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REGULAR MEETING OF THE UTILITIES COMMISSION February 13, 2018, 3:30 P.M. Utilities Conference Room
AGENDA 1.0 1.1 1.2 1.3
GOVERNANCE Call Meeting to Order Pledge of Allegiance Consider the Agenda
2.0 2.1 2.2 2.3
CONSENT (Routine items. No discussion. Approved by one motion.) Check Register Regular Meeting Minutes – January 9, 2018 Demand All Electric Service Tariff
3.0 OPEN FORUM (Non-agenda items for discussion. No action.) 4.0 POLICY & COMPLIANCE (Policy review, policy development, and compliance monitoring.) 4.1 Distributed Generation and Net Metering Policy 5.0 5.1 5.2 5.3 5.4
BUSINESS ACTION (Current business action requests and performance monitoring reports.) Financial Report – December 2017 2017 Annual Safety Report 2018 Bank Signatories 2017 Fourth Quarter Delinquent Items
6.0 6.1 6.2 6.3 6.4
BUSINESS DISCUSSION (Future business planning, general updates, and informational reports.) Staff Updates Landfill Gas Plant to Electric Generation Facility Performance for 2017 Electric Vehicle Suitability Assessment Presentation Future Planning (Announce the next regular meeting, special meeting, or planned quorum.) a. Regular Commission Meeting – March 13, 2018 6.5 Other Business (Items added during agenda approval.) 7.0 ADJOURN REGULAR MEETING
______________________________________________________________________________ Page 1 of 1
Elk River Municipal Utilities 02/05/2018 9:45:44 am
Revision: 90160 Page: 1
Payroll/Labor Check Register Totals 01/12/2018 To 01/12/2018
Pays 2 3 5 24 18 VAC SICK HOL 5-2 PTO 18A
Pay Total: Deductions 9 PERA/C 67 HCSP1 76 HCSP2 77 HCSP3 14 Def/MN 36 Def/Wenzel 17 Flex/Health 37 Flex/Dependent 21 Extra Life Insurance 26 United Way 38 World Vision 30 Dental-Single 31 Dental-Single+Spouse 62 Dental-Single+Child(ren) 32 Dental-Family 85 HSA/Single 86 HSA/Single+1 87 HSA/Family 92 HSA Contribution 14A Def/MN Roth 50 Insurance Opt-Out - Electric 51 Insurance Opt-Out - Water Deduction Total:
25203
Amount
Job Reg Hrly Overtime On-Call/Stand-by FLSA Commissioner Reimb. - Electric Vacation Pay Sick Pay Holiday Pay On-Call/Stand-by/OT Personal Day Commissioner Reimb. - Water
90,268.91 225.30 1,736.98 2.36 600.00 7,148.08 5,325.78 26,092.24 23.80 346.64 150.00 131,920.09
Hours 2,417.75 5.75 48.08 0.00 0.00 178.50 161.75 704.00 0.50 8.00 0.00 3,524.33
Amount 8,526.03 936.06 501.62 374.56 4,393.90 1,277.92 201.93 1,103.10 110.70 22.98 19.12 22.15 53.10 53.05 285.57 597.31 1,262.45 6,045.38 3,631.51 401.10 -796.20 -173.10 28,850.24
/pro/rpttemplate/acct/2.40.1/pl/PL_CHK_REG_TOTALS.xml.rpt
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KGreenberg25
Elk River Municipal Utilities 02/05/2018 9:46:44 am
Revision: 90160 Page: 1
Payroll/Labor Check Register Totals 01/26/2018 To 01/26/2018
Pays 2 3 4 5 24 10 VAC SICK HOL 5-2 PTO
Pay Total: Deductions 9 PERA/C 67 HCSP1 76 HCSP2 77 HCSP3 14 Def/MN 36 Def/Wenzel 17 Flex/Health 37 Flex/Dependent 21 Extra Life Insurance 26 United Way 38 World Vision 30 Dental-Single 31 Dental-Single+Spouse 62 Dental-Single+Child(ren) 32 Dental-Family 85 HSA/Single 86 HSA/Single+1 87 HSA/Family 92 HSA Contribution 14A Def/MN Roth 50 Insurance Opt-Out - Electric 51 Insurance Opt-Out - Water Deduction Total:
25203
Amount
Job Reg Hrly Overtime Double Time On-Call/Stand-by FLSA Bonus Pay Vacation Pay Sick Pay Holiday Pay On-Call/Stand-by/OT Personal Day
109,983.87 417.31 2,126.61 1,924.36 65.88 229.85 4,876.70 3,390.24 12,985.92 726.16 0.00 136,726.90
Hours 2,913.25 7.50 29.75 48.08 0.00 5.00 137.45 92.00 344.00 11.50 0.00 3,588.53
Amount 8,783.19 953.30 523.72 408.33 4,686.00 1,282.00 201.93 1,103.10 110.70 22.98 19.12 22.15 53.10 53.05 285.57 597.31 1,262.45 6,045.38 2,941.80 491.98 -796.20 -173.10 28,877.86
/pro/rpttemplate/acct/2.40.1/pl/PL_CHK_REG_TOTALS.xml.rpt
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KGreenberg25
CHECK REGISTER
January, 2018
APPROVED BY:
John Dietz
Allan Nadeau
Mary Stewart
Daryl Thompson
Matt Westgaard
3
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Page 1
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
36 01/18/2018 DD
Vendor
Vendor Name
Reference
Amount
1327
AUTOMATIC SYSTEMS CO
WELL #9 REPAIRS
435.80
WELL #9 REPAIRS
-435.80 0.00
Total for Check/Tran - 36: 37 01/31/2018 DD
8247
FERGUSON WATERWORKS #2516
MISC PARTS & SUPPLIES
-54.68
MISC PARTS & SUPPLIES - WELL #5 Total for Check/Tran - 37: 38 01/31/2018 DD
9273
METERING & TECHNOLOGY SOLUTION 6" Meter & ERT
-1,170.53
2" Meter & ERT, 1" D70 ERT & M70 Chamber
1,063.68
#33334-016 M70 Chamber Total for Check/Tran - 38: 1887 01/02/2018 WIRE 160
HCSP (ELECTRONIC)
HCSP EMPLOYEE CONTRIBUTIONS Total for Check/Tran - 1887:
MNDCP (ELECTRONIC)
MNDCP EMPLOYEE CONTRIBUTIONS
122.27 1,807.20 3,868.37
MNDCP ROTH EE CONTRIBUTIONS
122.79
MNDCP EMPLOYEE CONTRIBUTIONS
157.00
MNDCP ROTH EE CONTRIBUTIONS Total for Check/Tran - 1888:
100.00 4,248.16
1889 01/02/2018 WIRE 285
JOHN HANCOCK
WENZEL EMPLOYEE CONTRIBUTIONS
1890 01/02/2018 WIRE 8181
AMERICAN EXPRESS
General Manager American Express
1891 01/02/2018 WIRE 152
IRS - USA TAX PMT (ELECTRONIC)
PAYROLL TAXES - FEDERAL & FICA
12,238.23
PAYROLL TAXES - FEDERAL & FICA
16,019.78
PAYROLL TAXES - FEDERAL & FICA
1,424.63
1,221.80 832.51
PAYROLL TAXES - FEDERAL & FICA Total for Check/Tran - 1891: 1892 01/02/2018 WIRE 152
IRS - USA TAX PMT (ELECTRONIC)
PAYROLL TAXES - FEDERAL & FICA Total for Check/Tran - 1892:
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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1,716.68 31,399.32 440.79
PAYROLL TAXES - FEDERAL & FICA
25203
106.85 0.00 1,684.93
HCSP EMPLOYEE CONTRIBUTIONS
1888 01/02/2018 WIRE 161
54.68 0.00
618.38 1,059.17
Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 2
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
1893 01/03/2018 WIRE 160
HCSP (ELECTRONIC)
2017 EXCESS SICK PAYOUT - 6 9
2,719.31
1894 01/04/2018 WIRE 154
MINNESOTA REVENUE (ELECTRONIC) PAYROLL TAXES - STATE
181.43
1895 01/04/2018 WIRE 154
MINNESOTA REVENUE (ELECTRONIC) PAYROLL TAXES - STATE
4,833.34
PAYROLL TAXES - STATE Total for Check/Tran - 1895: 1896 01/04/2018 WIRE 7463
SELECTACCOUNT
HSA EMPLOYEE CONTRIBUTION
2,332.32
HSA EMPLOYEE CONTRIBUTION Total for Check/Tran - 1896: 1897 01/03/2018 WIRE 7463
SELECTACCOUNT
1898 01/08/2018 WIRE 166
ONLINE UTILITY EXCHANGE (ELECTR UTILITY EXCHANGE REPORT
FSA CLAIM REIMBURSEMENTS - 147
320.58 Total for Check/Tran - 1898:
PERA (ELECTRONIC)
7,736.94
PERA CONTRIBUTIONS
8,927.27 789.09
PERA CONTRIBUTIONS Total for Check/Tran - 1899: HCSP (ELECTRONIC)
HCSP EMPLOYEE CONTRIBUTIONS Total for Check/Tran - 1900:
MNDCP (ELECTRONIC)
MNDCP EMPLOYEE CONTRIBUTIONS
121.40 1,812.24 4,186.90
MNDCP ROTH EE CONTRIBUTIONS
251.10
MNDCP EMPLOYEE CONTRIBUTIONS
207.00
MNDCP ROTH EE CONTRIBUTIONS Total for Check/Tran - 1901:
25203
910.49 18,363.79 1,690.84
HCSP EMPLOYEE CONTRIBUTIONS
1901 01/16/2018 WIRE 161
80.14 400.72
PERA EMPLOYEE CONTRIBUTION PERA EMPLOYEE CONTRIBUTION
1900 01/16/2018 WIRE 160
233.25 2,565.57 600.00
UTILITY EXCHANGE REPORT
1899 01/12/2018 WIRE 153
541.79 5,375.13
1902 01/16/2018 WIRE 285
JOHN HANCOCK
WENZEL EMPLOYEE CONTRIBUTIONS
1903 01/09/2018 WIRE 7463
SELECTACCOUNT
2018 ER HSA CONTRIBUTION /pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
5
150.00 4,795.00 1,277.92 50,439.50
Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 3
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
2018 ER HSA CONTRIBUTION Total for Check/Tran - 1903: 1904 01/11/2018 WIRE 7463
SELECTACCOUNT
FSA CLAIM REIMBURSEMENTS - 32
115.25
FSA CLAIM REIMBURSEMENTS - 131
176.75
FSA CLAIM REIMBURSEMENTS - 133
165.00
FSA CLAIM REIMBURSEMENTS- 127
192.25
FSA CLAIM REIMBURSEMENTS - 139
192.25
FSA CLAIM REIMBURSEMENTS - 147
200.00 1,041.50
Total for Check/Tran - 1904: 1905 01/17/2018 WIRE 7463
SELECTACCOUNT
FSA CLAIM REIMBURSEMENTS - 131
176.93
1906 01/17/2018 WIRE 152
IRS - USA TAX PMT (ELECTRONIC)
PAYROLL TAXES - FEDERAL & FICA
11,923.83
PAYROLL TAXES - FEDERAL & FICA
16,543.58
PAYROLL TAXES - FEDERAL & FICA
1,394.72
PAYROLL TAXES - FEDERAL & FICA Total for Check/Tran - 1906: 1907 01/18/2018 WIRE 154
MINNESOTA REVENUE (ELECTRONIC) PAYROLL TAXES - STATE Total for Check/Tran - 1907:
1908 01/17/2018 WIRE 7463
SELECTACCOUNT
HSA EMPLOYEE CONTRIBUTION Total for Check/Tran - 1908:
WORLD VISION
EMPLOYEE CONTRIBUTIONS Total for Check/Tran - 1910:
MINNESOTA REVENUE SALES TX (ELE SALES AND USE TAX - DEC 2017 Total for Check/Tran - 1911: SELECTACCOUNT
FSA CLAIM REIMBURSEMENTS - 144 /pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
6
5.00 40.00 138,027.06
SALES AND USE TAX - DEC 2017
1912 01/24/2018 WIRE 7463
309.04 3,631.51 35.00
EMPLOYEE CONTRIBUTIONS
1911 01/22/2018 WIRE 174
528.51 5,227.17 3,322.47
HSA EMPLOYEE CONTRIBUTION
1910 01/19/2018 WIRE 3936
1,703.36 31,565.49 4,698.66
PAYROLL TAXES - STATE
25203
11,675.50 62,115.00
2,001.94 140,029.00 209.67
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9:44:26 AM
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01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
1913 01/24/2018 WIRE 7463
SELECTACCOUNT
FSA CLAIM REIMBURSEMENTS - 19
1914 01/26/2018 WIRE 153
PERA (ELECTRONIC)
PERA EMPLOYEE CONTRIBUTION
7,893.08
PERA CONTRIBUTIONS
9,107.40
139.98
PERA EMPLOYEE CONTRIBUTION
890.11
PERA CONTRIBUTIONS Total for Check/Tran - 1914: 1915 01/29/2018 WIRE 160
HCSP (ELECTRONIC)
HCSP EMPLOYEE CONTRIBUTIONS
1,748.40
HCSP EMPLOYEE CONTRIBUTIONS Total for Check/Tran - 1915: 1916 01/29/2018 WIRE 161
MNDCP (ELECTRONIC)
MNDCP EMPLOYEE CONTRIBUTIONS
136.95 1,885.35 4,479.00
MNDCP ROTH EE CONTRIBUTIONS
341.98
MNDCP EMPLOYEE CONTRIBUTIONS
207.00
MNDCP ROTH EE CONTRIBUTIONS Total for Check/Tran - 1916:
150.00 5,177.98
1917 01/29/2018 WIRE 285
JOHN HANCOCK
WENZEL EMPLOYEE CONTRIBUTIONS
1918 01/29/2018 WIRE 160
HCSP (ELECTRONIC)
TERMED EE 1/2 SICK REMITTED - 125
1919 01/30/2018 WIRE 152
IRS - USA TAX PMT (ELECTRONIC)
PAYROLL TAXES - FEDERAL & FICA
10,239.13
PAYROLL TAXES - FEDERAL & FICA
17,137.76
PAYROLL TAXES - FEDERAL & FICA
1,377.61
1,282.00 565.33
PAYROLL TAXES - FEDERAL & FICA Total for Check/Tran - 1919: 1920 01/30/2018 WIRE 7463
SELECTACCOUNT
HSA EMPLOYEE CONTRIBUTION Total for Check/Tran - 1920:
74214 01/04/2018 CHK
11
CITY OF ELK RIVER
1,938.84 30,693.34 2,632.76
HSA EMPLOYEE CONTRIBUTION
25203
1,027.06 18,917.65
309.04 2,941.80
PARTS & LABOR FOR UNIT #12
-1.92
PARTS & LABOR FOR UNIT #12
69.80
PARTS & LABOR FOR UNIT #5
-3.66
PARTS & LABOR FOR UNIT #5
136.86
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Accounts Payable Check Register
9:44:26 AM
Page 5
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
PARTS & LABOR FOR UNIT #8
-3.92
PARTS & LABOR FOR UNIT #8
140.98
PARTS & LABOR FOR UNIT #55
-9.62
PARTS & LABOR FOR UNIT #55
189.57
PARTS & LABOR FOR UNIT #61
97.70
PARTS & LABOR FOR UNIT #56
32.78
PARTS & LABOR FOR UNIT #3
-1.92
PARTS & LABOR FOR UNIT #3
69.80
PARTS & LABOR FOR UNIT #24
-1.22
PARTS & LABOR FOR UNIT #24
58.94
PARTS & LABOR FOR UNIT #11
194.44
PARTS & LABOR FOR UNIT #23
128.15
PARTS & LABOR FOR UNIT #14
-1.09
PARTS & LABOR FOR UNIT #14
35.96
PARTS & LABOR FOR UNIT #14
-0.06
PARTS & LABOR FOR UNIT #14 Total for Check/Tran - 74214: 74215 01/04/2018 CHK
112
DACOTAH PAPER CO.
CLEANING SUPPLIES
198.96
CLEANING SUPPLIES Total for Check/Tran - 74215: 74216 01/04/2018 CHK
398
ALTEC INDUSTRIES, INC
49.74 248.70
PARTS & LABOR FOR UNIT #21
-102.65
PARTS & LABOR FOR UNIT #21
3,094.26
PARTS & LABOR FOR UNIT #21
-0.52
PARTS & LABOR FOR UNIT #21
507.52 3,498.61
Total for Check/Tran - 74216:
25203
1.90 1,133.47
74217 01/04/2018 CHK
2512
AMARIL UNIFORM COMPANY
EMPLOYEE CLOTHING - HOMMERDING
74218 01/04/2018 CHK
4531
AT & T MOBILITY
AIRCARDS FOR LAPTOPS
49.69
AIRCARDS FOR LAPTOPS
1,271.43
AIRCARDS FOR LAPTOPS
307.04
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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1,197.00
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9:44:26 AM
Page 6
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount Total for Check/Tran - 74218:
74219 01/04/2018 CHK
8552
BECK LAW OFFICE
LEGAL SERVICES - NOV 2017
1,434.24
LEGAL SERVICES - NOV 2017 Total for Check/Tran - 74219:
358.56 1,792.80
74220 01/04/2018 CHK
388
BEVINS COMPANY
Hi-pot repair
74221 01/04/2018 CHK
8840
BLUE 42
MONTHLY HOSTING OF WEBSITE
59.60
MONTHLY HOSTING OF WEBSITE
59.60
244.85
MONTHLY HOSTING OF WEBSITE Total for Check/Tran - 74221:
29.80 149.00
74222 01/04/2018 CHK
9654
CARDMEMBER SERVICE
FIRST NATIONAL BANK VISA
1,562.58
74223 01/04/2018 CHK
5019
DELTA DENTAL OF MINNESOTA
DENTAL INSURANCE - JAN 2018
2,500.30
DENTAL INSURANCE - JAN 2018
925.59
DENTAL INSURANCE - JAN 2018
558.21
DENTAL INSURANCE - JAN 2018 Total for Check/Tran - 74223:
25203
1,628.16
74224 01/04/2018 CHK
9997
RYAN DOLIBER
Credit Balance Refund
74225 01/04/2018 CHK
338
DRYDEN EXCAVATING INC
WATERMAIN TIE-IN & RELOCATION
74226 01/04/2018 CHK
4459
DVS RENEWAL
TAB RENEWAL - UNIT #1
93.92 4,078.02 375.00 1,975.00 12.80
TAB RENEWAL - UNIT #1
3.20
TAB RENEWAL - UNIT #2
15.20
TAB RENEWAL - UNIT #2
0.80
TAB RENEWAL - UNIT #3
16.00
TAB RENEWAL - UNIT #4
16.00
TAB RENEWAL - UNIT #5
16.00
TAB RENEWAL - UNIT #6
15.20
TAB RENEWAL - UNIT #6
0.80
TAB RENEWAL - UNIT #7
16.00
TAB RENEWAL - UNIT #8
16.00
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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9:44:26 AM
Revision: 92262 Page 7
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
25203
Pmt Type
Vendor
Vendor Name
Reference
Amount
TAB RENEWAL - UNIT #9
16.00
TAB RENEWAL - UNIT #10
16.00
TAB RENEWAL - UNIT #12
16.00
TAB RENEWAL - UNIT #13
16.00
TAB RENEWAL - UNIT #14
15.20
TAB RENEWAL - UNIT #14
0.80
TAB RENEWAL - UNIT 15
16.00
TAB RENEWAL - UNIT #17
16.00
TAB RENEWAL - UNIT #18
12.80
TAB RENEWAL - UNIT #18
3.20
TAB RENEWAL - UNIT #20
16.00
TAB RENEWAL - UNIT #22
16.00
TAB RENEWAL - UNIT #25
16.00
TAB RENEWAL - UNIT #26
16.00
TAB RENEWAL - UNIT #28
16.00
TAB RENEWAL - UNIT #29
16.00
TAB RENEWAL - UNIT #30
16.00
TAB RENEWAL - UNIT #32
15.20
TAB RENEWAL - UNIT #32
0.80
TAB RENEWAL - UNIT #33
15.20
TAB RENEWAL - UNIT #33
0.80
TAB RENEWAL - UNIT #34
16.00
TAB RENEWAL - UNIT #35
12.80
TAB RENEWAL - UNIT #35
3.20
TAB RENEWAL - UNIT #36
15.20
TAB RENEWAL - UNIT #36
0.80
TAB RENEWAL - UNIT #40
16.00
TAB RENEWAL - UNIT #42
16.00
TAB RENEWAL - UNIT #43
16.00
TAB RENEWAL - UNIT #45
16.00
TAB RENEWAL - UNIT #47
16.00
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Accounts Payable Check Register
9:44:26 AM
Page 8
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
TAB RENEWAL - UNIT #48
16.00
TAB RENEWAL - UNIT #49
16.00
TAB RENEWAL - UNIT #60
17.00
TAB RENEWAL - UNIT #61
38.00
TAB RENEWAL - UNIT #11
16.00
TAB RENEWAL - UNIT #16
16.00
TAB RENEWAL - UNIT #21
16.00
TAB RENEWAL - UNIT #23
16.00
TAB RENEWAL - UNIT #41
16.00
TAB RENEWAL - UNIT #44
16.00
TAB RENEWAL - UNIT #46
16.00
TAB RENEWAL - UNIT #40
16.00
TAB RENEWAL - UNIT #51 Total for Check/Tran - 74226: 74227 01/04/2018 CHK
671
FASTENAL COMPANY
MISC PARTS & SUPPLIES
74228 01/04/2018 CHK
8949
FS3 INC.
Class 2 Zipper knit mesh safety vests
6.00 -8.07
Safty vest Total for Check/Tran - 74228: 74229 01/04/2018 CHK
28
G & K SERVICES
MATS & TOWELS
125.48 117.41 113.14
MATS & TOWELS Total for Check/Tran - 74229:
28.29 141.43
74230 01/04/2018 CHK
80
GRAINGER
MISC PARTS & SUPPLIES - WELL #3
53.66
74231 01/04/2018 CHK
5118
GRAND RENTAL STATION
CHAINSAW REPAIR
85.17
MISC PARTS & SUPPLIES - CHAINSAW PARTS Total for Check/Tran - 74231:
25203
20.00 763.00
48.33 133.50
74232 01/04/2018 CHK
8246
GRANITE CITY CONSTRUCTION AND D Waco Bank #2-Concrete Work & Fence Insta
74233 01/04/2018 CHK
6836
INNOVATIVE OFFICE SOLUTIONS, LLC OFFICE SUPPLIES
77.15
OFFICE SUPPLIES
19.29
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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11,990.59
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Accounts Payable Check Register
9:44:26 AM
Page 9
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount Total for Check/Tran - 74233:
MENARDS-0296
74234 01/04/2018 CHK
145
MENARDS
74235 01/04/2018 CHK
147
MINNESOTA POLLUTION CONTROL AG WATER OPERATOR RENEWAL - VOLK
74236 01/04/2018 CHK
811
PRIME ADVERTISING & DESIGN, INC.
MARKETING & DESIGN CONTRACT - JAN 2018
74237 01/04/2018 CHK
8897
RALPHIE'S MINNOCO
RALPHIE'S MINNOCO
81.29
74238 01/04/2018 CHK
3218
RDO EQUIPMENT
Wand male fitting
11.32
850.67 23.00
famale wand fitting
2,500.00
11.32
vac wand
343.49
MISC PARTS & SUPPLIES - MINI EXCAVATOR frost teeth
35.35 -64.00
frost teeth Total for Check/Tran - 74238:
71.68 409.16
74239 01/04/2018 CHK
9161
SHERBURNE COUNTY AREA UNITED W EMPLOYEE CONTRIBUTIONS - 4TH QTR
160.86
74240 01/04/2018 CHK
227
SHOE MENDERS & SADDLERY, INC
EMPLOYEE CLOTHING - GROEBNER BOOTS
-14.78
EMPLOYEE CLOTHING - GROEBNER BOOTS
229.78
EMPLOYEE CLOTHING - WEBER BOOTS
-13.75
EMPLOYEE CLOTHING - WEBER BOOTS Total for Check/Tran - 74240: 74241 01/04/2018 CHK
74
SCOTT THORESON
74242 01/04/2018 CHK
90
TOTAL TOOL SUPPLY INC
213.75 415.00
URD SCHOOL EXPENSES - THORESON
103.93
STOP PAYMENT FEE - CHECK #72946
-20.00 83.93
Total for Check/Tran - 74241: MISC PARTS & SUPPLIES - SHIPPING
-0.67
MISC PARTS & SUPPLIES - SHIPPING Total for Check/Tran - 74242:
25203
96.44
KEROSENE
10.45 9.78
74243 01/11/2018 CHK
11
CITY OF ELK RIVER
74244 01/11/2018 CHK
610
WRIGHT HENNEPIN COOPERATIVE ELE FIRE PANEL MONITORING - WELL #7
29.87
74245 01/11/2018 CHK
9997
805 SCHOOL ST LLC
26.18
Credit Balance Refund /pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
12
32.85
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Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 10
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
74246 01/11/2018 CHK
2512
AMARIL UNIFORM COMPANY
EMPLOYEE CLOTHING - BEANIES
74247 01/11/2018 CHK
600
ANDY'S ELECTRIC, INC
COBORN'S EV CHARGER INSTALLATION
74248 01/11/2018 CHK
6138
BLUE EGG BAKERY
COOKIES FOR MEETINGS
Amount 86.69 3,945.46 5.60
COOKIES FOR MEETINGS Total for Check/Tran - 74248: 74249 01/11/2018 CHK
9997
STEPHEN BOYER
Credit Balance Refund
74250 01/11/2018 CHK
9997
CARLSON BROTHERS, LLC
DEP To AP
74251 01/11/2018 CHK
5013
CARR'S TREE SERVICE, INC
TREE TRIMMING - 12/14/17
44.92 150.03 4,979.52
TREE TRIMMING - 11/27/17
74252 01/11/2018 CHK
74253 01/11/2018 CHK
671
2960
FASTENAL COMPANY
FRED PRYOR SEMINARS
Total for Check/Tran - 74251:
5,973.54 10,953.06
MISC PARTS & SUPPLIES
-1.61
MISC PARTS & SUPPLIES Total for Check/Tran - 74252:
25.00 23.39
EXCEL 2 SEMINAR - GREENBERG
39.20
EXCEL 2 SEMINAR - GREENBERG
9.80
EXCEL SEMINAR - GREENBERG
63.20
EXCEL SEMINAR - GREENBERG Total for Check/Tran - 74253: 74254 01/11/2018 CHK
5118
GRAND RENTAL STATION
MISC PARTS & SUPPLIES - CHAINSAW SCREW MISC PARTS & SUPPLIES - HELMET SYSTEM Total for Check/Tran - 74254:
74255 01/11/2018 CHK
53
GREAT RIVER ENERGY
15.80 128.00 0.65 79.03 79.68
MAPPING SERVICES
196.80
MAPPING SERVICES
49.20
4TH QTR CONNECTION CHARGE Total for Check/Tran - 74255:
25203
1.40 7.00
150.00 396.00
74256 01/11/2018 CHK
809
HAWKINS, INC.
