, each utility shall submit:
(A) a schedule detailing the charges of interconnection studies and all supporting cost data for the
charges;
(B) a standard application for interconnection and parallel operation of distributed generation; and
(C) the interconnection agreement approved by the commission.
Disconnection and reconnection. A utility may disconnect a distributed generation unit from the utility
system under the following conditions:
(1) Expiration or termination of interconnection agreement. The interconnection agreement specifies
the effective term and termination rights of company and customer. Upon expiration or termination
of the interconnection agreement with a customer, in accordance with the terms of the agreement, the
utility may disconnect customer's facilities.
(2) Non-compliance with the technical requirements specified in §25.212 of this title. A utility may
disconnect a distributed generation facility if the facility is not in compliance with the technical
requirements specified in §25.212 of this title. Within two business days from the time the customer
notifies the utility that the facility has been restored to compliance with the technical requirements of
§25.212 of this title, the utility shall have an inspector verify such compliance. Upon such
verification, the customer in coordination with the utility may reconnect the facility.
(3) System emergency. A utility may temporarily disconnect a customer's facility without prior written
notice in cases where continued interconnection will endanger persons or property. During the forced
outage of a utility system, the utility shall have the right to temporarily disconnect a customer's
facility to make immediate repairs on the utility's system. When possible, the utility shall provide the
customer with reasonable notice and reconnect the customer as quickly as reasonably practical.
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§25.211(e) continued
(4)
(5)
Routine maintenance, repairs, and modifications. A utility may disconnect a customer or a
customer's facility with seven business days prior written notice of a service interruption for routine
maintenance, repairs, and utility system modifications. The utility shall reconnect the customer as
quickly as reasonably possible following any such service interruption.
Lack of approved application and interconnection agreement. In order to interconnect distributed
generation to a utility system, a customer must first submit to the utility an application for
interconnection and parallel operation with the utility system and execute an interconnection
agreement on the forms prescribed by the commission. The utility may refuse to connect or may
disconnect the customer's facility if such application has not been received and approved.
(f)
Incremental demand charges. During the term of an interconnection agreement a utility may require that
a customer disconnect its distributed generation unit and/or take it off-line as a result of utility system
conditions described in subsection (e)(3) and (4) of this section. Incremental demand charges arising from
disconnecting the distributed generator as directed by company during such periods shall not be assessed by
company to the customer. After January 1, 2002, the distribution utility shall not be responsible for the
provision of generation services or their related charges.
(g)
Pre-interconnection studies for non-network interconnection of distributed generation. A utility may
conduct a service study, coordination study or utility system impact study prior to interconnection of a
distributed generation facility. In instances where such studies are deemed necessary, the scope of such
studies shall be based on the characteristics of the particular distributed generation facility to be
interconnected and the utility's system at the specific proposed location. By agreement between the utility
and its customer, studies related to interconnection of DG on the customer's premise may be conducted by a
qualified third party.
(1) Distributed generation facilities for which no pre-interconnection study fees may be charged. A
utility may not charge a customer a fee to conduct a pre-interconnection study for pre-certified
distributed generation units up to 500 kW that export not more than 15% of the total load on a single
radial feeder and contribute not more than 25% of the maximum potential short circuit current on a
single radial feeder.
(2) Distributed generation facilities for which pre-interconnection study fees may be charged. Prior
to the interconnection of a distributed generation facility not described in paragraph (1) of this
subsection, a utility may charge a customer a fee to offset its costs incurred in the conduct of a preinterconnection study. In those instances where a utility conducts an interconnection study the
following shall apply:
(A) The conduct of such pre-interconnection study shall take no more than four weeks;
(B) A utility shall prepare written reports of the study findings and make them available to the
customer;
(C) The study shall consider both the costs incurred and the benefits realized as a result of the
interconnection of distributed generation to the company's utility system; and
(D) The customer shall receive an estimate of the study cost before the utility initiates the study.
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(h)
Network interconnection of distributed generation. Certain aspects of secondary network systems
create technical difficulties that may make interconnection more costly to implement. In instances where
customers request interconnection to a secondary network system, the utility and the customer shall use
best reasonable efforts to complete the interconnection and the utility shall utilize the following guidelines:
(1) A utility shall approve applications for distributed generation facilities that use inverter-based
protective functions unless total distributed generation (including the new facility) on affected feeders
represents more than 25% of the total load of the secondary network under consideration.
(2) A utility shall approve applications for other on-site generation facilities whose total generation is less
than the local customer's load unless total distributed generation (including the new facility) on
affected feeders represents more than 25% of the total load of the secondary network under
consideration.
(3) A utility may postpone processing an application for an individual distributed generation facility
under this section if the total existing distributed generation on the targeted feeder represents more
than 25% of the total load of the secondary network under consideration. If that is the case, the utility
should conduct interconnection and network studies to determine whether, and in what amount,
additional distributed generation facilities can be safely added to the feeder or accommodated in some
other fashion. These studies should be completed within six weeks, and application processing
should then resume.
(4) A utility may reject applications for a distributed generation facility under this section if the utility
can demonstrate specific reliability or safety reasons why the distributed generation should not be
interconnected at the requested site. However, in such cases the utility shall work with the customer
to attempt to resolve such problems to their mutual satisfaction.
(5) A utility shall make all reasonable efforts to seek methods to safely and reliably interconnect
distributed generation facilities that will export power. This may include switching service to a radial
feed if practical and if acceptable to the customer.
(i)
Pre-Interconnection studies for network interconnection of distributed generation. Prior to charging a
pre-interconnection study fee for a network interconnection of distributed generation, a utility shall first
advise the customer of the potential problems associated with interconnection of distributed generation with
its network system. For potential interconnections to network systems there shall be no pre-interconnection
study fee assessed for a facility with inverter systems under 20 kW. For all other facilities the utility may
charge the customer a fee to offset its costs incurred in the conduct of the pre-interconnection study. In
those instances where a utility conducts an interconnection study, the following shall apply:
(1) The conduct of such pre-interconnection studies shall take no more than four weeks;
(2) A utility shall prepare written reports of the study findings and make them available to the customer;
(3) The studies shall consider both the costs incurred and the benefits realized as a result of the
interconnection of distributed generation to the utility's system; and
(4) The customer shall receive an estimate of the study cost before the utility initiates the study.
(j)
Communications concerning proposed distributed generation projects. In the course of processing
applications for interconnection and parallel operation and in the conduct of pre-interconnection studies,
customers shall provide the utility detailed information concerning proposed distributed generation
facilities.
Such
communications
concerning
the
nature
of
proposed
distributed
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§25.211(j) continued
generation facilities shall be made subject to the terms of §25.84 of this title (Relating to Annual Reporting
of Affiliate Transactions for Electric Utilities), §25.272 of this title (Relating to Code of Conduct for
Electric Utilities and their Affiliates), and §25.273 (Relating to Contracts between Electric Utilities and
their Competitive Affiliates). A utility and its affiliates shall not use such knowledge of proposed
distributed generation projects submitted to it for interconnection or study to prepare competing proposals
to the customer that offer either discounted rates in return for not installing the distributed generation, or
offer competing distributed generation projects.
(k)
Equipment pre-certification.
(1) Entities performing pre-certification. The commission may approve one or more entities that shall
pre-certify equipment as defined pursuant to this section.
(2) Standards for entities performing pre-certification. Testing organizations and/or facilities capable
of analyzing the function, control, and protective systems of distributed generation units may request
to be certified as testing organizations.
(3) Effect of pre-certification. Distributed generation units which are certified to be in compliance by
an approved testing facility or organization as described in this subsection shall be installed on a
company utility system in accordance with an approved interconnection control and protection
scheme without further review of their design by the utility.
(l)
Designation of utility contact persons for matters relating to distributed generation interconnection.
(1) Each electric utility shall designate a person or persons who will serve as the utility's contact for all
matters related to distributed generation interconnection.
(2) Each electric utility shall identify to the commission its distributed generation contact person.
(3) Each electric utility shall provide convenient access through its internet web site to the names,
telephone numbers, mailing addresses and electronic mail addresses for its distributed generation
contact person.
(m) Time periods for processing applications for interconnection with the utility system. In order to apply
for interconnection the customer shall provide the utility a completed application for interconnection and
parallel operation with the utility system. The interconnection of distributed generation to the utility
system shall take place within the following schedule:
(1) For a facility with pre-certified equipment, interconnection shall take place within four weeks of the
utility's receipt of a completed interconnection application.
(2) For other facilities, interconnection shall take place within six weeks of the utility's receipt of a
completed application.
(3) If interconnection of a particular facility will require substantial capital upgrades to the utility system,
the company shall provide the customer an estimate of the schedule and customer's cost for the
upgrade. If the customer desires to proceed with the upgrade, the customer and the company will
enter into a contract for the completion of the upgrade. The interconnection shall take place no later
than two weeks following the completion of such upgrades. The utility shall employ best reasonable
efforts to complete such system upgrades in the shortest time reasonably practical.
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§25.211(m) continued
(4)
(5)
A utility shall use best reasonable efforts to interconnect facilities within the time frames described in
this subsection. If in a particular instance, a utility determines that it can not interconnect a facility
within the time frames stated in this subsection, it will notify the applicant in writing of that fact. The
notification will identify the reason or reasons interconnection could not be performed in accordance
with the schedule and provide an estimated date for interconnection.
All applications for interconnection and parallel operation of distributed generation shall be processed
by the utility in a non-discriminatory manner. Applications will be processed in the order that they
are received. It is recognized that certain applications may require minor modifications while they are
being reviewed by the utility. Such minor modifications to a pending application shall not require
that it be considered incomplete and treated as a new or separate application.
(n)
Reporting requirements. Each electric utility shall maintain records concerning applications received for
interconnection and parallel operation of distributed generation. Such records will include the date each
application is received, documents generated in the course of processing each application, correspondence
regarding each application, and the final disposition of each application. By March 30 of each year, every
electric utility shall file with the commission a distributed generation interconnection report for the
preceding calendar year that identifies each distributed generation facility interconnected with the utility's
distribution system. The report shall list the new distributed generation facilities interconnected with the
system since the previous year' report, any distributed generation facilities no longer interconnected with
the utility's system since the previous report, the capacity of each facility, and the feeder or other point on
the company's utility system where the facility is connected. The annual report shall also identify all
applications for interconnection received during the previous one-year period, and the disposition of such
applications.
(o)
Interconnection disputes. Complaints relating to interconnection disputes under this section shall be
handled in an expeditious manner pursuant to §22.242 (relating to Complaints). In instances where
informal dispute resolution is sought, complaints shall be presented to the Electric Division. The Electric
Division shall attempt to informally resolve complaints within 20 business days of the date of receipt of the
complaint. Unresolved complaints shall be presented to the commission at the next available open meeting.
§25.212.
Technical Requirements for Interconnection and Parallel Operation of On-Site Distributed
Generation.
(a)
Purpose. The purpose of this section is to describe the requirements and procedures for safe and effective
connection and operation of distributed generation.
(1) A customer may operate 60 Hertz (Hz), three-phase or single-phase generating equipment, whether
qualifying facility (QF) or non-QF, in parallel with the utility system pursuant to an interconnection
agreement, provided that the equipment meets or exceeds the requirements of this section.
(2) This section describes typical interconnection requirements. Certain specific interconnection
locations and conditions may require the installation and use of more sophisticated protective devices
and operating schemes, especially when the facility is exporting power to the utility system.
(3) If the utility concludes that an application for parallel operation describes facilities that may require
additional devices and operating schemes, the utility shall make those additional requirements known
to the customer at the time the interconnection studies are completed.
(4) Where the application of the technical requirements set forth in this section appears inappropriate for
a specific facility, the customer and utility may agree to different requirements, or a party may
petition the commission for a good cause exception, after making every reasonable effort to resolve
all issues between the parties.
(b)
General interconnection and protection requirements.
(1) The customer's generation and interconnection installation must meet all applicable national, state,
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§25.212(b) continued
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(c)
and local construction and safety codes.
The customer's generator shall be equipped with protective hardware and software designed to
prevent the generator from being connected to a de-energized circuit owned by the utility.
The customer's generator shall be equipped with the necessary protective hardware and software
designed to prevent connection or parallel operation of the generating equipment with the utility
system unless the utility system service voltage and frequency is of normal magnitude.
Pre-certified equipment may be installed on a company's utility systems in accordance with an
approved interconnection control and protection scheme without further review of their design by the
utility. When the customer is exporting to the utility system using pre-certified equipment, the
protective settings and operations shall be those specified by the utility.
The customer will be responsible for protecting its generating equipment in such a manner that utility
system outages, short circuits or other disturbances including zero sequence currents and
ferroresonant over-voltages do not damage the customer's generating equipment. The customer's
protective equipment shall also prevent unnecessary tripping of the utility system breakers that would
affect the utility system's capability of providing reliable service to other customers.
For facilities greater than two megawatts (MW), the utility may require that a communication channel
be provided by the customer to provide communication between the utility and the customer's facility.
The channel may be a leased telephone circuit, power line carrier, pilot wire circuit, microwave, or
other mutually agreed upon medium.
Circuit breakers or other interrupting devices at the point of common coupling must be capable of
interrupting maximum available fault current. Facilities larger than two MW and exporting to the
utility system shall have a redundant circuit breaker unless a listed device suitable for the rated
application is used.
The customer will furnish and install a manual disconnect device that has a visual break that is
appropriate to the voltage level (a disconnect switch, a draw-out breaker, or fuse block), and is
accessible to the utility personnel, and capable of being locked in the open position. The customer
shall follow the utility's switching, clearance, tagging, and locking procedures, which the utility shall
provide for the customer.
Prevention of interference. To eliminate undesirable interference caused by operation of the customer's
generating equipment, the customer's generator shall meet the following criteria:
(1) Voltage. The customer will operate its generating equipment in such a manner that the voltage levels
on the utility system are in the same range as if the generating equipment were not connected to the
utility's system. The customer shall provide an automatic method of disconnecting the generating
equipment from the utility system if a sustained voltage deviation in excess of +5.0 % or –10% from
nominal voltage persists for more than 30 seconds, or a deviation in excess of +10% or –30% from
nominal voltage persists for more than ten cycles. The customer may reconnect when the utility
system voltage and frequency return to normal range and the system is stabilized.
(2) Flicker. The customer's equipment shall not cause excessive voltage flicker on the utility system.
This flicker shall not exceed 3.0% voltage dip, in accordance with Institute of Electrical and
Electronics Engineers (IEEE) 519 as measured at the point of common coupling.
