by Charles W. Newton, Newton-Evans Research Co.
Editor’s note: The following article is the full version of a shorter article that appeared in the February 2009 issue of Utility Automation and Engineering T&D magazine.
Nearly 150 major and mid-size electric power utilities from the U.S. and Canada participated in the 2008 North American control systems market study. Ninety-five percent of the respondents indicated that their utility has at least one control system installed for use in operating the transmission and/or distribution network. More than 40 sites reported having a second control system and nine had three (or more) control systems installed.
Each of the investor-owned utilities (IOUs) reported having an energy management system installed as of mid-2008. Almost all utilities with 25,000 or more customers reported having a supervisory control and data acquisition (SCADA) or energy management system (EMS) in operation. A lower number of mentions were received for installations of “stand-alone” distribution management systems, as most distribution utilities incorporate at least some distribution grid management functions within their SCADA system. Only 17 percent of respondents reported having a “stand-alone” distribution management system (DMS) in operation.
In this year’s study, 55 percent of the respondents stated that their outage management system (OMS) is currently a separate system from EMS or SCADA or DMS. Sixteen percent stated that OMS is, or will be, integral to DMS/SCADA. Nine percent indicated plans to implement DMS as a separate system by 2010. One in five (20 percent) stated that the utility is not currently using and has no plans to use an OMS (see Figure 1 above).
IOUs were very likely to have separate OMS installations, as indicated by 87 percent of that subgroup. This compares with 61 percent of the cooperatives, 41 percent of the public power operations and only 22 percent of the Canadian utilities. However, Canadian respondents reported the most significant plans to offload the OMS functions from currently installed systems. Nearly one-third of the public power utilities indicated no use and no plans for use of OMS.
Generation management system
Only 17 percent of the respondents indicated that they operated a separate generation management system or GMS as of April 2008. This included 32 percent of the IOU replies, but much lower percentages among other subgroups (including 14 percent of public power respondents, 10 percent among cooperatives, and nine percent for the Canadian utilities). Twelve citations of GMS vendors were made, centering on a few each for ABB and Areva with scattered mentions for seven other suppliers.
None of the utility participants in this new study indicated any plans to invest in any additional separation of the GMS functions, and most felt that automatic generation control (AGC) applications available on SCADA were sufficient, if needed at all. Power plants of any size do have their own set of control systems technology.
Additional links between EMS, SCADA and DMS systems
On a summary basis, taking into account all sizes and types of utilities, Inter-Control Center Communications Protocol (ICCP) links were the most important by mid-2008. Links to historian files were close in importance to these utilities. Outage management and load management linkages were cited by more than 40 percent of the overall group.
IOUs were more likely than other groups to have linkages already established to most of the 20 links listed in the survey. Nearly 90 percent of IOUs had established ICCP links to one or more neighbors or independent system operators/regional transmission organizations (ISOs/RTOs). One half or more had links to power plants, distributed generation via remote terminal units (RTUs), simulators, historian files, regional control centers and outage management systems,
Link rates were lower for public power utilities and cooperatives, except that electric power cooperatives were more likely to have a link to load management systems than were other industry groups. Canadian utilities had high rates of linkages to geographic information system (GIS) and customer information system (CIS) functions, and to ICCP and operations planning systems.
Future linkages were more likely to be planned for use with OMS and GIS on average. IOUs were planning for more links to the North American Electric Reliability Corporation (NERC) compliance reporting systems, as were public power utilities. Public power utilities were also planning to link up with GIS. Canadian utilities were focused on GIS and OMS links and were more likely than their U.S. counterparts to be looking to link with distributed generation facilities via either dedicated RTUs or via a direct data link.
Protocol usage within substations
On a summary basis, nearly 80 percent of all North American participating utilities reported at least some use of distributed network protocol (DNP) serial communications protocol. DNP 3 local area network (LAN) use now stands at 38 percent among these survey participants. Modbus serial remains popular, with 36 percent making some use of this protocol, including a high 61 percent rate among IOUs. Fully one half of the IOUs also reported some use of Modbus Plus. Legacy protocols developed mainly by EMS and SCADA vendors in years past continue in use within the substation by about one quarter of the utilities participating in the study (and legacy protocols are still widely used for wide-area communications to-and-from the substation, as noted in the following section).
Plans for protocol change center on migrating from a serial to a LAN-based version of DNP 3. The outlook for field deployment or adoption of IEC 61850 is likely to remain at the “noise” level for North American utilities though the year 2010, based on feedback from these many utilities.
Protocol usage substation to external host/network
Protocol use for substation-to-control center and other systems continues to center on the use of DNP 3, with nearly two-thirds of respondents citing use of DNP 3 serial, and now, 40 percent citing use of DNP 3 LAN. Legacy protocols remain widely deployed, with more than one-half (54 percent) citing some use of legacy protocols in their SCADA-related data transmission activities. Among IOUs the rate of use of legacy protocols is nearly 80 percent.
TCP/IP (transmission control protocol/internet protocol, together the Internet Protocol Suite) continues to edge up in overall usage levels, with many using TCP/IP as a data transfer technology of choice.
[NOTE: TCP/IP is not a substation protocol but rather an underlying data transfer method comprised of a suite of protocols for Internet/Intranet use. TCP is responsible for verifying the correct delivery of data from client to server. Since data can be lost in the intermediate network, TCP adds support to detect errors or lost data and to trigger retransmission until the data is correctly and completely received. IP is responsible for moving packets of data from node to node. IP forwards each packet based on a four-byte destination address (the IP number). (See Figure 2 below.)
