March 31, Please call me at the number below or the address above if you have any questions regarding this filing.

Transcription

1 David R. Moeller, Attorney Legal Services Fax / dmoeller@allete.com March 31, 2010 VIA E-FILING Dr. Burl W. Haar Executive Secretary Minnesota Public Utilities Commission th Place East, Suite 350 St. Paul, MN Re: 2010 Safety, Reliability and Service Quality Standards Report Docket No. E015/M-10- Dear Dr. Haar: Minnesota Power hereby submits, via electronic filing, its 2010 Safety, Reliability and Service Quality Standards Report as required by Minn. Rules and Docket No. E-015/M Please call me at the number below or the address above if you have any questions regarding this filing. Yours truly, David R. Moeller DRM:sr Attachment cc: Service List Al Lian 30 west superior street / duluth, minnesota / / ww.mnpower.com

2 STATE OF MINNESOTA ) AFFIDAVIT OF SERVICE VIA ) ss E-FILING AND FIRST CLASS COUNTY OF ST. LOUIS ) MAIL Susan Romans of the City of Duluth, County of St. Louis, State of Minnesota, says that on the 31 st day of March, 2010, she served Minnesota Power s 2010 Safety, Reliability and Service Quality Standards Report to Burl Haar via e-filing. The individuals on the attached Official Service List were served as requested and stated. Subscribed and sworn to before me this 31 st day of March, /s/ Susan Romans Susan Romans /s/ Jodi Nash Jodi Nash, Notary Public Commission Expires on Jan 31, 2015

3 MP's SRSQ Service List Dr. Burl W. Haar MN Public Utilities Commission Suite th Place East St. Paul, MN Sharon Ferguson MN Department of Commerce Suite th Place East St. Paul, MN John Lindell Attorney General s Office 445 Minnesota Street, Ste 900 St. Paul, MN Julia Anderson Office of Attorney General 1400 Bremer Tower 445 Minnesota Street St. Paul, MN Al Krug Xcel Energy 414 Nicollet Mall Minneapolis, MN Ron Spangler Otter Tail Power Company 215 South Cascade Street Fergus Falls, MN Douglas Larson Dakota Electric Association th Street West Farmington, MN David R. Moeller Attorney Minnesota Power 30 West Superior Street Duluth, MN 55802

4 Before The Minnesota Public Utilities Commission Docket No. E-999/R Minnesota Power s Safety, Reliability and Service Quality Standards Report under Minn. Rule 7826 March 31, 2010

5 Information Ordered From E015/M

6 STATE OF MINNESOTA POWER BEFORE THE MINNESOTA PUBLIC UTILITIES COMMISSION ****************************************************************************** In the Matter of Minnesota Power s 2010 Annual Filing Docket No. E015/M-10- Concerning Safety, Reliability, Service Quality, And Proposed Annual Reliability Standards ****************************************************************************** Minnesota Power submits this Petition to the Minnesota Public Utilities Commission ( Commission ) pursuant to Minn. Rules, Chapter 7826 and in compliance with the Commission s Order dated August 11, 2009 in Docket No. E015/M Included in that Order was the requirement that Minnesota Power shall, augment their next filing to include a description of the policies, procedures and actions that it has implemented, and plans to implement, to assure reliability. Minnesota Power should include information on how it is demonstrating pro-active management of the system as a whole, increased reliability and active contingency planning. Through this filing, Minnesota Power presents a comprehensive view of its current and pro-active management plan and standards for safe, reliable and service quality focused distribution of electricity. Minnesota Power also provides, as directed under the Commission s Order Paragraph 6(D), a detailed explanation for the basis of its 2010 proposed indices. These indices will show responsiveness by Minnesota Power to the Commission s desire for a proposed higher level of reliability performance indices for Minnesota Power, a long-standing and respected distribution utility, has implemented policies and procedures and taken actions to ensure sound management of its electrical system. Minnesota Power employs several methods to demonstrate pro-active management of our system as a whole, maintain reliability and provide active contingency planning. Six of the primary methods used are discussed in detail below: PLANNING Minnesota Power currently uses a planning horizon of ten years to optimize the use of our time, labor and capital. This planning takes place within five defined, but broad categories, 1

7 and one additional broad category that includes projects related to the electrical system, but not to the process of generating, transmitting or distributing electricity. The categories are: REVENUE - Extension of service to new customers. This fulfills our obligation to serve and grows our customer base. SYSTEM IMPROVEMENTS - System improvements are the accumulation of all the projects completed to keep our system in compliance with regulations and codes. Issues which are addressed include, but are not limited to: system capacity, voltage performance and power quality. AGE RELATED REPLACEMENTS - These are end-of-life replacement projects. This equipment is still in service, but may be jeopardized by ice accumulations, high winds or additional decay. BULK SUBSTATION IMPROVEMENTS Capital is spent on building or replacing Distribution substations. Most often spent to create substations to meet capacity needs or upgrade substations to meet capacity needs. GOVERNMENT MANDATE - These are projects done to comply with government requests. Most often these projects are system relocations due to road construction which require vacation of or relocation in a road right of way. OTHER PROJECTS - These are projects which are necessary to the operation of the electrical system, but are not used for the Generation, Transmission or Distribution of electricity. They are typically facility projects, and often pertain to the upkeep of our buildings and properties. 2