WATER CHEMICALS
767.79
74257 01/11/2018 CHK
9997
DANIEL HORST
Credit Balance Refund
64.54
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 11
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
74258 01/11/2018 CHK
9997
KAYAK PROPERTIES
Credit Balance Refund
133.18
74259 01/11/2018 CHK
9997
KEVIN KOCH
Credit Balance Refund
64.50
74260 01/11/2018 CHK
9997
PAVLO LAVRYNETS
Credit Balance Refund
60.93
74262 01/11/2018 CHK
119
MINNESOTA COMPUTER SYSTEMS INC OFFICE SUPPLIES
393.67
COPIER CONTRACTS
293.83
COPIER CONTRACTS Total for Check/Tran - 74262: 74263 01/11/2018 CHK
120
NAPA AUTO PARTS
PARTS FOR UNIT #53
152.46
MISC PARTS & SUPPLIES
24.98
PARTS FOR UNIT #54 Total for Check/Tran - 74263: 74264 01/11/2018 CHK
573
NCPERS MINNESOTA
8606
NEOPOST USA INC.
208.00
EXTRA LIFE INSURANCE FOR ERMU EMPLOYEES
32.00 240.00
FOLDING MACHINE REPAIR
447.18
FOLDING MACHINE REPAIR Total for Check/Tran - 74265: 74266 01/11/2018 CHK
3321
NORTHSTAR CHAPTER - APA
MEMBERSHIP RENEWAL - GREENBERG
111.79 558.97 40.00
MEMBERSHIP RENEWAL - GREENBERG Total for Check/Tran - 74266:
25203
74.13 251.57
EXTRA LIFE INSURANCE FOR ERMU EMPLOYEES Total for Check/Tran - 74264:
74265 01/11/2018 CHK
73.46 760.96
10.00 50.00
74267 01/11/2018 CHK
9997
NTW LLC
Credit Balance Refund
932.00
74268 01/11/2018 CHK
9997
DAVID PALMER
Credit Balance Refund
31.61
74269 01/11/2018 CHK
9997
PENNYMAC LOAN SVCS, LLC.
DEP To AP
250.23
74270 01/11/2018 CHK
9997
PENNYMAC LOAN SVCS, LLC.
Credit Balance Refund
133.89
74272 01/11/2018 CHK
572
RAMADA MARSHALL
TRANSFORMER SCHOOL HOTEL - WARK
326.97
TRANSFORMER SCHOOL HOTEL - GROEBNER
326.97
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 12
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
TRANSFORMER SCHOOL HOTEL - KOEHLER Total for Check/Tran - 74272: 74273 01/11/2018 CHK
128
RANDY'S SANITATION, INC.
TRASH SERVICE - DEC 2017
594.18
TRASH SERVICE - DEC 2017
148.54
RECYCLING SERVICE - JAN 2018
32.04
RECYCLING SERVICE - JAN 2018
8.01 782.77
Total for Check/Tran - 74273: 74274 01/11/2018 CHK
3218
RDO EQUIPMENT
MISC PARTS & SUPPLIES - BORE RIG
1,403.28
PARTS & LABOR FOR UNIT #61 Total for Check/Tran - 74274:
1,480.74 2,884.02
74275 01/11/2018 CHK
130
RESCO
300KVA Transformer
6,774.00
74276 01/11/2018 CHK
9997
ISAAC SOUDER
Credit Balance Refund
79.16
74277 01/11/2018 CHK
9997
EUNICE STEGINK
Credit Balance Refund
127.51
74278 01/11/2018 CHK
6107
STUART C. IRBY CO.
Animal Guard
246.00
74279 01/11/2018 CHK
331
TRANSUNION
SKIP TRACING - NOV 2017
20.00
SKIP TRACING - NOV 2017 Total for Check/Tran - 74279:
5.00 25.00
74280 01/11/2018 CHK
9997
UNDERGROUND PIERCING INC
Credit Balance Refund
74281 01/11/2018 CHK
9191
UPS
SHIPPING
34.64
74282 01/11/2018 CHK
222
UTILITY CONSULTANTS, INC
OIL SAMPLING
13.00
74283 01/11/2018 CHK
2454
WAL-MART 01-3209
CIP - LIGHTING COUPONS
24.00
74284 01/11/2018 CHK
9997
WASHINGTON STREET INVESTORS
DEP To AP
74285 01/11/2018 CHK
2609
WASTE MANAGEMENT
ERMU GAS GENERATOR SERV AGMNT-DEC 2017
32,761.33
LANDFILL GAS PLANT - DEC 2017
12,594.39 45,355.72
400.33
250.05
Total for Check/Tran - 74285: 74286 01/11/2018 CHK 25203
326.97 980.91
135
WATER LABORATORIES INC
WATER TESTING - DEC 2017
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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480.00
Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 13
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
74287 01/11/2018 CHK
Vendor
Vendor Name
Reference
Amount
1074
WINDSTREAM
OFFICE TELEPHONE
357.67
OFFICE TELEPHONE
89.42 447.09
Total for Check/Tran - 74287: 74288 01/11/2018 CHK
7462
QUILL.COM
OFFICE SUPPLIES
108.52
OFFICE SUPPLIES Total for Check/Tran - 74288: 74289 01/11/2018 CHK
145
MENARDS
CIP - LIGHTING COUPONS
1,168.00
74290 01/18/2018 CHK
11
CITY OF ELK RIVER
FUEL USAGE - NOV 2017
2,913.37
FUEL USAGE - NOV 2017
704.95
PHONE MAINTENANCE
477.60
PHONE MAINTENANCE
119.40
LEGAL FEES Total for Check/Tran - 74290: 74291 01/18/2018 CHK
2512
AMARIL UNIFORM COMPANY
EMPLOYEE CLOTHING - LOGO
74292 01/18/2018 CHK
2920
BATTERIES PLUS BULBS
PARTS FOR UNIT #1
114.53 Total for Check/Tran - 74292:
74293 01/18/2018 CHK
9
BORDER STATES ELECTRIC SUPPLY
108.50 4,323.82 15.43
PARTS FOR UNIT #1
1/0 Solid 220 TRXLP 15KV URD Primary Wir
28.63 143.16 20,238.22
6 amp type T fuses & 5/8 square washers
218.00
5/8 square washers
136.00
17 oz white marking paint
-22.08
White Paint
343.20
Tallboy APWA Brillant Red
-22.61
Red tall boys
351.41
#4/0 Peguin Wire & #336 ACSR Merlin Wire
8,264.68
WACO SUBSTATION RETURNS
-29,306.38
900 AMP 15KV 3PH Gand Switches Total for Check/Tran - 74293: 25203
27.14 135.66
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
16
6,603.50 6,803.94
Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 14
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
74294 01/18/2018 CHK
5013
CARR'S TREE SERVICE, INC
TREE TRIMMING - 12/11/17
6,189.26
74295 01/18/2018 CHK
9997
ABBY COTA
INACTIVE REFUND
31.33
74296 01/18/2018 CHK
9192
CUB FOODS ELK RIVER
LEADERSHIP DEVELOPMENT - SNACK
11.18
LEADERSHIP DEVELOPMENT - SNACK Total for Check/Tran - 74296: 74297 01/18/2018 CHK
112
DACOTAH PAPER CO.
OFFICE SUPPLIES
184.49
74298 01/18/2018 CHK
9997
DONE RIGHT PROPERTIES LLC
Credit Balance Refund
405.01
74299 01/18/2018 CHK
25
ECM PUBLISHERS INC
CLASSIFIED AD - INVENTORY FOREPERSON
162.00
74300 01/18/2018 CHK
23
ELK RIVER MUNICIPAL UTILITIES
ELECTRIC SERVICES - LIGHTS & SIGNALS
175.00
ELECTRIC SERVICES - LIGHTS & SIGNALS
1,090.53
ELECTRIC SERVICE - WELLS Total for Check/Tran - 74300: 74301 01/18/2018 CHK
122
ELK RIVER WINLECTRIC CO
2" Pipe Straps
85.09 1,350.62 48.90
2" PVC Conduit
200.52
2" PVC Conduit
-12.90
2" PVC Conduit
56.30
2" PVC Conduit
-3.62
2" PVC Conduit
37.53
2" PVC Conduit
-2.41
MISC PARTS & SUPPLIES Total for Check/Tran - 74301:
6.89 331.21
74302 01/18/2018 CHK
9997
TIM FOGARTY
INACTIVE REFUND
74303 01/18/2018 CHK
5053
FRONTIER PRECISION, INC.
Trimble
3,839.81
Trimble
959.95 4,799.76
25.48
Total for Check/Tran - 74303:
25203
2.80 13.98
74304 01/18/2018 CHK
5118
GRAND RENTAL STATION
MISC PARTS & SUPPLIES - CHAINSAW
28.52
74305 01/18/2018 CHK
4984
ANGELA HAUGE
OFFICE SUPPLIES
74.63
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 15
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
74306 01/18/2018 CHK
Vendor
Vendor Name
Reference
Amount
809
HAWKINS, INC.
EQUIPMENT RENTAL
3,420.00
WATER CHEMICALS
1,133.52 4,553.52
Total for Check/Tran - 74306: 74307 01/18/2018 CHK
9997
MATHEW HEVEY
INACTIVE REFUND
75.00
74308 01/18/2018 CHK
9997
LEE HOHLEN
INACTIVE REFUND
80.66
74309 01/18/2018 CHK
9997
BRUCE HOLLAND
INACTIVE REFUND
66.73
74310 01/18/2018 CHK
9997
DAVID JANTZI
INACTIVE REFUND
37.34
74311 01/18/2018 CHK
9997
AMANDA JERKOVICH
INACTIVE REFUND
44.48
74312 01/18/2018 CHK
9997
AMANDA KASPER
INACTIVE REFUND
62.51
74313 01/18/2018 CHK
9997
PORTER MORRELL
INACTIVE REFUND
60.37
74314 01/18/2018 CHK
120
NAPA AUTO PARTS
PARTS FOR UNIT #15
89.20
PARTS FOR UNIT #58
56.41 145.61
Total for Check/Tran - 74314: 74315 01/18/2018 CHK
9997
NICHOLAS OLSEN
INACTIVE REFUND
148.56
74316 01/18/2018 CHK
9997
MICHAEL OLSON
Credit Balance Refund
40.79
74317 01/18/2018 CHK
9997
PATHLIGHT PROPERTY MGMT
INACTIVE REFUND
189.96
74318 01/18/2018 CHK
106
PERFECTION PLUS, INC.
MONTHLY CLEANING FOR THE PLANT-JAN 2018
470.25
MONTHLY CLEANING FOR THE PLANT-JAN 2018
117.56 587.81
Total for Check/Tran - 74318: 74319 01/18/2018 CHK
9997
BRETT RADDE
INACTIVE REFUND
16.87
74320 01/18/2018 CHK
3218
RDO EQUIPMENT
PARTS FOR UNIT #53
23.28
PARTS FOR UNIT #53 Total for Check/Tran - 74320:
25203
23.00 46.28
74321 01/18/2018 CHK
9997
REBECCA DORAN PROPERTIES, LLC
Credit Balance Refund
182.24
74322 01/18/2018 CHK
9997
CAROLYN REHLING
INACTIVE REFUND
43.00
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 16
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
74323 01/18/2018 CHK
Vendor
Vendor Name
Reference
Amount
688
RESOURCE TRAINING & SOLUTIONS
2018 MEMBERSHIP FEE
148.80
2018 MEMBERSHIP FEE
37.20 186.00
Total for Check/Tran - 74323: 74324 01/18/2018 CHK
3219
RESOURCE TRAINING & SOLUTIONS/B HEALTH CARE PREMIUMS - FEB 2018
43,498.76
HEALTH CARE PREMIUMS - FEB 2018
17,703.26
HEALTH CARE PREMIUMS - FEB 2018
9,666.48
HEALTH CARE PREMIUMS - FEB 2018 Total for Check/Tran - 74324: 74325 01/18/2018 CHK
9997
SHADE TREE CONSTRUCTION INC
Credit Balance Refund
74326 01/18/2018 CHK
229
SHERBURNE COUNTY ZONING
PROMISSORY NOTE & SEC AGRMNT - FEB 2018
74327 01/18/2018 CHK
9997
DARCY SWIGART
INACTIVE REFUND
86.38
74328 01/18/2018 CHK
9191
UPS
SHIPPING
58.37
74329 01/18/2018 CHK
3360
UPS STORE #5093
SHIPPING
49.06
74330 01/18/2018 CHK
9997
ISABELLA WILSON
INACTIVE REFUND
61.97
74331 01/18/2018 CHK
9997
VICKI WREDBERG
INACTIVE REFUND
78.90
74332 01/25/2018 CHK
76
CONNEXUS ENERGY
CTY RD 12 INTERCONNECTION
2,416.49
74333 01/25/2018 CHK
102
ABDO EICK & MEYERS, LLP
AUDIT SERVICES YEAR ENDED 12/31/17
4,800.00
314.60
AUDIT SERVICES YEAR ENDED 12/31/17 Total for Check/Tran - 74333:
16,521.00
1,200.00 6,000.00
74334 01/25/2018 CHK
522
ALTERNATIVE TECHNOLOGIES, INC
OIL SAMPLES
1,560.00
74335 01/25/2018 CHK
5013
CARR'S TREE SERVICE, INC
TREE TRIMMING - 12/30/17
3,436.93
TREE TRIMMMING - 12/23/17 Total for Check/Tran - 74335: 74336 01/25/2018 CHK
11
CITY OF ELK RIVER
FRANCHISE FEE CREDIT - NOV 2017 FRANCHISE FEE - ASSESSMENTS 2017 FRANCHISE FEE - 4TH QTR 2017
25203
1,581.50 72,450.00
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
19
5,591.76 9,028.69 -950.00 100.78 218,165.84
Elk River Municipal Utilities 02/05/2018
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Accounts Payable Check Register
9:44:26 AM
Page 17
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
FRANCHISE FEE CREDIT - DEC 2017
-950.00
BILLED SERVICES - SEWER DEC 2017
173,339.24
WRITE OFF - SEWER DEC 2017
-3.66
BILLED SERVICES - ORGANICS DEC 2017
1,138.31
BILLED SERVICES - STICKERSS DEC 2017
108.00
BILLED SERVICES - TRASH DEC 2017
111,617.80
SERVICES BILLED - STORMWATER DEC 2017 WRITE OFF - DEC 2017
-24.77
REVENUE TRANSFER - DEC 2017 Total for Check/Tran - 74336:
89,668.02 630,719.91
74337 01/25/2018 CHK
76
CONNEXUS ENERGY
LOSS OF REVENUE - AREA 1 & 2
74338 01/25/2018 CHK
151
CONNEXUS ENERGY
PURCHASED POWER & SUBSTATION CREDIT
-400.00
PURCHASED POWER & SUBSTATION CREDIT
2,150,983.54 2,150,583.54
570,725.47
Total for Check/Tran - 74338: 74339 01/25/2018 CHK
7448
CRC
CUSTOMER SERVICE FOR AFTER HOURS
1,764.61
CUSTOMER SERVICE FOR AFTER HOURS Total for Check/Tran - 74339: 74340 01/25/2018 CHK
9192
CUB FOODS ELK RIVER
441.15 2,205.76
EMPLOYEE RECOGNITION LUNCH BEVERAGE
5.42
EMPLOYEE RECOGNITION LUNCH BEVERAGE
1.36 6.78
Total for Check/Tran - 74340: 74341 01/25/2018 CHK
212
DAKOTA SUPPLY GROUP
#VM-2E2T1P Vision Meter
74342 01/25/2018 CHK
5019
DELTA DENTAL OF MINNESOTA
DENTAL INSURANCE - FEB 2018
2,169.27
DENTAL INSURANCE - FEB 2018
810.45
DENTAL INSURANCE - FEB 2018
486.25
193.00
DENTAL INSURANCE - FEB 2018 Total for Check/Tran - 74342:
25203
38,510.35
74.73 3,540.70
74343 01/25/2018 CHK
9354
DIRECT PORTABLE TOILET SERVICES L PORTABLE TOILET RENTAL SERVICE
144.26
74344 01/25/2018 CHK
25
ECM PUBLISHERS INC
162.00
CLASSIFIED AD
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Elk River Municipal Utilities 02/05/2018
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Accounts Payable Check Register
9:44:26 AM
Page 18
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
74345 01/25/2018 CHK
Vendor
Vendor Name
Reference
Amount
23
ELK RIVER MUNICIPAL UTILITIES
ELECTRIC SERVICE
1,172.20
ELECTRIC SERVICE
719.44
ELECTRIC SERVICE
1,064.59
ELECTRIC SERVICE
4,726.15
ELECTRIC SERVICE
266.15
ELECTRIC SERVICE - PLANT
1,870.78
ELECTRIC SERVICE - LIGHTS & SIGNALS
500.00
ELECTRIC SERVICE - LIGHTS & SIGNALS
13,699.07
ELECTRIC SERVICE - DT EV CHARGER
11.73
ELECTRIC SERVICE - LANDFILL Total for Check/Tran - 74345: 74346 01/25/2018 CHK
28
G & K SERVICES
MATS & TOWELS
113.14
MATS & TOWELS Total for Check/Tran - 74346: 74347 01/25/2018 CHK
91
GOPHER STATE ONE-CALL
28.29 141.43
LOCATES FOR - DEC 2017
76.95
LOCATES FOR - DEC 2017
25.65
LOCATES FOR - DEC 2017 Total for Check/Tran - 74347:
25.65 128.25
74348 01/25/2018 CHK
9997
JOHN HAWKINS
Credit Balance Refund
318.37
74349 01/25/2018 CHK
824
HOME DEPOT CREDIT SERVICES
HOME DEPOT
171.83
74350 01/25/2018 CHK
6836
INNOVATIVE OFFICE SOLUTIONS, LLC OFFICE SUPPLIES
15.85
OFFICE SUPPLIES
3.96
OFFICE SUPPLIES
20.58
OFFICE SUPPLIES
4.00
OFFICE SUPPLIES
19.88
OFFICE SUPPLIES
4.97
OFFICE SUPPLIES
-7.99
OFFICE SUPPLIES OFFICE SUPPLIES - SALES TAX CREDIT 25203
149.62 24,179.73
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
21
-1.99 -20.29
Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 19
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
OFFICE SUPPLIES - SALES TAX CREDIT Total for Check/Tran - 74350: 74351 01/25/2018 CHK
297
JACK HENRY & ASSOCIATES, INC
ACH TRANSACTIONS
163.20
ACH TRANSACTIONS Total for Check/Tran - 74351: 74352 01/25/2018 CHK
202
MINNESOTA DEPT OF PUBLIC SAFETY HAZARDOUS MATERIALS - WELL #2
40.80 204.00 100.00
HAZARDOUS MATERIAL - WELL #3
100.00
HAZARDOUS MATERIALS - WELL #4
100.00
HAZARDOUS MATERIALS - WELL #5
100.00
HAZARDOUS MATERIALS - WELL #6
100.00
HAZARDOUS MATERIALS - WELL #7
100.00
HAZARDOUS MATERIALS
100.00
HAZARDOUS MATERIALS - PLANT Total for Check/Tran - 74352:
25.00 725.00
74353 01/25/2018 CHK
2956
MINNESOTA DEPT OF TRANSPORTATIO HWY 10 WATER MAIN RELOCATION
74354 01/25/2018 CHK
9997
MINNESOTA HOME VENTURE, INC.
Credit Balance Refund
155.87
74355 01/25/2018 CHK
9997
MINNESOTA HOME VENTURE, INC.
Credit Balance Refund
137.12
74356 01/25/2018 CHK
39
MMUA
MEMBER DUES - 2018
74357 01/25/2018 CHK
8606
NEOPOST USA INC.
FOLDING MACHINE REPAIR PART
206,161.20
29,504.00 10.12
FOLDING MACHINE REPAIR PART Total for Check/Tran - 74357: 74358 01/25/2018 CHK
25203
-5.07 33.90
9300
NISC
2.52 12.64
RECURRING INVOICE - DEC 2017
53.43
RECURRING INVOICE - DEC 2017
9,174.09
RECURRING INVOICE - DEC 2017
1,479.94
BILLING INSERT
715.63
BILLING INSERT
178.91
MONTHLY AMS INVOICE - DEC 2017
5,956.71
MONTHLY AMS INVOICE - DEC 2017
1,489.18
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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Accounts Payable Check Register
9:44:26 AM
Page 20
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
MONTHLY MISC INVOICE - DEC 2017
915.53
MONTHLY MISC INVOICE - DEC 2017
228.88 20,192.30
Total for Check/Tran - 74358: 74359 01/25/2018 CHK
6149
OLD REPUBLIC
ELECTRICAL CONTRACTOR BOND
74360 01/25/2018 CHK
5056
PLAISTED COMPANIES, INC.
FILL SAND
219.00 31.02
FILL SAND Total for Check/Tran - 74360: 74361 01/25/2018 CHK
3218
RDO EQUIPMENT
PARTS FOR UNIT #46
74362 01/25/2018 CHK
5022
CHRISTOPHER SCHEFF
CIP - GROUND SOURCE HEAT PUMP REBATE
74363 01/25/2018 CHK
9997
MELINDA SUCHECKI
Credit Balance Refund
74364 01/25/2018 CHK
7237
SUSA
MEMBERSHIP RENEWAL - 2018
125.00
74365 01/25/2018 CHK
8948
TRYCO LEASING INC.
LEASE FOR COPIER AT PLANT
112.20
235.27 3,600.00 38.69
LEASE FOR COPIER AT PLANT Total for Check/Tran - 74365:
28.04 140.24
74366 01/25/2018 CHK
8808
WATER CONSERVATION SERVICE, INC. WATER LEAK DETECTING
796.35
74367 01/25/2018 CHK
55
WESCO RECEIVABLES CORP.