More than one third (39 percent) suggested “maybe” in reply to whether they had any plans to implement IEC 61850 beyond 2010. More than one half (52 percent) indicated “no plans” for any of a number of listed reasons. Most importantly, 36 percent said they were going to continue to use other protocols. Fourteen percent indicated that the advantages of IEC 61850 were “not that great.” Seven percent replied that “some vendors have not implemented it.” Four percent considered the cost as too high.
Use of external assistance or third party services needed
On a summary basis of results from more than 130 officials replying to this question of what external professional services might be needed today, about one-third expressed a need for either training or long-term maintenance. However, the rate of need among IOU officials was much higher for every one of the ten listed categories.
More than 40 percent of the IOU respondents indicated a current need in 2008 for long-term maintenance and for training. Almost 40 percent indicated a current need for integrated concepts for distribution automation. Twenty-five percent or more of the IOUs also cited a current need for standardization and prepackaging of DA solutions for primary substations vulnerability assessments, commissioning and testing of new systems and network model building.
Approaches used for reducing vulnerability on T&D operations networks
The top four approaches being taken in 2008 by North American electric power utilities in an attempt to reduce cyber vulnerabilities include: 1) password protection (92 percent); 2) firewalls and DMZ between control center-based systems and the enterprise LAN (84 percent); 3) VPN (virtual private network) established by 80 percent and 4) advanced virus protection software (75 percent). Three of these represent significant increases from the percentages reported in the 2005 study, which themselves were significant measurable increases taken since the 2003 study.
In most categories among the 24 listed on the survey, IOUs were more likely to have implemented additional vulnerability reduction measures by a wide margin over their counterparts in public power, cooperatives or those reported among the Canadian utilities.
Some interesting exceptions included many public power utilities disallowing any remote dial in to the control center systems; almost all cooperative utilities adopting at least password protected access and being more likely to use their SCADA as the master security center for substation intelligent electronic devices (IEDs) requiring additional passwords. Canadian utilities were stronger adopters of ICCP encryption than were their U.S. counterparts and were somewhat more likely to be protecting SCADA systems with firewalls and DMZ measures (demilitarized zones within computer networking).
On a summary basis, there are more cyber protection measures being taken by North American electric utilities of all sizes and types than in any previous study over the past decade in which these measures were researched. In part, these are pure defensive strategies. In large part, we believe, the increased adoption of these measures is due to the impact of NERC compliance requirements. If the even “stricter” (more robust) NIST (National Institute of Standards and Technology) cyber security guidelines being proposed for electric power cyber security become mandatory over the next two years, the subsequent Newton-Evans research study will undoubtedly find increases in the extent of adoption and in the number of sophisticated measures being utilized by North America’s electric power industry infrastructure, numbering over 3,000 distinct utilities serving approximately 160 million metered customers.
Plans for procurement of new and replacement SCADA, DMS and EMS systems during 2008-2010
A total of 86 sites in this survey were identified with some level of procurement activities for control system upgrades, add-ons or system replacements. However, a few of the respondents identified recently completed procurements as in their “plans” even if these were currently already selected, and perhaps more properly belonged in the “installation or implementation” phase.
The total volume of recent or upcoming procurement activities released to us by this group of respondents is in the range of 120 million dollars. This amount represents a significantly higher level of planned spending and by more utilities, than has been reported in recent surveys.
Requests for “NERC CIP compliance” features, tools and reports far outpolled mentions for other features, tools, applications and services mentioned by this large group of respondents. This year’s inputs far outweighed in number and range the comments made in previous studies. The feedback was also clearly focused by the larger utilities as NERC compliance issues. Systems integration topics were also important to this group with comments ranging from “true integration” to “seamless integration between our SCADA system and our new OMS” and “complete integration with OMS systems.”
There were also a number of mentions related to SOA (service-oriented architecture), user friendly interfaces, history data management and more information on IEC 61850 experiences.
Utility focus on intelligent grid components during 2008-2010
In a new question included in the 2008 Newton-Evans’ survey, this group of utilities was asked to check the two most important components of near-term (2008-2010) work on the intelligent grid. A total of 136 North American utilities provided their comments by indicating their two most important efforts during the planning horizon.
On a summary basis, advanced metering infrastructure (AMI) led in mentions from 48 percent of the group. EMS/SCADA investments in upgrades, new applications, interfaces et al was next, mentioned by 42 percent of the group. Distribution automation was cited by 35 percent as a near-term thrust related to intelligent grid activities. GIS followed with a 30 percent mention rate. Fault detection, isolation and service restoration, a very recently developed term, was mentioned by 20 percent of the group. Eleven sites (8 percent) indicated “no plans” for any near-term focus on intelligent grid activities.
There were substantial changes in intelligent grid priorities when the data is reviewed on “numbers of customers served” basis. The largest utilities were likely to be investing in advanced metering infrastructure (AMI) and distribution automation in that order, while the utilities serving from 100,000 to 250,000 customers placed slightly more emphasis on distribution automation than on AMI activities. Smaller utilities serving from 10,000-100,000 customers were emphasizing GIS work during the 2008-2010 periods.
Capital and O&M spending outlook at year-end 2008
In a supplemental study of utilities located in 40 countries, Newton-Evans has found that capital spending plans for EMS, SCADA and DMS systems will remain largely as had been budgeted and planned in January 2008. The findings reported in this study suggest that, by and large, capital spending plans for new or upgraded control systems are to remain as planned a year ago (71 percent), while 14 percent plan to raise their capital spending in this area and 15 percent plan to reduce or defer spending for new and upgraded systems. Eighty-three percent indicated plans to stick with their operations and maintenance (O&M) budgets for 2009 as planned last January, with equal percentages of the others planning to raise O&M spending as to lowering O&M spending.
Charles W. Newton is president of Newton-Evans Research Co. More information on Newton-Evans can be found online at www.newton-evans.com.