(3) Frequency. The operating frequency of the customer's generating equipment shall not deviate more
than +0.5 Hertz (Hz) or –0.7 Hz from a 60 Hz base. The customer shall automatically disconnect the
generating equipment from the utility system within 15 cycles if this frequency tolerance cannot be
maintained. The customer may reconnect when the utility system voltage and frequency return to
normal range and the system is stabilized.
(4) Harmonics. In accordance with IEEE 519 the total harmonic distortion (THD) voltage shall not
exceed 5.0% of the fundamental 60 Hz frequency nor 3.0% of the fundamental frequency for any
individual harmonic when measured at the point of common coupling with the utility system.
(5) Fault and line clearing. The customer shall automatically disconnect from the utility system within
ten cycles if the voltage on one or more phases falls below -30% of nominal voltage on the utility
system serving the customer premises. This disconnect timing also ensures that the generator is
PUCT DG Interconnection Manual 05/01/02
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disconnected from the utility system prior to automatic re-close of breakers. The customer may
reconnect when the utility system voltage and frequency return to normal range and the system is
stabilized. To enhance reliability and safety and with the utility's approval, the customer may employ
a modified relay scheme with delayed tripping or blocking using communications equipment between
customer and company.
(d)
Control, protection and safety equipment requirements specific to single phase generators of 50
kilowatts (kW) or less connected to the utility's system. Exporting to the utility system may require
additional operational or protection devices and will require coordination of operations with the host utility.
The necessary control, protection, and safety equipment specific to single-phase generators of 50 kW or
less connected to secondary or primary systems include an interconnect disconnect device, a generator
disconnect device, an over-voltage trip, an under-voltage trip, an over/under frequency trip, and a
synchronizing check for synchronous and other types of generators with stand-alone capability.
(e)
Control, protection and safety equipment requirements specific to three-phase synchronous
generators, induction generators, and inverter systems. This subsection specifies the control,
protection, and safety equipment requirements specific to three phase synchronous generators, induction
generators, and inverter systems. Exporting to the utility system may require additional operational or
protection devices and will require coordination of operations with the utility.
(1) Three phase synchronous generators. The customer's generator circuit breakers shall be threephase devices with electronic or electromechanical control. The customer is solely responsible for
properly synchronizing its generator with the utility. The excitation system response ratio shall not be
less than 0.5. The generator's excitation system(s) shall conform, as near as reasonably achievable, to
the field voltage versus time criteria specified in American National Standards Institute Standard
C50.13-1989 in order to permit adequate field forcing during transient conditions. For generating
systems greater than two MW the customer shall maintain the automatic voltage regulator (AVR) of
each generating unit in service and operable at all times. If the AVR is removed from service for
maintenance or repair, the utility's dispatching office shall be notified.
(2) Three-phase induction generators and inverter systems. Induction generation may be connected
and brought up to synchronous speed (as an induction motor) if it can be demonstrated that the initial
voltage drop measured on the utility system side at the point of common coupling is within the visible
flicker stated in subsection (c)(2) of this section. Otherwise, the customer may be required to install
hardware or employ other techniques to bring voltage fluctuations to acceptable levels. Linecommutated inverters do not require synchronizing equipment. Self-commutated inverters whether of
the utility-interactive type or stand-alone type shall be used in parallel with the utility system only
with synchronizing equipment. Direct-current generation shall not be operated in parallel with the
utility system.
(3) Protective function requirements. The protective function requirements for three phase facilities of
different size and technology are listed below.
(A) Facilities rated ten kilowatts (kW) or less must have an interconnect disconnect device, a
generator disconnect device, an over-voltage trip, an under-voltage trip, an over/under
frequency trip, and a manual or automatic synchronizing check (for facilities with stand alone
capability).
(B) Facilities rated in excess of ten kW but not more than 500 kW must have an interconnect
disconnect device, a generator disconnect device, an over-voltage trip, an under-voltage trip, an
over/under frequency trip, a manual or automatic synchronizing check (for facilities with stand
alone capability), either a ground over-voltage trip or a ground over-current trip depending on
the grounding system if required by the company, and reverse power sensing if the facility is
not exporting (unless the generator is less than the minimum load of the customer).
(C) Facilities rated more than 500 kW but not more than 2,000 kW must have an interconnect
disconnect device, a generator disconnect device, an over-voltage trip, an under-voltage trip, an
over/under frequency trip, either a ground over-voltage trip or a ground over-current trip
depending on the grounding system if required by the company, an automatic synchronizing
check (for facilities with stand alone capability) and reverse power sensing if the facility is not
PUCT DG Interconnection Manual 05/01/02
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exporting (unless the facility is less than the minimum load of the customer). If the facility is
exporting power, the power direction protective function may be used to block or delay the
under frequency trip with the agreement of the utility.
(D) Facilities rated more than 2,000 kW but not more than 10,000 kW must have an interconnect
disconnect device, a generator disconnect device, an over-voltage trip, an under-voltage trip, an
over/under frequency trip, either a ground over-voltage trip or a ground over-current trip
depending on the grounding system if required by the company, an automatic synchronizing
check and AVR for facilities with stand alone capability, and reverse power sensing if the
facility is not exporting (unless the facility is less than the minimum load of the customer). If
the facility is exporting power, the power direction protective function may be used to block or
delay the under frequency trip with the agreement of the utility. A telemetry/transfer trip may
also be required by the company as part of a transfer tripping or blocking protective scheme.
(f)
Facilities not identified. In the event that standards for a specific unit or facility are not set out in this
section, the company and customer may interconnect a facility using mutually agreed upon technical
standards.
(g)
Requirements specific to a facility paralleling for sixty cycles or less (closed transition switching).
The protective devices required for facilities ten MW or less which parallel with the utility system for 60
cycles or less are an interconnect disconnect device, a generator disconnect device, an automatic
synchronizing check for generators with stand alone capability, an over-voltage trip, an under-voltage trip,
an over/under frequency trip, and either a ground over-voltage trip or a ground over-current trip depending
on the grounding system, if required by the utility.
(h)
Inspection and start-up testing. The customer shall provide the utility with notice at least two weeks
before the initial energizing and start-up testing of the customer's generating equipment and the utility may
witness the testing of any equipment and protective systems associated with the interconnection. The
customer shall revise and re-submit the application with information reflecting any proposed modification
that may affect the safe and reliable operation of the utility system.
(i)
Site testing and commissioning. Testing of protection systems shall include procedures to functionally
test all protective elements of the system up to and including tripping of the generator and interconnection
point. Testing will verify all protective set points and relay/breaker trip timing. The utility may witness the
testing of installed switchgear, protection systems, and generator. The customer is responsible for routine
maintenance of the generator and control and protective equipment. The customer will maintain records of
such maintenance activities, which the utility may review at reasonable times. For generation systems
greater than 500 kW, a log of generator operations shall be kept. At a minimum, the log shall include the
date, generator time on, and generator time off, and megawatt and megavar output. The utility may review
such logs at reasonable times.
(j)
Metering. Consistent with Chapter 25, Subchapter F of this title (relating to Metering), the utility may
supply, own, and maintain all necessary meters and associated equipment to record energy purchases by the
customer and energy exports to the utility system. The customer shall supply at no cost to the utility a
suitable location on its premises for the installation of the utility's meters and other equipment. If metering
at the generator is required in such applications, metering that is part of the generator control package will
be considered sufficient if it meets all the measurements criteria that would be required by a separate stand
alone meter.
PUCT DG Interconnection Manual 05/01/02
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Form of Tariff for Interconnection and Parallel Operation of DG
Distributed Generation Interconnection
Availability
Company shall interconnect distributed generation as described in PUC Substantive
Rules §25.211 and §25.212 pursuant to the terms of the Agreement for Interconnection
and Parallel Operation of Distributed Generation which is incorporated herein.
Application
A person seeking interconnection and parallel operation of distributed generation with
Company must complete and submit the Application for Interconnection and Parallel
Operation of Distributed Generation with the Utility System, which is incorporated
herein.
Definitions
1) Non-Peak Hours - ____________________________________.
2) Peak Hours - ________________________________________.
Pricing
Standby
Maintenance
Supplemental
Terms and Conditions of Service
The terms and conditions under which interconnection of distributed generation is to be
provided are contained in Commission Substantive Rules §25.211 and §25.212, which
are incorporated herein by reference, and in the Agreement for Interconnection and
Parallel Operation of Distributed Generation, which is incorporated herein. The rules
are subject to change from time to time as determined by the Commission, and such
changes shall be automatically applicable hereto based upon the effective date of any
PUCT DG Interconnection Manual 05/01/02
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Commission order or rule amendment.
Studies and Services
Pre-interconnection studies may be required and conducted by Company. Other
services may be provided as requested by the customer and provided pursuant to
negotiations and agreement by the customer and Company and may be subject to
approval by the Commission.
Pre-Interconnection Study Fee Schedule
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Prescribed Form Application for Interconnection and Parallel Operation of
Distributed Generation with the Utility System
Customers seeking to interconnect distributed generation with the utility system will
complete and file with the company the following Application for Parallel Operation:
PUCT DG Interconnection Manual 05/01/02
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APPLICATION FOR INTERCONNECTION AND PARALLEL OPERATION OF DISTRIBUTED
GENERATION WITH THE UTILITY SYSTEM
Return Completed Application to:
[Company name]
[Attention: Manager, Distribution Planning
[Company address]
[Company address]
Customer’s Name: _______________________________________________________
Address:________________________________________________________________
Contact Person: __________________________________________________________
Telephone Number: ______________________________________________________
Service Point Address: ____________________________________________________
Information Prepared and Submitted By: ______________________________________
(Name and Address) ______________________________________________________
Signature _______________________________________
The following information shall be supplied by the Customer or Customer’s designated
representative. All applicable items must be accurately completed in order that the Customer’s
generating facilities may be effectively evaluated by the (Company) _____________for
interconnection with the utility system.
GENERATOR
Number of Units: __________________________________________________________
Manufacturer: ____________________________________________________________
Type (Synchronous, Induction, or Inverter): ____________________________________
Fuel Source Type (Solar, Natural Gas, Wind, etc.): _______________________________
Kilowatt Rating (95 F at location) _____________________________________________
Kilovolt-Ampere Rating (95 F at location): ______________________________________
Power Factor: ___________________________________________________________
Voltage Rating: __________________________________________________________
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Ampere Rating: __________________________________________________________
Number of Phases: ________________________________________________________
Frequency: _____________________________________________________________
Do you plan to export power: _____________Yes / _______________No
If Yes, maximum amount expected: __________________________________________
Pre-Certification Label or Type Number: ______________________________________
Expected Energizing and Start-up Date: _______________________________________
Normal Operation of Interconnection: (examples: provide power to meet base load, demand
management, standby, back-up, other (please describe))_____________________________
One-line diagram attached: __________Yes
Has the generator Manufacturer supplied its dynamic modeling values to the Host Utility?
_______Yes
[Note: Requires a Yes for complete application. For Pre-Certified Equipment answer is Yes.]
Layout sketch showing lockable, "visible" disconnect device:
_____________Yes
[COMPANY NAME]
[CUSTOMER NAME]
BY: _________________________
BY: __________________________
TITLE: _______________________
TITLE: _______________________
DATE: _______________________
DATE: ________________________
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AGREEMENT FOR INTERCONNECTION AND PARALLEL OPERATION OF
DISTRIBUTED GENERATION
This Interconnection Agreement (“Agreement”) is made and entered into this
________ day of ________________, 19__, by _______________________________,
(“Company”), and __________________________________________ (“Customer”), a
___________________________________ [specify whether corporation, and if so
name state, municipal corporation, cooperative corporation, or other], each hereinafter
sometimes referred to individually as “Party” or both referred to collectively as the
“Parties”. In consideration of the mutual covenants set forth herein, the Parties agree
as follows:
1.
Scope of Agreement -- This Agreement is applicable to conditions under
which the Company and the Customer agree that one or more generating facility or
facilities of ten MW or less to be interconnected at 60 kV or less (“Facility or Facilities”)
may be interconnected to the Company’s utility system, as described in Exhibit A.
2.
Establishment of Point(s) of Interconnection -- Company and Customer
agree to interconnect their Facility or Facilities at the locations specified in this
Agreement, in accordance with Public Utility Commission of Texas Substantive Rules §
25.211 relating to Interconnection of Distributed Generation and § 25.212 relating to
Technical requirements for Interconnection and Parallel Operation of On-Site
Distributed Generation, (16 Texas Administrative Code §25.211 and §25.212) (the
“Rules”) or any successor rule addressing distributed generation and as described in
the attached Exhibit A (the “Point(s) of Interconnection”).
3. Responsibilities of Company and Customer -- Each Party will, at its own cost
and expense, operate, maintain, repair, and inspect, and shall be fully responsible for,
Facility or Facilities which it now or hereafter may own unless otherwise specified on
Exhibit A. Customer shall conduct operations of its facility(s) in compliance with all
aspects of the Rules, and Company shall conduct operations on its utility system in
compliance with all aspects of the Rules, or as further described and mutually agreed to
in the applicable Facility Schedule.
Maintenance of Facilities or interconnection
facilities shall be performed in accordance with the applicable manufacturer’s
recommended maintenance schedule. The Parties agree to cause their Facilities or
systems to be constructed in accordance with specifications equal to or greater than
those provided by the National Electrical Safety Code, approved by the American
National Standards Institute, in effect at the time of construction.
Each Party covenants and agrees to design, install, maintain, and operate, or cause the
design, installation, maintenance, and operation of, its distribution system and related
Facilities and Units so as to reasonably minimize the likelihood of a disturbance,
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originating in the system of one Party, affecting or impairing the system of the other
Party, or other systems with which a Party is interconnected.
Company will notify Customer if there is evidence that the Facility operation causes
disruption or deterioration of service to other customers served from the same grid or if
the Facility operation causes damage to Company’s system.
Customer will notify Company of any emergency or hazardous condition or occurrence
with the Customer’s Unit(s) which could affect safe operation of the system.