3/8" Guy Wire
646.00
74368 01/25/2018 CHK
3936
WORLD VISION
2017 BALANCE OF EE CONTRIBUTIONS
13.16
2017 BALANCE OF EE CONTRIBUTIONS Total for Check/Tran - 74368: 74369 01/31/2018 CHK
2512
AMARIL UNIFORM COMPANY
2.50 15.66
EMPLOYEE COTHING - OLSON
308.86
EMPLOYEE CLOTHING - MCLEAN
181.40
EMPLOYEE CLOTHING - MCLEAN
25203
9.51 40.53
9.55
EMPLOYEE CLOTHING - HOMMERDING
190.95
EMPLOYEE CLOTHING - JAGERSON
190.95
EMPLOYEE CLOTHING - HOMMERDING
316.30
EMPLOYEE CLOTHING - RUPRECHT
193.89
EMPLOYEE CLOTHING - RUPRECHT
10.20
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Elk River Municipal Utilities 02/05/2018
Revision: 92262
Accounts Payable Check Register
9:44:26 AM
Page 21
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount Total for Check/Tran - 74369:
74370 01/31/2018 CHK
1
AMERICAN PUBLIC POWER ASSOC
E & O CONF - 6 72
74371 01/31/2018 CHK
4531
AT & T MOBILITY
AIRCARDS FOR LAPTOPS
49.73
AIRCARDS FOR LAPTOPS
1,273.23
1,500.00
AIRCARDS FOR LAPTOPS Total for Check/Tran - 74371: 74372 01/31/2018 CHK
8552
BECK LAW OFFICE
LEGAL SERVICES - DEC 2017
307.35 1,630.31 1,434.24
LEGAL SERVICES - DEC 2017 Total for Check/Tran - 74372:
358.56 1,792.80
74373 01/31/2018 CHK
214
BELL LUMBER & POLE COMPANY
Poles
74374 01/31/2018 CHK
5024
BURSCHVILLE CONSTRUCTION, INC
REPAIR GATE VALVE BOX
74375 01/31/2018 CHK
3982
CENTERPOINT ENERGY
NATURAL GAS & IRON REMOVAL - DEC 2017
3,821.92
NATURAL GAS & IRON REMOVAL - DEC 2017
447.19 4,269.11
15,689.00 413.00
Total for Check/Tran - 74375: 74376 01/31/2018 CHK
11
CITY OF ELK RIVER
2010A GO IMP BOND PRINCIPAL & INTEREST
80,000.00
2010A GO IMP BOND PRINCIPAL & INTEREST
10,480.00
2010A GO IMP BOND PRINCIPAL & INTEREST
20,000.00
2010A GO IMP BOND PRINCIPAL & INTEREST
2,620.00
PARTS & LABOR FOR UNIT #32
-2.92
PARTS & LABOR FOR UNIT #32
197.33
PARTS & LABOR FOR UNIT #32
-0.15
PARTS & LABOR FOR UNIT #32
10.38
PARTS & LABOR FOR UNIT #6
-1.27
PARTS & LABOR FOR UNIT #6
57.85
PARTS & LABOR FOR UNIT #6
-0.07
PARTS & LABOR FOR UNIT #6
3.05
LABOR FOR UNIT #21 PARTS & LABOR FOR UNIT #7 25203
1,402.10
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
24
80.00 -105.22
Elk River Municipal Utilities 02/05/2018
Revision: 92262
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9:44:26 AM
Page 22
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
PARTS & LABOR FOR UNIT #7
1,735.72
PARTS & LABOR FOR UNIT #28
-1.95
PARTS & LABOR FOR UNIT #28 Total for Check/Tran - 74376: 74377 01/31/2018 CHK
9192
CUB FOODS ELK RIVER
SAFETY MEETING SNACKS
33.24
SAFETY MEETING SNACKS
8.31
SAFETY MEETING SNACKS
7.99
SAFETY MEETING SNACKS
2.00 51.54
Total for Check/Tran - 74377: 74378 01/31/2018 CHK
25
ECM PUBLISHERS INC
CLASSIFIED AD - INVENTORY FOREPERSON
74379 01/31/2018 CHK
23
ELK RIVER MUNICIPAL UTILITIES
ELECTRIC SERVICE - BOOSTER
162.00 83.86
ELECTRIC SERVICE - LIGHTS & SIGNALS
100.00
ELECTRIC SERVICE - LIGHTS & SIGNALS
494.67
ELECTRIC SERVICE - WELL #6 Total for Check/Tran - 74379:
3,161.06 3,839.59
74380 01/31/2018 CHK
24
ELK RIVER PRINTING
OFFICE SUPPLIES
179.55
74381 01/31/2018 CHK
671
FASTENAL COMPANY
MISC PARTS & SUPPLIES - UNIT #23
225.00
74382 01/31/2018 CHK
204
MARK FUCHS
JTS PLANNING MEETING MILEAGE - FUCHS
105.73
74383 01/31/2018 CHK
28
G & K SERVICES
MATS & TOWELS
113.14
MATS & TOWELS Total for Check/Tran - 74383: 74384 01/31/2018 CHK
404
GARAGE DOOR STORE
REPAIR WASH BAY DOOR Total for Check/Tran - 74384:
74385 01/31/2018 CHK
5118
GRAND RENTAL STATION
MISC PARTS & SUPPLIES - HELMET SYSTEM
74386 01/31/2018 CHK
64
GRANITE ELECTRONICS INC
REPAIRS & SERVICE
74387 01/31/2018 CHK
6836
INNOVATIVE OFFICE SOLUTIONS, LLC OFFICE SUPPLIES /pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
25
28.29 141.43 -0.76
REPAIR WASH BAY DOOR
25203
70.35 115,143.10
207.76 207.00 79.03 2,994.92 81.15
Elk River Municipal Utilities 02/05/2018
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Accounts Payable Check Register
9:44:26 AM
Page 23
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
Vendor
Vendor Name
Reference
Amount
OFFICE SUPPLIES
20.29
OFFICE SUPPLIES
5.49
OFFICE SUPPLIES Total for Check/Tran - 74387: 74388 01/31/2018 CHK
9020
MAILFINANCE
POSTAGE MACHINE RENTAL - 2-18 to 5-18
458.30
POSTAGE MACHINE RENTAL - 2-18 to 5-18
114.57 572.87
Total for Check/Tran - 74388: 74389 01/31/2018 CHK
330
METRO SALES, INC
LEASE FOR COPIER AT OFFICE
119.70
LEASE FOR COPIER AT OFFICE Total for Check/Tran - 74389:
29.93 149.63
74390 01/31/2018 CHK
4355
MIDWEST MUNICIPAL TRANSMISSION MEMBERSHIP DUES - JAN to JUNE 2018
74391 01/31/2018 CHK
349
MINNESOTA EQUIPMENT
MISC PARTS & SUPPLIES - HELMET SYSTEM
79.51
74392 01/31/2018 CHK
147
MINNESOTA POLLUTION CONTROL AG 2018 COLLECTION SYSTEM OP CONF - VOLK
390.00
74393 01/31/2018 CHK
39
MMUA
METER SCHOOL - 155 156
74394 01/31/2018 CHK
9997
MNSC INC
DEP To AP
250.14
74395 01/31/2018 CHK
573
NCPERS MINNESOTA
EXTRA LIFE INSURANCE FOR ERMU EMPLOYEES
224.00
EXTRA LIFE INSURANCE FOR ERMU EMPLOYEES
32.00
3,275.00
1,160.00
#155 JULY 2017 - DEC 2017 PREMIUM Total for Check/Tran - 74395: 74396 01/31/2018 CHK
3769
O'REILLY AUTOMOTIVE STORES, INC
MISC PARTS & SUPPLIES
74397 01/31/2018 CHK
71
PRINCIPAL LIFE INSURANCE CO GRAN LIFE & LTD INSURANCE - FEB 2018
74398 01/31/2018 CHK
6575
ROGERS PRINTING
96.00 352.00 17.07 1,714.00
LIFE & LTD INSURANCE - FEB 2018
27.82
LIFE & LTD INSURANCE - FEB 2018
325.60 2,067.42
Total for Check/Tran - 74397: OFFICE SUPPLIES
694.28
OFFICE SUPPLIES Total for Check/Tran - 74398: 25203
1.38 108.31
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
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125.03 819.31
Elk River Municipal Utilities 02/05/2018
Revision: 92262
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9:44:26 AM
Page 24
01/01/2018 To 01/31/2018 Bank Account: 1 - ELECTRIC/GENERAL FUND Check / Tran Date
Pmt Type
74399 01/31/2018 CHK
Vendor
Vendor Name
Reference
Amount
4021
SPX TRANSFORMER SOLUTIONS, INC.
Oil Filtration System-Waco 2
14,421.71
Internal piping/tubing and fittings
-338.79 14,082.92
Total for Check/Tran - 74399:
25203
74400 01/31/2018 CHK
5026
TOOLS & HYDRAULICS INC
EQUIPMENT REPAIR
35.00
74401 01/31/2018 CHK
9191
UPS
SHIPPING
14.73
/pro/rpttemplate/acct/2.40.1/ap/AP_CHK_REGISTER.xml.rpt
27
Total for Bank Account - 1 :
(222)
4,459,907.79
Grand Total :
(222)
4,459,907.79
Elk River Municipal Utilities 02/05/2018
9:44:26 AM
Accounts Payable Check Register PARAMETERS ENTERED: Check Date: Bank: Vendor: Check: Journal: Format: Extended Reference: Sort By: Voids: Payment Type: Group By Payment Type: Minimum Amount: Authorization Listing: Authorization Comments: Credit Card Charges:
25203
01/01/2018 To 01/31/2018 All All All All GL References/Amounts No Check/Transaction None All No 0.00 No No No
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Revision: 92262 Page 25
ELK RIVER MUNICIPAL UTILITIES REGULAR MEETING OF THE UTILITIES COMMISSION HELD AT UTILITIES CONFERENCE ROOM January 9, 2018 Members Present:
Chair John Dietz; Vice Chair Daryl Thompson; Commissioners Al Nadeau and Mary Stewart Members Absent: Matt Westgaard ERMU Staff Present: Troy Adams, General Manager; Theresa Slominski, Finance and Office Manager; Mark Fuchs, Electric Superintendent; Mike Tietz, Technical Services Superintendent; Eric Volk, Water Superintendent; Tom Sagstetter, Conservation & Key Accounts Manager; Michelle Canterbury, Executive Administrative Assistant; Jennie Nelson, Customer Service Manager; Mike Langer, Lead Water Operator Others Present: Cal Portner, City Administrator
1.0
GOVERNANCE
1.1
Call Meeting to Order The regular meeting of the Utilities Commission was called to order at 3:30 p.m. by Chair Dietz.
1.2
Pledge of Allegiance The Pledge of Allegiance was recited.
1.3
Consider the Agenda There were no additions or corrections to the agenda. Moved by Commissioner Nadeau and seconded by Commissioner Stewart to approve the January 9, 2018, agenda. Motion carried 4-0.
1.4
Water Fluoridation Quality Award Mr. Volk announced that the U.S. Department of Health and Human Services for Disease Control has recognized Elk River for achieving excellence in community water fluoridation by maintaining a consistent level of fluoride in the drinking water throughout 2016. He shared that the achievement
Page 1
Regular Meeting of the Elk River Municipal Utilities Commission January 9, 2018 29
of receiving this award is a testament of the attention to detail the water operators demonstrate on a daily basis. There was discussion on how long Elk River has been adding fluoride to their water. The Commission congratulated the water department on their achievement. 2.0
CONSENT AGENDA (Approved By One Motion) On page 24 of the check register, Commissioner Stewart asked for further clarification on what check number 74213 issued to the Minnesota Department of Commerce was for. Staff responded. Commissioner Stewart also had a question on whether that expense was for 2017 or 2018. Staff stated they would need to verify that and get back to her. Moved by Commissioner Nadeau and seconded by Commissioner Thomson to approve the Consent Agenda as follows: 2.1 2.2 2.3 2.4 2.5 2.6 2.7
December Check Register December 12, 2017 Regular Meeting Minutes December 12, 2017 Closed Meeting Minutes Summary of General Manager Performance Evaluation Customer Deposit Policy 2018 Pay Equity Report Filing Notice to Connexus Energy of Electric Service Territory Area 5 & 6 Transfer Date
Motion carried 4-0. 3.0
OPEN FORUM No one appeared for open forum.
4.0
POLICY & COMPLIANCE
4.1
Integrity Testing Policy Mr. Sagstetter presented the revised Integrity Testing Policy and explained that the proposed changes will allow for all customers in the demand electric service customer class to utilize this policy. Prior to the revisions, the policy only applied to customers with demand greater than 1,000 kW. Mr. Sagstetter explained that other changes in the policy are proposed to better document the integrity testing request, and provide a communication mechanism that the customer, field services, and billing staff can use to ensure the integrity testing date and time are communicated to affected departments, and meet policy criteria. There was discussion. Moved by Commissioner Thompson and seconded by Commissioner Nadeau to approve the revised Integrity Testing Policy. Motion carried 4-0.
Page 2
Regular Meeting of the Elk River Municipal Utilities Commission January 9, 2018 30
4.2
Conservation Improvement Programs Policy Mr. Sagstetter presented the Conservation Improvement Programs Policy which had been revised to reflect the programs that are currently being offered in 2018. Mr. Sagstetter went over notable changes to the programs as highlighted in his memo. The 2018 electric efficiency spending requirements and energy savings goals were also presented. Moved by Commissioner Stewart and seconded by Commissioner Nadeau to approve the revised Conservation Improvement Programs Policy. Motion carried 4-0.
5.0
BUSINESS ACTION
5.1
Financial Report – November 2017 Ms. Slominski presented the November 2017 financial report. Commissioner Stewart inquired as to where we were at year-to-date with the power cost adjustments (PCAs). As staff was not certain of the exact amount, Ms. Slominski stated she would provide the details in next month’s staff update. Moved by Commissioner Thompson and seconded by Commissioner Nadeau to receive and file the November 2017 Financial Report. Motion carried 4-0.
6.0 BUSINESS DISCUSSION 6.1
Staff Updates Mr. Adams announced that the Minnesota Municipal Power Agency (MMPA) Solar Project located in Buffalo, MN just went live. Mr. Adams also shared that he and ERMU staff met with Connexus representatives today regarding Areas 5 & 6. At that meeting, there was also discussion on Connexus transferring over the Highway 10 street lights to ERMU and canceling the city maintenance and energy contract with Connexus; more to come on this later. Ms. Slominski provided a verbal update to the Commission regarding the preliminary audit work the auditors performed yesterday. She stated things had gone very well. Ms. Nelson provided an update on the multi-billing cycle transition, and shared that staff has received quite a few calls. Ms. Nelson also spoke to some of the negative comments that were being posted on social media and how she has reached out to those customers voicing their concerns. As presented in his staff report, Mr. Tietz stated that the locating department had a total of 99 locate tickets in December; a 62% decrease over the previous month. Chair Dietz inquired as to what the locators are doing when we have such a decrease of locates during the winter months. Mr. Tietz shared that they have been filling in with gathering GPS points for all of our systems assets which will be entered into our new ESRI ArcView GIS mapping system.
Page 3
Regular Meeting of the Elk River Municipal Utilities Commission January 9, 2018 31
Mr. Sagstetter noted that the FleetCarma study results he had referenced in his staff report would be formally presented at next month’s Commission meeting. Mr. Sagstetter also provided an update on the success of the DC fast charger at the Coborn’s location. The Commission revisited the topic of the annual Holiday Lighting Contest, and talked about ways to increase participation including changing up the judging criteria. Commissioner Stewart suggested taking the word “contest” out of the name and promoting it as part of a tour of lights, and Chair Dietz suggested using Minnesota Municipal Utilities Association (MMUA) as a resource to poll other utilities that have lighting contests to see what they are using for criteria. Chair Dietz requested staff further evaluate this and report back in a couple of months. Mr. Sagstetter’s staff report stated that staff has been working with MMUA and MMPA on standardizing the contracts, requirements, and processes that govern the interconnection of cogeneration and small power production in Minnesota. The initiative is to gain compliance with Minnesota State Statute based on the recent decisions of the Minnesota Public Utilities Commission (MPUC) pertaining to a few cooperative utilities. Mr. Sagstettter shared that although ERMU has not been in total compliance with the Statutes, they have been clear and fair with the small power producers so there have not been many challenges with the current policies. Commissioner Stewart asked staff to elaborate on the compliance issue and whether it was subject to a monetary fine for non-compliance. Mr. Sagstetter provided further explanation, including that most utilities were not in total compliance as they have been waiting for the resolution of proceedings at the MPUC before finalizing the interconnection of cogeneration and small power production tariff. There was discussion. Staff will continue to work on the requirements and indicated they should have something for Commission consideration within the next few months. 6.2
Bonding Discussion Mr. Adams provided some background on the MMPA membership. He shared that in 2016, ERMU made an advance payment towards the buy-in of approximately $10 million and that a true-up of the balance of the buy-in will be due prior to October 2018 when we begin receiving our wholesale power from MMPA. In preparation for the true-up payment to MMPA, staff is reviewing bonding options with our bonding consultants at Springsted. Two handouts containing graphs of the estimated bonds cost and MMPA savings for a 20 year scenario, and a 30 year scenario were provided at the time of the meeting. Mr. Adams shared that the purpose of this discussion is to talk through the true-up and bonding options so that the Commissioners can gain a better understanding should they get questions from members of the community. Staff had identified four topics relevant to the investment and provided an overview on the following: return on investment (ROI) and long term strategic analysis of the decision to join
Page 4
Regular Meeting of the Elk River Municipal Utilities Commission January 9, 2018 32
MMPA; cash flow and short term financial strategic analysis of the buy-in; other value add related to the membership; and other factors which could affect the ROI and short term cash flow. After the overview, Mr. Adams opened it up for discussion and asked for feedback from the Commission regarding their preference on scenario 1 with the 20 year bond option, or scenario 2 with the 30 year bond option. After discussion, Commission consensus was scenario 2 with the 30 year bond option. Staff will continue to work with Springsted on the bonding and anticipated bringing something back to the Commission sometime in July. 6.3
Future Planning Chair Dietz announced the following: a. Regular Commission Meeting – February 13, 2018 b. Quorum – Employee Recognition Luncheon – January 22, 2018, 12:00 – 1:00 p.m.
6.4
Other Business There was no other business.
7.0
ADJOURN REGULAR MEETING Moved by Commissioner Nadeau and seconded by Commissioner Stewart to adjourn the regular meeting of the Elk River Municipal Utilities Commission at 4:46 p.m. Motion carried 4-0.
Minutes prepared by Michelle Canterbury.
___________________________________ John J. Dietz, ERMU Commission Chair ___________________________________ Tina Allard, City Clerk
Page 5
Regular Meeting of the Elk River Municipal Utilities Commission January 9, 2018 33
UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Jennie Nelson – Customer Service Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2018 2.3 SUBJECT: Demand All Electric Service Tariff ACTION REQUESTED: Approve the Demand All Electric Service Tariff BACKGROUND: Elk River Municipal Utilities (ERMU) has a residential rate for those who use all electric heat. Customers who are on that rate should not be taxed in the winter according to the State of Minnesota. We also have a rate that works that way for non-demand commercial customers, but we do not have a rate for demand billed customers as we were never aware of a customer that was eligible. DISCUSSION: We were recently informed that we have a customer who may qualify for an All Electric Demand rate. The proposed tariff is exactly the same as the Demand Electric Service tariff, with the exception of some additional language regarding sales tax and exemptions. We may require customers to provide and ST3 exemption form to qualify as stated in the tariff. FINANCIAL IMPACT: None ATTACHMENTS: Proposed ERMU Policy – T15 – Demand All Electric Service Tariff
______________________________________________________________________________ Page 1 of 1 34
ELK RIVER MUNICIPAL UTILITIES Demand All Electric Service Available: Within Elk River Municipal Utilities (ERMU) established service territory. Applicable: Available for non-residential customer accounts. Existing or new Customer accounts with actual or projected demand greater than or equal to 50 kW. A Customer account with a billing demand of less than 50 kW for 12 consecutive months will be given the option of switching to the Non-Demand rate. The Customer accounts shall be in compliance with all policies, procedures, and safety requirements, and shall be taken through one meter. (Not applicable to resale, standby or auxiliary service.) Character Of Service: AC, 60 cycles, 120 volts or 120/240 volts, single-phase; 120/208 volts, or 277/480 volts, three-phase. Four wire, 240 volts three-phase will only be applicable to existing customers now being served by this voltage. A customer requiring voltages other than that already established shall be required to provide suitable space and location for Elk River Municipal Utilities transformers, metering and associated equipment. Special Conditions: One meter shall be installed to service one class of business. If additional buildings are required for a given business, they shall be interconnected by the customer to obtain one meter, unless an exception is approved by management. If additional meters and services are requested by the customer, each shall be treated as a separate customer and billed individually. Meter to be accessible to our service department at any time. Demand Service Rate: Basic Monthly Electric Charge: $75.00 per month.
Demand Charge: Energy Charge:
Summer
Winter
$17.00 $ 0.0667
$12.00 in kW / month $ 0.0667 in kWh / month
Summer Rate: Applicable during the five monthly billing periods of June – October. Summer rates are subject to sales tax unless an exemption is filed. Winter Rate: Applicable during the seven monthly billing periods of November – May. Winter rates are sales tax exempt and may require an exemption to be filed. Rates are subject to application of Power Cost Adjustment (PCA). Minimum Bill: Maximum billing demand during previous twelve months times 3.0% of the demand charge, or the actual demand multiplied by the demand charge, whichever is greater plus $1.00 per kVA per month of excess transformer capacity requested by customer. Determination of Billing Demand: The billing demand shall be the highest measured demand (corrected for power factor if required) during any fifteen (15) minute period occurring in the current billing period. But in no month shall the billing demand be
35
ELK RIVER MUNICIPAL UTILITIES Demand All Electric Service greater than the value in kW determined by dividing the kWh sales for the billing month by 75 hours per month. This billing adjustment applies only if the customer’s peak demand DOES NOT occur between the hours of 3:00 p.m. and 10:00 p.m. Fluctuating Loads: Customers operating equipment having a highly fluctuating or large instantaneous demand, such as welders and X-ray machines, shall be required to pay all non-betterment costs of isolating the load from the balance of Elk River Municipal Utilities’ system so that the load will not unduly interfere with service on Elk River Municipal Utilities’ lines. In addition, Customers who fail to provide adequate corrective equipment shall be required to own and maintain their own transformers. No motor larger than ten (10) HP (or 7.355 kW) will be allowed to be across-the-line started without notification and written authorization from Elk River Municipal Utilities. Power Factor Adjustment: For loads of 50 kW or more, or at the option of Elk River Municipal Utilities for loads of less than 50 kW, power factor adjustments may be made in the billing demand, when the power factor, as determined by test, at the time of the Customer’s maximum use is less than 95%. If the power factor, as measured by Elk River Municipal Utilities’ electric department, is lower than 95%, the monthly demand charge may be multiplied by the ratio 95% divided by the measured power factor, or at Elk River Municipal Utilities option, the power factor may be corrected at the Customer’s expense. Terms of Payment: Bills are due and payable upon receipt and are considered delinquent if not paid by the due date noted the bill. There will be a ten (10) percent late payment charge added to all accounts that are not paid by the due date. Terms and Conditions: 1. Usage may be fractionalized on the actual days of service for application of a
change in rate.
2. Service will be furnished under Elk River Municipal Utilities rules. 3. Extensions made for service under this schedule are subject to the provisions of Elk
River Municipal Utilities’ rules governing Extension of Service and Facilities.
4. The rates set forth herein may be modified by the amount of any governmental
changes imposed and levied on transmission, distribution, production, or the sale of electrical power.
5. Exceptions by management approval only.
Approved______________________________________ Adopted February 13, 2018 Effective February 13, 2018
36
UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Tom Sagstetter – Conservation and Key Accounts Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2018 4.1 SUBJECT: Distributed Generation and Net Metering Policy ACTION REQUESTED: Resolution 1 - Adopt by resolution the Distributed Generation and Net Metering Policy; and the Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities. Resolution 2 – Adopt by resolution the Cogeneration and Small Power Production Tariff. BACKGROUND: Every municipal electric utility should have a policy reflecting the expectations and obligations of the municipal utility and of customers who seek to interconnect their own electric generation facilities with the municipal utility distribution system. For ERMU these systems consist of wind or solar PV systems that are less than 40kW. ERMU and any customer wishing to interconnect (less than 10 MW) are subject to state statues and rules implementing those statutes. The rules established by the Minnesota Public Utilities Commission (MPUC) can be adapted to apply to municipal utilities and adopted by the utility's governing body. The attached documents (Policy, Rules, and Annual Tariff) are versions of the documents that were established by the MPUC and modified by the Minnesota Municipal Utilities Association (MMUA) and Minnesota Municipal Power Agency (MMPA) to create models for member municipals to use with their local governing bodies. These models create a standard that will allow for consistency over all municipal utilities in the state. Each municipal utility and their local governing body have the authority to adopt the utility's policies, rules, and tariff as they pertain to the interconnection of cogeneration and small power production facilities. Adopting the attached policy, rules, and tariff by the ERMU Utilities Commission will provide the Commission the authority to settle disputes when they arise between ERMU and the cogeneration and/or small power production facility. These documents will have to be reviewed annually to adjust customer compensation rates for excess electricity generated by the customer and put onto the utility system for use by other customers. If the ERMU Commission would not adopt policies, rules and tariff as presented, ERMU would continue to be under the state's rules that requires annual compensation rate filings for approval by the Minnesota Public Utilities Commission and could potentially result in costly dispute resolution proceedings by the state-level agency.
