North American electric power utilities account for more than one quarter of the world total for spending related to substation automation and integration (A&I) programs. Newton-Evans Research estimates the current annual global spending for substation automation and integration programs at about $550-600 million, with an overall potential market size of nearly $40 billion. The year-end 2005 study has found that 76% of the North American utility respondents indicated having a substation automation and integration strategy in place.
Ranking of Importance of “Potential Obstacles” to Implementing Substation Automation for New and Existing (Retrofit) Substations:
New Substations - The lack of appropriate communications technology (substation to substation) and the fact of not enough skilled internal staff were the leading “potential obstacles” to substation A&I program investments. Lack of funding was especially important for investor-owned utilities and for Canadian utilities.
Existing (Retrofit) Substations - For retrofit substations, the biggest obstacles reported were lack of funding and benefits/costs perceptions. This finding was reported by IOUs, public power utilities and Canadian utilities. Cooperatives were more likely to be concerned with the benefits, but concerns over substation communications were strong as well.
Spending Estimates for New and Retrofit Substation Automation Programs between 2005-2007:
North American utilities reported significantly increased plans for spending on substation automation-related programs from earlier studies. The total of about $155 million is more than double the amounts reported as available for substation automation spending in the 2002 study. Again this year, IOUs in the US and Canada dominated spending plans, but the other utility groups also plan to spend in the millions of dollars ranges. Plans for spending on retrofit substations for the next five years (192 million dollars) outpaced plans for similar spending on new substations over the same five year period (177 million dollars).
Approach to Obtaining Substation Automation Systems and Equipment:
Forty-six percent of the North American utilities indicated that they bought from “Best in Class” suppliers of individual substation equipment for A&I programs. Nine percent indicated purchases only from larger suppliers active in the market. Over one third (34%) reported buying equipment only, and then integrating the equipment internally. Thirteen others reported use of consultants to develop a comprehensive substation A&I plan. Only three reported purchasing directly from substation system integrators.
Current and Planned Use of Protocols Within the Substation:
Just about three quarters of the North American utility respondents cited current use of DNP3.0 (Serial) and nearly one quarter indicated use of DNP 3.0 (LAN). None of the current international standard IEC protocols was cited by any utilities as being in use by August 2005. There were some plans to use IEC 61850 by 2007 (six percent). Modbus and Modbus Plus remain strong, with 37% citing some use of Modbus (serial) and 22% citing use of Modbus Plus.
Current and Planned Use of Protocols from the Substation to An External Host:
One half of the group was using DNP 3.0 and 22% had moved on to DNP 3.0 LAN. There was only minimal use of any other protocol listed, while several write-ins of older legacy proprietary protocols were still popular. Among these were: ACS, CDC, Conitel, L&G/Telegyr, QUICS and Tejas/Valment/Metso protocols. Current users of DNP serial were by and large planning to migrate to the LAN version of DNP. Officials indicated that for the most part (81%) they were using standard versions of protocols, while 18% were using both tailored and standard versions of communications protocols. Fewer than ten percent of the North American utility substation officials indicated that they were encrypting data transmissions (or protocols) used in substation communications.
Current and Planned Choices of Physical Links and Media from the Substation to External Hosts/Networks:
Over one half of the respondents indicated at least some use of fiber or synchronous optical network linkages. Forty-three percent continue to rely on leased lines, while 40% cited use of MAS radio, and 38% were using microwave. Importantly, IOUs are the subgroup most likely to use at least some telephony in their comms media mix. IOUs were also planning to use some frame relay and microwave, more than other subgroups.
Number of Ethernet Ports Available in a Typical Substation:
Thirty-six officials indicated that no Ethernet ports were typically available in their T&D substations. Of those who did indicate having such ports available, the nominal midpoint was 8 ports, with a few having either 24 or 48 ports. Eighty percent of the respondents to this question indicated that their substation Ethernet ports were in fact secured. Two thirds of those who had indicated secure ports stated that they were secured via port security methods, while 19 said “other” methods were being used. Other methods included: NMS, authentication, OP addressing, firewalls, and passwords.