4. Limitation of Liability and Indemnification
a. Notwithstanding any other provision in this Agreement, with respect to Company’s
provision of electric service to Customer, Company’s liability to Customer shall be
limited as set forth in ______ of Company’s PUC-approved tariffs and terms and
conditions for electric service, which is incorporated herein by reference.
b. Neither Company nor Customer shall be liable to the other for damages for any act
that is beyond such party's control, including any event that is a result of an act of
God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or
flood, explosion, breakage or accident to machinery or equipment, a curtailment,
order, or regulation or restriction imposed by governmental, military, or lawfully
established civilian authorities, or by the making of necessary repairs upon the
property or equipment of either party.
c. Notwithstanding Paragraph 4.b of this Agreement, Company shall assume all liability
for and shall indemnify Customer for any claims, losses, costs, and expenses of any
kind or character to the extent that they result from Company’s negligence in
connection with the design, construction, or operation of its facilities as described on
Exhibit A; provided, however, that Company shall have no obligation to indemnify
Customer for claims brought by claimants who cannot recover directly from
Company. Such indemnity shall include, but is not limited to, financial responsibility
for: (a) Customer’s monetary losses; (b) reasonable costs and expenses of
defending an action or claim made by a third person; (c) damages related to the
death or injury of a third person; (d) damages to the property of Customer; (e)
damages to the property of a third person; (f) damages for the disruption of the
business of a third person. In no event shall Company be liable for consequential,
special, incidental or punitive damages, including, without limitation, loss of profits,
loss of revenue, or loss of production. The Company does not assume liability for
any costs for damages arising from the disruption of the business of the Customer or
for the Customer’s costs and expenses of prosecuting or defending an action or
claim against the Company. This paragraph does not create a liability on the part of
the Company to the Customer or a third person, but requires indemnification where
such liability exists. The limitations of liability provided in this paragraph do not apply
PUCT DG Interconnection Manual 05/01/02
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in cases of gross negligence or intentional wrongdoing.
d. Notwithstanding Paragraph 4.b of this Agreement, Customer shall assume all liability
for and shall indemnify Company for any claims, losses, costs, and expenses of any
kind or character to the extent that they result from Customer’s negligence in
connection with the design, construction or operation of its facilities as described on
Exhibit A; provided, however, that Customer shall have no obligation to indemnify
Company for claims brought by claimants who cannot recover directly from
Customer. Such indemnity shall include, but is not limited to, financial responsibility
for: (a) Company’s monetary losses; (b) reasonable costs and expenses of
defending an action or claim made by a third person; (c) damages related to the
death or injury of a third person; (d) damages to the property of Company; (e)
damages to the property of a third person; (f) damages for the disruption of the
business of a third person. In no event shall Customer be liable for consequential,
special, incidental or punitive damages, including, without limitation, loss of profits,
loss of revenue, or loss of production. The Customer does not assume liability for
any costs for damages arising from the disruption of the business of the Company or
for the Company’s costs and expenses of prosecuting or defending an action or
claim against the Customer. This paragraph does not create a liability on the part of
the Customer to the Company or a third person, but requires indemnification where
such liability exists. The limitations of liability provided in this paragraph do not apply
in cases of gross negligence or intentional wrongdoing.
e. Company and Customer shall each be responsible for the safe installation,
maintenance, repair and condition of their respective lines and appurtenances on
their respective sides of the point of delivery. The Company does not assume any
duty of inspecting the Customer’s lines, wires, switches, or other equipment and will
not be responsible therefor. Customer assumes all responsibility for the electric
service supplied hereunder and the facilities used in connection therewith at or
beyond the point of delivery, the point of delivery being the point where the electric
energy first leaves the wire or facilities provided and owned by Company and enters
the wire or facilities provided by Customer.
f. For the mutual protection of the Customer and the Company, only with Company
prior authorization are the connections between the Company’s service wires and
the Customer’s service entrance conductors to be energized.
5. Right of Access, Equipment Installation, Removal & Inspection– Upon
reasonable notice, the Company may send a qualified person to the premises of the
Customer at or immediately before the time the Facility first produces energy to inspect
the interconnection, and observe the Facility’s commissioning (including any testing),
startup, and operation for a period of up to no more than three days after initial startup
of the unit.
Following the initial inspection process described above, at reasonable hours, and upon
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reasonable notice, or at any time without notice in the event of an emergency or
hazardous condition, Company shall have access to Customer’s premises for any
reasonable purpose in connection with the performance of the obligations imposed on it
by this Agreement or if necessary to meet its legal obligation to provide service to its
customers.
6. Disconnection of Unit – Customer retains the option to disconnect from
Company’s utility system. Customer will notify the Company of its intent to disconnect
by giving the Company at least thirty days’ prior written notice. Such disconnection
shall not be a termination of the agreement unless Customer exercises rights under
Section 7.
Customer shall disconnect Facility from Company’s system upon the effective date of
any termination under Section 7.
Subject to Commission Rule, for routine maintenance and repairs on Company’s utility
system, Company shall provide Customer with seven business days’ notice of service
interruption.
Company shall have the right to suspend service in cases where continuance of service
to Customer will endanger persons or property. During the forced outage of the
Company’s utility system serving customer, Company shall have the right to suspend
service to effect immediate repairs on Company’s utility system, but the Company shall
use its best efforts to provide the Customer with reasonable prior notice.
7. Effective Term and Termination Rights-- This Agreement becomes effective
when executed by both parties and shall continue in effect until terminated. The
agreement may be terminated for the following reasons: (a) Customer may terminate
this Agreement at any time, by giving the Company sixty days’ written notice; (b)
Company may terminate upon failure by the Customer to generate energy from the
Facility in parallel with the Company’s system within twelve months after completion of
the interconnection; (c) either party may terminate by giving the other party at least sixty
days prior written notice that the other Party is in default of any of the material terms
and conditions of the Agreement, so long as the notice specifies the basis for
termination and there is reasonable opportunity to cure the default; or (d) Company may
terminate by giving Customer at least sixty days notice in the event that there is a
material change in an applicable rule or statute.
8. Governing Law and Regulatory Authority -- This Agreement was executed in
the State of Texas and must in all respects be governed by, interpreted, construed, and
enforced in accordance with the laws thereof. This Agreement is subject to, and the
parties’ obligations hereunder include, operating in full compliance with all valid,
applicable federal, state, and local laws or ordinances, and all applicable rules,
regulations, orders of, and tariffs approved by, duly constituted regulatory authorities
having jurisdiction.
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9. Amendment --This Agreement may be amended only upon mutual agreement of
the Parties, which amendment will not be effective until reduced to writing and executed
by the Parties.
10. Entirety of Agreement and Prior Agreements Superseded -- This Agreement,
including all attached Exhibits and Facility Schedules, which are expressly made a part
hereof for all purposes, constitutes the entire agreement and understanding between
the Parties with regard to the interconnection of the facilities of the Parties at the Points
of Interconnection expressly provided for in this Agreement. The Parties are not bound
by or liable for any statement, representation, promise, inducement, understanding, or
undertaking of any kind or nature (whether written or oral) with regard to the subject
matter hereof not set forth or provided for herein. This Agreement replaces all prior
agreements and undertakings, oral or written, between the Parties with regard to the
subject
matter
hereof,
including
without
limitation
________________________________________________
[specify
any
prior
agreements being superseded], and all such agreements and undertakings are agreed
by the Parties to no longer be of any force or effect. It is expressly acknowledged that
the Parties may have other agreements covering other services not expressly provided
for herein, which agreements are unaffected by this Agreement.
11. Notices -- Notices given under this Agreement are deemed to have been duly
delivered if hand delivered or sent by United States certified mail, return receipt
requested, postage prepaid, to:
(a)
If to Company:
______________________
______________________
______________________
______________________
(b)
If to Customer:
______________________
______________________
______________________
______________________
The above-listed names, titles, and addresses of either Party may be changed by
written notification to the other, notwithstanding Section 10.
12. Invoicing and Payment -- Invoicing and payment terms for services associated
with this agreement shall be consistent with applicable Substantive Rules of the PUCT.
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13. No Third-Party Beneficiaries -- This Agreement is not intended to and does not
create rights, remedies, or benefits of any character whatsoever in favor of any persons,
corporations, associations, or entities other than the Parties, and the obligations herein
assumed are solely for the use and benefit of the Parties, their successors in interest
and, where permitted, their assigns.
14. No Waiver -- The failure of a Party to this Agreement to insist, on any occasion,
upon strict performance of any provision of this Agreement will not be considered to
waive the obligations, rights, or duties imposed upon the Parties.
15. Headings -- The descriptive headings of the various articles and sections of this
Agreement have been inserted for convenience of reference only and are to be
afforded no significance in the interpretation or construction of this Agreement.
16. Multiple Counterparts -- This Agreement may be executed in two or more
counterparts, each of which is deemed an original but all constitute one and the same
instrument.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be signed by
their respective duly authorized representatives.
[COMPANY NAME]
[CUSTOMER NAME]
BY:_____________________________
BY:___________________________________
TITLE:_________________________
TITLE:_________________________________
DATE:___________________________
DATE:________________________________
PUCT DG Interconnection Manual 05/01/02
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EXHIBIT A
LIST OF FACILITY SCHEDULES AND POINTS OF INTERCONNECTION
Facility Schedule No.
Name of Point of Interconnection
[Insert Facility Schedule number and name for each Point of Interconnection]
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FACILITY SCHEDULE NO.
[The following information is to be specified for each Point of Interconnection, if applicable.]
1. Name:
2. Facility location:
3. Delivery voltage:
4. Metering (voltage, location, losses adjustment due to metering location, and other):
5. Normal Operation of Interconnection:
6. One line diagram attached (check one): ______ Yes /_______ No
7. Facilities to be furnished by Company:
8. Facilities to be furnished by Customer:
9. Cost Responsibility:
10. Control area interchange point (check one): ______ Yes /_______ No
11. Supplemental terms and conditions attached (check one): _____ Yes / ______ No
[COMPANY NAME]
[CUSTOMER NAME]
BY:_____________________________
BY:___________________________________
TITLE:__________________________
TITLE:_________________________________
DATE:___________________________
DATE:_________________________________
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Definition of “electric utility” from PURA §31.002(6)
Also see Definitions A-1
FILE: PURA31.002(6)
ATTACHMENT G
EXCERPT FROM PUBLIC UTILITY REGULATORY ACT, 1999, SEC. 31.002
DEFINITIONS, (6)
(6) "Electric utility" means a person or river authority that owns or operates for
compensation in this state equipment or facilities to produce, generate, transmit,
distribute, sell, or furnish electricity in this state. The term includes a lessee, trustee,
or receiver of an electric utility and a recreational vehicle park owner who does not
comply with Subchapter C, Chapter 184, with regard to the metered sale of electricity
at the recreational vehicle park. The term does not include:
(A) a municipal corporation;
(B) a qualifying facility;
(C) a power generation company;
(D) an exempt wholesale generator;
(E) a power marketer;
(F) a corporation described by Section 32.053 to the extent the corporation
sells electricity exclusively at wholesale and not to the ultimate consumer;
(G) an electric cooperative;
(H) a retail electric provider;
(I)
this state or an agency of this state; or
(J)
a person not otherwise an electric utility who:
(i)
furnishes an electric service or commodity only to itself, its employees,
or its tenants as an incident of employment or tenancy, if that service or
commodity is not resold to or used by others;
(ii) owns or operates in this state equipment or facilities to produce,
generate, transmit, distribute, sell, or furnish electric energy to an electric utility,
if the equipment or facilities are used primarily to produce and generate electric
energy for consumption by that person; or
(iii) owns or operates in this state a recreational vehicle park that provides
metered electric service in accordance with Subchapter C, Chapter 184.
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Appendix A3: Summary of DG Technologies
This Appendix provides brief descriptions of leading DG technologies. For context, it
includes generic cost and performance information. Readers should note that for any
given situation it is important to consult with vendors or their agents or dealers regarding
actual price. To assist, this Appendix includes a list of links to World Wide Web sites for
many leading DG equipment vendors.
Introduction
Distributed generation (DG) systems may be comprised of one or more primary
technologies such as internal combustion engines, combustion turbines, photovoltaics,
and batteries. Innumerable combinations of DG technology/fuel options are possible, to
take advantage of synergies between individual technologies, making them as robust
and/or cost-effective as possible.4
Most DG systems operate on gaseous or liquid hydrocarbon fuel to produce electricity
as needed; natural gas fuel is piped in; diesel fuel is stored on-site. Battery systems
store electric energy from the grid for use when needed. Renewable energy DGs use
solar or wind energy as fuel.
One important DG type category is the duty cycle for the DG is used: 1) for “peaking”
duty cycle applications DGs only operate for a small portion of the year, usually
between 50 – 600 hours annually, and 2) for “baseload” duty cycle DGs operate for
many hours per year for.
Peaking duty distributed generation tends to have relatively low installed cost and can
take on load in just a few minutes (or less). It tends to be relatively inefficient and have
significant air emissions per hour operated. Peak duty cycle DGs usually operate for
just a few hundred hours between overhauls. Typical installed costs range from about
$200 – $500/kW and non-fuel operating cost ranges from 1¢ - 5¢/kWh.
Primary distributed generation technologies used for baseload duty cycle (when
compared to peaking duty cycle described above) tend to be fuel efficient, reliable, and
clean burning combustion-based options. Typical installed costs range from about $400
– $800/kW and non-fuel operating cost ranges from ½¢ - 3¢/kWh.
4
Perhaps one of the best examples is an uninterruptible power supply (UPS) that can carry a facility’s
load for several minutes combined with a diesel engine generator that takes a few minutes to come on
line. Batteries are an expensive way to store/provide a significant amount of electric energy. So in this
case the synergy is that once running, the diesel generator provides much lower cost energy.
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Most types of distributed generation can provide useful and valuable thermal energy.
To do so, additional equipment (e.g., pipes and pumps) is added to the generation
system so that during electricity generation otherwise wasted heat energy is captured
and used to heat water or air, or for processes. This concept is often referred to as
combined heat and power (CHP) or cogeneration. Depending on type of generator
used, existing thermal energy infrastructure in the facility, and many other projectspecific factors, equipment for CHP can add 25% - 100% to the installed cost for a
generation-only system.
Important “enabling” subsystems include:
• power conditioning equipment such as electricity generator, transformer, and
inverters
• controls
• communications
• fuel handling and/or fuel storage
• emission controls
• sound attenuation enclosures.
Internal Combustion/Reciprocating Engine Generators
An internal combustion reciprocating (piston-driven) engine generator set (genset)
includes an internal combustion engine as prime mover coupled with an electric
generator and often control and power conditioning subsystems. Sound attenuation
enclosures may be also needed.
Most engines are one of two types:
1) compression ignition of fuel — the diesel cycle in which fuel combustion
occurs as fuel is compressed causing heat leading to ignition.
2) “spark-ignited” combustion of fuel — the Otto cycle characterized by how fuel
spark ignition of fuel (gasoline fueled automobile engines employ the Otto
cycle).