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DISCUSSION: ERMU used the model documents provided by MMUA and MMPA to create the attached ERMU policy, rules and tariff. On an annual basis, at a minimum, the Commission will have to review and adopt Schedules 1 and 5 of the tariff. These two schedules reflect the average retail rate for each customer class that a customer would receive for any excess generation they chose to be reimbursed for on a monthly or annual basis and the avoided costs to customers for distributed generation from the wholesale power providers. The policy, rules, and tariff together represent a great deal of material. Developing standards for interconnecting cogeneration and small power production facilities for the state of Minnesota is a daunting task. The proposed tariff is much different than any other tariff of ERMU. This tariff consists of very detailed rules, requirements, and processes that are not applicable to customers that are retail consumers of electricity. This process has taken years and is still under review. There are many interested parties that are involved in this process because it impacts over 170 utilities, their customers, and renewable energy developers. It’s important that the ERMU Utilities Commission adopt the policy, rules, and tariff because by doing so, it should preserve the right of the ERMU Utility Commission to retain control over these issues. If the ERMU Utility Commission does not take action on these items, customers would have the right to dispute a utility’s actions regarding cogeneration and small power production facilities with the Minnesota Public Utilities Commission. FINANCIAL IMPACT: N/A ATTACHMENTS: Resolution No.18-1 – Adopting the Distributed Generation and Net Metering Policy; and Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities Proposed ERMU Policy – E.12 – Distributed Generation and Net Metering Policy Proposed ERMU Policy – E.12a – Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities Resolution No. 18-2 – Adopting the Cogeneration and Small Power Production Tariff Proposed ERMU Policy – E.12b – Cogeneration and Small Power Production Facilities Tariff
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RESOLUTION NO. 18-1 BOARD OF COMMISSIONERS ELK RIVER MUNICIPAL UTILITIES A RESOLUTION ADOPTING ELK RIVER MUNICIPAL UTILITIES POLICY REGARDING DISTRIBUTED GENERATION AND NET METERING; AND RULES GOVERNING THE INTERCONNECTION OF COGENERATION AND SMALL POWER PRODUCTION FACILITIES. WHEREAS, the City is served by Elk River Municipal Utilities, which is committed to providing customers with reliable and affordable power. WHEREAS, the purpose of the distributed generation and net metering policy is to establish the application procedures and qualification criteria for the delivery, interconnection, metering, and purchase of electricity from distributed generation facilities. WHEREAS, it is the responsibility of Elk River Municipal Utilities to implement this policy and give the maximum possible encouragement to cogeneration and small power production consistent with protection of the ratepayers and the public. WHEREAS, the purpose of the cogeneration and small power production rules is for Elk River Municipal Utilities to implement certain provisions of Minnesota Statutes Section 216B.164, the Public Utility Regulatory Policies Act of 1978, and Federal Energy Regulatory Commission regulations related to customer distributed generation. WHEREAS, the adoption of these rules establishes that the Elk River Municipal Utilities Commission is the interpreting body and arbiter of the provisions of Minnesota Statutes Section 216B.164 for Elk River Municipal Utilities. WHEREAS, Elk River Municipal Utilities shall annually file a cogeneration and small power production tariff with Elk River Municipal Utilities Commission under these rules. WHEREAS, the cogeneration and small power production tariff shall include a calculation of average retail utility energy rates, standard contracts to be used with qualifying facilities, interconnection process and technical requirements, procedures for notifying qualifying facilities when Elk River Municipal Utilities Commission will not purchase energy or capacity, and Elk River Municipal Utilities estimated average incremental energy costs and net annual avoided capacity costs. WHEREAS, all filings under these rules shall be maintained at the Elk River Municipal Utilities offices and shall be made available for public inspection during normal business hours.
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THEREFORE, BE IT RESOLVED that the Elk River Municipal Utilities Commission adopts the Policy Regarding Distributed Generation and Net Metering; and Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities. This Resolution Passed and Adopted this 13th day of February, 2018.
___________________________________ John J. Dietz, Chair ___________________________________ Troy Adams, P.E., General Manager
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E.12 - Distributed Generation and Net Metering Policy
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The purpose of this policy is to establish the application procedure and qualification criteria for all customers for the delivery, interconnection, metering and purchase of electricity from distributed generation facilities and to comply with applicable laws and rules governing distributed generation. Elk River Municipal Utilities (Utility) recognizes its obligation to provide an interconnection to qualifying facilities that are eligible for distributed generation and will comply with all applicable laws and rules governing distributed generation. For purposes of this policy, the following terms have the meaning given them: A. Net Metering/Net Billing - the process whereby the customer and the utility compensate each other based on the difference in the amount of energy each sells to the other at the net metered facility. B. Net Metered Facility - an electric generation facility constructed for the purpose of offsetting energy use through the use of renewable energy or high efficiency generation sources. C. Average Retail Energy Rate - the average of the retail energy rates, exclusive of special rates based on income, age, or energy conservation, according to the applicable rate schedule of the utility for sales to the class of customer of which the customer/qualifying facility belong. D. Avoided Costs - the incremental costs to the utility of electric energy or capacity or both which, but for the purchase from the qualifying facility, the utility would generate itself or purchase from another source. E. Interconnection Rules - means any applicable Utility Cogeneration Rules developed in accordance with Minnesota Statutes 216B.164 and 216B.1611 that include issues outlined in the State of Minnesota Interconnection Process for Distributed Generation Systems, Distributed Generation Interconnection Requirements, General Interconnection Application, Engineer Data Submittal and Interconnection Agreement. F. Interconnection Application - the form to be used by the customer to submit its formal request for interconnection to the utility and which shall be substantially similar in form to that Application attached as Exhibit A to this policy. The customer signature on the interconnection application indicated the customer shall follow the steps outlined in the Utility Cogeneration Rules and the State of Minnesota Interconnection Process for Distributed Generation System. The interconnection between the qualifying facility or net metered facility and the utility must comply with the requirements as stated in the State of Minnesota Distributed Generation Interconnection Requirements. G. Contract - the written agreement between the customer/qualifying facility and the utility, as established in the Utility Cogeneration Rules. H. Total Generator Nameplate Capacity - the total kW output of a qualifying facility's generator. For purposes of this definition total output is determined by the nameplate capacity rating, or in the event that the nameplate capacity is not less than 40 kW, then the existence of any variable speed drive or other limiting device shall be factored into determining total generator nameplate capacity. The customer must fully, accurately and completely disclose in its interconnection application to the utility, the technical specifications for any capacity limiting device contemplated and the customer shall furnish the utility with any factory manuals or other similar documents requested from the utility regarding such limiting or other control devices which factor into the calculation of total generator nameplate capacity. 1
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I. J.
Measured Capacity - for purposes of determining capacity, it shall be measured based on the highest fifteen (15) minute average demand of the unit in any one billing period. In the event an inconsistency exists between terms in this policy and those established by Statute, Rule or Court Order, then the definition so established shall supersede the definition used in this policy and shall govern.
All customers are eligible for distributed generation, interconnection with the utility's distribution system and application of net metering upon the following terms and conditions. 1. The customer must meet the eligibility requirements set forth in the federal Public Utility Regulatory Policies Act of 1978 (PURPA) *18 C.F.R. 292.303, 292.304 and Minnesota's Distributed Generation laws. Minn. Stat. §216B.164. 2. The customer shall complete, sign and return to Utility an Interconnection Application in the form prescribed in Exhibit A hereto. The Application shall be approved by Utility prior to the customer beginning the project. 3. The customer shall enter into a written contract with the Utility using the uniform utility contract contained in the Utility Cogeneration Rules. 4. The qualifying facility shall pay the Utility for all reasonable costs of interconnection including those costs outlined in Minnesota Statute 216B.164, the Minnesota Interconnection Process, and the Minnesota Interconnection Technical Requirements as established in PUC Docket CI-01-1023. 5. The qualifying facilities total generator nameplate capacity shall be less than 40 kW and the facility shall operate at a measured capacity of less than 40 kW at all times. 6. The Utility may limit the capacity and operating characteristics of distributed generation single phase generators in a manner consistent with the utility limitations for single phase motors, when necessary to avoid a qualifying facility from causing problems with the service of other customers. 7. The Utility may require the qualifying facility to discontinue parallel generation operations when necessary for system safety. 8. The power output from the qualifying facility must be maintained so that frequency and voltage are compatible with normal utility service and do not cause that service to fall outside the prescribed limits of interconnection rules and other standard limitations. 9. The qualifying facility shall keep in force liability insurance against personal or property damage due to the installation, interconnection, and operation of its electric generating facilities. The amount of insurance coverage shall be the maximum amount of said insurance for a qualifying facility or net metered facility as outlined in the State of Minnesota Distributed Generation Interconnection Requirements. 10. Failure of the qualifying facility to operate its generators at a measured capacity below the 40 kW capacity limit established by M.S. 216B.164, Sub. 3 and as contemplated by this policy, shall result in the following. The Utility will notify the customer/qualifying facility of the fact that its generating equipment has failed to operate below the 40 kW maximum capacity and will provide the customer/qualifying facility with the date, time and kW reading that substantiate this finding.
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11. The Utility shall compensate the customer/qualifying facility for all metered electricity produced by said qualifying facility during the thirty (30) day period during which the failure occurred, at the Utility's Generation and Transmission Supplier's avoided cost rate. 12. The Utility shall continue to pay the customer/qualifying facility for subsequent electricity produced and delivered pursuant to this distributed generation agreement, at the Utility's Generation and Transmission Supplier's avoided cost rate until: 1. The problem with the generator that caused it to operate at or above the statutory maximum capacity has been remedied; and 2. The Utility has been provided documentation adopted by a Minnesota Professional Engineer that confirms the problem with the generator has been remedied. 13. Any customer account eligible for net metering and the net billing rate may not be eligible for any other load management discounts unless agreed to by the Utility. 14. Payment for the purchase of distributed generation electricity herein shall be in the form of a credit on the customer’s monthly billing invoice or paid by check or electronic payment to the customer within fifteen (15) days of the billing date, whichever is selected and indicated in the Contract. 15. The customer must be, and continue to be, current with payment on its electric account with Utility. 16. The customer must not enter into any arrangement that violates the Utility’s exclusive right to provide electric service in its service area under Minnesota Statutes §216B.40. 17. In the event that the distributed generator fails to meet the requirements of this policy for a Total Generator Nameplate Capacity of less than 40 kW, and fails to satisfy the corrective requirements set forth in Section 12 above, then Utility will have the right to (1) cancel the Contract with the owner of the distributed generator, and (2) enter into a new contract with the owner of the distributed generator that, among other changes, adjusts the distributed generator's rated capacity and specifies avoided cost pricing for the distributed generator's output. To the extent that the Utility does not have the obligation to make purchases from qualifying facilities of 40 kW or greater due to transfer of the obligation to the Utility's wholesale supplier that has been approved by the Federal Energy Regulatory Commission, the new agreement will be between the Utility's wholesale supplier and the distributed generator. In either case, Utility (and as applicable Utility's wholesale supplier) and the owner of the distributed generator will cooperate in the transition from the form of contract set forth in the Utility’s adopted cogeneration rules to a new form of contract appropriate to a distributed generator with a capacity of 40 kW or greater.
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E.12a – Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities with Elk River Municipal Utilities
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Part A. DEFINITIONS. Subpart 1. Applicability. For purposes of these rules, the following terms have the meanings given them below. Subp. 2. Average retail utility energy rate. "Average retail utility energy rate" means, for any class of utility customer, the quotient of the total annual class revenue from sales of electricity minus the annual revenue resulting from fixed charges, divided by the annual class kilowatt-hour sales. The computation shall use data from the most recent 12month period available. Subp. 3. Backup power. "Backup power" means electric energy or capacity supplied by the utility to replace energy ordinarily generated by a qualifying facility's own generation equipment during an unscheduled outage of the facility. Subp. 4. Capacity. "Capacity" means the capability to produce, transmit, or deliver electric energy, and is measured by the number of megawatts alternating current at the point of common coupling between a qualifying facility and the utility's electric system during a 15-minute interval period. Subp. 5. Capacity costs. "Capacity costs" means the costs associated with providing the capability to deliver energy. The utility capital costs consist of the costs of facilities from the utility and the utility’s wholesale provider used to generate, transmit, and distribute electricity and the fixed operating and maintenance costs of these facilities. Subp. 6. Customer. "Customer" means the person named on the utility electric bill for the premises. Subp. 7. Energy. "Energy" means electric energy, measured in kilowatt-hours. Subp. 8. Energy costs. "Energy costs" means the variable costs associated with the production of electric energy. They consist of fuel costs and variable operating and maintenance expenses. Subp. 9. Firm power. "Firm power" means energy delivered by the qualifying facility to the utility with at least a 65 percent on-peak capacity factor in the month. The capacity factor is based upon the qualifying facility's maximum metered capacity delivered to the utility during the on-peak hours for the month. Subp. 10. Governing body. “Governing body” means [replace this text and brackets with the name of the city council or commission or board that governs the utility]. Subp. 11. Interconnection costs. "Interconnection costs" means the reasonable costs of connection, switching, metering, transmission, distribution, safety provisions, and administrative costs incurred by the utility that are directly related to installing and maintaining the physical facilities necessary to permit interconnected operations with a 1
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qualifying facility. Costs are considered interconnection costs only to the extent that they exceed the costs the utility would incur in selling electricity to the qualifying facility as a nongenerating customer. Subp. 12. Interruptible power. "Interruptible power" means electric energy or capacity supplied by the utility to a qualifying facility subject to interruption under the provisions of the utility's tariff applicable to the retail class of customers to which the qualifying facility would belong irrespective of its ability to generate electricity. Subp. 13. Maintenance power. "Maintenance power" means electric energy or capacity supplied by a utility during scheduled outages of the qualifying facility. Subp. 14. On-peak hours. "On-peak hours" means either those hours formally designated by the utility as on-peak for ratemaking purposes or those hours for which its typical loads are at least 85 percent of its average maximum monthly loads. Subp. 15. Point of common coupling. "Point of common coupling" means the point where the qualifying facility's generation system, including the point of generator output, is connected to the utility's electric power grid. Subp. 16. Purchase. "Purchase" means the purchase of electric energy or capacity or both from a qualifying facility by the utility. Subp. 17. Qualifying facility. "Qualifying facility" means a cogeneration or small power production facility which satisfies the conditions established in Code of Federal Regulations, title 18, part 292. The initial operation date or initial installation date of a cogeneration or small power production facility must not prevent the facility from being considered a qualifying facility for the purposes of this chapter if it otherwise satisfies all stated conditions. The qualifying facility must be owned by a Customer and located in the utility service area. Subp. 18. Sale. "Sale" means the sale of electric energy or capacity or both by the utility to a qualifying facility. Subp. 19a. Standby charge. "Standby charge" means the charge imposed by the utility upon a qualifying facility for the recovery of costs for the provision of standby services necessary to make electricity service available to the qualifying facility. Subp. 19b. Standby service. "Standby service" means the service to potentially provide electric energy or capacity supplied by the utility to a qualifying facility greater than 40 kW. Subp. 20. Supplementary power. "Supplementary power" means electric energy or capacity supplied by the utility which is regularly used by a qualifying facility in addition to that which the facility generates itself.
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Subp. 21. System emergency. "System emergency" means a condition on the utility's system which is imminently likely to result in significant disruption of service to customers or to endanger life or property. Subp. 22. Utility. "Utility" means [replace this text with the name of the municipal utility]. Part B. SCOPE AND PURPOSE. The purpose of these rules are to implement certain provisions of Minnesota Statutes, section 216B.164; the Public Utility Regulatory Policies Act of 1978, United States Code, title 16, section 824a-3; and the Federal Energy Regulatory Commission regulations, Code of Federal Regulations, title 18, part 292. These rules shall be applied in accordance with their intent to give the maximum possible encouragement to cogeneration and small power production consistent with protection of the ratepayers and the public. Part C. FILING REQUIREMENTS Annually the utility shall file for review and approval, a cogeneration and small power production tariff with the governing body. The tariff must contain schedules 1 – 5. SCHEDULE 1. Schedule 1 shall contain the calculation of the average retail utility energy rates to be updated annually. SCHEDULE 2. Schedule 2 shall contain all standard contracts to be used with qualifying facilities, containing applicable terms and conditions. SCHEDULE 3. Schedule 3 shall contain the utility's adopted interconnection process, safety standards, technical requirements for distributed energy resource systems, required operating procedures for interconnected operations, and the functions to be performed by any control and protective apparatus. SCHEDULE 4. Schedule 4 shall contain procedures for notifying affected qualifying facilities of any periods of time when the utility will not purchase electric energy or capacity because of extraordinary operational circumstances which would make the costs of purchases during those periods greater than the costs of internal generation. SCHEDULE 5. Schedule 5 shall contain the estimated average incremental energy costs by seasonal, peak and off-peak periods for the utility’s power supplier from which energy purchases are first avoided. Schedule 5 shall also contain the net annual avoided capacity costs, if 3
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any, stated per kilowatt-hour and averaged over the on-peak hours and over all hours for the utility’s power supplier from which capacity purchases are first avoided. Both the average incremental energy costs and net annual avoided capacity costs shall be increased by a factor equal to 50 percent of the utility and the utility’s power supplier’s overall line losses due to distribution, transmission and transformation of electric energy. Part D. AVAILABILITY OF FILINGS. All filings shall be maintained at the utility's general office and any other offices of the utility where rate tariffs are kept. The filings shall be made available for public inspection during normal business hours. The utility shall supply the current year’s distributed generation rates, interconnection procedures and application form on the utility website, if practicable, or at the utility office. Part E. REPORTING REQUIREMENTS Annually the utility shall report to the governing body for its review and approval an annual report including information in subparts 1-3. The utility shall still comply with other federal and state reporting of distributed generation to federal and state agencies expressly required by statute. Subpart 1. Summary of Average Retail Utility Energy Rate. A summary of the qualifying facilities that are currently served under average retail utility energy rate. Subp. 2. Other Qualifying Facilities. A summary of the qualifying facilities that are not currently served under average retail utility energy rate. Subp. 3. Wheeling. A summary of the wheeling undertaken with respect to qualifying facilities. Part F. CONDITIONS OF SERVICE Subpart 1. Requirement to Purchase. The utility shall purchase energy and capacity from any qualifying facility which offers to sell energy and capacity to the utility and agrees to the conditions in these rules. Subp. 2. Written Contract. A written contract shall be executed between the qualifying facility and the utility. Part G. ELECTRICAL CODE COMPLIANCE. Subpart 1. Compliance; standards. The interconnection between the qualifying facility and the utility must comply with the requirements in the most recently published edition of the National Electrical Safety Code issued by the Institute of Electrical and Electronics Engineers. The interconnection is subject to subparts 2 and 3.
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Subp. 2. Interconnection. The qualifying facility is responsible for complying with all applicable local, state, and federal codes, including building codes, the National Electrical Code (NEC), the National Electrical Safety Code (NESC), and noise and emissions standards. The utility shall require proof that the qualifying facility is in compliance with the NEC before the interconnection is made. The qualifying facility must obtain installation approval from an electrical inspector recognized by the Minnesota State Board of Electricity. Subp. 3. Generation system. The qualifying facility's generation system and installation must comply with the American National Standards Institute/Institute of Electrical and Electronics Engineers (ANSI/IEEE) standards applicable to the installation. Part H. RESPONSIBILITY FOR APPARATUS. The qualifying facility, without cost to the utility, must furnish, install, operate, and maintain in good order and repair any apparatus the qualifying facility needs in order to operate in accordance with schedule 3. Part I. TYPES OF POWER TO BE OFFERED; STANDBY SERVICE. Subpart 1. Service to be offered. The utility shall offer maintenance, interruptible, supplementary, and backup power to the qualifying facility upon request. Subp. 2. Standby service. The utility shall offer a qualifying facility standby power or service at the utility’s applicable standby rate schedule. Part J. DISCONTINUING SALES DURING EMERGENCY. The utility may discontinue sales to the qualifying facility during a system emergency, if the discontinuance and recommencement of service is not discriminatory. Part K. RATES FOR UTILITY SALES TO A QUALIFYING FACILITY. Rates for sales to a qualifying facility are governed by the applicable tariff for the class of electric utility customers to which the qualifying facility belongs or would belong were it not a qualifying facility. Such rates are not guaranteed and may change from time to time at the discretion of the utility. Part L. STANDARD RATES FOR PURCHASES FROM QUALIFYING FACILITIES. Subpart 1. Qualifying facilities with 100 kilowatt capacity or less. For qualifying facilities with capacity of 100 kilowatts or less, standard purchase rates apply. The utility shall make available four types of standard rates, described in parts M, N, O, and P. The qualifying facility with a capacity of 100 kilowatts or less must choose interconnection under one of these rates, and must specify its choice in the written contract required in part V. Any net credit to the qualifying facility must, at its option, be credited to its 5
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account with the utility or returned by check or comparable electronic payment service within 15 days of the billing date. The option chosen must be specified in the written contract required in part V. Qualifying facilities remain responsible for any monthly service charges and demand charges specified in the tariff under which they consume electricity from the utility. Subp. 2. Qualifying facilities over 100-kilowatt capacity. A qualifying facility with more than 100-kilowatt capacity has the option to negotiate a contract with the utility or, if it commits to provide firm power, be compensated under standard rates. Subp. 3. Grid Access Charge. A qualifying facility shall be assessed a monthly Grid Access Charge to recover the fixed costs not already paid by the customer through the customer’s existing billing arrangement. The additional charge shall be reasonable and appropriate for the class of customer based on the most recent cost of service study defining the Grid Access Charge. The cost of service study for the Grid Access Charge shall be made available for review by the customer of the utility upon request. Part M. AVERAGE RETAIL UTILITY ENERGY RATE. Subpart 1. Applicability. The average retail utility energy rate is available only to customer-owned qualifying facilities with capacity of less than 40 kilowatts which choose not to offer electric power for sale on either a time-of-day basis, a simultaneous purchase and sale basis or roll-over credit basis. Subp. 2. Method of billing. The utility shall bill the qualifying facility for the excess of energy supplied by the utility above energy supplied by the qualifying facility during each billing period according to the utility's applicable retail rate schedule. Subp. 3. Additional calculations for billing. When the energy generated by the qualifying facility exceeds that supplied by the utility to the customer at the same site during the same billing period, the utility shall compensate the qualifying facility for the excess energy at the average retail utility energy rate. Part N. SIMULTANEOUS PURCHASE AND SALE BILLING RATE. Subpart 1. Applicability. The simultaneous purchase and sale rate is available only to qualifying facilities with capacity of less than 40 kilowatts which choose not to offer electric power for sale on average retail utility energy rate basis, time-of-day basis or rollover credit basis. Subp. 2. Method of billing. The qualifying facility must be billed for all energy and capacity it consumes during a billing period according to the utility's applicable retail rate schedule.
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Subp. 3. Compensation to qualifying facility; energy purchase. The utility shall purchase all energy which is made available to it by the qualifying facility. At the option of the qualifying facility, its entire generation must be deemed to be made available to the utility. Compensation to the qualifying facility must be the energy rate shown on schedule 5. Subp. 4. Compensation to qualifying facility; capacity purchase. If the qualifying facility provides firm power to the utility, the capacity component must be the utility’s net annual avoided capacity cost per kilowatt-hour averaged over all hours shown on schedule 5, divided by the number of hours in the billing period. If the qualifying facility does not provide firm power to the utility, no capacity component may be included in the compensation paid to the qualifying facility. Part O. TIME-OF-DAY PURCHASE RATES. Subpart 1. Applicability. Time-of-day rates are required for qualifying facilities with capacity of 40 kilowatts or more and less than or equal to 100 kilowatts, and they are optional for qualifying facilities with capacity less than 40 kilowatts. Time-of-day rates are also optional for qualifying facilities with capacity greater than 100 kilowatts if these qualifying facilities provide firm power. Subp. 2. Method of billing. The qualifying facility must be billed for all energy and capacity it consumes during each billing period according to the utility's applicable retail rate schedule. Subp. 3. Compensation to qualifying facility; energy purchases. The utility shall purchase all energy which is made available to it by the qualifying facility. Compensation to the qualifying facility must be the energy rate shown on schedule 5. Subp. 4. Compensation to qualifying facility; capacity purchases. If the qualifying facility provides firm power to the utility, the capacity component must be the capacity cost per kilowatt shown on schedule 5 divided by the number of on-peak hours in the billing period. The capacity component applies only to deliveries during on-peak hours. If the qualifying facility does not provide firm power to the utility, no capacity component may be included in the compensation paid to the qualifying facility. Part P. ROLL-OVER CREDIT PURCHASE RATES. Subpart 1. Applicability. The roll-over credit rate is available only to qualifying facilities with capacity of less than 40 kilowatts which choose not to offer electric power for sale on average retail utility energy rate basis, time-of-day basis or simultaneous purchase and sale basis.