8 120 Budgeted Capital Spend both actual budgets and future budgets shown Percentage Year REVENUE SYSTEM IMPROVEMENTS AGE RELATED REPLACEMENTS BULK SUBSTATION IMPROVEMENTS GOVERNMENT MANDATES OTHER Contained in Minnesota Power s ten-year plan are projects identified and developed for the purpose of making the electric system more reliable. It is our construction roadmap and is written to not only address specific problems, but to also increase overall system reliability. It is important to understand that this ten year plan is not an inflexible or unmovable course of action. Because it serves as our roadmap, the plan details are reviewed frequently and are modified, if necessary, to reflect the needs of our customers, government agencies or Minnesota Power s business needs. VEGETATION MANAGEMENT Much of our system s reliability comes not from what we put into the system, but what we take away. Minnesota Power has a vegetation management program designed to address each distribution line approximately every five years and every transmission line every seven years. Vegetation management benefits the system in various ways. It reduces momentaries and outages due to vegetation contact It improves system performance by reducing wildlife issues 3

9 It improves restoration as circuits are easier to access LINE INSPECTION Minnesota Power s line inspection program requires each pole be inspected every ten years. Poles that are 20 years and older are bored and checked internally. Depending on what is found during the pole inspection, one of four following actions is taken: 1) Poles found to be compliant with our inspection criteria are identified as needing no work until the next ten year inspection; or 2) If inspection reveals a physical loss of strength at the ground line, but an otherwise good pole, a metal brace called a pole stub is applied; or 3) If insects or decay within the pole is found and treatable, action is taken to stop further effects from the insect or decay; or 4) If the pole is beyond treatment or stubbing; it is replaced. Besides poles, line inspectors also inspect the ground mounted equipment to determine if there are any potential problems. All inspectors are given contact phone numbers that will enable them to escalate a problem to resolution should they see a serious problem in the field. FASTER CUSTOMER COMMUNICATION In 2008, Minnesota Power committed to finding ways to improve communication with customers during outages. In response to this commitment we have installed and improved the Interactive Voice Response (IVR) unit. This is a telephone device that is able to interact with customers. It has the intelligence to read the phone number of the customer placing the call. If that number is in our Customer Information System (CIS), the IVR will look to the Outage Management System (OMS) to see if the caller is in an affected area. With this system, we are able to let a customer in International Falls know what problem is affecting International Falls and how long their outage will be, while at the same time informing a customer in Long Prairie of the problems affecting that area and how long their outage will be. With this system in place, we are able to see that a large initial response to an outage quickly tapers off as customers learn the details of the problem affecting them. Minnesota Power is also using the IVR to effect data input into the Outage Management System. The Outage Management system was installed late in 2006 and is a General Electric Power On system. This system gives a real time look at the distribution system by tying 4

10 incoming IVR data, information from the field and our Geographic information system together. With data from all of those sources, the Outage Management System is able to predict the problem. Based on that information, the OMS predicts what customers are without power. Once the problem is confirmed in the field, actual conditions are modeled in the OMS and the exact customers affected by the outage are identified. This method of outage detection makes identifying outages less reliant on the expertise of those responding and uses real time data to make reliable predictions. While this OMS must overcome 100 years of outage restoration inertia, it becomes a more valuable tool every day. ANIMAL PROTECTION Efforts are underway to reduce animal contact with energized equipment. While wildlife protectors have been available for years, the medicine was as bad as the disease. In years past, when animal protection was put on electrical equipment it took care of the wildlife problems in short order. Unfortunately, in time, the inside of the wildlife protectors would become contaminated, cause flashovers and outages would return. These flashovers were difficult to find as they generally happened on the inside of the wildlife protection and were not visible. Issues were also created by animal protection contributing to overheating of equipment. Over the last several years, however, wildlife protection has changed. New designs may be applied without customer outages, are effective in controlling wildlife, are not plagued with contamination and do not cause overheating problems. The new devices are five times as expensive as previously used equipment, but the success of our latest wildlife protection projects provides a demonstrated benefit to the customer. MAIFI The Commission s August 11, 2009 Order in Docket No. E015/M at Paragraphs 6(F) and 6(G) directed Minnesota Power to make preparations to begin reporting on MAIFI by April 1, 2011 and work with Commission Staff to develop more meaningful reliability reporting on a number of basis, including MAIFI. Minnesota Power had a conference call with Commission Staff in early November 2009 and submitted an interim report in December 2009 addressing the issues in Order Point G. Building off of those discussions, we provide additional information on MAIFI and related issues as spelled out in the Commission s Order. In addition, as discussed at the July 30, 2009 Commission hearing on SRSQ and with Commission Staff, Minnesota Power s MAIFI reporting will only be collecting and reporting from existing 5