Number of Simultaneous Wireless Connections Allowed in the Substation:
Forty-four of 74 respondents indicated that they allow “no” simultaneous wireless connections in their substations. Fifteen said that one or two were permitted. The need for simultaneity seems to be more apparent when the substation data is required by two or more entities (utilities, utility-ISO/RTO, utility engineering/ utility operations).
Use of Modems in the Substation Communications Schema:
Twenty-two percent of the 97 respondents indicated no use of modems. This was especially likely among public power utilities. IOUs were very likely to be using at least some modems. Most of the modem users were using at least some hardwired modems (97%), while 12% were also using some cellular modems and seven percent were using other forms of wireless modems.
Security of Remote Connections (Such as Modems, Wireless Connections):
Fifty-nine percent of the 96 respondents to this question indicated that their remote connections were secured, while 41% admitted using unsecured connections. Only 37 of the 57 users who cited having secure connections indicated having ALL of their connections secured. Only 19% of the 96 responding utility officials indicated that they encrypted or otherwise protected communications in remote connections. Eighty-one percent admitted to using unsecured communications in their remote connections. Only one third of the utilities were making use of routable paths to their end devices. Most (77%) of those utilities using routable paths were also monitoring the pathing.
Current and Planned Choice of Communications Architecture within and to the Substation:
Within the Substation - By and large, serial links continue to be widely used in North American substations in mid-2005, regardless of the type of utility operating the substation. LAN usage is found in substations operated by 42% of the respondent sites. There was minimal use of and minimal plans for VSATs and WANs in the substations of North America, based on the study findings.
To the Substation - Current communications architecture to and from the substation was still likely to be serial links, but the use of WANs has increased from earlier Newton-Evans studies. Plans call for even more use of WAN architecture over the next few years, followed at a distance by increased uses of LANs.
Current and Planned Handling of Primary Substation Information Processing Tasks “Inside the Fence”:
By late 2005, smart RTUs were prevalent in North American substations, with dumb RTUs next. PLC use was acknowledged by 26% of the group. PC use in substations had reached 20%. Dumb RTUs were still in use at least in some substations among 53% of Canadian utilities and one half of the responding electric cooperatives.
Current and Planned Connectivity of Substations to Other Utility Systems:
Across the industry, utility SCADA or EMS systems led the way with 93% indicating links from substations back to these systems. Smart feeder devices were mentioned by 41% of the group, and protection engineering by 36%. Plans centered around establishing some degree of linkage capability from the substation to the corporate WAN, to GIS systems and to trouble call, protection engineering and maintenance, but all of these plans were below 20% mention rates.
External Assistance Needed for Various Substation Automation Activities:
This question was asked to gain insight into what types of services could be provided by third-party firms, whether they are specialist service firms, or equipment or systems suppliers, into the substation marketplace. By mid-2005, utilities were indicating a need for training assistance (42%), for IED configuration support (34%) and for engineering drawing support (31%). These rates exceed the demand seen in earlier Newton-Evans studies.
Level of Current and Planned Automation Indicated for Transmission and Distribution Substations:
The respondents included 81 transmission utilities and 95 utilities with distribution substation assets. Together, these utilities accounted for about 35% of T&D substations in North America. Respondents were requested to indicate whether their transmission and distribution substations were not at all automated, or whether they had one of four stages of automation. These four stages were identified as:
Stage 1 - IED implementation; substation has IEDs installed - no integration
Stage 2 - IED integration; installed IEDs are integrated, utilizing 2-way communications capability and NO substation LAN
Stage 3 - IED integration; installed IEDs are integrated, utilizing 2-way communications capability and/or substation LAN
Stage 4 - Applications are run at the substation level to automate various substation functions.
In this study, 7,031 substations were classified by respondents as transmission voltage substations. Another 18,938 units were classified as distribution voltage substations. There were plans in place to construct 223 new transmission voltage substations over the 2005-2007 periods, and an additional 725 new distribution class substations were also planned. The Newton-Evans estimate of total North American utility operated T&D substations is some 64000 units, with non-utility operated substations hovering in the 6,500-8,000 unit range.