These are described in more detail below.
Diesel Engine Generators
Diesel engine generator sets (gensets) consists of a diesel cycle reciprocating engine
prime mover, burning diesel fuel, which is coupled to an electric generator. The diesel
engine operates at a relatively high compression ratio and at relatively low rpm
(compared to Otto cycle/spark engines and to combustion turbines described below).
Diesel engine gensets are very common, especially in areas where grid power is not
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available or is unreliable. They are manufactured in a wide range of sizes up to 15 MW;
however, for typical distributed energy applications multiple small units, rather than one
large unit, are installed for added reliability.
These power plants can be cycled frequently and operate as peak load power plants or
as load-following plants. In some cases, usually at sites not connected to a power grid,
diesel gensets are used for baseload operation (sometimes referred to as "village"
power). Diesel gensets are proven, cost-effective, and extremely reliable, and should
have a service life of 20 to 25 years if properly maintained.
Installed cost for diesel engines varies significantly. Used/refurbished models can cost
as little as $200/kW and newer, more robust, more efficient machines costing $500/kW
or more. Depending on duty cycle and engine design, non-fuel O&M for diesel gensets
operating on diesel fuel can vary widely, typically ranging from 2.5¢/kWh - 4¢/kWh, with
an allowance for overhauls. Frequent cycling increases O&M costs considerably.
Though fuel conversion efficiency for diesels engines can exceed 43% (fuel input of
about 7,900 Btu/kWhe, HHV), typical heat rates range widely from 8,000 Btu/kWhe to
10,000 Btu/kWhe (HHV).
“Dual Fuel” Diesel Engine Generators
A dual-fuel engine is a diesel (cycle) engine modified to use mostly natural gas. Diesel
cycle engines cannot operate on natural gas alone because natural gas will not
combust under pressure like diesel fuel does, so they must operate in what is called
“dual fuel” mode. For that, natural gas is mixed with a small portion of diesel fuel so that
the resulting fuel mixture (i.e., 5 – 10% diesel fuel) does combust under pressure. This
requires de-rating of and modest modifications to a diesel cycle engine. (Note: for the
same displacement a diesel engine operating on natural gas generates less power than
the same sized engine operating on diesel fuel only).
Although diesel engines are common, dual fuel versions are not. But because the
underlying technology is commercial and well known, in theory natural gas fired
versions (for power generation) could become much more common in sizes ranging
from kilowatts to megawatts. For distributed energy systems small multiple unit systems
would probably be installed, rather than one single large unit, to improve electric service
reliability.
Dual fuel gensets can be cycled frequently to provide peaking power or “load-following”
or they can be used for baseload or cogeneration applications. They employ mostly
well-proven technology and are very reliable. Service life should be at least 20 to 25
years if properly maintained.
Non-fuel O&M cost is similar to that for diesel gensets. It typically ranges from 2 - 4
¢/kWh including allowance for overhauls. Typical heat rates (HHV) also have a wide
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range, from 8,200 Btu/kWhe to 10,000 Btu/kWhe.
Spark Ignited/Otto Cycle Engine Generators
Spark-ignited combustion (Otto cycle) reciprocating engines are very common. They
range in power output of less than a horsepower to megawatts. Perhaps the most
familiar use for these engines is for automobiles. For stationary power applications
including DG a system includes the engine, internal combustion engine as prime mover
coupled with an electric generator. The engine prime mover is usually one of two types:
Although spark-ignition engines designed to use gasoline are common, natural gas
fueled versions are not so common. However, because the underlying technology is
commercial and well known, in theory, natural gas fired versions (for power generation)
could become much more common for a variety of applications and load sizes.
Natural gas-fueled reciprocating engine gensets can be cycled frequently to provide
peaking power or “load-following” or they can be used for baseload or cogeneration
applications. They employ mostly well-proven technology and are very reliable.
Service life should be at least 20 to 25 years if properly maintained.
Installed cost tends to range between $400/kW – $600/kW. O&M cost is similar to and
possibly somewhat lower than that for diesel gensets. It typically ranges from 2¢/kWh –
4.5¢/kWh. Typical heat rates (HHV) also have a wide range, from 8,800 to 10,500
Btu/kWh.
Combustion Turbines
Combustion turbines (also called gas turbines) burn gaseous or liquid fuel to produce
electricity in a relatively efficient, reliable, cost-effective, and in some instances clean
manner. Generically, combustion turbines s are "expansion turbines" which derive their
motive power from the expansion of hot gasses—heated with fuel—through a turbine
with many blades. The resulting high-speed rotary motion is converted to electricity via
a connected generator using the Brayton heat cycle. A full generation system consists
of the turbine itself, a compressor, a combustor, power conditioning equipment (usually
electricity generator and transformer), a fuel handling subsystem, and possibly other
subsystems. They may also include a sound attenuation enclosure.
Combustion turbine generation systems are commonplace as electricity generators and
are available in sizes from hundreds of kilowatts to very large units rated at hundreds of
megawatts. Combustion turbine systems have a moderate capital cost, but they often
are used to burn relatively high cost distillate oil or natural gas. Combustion turbine
generation systems should have a minimum service life of 25 - 30 years if properly
maintained and depending on how and how often they are used.
Depending
on
the
size,
type,
PUCT DG Interconnection Manual 05/01/02
and application, full-load heat rates (HHV) for
A3-4
commercial equipment can range from 8,000 Btu/kWh to 14,000 Btu/kWh. Non-fuel
O&M costs are relatively low – typically ranging from ½ ¢/kWh - 5 ¢/kWh. Variation is a
function of criteria such as turbine size, turbine age, turbine materials, turbine
complexity/simplicity, reliability required, availability of components, and maintenance
protocol/frequency.
Combustion turbines can start and stop quickly and can respond to load changes
rapidly making them ideal for peaking and load-following applications. In many
industrial cogeneration applications they would also make excellent sources of baseload
power, especially at sizes in the 5 to 50 MW range.
“Conventional” Combustion Turbine Generators
Conventional combustion turbine generators vary significantly in price, size, and are
designed for a wide range of duty cycles. Typical sizes range from 1 to 300 MW.
Smaller turbines used for stationary power generation are often those developed for
transportation applications, especially for marine vessels and airplanes. (Note that for
those applications reliability and in some cases fuel efficiency are important
performance criteria.)
Installed costs range from as low as $300/kW for refurbished units and lighter duty
machines to 700 - $800/kW for heavier duty/more efficient versions, with non-fuel O&M
ranging from .75¢/kWh - 4¢/kWh depending in large part on the intended duty cycle and
on maintenance practices.
Microturbine Generators
Microturbines are small versions of traditional gas turbines, with very similar operational
characteristics.
They are based on designs developed primarily for
transportation-related applications such as turbochargers and power generation in
aircraft. In general, electric generators using microturbines as the prime mover are
designed to be very reliable with simple designs, some with only one moving part.
Typical sizes are 20 to 300 kW.
Microturbines are "near-commercial" with many demonstration and evaluation units in
the field. Several companies, some of which are very large, are committed to making
these devices a viable, competitive generation option. One key characteristic of
microturbines is that their simple design lends itself to mass production—should
significant demand materialize. For the most part, prices too are still being established.
Possibly the key driver will be manufacturing scale. Installed price is currently in the
range of about $1,000/kW – 1,500/kW.
Definitive data on reliability, durability, and non-fuel O&M costs are just being developed
though based on simplicity and in some cases well-proven designs non-fuel O&M could
be similar to that of conventional combustion turbines.
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Fuel efficiency tends to be somewhat or even significantly lower than that of larger
combustion turbines and internal combustion reciprocating engines, ranging from
10,000 Btu/kWhe –15,000 Btu/kWhe. Note, however, that if microturbines are used in
situations involving use of steam and/or hot water, then they can generate electricity
and thermal energy (combined heat and power, CHP) cost-effectively due to a) the
temperatures involved and b) the large amount of waste heat produced.
Advanced Turbine System (ATS) Generators
The Advanced Turbine System (ATS) was developed as a small, efficient, clean, lowcost, power generation prime mover by Solar Turbines in conjunction with the U.S.
Department of Energy. It employs the latest combustion turbine design philosophy and
state-of-the-art materials. It generates 4.2 MW. Fuel requirements are about 8,800 –
9,000 Btu/kWh (LHV). Installed cost is expected to be about $400/kW, with non-fuel
O&M expected to be below ½¢ per kWh generated.
Fuel Cells
Fuel cells are energy conversion devices that convert hydrogen (H2) or high-quality
(hydrogen-rich) fuels like methane into electric current without combustion and with
minimal environmental impact. Due in part to how fuel cells convert fuel to electricity
(i.e., without combustion) conversion is relatively efficient and fuel cells' emissions of
key air pollutants are much lower than for combustion technologies, especially nitrogen
oxides (NOx). Fuel cells are very modular (from a few watts to one MW).
Fuel cells are often categorized by the type of electrolyte used. The most common
electrolyte for fuel cells used for stationary power is phosphoric acid; others include
solid oxide and molten carbonate. Another promising type of fuel cell utilizes a proton
exchange membrane, hence the name PEM fuel cell.
A fuel cell system consists of a fuel processor, the chemical conversion section (the fuel
cell "stack"), and a power conditioning unit (PCU) to convert the direct current (DC)
electricity from the fuel cell's stack into alternating current (AC) power for the grid or for
loads and for supporting hardware such as gas purification systems.
Unless hydrogen is used as the fuel, prior to entering the fuel cell stack, the raw fuel
(e.g., natural gas) must be dissociated into hydrogen and a supply of oxygen from air
must be available. Within the fuel cell stack, the hydrogen and oxygen react to produce
a voltage across the electrodes, essentially the inverse of the process which occurs in a
water electrolyzer.
There are hundreds of fuel cells in service worldwide and the number of units in service
is growing rapidly. Advocates are awaiting expected manufacturing advances that will
reduce fuel cells' equipment cost and improve its efficiency such that they
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produce very low cost energy. Typical plant unit sizes (which can be aggregated into
any plant output rating needed) are expected to range widely from a few kW to 200 kW.
Currently available fuel cells based on phosphoric-acid electrolytes have heat rates
(HHV) of 9,500 Btu/kWhe – 10,000 Btu/kWhe and cost about $3000/kW installed. Nonfuel O&M for installed devices is about 2.5¢/kWh – 3¢/kWh.
Advanced fuel cells systems are expected to have efficiencies of ranging from 40% to
perhaps as high as 55%. (6,300 Btu/kWhe - 8,500 Btu/kWhe) over the next 5 years and
ultimately to cost less than $1000/kW installed.
Energy Storage Systems
Energy storage systems used for DG applications include devices that store energy:
a) electrochemically or b) as mechanical energy, and which “discharge” electricity for
use when needed. Battery energy storage systems consist of the battery and a power
conditioning unit (PCU) sub-system to convert grid power from alternating current (AC)
power to direct current (DC) power during battery charging, and to convert battery
power from DC to AC power during battery discharge.
Most batteries can change their rate of discharge/storage in milliseconds.
Note that there are two key elements to energy storage plant cost (unlike generators
with just one). They are: 1) output rated in Watts (or Volt-amps) indicating the rate at
which the system can “discharge: (i.e. provide energy to a load) and 2) the energy
storage capacity, the amount of energy that can be stored (rated in kiloWatt-hours).
Storage is used for a variety of applications, such as:
• increase reliability—for longer duration power outages
• reduce impacts from an electric supply’s poor power quality—for shorter
duration electric service disruptions
• to take advantage of “buy low-sell high” (energy cost reduction) opportunities or
of peak shaving (electric demand reduction) opportunities
• to reduce peak demand on a local electricity infrastructure
Electrochemical batteries are by far the most common type of battery, primarily these
are the “lead-acid” type, though other types are emerging as competitive options. They
are proven, reliable, and highly modular. A robust international industry exists to
support use of electrochemical batteries. Off the shelf and, in the future, “advanced”
battery systems will be viable for distributed energy systems.
Plant costs range from about $200 - $300 per kW of maximum power output/discharge,
and about the same to somewhat higher installed cost for each kWh of energy storage
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“reservoir” capacity ($200/kWh - $400/kWh of storage capacity).
O&M for
electrochemical includes replacement of battery cells and secondarily periodic watering
of the cells and periodic maintenance of the PCU. Non-fuel O&M ranges from .75¢/kWh
– 1.5 ¢/kWh. “Round-trip” energy efficiency (AC to DC to AC, or charge-discharge)
usually ranges from 65% - 75%.
There may be limited hazardous emissions from battery charging and some batteries
contain hazardous material(s).
Superconducting magnetic energy storage (SMES), flywheels, “supercapacitors” are
emerging alternatives to electrochemical batteries. These devices tend to be more
efficient. SMES units may be superior for larger scale applications. SMES units are
being used commercially in the U.S. to stabilize voltage on transmission lines.
Flywheels and supercapacitors are more modular and tend to be relatively light.
In addition be being a discreet system type, often energy storage is a key subsystem
within systems employing other types of DG. Depending on the type of system, energy
storage does one or more of the following: a) provide power for loads during engine
start-up, b) provide electric energy needed to start the engine itself, or c) store electric
energy from the DG system (or even the utility grid) for later use.
Uninterruptible Power Systems (UPS)
UPSs are connected to specific equipment, buildings or entire facilities with critical loads
to provide protection from power fluctuations lasting from just a few milliseconds to a
few minutes. Specifically they provide: a) filtered/high quality power on a continuous
basis and/or b) energy for use during power outages lasting several minutes. Often
they have sufficient energy to power loads long enough to allow orderly shutdowns (e.g.
of information or process equipment).
UPSs can either be stand-by or in-line. Stand-by devices monitor the line (power
source) and provide energy as needed when problems are detected. In-line systems
are connected between the power source and the load and thus can provide very
complete, continuous filtering of grid power, although “throughput” losses can be as
high as 40%.
Photovoltaics (PV)
Photovoltaics are semiconductor devices which convert sunlight directly to DC
electricity; power conditioners (inverters) are used to convert the DC to standard AC
power. Photovoltaic cells are thin layers of semiconductor (usually crystalline silicon).
The cells are integrated in series and parallel into a module which is easily mountable
on a structure. Modules can be attached to fixed surfaces, accepting output variations
due to the sun’s position, or they can be made to track the sun for maximum output.