11 resources and data points. As new technologies are developed and implemented, additional MAIFI reporting will likely occur. MAIFI stands for the Momentary Average Interruption Frequency Index. The MAIFI index provides a measure of the average number of short outages, an interruption of electrical service that Minnesota Power defines as lasting less than five minutes, an average customer experiences in a year. While Minnesota Power has tracked MAIFI statistics for the last decade, it has done so with the knowledge that our MAIFI data collection is and will be incomplete without an investment in the technology necessary to collect and report all momentary outages. Increased accuracy in the MAIFI index will occur as new technologies are developed and implemented. Short momentary outages or blinks have been common on electrical systems for decades. In the 1950 s, they caused no problems. There were no electronics and a momentary outage meant a clock lost a few seconds and an incandescent light dimmed for a moment. Motors were not computer controlled and inertia carried them through the outage. Momentary outages reduced long outages by eliminating temporary faults and were a success. The philosophy behind momentaries is called fuse saving. It is a protection scheme used by utilities around the world. Over 80 percent of all faults (referred to by most homeowners as a short) on an electrical system are temporary in nature. They may be caused by lightning, vegetation, animals or humans. Regardless of cause, once a fault is created, the system provides follow through current which keeps the fault alive. If left unaddressed, the system will arc until catastrophic failure occurs. In temporary fault situations, extinguishing the arc allows the fault to clear and the system to be reenergized without additional work. Fuse saving is accomplished by setting the protection (breaker or recloser) such that it sees a problem and reacts before any fuses know there is a problem. When the high current is detected, the breaker or recloser opens and closes in about one-third of a second. This allows the arc to extinguish and the system to re-energized. 6

12 In the event the problem is not temporary in nature, a fuse saving scheme will close the breaker or recloser and hold it closed long enough for a fuse to operate. If the time needed for the fuse to operate passes and the problem persists, the system opens and locks out. A lineman is sent out to evaluate, repair and restore the system. Most people will recognize this as the scheme that causes the lights to blink once or twice then sometimes stay on and sometimes go out. The up side of this protection scheme is that temporary problems are resolved in seconds without any human input. The down side of this system is some sensitive electronics find the short interruption too long and cannot maintain normal operation. Momentary outage data is collected a few ways. About 30 percent of Minnesota Power s systems report through SCADA. 1 The remaining data is collected manually. Some is collected to satisfy a request, and some is collected when device maintenance is done. The rest is collected in the Outage Management System from customer phone calls reporting a brief interruption. A system which will bring data from all of our protective devices back to SCADA is being tested. Early tests are encouraging. However, the cost to implement this system across the roughly 600 remaining sites approaches five million dollars. That cost must be weighed against the benefit of the data collected. POWER QUALITY AND RELIABILITY COST MATRIX The Commission s Order also makes an inquiry regarding power quality. Power quality is a very social issue with no clear answer. The power quality required at a residential customer is vastly different from the power quality required at a computer control manufacturing facility. At Minnesota Power, quality issues are resolved on a case by case basis. Normally, a customer calls with a complaint or questions regarding an issue. Minnesota Power investigates and resolves all problems caused by Minnesota Power. For complaints of low voltage or high voltage, we will do an investigation of the customer s service, by checking for loose or 1 Supervisory Control and Data Acquisition SCADA A system of remote and telemetry used to monitor and control the electrical system 7

13 overheated connections. If we do not find a problem or if the problem is intermittent, we will install a recording voltmeter. This allows us to look at the voltage over time and under various customer and system loading conditions. If we find in those recordings that we are not within our voltage standards, Minnesota Power will make needed corrections to bring our voltage within the limits stated in our Distribution Standards. As with reliability, increased power quality comes with a cost. The third issue addressed in the Order is a Reliability Cost Matrix. At this time a reliability cost matrix is indeterminate. It is not possible to purchase ten dollars of reliability. Reliability is the accumulation of many factors. There are issues we can control such as the strength of the poles, the size of the wire, the age of the cable or the number of anchors; and there are issues we cannot control such as high winds, ice, animal or, drunk drivers. With so many inputs it is impossible to quantify what a dollar spent will do to reliability statistics. Operating and maintaining a car provides a good analogy. It is intuitive that spending more money on maintenance will lead to better reliability and spending less money will lead to worse reliability. It is impossible, however, to say that spending fifty dollars on a new tire will aid reliability more than spending fifty dollars on an oil change. Either could have profound effects on the car s operation. Electrical distribution is no different. We are constrained by limited resources and must make decisions to address known and anticipated problems. The variables affecting those decisions, however, make them very difficult decisions. To do so we perpetuate searching for the balance between cost, service and reliability. We take this responsibility very seriously and work hard on behalf of our customers. 8