Specific Equipment Types in Use and Planned for Use in Conjunction with Substation Automation Programs:
Transmission Substations - Seventy-five utility officials took the time to indicate which of 15 specific equipment types were or were planned to be part of their utility’s transmission substation-wide automation programs. RTUs, digital relays, redundant protection schemes and digital fault recorders were all indicated by more than one half of the respondents as component parts of their utility substation automation programs.
Distribution Voltage Substations - Ninety-two officials provided information on the equipment types being used or planned for use in conjunction with distribution substation automation programs. In distribution substations, RTUs, digital relays and LTC transformers were indicated as the most widely used components in automation and integration programs.
Voltage Ranges Used to Power Substation Automation Equipment:
Respondents were requested to indicate the most used voltage ranges to power substation automation equipment in the substations operated by the utilities. Range choices were: 110 or 200 VAC, <24 VDC, 24 to 48 VDC, 72 to 125 VDC, and >125 VDC.
Based on the North American utility responses, the most frequently used voltage ranges used to power T&D substation automation equipment were: 72-125 VDC followed by 24-48 VDC.
Current and Planned Use of Substation Security Measures:
Seven optional responses were listed in this question on substation security methods and practices. Utilities were asked to indicate whether they were using or had plans to use any of the following: encryption of RTU communications, password protection for IEDs, video camera surveillance, improved intrusion detection, secure facilities, eye/fingerprint identification, and limited accessibility to substation-related keys.
Three security measures stand out from the group as having been implemented by mid-2005. These included two physical measures and one cyber measure. First, limited accessibility to substation-related keys; secondly, secure substation facilities (locked building and enclosures); and thirdly, password protection for access to intelligent electronic devices. Plans for adding additional security by 2007 include: improved intrusion detection, deployment of camera surveillance and encryption of RTU communications.
Additional Observations Gleaned from the Study:
• The years 2002-2004 were slow growth - or no growth - years in most categories of intelligent electronic equipment sales related to the modern, increasingly digital, electric power substation. Few retrofit programs were undertaken except for the most critical of substations.
• Increasingly, it is becoming more difficult to separate substation product classifications as manufacturers tout their platforms as "multifunctional" and the product positioning of many electronic devices now cuts across multiple product classifications.
• Newton-Evans further estimates that only about 12% of utility operated substations have been fully automated and integrated by year end 2005. Most of these are in fact newly or recently constructed substations.
• Most substation equipment manufacturers (mid size and smaller companies) and integrators surveyed in the second half of 2005 have indicated some moderate-to-good growth market conditions within their utility sales sectors, resulting in sales that are as much as 5% to 15% higher than 2003 or 2004 sales levels.
• Economic growth has continued in many electricity dependent sectors. In turn, this spurs demand for increased electric power, and increasingly reliable power. This results in internal planning for infrastructure and automation programs.
• There remains some concern in the industry about the dearth of skilled engineering resources due to retirements and layoffs. This may further impact the ability of technology supplier companies to engage utilities for other than short-term requirements. However, third party engineering and integration service firms are now making significant strides in winning substation automation-related business from planning to design to construction.
• If distributed generation activities continue to increase across the world, there is some positive benefit that will occur for the substation automation, integration and retrofit business, as utilities become more involved with DG efforts.
• In summary, retrofit substations will be upgraded as warranted, based on load growth, criticality to customers, and development of DG programs. New substations will increasingly be designed and constructed as integrated and automated remote assets for the utility.
• Protocol use and plans among North American electric power utilities continue to differ from the trends among utilities in the international communities. North American utilities continue to strongly support DNP 3, and will likely migrate to a LAN version of this protocol. See the comparative charts at the end of the release.
• International utilities tend to use IEC protocols. Currently, the 60870-5-103 protocol is popular, especially in Europe, while migration to IEC 61850 is underway in Europe, the Middle East and Africa, and among some of the largest utilities elsewhere. Nonetheless, Latin American and Asian Pacific utilities report strong use of Modbus and Asia-Pacific utilities tend to align themselves more with DNP 3 at the present time.