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Subp. 2. Method of billing. The utility shall bill the qualifying facility for the excess of energy supplied by the utility above energy supplied by the qualifying facility during each billing period according to the utility’s applicable retail rate schedule. Subp. 3. Additional calculations for billing. When the energy generated by the qualifying facility exceed that supplied by the utility during a billing period, the utility shall apply the excess kilowatt hours as a credit to the next billing period kilowatt hour usage. Excess kilowatt hours that are not offset in the next billing period shall continue to be rolled over to the next consecutive billing period. Any excess kilowatt hours rolled over that are remaining at the end of each calendar year shall cancel with no additional compensation. Part Q. CONTRACTS NEGOTIATED BY CUSTOMER. A qualifying facility with capacity greater than 100 kilowatts must negotiate a contract with the utility setting the applicable rates for payments to the customer of avoided capacity and energy costs. Subpart 1. Amount of Capacity Payments. The qualifying facility which negotiates a contract under part Q must be entitled to the full avoided capacity costs of the utility. The amount of capacity payments will be determined by the utility and the utility’s wholesale power provider. Subp. 2. Full Avoided Energy Costs. The qualifying facility which negotiates a contract under part Q must be entitled to the full avoided energy costs of the utility. The costs must be adjusted as appropriate to reflect line losses. Part R. WHEELING Qualifying facilities with capacity of 30 kilowatts or greater, are interconnected to the utility’s distribution system and choose to sell the output of the qualifying facility to any other utility, must pay any appropriate wheeling charges to the utility. Within 15 days of receiving payment from the utility ultimately receiving the qualifying facility’s output, the utility shall pay the qualifying facility the payment less the charges it has incurred and its own reasonable wheeling costs. Part S. NOTIFICATION TO CUSTOMERS Subpart 1. Contents of Written Notice. Following each annual review and approval by the utility of the cogeneration rate tariffs the utility shall furnish in the monthly newsletter or similar mailing, written notice to each of its customers that the utility is obligated to interconnect with and purchase electricity from cogenerators and small power producers. Subp. 2. Availability of Information. The utility shall make available to all interested persons upon request, the interconnection process and requirements adopted by the utility, pertinent rate schedules and sample contractual agreements. 8
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Part T. DISPUTE RESOLUTION In case of a dispute between a utility and a qualifying facility or an impasse in the negotiations between them, either party may request the governing body to determine the issue. Part U. INTERCONNECTION CONTRACTS Subpart 1. Interconnection Standards. The utility shall provide a customer applying for interconnection with a copy of, or electronic link to, the utility’s adopted interconnection process and requirements. Subp. 2. Existing Contracts. Any existing interconnection contract executed between the utility and a qualifying facility with capacity of less than 40 kilowatts remains in force until terminated by mutual agreement of the parties or as otherwise specified in the contract. The governing body has assumed all dispute responsibilities as listed in existing interconnection contracts. Disputes are resolved in accordance with Part T. Subp. 3. Renewable Energy Credits; Ownership. Generators own all renewable energy credits unless other ownership is expressly provided for by a contract between a generator and the utility Part V. UNIFORM CONTRACT. The form for uniform contract that shall be used between the utility and a qualifying facility having less than 40 kilowatts of capacity is as shown in subpart 1. Subpart 1. Contract for Cogeneration and Small Power Production Facilities. (See attached contract form.)
ADOPTED ON: SIGNED: Chair of the Elk River Municipal Utilities Commission
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CONTRACT FOR COGENERATION AND SMALL POWER PRODUCTION FACILITIES THIS CONTRACT is entered into this _____day of ___________, ______, by Elk River Municipal Utilities, a municipal utility under Minnesota law (hereafter called "Utility") and ______________________________________________ (hereafter called "QF"). RECITALS ∙ The QF has installed electric generating facilities, consisting of ____________________ ___________________________________________________ (Description of facilities), rated at ___ kilowatts of electricity, on property located at _________________________ ________________________________________________________________________. ∙ The QF is a customer of the Utility located within the assigned electric service territory of the Utility. ∙ The QF is prepared to generate electricity in parallel with the Utility. ∙ The QF's electric generating facilities meet the requirements of the rules adopted by the Utility on Cogeneration and Small Power Production and any technical standards for interconnection the Utility has established that are authorized by those rules. ∙ The Utility is obligated under federal and Minnesota law to interconnect with the QF and to purchase electricity offered for sale by the QF. ∙ A contract between the QF and the Utility is required. AGREEMENTS The QF and the Utility agree: 1. The Utility will sell electricity to the QF under the rate schedule in force for the class of customer to which the QF belongs. 2. The Utility will buy electricity from the QF under the current rate schedule filed with the city council or city-appointed body governing the utility. The QF elects the rate schedule category hereinafter indicated: ____ a. Average retail utility rate. QF capacity must be less than 40 kW. ____ b. Simultaneous purchase and sale billing rate. QF capacity must be less than 40 kW.
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____ c. Roll-over credits. QF capacity must be less than 40 kW. ____ d. Time-of-day purchase rate. QF capacity must be 40 kW or more and less than or equal to 100 kW. A copy of the presently filed rate schedule is attached to this contract. 3. The rates for sales and purchases of electricity may change over the time this contract is in force, due to actions of the Utility or of the State of Minnesota, and the QF and the Utility agree that sales and purchases will be made under the rates in effect each month during the time this contract is in force. 4. The Utility will compute the charges and payments for purchases and sales for each billing period. Any net credit to the QF, other than kilowatt-hour credits under clause 2(c), will be made under one of the following options as chosen by the QF: ____ a. Credit to the QF's account with the Utility. ____ b. Paid by check or electronic payment service to the QF within 15 days of the billing date. 5. Renewable energy credits associated with generation from the facility are owned by QF: ________________________________________________________________________ 6. The QF must operate its electric generating facilities within any rules, regulations, and policies adopted by the Utility not prohibited by the Minnesota Public Utilities Commission's rules on Cogeneration and Small Power Production. The Utility's rules, regulations, and policies must be consistent with the Minnesota Public Utilities Commission's rules on Cogeneration and Small Power Production, as required under Minnesota Statutes §216B.164, subdivision 9. 7. The QF will not enter into an arrangement whereby electricity from the generating facilities will be sold to an end user in violation of the Utility’s or any other electric utility’s exclusive right to provide electric service in its service area under Minnesota Statutes, Sections 216B.37-44. 8. The QF will operate its electric generating facilities so that they conform to the national, state, and local electric and safety codes, and will be responsible for the costs of conformance. 9. The QF is responsible for the actual, reasonable costs of interconnection which are estimated to be $_____________. The QF will pay the Utility in this way:
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____________________________________________________________________________ ________________________________________________________________________.
10. The QF will give the Utility reasonable access to its property and electric generating facilities if the configuration of those facilities does not permit disconnection or testing from the Utility's side of the interconnection. If the Utility enters the QF's property, the Utility will remain responsible for its personnel. 11. The Utility may stop providing electricity to the QF during a system emergency. The Utility will not discriminate against the QF when it stops providing electricity or when it resumes providing electricity. 12. The Utility may stop purchasing electricity from the QF when necessary for the Utility to construct, install, maintain, repair, replace, remove, investigate, or inspect any equipment or facilities within its electric system. The Utility will notify the QF before it stops purchasing electricity in this way: _____________________________________________________________________________ ____________________________________________________________________. 13. The QF will keep in force liability insurance against personal or property damage due to the installation, interconnection, and operation of its electric generating facilities. The amount of insurance coverage will be $______________ (The amount must be consistent with the Utility’s distributed generation tariff under Minnesota Statutes §216B.1611, subdivision 3, clause 2. 14. The Utility and the QF agree to attempt to resolve any dispute arising hereunder promptly and in a good faith manner. 15. The city council or city-appointed body governing the Utility has authority to consider and determine disputes, if any, that arise under this contract pursuant to Minnesota Statues §216B.164, subd. 9. 16. This contract becomes effective as soon as it is signed by the QF and the Utility. This contract will remain in force until either the QF or the Utility gives written notice to the other that the contract is canceled. This contract will be canceled 30 days after notice is given. 17. Neither the QF or the Utility will be considered in default as to any obligation if the QF or the Utility is prevented from fulfilling the obligation due to an event of Force Majeure. However, the QF or Utility whose performance under this contract is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations. 18. This contract can only be amended or modified by mutual agreement in writing signed by the QF and the Utility.
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19. Each Party will be responsible for its own acts or omissions and the results thereof to the extent authorized by law and shall not be responsible for the acts or omissions of any others and the results thereof. 20. The QF’s and the Utility’s liability to each other for failure to perform its obligations under this contract shall be limited to the amount of direct damage actually occurred. In no event, shall the QF or the Utility be liable to each other for any punitive, incidental, indirect, special, or consequential damages of any kind whatsoever, including for loss of business opportunity or profits, regardless of whether such damages were foreseen. 21. The Utility does not give any warranty, expressed or implied, to the adequacy, safety, or other characteristics of the QF’s interconnected system. 22. This contract contains all the agreements made between the QF and the Utility. The QF and the Utility are not responsible for any agreements other than those stated in this contract.
THE QF AND THE UTILITY HAVE READ THIS CONTRACT AND AGREE TO BE BOUND BY ITS TERMS. AS EVIDENCE OF THEIR AGREEMENT, THEY HAVE EACH SIGNED THIS CONTRACT BELOW ON THE DATE WRITTEN AT THE BEGINNING OF THIS CONTRACT.
QF
UTILITY
________________________________
________________________________
Signature
Signature
________________________________
________________________________
Printed Name
Printed Name
________________________________
________________________________
Title
Title
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RESOLUTION NO. 18-2 BOARD OF COMMISSIONERS ELK RIVER MUNICIPAL UTILITIES A RESOLUTION ADOPTING ELK RIVER MUNICIPAL UTILITIES COGENERATION AND SMALL POWER PRODUCTION TARIFF. WHEREAS, Elk River Municipal Utilities rules and Minnesota Statutes Section 216B.164 require the utility to annually file a Cogeneration and Small Power Production Tariff with the Elk River Municipal Utilities Commission WHEREAS, Schedule 1 of this tariff shall provide the calculation of average retail utility energy rates. WHEREAS, Schedule 2 provides standard contracts to be used with qualifying facilities. WHEREAS, Schedule 3 provides the utility’s safety standards, required operating procedures for interconnected operations, and the functions to be performed by any control and protective apparatus. WHEREAS, Schedule 4 provides procedures for notifying qualifying facilities of periods when Elk River Municipal Utilities will not purchase energy or capacity. WHEREAS, Schedule 5 provides the estimated seasonal peak and off-peak system average incremental energy costs for the utility’s power supplier from which energy purchases are first avoided, as well as the power supplier’s net annual avoided capacity costs. WHEREAS, these filings shall be maintained at the Elk River Municipal Utilities offices and shall be made available for public inspection during normal business hours. THEREFORE, BE IT RESOLVED that the Elk River Municipal Utilities Commission adopts the Cogeneration and Small Power Production Tariff for transactions following the date of adoption stated below. This Resolution Passed and Adopted this 13th day of February, 2018.
___________________________________ John J. Dietz, Chair ___________________________________ Troy Adams, P.E., General Manager
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Cogeneration and Small Power Production Tariff - Introduction
E.12b - Tariff Pursuant to its Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities, Elk River Municipal Utilities (“Utility”) establishes and/or updates its Cogeneration and Small Power Production Tariff (“Tariff”) for billing and sales transactions following the date of Tariff approval as follows. The Tariff shall consist of: SCHEDULE 1. Calculation of average retail utility energy rates SCHEDULE 2. Standard contracts to be used with Qualifying Facilities. SCHEDULE 3. Interconnection process, safety standards, and technical requirements for distributed energy resource systems, required operating procedures for interconnected operations, and functions to be performed by any control and protective apparatus. SCHEDULE 4. Procedures for notifying affected Qualifying Facilities of any periods of time when the utility will not purchase electric energy or capacity because of extraordinary operational circumstances. SCHEDULE 5. Estimated average incremental energy costs by seasonal, peak and off-peak periods and annual avoided capacity costs from the utility’s wholesale power supplier.
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SCHEDULE 1 – AVERAGE RETAIL UTILITY ENERGY RATES
Average Retail Utility Energy Rate: Available to any Qualifying Facility of less than 40 kW capacity that does not select either Roll Over Credits, Simultaneous Purchase and Sale Billing or Time of Day rates. Utility shall bill Qualifying Facilities for any excess of energy supplied by Utility above energy supplied by the Qualifying Facility during each billing period according to Utility’s applicable rate schedule. Utility shall pay the customer for the energy generated by the Qualifying Facility that exceeds that supplied by Utility during a billing period at the “average retail utility energy rate.” "Average retail utility energy rate" means, for any class of utility customer, the quotient of the total annual class revenue from sales of electricity minus the annual revenue resulting from fixed charges, divided by the annual class kilowatt-hour sales. Data from the most recent 12-month period available shall be used in the computation. “Average retail utility energy rates” are as follows: Customer Class
Average Retail Utility Energy Rate
Residential Commercial Non-Demand Commercial Demand
$0.1269 /kWh $0.1133 /kWh $0.0613 /kWh
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SCHEDULE 2 – STANDARD CONTRACT
CONTRACT FOR COGENERATION AND SMALL POWER PRODUCTION FACILITIES THIS CONTRACT is entered into on this ______day of ___________, _____, by Elk River Municipal Utilities, a municipal utility under Minnesota law (hereafter called "Utility") and ____________________________________________________ (hereafter called "QF"). RECITALS ∙ The QF has installed electric generating facilities, consisting of ____________________ ___________________________________________________ (Description of facilities), rated at ___ kilowatts of electricity, on property located at _________________________ ________________________________________________________________________. ∙ The QF is a customer of the Utility located within the assigned electric service territory of the Utility. ∙ The QF is prepared to generate electricity in parallel with the Utility. ∙ The QF's electric generating facilities meet the requirements of the rules adopted by the Utility on Cogeneration and Small Power Production and any technical standards for interconnection the Utility has established that are authorized by those rules. ∙ The Utility is obligated under federal and Minnesota law to interconnect with the QF and to purchase electricity offered for sale by the QF. ∙ A contract between the QF and the Utility is required. AGREEMENTS The QF and the Utility agree: 1. The Utility will sell electricity to the QF under the rate schedule in force for the class of customer to which the QF belongs. 2. The Utility will buy electricity from the QF under the current rate schedule filed with the city council or city-appointed body governing the utility. The QF elects the rate schedule category hereinafter indicated: ____ a. Average retail utility rate. QF capacity must be less than 40 kW. ____ b. Simultaneous purchase and sale billing rate. QF capacity must be less than 40 kW.
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SCHEDULE 2 – STANDARD CONTRACT
____ c. Roll-over credits. QF capacity must be less than 40 kW. ____ d. Time-of-day purchase rate. QF capacity must be 40 kW or more and less than or equal to 100 kW. A copy of the presently filed rate schedule is attached to this contract. 3. The rates for sales and purchases of electricity may change over the time this contract is in force, due to actions of the Utility or of the State of Minnesota, and the QF and the Utility agree that sales and purchases will be made under the rates in effect each month during the time this contract is in force. 4. The Utility will compute the charges and payments for purchases and sales for each billing period. Any net credit to the QF, other than kilowatt-hour credits under clause 2(c), will be made under one of the following options as chosen by the QF: ____ a. Credit to the QF's account with the Utility. ____ b. Paid by check or electronic payment service to the QF within 15 days of the billing date. 5. Renewable energy credits associated with generation from the facility are owned by QF: ________________________________________________________________________ 6. The QF must operate its electric generating facilities within any rules, regulations, and policies adopted by the Utility not prohibited by the Minnesota Public Utilities Commission's rules on Cogeneration and Small Power Production. The Utility's rules, regulations, and policies must be consistent with the Minnesota Public Utilities Commission's rules on Cogeneration and Small Power Production, as required under Minnesota Statutes §216B.164, subdivision 9. 7. The QF will not enter into an arrangement whereby electricity from the generating facilities will be sold to an end user in violation of the Utility’s or any other electric utility’s exclusive right to provide electric service in its service area under Minnesota Statutes, Sections 216B.37-44. 8. The QF will operate its electric generating facilities so that they conform to the national, state, and local electric and safety codes, and will be responsible for the costs of conformance. 9. The QF is responsible for the actual, reasonable costs of interconnection which are estimated to be $_____________. The QF will pay the Utility in this way: ___________________________________________________________________________ ______________________________________________________________________.
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SCHEDULE 2 – STANDARD CONTRACT
10. The QF will give the Utility reasonable access to its property and electric generating facilities if the configuration of those facilities does not permit disconnection or testing from the Utility's side of the interconnection. If the Utility enters the QF's property, the Utility will remain responsible for its personnel. 11. The Utility may stop providing electricity to the QF during a system emergency. The Utility will not discriminate against the QF when it stops providing electricity or when it resumes providing electricity. 12. The Utility may stop purchasing electricity from the QF when necessary for the Utility to construct, install, maintain, repair, replace, remove, investigate, or inspect any equipment or facilities within its electric system. The Utility will notify the QF before it stops purchasing electricity in this way: ___________________________________________________________________________ ______________________________________________________________________. 13. The QF will keep in force liability insurance against personal or property damage due to the installation, interconnection, and operation of its electric generating facilities. The amount of insurance coverage will be $______________ (The amount must be consistent with the Utility’s distributed generation tariff under Minnesota Statutes §216B.1611, subdivision 3, clause 2. 14. The Utility and the QF agree to attempt to resolve any dispute arising hereunder promptly and in a good faith manner. 15. The city council or city-appointed body governing the Utility has authority to consider and determine disputes, if any, that arise under this contract pursuant to Minnesota Statues §216B.164, subd. 9. 16. This contract becomes effective as soon as it is signed by the QF and the Utility. This contract will remain in force until either the QF or the Utility gives written notice to the other that the contract is canceled. This contract will be canceled 30 days after notice is given. 17. Neither the QF or the Utility will be considered in default as to any obligation if the QF or the Utility is prevented from fulfilling the obligation due to an event of Force Majeure. However, the QF or Utility whose performance under this contract is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations. 18. This contract can only be amended or modified by mutual agreement in writing signed by the QF and the Utility. 19. Each Party will be responsible for its own acts or omissions and the results thereof to the extent authorized by law and shall not be responsible for the acts or omissions of any others and the results thereof.
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SCHEDULE 2 – STANDARD CONTRACT
20. The QF’s and the Utility’s liability to each other for failure to perform its obligations under this contract shall be limited to the amount of direct damage actually occurred. In no event, shall the QF or the Utility be liable to each other for any punitive, incidental, indirect, special, or consequential damages of any kind whatsoever, including for loss of business opportunity or profits, regardless of whether such damages were foreseen. 21. The Utility does not give any warranty, expressed or implied, to the adequacy, safety, or other characteristics of the QF’s interconnected system. 22. This contract contains all the agreements made between the QF and the Utility. The QF and the Utility are not responsible for any agreements other than those stated in this contract. THE QF AND THE UTILITY HAVE READ THIS CONTRACT AND AGREE TO BE BOUND BY ITS TERMS. AS EVIDENCE OF THEIR AGREEMENT, THEY HAVE EACH SIGNED THIS CONTRACT BELOW ON THE DATE WRITTEN AT THE BEGINNING OF THIS CONTRACT. QF
UTILITY
________________________________
________________________________
Signature
Signature
________________________________
________________________________
Printed Name
Printed Name
________________________________
________________________________
Title
Title
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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
State of Minnesota
Interconnection Process for Distributed Generation Systems Introduction
This document has been prepared to explain the process established in the State of Minnesota, to interconnect a Generation System with the Area Electrical Power System (Area EPS). This document covers the interconnection process for all types of Generation Systems which are rated 10MW’s or less of total generation Nameplate Capacity; are planned for interconnection with the Area EPS’s Distribution System; are not intended for wholesale transactions and aren’t anticipated to affect the transmission system. This document does not discuss the interconnection Technical Requirements, which are covered in the “State of Minnesota Distributed Generation Interconnection Requirements” document. This other interconnection requirements document also provides definitions and explanations of the terms utilized within this document. To interconnect a Generation System with the Area EPS, there are several steps that must be followed. This document outlines those steps and the Parties’ responsibilities. At any point in the process, if there are questions, please contact the Generation Interconnection Coordinator at the Area EPS. Since this document has been developed to provide an interconnection process which covers a very diverse range of Generation Systems, the process appears to be very involved and cumbersome. For many Generation Systems the process is streamlined and provides an easy path for interconnection. The promulgation of interconnection standards for Generation Systems by the Minnesota Public Utilities Commission (MPUC) must be done in the context of a reasonable interpretation of the boundary between state and federal jurisdiction. The Federal Energy Regulatory Commission (FERC) has asserted authority in the area, at least as far as interconnection at the transmission level is concerned. This, however, leaves open the question of jurisdiction over interconnection at the distribution level. The Midwest Independent System Operator’s (MISO) FERC Electric Tariff, (first revised volume 1, August 23,2001) Attachment R (Generator Interconnection Procedures and Agreement) states in section 2.1 that “Any existing or new generator connecting at transmission voltages, sub-transmission voltages, or distribution voltages, planning to engage in the sale for resale of wholesale energy, capacity, or ancillary services requiring transmission service under the Midwest ISO OATT must apply to the Midwest ISO for interconnection service”. Further in section 2.4 it states that “A Generator not intending to engage in the sale of wholesale energy, capacity, or ancillary services under the Midwest ISO OATT, that proposes to interconnect a new generating facility to the distribution system of a Transmission Owner or local distribution utility interconnected with the Transmission System shall apply to the Transmission Owner or local distribution utility for interconnection”. It goes on further to state “Where facilities under the control of the Midwest ISO are affected by such interconnection, such interconnections may be subject to the planning and operating protocols of the Midwest ISO….” Through discussions with MISO personnel and as a practical matter, if the Generation System Nameplate Capacity is not greater in size than the minimum expected load on the distribution substation, that is feeding the proposed Generation System, and Generation System’s energy is not being sold on the wholesale market, then that installation may be considered as not “affecting” the transmission system and the interconnection may be considered as governed by this process. If the Generation System will be selling energy on the wholesale market or the Generation System’s total Nameplate Capacity is greater than the expected distribution substation minimum load, then the Applicant shall contact MISO (Midwest Independent System Operator) and follow their procedures.
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GENERAL INFORMATION A)
Definitions 1) “Applicant” is defined as the person or entity who is requesting the interconnection of the Generation System with the Area EPS and is responsible for ensuring that the Generation System is designed, operated and maintained in compliance with the Technical Requirements. 2) “Area EPS” is defined as an electric power system (EPS) that serves Local EPS’s. Note. Typically, an Area EPS has primary access to public rights-of-way, priority crossing of property boundaries, etc. 3) “Area EPS Operator” is the entity who operates the Area EPS. 4) “Dedicated Facilities” is the equipment that is installed due to the interconnection of the Generation System and not required to serve other Area EPS customers. 5) “Distribution System” is the Area EPS facilities which are not part of the Area EPS Transmission System or any Generation System. 6) “Extended Parallel” means the Generation System is designed to remain connected with the Area EPS for an extended period of time. 7) “Generation” is defined as any device producing electrical energy, i.e., rotating generators driven by wind, steam turbines, internal combustion engines, hydraulic turbines, solar, fuel cells, etc.; or any other electric producing device, including energy storage technologies. 8) “Generation Interconnection Coordinator” is the person or persons designated by the Area EPS Operator to provide a single point of coordination with the Applicant for the generation interconnection process. 9)
“Generation System” is the interconnected generator(s), controls, relays, switches, breakers, transformers, inverters and associated wiring and cables, up to the Point of Common Coupling.
10) “Interconnection Customer” is the party or parties who will own/operate the Generation System and are responsible for meeting the requirements of the agreements and Technical Requirements. This could be the Generation System applicant, installer, owner, designer, or operator. 11) “Local EPS” is an electric power system (EPS) contained entirely within a single premises or group of premises 12) “Nameplate Capacity” is the total nameplate capacity rating of all the Generation included in the Generation System. For this definition the “standby” and/or maximum rated kW capacity on the nameplate shall be used. 13) “Open Transfer” is a method of transferring the local loads from the Area EPS to the generator such that the generator and the Area EPS are never connected together.
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14) “Point of Common Coupling” is the point where the Local EPS is connected to an Area EPS 15) “Quick Closed” is a method of generation transfer which does not parallel or parallels for less than 100msec with the Area EPS and has utility grade timers which limit the parallel duration to less than 100 msec with the Area EPS. 16) “Technical Requirements” “is the State of Minnesota Distributed Generation Interconnection Requirements”. 17) “Transmission System” means those facilities as defined by using the guidelines established by the Minnesota State Public Utilities Commission; “In the Matter of Developing Statewide Jurisdictional Boundary Guidelines for Functionally Separating Interstate Transmission from Generation and Local Distribution Functions” Docket No. E-015/M-99-1002.
B)
Dispute Resolution The following is the dispute resolution process to be followed for problems that occur with the implementation of this process. 1) Each Party agrees to attempt to resolve all disputes arising hereunder promptly, equitably and in a good faith manner. 2) In the event a dispute arises under this process, and the parties are not successful in resolving their disputes, then either party may refer the dispute for resolution to the Elk River Municipal Utilities Commission, which shall maintain continuing jurisdiction over this process.