14 SUMMARY TABLE As directed under the Commission s Order Paragraph 6(B) and previously provided to Commission Staff as directed under Paragraph 6(E), attached are graphs of the SRSQ issues which impact our customer base. Each graph contains a brief explanation of the indices. The graphs shown are 1) SAIDI performance vs. SAIDI Goal, 2) SAIFI performance vs. SAIFI Goal 3) 5 yr. historic SAIDI and SAIFI, 4) 5 yr. Historic CAIDI Values, 5) MAIFI Momentary Average Interruption Frequency Indice, 6) Vegetation Budget vs. Vegetation Spend, 7) Percentage of Calls Answered in 20 Seconds and 8) Customer Complaints. 9) Number of Lineworkers available for Trouble Calls. Current year details of this data are available within the full 2009 report. Previous year details are available in their respective reports Minnesota Power 2009 Summary Graphs SAIDI Performance vs. SAIDI Goal SAIDI (min.) SAIDI GOAL SAIDI SAIDI is the System Average Interruption Duration Indice. SAIDI provides the duration, in minutes, of the average time customers are interrupted Year 9

15 SAIFI Perfomance vs. SAIFI Goal SAIFI (number) SAIFI GOAL SAIFI SAIFI is the System Average Interruption Frequency Indice. SAIFI provides the frequency of sustained (over five minutes) outages experienced by the average customer Year SAIDI yr Historic SAIDI and SAIFI SAIDI SAIFI Year SAIFI SAIFI is an indication of how many outages an average customer experiences and SAIDI is an indication of how long the average customer is without power. These numbers have been difficult to accurately track through history. The difficulty resides in the iterative process of collecting and reporting data. While the system is improving, the accuracy of the data being collected is also improving. As we collect more data, the resulting reliability appears to worsen. 10

16 5 year Historic CAIDI Values CAIDI 150 CAIDI CAIDI is derived by dividing SAIDI by SAIFI. The statistic generally speaks to the amount of time needed to respond to an outage Year MAIFI - Momentary Average Interuption Frequency Indice MAIFI* is the Momentary Average Interruption Frequency Indicie. MAIFI (# of momentaries) MAIFI *The reader should be aware that the MAIFI calculation is as complete as our current data collection allows. Minnesota Power is aware, however, that data may be incomplete Year 11

17 Vegetation Budget vs Vegetation Spending Dollars $4,000,000 $3,500,000 $3,000,000 $2,500,000 $2,000,000 $1,500,000 $1,000,000 $500,000 Vegetation Budget Vegetation Spending Vegetation management is administered to each distribution circuit on approximately a five year schedule. Successful vegetation management not only keeps vegetation out of the line, but also aids in keeping wildlife away from the line; and makes access to lines easier. $ Year 100 Percentage of Calls Answered Within 20 sec. 7A.M. to 5:30 P.M. % calls in 20 goal % of calls answered in 20 sec Answering a call in 20 seconds generally equates to three rings. Goal is 80% Year 12

18 Residential and Commercial Complaints Residential Complaints Commercial Complaints Residential Complaints Commercial Complaints Customer complaints are generally tracked for alleged billing errors, inaccurate metering, wrongful disconnection, service extension intervals, service restoration intervals as well as other issues Year Full Time Lineworkers Available for Trouble Full time 100 Number of Workers Minnesota Power had 105 full-time equivalent employees in Field Operations during Year 13

19 Annual Safety Reporting Minnesota Power 3/31/2010

20 Minnesota Public Utilities Commission Part: Safety, Reliability and Service Quality Standards Schedule: N/A Filing Requirements Subpart: N/A A. Summaries of all reports filed with United States Occupational Safety and Health Administration and the Occupational Safety and Health Division of the Minnesota Department of Labor and Industry during the calendar year. Total number of deaths Total number of cases with days away from work Number of Cases Total number of cases with job transfer or restriction Total number of other recordable cases Number of Days Total number of days of job Total number of days away from transfer or restriction work Injury and Illness Types Injuries Skin disorders Respiratory conditions Poisonings All other illnesses B. A description of all incidents during the calendar year in which an injury requiring medical attention or property damage resulting in compensation occurred as a result of downed wires or other electrical system failures and all remedial action taken as a result of any injuries or property damage described. There were no incidents in 2009 in which injuries requiring medical attention occurred as a result of downed wires or other electrical system failures. A listing of all incidents in which property damage resulting in compensation occurred as a result of downed wires or other electrical system failures and the remedial actions taken is included in the following table: 1