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Photovoltaic systems using crystalline silicon are readily available. However, PV
lifecycle and equipment costs are not competitive with more conventional generation
technology for large-scale generation applications. Conversely, PV is cost-effective in a
growing number of circumstances for applications requiring low power and/or small
amounts of energy. Therefore remote installations and niche applications (e.g., power
for communications systems, roadside emergency cellular phones, and off-grid homes)
are the most common applications for PV.
Photovoltaic energy production can vary dramatically from one day to the next—due
mostly to weather, and from one region to the next—due mostly to differences in latitude
and weather. Frequently, battery storage and/or diesel genset systems are integrated
with photovoltaics to carry loads through times when sunlight does not provide enough
energy.
PV systems can cost between $5,000 - $10,000/kW installed, with variation driven
mostly by system maximum output and cost for subsystems used such as inverters,
integrated engine-generator, battery energy storage.
Controls
Control subsystems perform a variety of tasks within a DG system including: 1) engine
start up and shut down, 2) managing how/how much fuel is used, 3) energy storage
charge/discharge control, 4) communications between DG subsystems and with
external systems, 5) monitoring and recording key performance and operational
parameters, and 6) system diagnostics.
Power Conditioning
Unless a DG system provides power in the form needed by loads, some type of power
conditioning is required. For example, fuel cells, photovoltaics and battery systems
produce direct current electricity. Power conditioning equipment called inverters are
used to convert DC electricity to alternating current (AC) electricity used by most types
of electricity-using equipment.
Reciprocating engines and combustion turbines create “rotational” mechanical power
that must be converted to electricity. To do that the engine is attached to a generator.
Generators create electricity via electromagnetism using coils of wire and magnets
(electricity is created by the motion of the wire coils or magnets relative to each other).
Generators used with combustion turbine and reciprocating engine based DG systems
usually produce electricity at frequencies and voltages that may have to be modified
being used by loads. Step-up or step-down transformers are used to increase/decrease
voltage respectively.
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Data Caveats
Cost and performance information presented herein is based on data from various
sources. In many cases manufacturers supplied their best current data or they
developed estimations based on projected costs or fuel efficiency. Installed cost for
actual distributed generation projects are usually quite site-specific.
Wind
A wind generation system (a.k.a. wind turbine) converts the kinetic energy in wind
(moving air) into mechanical work and then to electric energy. Key subsystems include:
airfoil shaped blades; a rotor (to which blades are attached) that converts wind energy
to rotational shaft energy; a drive train, usually including a gearbox; a tower that
supports the rotor and drive train, a generator that converts mechanical energy to
electricity, and power conditioning that converts the electricity generated into a form
(Voltage and current frequency) used by the grid. Systems also include other
equipment such as electrical wires, ground support equipment, interconnection gear,
and controls.
During generation wind passes over both surfaces of the airfoil shaped blade; air
passes over the longer (upper) side of the airfoil more rapidly than it moves past the
underside, creating a lower-pressure area above the airfoil. The pressure differential
between top and bottom surfaces results in a force called aerodynamic lift (the same
phenomenon that causes aircraft wing use this phenomenon to “lift” an airplane).
Wind turbine electric power output varies with wind speed. The "rated wind speed" is
the wind speed at which the "rated power" is achieved and generally corresponds to the
point at which the conversion efficiency is near its maximum. In many systems power
output during times when wind speed exceeds the rated wind speed, turbine speed is
maintained at a constant level, allowing more stable system control. Note that at lower
wind speeds, the power output drops off sharply as turbine output is a function of the
cube of the wind speed (e.g.; power available in the wind increases eight times for every
doubling of wind speed).
Individual wind generation systems range in electrical output from a few Watts to over 1
MW and can be used for applications including small/residential electricity production to
utility scale power generation. In both cases power from the turbine must be converted
to the form used by the grid before being transferred to the grid (i.e., the process called
power conditioning).
For large scale applications turbines are often constructed in “wind farms” whose total
output can range from tens to hundreds of MW.
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Distributed Power Equipment and Services Vendors
Batteries and UPSs
American Superconductor
General Electric (GE) Industrial Systems
GNB
Powercell
Fuel Cells
Avista Labs
Ballard Power Systems
DCH Technology
Dais Analytic
FuelCell Energy
GE MicroGeneration
H Power Corp.
IdaTech (Northwest Power Systems)
International Fuel Cells (United
Technologies)
Matsushita Electric Industry
NuPower (Energy Partners, Inc.)
Plug Power
Proton Energy Systems
Sanyo
Siemens Westinghouse
Sure Power
Microturbines
AeroVironment
Capstone
Elliott Energy Systems/MagneTek
GE Power Systems
Honeywell Parallon Power Systems
Ingersoll-Rand Energy Systems
http://www.amsuper.com
http://www.geindustrial.com/
http://www.gnb.com/
http://www.powercell.com/
http://www.avistalabs.com
http://www.ballard.com
http://www.dch-technology.com
http://www.daisanalytic.com
http://www.fce.com
http://www.gemicrogen.com
http://www.hpower.com
http://www.idatech.com
http://www.internationalfuelcells.com
http://www.mei.co.jp
http://www.energypartners.org
http://www.plugpower.com
http://www.protonenergy.com
http://www.sanyo.co.jp
http://www.spcf.siemens.com
http://www.hi-availability.com
http://www.aerovironment.com/
http://www. capstoneturbine.com
http://www.magnatek.com/
http://www.ge.com
http://www.parallon75.com/
http://www.ingersollrand.com/energystystems
Solo Energy Corp.
Turbec AB
PowerPac (Elliot Microturbine Systems)
Williams Distributed Power Services
http://www.powerpac.com/turbine.html
http://www.williamsgen.com
Photovoltaics
Amonix
http://www.amonix.com/
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Applied Power
ASE Americas
AstroPower
BP Solarex
Ebara Solar
Energy Conversion Devices
Evergreen Solar
Kyocera
PowerLight
Photowatt International
Sharp
Shell Renewables
Siemens Solar
Solar Electric Light Company
Solarex
http://www.appliedpower.com/
http://www.asepv.com
http://www.astropower.com
http://www.solarex.com
http://www.ebara.co.jp
http://www.ovonic.com/
http://www.evergreensolar.com
http://www.kyocera.com
http://www.powerlight.com/
http://www.photowatt.com
http://www.sharp-usa.com
http://www.shell.com
http://www.siemenssolar.com
http://www.selco-intl.com
http://www.solarex.com/
Internal Combustion Engines
Caterpillar
Cooper Energy Services
Cummins Energy Company
Detroit Diesel
Honda
Jenbacher Energie-systeme AG
Kohler Generators
MAN B&W Diesel
SenerTec
Wartsila Diesel
Waukesha Engine
http://www.cat.com
http://www.cooperenergy.com
http://www.cummins.com
http://www.detroitdiesel.com
http://www.honda.com
http://www.jenbacher.com
http://www.kohlergenerators.com
http://www.manbw.dk
http://www.senertec.de
http://www.wartsila-nsd.com
http://www.waukeshaengine.com
Stirling Engines
BG Technology
SIG Swiss Industrial Company
Sigma Elektroteknisk A.S.
Solo Kleinmotoren GmbH
Stirling Technology Company
Stirling Technology, Inc.
Sunpower, Inc.
Tamin Enterprises
Whisper Tech Ltd.
http://www.bgtech.co.uk
http://www.sig-group.com
http://www.sigma-el.com
http://www.solo-germany.com
http://www.stirlingtech.com
http://www.stirling-tech.com
http://www.sunpower.com
http://www.tamin.com
http://www.whispertech.co.nz
Wind Turbines
Bergey WindPower
Bonus Energy A/S
http://www.bergey.com
http://www.bonus.dk
PUCT DG Interconnection Manual 05/01/02
A3-12
Dewind Technik
Ecotecnia
Enercon
Enron Wind
Gamesa Eolica
Mitsubishi Heavy Industries
NEG Micon
Nordex
Nordic Windpower
Vesta Wind Systems A/S
http://www.dewind.de
http://www.icaen.es/icaendee/ent/ecotech.
htm
http://www.enercon.de
http://www.wind.eneron.com
http://www.gamesa.es
http://www.mhi.co.jp
http://www.neg-micon.dk
http://www.nordex.dk
http://www.nwp.se
http://www.vestas.com
Controls
Encorp
GE Zenith Controls
Woodward Industrial Controls
http://www.encorp.com/
http://www.zenithcontrols.com/
http://www.woodward.com/
Combined Heat and Power
Asea Brown Boveri
http://www.abb.com
Inverters and Power Conditioning Systems
Advanced Energy Systems
http://www.advancedenergy.com/
AeroVironment
http://www.aerovironment.com/
Heart Interface
http://www.heartinterface.com/
Omnion Power Engineering
http://www.omnion.com/
Trace Engineering
http://www.traceengineering.com/
Trace Technologies
http://www.tracetechnologies.com/
MajorPower
http://www.majorpower.com/
California Energy Commission Inverter
http://www.energy.ca.gov/greengrid/certifie
Buy-down Program
d_inverters.html
Organizations
Distributed Power Coalition of America
PUCT DG Interconnection Manual 05/01/02
http://www.dpc.org/
A3-13
Appendix A4: Texas Utility Contacts
Updated November 1, 2000
Company Name
American Electric Power
Austin Energy
Bailey County Electric Cooperative
Association
Baird, City Of
Bandera Electric Cooperative, Inc.
Bartlett Electric Cooperative, Inc.
Bartlett, City Of (Bartlett Municipal Light
Department)
Bastrop, City Of (Bastrop Electric
Department)
Belfalls Electric Cooperative, Inc.
Bellville, City Of
Big Country Electric Cooperative, Inc.
(Midwest E. C.)
B-K Electric Cooperative, Inc. (See TriCounty E.C.)
Bluebonnet Electric Cooperative, Inc.
Boerne Utilities (Boerne, City Of)
Bowie Utilities (Bowie, City Of)
Bowie-Cass Electric Cooperative, Inc.
Brady Water & Light Works (Brady, City Of)
Brazos Electric Power Cooperative, Inc.
Brazos River Authority
Brenham, City Of
Bridgeport, City Of
Brownfield Power & Light
Brownsville Public Utilities Board
Btu, Rural Electric Division
Burnet Utilities (Burnet, City Of)
Caldwell, City Of
Canadian, City Of
Cap Rock Electric Cooperative, Inc.
PUCT DG Interconnection Manual 05/01/02
Telephone
918-594-4142
512-322-6514
806-272-4504
512-322-6037
806-272-4509
830-796-3741
254-527-3551
254-527-3557
830-460-3030
254-527-3221
254-527-4280
J.R. Vander Zee
Lawrence Karl
Mike Williams
512-321-3941
512-321-6684
Joann Wilcoxen
254-583-7955
409-865-3136
915-776-2244
254-583-7954
409-865-9485
915-776-2246
Joe Marek
John Mumme
Jerry L. Stapp
409-542-3151
830-249-9511
940-872-1114
903-846-2311
915-597-2152
254-750-6500
254-776-1441
409-836-7911
940-683-5906
806-637-4547
956-982-6260
409-821-5715
512-756-4858
409-567-3271
409-542-1187
830-249-9264
940-872-5702
903-846-2406
915-597-2068
254-750-6290
254-772-5780
409-836-7605
940-683-5995
806-637-9369
956-982-6269
409-821-5795
512-756-8560
409-567-9233
800-442-8688
915-684-0333
A4-1
Fax
Web Site
www.aep.com
www.electric.austin.tx.us
www.bluebon.net/bechome.html
www.bcec.com
Contact
Bernard Ross
Ed Clark
Duane Lloyd
David W. Peterson
Ronald C. Bowman
Ronnie Parkinson
W.D. Heldt
Gary Broz
Clifton B. Karnei
Gary Gwyn
Ron Bottoms
Doug Whitehead
Richard Fletcher
Don Ouchley
Dan Wilkerson
Johnny Sartain
William L. Broaddus
David W. Pruitt
Company Name
Castroville, City Of
Central And South West Corp. (See AEP)
Central Power & Light Company
Central Texas Electric Cooperative, Inc.
Cherokee County Electric Cooperative
Association
City Of Austin Electric Utility
City Public Service Of San Antonio
Cogen Power, Inc.
Coleman County Electric Cooperative, Inc.
Coleman, City Of
College Station, City Of
Comanche County Electric Cooperative
Association
Commerce, City Of
Community Public Service
Concho Valley Electric Cooperative, Inc.
Cooke County Electric Cooperative
Association
Coserv Electric (Formerly Denton County
E.C.)
Crosbyton, City Of
Cuero Electric Utility (Cuero, City Of)
Dallas Power And Light Company
Deaf Smith Electric Cooperative, Inc.
Deep East Texas Electric Cooperative, Inc.
Denton Municipal Utilities (Denton, City Of)
Dewitt County Electric Cooperative, Inc.
Dickens Electric Cooperative, Inc.
East Texas Electric Cooperative, Inc.
El Paso Electric Company
Electra, City Of (Electra Electric
Department)
Entergy Gulf States, Inc. (Gulf States
Utilities)
Erath County Electric Cooperative
Association
PUCT DG Interconnection Manual 05/01/02
Telephone
830-538-2224
918-594-4142
361-881-5300
830-997-2126
903-683-2248
361-881-5331
830-997-9034
903-683-5012
210-978-2000
210-978-3055
915-625-2128
915-625-5114
409-764-3688
800-915-2533
915-625-4600
915-625-5837
409-764-3452
915-356-3038
James C. Barr
David S. Sooter
J.C. Woody
Ronnie Robinson
915-655-695
800-962-0296
915-655-6950
940-759-2285
Alton Rollans
Philip E. Slater
800-274-4014
940-497-6525
361-275-6114
361-275-5655
John M. Trayhan
806-364-1166
409-275-2314
940-349-8487
361-275-2334
806-271-3311
409-560-9532
915-543-5951
940-495-2432
806-364-5481
409-275-2135
940-349-7334
361-275-5662
806-271-3746
409-560-9215
915-543-5711
940-495-3025
Steve Louder
Mike Elder
Sharon W. Mays
Jim Springs
Ron Golden
John H. Butts
James S. Haines, Jr.
Danny Neff
800-368-3749
409-827-5438
www.entergy.com
Joe Domino
254-965-3153
254-965-4387
www.erathelectric.com/
Zeb S. Deck Jr.
A4-2
Fax
830-538-9366
Web Site
www.aep.com
www.citypublicservice.com
www.dcec.com/
www.epelectric.com
Contact
Bruce A. Alexander
Bernard Ross
Gonzalo Sandoval
Robert A. Loth III
Greg Jones
Mrs. Jamie A.