Ranking of Importance of “Potential Obstacles” to Implementing Substation Automation for New and Existing (Retrofit) Substations:
New Substations - The lack of appropriate communications technology (substation to substation) and the fact of not enough skilled internal staff were the leading “potential obstacles” to substation A&I program investments. Lack of funding was especially important for investor-owned utilities and for Canadian utilities.
Existing (Retrofit) Substations - For retrofit substations, the biggest obstacles reported were lack of funding and benefits/costs perceptions. This finding was reported by IOUs, public power utilities and Canadian utilities. Cooperatives were more likely to be concerned with the benefits, but concerns over substation communications were strong as well.
Spending Estimates for New and Retrofit Substation Automation Programs between 2005-2007:
North American utilities reported significantly increased plans for spending on substation automation-related programs from earlier studies. The total of about $155 million is more than double the amounts reported as available for substation automation spending in the 2002 study. Again this year, IOUs in the US and Canada dominated spending plans, but the other utility groups also plan to spend in the millions of dollars ranges. Plans for spending on retrofit substations for the next five years (192 million dollars) outpaced plans for similar spending on new substations over the same five year period (177 million dollars).
Approach to Obtaining Substation Automation Systems and Equipment:
Forty-six percent of the North American utilities indicated that they bought from “Best in Class” suppliers of individual substation equipment for A&I programs. Nine percent indicated purchases only from larger suppliers active in the market. Over one third (34%) reported buying equipment only, and then integrating the equipment internally. Thirteen others reported use of consultants to develop a comprehensive substation A&I plan. Only three reported purchasing directly from substation system integrators.
Current and Planned Use of Protocols Within the Substation:
Just about three quarters of the North American utility respondents cited current use of DNP3.0 (Serial) and nearly one quarter indicated use of DNP 3.0 (LAN). None of the current international standard IEC protocols was cited by any utilities as being in use by August 2005. There were some plans to use IEC 61850 by 2007 (six percent). Modbus and Modbus Plus remain strong, with 37% citing some use of Modbus (serial) and 22% citing use of Modbus Plus.
Current and Planned Use of Protocols from the Substation to An External Host:
One half of the group was using DNP 3.0 and 22% had moved on to DNP 3.0 LAN. There was only minimal use of any other protocol listed, while several write-ins of older legacy proprietary protocols were still popular. Among these were: ACS, CDC, Conitel, L&G/Telegyr, QUICS and Tejas/Valment/Metso protocols. Current users of DNP serial were by and large planning to migrate to the LAN version of DNP. Officials indicated that for the most part (81%) they were using standard versions of protocols, while 18% were using both tailored and standard versions of communications protocols. Fewer than ten percent of the North American utility substation officials indicated that they were encrypting data transmissions (or protocols) used in substation communications.
Current and Planned Choices of Physical Links and Media from the Substation to External Hosts/Networks:
Over one half of the respondents indicated at least some use of fiber or synchronous optical network linkages. Forty-three percent continue to rely on leased lines, while 40% cited use of MAS radio, and 38% were using microwave. Importantly, IOUs are the subgroup most likely to use at least some telephony in their comms media mix. IOUs were also planning to use some frame relay and microwave, more than other subgroups.
Number of Ethernet Ports Available in a Typical Substation:
Thirty-six officials indicated that no Ethernet ports were typically available in their T&D substations. Of those who did indicate having such ports available, the nominal midpoint was 8 ports, with a few having either 24 or 48 ports. Eighty percent of the respondents to this question indicated that their substation Ethernet ports were in fact secured. Two thirds of those who had indicated secure ports stated that they were secured via port security methods, while 19 said “other” methods were being used. Other methods included: NMS, authentication, OP addressing, firewalls, and passwords.