21 Date of Claim Name Cause of Damage Paid Remedial Action 1/12/2009 Robin Maharry Work Procedure $3, Reimbursement made for damages incurred 1/21/2009 Frontline Plus Fire Miscellaneous Equipment Failure $12, Reimbursement made for damages incurred 1/22/2009 Charlene Wilson Miscellaneous Equipment Failure $ Reimbursement made for damages incurred 2/18/2009 Qwest Work Procedure $2, Reimbursement made for damages incurred 2/24/2009 Greg Wester Miscellaneous Equipment Failure $ Reimbursement made for damages incurred 2/27/2009 Fred Kollmann Miscellaneous Equipment Failure $79.70 Reimbursement made for damages incurred 3/12/2009 Next Innovations, Ltd. Miscellaneous Equipment Failure $86.00 Reimbursement made for damages incurred 3/22/2009 Michael Sundberg Work Procedure $1, Reimbursement made for damages incurred 4/6/2009 Earl Richards Work Procedure $2, Reimbursement made for damages incurred 4/12/2009 Denny Mueller Miscellaneous Equipment Failure $ Reimbursement made for damages incurred 4/16/2009 Omar Sand & Gravel Miscellaneous Equipment Failure $ Reimbursement made for damages incurred 4/27/2009 Corey Kurbis Reimbursement for Electrician Exp. $ Reimbursement made for damages incurred 5/2/2009 Tami Eckel Miscellaneous Equipment Failure $ Reimbursement made for damages incurred 5/12/2009 Gary Liquors Work Procedure $3, Reimbursement made for damages incurred 5/21/2009 Dave Kilber Property Restoration $ Reimbursement made for damages incurred 5/29/2009 James Delmore Work Procedure $ Reimbursement made for damages incurred 6/5/2009 Marie Frey Work Procedure $ Reimbursement made for damages incurred 6/15/2009 Excel Energy Work Procedure $ Reimbursement made for damages incurred 6/16/2009 Hermantown Liquors Reimbursement for Electrician Exp $ Reimbursement made for damages incurred 6/23/2009 KTM Paving, Inc. Work Procedure $ Reimbursement made for damages incurred 6/25/2009 Debra Lambrecht Miscellaneous Equipment Failure $37.58 Reimbursement made for damages incurred 6/25/2009 Susan Langer decrease in voltage due to GRE $ Reimbursement made for damages incurred 6/25/2009 Tim & Sheryl Grittner decrease in voltage due to GRE $1, Reimbursement made for damages incurred 6/30/2009 Barry Buria Property Restoration $ Reimbursement made for damages incurred 9/8/2009 Jeff Heinlen Work Procedure $ Reimbursement made for damages incurred 9/8/2009 Gerald Kepke Work Procedure $ Reimbursement made for damages incurred 10/29/2009 David Beasley Work Procedure $ Reimbursement made for damages incurred 11/9/2009 Duane Lula Property Restoration $50.00 Reimbursement made for damages incurred 11/11/2009 Richard Hiti Miscellaneous Equipment Failure $ Reimbursement made for damages incurred 11/19/2009 Tom Pavlowich Miscellaneous Equipment Failure $1, Reimbursement made for damages incurred 11/19/2009 Amber Hammitt Miscellaneous Equipment Failure $2, Reimbursement made for damages incurred 12/3/2009 Mike Zimmerman Increase in voltage $ Reimbursement made for damages incurred 12/3/2009 Long Prairie Plumbing Work Procedure $ Reimbursement made for damages incurred 12/03/2009 Robert Duncan Work Procedure $5, Reimbursement made for damages incurred 12/3/2009 Mark Koski Work Procedure $60.00 Reimbursement made for damages incurred Total Claims: 35 $46,

22 Annual Reliability Reporting Subpart 1 Minnesota Power 3/31/2010 3

23 Minnesota Public Utilities Commission Part: Safety, Reliability, and Service Quality Standards Schedule: N/A Filing Requirements Subpart: 1 A. B. C. The utility s SAIDI, SAIFI and CAIDI for the calendar year, by work center and for its assigned service area as a whole. The indices reported herein are for the Minnesota Power assigned service area, which is a single work center. SAIDI (in minutes) SAIFI (# of outages) CAIDI (outage min/customer) D. An explanation of how the utility normalizes its reliability data to account for major storms. Since 2008, any major events occurring in the Minnesota Power service area have been excluded based on the 2.5 beta method defined by the IEEE Standard for Distribution Reliability. The normalization process is designed to remove all outage records attributed to a specific, catastrophic event such as a large storm. At Minnesota Power normalization is performed only when the following criterion is met for a catastrophic event: 1. Daily SAIDI is greater than the Threshold for Major Event Days. As storms occur, customers call into our representatives and/or the IVR (Interactive Voice Responder) to report outages. Those calls are then used to create trouble orders using a prediction engine within our Outage Management System. That information, along with information from other sources (Operations Log, and Telemetric s s) is entered into a database for comparison. Often the event will have been detected by multiple sources. Duplications are eliminated and an accurate time and duration for each event is calculated. Once all data streams have been combined and duplications have been eliminated, the resulting database is ready for analysis by our Reliability Engineer. The database is queried to look for timeframes when the Company SAIDI has incurred an incremental increase above the Threshold for Major Event Days. When sets of data are discovered that meet the criterion discussed above, that data is flagged and set aside. What remains is Minnesota Power s Storm Normalized Data. 4