C)
Area EPS Generation Interconnection Coordinator. Each Area EPS Operator shall designate a Generation Interconnection Coordinator(s) and this person or persons shall provide a single point of contact for an Applicant’s questions on this Generation Interconnection process. Some Area EPS Operators may have several Generation Interconnection Coordinators assigned, due to the geographical size of their electrical service territory or the amount of interconnection applications. This Generation Interconnection Coordinator will typically not be able to directly answer or resolve all of the issues involved in the review and implementation of the interconnection process and standards, but shall be available to provide coordination assistance with the Applicant
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D)
Engineering Studies During the process of design of a Generation System interconnection between a Generation System and an Area EPS, there are several studies which many need to be undertaken. On the Local EPS (Customers side of the interconnection) the addition of a Generation System may increase the fault current levels, even if the generation is never interconnected with the Area EPS’s system. The Interconnection Customer may need to conduct a fault current analysis of the Local EPS in conjunction with adding the Generation System. The addition of the Generation System may also affect the Area EPS and special engineering studies may need to be undertaken looking at the Area EPS with the Generation System included. Appendix D, lists some of the issues that may need to receive further analysis for the Generation System interconnection. While, it is not a straightforward process to identify which engineering studies are required, we can at least develop screening criteria to identify which Generation Systems may require further analysis. The following is the basic screening criteria to be used for this interconnection process. 1) Generation System total Nameplate Capacity does not exceed 5% of the radial circuit expected peak load. The peak load is the total expected load on the radial circuit when the other generators on that same radial circuit are not in operation. 2) The aggregate generation’s total Nameplate Capacity, including all existing and proposed generation, does not exceed 25% of the radial circuit peak load and that total is also less than the radial circuit minimum load. 3) Generation System does not exceed 15% of the Annual Peak Load for the Line Section, which it will interconnect with. A Line Section is defined as that section of the distribution system between two sectionalizing devices in the Area EPS. 4) Generation System does not contribute more than 10% to the distribution circuit’s maximum fault current at the point at the nearest interconnection with the Area EPS’s primary distribution voltage. 5) The proposed Generation System total Nameplate Capacity, in aggregate with other generation on the distribution circuit, will not cause any distribution protective devices and equipment to exceed 85 percent of the short circuit interrupting capability. 6) If the proposed Generation System is to be interconnected on a single-phase shared secondary, the aggregate generation Nameplate Capacity on the shared secondary, including the proposed generation, does not exceed 20kW. 7) Generation System will not be interconnected with a “networked” system
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E)
Scoping Meeting During Step 2 of this process, the Applicant or the Area EPS Operator has the option to request a scoping meeting. The purpose of the scoping meeting shall be to discuss the Applicant’s interconnection request and review the application filed. This scoping meeting is to be held so that each Party can gain a better understanding of the issues involved with the requested interconnection. The Area EPS and Applicant shall bring to the meeting personnel, including system engineers, and other resources as may be reasonably required, to accomplish the purpose of the meeting. The Applicant shall not expect the Area EPS to complete the preliminary review of the proposed Generation System at the scoping meeting. If a scoping meeting is requested, the Area EPS shall schedule the scoping meeting within the 15 business day review period allowed for in Step 2. The Area EPS shall then have an additional 5 days, after the completion of the scoping meeting, to complete the formal response required in Step 2. The Application fee shall cover the Area EPS’s costs for this scoping meeting. There shall be no additional charges imposed by the Area EPS for this initial scoping meeting
F)
Insurance 1) At a minimum, in connection with the Interconnection Customer’s performance of its duties and obligations under this Agreement, the Interconnection Customer shall maintain, during the term of the Agreement, general liability insurance, from a qualified insurance agency with a B+ or better rating by “Best” and with a combined single limit of not less then: a) Two million dollars ($2,000,000) for each occurrence if the Gross Nameplate Rating of the Generation System is greater than 250kW. b) One million dollars ($1,000,000) for each occurrence if the Gross Nameplate Rating of the Generation System is between 40kW and 250kW. c) Three hundred thousand ($300,000) for each occurrence if the Gross Nameplate Rating of the Generation System is less than 40kW. d) Such general liability insurance shall include coverage against claims for damages resulting from (i) bodily injury, including wrongful death; and (ii) property damage arising out of the Interconnection Customer’s ownership and/or operating of the Generation System under this agreement. 2) The general liability insurance required shall, by endorsement to the policy or policies, (a) include the Area EPS Operator as an additional insured; (b) contain a sever ability of interest clause or cross-liability clause; (c) provide that the Area EPS Operator shall not by reason of its inclusion as an additional insured incur liability to the insurance carrier for the payment of premium for such insurance; and (d) provide for thirty (30) calendar days’ written notice to the Area EPS Operator prior to cancellation, termination, alteration, or material change of such insurance. 3) If the Generation System is connected to an account receiving residential service from the Area EPS Operator and it total generating capacity is smaller than 40kW, then the endorsements required in Section F.2 shall not apply.
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4) The Interconnection Customer shall furnish the required insurance certificates and endorsements to the Area EPS Operator prior to the initial operation of the Generation System. Thereafter, the Area EPS Operator shall have the right to periodically inspect or obtain a copy of the original policy or policies of insurance 5) Evidence of the insurance required in Section F.1. shall state that coverage provided is primary and is not excess to or contributing with any insurance or self-insurance maintained by the Area EPS Operator. 6) If the Interconnection Customer is self-insured with an established record of selfinsurance, the Interconnection Customer may comply with the following in lieu of Section F.1 – 5: 7) Interconnection Customer shall provide to the Area EPS Operator, at least thirty (30) days prior to the date of initial operation, evidence of an acceptable plan to self- insure to a level of coverage equivalent to that required under section F.1 8) If Interconnection Customer ceases to self-insure to the level required hereunder, or if the Interconnection Customer is unable to provide continuing evidence of its ability to selfinsure, the Interconnection Customer agrees to immediately obtain the coverage required under section F.1. 9) Failure of the Interconnection Customer or Area EPS Operator to enforce the minimum levels of insurance does not relieve the Interconnection Customer from maintaining such levels of insurance or relieve the Interconnection Customer of any liability.
G)
Pre-Certification The most important part of the process to interconnect generation with Local and Area EPS’s is safety. One of the key components of ensuring the safety of the public and employees is to ensure that the design and implementation of the elements connected to the electrical power system operate as required. To meet this goal, all of the electrical wiring in a business or residence, is required by the State of Minnesota to be listed by a recognized testing and certification laboratory, for its intended purpose. Typically we see this as “UL” listed. Since Generation Systems have tended to be uniquely designed for each installation they have been designed and approved by Professional Engineers. This process has been set up to be able to deal with these uniquely designed systems. As the number of Generation Systems installed increase, vendors are working towards creating equipment packages which can be tested in the factory and then will only require limited field testing. This will allow us to move towards “plug and play” installations. For this reason, this interconnection process recognizes the efficiency of “pre-certification” of Generation System equipment packages that will help streamline the design and installation process.
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An equipment package shall be considered certified for interconnected operation if it has been submitted by a manufacture, tested and listed by a nationally recognized testing and certification laboratory (NRTL) for continuous utility interactive operation in compliance with the applicable codes and standards. Presently generation paralleling equipment that is listed by a nationally recognized testing laboratory as having met the applicable type-testing requirements of UL 1741 and IEEE 929 shall be acceptable for interconnection without additional protection system requirements. An “equipment package” shall include all interface components including switchgear, inverters, or other interface devices and may include an integrated generator or electric source. If the equipment package has been tested and listed as an integrated package which includes a generator or other electric source, it shall not require further design review, testing or additional equipment to meet the certification requirements for interconnection. If the equipment package includes only the interface components (switchgear, inverters, or other interface devices), then the Interconnection Customer shall show that the generator or other electric source being utilized with the equipment package is compatible with the equipment package and consistent with the testing and listing specified for the package. Provided the generator or electric source combined with the equipment package is consistent with the testing ad listing performed by the nationally recognized testing and certification laboratory, no further design review, testing or additional equipment shall be required to meet the certification requirements of this interconnection procedure. A certified equipment package does not include equipment provided by the Area EPS. The use of Pre-Certified equipment does not automatically qualify the Interconnection Customer to be interconnected to the Area EPS. An application will still need to be submitted and an interconnection review may still need to be performed, to determine the compatibility of the Generation System with the Area EPS. H)
Confidential Information Except as otherwise agreed, each Party shall hold in confidence and shall not disclose confidential information, to any person (except employees, officers, representatives and agents, who agree to be bound by this section). Confidential information shall be clearly marked as such on each page or otherwise affirmatively identified. If a court, government agency or entity with the right, power, and authority to do so, requests or requires either Party, by subpoena, oral disposition, interrogatories, requests for production of documents, administrative order, or otherwise, to disclose Confidential Information, that Party shall provide the other Party with prompt notice of such request(s) or requirements(s) so that the other Party may seek an appropriate protective order or waive compliance with the terms of this Agreement. In the absence of a protective order or waiver the Party shall disclose such confidential information which, in the opinion of its counsel, the party is legally compelled to disclose. Each Party will use reasonable efforts to obtain reliable assurance that confidential treatment will be accorded any confidential information so furnished.
I)
Non-Warranty. Neither by inspection, if any, or non-rejection, nor in any other way, does the Area EPS Operator give any warranty, expressed or implied, as to the adequacy, safety, or other characteristics of any structures, equipment, wires, appliances or devices owned, installed or maintained by the Applicant or leased by the Applicant from third parties, including without limitation the Generation System and any structures, equipment, wires, appliances or devices pertinent thereto.
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J)
Required Documents The chart below lists the documents required for each type and size of Generation System proposed for interconnection. Find your type of Generation System interconnection, across the top, then follow the chart straight down, to determine what documents are required as part of the interconnection process.
GENERATION INTERCONNECTION DOCUMENT SUMMARY Open Transfer
Quick Closed Transfer
Soft Loading Transfer
Extended Parallel Operation QF facility <40kW
Without Sales
With Sales
Interconnection Process (This document) State of Minnesota Distributed Generation Interconnection Requirements Generation Interconnection Application (Appendix B) Engineering Data Submittal (Appendix C) Interconnection Agreement (Appendix E) MISO / FERC PPA Interconnection Process = “State of Minnesota Interconnection Process for Distributed Generation Systems.” (This document) State of Minnesota Distributed Generation Interconnection Requirements = “State of Minnesota Distributed Generation Interconnection Requirements” Generation Interconnection Application = The application form in Appendix B of this document. Engineering Data Submittal = The Engineering Data Form/Agreement, which is attached as Appendix C of this document. Interconnection Agreement = “Minnesota State Interconnection Agreement for the Interconnection of Extended Parallel Distributed Generation Systems with Electric Utilities.” MISO. = Midwest Independent System Operator, www.midwestiso.org FERC = Federal Energy Regulatory Commission, www.ferc.gov PPA = Power Purchase Agreement.
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Process for Interconnection Step 1 Application (By Applicant) Once a decision has been made by the Applicant, that they would like to interconnect a Generation System with the Area EPS, the Applicant shall supply the Area EPS with the following information: 1) Completed Generation Interconnection Application (Appendix C), including; a) One-line diagram showing; i) Protective relaying. ii) Point of Common Coupling. b) Site plan of the proposed installation. c) Name plate capacity of proposed generation system. d) Estimate of annual energy production from proposed generation system. e) Proposed schedule of the installation. 2) Payment of the application fee, according to the following sliding scale.
Generation Interconnection Application Fees: $200 This application fee is to contribute to the Area EPS Operator’s labor costs for administration, review of the design concept and preliminary engineering screening for the proposed Generation System interconnection.
Step 2 Preliminary Review (By Area EPS) Within 15 business days of receipt of all the information listed in Step 1, the Area EPS Generation Interconnection Coordinator shall respond to the Applicant with the information listed below. (If the information required in Step 1 is not complete, the Applicant will be notified, within 10 business days of what is missing and no further review will be completed until the missing information is submitted. The 15-day clock will restart with the new submittal) As part of Step 2 the proposed Generation System will be screened to see if additional Engineering Studies are required. The base screening criteria is listed in the general information section of this document.
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1) A single point of contact with the Area EPS Operator for this project. (Generation Interconnection Coordinator) 2) Approval or rejection of the generation interconnection request. a) Rejection – The Area EPS shall supply the technical reasons, with supporting information, for rejection of the interconnection Application. b) Approval - An approved Application is valid for 6 months from the date of the approval. The Area EPS Generation Interconnection Coordinator may extend this time if requested by the Applicant 3) If additional specialized engineering studies are required for the proposed interconnection, the following information will be provided to the Applicant. Typical Engineering Studies are outlined in Appendix D. The costs to the Applicant, for these studies shall be not exceed the values shown in the following table for pre-certified equipment. Generation System Size ≤40kW >40kW
Engineering Study Maximum Costs Actual Costs Actual Costs
a) b) c) d)
General scope of the engineering studies required. Estimated cost of the engineering studies. Estimated duration of the engineering studies. Additional information required to allow the completion of the engineering studies. e) Study authorization agreement. 4) Comments on the schedule provided. 5) If the rules of MISO (Midwest Independent System Operator) require that this interconnection request be processed through the MISO process, the Generation Interconnection Coordinator will notify the Applicant that the generation system is not eligible for review through the State of Minnesota process.
Step 3 Go-No Go Decision for Engineering Studies (By Applicant)
In this step, the Applicant will decide whether or not to proceed with the required engineering studies for the proposed generation interconnection. If no specialized engineering studies are required by the Area EPS Operator, the Area EPS Operator and the Applicant will automatically skip this step. If the Applicant decides NOT to proceed with the engineering studies, the Applicant shall notify the Area EPS Generation Interconnection Coordinator, so other generation interconnection requests in the queue are not adversely impacted. Should the Applicant decide to proceed, the Applicant shall provide the following to the Area EPS Generation Interconnection Coordinator: 1) Payment required by the Area EPS Operator for the specialized engineering studies. 2) Additional information requested by the Area EPS Operator to allow completion of the engineering studies.
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Step 4 Engineering Studies (By Area EPS)
In this step, the Area EPS Operator will be completing the specialized engineering studies for the proposed generation interconnection, as outlined in Step 2. These studies should be completed in the time frame provided in step 2, by the Area EPS. It is expected that the Area EPS Operator shall make all reasonable efforts to complete the Engineering Studies within the time frames shown below. If additional time is required to complete the engineering studies the Generation Interconnection Coordinator shall notify the Applicant and provide the reasons for the time extension. Upon receipt of written notice to proceed, payment of applicable fee, and receipt of all engineering study information requested by the Area EPS Operator in step 2, the Area EPS Operator shall initiate the engineering studies. Generation System Size ≤40kW >40kW
Engineering Study Completion 20 working days 30 – 90 working days
Once it is known by the Area EPS Operator that the actual costs for the engineering studies will exceed the estimated amount by more the 25%, then the Applicant shall be notified. The Area EPS Operator shall then provide the reason(s) for the studies needing to exceed the original estimated amount and provide an updated estimate of the total cost for the engineering studies. The Applicant shall be given the option of either withdrawing the application, or paying the additional estimated amount to continue with the engineering studies.
Step 5 Study Results and Construction Estimates (By Area EPS)
Upon completion of the specialized engineering studies, or if none was necessary, the following information will be provided to the Applicant. 1) Results of the engineering studies, if needed. 2) Monitoring & control requirements for the proposed generation. 3) Special protection requirements for the Generation System interconnection. 4) Comments on the schedule proposed by the Applicant. 5) Distributed Generation distribution constrained credits available 6) Interconnection Agreement (if applicable). 7) Cost estimate and payment schedule for required Area EPS work, including, but not limited to; a) Labor costs related to the final design review. b) Labor & expense costs for attending meetings c) Required Dedicated Facilities and other Area EPS modification(s). d) Final acceptance testing costs.
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Step 6 Final Go-No Go Decision (By Applicant)
In this step, the Applicant shall again have the opportunity to indicate whether or not they want to proceed with the proposed generation interconnection. If the decision is NOT to proceed, the Applicant will notify the Area EPS Generation Interconnection Coordinator, so that other generation interconnections in the queue are not adversely impacted. Should the Applicant decide to proceed, a more detailed design, if not already completed by the Applicant, must be done, and the following information is to be supplied to the Area EPS Generation Interconnection Coordinator: 1) Applicable up-front payment required by the Area EPS, per Payment Schedule, provided in Step 5. (if applicable) 2) Signed Interconnection Agreement (if applicable). 3) Final proposed schedule, incorporating the Area EPS comments. The schedule of the project should include such milestones as foundations poured, equipment delivery dates, all conduit installed, cutover (energizing of the new switchgear/transfer switch), Area EPS work, relays set and tested, preliminary vendor testing, final Area EPS acceptance testing, and any other major milestones. 4) Detailed one-line diagram of the Generation System, including the generator, transfer switch/switchgear, service entrance, lockable and visible disconnect, metering, protection and metering CT’s / VT’s, protective relaying and generator control system. 5) Detailed information on the proposed equipment, including wiring diagrams, models and types. 6) Proposed relay settings for all interconnection required relays. 7) Detailed site plan of the Generation System. 8) Drawing(s) showing the monitoring system (as required per table 5A and section 5 of the “State of Minnesota Distributed Generation Interconnection Requirements”. Including a drawing which shows the interface terminal block with the Area EPS monitoring system. 9) Proposed testing schedule and initial procedure, including; a) Time of day (after-hours testing required?). b) Days required. c) Testing steps proposed.
Step 7 Final Design Review (By Area EPS) Within 15 business days of receipt of the information required in Step 6, The Area EPS Generation Interconnection Coordinator will provide the Applicant with an estimated time table for final review. If the information required in Step 6 is not complete, the Applicant will be notified, within 10 business days of what information is missing. No further review may be completed until the missing information is submitted. The 15-business day clock will restart with the new submittal. This final design review shall not take longer than 15 additional business days to complete, for a total of 30 business days.
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During this step, the Area EPS shall complete the review of the final Generation System design. If the final design has significant changes from the Generation System proposed on the original Application which invalidate the engineering studies or the preliminary engineering screening, the Generation System Interconnection Application request may be rejected by the Area EPS Operator and the Applicant may be requested to reapply with the revised design. Upon completion of this step the Generation Interconnection Coordinator shall supply the following information to the Applicant. 1) Requested modifications or corrections of the detailed drawings provided by the Applicant. 2) Approval of and mutual agreement with the Project Schedule. (This may need to be interactively discussed between the Parties, during this Step) 3) Final review of Distributed Generation Credit amount(s) (where applicable). 4) Initial testing procedure review comments. (Additional work on the testing process will occur during Step 8, once the actual equipment is identified)
Step 8 Order Equipment and Construction (By Both Parties)
The following activities shall be completed during this step. For larger installations this step will involve much interaction between the Parties. It is typical for approval drawings to be supplied by the Applicant to the Area EPS for review and comments. It is also typical for the Area EPS to require review and approval of the drawings that cover the interconnection equipment and interconnection protection system. If the Area EPS also requires remote control and/or monitoring, those drawings are also exchanged for review and comment. By the Applicant’s personnel: 1) Ordering of Generation System equipment. 2) Installing Generation System. 3) Submit approval drawings for interconnection equipment and protection systems, as required by Area EPS Operator. 4) Provide final relay settings provided to the Area EPS Operator. 5) Submit Completed and signed Engineering Data Submittal form. 6) Submit proof of insurance, as required by the Area EPS tariff(s) or interconnection agreements. 7) Submit required State of Minnesota electrical inspection forms (“blue Copy) filed with the Area EPS Operator. 8) Inspecting and functional testing Generation System components. 9) Work with the Area EPS personnel and equipment vendor(s) to finalize the installation testing procedure. By Area EPS personnel: 1) Ordering any necessary Area EPS equipment. 2) Installing and testing any required equipment. a) Monitoring facilities. b) Dedicated Equipment. 3) Assisting Applicant’s personnel with interconnection installation coordination issues 4) Providing review and input for testing procedures.
Step 9 Final Tests (By Area EPS / Applicant)
(Due to equipment lead times and construction, a significant amount of time may take place between the execution of Step 8 and Step 9.) During this time the final test steps are developed and the construction of the facilities are completed.
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Final acceptance testing will commence when all equipment has been installed, all contractor preliminary testing has been accomplished and all Area EPS preliminary testing of the monitoring and dedicated equipment is completed. One to three weeks prior to the start of the acceptance testing of the generation interconnection the Applicant shall provide, a report stating: 1. That the Generation System meets all interconnection requirements. 2. All contractor preliminary testing has been completed. 3. The protective systems are functionally tested and ready. 4. A proposed date that the Generation System will be is ready to be energized and acceptance tested. For non-type certified systems a Professional Electrical Engineer registered in the State of Minnesota is required to provide this formal report. For smaller systems scheduling of this testing may be more flexible, as less testing time is required than for larger systems. In many cases, this testing is done after hours to ensure no typical business-hour load is disturbed. If acceptance testing occurs after hours, the Area EPS Operator’s labor will be billed at overtime wages. During this testing, the Area EPS Operator will typically run three different tests. These tests can differ depending on which type of communication / monitoring system(s) the Area EPS Operator decides to install at the site. For, problems created by Area EPS or any Area EPS equipment that arise during testing, the Area EPS will fix the problem as soon as reasonably possible. If problems arise during testing which are caused by the Applicant or Applicant’s vendor or any vendor supplied or installed equipment, the Area EPS will leave the project until the problem is resolved. Having the testing resume will then be subject to Area EPS personnel time and availability.
Step 10 (By Area EPS) After all Area EPS Operator’s acceptance testing has been accomplished and all requirements are met, the Area EPS Operator shall provide written approval for normal operation of the Generation System interconnection, within 3 business days of successful completion of the acceptance tests.
Step 11 (By Applicant) Within two (2) months of interconnection, the Applicant shall provide the Area EPS with updated drawings and prints showing the Generation System as it was when approved for normal operation by the Area EPS Operator. The drawings shall also include all changes which were made during construction and the testing process.
Attachments: Attached are several documents which may be required for the interconnection process. They are as follows; Appendix A: Appendix B:
Flow chart showing summary of the interconnection process. Generation Interconnection Application Form.
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Appendix C:
Engineering Data Submittal Form.
Appendix D: Engineering Studies: Brief description of the types of possible Engineering Studies that may be required for the review of the Generation System interconnection.
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APPENDIX A
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APPENDIX B
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APPENDIX C
INSERT ENGINEERING DATA SUBMITTAL FORM (if applicable)
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APPENDIX D Engineering Studies For the engineering studies the major concerns are; 1. Does the distributed generator cause a problem? and 2. What would it cost to make a change to handle the problem? The first question is relatively straightforward to determine as the Area EPS Engineer reviews the proposed installation. The second question typically has multiple alternatives and can turn into an iterative process. This iterative process can become quite large for more complex generation installations. For the Engineer there is no “cook book” solution which can be applied. For some of the large generation installations and/or the more complex interconnections the Area EPS Operator may suggest dividing up the engineering studies into the two parts; identify the scope of the problems and attempt to identify solutions to resolve the problems. By splitting the engineering studies into two steps, it will allow for the Applicant to see the problems identified and to provide the Applicant the ability to remove the request for interconnection if the problems are too large and expensive to resolve. This would then save the additional costs to the Applicant for the more expensive engineering studies; to identity ways to resolve the problem(s). This appendix provides an overview of some of the main issues that are looked at during the engineering study process. Every interconnection has its unique issues, such as relative strength of the distribution system, ratio of the generation size to the existing area loads, etc. Thus many of the generation interconnections will require further review of one or several of the issues listed.
Short circuit analysis – the system is studied to make sure that the addition of the generation will not over stress any of the Area EPS equipment and that equipment will still be able to clear during a fault. It is expected that the Applicant will complete their own short circuit analysis on their equipment to ensure that the addition of the generation system does not overstress the Applicant’s electrical equipment.
Power Flow and Voltage Drop - Reviews potential islanding of the generation - Will Area EPS Equipment be overloaded • Under normal operation? • Under contingent operation? With back feeds?
Flicker Analysis – - Will the operation of the generation cause voltage swings? • When it loads up? When it off loads? - How will the generation interact with Area EPS voltage regulation? - Will Area EPS capacitor switching affect the generation while on-line?
Protection Coordination - Reclosing issues – this is where the reclosing for the distribution system and transmission system are looked at to see if the Generation System protection can be set up to ensure that it will clear from the distribution system before the feeder is reenergized. • Is voltage supervision of reclosing needed? - Is transfer-trip required? - Do we need to modify the existing protection systems? Existing settings? - At which points do we need “out of sync” protection? - Is the proposed interconnection protection system sufficient to sense a problem on the Area EPS? - Are there protection problems created by the step-up transformer?
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Grounding Reviews - Does the proposed grounding system for the Generation System meet the requirements of the NESC? “National Electrical Safety Code” published by the Institute of Electrical and Electronics Engineers (IEEE)
System Operation Impact. - Are special operating procedures needed with the addition of the generation? - Reclosing and out of sync operation of facilities. - What limitations need to be placed on the operation of the generation? - Operational Var requirements?
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STATE OF MINNESOTA
DISTRIBUTED GENERATION INTERCONNECTION REQUIREMENTS TABLE OF CONTENTS Foreword
2
1.
Introduction
3
2.
References
6
3.
Types of Interconnections
7
4.
Interconnection Issues and Technical Requirements
10
5.
Generation Metering, Monitoring and Control Table 5A – Metering, Monitoring and Control Requirements
13 14
6.
Protective Devices and Systems Table 6A – Relay Requirements
17 19
7.
Agreements
20
8.