Rochelle
Bill McGinnis
Company Name
Fannin County Electric Cooperative, Inc.
Farmers Electric Cooperative (Tx) (See Fec)
Farmers Electric Cooperative, Inc. Of New
Mexico
Farmersville, City Of
Fayette Electric Cooperative, Inc.
Fec Electric Cooperative, Inc.
Flatonia, City Of
Floresville Electric Light & Power System
Floydada, City Of
Fort Belknap Electric Cooperative, Inc.
Fredericksburg, City Of
Garland Power & Light System
Garrison Electric Department (Garrison, City
Of)
Gate City Electric Cooperative, Inc.
Georgetown Community Owned Utilities
Giddings, City Of
Golden Spread Electric Cooperative, Inc.
Goldsmith, City Of
Goldthwaite Utilities (Goldthwaite, City Of)
Gonzales, City Of (Gonzales Electric
System)
Granbury, City Of (Granbury Municipal
Electric Department)
Grayson-Collin Electric Cooperative, Inc.
Greenbelt Electric Cooperative, Inc.
Greenville Electric Utility
Guadalupe Valley Electric Cooperative, Inc.
Guadalupe-Blanco River Authority
Gulf States Utilities Company (See Entergy
Gulf States, Inc.)
Hall County Electric Cooperative (See
Lighthouse E.C.)
Halletsville Municipal Utilities (Halletsville,
City Of)
Hamilton County Electric Cooperative
Association
PUCT DG Interconnection Manual 05/01/02
Telephone
903-583-2117
Fax
903-583-7384
505-769-2116
505-769-2118
Lance Adkins
972-782-6151
800-874-8290
903-455-1715
361-865-3548
830-216-7000
806-983-2834
940-564-3526
830-997-7521
972-205-2650
409-347-2201
409-968-6752
903-455-8125
361-865-2817
830-393-0362
806-983-5542
940-564-3247
830-997-1861
972-205-2636
Alan Hein
Gary Don Nietsche
Lawson White
Doris Walker
David K. McMillan
Connie Galloway
Mark A. Stubbs
Jerry Bain
Robert E. Corder
Melvis Bell
940-937-2565
512-930-3555
409-542-2311
806-379-7766
915-827-3404
915-648-3186
830-672-2815
940-937-2698
512-930-3509
409-542-0950
806-374-2922
915-827-3404
915-648-2570
830-672-2813
James C. Driver
Jim Briggs
D. E. Sosa
Robert W. Bryant
Jean Lucas
Dale Allen
E.T. Gibson
817-573-1115
817-573-7678
Robert D. Brockman
903-482-5231
806-447-2536
903-457-2800
830-672-2871
830-379-5822
903-482-5906
806-447-2434
903-457-2893
830-672-9841
830-379-9718
David McGinnis
Stan McClendon
Tom Darte
Marcus W. Pridgeon
Bill West
361-798-3681
361-798-5324
Ervin Kolacny
254-386-3123
254-386-8757
John Hartgraves
A4-3
Web Site
Contact
Ronald G. Odom
Company Name
Harmon Electric Association, Inc.
Hearne Municipal Electric System (Hearne,
City Of)
Hemphill, City Of
Hempstead, City Of (Hempstead Electric
Department)
Hilco Electric Cooperative, Inc.
Hill County Electric Cooperative, Inc. (See
Hilco)
Hondo, City Of (Hondo Electric System)
Houston County Electric Cooperative, Inc.
Houston Lighting And Power Co. (See
Reliant Energy)
Hunt-Collin Electric Cooperative, Inc.(See
Cap Rock E.C.)
J-A-C Electric Cooperative, Inc.
Jackson Electric Cooperative, Inc.
Jasper Light & Power System (Jasper, City
Of)
Jasper-Newton Electric Cooperative, Inc.
Jcec (Johnson County Electric Cooperative)
Johnson County Electric (See Jcec)
Karnes Electric Cooperative, Inc.
Kaufman County Electric Cooperative, Inc.
Kerrville Public Utility Board
Kimble Electric Cooperative, Inc.
Kirbyville Light & Power Company
La Grange Utilities (La Grange, City Of)
Lamar County Electric Cooperative
Association
Lamb County Electric Cooperative, Inc.
Lampasas Public Utilities (Lampasas, City
Of)
Lea County Electric Cooperative, Inc.
Lexington, City Of (Lexington Municipal
Electric Department)
Liberty Municipal Electric System (Liberty,
City Of)
PUCT DG Interconnection Manual 05/01/02
Telephone
580-688-3342
409-279-3461
Fax
580-688-2981
409-279-2431
Web Site
Contact
Dwight Bowen
Robert Penney
409-787-2251
409-826-2486
409-787-2259
409-826-6703
Frank Coday
James Vines
254-687-2331
254-687-2428
Gerald W. Lemons
830-426-3378
409-544-5641
830-426-5189
409-544-4628
Rudy DeLeon
Edd Hargett
www.hlp.com
940-895-3311
361-782-7193
409-384-4651
940-895-3321
361-782-3252
409-384-3790
800-231-9340
817-556-4000
409-423-2264
817-556-4068
800-780-2347
830-780-2347
830-257-3050
915-446-2625
409-423-4659
409-968-3127
903-784-4303
830-257-8078
915-446-3482
409-423-3664
409-968-5743
903-784-7084
Bill Taylor
Hubert D'Spain
C. B. Herndon
Frank D. Menefee, Jr
Don McCaskill
806-385-5191
512-556-6831
806-385-5197
512-556-2074
Delbert Smith
Michael H. Talbot
505-396-3631
409-773-2221
505-396-3634
409-773-4878
Michael Dreyspring
Patrick Jatzlau
409-336-6872
409-336-9846
Don Ivy
A4-4
/www.ykc.com/jec/
Sarah Sears
Roy Griffin
Kerry Lacy
Fred Solly
Hollis E. Joslin
www.karnesec.org
Leroy T. Skloss
Company Name
Lighthouse Electric Cooperative, Inc.
Limestone County Electric Cooperative, Inc.
Livingston Municipal Electric System
(Livingston, City Of)
Llano Utilities (Llano, City Of)
Lockhart Utilities (Lockhart, City Of)
Lone Star Municipal Power Agency
Lone Wolf Electric Cooperative, Inc.
Lower Colorado River Authority
Lubbock Power & Light System (Lubbock,
City Of)
Luling Utilities (Luling, City Of)
Lyntegar Electric Cooperative, Inc.
Magic Valley Electric Cooperative, Inc.
Mason Utilities (Mason, City Of)
Mcculloch Electric Cooperative, Inc.
Mclennan COUNTY ELECTRIC
COOPERATIVE, INC.
Medina Electric Cooperative, Inc.
Mid-South Electric Cooperative Association
Mid-Tex Generation And Transmission
Electric Coop.
Midwest Electric Cooperative, Inc. (See Big
Country)
Moulton, City Of (Moulton Electric
Department)
Navarro County Electric Cooperative, Inc.
Navasota Valley Electric Cooperative, Inc.
New Braunfels Utilities (New Braunfels, City
Of)
New Century Energies
Newton Municipal Utilities (Newton, City Of)
North Plains Electric Cooperative, Inc.
Northeast Texas Electric Cooperative, Inc.
Nueces Electric Cooperative, Inc.
O'donnell Telephone Company, Inc.
PUCT DG Interconnection Manual 05/01/02
Telephone
806-983-2814
Fax
806-983-2804
409-327-4311
409-327-7784
Sam Gordon
915-247-4158
512-398-3461
915-247-4150
512-398-5103
Frank Salvato
Hector Garcia
C. B. Herndon
512-473-3200
806-775-2500
512-473-3298
806-775-3112
830-875-2481
806-998-4588
956-565-2451
915-347-6449
800-266-1774
254-840-2871
830-875-2038
806-998-4724
956-565-4182
915-347-5955
915-597-3307
254-840-4250
830-741-4384
409-825-5100
915-776-3909
830-426-2796
409-825-5166
915-776-2246
Larry Oefinger
Kenneth D. Camp
Jerry Stapp
361-596-4621
361-596-7075
Michael J. Slobojan
903-874-7411
800-443-9462
830-629-8400
903-874-8422
409-828-5563
830-629-8467
Billy J. Gillespie
James E. Calhoun
Paula J. DiFonzo
806-378-2121
806-378-2517
Bill D. Helton
409-379-4656
806-435-5482
903-757-3282
800-632-9288
409-379-5065
806-435-7225
903-757-3297
361-387-4139
Melvin Forward
Pat McAlister
Gary L. Dockham
John Sims
A4-5
Web Site
www.lcra.org
www.lotsofwatts.com
Contact
Billy C. Harbin
Joseph J. Beal
Derrell Oliver
Lamar Schulz
Wilton J. Payne
Bob Merett
Mark Hahn
Jeanagayle Behrens
Rick Haile
Company Name
Panola-Harrison Electric Cooperative, Inc.
Pedernales Electric Cooperative, Inc.
Pineland, City Of
Plains, City Of
Public Service Company Of Oklahoma
Telephone
903-935-0154
830-868-7155
409-584-2390
806-456-2288
918-599-2000
806-456-4341
918-599-2881
Rayburn Country Electric Cooperative, Inc.
Reliant Energy HL&P (Houston Lighting &
Power)
972-771-1336
713-207-6616
972-771-3046
713-207-9164
Rio Grande Electric Cooperative, Inc.
Rita Blanca Electric Cooperative, Inc.
Robertson Electric Cooperative
Robstown Utility System (Robstown, City
Of)
Rusk County Electric Cooperative, Inc.
Sabine River Authority
Sam Houston Electric Cooperative, Inc.
Sam Rayburn Dam Electric Cooperative,
Inc.
Sam Rayburn G & T Electric Cooperative,
Inc.
Sam Rayburn Municipal Power Agency
San Antonio City Public Service Board
San Augustine, City Of (San Augustine Light
& Water Dept.)
San Bernard Electric Cooperative, Inc.
San Marcos Electric Utility (San Marcos,
City Of)
San Miguel Electric Cooperative, Inc.
San Patricio Electric Cooperative, Inc.
830-563-2444
806-249-4506
830-563-2006
806-249-5620
Daniel G. Laws
Aubrey L. Neff
361-387-3554
361-387-9353
Ernest R. Gaza
903-657-4571
409-746-3200
800-458-0381
409-327-5711
903-657-5377
409-746-3749
409-328-1207
409-328-1207
Jesse Bankhead
Jerry L. Clark
H. E. Striedel
H.E. Striedel
409-560-9532
409-560-9215
John H. Butts
409-327-5303
409-327-7045
Bert B. Ogletree, Jr
409-275-2121
409-275-9146
Alton Shaw
409-865-3171
512-396-2541
409-865-9706
512-396-2683
John Q. Adams
Robert L. Higgs
830-784-3411
888-740-2220
830-784-3411
361-364-3467
915-372-5144
940-458-7930
409-743-4126
915-372-3989
940-458-4180
409-743-4760
830-379-3212
830-401-2499
Marshall B. Darby
F.D. "Buddy"
McDowell
Joe Ragsdale
Jeff Morris
Ronald G.
Brossmann
Douglas A. Faseler
940-888-3148
940-888-8882
Dick Wirz
San Saba, City Of
Sanger Electric System (Sanger, City Of)
Schulenburg, City Of (Schulenburg Utilities
Dept.)
Seguin Electric System (Seguin, City Of)
Sentry Power And Light Company, Inc.
Seymour, City Of
PUCT DG Interconnection Manual 05/01/02
A4-6
Fax
903-935-3361
830-868-4999
Web Site
www.rayburnelectric.com
www.hlp.com
Contact
Victor Schwartz, Jr.
Bennie Fuelberg
Gail Kilcrease
David Brunson
T.D. "Pete"
Churchwell
John Kirkland
Reginald Comfort
Company Name
Shiner Light & Water Utilities (Shiner, City
Of)
Smithville, City Of (Smithville Utilities Dept.)
South Plains Electric Coop. (Merged With
Dickens E.C.)
South Texas Electric Cooperative, Inc.
Southwest Arkansas Electric Cooperative
Corp.
Southwest Rural Electric Association, Inc.
Southwest Texas Electric Cooperative, Inc.
Southwestern (Nm) Electric Cooperative,
Inc.
Southwestern Electric Power Company
(Headquarters) (See AEP)
Southwestern Electric Power Company
(Texas Division) (See AEP)
Southwestern Electric Service Company
Southwestern Public Service
Stamford Electric Cooperative (See Big
Country)
Swisher Electric Cooperative, Inc.
Taylor Electric Cooperative, Inc.
Texas Electric Service Company
Texas Municipal Power Agency
Texas Power And Light
Texas Utilities Electric Company (TXU)
Texas-New Mexico Power Company
Tex-La Electric Cooperative Of Texas, Inc.
Timpson, City Of (Timpson Light & Water
Dept.)
Toledo Bend Project
Tri-County Electric Cooperative, Inc.
Trinity Valley Electric Cooperative, Inc.
Tulia Municipal Power & Light (Tulia, City
Of)
TXU (See Texas Utilities Electric Company)
Upshur-Rural Electric Cooperative, Inc.
Victoria Electric Cooperative, Inc.
PUCT DG Interconnection Manual 05/01/02
Telephone
361-594-3362
Fax
361-594-3566
Web Site
Contact
Norma Goetz
512-237-3267
806-775-7732
512-237-4549
806-775-7796
Bob Miller
J.C. Roberts
361-575-6491
501-772-2743
361-576-1433
David L. Grubbs
Wayne Whitaker
580-667-5281
915-853-2544
505-374-2451
580-667-5284
915-853-3141
505-374-2030
Ray Beavers
Jim Martin
Ann Garcia
918-594-4142
Bernard Ross
918-594-4142
Bernard Ross
214-812-4887
303-571-3542
214-741-5637
303-571-3524
John Barton
Lynn /worrell
800-530-4344
800-992-0086
806/995-2249
915/928-5216
Charles Castleberry
Tommie Cutler
409-873-2013
409-873-1183
Ed Wagoner
214-875-2643
817-731-0099
409-560-9632
409-254-2421
214-875-2953
817-377-5521
409-560-9215
www.txu.com
www.tnpe.com
Mike Murphy
Kevern R. Joyce
John H. Butts
Tommy Sparks
409-565-2273
817-444-3201
800-766-9576
806-995-3547
817-444-3542
972-932-6466
806-995-2331
Jim Washburn
A. Craig Knight
Jack Schwartz
Steve Stout
903-843-2536
361-573-2428
903-843-2736
361-573-5753
John C. Dugan
Winston Low
A4-7
Company Name
Waelder, City Of (Waelder Electric Dept.)