24 Threshold for Major Event Day calculation description: A Threshold for a major event day (T med ) is computed once per year. Assemble the 5 most recent years of historical values of daily SAIDI and discard any day with a SAIDI value of zero. Then, compute the natural log of each SAIDI value and compute the average (alpha) and standard deviation(beta) of the natural logarithms. The major event day threshold can then be found by using this equation: T med = exp (alpha + 2.5*beta). If any day in the next year has SAIDI greater than T med, it is a major event day. Note that an excluded event is not limited to a single day and may span consecutive days depending on the severity of the event. As stated earlier, storm normalization is designed to exclude data from rare, catastrophic events. There were 2 storm excluded events in 2008 that met the Threshold for Major Event Day criterion. In 2007, there were 2 storms excluded. No events were excluded in 2006 and storm exclusions have followed similar patterns in previous years. In 2004 and 2002 there were no events excluded. Three events were excluded in 2003 and only one in 2001 and It is important to note that our GIS mapping system was completed in The newer version shows all of the customers by electric continuity (feeders), whereas the older version was simply a drawing without the electric continuity. In the older version the margin of error for counting customers affected by an outage was much greater. The addition of electric continuity will assist the Reliability Engineer in accurately determining a true customer count for the purposes of calculating SAIDI, SAIFI, etc. Minnesota Power has committed the personnel and financial resources necessary to continually improve our reliability reporting and response to outages. In addition to the GIS improvements noted above, Minnesota Power has chosen GE s Power-On, as our Outage Management System (OMS). The OMS is fully operational as of December Not only will the OMS system enable more timely analysis and response to outage situations, but it will also provide more accurate outage reports with less manual intervention. Although the increased accuracy of reports could result in either an increase or decrease in reliability statistics, it has been the experience of companies that Minnesota Power has spoken with; that the introduction of an OMS generally results in what appears to be poorer reliability numbers due to greater accuracy in the outage reporting. So although the combination of the improvement in the GIS and introduction of an OMS will clearly enable Minnesota Power to better serve our customers in outage situations, it is conceivable that the resulting SAIDI, SAIFI, and CAIDI could reflect what appears to be decreased performance statistics. 5

25 E. An action plan for remedying any failure to comply with the reliability standards set forth at part or an explanation as to why non-compliance was unavoidable under the circumstances. Minnesota Power was successfully able to meet the reliability standards set for SAIDI for the year MP used the 2.5 Beta method for excluding storm related outages and did not exclude any major events. F. To the extent technically and administratively feasible, a report on each interruption of a bulk power supply facility during the calendar year, including the reasons for interruption, duration of interruption, and any remedial steps that have been taken or will be taken to prevent future interruption. 77L On January , New relays were installed at the LSPI sub. One of the new relays was programmed wrong and caused 77L to open and the LSPI sub to lose power for 14 minutes. The relay was reprogrammed by Field Operations. All repairs are complete, no further action required. 42L On March , 42 Line opened. Crews found a broken transmission structure one mile north of the Silver Bay 115kv sub. A small scale ice storm moved through the area and was the cause of the broken structure. The structure was isolated and power was restored to customers after 13minutes. Line inspections were performed by Field Operations and all repairs are complete, no further action required. 1L On March , 1L opened by relay and would not close because of a relay communication failure. Field Operations was contacted for an update on 42L structure repair. Emergency repairs were completed to the broken structure in 42L and the SilverBay 115kv sub was restored after 207 minutes. Corrective action was taken the following day to rebuild the broken structure so that the transmission could be restored to normal configuration. Line inspections were performed by Field Operations. All repairs are complete, no further action required. 2L On March , 2L opened by relay and would not close because of a relay communication failure. Field Operations was contacted for an update on 42L structure repair. Emergency repairs were completed to the broken structure in 42L and the SilverBay 115kv sub was restored after 207 minutes. Corrective action was taken the 6

26 following day to rebuild the broken structure so that the transmission could be restored to normal configuration. Line inspections were performed by Field Operations. All repairs are complete, no further action required. 129L On April , GRE owned 129L feeding the two MP feeders at the Four Corners sub opened by relay. GRE could not get their equipment back online so MP completed switching and restored our customers after 121 minutes. Line inspections were performed by GRE and MP Field Operations and all repairs are complete, no further action required. 34L On August , contact was made between a grounded jumper from the new relocated de-energized 34line and the energized 34line, this caused the 34L to open and power was restored after 63 minutes. Line inspections were performed by Field Operations and all repairs and relocation work are complete, no further action required. 23LM On September , a tree was found on the 23L between Askov and Kerrick. The line was sectionalized and power restored to the Askov area after 76 minutes and Kerrick area after 110 minutes. Line inspections were performed by Field Operations and all repairs are complete. Extensive tree trimming is scheduled to start for the entire 23 line. 30L On December , 30L by relay and locked out. Crews patrolled the line and found a broken insulator and one phase resting on the cross arm. The line was sectionalized and power restored after 74 minutes. Line inspections were completed by Field Operations and all repairs are complete, no further action is needed. 7

27 G. A copy of each report filed under part major interruptions affecting 500 or more customers for over an hour There were 33 reports filed under during Please refer to Attachment A for written copies of the reports. 8