Testing Requirements
21
Attachments:
System Diagrams Figure 1 – Open Transition
25
Figure 2 – Closed Transition
26
Figure 3 – Soft Loading Transfer With Limited Parallel Operation
27
Figure 4 – Soft Loading Transfer With Limited Parallel Operation
28
Figure 5 – Extended Parallel With Transfer-Trip
29
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Foreword Electric distribution system connected generation units span a wide range of sizes and electrical characteristics. Electrical distribution system design varies widely from that required to serve the rural customer to that needed to serve the large commercial customer. With so many variations possible, it becomes complex and difficult to create one interconnection standard that fits all generation interconnection situations. In establishing a generation interconnection standard there are three main issues that must be addressed; Safety, Economics and Reliability. The first and most important issue is safety; the safety of the general public and of the employees working on the electrical systems. This standard establishes the technical requirements that must be met to ensure the safety of the general public and of the employees working with the Area EPS. Typically designing the interconnection system for the safety of the general public will also provide protection for the interconnected equipment. The second issue is economics; the interconnection design must be affordable to build. The interconnection standard must be developed so that only those items, that are necessary to meet safety and reliability, are included in the requirements. This standard sets the benchmark for the minimum required equipment. If it is not needed, it will not be required. The third issue is reliability; the generation system must be designed and interconnected such that the reliability and the service quality for all customers of the electrical power systems are not compromised. This applies to all electrical systems not just the Area EPS. Many generation interconnection standards exist or are in draft form. The IEEE, FERC and many states have been working on generation interconnection standards. There are other standards such as the National Electrical Code (NEC) that, establish requirements for electrical installations. The NEC requirements are in addition to this standard. This standard is designed to document the requirements where the NEC has left the establishment of the standard to “the authority having jurisdiction” or to cover issues which are not covered in other national standards. This standard covers installations, with an aggregated capacity of 10MW’s or less. Many of the requirements in this document do not apply to small, 40kW or less generation installations. As an aid to the small, distributed generation customer, these small unit interconnection requirements have been extracted from this full standard and are available as a separate, simplified document titled: “Standards for Interconnecting Generation Sources, Rated Less then 40kW with Minnesota Electric Utilities”
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1.
Introduction
This standard has been developed to document the technical requirements for the interconnection between a Generation System and an area electrical power system “Utility system or Area EPS”. This standard covers 3 phase Generation Systems with an aggregate capacity of 10 MW’s or less and single phase Generation Systems with an aggregate capacity of 40kW or less at the Point of Common Coupling. This standard covers Generation Systems that are interconnected with the Area EPS’s distribution facilities. This standard does not cover Generation Systems that are directly interconnected with the Area EPS’s Transmission System, Contact the Area EPS for their Transmission System interconnection standards. While, this standard provides the technical requirements for interconnecting a Generation System with a typical radial distribution system, it is important to note that there are some unique Area EPS, which have special interconnection needs. One example of a unique Area EPS would be one operated as a “networked” system. This standard does not cover the additional special requirements of those systems. The Interconnection Customer must contact the Owner/operator of the Area EPS with which the interconnection is intended, to make sure that the Generation System is not proposed to be interconnected with a unique Area EPS. If the planned interconnection is with a unique Area EPS, the Interconnection Customer must obtain the additional requirements for interconnecting with the Area EPS. The Area EPS operator has the right to limit the maximum size of any Generation System or number of Generation Systems that, may want to interconnect, if the Generation System would reduce the reliability to the other customers connected to the Area EPS. This standard only covers the technical requirements and does not cover the interconnection process from the planning of a project through approval and construction. Please read the companion document “State of Minnesota Interconnection Process for Distributed Generation Systems” for the description of the procedure to follow and a generic version of the forms to submit. It is important to also get copies of the Area EPS’s tariff’s concerning generation interconnection which will include rates, costs and standard interconnection agreements. The earlier the Interconnection Customer gets the Area EPS operator involved in the planning and design of the Generation System interconnection the smoother the process will go.
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A) Definitions The definitions defined in the “IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems” (1547 Draft Ver. 11) apply to this document as well. The following definitions are in addition to the ones defined in IEEE 1547, or are repeated from the IEEE 1547 standard. i) “Area EPS” an electric power system (EPS) that serves Local EPS’s. Note. Typically, an Area EPS has primary access to public rights-of-way, priority crossing of property boundaries, etc. ii) “Generation” any device producing electrical energy, i.e., rotating generators driven by wind, steam turbines, internal combustion engines, hydraulic turbines, solar, fuel cells, etc.; or any other electric producing device, including energy storage technologies. iii) “Generation System” the interconnected Distributed Generation(s), controls, relays, switches, breakers, transformers, inverters and associated wiring and cables, up to the Point of Common Coupling. iv) “Interconnection Customer” the party or parties who are responsible for meeting the requirements of this standard. This could be the Generation System applicant, installer, designer, owner or operator. v) “Local EPS” an electric power system (EPS) contained entirely within a single premises or group of premises. vi) “Point of Common Coupling” the point where the Local EPS is connected to an Area EPS. vii) “Transmission System”, are those facilities as defined by using the guidelines established by the Minnesota State Public Utilities Commission; “In the Matter of Developing Statewide Jurisdictional Boundary Guidelines for Functionally Separating Interstate Transmission from Generation and Local Distribution Functions” Docket No. E-015/M-99-1002. viii) “Type-Certified” Generation paralleling equipment that is listed by an OSHA listed national testing laboratory as having met the applicable type testing requirement of UL 1741. At the time is document was prepared this was the only national standard available for certification of generation transfer switch equipment. This definition does not preclude other forms of type- certification if agreeable to the Area EPS operator.
B) Interconnection
Requirements Goals
This standard defines the minimum technical requirements for the implementation of the electrical interconnection between the Generation System and the Area EPS. It does not define the overall requirements for the Generation System. The requirements in this standard are intended to achieve the following: i) Ensure the safety of utility personnel and contractors working on the electrical power system. ii) Ensure the safety of utility customers and the general public. iii) Protect and minimize the possible damage to the electrical power system and other customer’s property. iv) Ensure proper operation to minimize adverse operating conditions on the electrical power Interconnection Process for Distributed Generation 91 Systems
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C) Protection The Generation System and Point of Common Coupling shall be designed with proper protective devices to promptly and automatically disconnect the Generation from the Area EPS in the event of a fault or other system abnormality. The type of protection required will be determined by: i) Size and type of the generating equipment. ii) The method of connecting and disconnecting the Generation System from the electrical power system. iii) The location of generating equipment on the Area EPS.
D) Area
EPS Modifications
Depending upon the match between the Generation System, the Area EPS and how the Generation System is operated, certain modifications and/or additions may be required to the existing Area EPS with the addition of the Generation System. To the extent possible, this standard describes the modifications which could be necessary to the Area EPS for different types of Generation Systems. For some unique interconnections, additional and/or different protective devices, system modifications and/or additions will be required by the Area EPS operator; in these cases the Area EPS operator will provide the final determination of the required modifications and/or additions. If any special requirements are necessary they will be identified by the Area EPS operator during the application review process.
E) Generation
System Protection
The Interconnection Customer is solely responsible for providing protection for the Generation System. Protection systems required in this standard, are structured to protect the Area EPS’s electrical power system and the public. The Generation System Protection is not provided for in this standard. Additional protection equipment may be required to ensure proper operation for the Generation System. This is especially true while operating disconnected, from the Area EPS. The Area EPS does not assume responsibility for protection of the Generation System equipment or of any portion Local EPS.
F) Electrical
Code Compliance
Interconnection Customer shall be responsible for complying with all applicable local, independent, state and federal codes such as building codes, National Electric Code (NEC), National Electrical Safety Code (NESC) and noise and emissions standards. As required by Minnesota State law, the Area EPS will require proof of complying with the National Electrical Code before the interconnection is made, through installation approval by an electrical inspector recognized by the Minnesota State Board of Electricity. The Interconnection Customer’s Generation System and installation shall comply with latest revisions of the ANSI/IEEE standards applicable to the installation, especially IEEE 1547; “Standard for Interconnecting Distributed Resources with Electric Power Systems”. See the reference section in this document for a partial list of the standards which apply to the generation installations covered by this standard.
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2. References The following standards shall be used in conjunction with this standard. When the stated version of the following standards is superseded by an approved revision then that revision shall apply.
IEEE Std 100-2000, “IEEE Standard Dictionary of Electrical and Electronic Terms” IEEE Std 519-1992, “IEEE Recommended Practices and Requirements for Harmonic Control in Electric Power Systems” IEEE Std 929-2000,”IEEE Recommended Practice for Utility Interface of Photovoltaic (PV) Systems”. IEEE Std 1547, “IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems” IEEE Std C37.90.1-1989 (1995), “IEEE Standard Surge Withstand Capability (SEC) Tests for Protective Relays and Relay Systems”. IEEE Std C37.90.2 (1995), “IEEE Standard Withstand Capability of Relay Systems to Radiated Electromagnetic Interference from Transceivers”. IEEE Std C62.41.2-2002, “IEEE Recommended Practice on Characterization of Surges in Low Voltage (1000V and Less) AC Power Circuits” IEEE Std C62.42-1992 (2002), “IEEE Recommended Practice on Surge Testing for Equipment Connected to Low Voltage (1000V and less) AC Power Circuits” ANSI C84.1-1995,”Electric Power Systems and Equipment – Voltage Ratings (60 Hertz)” ANSI/IEEE 446-1995, “Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications”. ANSI/IEEE Standard 142-1991, “IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems – Green Book”, UL Std. 1741 “Inverters, Converters, and Controllers for use in Independent Power Systems” NEC – “National Electrical Code”, National Fire Protection Association (NFPA), NFPA-70-2002. NESC – “National Electrical Safety Code”. ANSI C2-2000, Published by the Institute of Electrical and Electronics Engineers, Inc.
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3. Types
of Interconnections
A) The manner in which the Generation System is connected to and disconnected from the Area EPS can vary. Most transfer systems normally operate using one of the following five methods of transferring the load from the Area EPS to the Generation System. B) If a transfer system is installed which has a user accessible selection of several transfer modes, the transfer mode that has the greatest protection requirements will establish the protection requirements for that transfer system. i) Open Transition (Break-Before-Make) Transfer Switch – With this transfer switch, the load to be supplied from the Distributed Generation is first disconnected from the Area EPS and then connected to the Generation. This transfer can be relatively quick, but voltage and frequency excursions are to be expected during transfer. Computer equipment and other sensitive equipment will shut down and reset. The transfer switch typically consists of a standard UL approved transfer switch with mechanical interlocks between the two source contactors that drop the Area EPS source before the Distributed Generation is connected to supply the load. (1) To qualify as an Open Transition switch and the limited protective requirements, mechanical interlocks are required between the two source contacts. This is required to ensure that one of the contacts is always open and the Generation System is never operated in parallel with the Area EPS. If the mechanical interlock is not present, the protection requirements are as if the switch is a closed transition switch. (2) As a practical point of application, this type of transfer switch is typically used for loads less than 500kW. This is due to possible voltage flicker problems created on the Area EPS, when the load is removed from or returned to the Area EPS source. Depending up the Area EPS’s stiffness this level may be larger or smaller than the 500kW level. (3) Figure 1 at the end of this document provides a typical one-line of this type of installation. ii) Quick Open Transition (Break-Before-Make) Transfer Switch – The load to be supplied from the Distributed Generation is first disconnected from the Area EPS and then connected to the Distributed Generation, similar to the open transition. However, this transition is typically much faster (under 500 ms) than the conventional open transition transfer operation. Voltage and frequency excursions will still occur, but some computer equipment and other sensitive equipment will typically not be affected with a properly designed system. The transfer switch consists of a standard UL approved transfer switch, with mechanical interlocks between the two source contacts that drop the Area EPS source before the Distributed Generation is connected to supply the load. (1) Mechanical interlocks are required between the two source contacts to ensure that one of the contacts is always open. If the mechanical interlock is not present, the protection requirements are as if the switch is a closed transition switch (2) As a practical point of application this type of transfer switch is typically used for loads less than 500kW. This is due to possible voltage flicker problems created on the Area EPS, when the load is removed from or returned to the Area EPS source. Depending up the Area EPS’s stiffness this level may be larger or smaller than the 500kW level. (3) Figure 2 at the end of this document provides a typical one-line of this type of installation and shows the required protective elements. Interconnection Process for Distributed Generation 94 Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
iii) Closed Transition (Make-Before-Break) Transfer Switch – The Distributed Generation is synchronized with the Area EPS prior to the transfer occurring. The transfer switch then parallels with the Area EPS for a short time (100 msec. or less) and then the Generation System and load is disconnected from the Area EPS. This transfer is less disruptive than the Quick Open Transition because it allows the Distributed Generation a brief time to pick up the load before the support of the Area EPS is lost. With this type of transfer, the load is always being supplied by the Area EPS or the Distributed Generation. (1) As a practical point of application this type of transfer switch is typically used for loads less than 500kW. This is due to possible voltage flicker problems created on the Area EPS, when the load is removed from or returned to the Area EPS source. Depending up the Area EPS’s stiffness this level may be larger or smaller than the 500kW level. (2) Figure 2 at the end of this document provides a typical one-line of this type of installation and shows the required protective elements. The closed transition switch must include a separate parallel time limit relay, which is not part of the generation control PLC and trips the generation from the system for a failure of the transfer switch and/or the transfer switch controls. iv) Soft Loading Transfer Switch (1) With Limited Parallel Operation – The Distributed Generation is paralleled with the Area EPS for a limited amount of time (generally less than 1-2 minutes) to gradually transfer the load from the Area EPS to the Generation System. This minimizes the voltage and frequency problems, by softly loading and unloading the Generation System. (a) The maximum parallel operation shall be controlled, via a parallel timing limit relay (62PL). This parallel time limit relay shall be a separate relay and not part of the generation control PLC. (b) Protective Relaying is required as described in section 6. (c) Figure 3 at the end of this document provide typical one-line diagrams of this type of installation and show the required protective elements. (2) With Extended Parallel Operation – The Generation System is paralleled with the Area EPS in continuous operation. Special design, coordination and agreements are required before any extended parallel operation will be permitted. The Area EPS interconnection study will identify the issues involved. (a) Any anticipated use in the extended parallel mode requires special agreements and special protection coordination. (b) Protective Relaying is required as described in section 6. (c) Figure 4 at the end of this document provides a typical one-line for this type of interconnection. It must be emphasized that this is a typical installations only and final installations may vary from the examples shown due to transformer connections, breaker configuration, etc. v) Inverter Connection This is a continuous parallel connection with the system. Small Generation Systems may utilize inverters to interface to the Area EPS. Solar, wind and fuel cells are some examples of Generation which typically use inverters to connect to the Area EPS. The design of such inverters shall either contain all necessary protection to prevent unintentional islanding, or the Interconnection Customer shall install conventional protection to affect the same protection. All required protective elements for a soft-loading transfer switch apply to an inverter Interconnection Process for Distributed Generation 95 Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES connection. Figure 5 at the end of this document, shows a typical inverter interconnection. (1) Inverter Certification – Prior to installation, the inverter shall be Type-Certified for interconnection to the electrical power system. The certification will confirm its anti- islanding protection and power quality related levels at the Point of Common Coupling. Also, utility compatibility, electric shock hazard and fire safety are approved through UL listing of the model. Once this Type Certification is completed for that specific model, additional design review of the inverter should not be necessary by the Area EPS operator. (2) For three-phase operation, the inverter control must also be able to detect and separate for the loss of one phase. Larger inverters will still require custom protection settings, which must be calculated and designed to be compatible with the specific Area EPS being interconnected with. (3) A visible disconnect is required for safely isolating the Distributed Generation when connecting with an inverter. The inverter shall not be used as a safety isolation device. (4) When banks of inverter systems are installed at one location, a design review by the Area EPS must be performed to determine any additional protection systems, metering or other needs. The issues will be identified by the Area EPS during the interconnection study process
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4. Interconnection
Issues and Technical Requirements
A) General Requirements - The following requirements apply to all interconnected generating equipment. The Area EPS shall be the source side and the customer’s system shall be the load side in the following interconnection requirements. i) Visible Disconnect - A disconnecting device shall be installed to electrically isolate the Area EPS from the Generation System. The only exception for the installation of a visible disconnect is if the generation is interconnected via a mechanically interlocked open transfer switch and installed per the NEC (702.6) “so as to prevent the inadvertent interconnection of normal and alternate sources of supply in any operation of the transfer equipment.” The visible disconnect shall provide a visible air gap between Interconnection Customer’s Generation and the Area EPS in order to establish the safety isolation required for work on the Area EPS. This disconnecting device shall be readily accessible 24 hours per day by the Area EPS field personnel and shall be capable of padlocking by the Area EPS field personnel. The disconnecting device shall be lockable in the open position. The visible disconnect shall be a UL approved or National Electrical Manufacture’s Association approved, manual safety disconnect switch of adequate ampere capacity. The visible disconnect shall not open the neutral when the switch is open. A draw-out type circuit breaker can be used as a visual open. The visible disconnect shall be labeled, as required by the Area EPS Operator to inform the Area EPS field personnel. ii) Energization of Equipment by Generation System – The Generation System shall not energize a deenergized Area EPS. The Interconnection Customer shall install the necessary padlocking (lockable) devices on equipment to prevent the energization of a de-energized electrical power system. Lock out relays shall automatically block the closing of breakers or transfer switches on to a de-energized Area EPS. iii) Power Factor - The power factor of the Generation System and connected load shall be as follows; (1) Inverter Based interconnections – shall operate at a power factor of no less than 90%.at the inverter terminals. (2) Limited Parallel Generation Systems, such as closed transfer or soft-loading transfer systems shall operate at a power factor of no less than 90%, during the period when the Generation System is parallel with the Area EPS, as measured at the Point of Common Coupling. (3) Extended Parallel Generation Systems shall be designed to be capable of operating between 90% lagging and 95% leading. These Generation Systems shall normally operate near unity power factor (+/-98%) or as mutually agreed between the Area EPS operator and the Interconnection Customer. iv) Grounding Issues (1) Grounding of sufficient size to handle the maximum available ground fault current shall be designed and installed to limit step and touch potentials to safe levels as set forth in “IEEE Guide for Safety in AC Substation Grounding”, ANSI/IEEE Standard 80. (2) It is the responsibility of the Interconnection Customer to provide the required grounding for the Generation System. A good standard for this is the IEEE Std. 142-1991 Interconnection Process for Distributed Generation 97 Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES “Grounding of Industrial and Commercial Power Systems” (3) All electrical equipment shall be grounded in accordance with local, state and federal electrical and safety codes and applicable standards v) Sales to Area EPS or other parties – Transportation of energy on the Transmission system is regulated by the area reliability council and FERC. Those contractual requirements are not included in this standard. The Area EPS will provide these additional contractual requirements during the interconnection approval process. B) For Inverter based, closed transfer and soft loading interconnections - The following additional requirements apply: i) Fault and Line Clearing - The Generation System shall be removed from the Area EPS for any faults, or outages occurring on the electrical circuit serving the Generation System ii) Operating Limits in order to minimize objectionable and adverse operating conditions on the electric service provided to other customers connected to the Area EPS, the Generation System shall meet the Voltage, Frequency, Harmonic and Flicker operating criteria as defined in the IEEE 1547 standard during periods when the Generation System is operated in parallel with the Area EPS. If the Generation System creates voltage changes greater than 4% on the Area EPS, it is the responsibility of the Interconnection Customer to correct these voltage sag/swell problems caused by the operation of the Generation System. If the operation of the interconnected Generation System causes flicker, which causes problems for others customer’s interconnected to the Area EPS, the Interconnection Customer is responsible for correcting the problem. iii) Flicker - The operation of Generation System is not allowed to produce excessive flicker to adjacent customers. See the IEEE 1547 standard for a more complete discussion on this requirement. The stiffer the Area EPS, the larger a block load change that it will be able to handle. For any of the transfer systems the Area EPS voltage shall not drop or rise greater than 4% when the load is added or removed from the Area EPS. It is important to note, that if another interconnected customer complains about the voltage change caused by the Generation System, even if the voltage change is below the 4% level, it is the Interconnection Customer’s responsibility to correct or pay for correcting the problem. Utility experience has shown that customers have seldom objected to instantaneous voltage changes of less than 2% on the Area EPS, so most Area EPS operators use a 2% design criteria iv) Interference - The Interconnection Customer shall disconnect the Distributed Generation from the Area EPS if the Distributed Generation causes radio, television or electrical service interference to other customers, via the EPS or interference with the operation of Area EPS. The Interconnection Customer shall either effect repairs to the Generation System or reimburse the Area EPS Operator for the cost of any required Area EPS modifications due to the interference.
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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES v) Synchronization of Customer Generation(1) An automatic synchronizer with synch-check relaying is required for unattended automatic quick open transition, closed transition or soft loading transfer systems. (2) To prevent unnecessary voltage fluctuations on the Area EPS, it is required that the synchronizing equipment be capable of closing the Distributed Generation into the Area EPS within the limits defined in IEEE 1547. Actual settings shall be determined by the Registered Professional Engineer establishing the protective settings for the installation. (3) Unintended Islanding – Under certain conditions with extended parallel operation, it would be possible for a part of the Area EPS to be disconnected from the rest of the Area EPS and have the Generation System continue to operate and provide power to a portion of the isolated circuit. This condition is called “islanding”. It is not possible to successfully reconnect the energized isolated circuit to the rest of the Area EPS since there are no synchronizing controls associated with all of the possible locations of disconnection. Therefore, it is a requirement that the Generation System be automatically disconnected from the Area EPS immediately by protective relays for any condition that would cause the Area EPS to be de-energized. The Generation System must either isolate with the customer’s load or trip. The Generation System must also be blocked from closing back into the Area EPS until the Area EPS is reenergized and the Area EPS voltage is within Range B of ANSI C84.1 Table 1 for a minimum of 1 minute. Depending upon the size of the Generation System it may be necessary to install direct transfer trip equipment from the Area EPS source(s) to remotely trip the generation interconnection to prevent islanding for certain conditions vi) Disconnection – the Area EPS operator may refuse to connect or may disconnect a Generation System from the Area EPS under the following conditions: (1) Lack of approved Standard Application Form and Standard Interconnection Agreement. (2) Termination of interconnection by mutual agreement. (3) Non-Compliance with the technical or contractual requirements. (4) System Emergency or for imminent danger to the public or Area EPS personnel (Safety). (5) Routine maintenance, repairs and modifications to the Area EPS. The Area EPS operator shall coordinate planned outages with the Interconnection Customer to the extent possible.
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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
5. Generation
Metering, Monitoring and Control
Metering, Monitoring and Control – Depending upon the method of interconnection and the size of the Generation System, there are different metering, monitoring and control requirements Table 5A is a table summarizing the metering, monitoring and control requirements. Due to the variation in Generation Systems and Area EPS operational needs, the requirements for metering, monitoring and control listed in this document are the expected maximum requirements that the Area EPS will apply to the Generation System. It is important to note that for some Generation System installations the Area EPS may wave some of the requirements of this section if they are not needed. An example of this is with rural or low capacity feeders which require more monitoring then larger capacity, typically urban feeders. Another factor which will affect the metering, monitoring and control requirements will be the tariff under which the Interconnection Customer is supplied by the Area EPS. Table 5A has been written to cover most application, but some Area EPS tariffs may have greater or less metering, monitoring and control requirements then, as shown in Table 5A. .
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TABLE 5A Metering, Monitoring and Control Requirements Generation System Capacity at Point of Common Coupling ≤ 40 kW with all sales to Area EPS >40 kW
Metering Bi-Directional metering at the point of common coupling Determined by engineering study
Interconnection Process for Distributed Generation 101Systems
Generation Remote Monitoring
Generation Remote Control
None Required
None Required
Determined by engineering study
Determined by engineering study
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
A) Metering i) As shown in Table 5A the requirements for metering will depend up on the type of generation and the type of interconnection. For most installations, the requirement is a single point of metering at the Point of Common Coupling. The Area EPS Operator will install a special meter that is capable of measuring and recording energy flow in both directions, for three phase installations or two detented meters wired in series, for single phase installations. A dedicated - direct dial phone line may be required to be supplied to the meter for the Area EPS’s use to read the metering. Some monitoring may be done through the meter and the dedicated – direct dial phone line, so in many installations the remote monitoring and the meter reading can be done using the same dial-up phone line. ii) Depending upon which tariff the Generation System and/or customer’s load is being supplied under, additional metering requirements may result. Contact the Area EPS for tariff requirements. In some cases, the direct dial-phone line requirement may be waived by the Area EPS for smaller Generation Systems. iii) All Area EPS’s revenue meters shall be supplied, owned and maintained by the Area EPS. All voltage transformers (VT) and current transformers (CT), used for revenue metering shall be approved and/or supplied by the Area EPS. Area EPS’s standard practices for instrument transformer location and wiring shall be followed for the revenue metering. iv) For Generation Systems that sell power and are greater than 40kW in size, separate metering of the generation and of the load is required. A single meter recording the power flow at the Point of Common Coupling for both the Generation and the load is not allowed by the rules under which the area transmission system is operated. The Area EPS is required to report to the regional reliability council (MAPP) the total peak load requirements and is also required to own or have contracted for, accredited generation capacity of 115% of the experienced peak load level for each month of the year. Failure to meet this requirement results in a large monetary penalty for the Area EPS operator. v) For Generation Systems which are less then 40kW in rated capacity and are qualified facilities under PURPA (Public Utilities Regulatory Power Act – Federal Gov. 1978), net metering is allowed and provides the generation system the ability to back feed the Area EPS at some times and bank that energy for use at other times. Some of the qualified facilities under PURPA are solar, wind, hydro, and biomass. For these net-metered installations, the Area EPS may use a single meter to record the bidirectional flow or the Area EPS Operator may elect to use two detented meters, each one to record the flow of energy in one direction. B) Monitoring (SCADA) is required as shown in table 5A. The need for monitoring is based on the need of the system control center to have the information necessary for the reliable operation of the Area EPS’s. This remote monitoring is especially important during periods of abnormal and emergency operation. The difference in Table 5A between remote monitoring and SCADA is that SCADA typically is a system that is in continuous communication with a central computer and provides updated values and status, to the Area EPS operator, within several seconds of the changes in the field. Remote monitoring on the other hand will tend to provide updated values and status within minutes of the change in state of the field. Remote monitoring is typically less expensive to install and operate. i) Where Remote Monitoring or SCADA is required, as shown in Table 5A, the following monitored and control points are required: (1) Real and reactive power flow for each Generation System (kW and kVAR). Only required if separate metering of the Generation and the load is required, otherwise #4 monitored at the point of Common Coupling will meet the requirements. Interconnection Process for Distributed Generation 102Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES (2) Phase voltage representative of the Area EPS’s service to the facility. (3) Status (open/close) of Distributed Generation and interconnection breaker(s) or if transfer switch is used, status of transfer switch(s). (4) Customer load from Area EPS service (kW and kVAR). (5) Control of interconnection breaker - if required by the Area EPS operator. When telemetry is required, the Interconnection Customer must provide the communications medium to the Area EPS’s Control Center. This could be radio, dedicated phone circuit or other form of communication. If a telephone circuit is used, the Interconnection Customer must also provide the telephone circuit protection. The Interconnection Customer shall coordinate the RTU (remote terminal unit) addition with the Area EPS. The Area EPS may require a specific RTU and/or protocol to match their SCADA or remote monitoring system.