Weatherford Municipal Utility System
(Weatherford, City Of)
Weimar Electric Utilities (Weimar, City Of)
West Texas Municipal Power Agency
West Texas Utilities Company (See AEP)
Telephone
361-665-7331
817-598-4250
409-725-8554
806-767-2501
918-594-4142
409-725-8488
806-763-9711
Francis E. Parks
Ty Cooke
Bernard Ross
Western Farmers Electric Cooperative, Inc.
Wharton County Electric Cooperative, Inc.
Whitesboro Electric Utility (Whitesboro, City
Of)
Winters, City Of
Wise Electric Cooperative, Inc.
Wood County Electric Cooperative, Inc.
Yoakum, City Of
405-247-3351
409-543-6271
903-564-3311
405-247-4444
409-543-6259
903-564-6015
J. D. Pendergrass
Donald D. Naiser, PE
Charles Whitecotton
888-627-9326
903-763-4567
361-293-6321
940-627-6540
903-763-5693
361-293-3318
Loyd L. Jackson
Debbie Robinson
A. J. Veselka
PUCT DG Interconnection Manual 05/01/02
A4-8
Fax
817-598-4138
Web Site
Contact
Sandra Shows
J. R. Dickason
Appendix A5: Internet Links
This appendix is a compilation of links for the documents referenced throughout the
manual. It also includes the web addresses for all electric utility distribution companies
in Texas.
Public Utilities Commission of Texas
Web: www.puc.state.tx.us/
Texas’ Public Utility Regulatory Act (PURA) of 1999
www.puc.state.tx.us/rules/statutes/index.cfm
Substantive Rules - Chapter 25
www.puc.state.tx.us/rules/subrules/electric/index.cfm
§25.211 Interconnection of On-Site Distributed Generation
www.puc.state.tx.us/rules/subrules/electric/25.211/25.211.pdf
§25.212 Technical Requirements for Interconnection and Parallel Operation of On-Site
Distributed Generation
www.puc.state.tx.us/rules/subrules/electric/25.212/25.212.pdf
Institute of Electrical and Electronics
Engineers (IEEE)
Web: http://www.ieee.org
IEEE Standard 519.
http://standards.ieee.org/reading/ieee/std/staticp/519-1992.pdf
IEEE Standard 100
http://standards.ieee.org/reading/ieee/std/switchgear/C37.09g-1991.pdf
Reliability Standard 1366
http://standards.ieee.org/reading/ieee/std/td/1366-1998.pdf
PUCT DG Interconnection Manual 05/01/02
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Links for Electric Distribution Companies in Texas
Austin Energy
www.electric.austin.tx.us/
City Public Service Company of San Antonio
www.citypublicservice.com/
CSE- CPL, SWP &WTU Now AEP
WWW.AEP.COM
El Paso Electric Co.
www.epelectric.com
Entergy
www.entergy.com
Houston Lighting & Power Co.
www.hlp.com
LCRA
www.lcra.org
Texas-New Mexico Power
www.tnpe.com
TXU
www.txu.com
Texas Electric Cooperatives
www.texas-ec.org
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Appendix A6: Additional Safety and Performance References
The following standards may be useful in the specification, design, and evaluation of a
DG system. Many of these documents are the standards used by utilities to design and
operate the distribution system. While most are not necessary for designing the typical
DG interconnection, any of them may be relevant for a particular application. One or
more of these documents will likely provide the basis of a utility’s application rejection or
claim for additional requirements. In such cases, specific sections of applicable
documents should be referenced.
Secondary Safety and Performance standards for DG:
• ANSI/IEEE Std. 100-1996, IEEE Standard Dictionary of Electrical and Electronic
Terms
• ANSI/IEEE Std. 493-1900 IEEE Recommended Practice for Design of Reliable
Industrial and Commercial Power Systems (IEEE Gold Book).
• ANSI/IEEE Std. 1100-1992 IEEE Recommended Practice for Powering and
Grounding Sensitive Electronic Equipment (IEEE Emerald Book).
• ANSI/IEEE Std. 1159-1995 IEEE Recommended Practice for Monitoring Electric
Power Quality.
• ANSI/IEEE Std. 1250-1995 IEEE Guide for Service to Equipment Sensitive to
Momentary Voltage Disturbances. .
• ANSI/IEEE Std. C37.04 ANSI/IEEE Standard Rating Structure for AC Highvoltage Circuit Breakers Rated on a Symmetrical Current Basis
• ANSI/IEEE Std. C37.06 ANSI/IEEE Standard for AC High-voltage Circuit
Breakers Rated on Symmetrical Current Basis – Preferred Ratings and Related
Required Capabilities
• ANSI/IEEE Std. C37.108-1989 IEEE Guide for the Protection of Network
Transformers.
• ANSI/IEEE Std. C37.13 ANSI/IEEE Standard for Low-voltage AC Power Circuit
Breakers Used in Enclosures
• ANSI/IEEE Std. C37.14 ANSI/IEEE Standard for Low-voltage DC Power Circuit
Breakers Used in Enclosures
• ANSI/IEEE Std. C37.16 ANSI/IEEE Standard for Low-voltage Power Circuit
Breakers and AC Power Circuit Protectors – Preferred Ratings, Related
Requirements, and Application
• ANSI/IEEE Std. C37.18 ANSI/IEEE Standard Enclosed Field Discharge Circuit
Breakers for Rotating Electric Machinery
• ANSI/IEEE Std. C37.2 IEEE Standard Electrical Power System Device Function
Numbers
• ANSI/IEEE Std. C37.27 ANSI/IEEE Standard Application Guide for Low-voltage
AC Nonintegrally Fused Power Circuit Breakers (Using Separately Mounted
Current-Limiting Fuses)
• ANSI/IEEE Std. C37.29 ANSI/IEEE Standard for Low-voltage AC Power Circuit
Protectors Used in Enclosures
PUCT DG Interconnection Manual 05/01/02
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•
•
•
•
•
•
•
•
•
•
•
•
ANSI/IEEE Std. C37.50 ANSI Standard Test Procedures for Low-voltage AC
Circuit Breakers Use In Enclosures
ANSI/IEEE Std. C37.51 ANSI Standard Conformance Test Procedure for Metal
Enclosed Low-voltage AC Power Circuit-Breaker Switchgear Assemblies
ANSI/IEEE Std. C37.52 ANSI Standard Test Procedures for Low-voltage AC
Power Circuit Protectors Used in Enclosures
ANSI/IEEE Std. C37.95 IEEE Guide for Protective Relaying of Utility Consumer
Interconnections
ANSI/IEEE Std. C57.12 IEEE Standard General Requirements for Liquid
Immersed Distribution, Power and Regulating Transformers
ANSI/IEEE Std. C57.12.13 Conformance Requirements for Liquid Filled
Transformers Used in Unit Installations including Unit Substations.
ANSI/IEEE Std. C57.12.40-1994 American National Standard for Secondary
Network Transformers - Subway and Vault Types (Liquid Immersed) Requirements.
ANSI/IEEE Std. C57.12.44-1994 IEEE Standard Requirements for Secondary
Network Protectors.
ANSI/IEEE Std. C84.1-1995, Electric Power Systems and Equipment - Voltage
Ratings (60Hertz)
IEC 1000-3-3 Limitation of voltage fluctuations and flicker in low-voltage supply
systems for equipment with rated current less than 16A
IEC1000-3-5 Limitation of voltage fluctuations and flicker in low-voltage supply
systems for equipment with rated current greater than 16A
UL 1008 Transfer Switch Equipment
Other UL standards apply to distributed generation systems but do not directly address
interconnection safety. UL 2200 is the Standard For Safety for Stationary Engine
Generator Assemblies. These requirements cover stationary engine generator
assemblies rated 600 volts or less that are intended for installation and use in nonhazardous locations in accordance with NEC. These requirements do not cover
generators for use in hazardous locations, which is covered by the Standard for Electric
Motors and Generators for Hazardous (Classified) Locations, UL 674. These
requirements also do not cover uninterruptible power system (UPS) equipment, which
are covered by the Standard for Uninterruptible Power Supply Equipment, UL 1778.
Standards Organizations:
PUCT DG Interconnection Manual 05/01/02
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1 Batterymarch Park
Quincy, MA 02269-9101
Phone (617) 770-3000, Fax: (617) 770-0700
Web: http://www.nfpa.org
333 Pfingsten Road
Northbrook, IL 60062-2096
Underwriters Laboratories
Phone: (847) 272-8800, Fax: (847) 272(UL)
8129
Web: http://www.ul.com/
7800 Highway 20 West
Wyle Laboratories, Inc.
Huntsville, AL 35806
Phone: (256) 837-4411, Fax: (256) 7210144
Web: http:// www.wylelabs.com
445 Hoes Lane, PO Box 459
Institute of Electrical and
Piscataway, NJ 08855-0459
Electronics Engineers (IEEE)
Phone: (800) 678-4333
Web: http://www.ieee.org
1617 Cole Boulevard
National Renewable
Golden, CO 80401
Energy Laboratory
Phone: (303) 275-3000, Fax: (303) 275-4053
Web: http://www.nrel.gov
P.O. Box 5800, Division 6218
Sandia National
Laboratories,
Albuquerque, NM 87185
Photovoltaic Systems Phone: (505) 844-8161, Fax: (505) 844-6541
Web:
Assistance Center
http://www.sandia.gov/Renewable_Energy/photovolt
aic/pv.html
National Fire Protection
Association (NFPA)
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Appendix A7: Pre-Certification Requirements
02/01/01 Version
TEXAS PUBLIC UTILITY COMMISSION REQUIREMENTS FOR
PRE-CERTIFICATION OF DISTRIBUTED GENERATION EQUIPMENT
BY A NATIONALLY RECOGNIZED TESTING LABORATORY
PROJECT NO. 22318
PUBLIC UTILITY COMMISSION OF TEXAS
FEBRUARY 2001
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PUC PROJECT NO. 22318
REQUIREMENTS FOR PRE-CERTIFICATION OF DISTRIBUTED GENERATION
EQUIPMENT BY A NATIONALLY RECOGNIZED TESTING LABORATORY
TABLE OF CONTENTS
Page
A1
INTRODUCTION
A7-3
B1
DOCUMENTATION REQUIRED
A7-3
C1
TECHNICAL REQUIREMENTS
A7-4
D1
LABELING REQUIREMENTS
A7-7
TABLES OF CONTROL, PROTECTION, AND SAFETY EQUIPMENT
TABLE 1-VOLTAGE/FREQUENCY DISTURBANCE TRIP TIMES
TABLE 2-SINGLE-PHASE CONNECTED TO SECONDARY OR PRIMARY SYSTEM
TABLE 3-THREE-PHASE CONNECTED TO SECONDARY OR PRIMARY SYSTEM
PUCT DG Interconnection Manual 05/01/02
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A7-8
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A1
INTRODUCTION
According to Substantive Rule 25.211(k)(3) distributed generation units (DG packages) that are certified
to be in compliance by an approved testing facility or organization shall be installed on a company utility
system in accordance with an approved interconnection control and protection scheme without further
review of their design by the utility. To ensure that the pre-certified DG package is compatible with the
utility’s system, the utility shall determine the interconnection and control scheme required and shall
review and approve the electrical configuration for each DG installation. DG packages that have not
been pre-certified may still be interconnected subject to utility review in accordance with Substantive
Rules 25.211 and 25.212. Refer to Appendix 1. In this document, a DG package is defined as including
the generating unit, the protection and control system and generator breaker. This document does not
preclude on-site testing requirements defined in Substantive Rules 25.211 and 25.212.
A2
This document describes the test requirements for pre-certification of distributed generation (DG) that
will be interconnected to an electric utility distribution system in Texas. Pre-certified equipment is
defined by the Public Utility Commission of Texas (PUCT) Substantive Rule 25.211(c)(13) as “A
specific generating and protective equipment system or systems that have been certified as meeting the
applicable parts of this section relating to safety and reliability by an entity approved by the
commission.”
A3
The purpose of pre-certifying a DG package is to certify that the DG package design meets the minimum
technical requirements of PUCT substantive rules 25.211 and § 25.212 and forms, which are included in
Appendix 1 to this document.
A4
Section B contains the minimum documentation requirements for pre-certification of a DG package.
A5
Section C contains the capability requirements through type testing of DG packages described in the
technical requirements in PUCT Substantive rule §25.212. These requirements are intended to form the
basis for a set of specific minimum requirements for a DG package of a given size and configuration to
be “pre-certified” as defined in the rule.
A6
Section D contains additional labeling required of the commission-approved certifying entity, the
nationally recognized testing laboratory (NRTL).
B1
DOCUMENTATION REQUIRED
B2
The NRTL shall provide by whom and the date it has received its accreditation.
B3
The NRTL shall provide the effective date of pre-certification of each DG package and when recertification will be required.
B4
Package Description: The entity requesting pre-certification shall provide to the NRTL a complete
description of the DG package. The description shall include model numbers, sizes and ratings. The
description shall also include software or firmware versions and date of revision.
B5
Drawings: The entity requesting pre-certification shall provide to the NRTL a one-line diagram of the
DG package’s major components and all protective functions. Major components to be included as a
minimum are the generator, step-up or step-down transformer (if provided), switching device (e.g.,
circuit breaker), visible disconnect device, protective functions and control functions. The major
components listed here may be any combination of discrete devices and packaged devices.
B6
Applicable Standards: The NRTL shall provide in the pre-certification test report a description of all the
national or international standards applied in the pre-certification testing process.
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B7
Test Procedures: The NRTL shall provide in the pre-certification test report a description of all test
procedures applied in the pre-certification testing process. The description shall explain how each of the
requirements in PUCT Substantive Rule § 25.212 is met by the tests.
B8
Traces: The NRTL shall provide in the pre-certification test report waveform traces for voltage and
frequency tests. At a minimum, the traces shall show 15 cycles prior to and following the initiation of
the fault or abnormal condition, clearly indicating the interruption of current. A trace of the normal
output voltage waveform shall also be provided with the pre-certification test report.
C1
TECHNICAL REQUIREMENTS
C1.1
Technical requirements for DG installations as defined by PUCT Substantive Rule § 25.212 are divided
into three groups for purposes of this document.