28 H. To the extent technically feasible, circuit interruption data, including identifying the worst performing circuit in each work center, stating the criteria the utility used to identify the worst performing circuit, stating the circuit s SAIDI, SAIFI, and CAIDI, explaining the reasons that the circuit s performance is in last place, and describing any operational changes the utility has made, is considering, or intends to make to improve its performance. Section H requires that Minnesota Power report our worst performing circuit per work center. Since Minnesota Power considers our entire service area a single work center, this would result in only one circuit being reported. As in the past, rather than listing only one feeder, the four worst performing feeders (2 each urban and rural) are identified here. This is done in recognition of how reliability indices are affected by differing characteristics of feeder length and quantity of customers. The feeder evaluation process utilized high feeder SAIDI and high total customer-minutes of outage (i.e. # customers X SAIDI) as criteria for selection of two urban and two rural feeders. The following table clarifies the selections: Worst Feeders Using Storm Normalized Data Criteria Circuit # Customers SAIDI SAIFI CAIDI High Feeder SAIDI Cotton Tail Drive High Customer Haines Road , Outage Minutes High Feeder SAIDI Sandstone High Customer Outage Minutes Sandstone , Cotton Tail Drive 1 Major Outage Events: On April 1 st 2009, one phase in a tap off the parent feeder RVT 506 failed and fell to the ground. The lineman switched around the problem and RVT 506 was able to be restored quickly. However, Cotton Tail Drive 1 was not able to be restored because the affected phase in 506fdr was on the same tap that Cotton Tail Drive 1 is on. Actions taken to improve performance: The downed wire in 506 feeder was repaired and Cotton Tail Drive 1 was restored. The copper wire in the above mentioned tap is really old and is in the process of being rebuilt. 9

29 Haines Road 236 Major Outage Events: On January 15 th 2009, One pin insulator tie wire failed due to excessive line tension on a tangent pole. The center phase dropped down on the crossarm and burned off a second pin insulator tie wire causing the outer phase to fall off the crossarm. Actions taken to improve performance: Tie wires were replaced, wires re-sagged to the correct tension, and power was restored Sandstone 6531 Major Outage Events: On June 9 th 2009 an old porcelain cutout in the main feeder failed and caused the City of Sandstone to lose power. On August 6 th 2009, another old porcelain cutout further down the feeder failed with the same result as before. Actions taken to improve performance: All main line taps and transformer porcelain cutouts off 6531 feeder were changed out with new polymer cutouts. Squirrel guards were installed. Hot spot tree trimming was completed in several locations around town. Sandstone 6531 Major Outage Events: On June 9 th 2009 an old porcelain cutout in the main feeder failed and caused the City of Sandstone to lose power. On August 6 th 2009, another old porcelain cutout further down the feeder failed with the same result as before. Actions taken to improve performance: All main line taps and transformer porcelain cutouts off 6531 feeder were changed out with new polymer cutouts. Squirrel guards were installed. Hot spot tree trimming was completed in several locations around town. 10

30 I. Data on all known instances in which nominal electric service voltages on the utility s side of the meter did not meet the standards of the American National Standards Institute for nominal system voltages greater or less than voltage range B. There were 4 reported instances in Date Account Trouble Order 12/18/ N/A 12/18/ N/A 12/21/ N/A 12/28/ N/A Starting in early 2009, a database was set up with the intent of being able to better collect ANSI service voltage violations. Engineers working in different parts of the service area have access to the Engineering Case Management database and can easily create a record of all voltage recorder results and can create a flag on the record if it has violated the ANSI standard. Minnesota Power hopes this database will help to reflect the number of violations that may or may not happen in the future. J. Data on staffing levels at each work center, including the number of full-time equivalent positions held by field employees responsible for responding to trouble and for the operation and maintenance of distribution lines. Minnesota Power had 105 full-time equivalent field employee positions in 2009 responsible for responding to trouble and for the operation and maintenance of distribution lines. K. Any other information the utility considers relevant in evaluating its reliability performance over the calendar year. We continued collecting data on planned outages beginning January 1 st 2009 and all data is included in the report and reliability statistics. 11

31 Reliability Standards Subpart 1 Minnesota Power 3/31/

32 Minnesota Public Utilities Commission Part: Safety, Reliability, and Service Quality Standards Filing Requirements Schedule: N/A Subpart: 1 A. On or before April 1 of each year, each utility shall file proposed reliability performance standards in the form of proposed numerical values for the SAIDI, SAIFI, and CAIDI for each of its work centers. These filings shall be treated as miscellaneous tariff filings under the Commission s rules of practice and procedure, part , subp. 11. For 2010 Minnesota Power proposes the following weather-excluded reliability indices as targets not to exceed: SAIDI = SAIFI = 1.06 CAIDI = We are proposing improved levels of reliability performance compared to the 2009 targets. The SAIDI target is calculated by taking the average of the last five years of actual SAIDI performance. The SAIFI target is calculated by taking the average of the last five years of actual SAIFI performance. The CAIDI target is calculated by dividing the SAIDI target by the SAIFI target. 13