Number of Simultaneous Wireless Connections Allowed in the Substation:
Forty-four of 74 respondents indicated that they allow “no” simultaneous wireless connections in their substations. Fifteen said that one or two were permitted. The need for simultaneity seems to be more apparent when the substation data is required by two or more entities (utilities, utility-ISO/RTO, utility engineering/ utility operations).
Use of Modems in the Substation Communications Schema:
Twenty-two percent of the 97 respondents indicated no use of modems. This was especially likely among public power utilities. IOUs were very likely to be using at least some modems. Most of the modem users were using at least some hardwired modems (97%), while 12% were also using some cellular modems and seven percent were using other forms of wireless modems.
Security of Remote Connections (Such as Modems, Wireless Connections):
Fifty-nine percent of the 96 respondents to this question indicated that their remote connections were secured, while 41% admitted using unsecured connections. Only 37 of the 57 users who cited having secure connections indicated having ALL of their connections secured. Only 19% of the 96 responding utility officials indicated that they encrypted or otherwise protected communications in remote connections. Eighty-one percent admitted to using unsecured communications in their remote connections. Only one third of the utilities were making use of routable paths to their end devices. Most (77%) of those utilities using routable paths were also monitoring the pathing.
Current and Planned Choice of Communications Architecture within and to the Substation:
Within the Substation - By and large, serial links continue to be widely used in North American substations in mid-2005, regardless of the type of utility operating the substation. LAN usage is found in substations operated by 42% of the respondent sites. There was minimal use of and minimal plans for VSATs and WANs in the substations of North America, based on the study findings.
To the Substation - Current communications architecture to and from the substation was still likely to be serial links, but the use of WANs has increased from earlier Newton-Evans studies. Plans call for even more use of WAN architecture over the next few years, followed at a distance by increased uses of LANs.
Current and Planned Handling of Primary Substation Information Processing Tasks “Inside the Fence”:
By late 2005, smart RTUs were prevalent in North American substations, with dumb RTUs next. PLC use was acknowledged by 26% of the group. PC use in substations had reached 20%. Dumb RTUs were still in use at least in some substations among 53% of Canadian utilities and one half of the responding electric cooperatives.
Current and Planned Connectivity of Substations to Other Utility Systems:
Across the industry, utility SCADA or EMS systems led the way with 93% indicating links from substations back to these systems. Smart feeder devices were mentioned by 41% of the group, and protection engineering by 36%. Plans centered around establishing some degree of linkage capability from the substation to the corporate WAN, to GIS systems and to trouble call, protection engineering and maintenance, but all of these plans were below 20% mention rates.
External Assistance Needed for Various Substation Automation Activities:
This question was asked to gain insight into what types of services could be provided by third-party firms, whether they are specialist service firms, or equipment or systems suppliers, into the substation marketplace. By mid-2005, utilities were indicating a need for training assistance (42%), for IED configuration support (34%) and for engineering drawing support (31%). These rates exceed the demand seen in earlier Newton-Evans studies.
Level of Current and Planned Automation Indicated for Transmission and Distribution Substations:
The respondents included 81 transmission utilities and 95 utilities with distribution substation assets. Together, these utilities accounted for about 35% of T&D substations in North America. Respondents were requested to indicate whether their transmission and distribution substations were not at all automated, or whether they had one of four stages of automation. These four stages were identified as:
Stage 1 - IED implementation; substation has IEDs installed - no integration
Stage 2 - IED integration; installed IEDs are integrated, utilizing 2-way communications capability and NO substation LAN
Stage 3 - IED integration; installed IEDs are integrated, utilizing 2-way communications capability and/or substation LAN
Stage 4 - Applications are run at the substation level to automate various substation functions.
In this study, 7,031 substations were classified by respondents as transmission voltage substations. Another 18,938 units were classified as distribution voltage substations. There were plans in place to construct 223 new transmission voltage substations over the 2005-2007 periods, and an additional 725 new distribution class substations were also planned. The Newton-Evans estimate of total North American utility operated T&D substations is some 64000 units, with non-utility operated substations hovering in the 6,500-8,000 unit range.