C1.2
Equipment and Functions that shall be pre-certified:
In order for a DG package to be pre-certified, the NRTL shall verify that the DG package meets these
requirements under all reasonably expected operating and installation conditions. Example- the range of
operation for over and under voltage relays is stated and will be the same regardless of point of
interconnection.
C1.3
Equipment and Functions that may be pre-certified:
Certification of some equipment and functions may be of value, if included in the DG package, but are
not required under the Substantive Rules for an installation. Example - Monitoring capability.
C1.4
Equipment and Functions to be pre-certified for which there is not a standard to be met:
In addition, there are certain attributes of distributed generation technologies (see sections C4 and D) that
shall be quantified in the certification process. The resulting measured values shall be certified, but
certification of the DG package will not be contingent upon their meeting a standard or being within any
limits.
C1.5
All equipment outputs and functions will be tested as part of the pre-certification process. Each
numerical test value must be within the tolerance limits specified for a minimum of three tests. Tests
verifying specific functions will be performed through a minimum of 5 tests to verify that the unit
responds in the manner prescribed. Tests requiring waveform plots will be recorded in the NRTL’s
standard test format, and all waveform plots will be supplied with the test documentation. Tables 2 and 3
specify which of the specific requirements apply to the different sizes of DG package in order to be precertified.
C2
REQUIRED TESTS FOR EQUIPMENT AND FUNCTION PRE-CERTIFICATION:
C2.1
Rule 25.212 (b) (2): The customer's generator shall be equipped with protective hardware and
software designed to prevent the generator from being connected to a de-energized circuit owned
by the utility.
Rule 25.212 (b) (3): The customer's generator shall be equipped with the necessary protective
hardware and software designed to prevent connection or parallel operation of the generating
equipment with the utility system unless the utility system service voltage and frequency is of
normal magnitude.
Tests will be performed of the interconnection control logic to determine that closing of the generator
interconnection device will not occur when the utility voltage is outside of the ranges of normal
magnitude and frequency as specified in the Rules and shown in Table 1 below. Verification will be
obtained by attempting to close the generator interconnection contacts with a test voltage applied that is
106 % of the nominal voltage, again with a test voltage that is 89 % of nominal voltage, and with zero
voltage. Verification will also be obtained by attempting to close the generator interconnection contacts
with a test voltage applied that is of normal magnitude and frequency greater than 60.5 Hz but less than
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60.6 Hz and again with a test voltage of normal magnitude and frequency that is less than 59.3 Hz but
greater than 59.2 Hz.
Table 1: Voltage/Frequency Disturbance Delay & Trip Times
Range
Percentage
<70%
70%-90%
90% - 105%
105% - 110%
>110%
Delay to Trip and Trip Time
[1]
Seconds
Cycles[2]
0.166
10 (Delay) & 10 (Trip)
30.0 & 0.166
1800 (Delay) & 10 (Trip)
Normal Operating Range
30.0 & 0.166
1800 (Delay)& 10 (Trip)
0.166
10 (Delay) & 10 (Trip)
Voltage
<84
84 – 108
108 – 126
126 – 132
>132
Frequency (Hz)
<59.3
59.3 – 60.5
0.25
15 (Trip)
Normal Operating Range
>60.5
[1]
[2]
0.25
15 (Trip)
Voltage shown based on 120V, nominal.
Trip times for voltage excursions were added for completeness by the PUCT Project No. 22318 Precertification Working Group as the intent of 25.212.
C2.2
Rule 25.212 (c) (1): Voltage. The customer will operate its generating equipment in such a manner
that the voltage levels on the utility system are in the same range as if the generating equipment
were not connected to the utility's system. The customer shall provide an automatic method of
disconnecting the generating equipment from the utility system if a sustained voltage deviation in
excess of +5.0 % or –10% from nominal voltage persists for more than 30 seconds, or a deviation in
excess of +10% or –30% from nominal voltage persists for more than ten cycles.
The application of protective functions and disconnect devices in the design of the DG package will be
tested to determine that they will reliably disconnect the unit when the voltage at the point of common
coupling is outside the specified ranges for the specified maximum time periods. Refer to Table 1 above.
The DG package will be operated in an interconnected mode at normal frequency and voltage and then
the voltage will be adjusted to a level outside of the prescribed limits at a rate of change appropriate to
the test. The generator disconnect device will be verified as having opened and the current essentially
decayed to zero within the prescribed time limit.
C2.3
Rule 25.212 (c) (3): Frequency. The operating frequency of the customer's generating equipment
shall not deviate more than +0.5 Hertz (Hz) or –0.7 Hz from a 60 Hz base. The customer shall
automatically disconnect the generating equipment from the utility system within 15 cycles if this
frequency tolerance cannot be maintained.
The application of protective functions or disconnect devices in the design of the DG package will be
tested to determine that they will reliably operate to disconnect the unit when the frequency at the point
of common coupling is outside the specified ranges for the specified maximum time periods. Refer to
Table 1 above. The DG package will be operated in an interconnected mode at normal frequency and
voltage and then the frequency will be adjusted to a level outside of the prescribed limits at a rate of
change appropriate to the test. The generator disconnect device will be verified as having opened and the
current essentially decayed to zero within the prescribed time limit.
C2.4
Rule 25.212 (c) (4): Harmonics. In accordance with IEEE 519, the total harmonic distortion (THD)
voltage shall not exceed 5.0% of the fundamental 60 Hz frequency nor 3.0% of the fundamental
frequency for any individual harmonic when measured at the point of common coupling with the
utility system. Tests will be performed for the THD of the current waveform and harmonic current
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contribution from individual odd order harmonics “h” for 3 ≤ h ≤ 35. Measurements shall be made at
rated output into a simulated utility interconnection with a voltage distortion of less than 2 %.
C2.5
Rule 25.212 (c) (5): Fault and line clearing. The customer shall automatically disconnect from the
utility system within ten cycles if the voltage on one or more phases falls below -30% of nominal
voltage on the utility system serving the customer premises. This disconnect timing also ensures that
the generator is disconnected from the utility system prior to automatic re-close of breakers. See
requirements in Table 1 and C2.2 above.
C2.6
Rule 25.212 (e) (1): Three-phase synchronous generators. The customer's generator circuit
breakers shall be three-phase devices with electronic or electromechanical control. The customer
is solely responsible for properly synchronizing its generator with the utility. The excitation
system response ratio shall not be less than 0.5. The generator's excitation system(s) shall conform,
as near as reasonably achievable, to the field voltage versus time criteria specified in American
National Standards Institute Standard C50.13-1989 in order to permit adequate field forcing
during transient conditions.
A test of the generator breaker will be performed including assessment of its suitability as a disconnect
device with fault clearing capability consistent with the size and type of generating unit. The manual
control of the generator breaker and its automatic operation through the relay function requirements
contained in 25.211 and 25.212 shall be tested to be reliable and of quality design and workmanship.
Additionally, the excitation system voltage time response shall be determined based on a starting point of
full rated load output at unity power factor and rated terminal voltage with a step change to 75% of rated
terminal voltage (as seen by the excitation system control). The excitation system voltage response ratio
shall be determined based on the first half-second of this response and verified to be at least 0.5. In
addition, the field voltage versus time criteria specified in ANSI C50.13-1989 will be verified as having
been met.
C2.7
Rule 25.212 (e) (1): The customer is solely responsible for properly synchronizing its generator
with the utility.
A test of the synchronizing relay or other scheme may be performed including its design reliability and
control of the generator interconnect device. The synchronizing feature of the DG package shall be
tested by the NRTL to verify that the generator interconnect device will not close (allowing for breaker
closure time) until the DG has synchronized properly with the utility, using procedures acceptable to the
PUCT.
C2.8
Rule 25.212 (e) (2): Self-commutated inverters whether of the utility-interactive type or stand-alone
type shall be used in parallel with the utility system only with synchronizing equipment.
Inverter based outputs that use the utility power for startup shall be tested by the NRTL for impacts on
the utility system during start up to verify that the DG has synchronized properly with the utility, using
procedures acceptable to the PUCT.
C3
OPTIONAL TESTS FOR EQUIPMENT AND FUNCTION PRE-CERTIFICATION:
C3.1
Rule 25.212 (b) (8): The customer will furnish and install a manual disconnect device that has a
visual break that is appropriate to the voltage level (a disconnect switch, a draw-out breaker, or
fuse block), and is accessible to the utility personnel, and capable of being locked in the open
position.
A manual disconnect device if integrated in the DG package configuration shall be verified as providing
the necessary visible air gap suitable for the rated voltage. In addition, its configuration in the electrical
circuitry of the DG package shall be verified and the locking mechanism determined to be secure for use
with a padlock having a shank diameter of not more than 0.375 inches and also suitable for wire or
plastic tags.
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C3.2
Rule 25.212 (c) (5): To enhance reliability and safety and with the utility's approval, the customer
may employ a modified relay scheme with delayed tripping or blocking using communications
equipment between the customer and the utility company.
The DG package design and wiring shall be reviewed and tested to determine the type of input required
to prevent tripping of the generator breaker under specific conditions. The design shall be certified as to
which relay functions can be selected and the range of time delay or full blocking. In addition, the
interface such as contacts, RTU protocol or some other communications shall be verified.
C3.3
Rule 25.212 (e) (3) (C): If the facility is exporting power, the power direction protective function
may be used to block or delay the under frequency trip with the agreement of the utility.
The DG package design and wiring shall be reviewed and tested to determine that the under frequency
relay function may be disabled based on an auxiliary input from the point of common coupling.
C4
TESTS FOR EQUIPMENT AND FUNCTION PRE-CERTIFICATION FOR WHICH THERE IS
NOT A STANDARD TO BE MET:
C4.1
Verify maximum continuous electrical output at ISO conditions for DG units. Tests will be performed at
test site conditions and calculated to ISO conditions.
C4.2
Verify maximum emergency output at ISO conditions for DG units, if available. Tests will be performed
at test site conditions and calculated to ISO conditions.
C4.3
Fuel conversion efficiency expressed in percentage or as a heat rate at maximum continuous output and
at 50 % and 75 % of maximum continuous output. Tests will be performed at test site conditions and
calculated to ISO conditions.
C4.4
Audible (20 Hz to 20 kHz) noise level in dBa measured at 1 meter and 10 meters from the unit.
C4.5
Stack emissions of NOX, SOX and CO2 measured in parts per million measured at maximum continuous
output and ISO conditions. Tests will be performed at test site conditions and calculated to ISO
conditions.
C4.6
Maximum leading and maximum lagging power factor at rated output power and voltage.
C4.7
Maximum fault current interrupting capability of the generator main power circuit breaker at rated
voltage.
C4.8
The generator rated maximum short circuit current output for 3-phase and phase-to-ground faults will be
verified for non-inverter output based DG packages. Modeling of machine parameters and computation
of fault current levels shall be acceptable for units with short circuit duties that could be damaging to the
unit. Equipment that is part of the DG package that could have an impact on short circuit duty such as
grounding resistors and excitation systems shall also be documented. Measured or calculated fault
current magnitudes shall be for one-half cycle after the fault is applied.
D1
LABELING REQUIREMENTS
D1.1
The results from the tests of the functionality of the requirements in Sections C4.1, C4.2, C4.3, C4.4, and
C4.5 must be shown on a label sufficiently durable for outdoor use to be affixed on each DG package as
applicable.
Labeling shall specify that the DG package has been pre-certified in compliance with PUCT Substantive
Rules 25.211 and 25.212.
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TABLES: The following Tables 2 and 3 outline the specific functional requirements for different types
and sizes of DG packages as indicated by "X". References are to paragraphs in this
document.
TABLE 2
Control, Protection and Safety Equipment1,3
Single-Phase Connected to Secondary or Primary System
Generator Size
Interconnect Disconnect Device
Generator Disconnect Device
Over-Voltage Trip
Under-Voltage Trip
Over/Under Frequency Trip
Synchronizing Check2
Reference
50 kW or Less
C2.1
C2.1
C2.2
C2.2
C2.3
C2.7
X
X
X
X
X
Manual or Automatic
Notes:
1. See the OEM Control, Protection and Safety Equipment Guidelines publication for discussion
and one-lines for acceptable installations.
2. For synchronous and other type of generators with stand-alone capability.
3. Exporting to the host electrical utility system may require additional operational/protection
devices and will require coordination of operations with the utility.
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TABLE 3
Control, Protection and Safety Equipment1,6
Three-Phase Connected to Secondary or Primary System
Generator Size
Ref.
Interconnect Disconnect Device
Generator Disconnect Device
Over-Voltage Trip
Under-Voltage Trip
Over/Under Frequency Trip
Ground Over-Voltage Trip
Or
Ground Over-Current Trip7
2
Synchronizing Check
C2.1
C2.1
C2.2
C2.2
C2.3
10 kW or less
11 500 kW
501 2,000 kW
2,001 10,000 kW
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Manual or
Automatic
Automatic
Automatic
X
X4
X4
X
X
X
X
X
C2.5
C2.7, C2.8
Manual or
Automatic
Power Direction3
C3.3
Telemetry/transfer Trip
C3.2
X5
Automatic Voltage
Regulation (AVR)2
C2.6
X
Notes:
1. See the OEM Control, Protection and Safety Equipment Guidelines publication for discussion
and one-line diagrams for acceptable installations.
2. For synchronous and other type of generators with stand-alone capability.
3. If NOT exporting and generator is less than minimum load of the customer, or if always
exporting, then not required except as noted.
4. If exporting, blocks under-frequency trip with agreement of host utility.
5. May be required as part of a transfer tripping/blocking protective scheme.
6. Exporting to the host electrical system may require additional operational/protection devices
and will require coordination of operations with the host utility.
7. Selection depends on grounding system, if required by host utility.
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REVISIONS TO THE MANUAL
Date of
Revision
01-25-01
Description
Revised Table 3-1 to add trip times and label delay and trip times; revised Table 1 in
Pre-certification Requirements to make consistent with Table 3-1 in manual.
02-01-01
Revised C2.1 in Pre-certification Requirements document change test voltages from
89.9% to 89% and from 105.1% to 106% after late comments received on 01-26-01.
02-23-01
Added credit to the U.S. Dept. of Energy Office of Energy Efficiency and Renewable
Energy on the cover sheet and on the Introduction page.
03-15-01
Deleted “retail electric customer,” from last sentence of first paragraph of Chapter
5.1.
05-05-02
Edited the contacting person for the electric division on page 8-1 from Ed Ethridge
to Tony Marciano at 512-936-7356.
01-31-07
Added Wyle Laboratories, Inc. to page A6-3.
PUCT DG Interconnection Manual 05/01/02
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A7-11
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