33 Reporting Meter-Reading Performance Minnesota Power 3/31/

34 Minnesota Public Utilities Commission Part: Safety, Reliability and Service Quality Standards Schedule: N/A Filing Requirements Subpart: N/A Meter-reading performance. The annual service quality report shall include a detailed report on the utility s meter-reading performance, including, for each customer class and for each calendar month: A. The numbers and percentages of customer meters read by utility personnel. Residential Month Co. Reads Est Total % Read System % Read of Total System Total Jan , , % 144, % Feb , , % 144, % Mar , , % 144, % Apr ,982 2, , % 144, % May ,441 1, , % 144, % Jun ,288 1, , % 144, % Jul ,362 1, , % 144, % Aug ,081 1, , % 144, % Sep ,008 1, , % 145, % Oct , , % 145, % Nov , , % 145, % Dec ,061 4, , % 145, % 2009 Avg 113,499 1, , % 78.34% Commercial Month Co. Reads Est Total % Read System % Read of Total System Total Jan-09 18, , % 144, % Feb-09 19, , % 144, % Mar-09 19, , % 144, % Apr-09 19, , % 144, % May-09 18, , % 144, % Jun-09 18, , % 144, % Jul-09 19, , % 144, % Aug-09 19, , % 144, % Sep-09 19, , % 145, % Oct-09 19, , % 145, % Nov-09 19, , % 145, % Dec-09 18, , % 145, % 2009 Avg 18, , % 13.11% 15

35 Industrial Month Co. Reads Est Total % Read System % Read of Total System Total Jan % 144, % Feb % 144, % Mar % 144, % Apr % 144, % May % 144, % Jun % 144, % Jul % 144, % Aug % 144, % Sep % 145, % Oct % 145, % Nov % 145, % Dec % 145, % 2009 Avg % 0.33% Municipal Pumping Month Co. Reads Est Total % Read System % Read of Total System Total Jan % 144, % Feb % 144, % Mar % 144, % Apr % 144, % May % 144, % Jun % 144, % Jul % 144, % Aug % 144, % Sep % 145, % Oct % 145, % Nov % 145, % Dec % 145, % 2009 Avg % 0.19% Lighting Month Co. Reads Est Total % Read System % Read of Total System Total Jan % 144, % Feb % 144, % Mar % 144, % Apr % 144, % May % 144, % Jun % 144, % Jul % 144, % Aug % 144, % Sep % 145, % Oct % 145, % Nov % 145, % Dec % 145, % 2009 Avg % 0.11% 16

36 B. The numbers and percentages of customer meters self-read by customers. Residential Month Cust Reads Est Total % Read System % Read of Total System Total Jan % 144, % Feb % 144, % Mar % 144, % Apr % 144, % May % 144, % Jun % 144, % Jul % 144, % Aug % 144, % Sep % 145, % Oct % 145, % Nov % 145, % Dec % 145, % 2009 Avg % 0.05% Commercial Month Cust Reads Est Total % Read System % Read of Total System Total Jan % 144, % Feb % 144, % Mar % 144, % Apr % 144, % May % 144, % Jun % 144, % Jul % 144, % Aug % 144, % Sep % 145, % Oct % 145, % Nov % 145, % Dec % 145, % 2009 Avg % 0.02% 17

37 Industrial Month Cust Reads Est Total % Read System % Read of Total System Total Jan % 144, % Feb % 144, % Mar % 144, % Apr % 144, % May % 144, % Jun % 144, % Jul % 144, % Aug % 144, % Sep % 145, % Oct % 145, % Nov % 145, % Dec % 145, % 2009 Avg % 0.00% Municipal Pumping No Self-reads Lighting No Self-reads 18

38 C. The number and percentage of customer meters that have not been read by utility personnel for periods of six to twelve months and for periods of longer than twelve months, and an explanation as to why they have not been read. Residential/Commercial/ Industrial /Municipal Pumping/Lighting Months Company Read % of Total Not Read Customer Read % of Total Not Read Estimated Service Points Reason Service Points Reason 6 Months % No Access/AMR % No Access 7 Months % No Access/AMR % No Access 8 Months % No Access/AMR % No Access 9 Months % No Access/AMR % No Access 10 Months % No Access/AMR % No Access 11 Months % No Access/AMR % No Access 12 Months % No Access/AMR % No Access 12+Months % No Access/AMR % No Access Totals: * Minnesota Rules requires that meters be read at least annually. Customers with Company Read meters that are not read between six months and twelve months are left reminder notices at the home and/or are sent reminder letters of the utility s need to access the meter. A similar process is used for Customer Read meters not read for 12+ months. In addition, phone calls are made to each customer in an attempt to schedule a meter reading. Disconnection warnings are issued for unresponsive accounts. In accordance with the Cold Weather Rule, no disconnections for unread meters are performed during the winter. 19

39 D. Data on monthly meter-reading staffing levels, by work center or geographical area Staffing by Work Center (Minnesota Power System) 2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Meter Reader Collector