Specific Equipment Types in Use and Planned for Use in Conjunction with Substation Automation Programs:
Transmission Substations - Seventy-five utility officials took the time to indicate which of 15 specific equipment types were or were planned to be part of their utility’s transmission substation-wide automation programs. RTUs, digital relays, redundant protection schemes and digital fault recorders were all indicated by more than one half of the respondents as component parts of their utility substation automation programs.
Distribution Voltage Substations - Ninety-two officials provided information on the equipment types being used or planned for use in conjunction with distribution substation automation programs. In distribution substations, RTUs, digital relays and LTC transformers were indicated as the most widely used components in automation and integration programs.
Voltage Ranges Used to Power Substation Automation Equipment:
Respondents were requested to indicate the most used voltage ranges to power substation automation equipment in the substations operated by the utilities. Range choices were: 110 or 200 VAC, <24 VDC, 24 to 48 VDC, 72 to 125 VDC, and >125 VDC.
Based on the North American utility responses, the most frequently used voltage ranges used to power T&D substation automation equipment were: 72-125 VDC followed by 24-48 VDC.
Current and Planned Use of Substation Security Measures:
Seven optional responses were listed in this question on substation security methods and practices. Utilities were asked to indicate whether they were using or had plans to use any of the following: encryption of RTU communications, password protection for IEDs, video camera surveillance, improved intrusion detection, secure facilities, eye/fingerprint identification, and limited accessibility to substation-related keys.
Three security measures stand out from the group as having been implemented by mid-2005. These included two physical measures and one cyber measure. First, limited accessibility to substation-related keys; secondly, secure substation facilities (locked building and enclosures); and thirdly, password protection for access to intelligent electronic devices. Plans for adding additional security by 2007 include: improved intrusion detection, deployment of camera surveillance and encryption of RTU communications.
Additional Observations Gleaned from the Study:
• The years 2002-2004 were slow growth - or no growth - years in most categories of intelligent electronic equipment sales related to the modern, increasingly digital, electric power substation. Few retrofit programs were undertaken except for the most critical of substations.
• Increasingly, it is becoming more difficult to separate substation product classifications as manufacturers tout their platforms as "multifunctional" and the product positioning of many electronic devices now cuts across multiple product classifications.
• Newton-Evans further estimates that only about 12% of utility operated substations have been fully automated and integrated by year end 2005. Most of these are in fact newly or recently constructed substations.
• Most substation equipment manufacturers (mid size and smaller companies) and integrators surveyed in the second half of 2005 have indicated some moderate-to-good growth market conditions within their utility sales sectors, resulting in sales that are as much as 5% to 15% higher than 2003 or 2004 sales levels.
• Economic growth has continued in many electricity dependent sectors. In turn, this spurs demand for increased electric power, and increasingly reliable power. This results in internal planning for infrastructure and automation programs.
• There remains some concern in the industry about the dearth of skilled engineering resources due to retirements and layoffs. This may further impact the ability of technology supplier companies to engage utilities for other than short-term requirements. However, third party engineering and integration service firms are now making significant strides in winning substation automation-related business from planning to design to construction.
• If distributed generation activities continue to increase across the world, there is some positive benefit that will occur for the substation automation, integration and retrofit business, as utilities become more involved with DG efforts.
• In summary, retrofit substations will be upgraded as warranted, based on load growth, criticality to customers, and development of DG programs. New substations will increasingly be designed and constructed as integrated and automated remote assets for the utility.
• Protocol use and plans among North American electric power utilities continue to differ from the trends among utilities in the international communities. North American utilities continue to strongly support DNP 3, and will likely migrate to a LAN version of this protocol. See the comparative charts at the end of the release.
• International utilities tend to use IEC protocols. Currently, the 60870-5-103 protocol is popular, especially in Europe, while migration to IEC 61850 is underway in Europe, the Middle East and Africa, and among some of the largest utilities elsewhere. Nonetheless, Latin American and Asian Pacific utilities report strong use of Modbus and Asia-Pacific utilities tend to align themselves more with DNP 3 at the present time.