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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
6. Protective
Devices and Systems
A) Protective devices required to permit safe and proper operation of the Area EPS while interconnected with customer’s Generation System are shown in the figures at the end of this document. In general, an increased degree of protection is required for increased Distributed Generation size. This is due to the greater magnitude of short circuit currents and the potential impact to system stability from these installations. Medium and large installations require more sensitive and faster protection to minimize damage and ensure safety. If a transfer system is installed which has a user accessible selection of several transfer modes, the transfer mode which has the greatest protection requirements will establish the protection requirements for that transfer system. The Interconnection Customer shall provide protective devices and systems to detect the Voltage, Frequency, Harmonic and Flicker levels as defined in the IEEE 1547 standard during periods when the Generation System is operated in parallel with the Area EPS. The Interconnection Customer shall be responsible for the purchase, installation, and maintenance of these devices. Discussion on the requirements for these protective devices and systems follows: i) Relay settings (1) If the Generation System is utilizing a Type-Certified system, such as a UL listed inverter a Professional Electrical Engineer is not required to review and approve the design of the interconnecting system. If the Generation System interconnecting device is not Type- Certified or if the Type-Certified Generation System interconnecting device has additional design modifications made, the Generation System control, the protective system, and the interconnecting device(s) shall be reviewed and approved by a Professional Electrical Engineer, registered in the State of Minnesota. (2) A copy of the proposed protective relay settings shall be supplied to the Area EPS operator for review and approval, to ensure proper coordination between the generation system and the Area EPS. ii) Relays (1) All equipment providing relaying functions shall meet or exceed ANSI/IEEE Standards for protective relays, i.e., C37.90, C37.90.1 and C37.90.2. (2) Required relays that are not “draw-out” cased relays shall have test plugs or test switches installed to permit field testing and maintenance of the relay without unwiring or disassembling the equipment. Inverter based protection is excluded from this requirement for Generation Systems <40kW at the Point of Common Coupling. (3) Three phase interconnections shall utilize three phase power relays, which monitor all three phases of voltage and current, unless so noted in the appendix one-lines. (4) All relays shall be equipped with setting limit ranges at least as wide as specified in IEEE 1547 , and meet other requirements as specified in the Area EPS interconnect study. Setting limit ranges are not to be confused with the actual relay settings required for the proper operation of the installation. At a minimum, all protective systems shall meet the requirements established in IEEE 1547. (a) Over-current relays (IEEE Device 50/51 or 50/51V) shall operate to trip the protecting breaker at a level to ensure protection of the equipment and at a speed to allow Interconnection Process for Distributed Generation 104Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES proper coordination with other protective devices. For example, the over-current relay monitoring the interconnection breaker shall operate fast enough for a fault on the customer’s equipment, so that no protective devices will operate on the Area EPS. 51V is a voltage restrained or controlled over-current relay and may be required to provide proper coordination with the Area EPS. (b) Over-voltage relays (IEEE Device 59) shall operate to trip the Distributed Generation per the requirements of IEEE 1547. (c) Under-voltage relays (IEEE Device 27) shall operate to trip the Distributed Generation per the requirements of IEEE 1547 (d) Over-frequency relays (IEEE Device 81O) shall operate to trip the Distributed Generation offline per the requirements of IEEE 1547. (e) Under-frequency relay (IEEE Device 81U) shall operate to trip the Distributed Generation offline per the requirements of IEEE 1547. For Generation Systems with an aggregate capacity greater then 30kW, the Distribution Generation shall trip off-line when the frequency drops below 57.0-59.8 Hz. typically this is set at 59.5 Hz, with a trip time of 0.16 seconds, but coordination with the Area EPS is required for this setting. The Area EPS will provide the reference frequency of 60 Hz. The Distributed Generation control system must be used to match this reference. The protective relaying in the interconnection system will be expected to maintain the frequency of the output of the Generation. (f) Reverse power relays (IEEE Device 32) (power flowing from the Generation System to the Area EPS) shall operate to trip the Distributed Generation off-line for a power flow to the system with a maximum time delay of 2.0 seconds. (g) Lockout Relay (IEEE Device 86) is a mechanically locking device which is wired into the close circuit of a breaker or switch and when tripped will prevent any close signal from closing that device. This relay requires that a person manually resets the lockout relay before that device can be reclosed. These relays are used to ensure that a denergized system is not reenergized by automatic control action, and prevents a failed control from auto-reclosing an open breaker or switch. (h) Transfer Trip – All Generation Systems are required to disconnect from the Area EPS when the Area EPS is disconnected from its source, to avoid unintentional islanding. With larger Generation Systems, which remain in parallel with the Area EPS, a transfer trip system may be required to sense the loss of the Area EPS source. When the Area EPS source is lost, a signal is sent to the Generation System to separate the Generation from the Area EPS. The size of the Generation System vs the capacity and minimum loading on the feeder will dictate the need for transfer trip installation. The Area EPS interconnection study will identify the specific requirements. If multiple Area EPS sources are available or multiple points of sectionalizing on the Area EPS, then more than one transfer trip system may be required. Area EPS interconnection study will identify the specific requirements. For some installations the alternate Area EPS source(s) may not be utilized except in rare occasions. If this is the situation, the Interconnection Customer may elect to have the Generation System locked out when the alternate source(s) are utilized, if agreeable to the Area EPS operator. (i) Parallel limit timing relay (IEEE Device 62PL) set at a maximum of 120 seconds for Interconnection Process for Distributed Generation 105Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES soft transfer installations and set no longer then 100ms for quick transfer installations, shall trip the Distributed Generation circuit breaker on limited parallel interconnection systems. Power for the 62 PL relay must be independent of the transfer switch control power. The 62PL timing must be an independent device from the transfer control and shall not be part of the generation PLC or other control system. TABLE 6A SUMMARY OF RELAYING REQUIREMENTS Type of Interconnection
Overcurrent (50/51)
Voltage (27/59)
Frequency (81 0/U)
Reverse Power (32)
Lockout (86)
Parallel Limit Timer
SyncCheck (25)
Transfer Trip
≤40 kW
Yes
>40 kW
Determined Determined by Determined by Determined by Determined by Determined by Determined Determined by by Engineering Engineering Study Engineering Engineering Engineering by Engineering Engineering Study Study Study Study Engineering Study Study Study
Yes
Yes
Interconnection Process for Distributed Generation 106Systems
Yes
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
7. Agreements A) Interconnection Agreement – This agreement is required for all Generation Systems that parallel with the Area EPS. Each Area EPS’s tariffs contain standard interconnection agreements. There are different interconnection agreements depending upon the size and type of Generation System. This agreement contains the terms and conditions upon which the Generation System is to be connected, constructed and maintained, when operated in parallel with the Area EPS. Some of the issues covered in the interconnection agreement are as follows; i) Construction Process ii) Testing Requirements iii) Maintenance Requirements iv) Firm Operating Requirements such as Power Factor v) Access requirements for the Area EPS personnel vi) Disconnection of the Generation System (Emergency and Non-emergency) vii) Term of Agreement viii) Insurance Requirements ix) Dispute Resolution Procedures B) Operating Agreement – For Generation Systems that normally operate in parallel with the Area EPS, an agreement separate from the interconnection agreement, called the “operating agreement”, is usually created. This agreement is created for the benefit of both the Interconnection Customer and the Area EPS operator and will be agreed to between the Parties. This agreement will be dynamic and is intended to be updated and reviewed annually. For some smaller systems, the operating agreement can simply be a letter agreement for larger and more intergraded Generation Systems the operating agreement will tend to be more involved and more formal. The operating agreement covers items that are necessary for the reliable operation of the Local and Area EPS. The items typically included in the operating agreement are as follows; i) Emergency and normal contact information for both the Area EPS operations center and for the Interconnection Customer ii) Procedures for periodic Generation System test runs. iii) Procedures for maintenance on the Area EPS that affect the Generation System. iv) Emergency Generation Operation Procedures
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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
8. Testing Requirements A) Pre-Certification of equipment The most important part of the process to interconnect generation with Local and Area EPS’s is safety. One of the key components of ensuring the safety of the public and employees is to ensure that the design and implementation of the elements connected to the electrical power system operate as required. To meet this goal, all of the electrical wiring in a business or residence, is required by the State of Minnesota to be listed by a recognized testing and certification laboratory, for its intended purpose. Typically we see this as “UL” listed. Since Generation Systems have tended to be uniquely designed for each installation they have been designed and approved by Professional Engineers. As the number of Generation Systems installed increase, vendors are working towards creating equipment packages which can be tested in the factory and then will only require limited field testing. This will allow us to move towards “plug and play” installations. For this reason, this standard recognizes the efficiency of “pre-certification” of Generation System equipment packages that will help streamline the design and installation process. An equipment package shall be considered certified for interconnected operation if it has been submitted by a manufacture, tested and listed by a nationally recognized testing and certification laboratory (NRTL) for continuous utility interactive operation in compliance with the applicable codes and standards. Presently generation paralleling equipment that is listed by a nationally recognized testing laboratory as having met the applicable type-testing requirements of UL 1741 and IEEE 929, shall be acceptable for interconnection without additional protection system requirements. An “equipment package” shall include all interface components including switchgear, inverters, or other interface devices and may include an integrated generator or electric source. If the equipment package has been tested and listed as an integrated package which includes a generator or other electric source, it shall not require further design review, testing or additional equipment to meet the certification requirements for interconnection. If the equipment package includes only the interface components (switchgear, inverters, or other interface devices), then the Interconnection Customer shall show that the generator or other electric source being utilized with the equipment package is compatible with the equipment package and consistent with the testing and listing specified for the package. Provided the generator or electric source combined with the equipment package is consistent with the testing ad listing performed by the nationally recognized testing and certification laboratory, no further design review, testing or additional equipment shall be required to meet the certification requirements of this interconnection procedure. A certified equipment package does not include equipment provided by the Area EPS. The use of Pre-Certified equipment does not automatically qualify the Interconnection Customer to be interconnected to the Area EPS. An application will still need to be submitted and an interconnection review may still need to be performed, to determine the compatibility of the Generation System with the Area EPS.
B) Pre-Commissioning Tests i) Non-Certified Equipment (1) Protective Relaying and Equipment Related to Islanding (a) Distributed generation that is not Type-Certified (type tested), shall be equipped with protective hardware and/or software designed to prevent the Generation from being connected to a de-energized Area EPS. (b) The Generation may not close into a de-energized Area EPS and protection provided Interconnection Process for Distributed Generation 108Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES to prevent this from occurring. It is the Interconnection Customer’s responsibility to provide a final design and to install the protective measures required by the Area EPS. The Area EPS will review and approve the design, the types of relays specified, and the installation. Mutually agreed upon exceptions may at times be necessary and desirable. It is strongly recommended that the Interconnection Customer obtain Area EPS written approval prior to ordering protective equipment for parallel operation. The Interconnection Customer will own these protective measures installed at their facility. (c) The Interconnection Customer shall obtain prior approval from the Area EPS for any revisions to the specified relay calibrations.
C) Commissioning Testing The following tests shall be completed by the Interconnection Customer. All of the required tests in each section shall be completed prior to moving on to the next section of tests. The Area EPS operator has the right to witness all field testing and to review all records prior to allowing the system to be made ready for normal operation The Area EPS shall be notified, with sufficient lead time to allow the opportunity for Area EPS personnel to witness any or all of the testing. i) Pre-testing The following tests are required to be completed on the Generation System prior to energization by the Generator or the Area EPS. Some of these tests may be completed in the factory if no additional wiring or connections were made to that component. These tests are marked with a “*” (1) Grounding shall be verified to ensure that it complies with this standard, the NESC and the NEC. (2) * CT’s (Current Transformers) and VT’s (Voltage Transformers) used for monitoring and protection, shall be tested to ensure correct polarity, ratio and wiring (3) CT’s shall be visually inspected to ensure that all grounding and shorting connections have been removed where required. (4) Breaker / Switch tests – Verify that the breaker or switch cannot be operated with interlocks in place or that the breaker or switch cannot be automatically operated when in manual mode. Various Generation Systems have different interlocks, local or manual modes etc. The intent of this section is to ensure that the breaker or switches controls are operating properly. (5) * Relay Tests – All Protective relays shall be calibrated and tested to ensure the correct operation of the protective element. Documentation of all relay calibration tests and settings shall be furnished to the Area EPS operator. (6) Trip Checks - Protective relaying shall functionally tested to ensure the correct operation of the complete system. Functional testing requires that the complete system is operated by the injection of current and/or voltage to trigger the relay element and proving that the relay element trips the required breaker, lockout relay or provides the correct signal to the next control element. Trip circuits shall be proven through the entire scheme (including breaker trip) For factory assembled systems, such as inverters the setting of the protective elements may occur at the factory. This section requires that the complete system including the wiring and the device being tripped or activated is proven to be in working condition through the injection of current and/or voltage.
Interconnection Process for Distributed Generation 109Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES (7) Remote Control, SCADA and Remote Monitoring tests – All remote control functions and remote monitoring points shall be verified operational. In some cases, it may not be possible to verify all of the analog values prior to energization. Where appropriate, those points may be verified during the energization process (8) Phase Tests – the Interconnection Customer shall work with the Area EPS operator to complete the phase test to ensure proper phase rotation of the Generation and wiring. (9) Synchronizing test – The following tests shall be done across an open switch or racked out breaker. The switch or breaker shall be in a position that it is incapable of closing between the Generation System and the Area EPS for this test. This test shall demonstrate that at the moment of the paralleling-device closure, the frequency, voltage and phase angle are within the required ranges, stated in IEEE 1547. This test shall also demonstrate that is any of the parameters are outside of the ranges stated; the paralleling-device shall not close. For inverter-based interconnected systems this test may not be required unless the inverter creates fundamental voltages before the paralleling device is closed.
ii) On-Line Commissioning Test – the following tests will proceed once the Generation System has completed Pre-testing and the results have been reviewed and approved by the Area EPS operator. For smaller Generation Systems the Area EPS may have a set of standard interconnection tests that will be required. On larger and more complex Generation Systems the Interconnection Customer and the Area EPS operator will get together to develop the required testing procedure. All on-line commissioning tests shall be based on written test procedures agreed to between the Area EPS operator and the Interconnection Customer. Generation System functionally shall be verified for specific interconnections as follows: (1) Anti-Islanding Test – For Generation Systems that parallel with the utility for longer than 100msec. (a) The Generation System shall be started and connected in parallel with the Area EPS source (b) The Area EPS source shall be removed by opening a switch, breaker etc. (c) The Generation System shall either separate with the local load or stop generating (d) The device that was opened to remove the Area EPS source shall be closed and the Generation System shall not re-parallel with the Area EPS for at least 5 minutes. iii) Final System Sign-off. (1) To ensure the safety of the public, all interconnected customer owned generation systems which do not utilize a Type-Certified system shall be certified as ready to operate by a Professional Electrical Engineer registered in the State of Minnesota, prior to the installation being considered ready for commercial use. iv) Periodic Testing and Record Keeping
Interconnection Process for Distributed Generation 110Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES (1) Any time the interface hardware or software, including protective relaying and generation control systems are replaced and/or modified, the Area EPS operator shall be notified. This notification shall, if possible, be with sufficient warning so that the Area EPS personnel can be involved in the planning for the modification and/or witness the verification testing. Verification testing shall be completed on the replaced and/or modified equipment and systems. The involvement of the Area EPS personnel will depend upon the complexity of the Generation System and the component being replaced and/or modified. Since the Interconnection Customer and the Area EPS operator are now operating an interconnected system. It is important for each to communicate changes in operation, procedures and/or equipment to ensure the safety and reliability of the Local and Area EPSs. (2) All interconnection-related protection systems shall be periodically tested and maintained, by the Interconnection Customer, at intervals specified by the manufacture or system integrator. These intervals shall not exceed 5 years. Periodic test reports and a log of inspections shall be maintained, by the Interconnection Customer and made available to the Area EPS operator upon request. The Area EPS operator shall be notified prior to the period testing of the protective systems, so that Area EPS personnel may witness the testing if so desired. (a) Verification of inverter connected system rated 15kVA and below may be completed as follows; The Interconnection Customer shall operate the load break disconnect switch and verify the Generator automatically shuts down and does not restart for at least 5 minutes after the switch is close (b) Any system that depends upon a battery for trip/protection power shall be checked and logged once per month for proper voltage. Once every four years the battery(s) must be either replaced or a discharge test performed. Longer intervals are possible through the use of “station class batteries” and Area EPS operator approval.
Interconnection Process for Distributed Generation 111Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
Interconnection Process for Distributed Generation 112Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
Interconnection Process for Distributed Generation 113Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
Interconnection Process for Distributed Generation 114Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
Interconnection Process for Distributed Generation 115Systems
SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
Interconnection Process for Distributed Generation 116Systems
SCHEDULE 4 – PURCHASE INTERRUPTION NOTIFICATION PROCEDURE
Elk River Municipal Utilities (Utility) does not foresee an event necessitating Utility to stop purchasing energy from a Qualifying Facility (QF). However, if such an event occurs, Utility shall notify the QF owner by mail, phone, email or other form of electronic communication approved by the QF owner.
117
SCHEDULE 5 – AVERAGE INCREMENTAL COSTS
GRE - 2018 Avoided Cost Rates (Effective January 1, 2018 - September 30, 2018) Summer Months (May - Oct) On Peak Off Peak All Hours
Energy ($/kWh) 0.03148 0.01801 0.02406
Capacity ($/kWh) 0
Winter Months (Nov - Apr) On Peak Off Peak All Hours
0.02856 0.01974 0.02367
0 0
0.001 0.001 0.001
Annual (Jan - Dec) All Hours
0.02387
0
0.001
0
REC ($/kWh) 0.001 0.001 0.001
MMPA - 2018 Avoided Cost Rates (Effective October 1, 2018 - December, 31, 2018) Summer Months (Jun - Sep) On Peak Off Peak All Hours
Energy ($/kWh) 0.0308 0.0180 0.0239
Capacity ($/kWh) 0 0 0
REC ($/kWh) 0 0 0
Winter Months (Oct - May) On Peak Off Peak All Hours
0.0301 0.0215 0.0255
0 0 0
0 0 0
Annual (Jan - Dec) All Hours
0.0250
0
0
118
UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Theresa Slominski – Finance & Office Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2018 5.1 SUBJECT: Financial Report - December 2017 ACTION REQUESTED: Receive the December 2017 Financial Report DISCUSSION: Electric P&L The Electric Department continues to be ahead of budgeted YTD Net Income. December’s electric kWh sales (from November consumption) are up from the prior year, 11%. For further breakdown: Residential usage is up 28% Small Commercial usage is up 25% Large Commercial usage is up 2% Electric Operating Revenue for December was $2,417,120, 46% above the prior year but 8% below budget. This includes the pro-forma adjustment to show the demand adjustment credit being funded through reserves. This month the adjustment was $37,587, and also this month the pro-forma reversal for the annual amount of $459,747. December’s Operating Revenue would be $2,839,280 without the pro-forma adjustments, which is 15% above prior year without the proforma adjustment. Other Revenue Total is above the prior year by 24% and is 37% above budget YTD. Overall, Total Revenues of $2,623,718 are above prior year by 44% and above prior YTD by 5%. YTD Total Revenues are at the budgeted amount. Without the pro-forma adjustments YTD Total Revenues are above prior YTD by 5%. Purchased Power of $2,150,983 is more than the prior year by 7%, and above budget by 12%. YTD costs are more than prior year by 6%, but are below YTD budget by 1%. Administrative Expenses of $345,369 are 8% below prior year, and 44% above budget. YTD costs are above prior year by 1%, and are at the budgeted amount. The increase over the prior YTD is most notably due to medical and dental insurances, which is $87,042 more than the prior ______________________________________________________________________________ Page 1 of 3 119
YTD or 15%. The increase in medical expense is largely driven by the increase in premium costs. General Expenses of $21,801 are 168% more than the prior year, but are 35% below budget YTD. The main driver causing this variance is that we exhausted the commercial rebates from GRE and self-funded the last part of the year. YTD costs are similar to prior YTD. For expenses, in total they are 3% less than the prior year, but are above prior YTD by 5%, and under budget YTD by 2%. For December 2017, the Electric Department has a Net Loss of $420,711 and YTD Net Income of $1,937,702. This is less than the budgeted monthly Net Income of $22,608 but ahead of the prior year monthly Net Loss of $1,299,605. It is above prior YTD Net Income of $1,888,424, and it is ahead of budgeted YTD Net Income of $988,982. ($433,480 represents net income in 2016 due to the security sale and security income generated in 2016.)
Water P&L The Water Department also continues to be ahead of budgeted YTD Net Income. December gallons of water sold (from November’s usage) are up 10% from the prior year. For further breakdown: Residential use up 11% Commercial use up 9% Water Operating Revenues for December of $129,061 are up from last year by 10% and above budget by 8%. Operating Revenue is 6% above prior YTD, and is 4% above YTD budget. Other Revenues of $41,246 are behind the prior year by 90% due to the Transfer in from City last year, and ahead of prior YTD by 13%. Other Revenues are also ahead of YTD budget by 226%, with the main driver being an increase in WAC Fees of $384,657 from the prior year. Overall, Total Revenues of $170,308 are behind the prior year by 67%, but are ahead of prior YTD by 8%. As previously stated WAC Fees and Transfer in from City are the driving force. YTD Total Revenues are ahead of budget by 35%. Expenses are behind the prior year by 9%, and are under YTD budget by 8%. For December 2017, the Water Department has a Net Loss of $54,265, which is behind last year’s Net Income of $276,250. December YTD Net Profit is $777,657 which is ahead of the prior YTD Net Profit of $595,750, and is significantly ahead of the budgeted YTD Net Loss of $338,406. ATTACHMENTS: Balance Sheet 12.2017
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Summary Electric Statement of Revenues, Expenses and Changes in Net Position 12.2017 Summary Water Statement of Revenues, Expenses and Changes in Net Position 12.2017 Graphs Prior Year and YTD 2017 Detailed Electric Statement of Revenues, Expenses and Changes in Net Position 12.2017 Detailed Water Statement of Revenues, Expenses and Changes in Net Position 12.2017
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ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA COMBINED BALANCE SHEET FOR PERIOD ENDING DECEMBER 2017 ELECTRIC ASSETS CURRENT ASSETS CASH ACCOUNTS RECEIVABLE INVENTORIES PREPAID ITEMS CONSTRUCTION IN PROGRESS TOTAL CURRENT ASSETS
WATER
10,172,412 3,344,113 949,695 192,139 672,161 15,330,520
4,054,100 324,351 16,276 32,575 64,711 4,492,014
997,660 2,587,839 38,884 3,624,383
0 1,171,298 113,824 1,285,122
645,285 3,801,373 2,301,867 37,659,675 9,886,490 54,294,689 (25,640,859) 28,653,831
13,390,006 0 0 22,724,766 1,008,275 37,123,047 (16,438,546) 20,684,501
9,393,794 981,883 0 10,375,676
0 0 0 0
1,519,555
157,271
59,503,966
26,618,908
4,360,926 434,622 708,402 25,000 198,252 720,000 0 6,447,202
199,944 68,371 1,581 0 0 255,000 93,336 618,232
820,608 0 11,609,423 3,749,423
0 0 1,135,284 375,285
TOTAL LONG TERM LIABILITIES
16,179,454
1,510,569
TOTAL LIABILITIES
22,626,656
2,128,801
415,506
41,589
997,660 0 33,526,442 1,937,703 36,461,804
0 0 23,670,861 777,657 24,448,518
59,503,966
26,618,908
RESTRICTED ASSETS BOND RESERVE FUND EMERGENCY RESERVE FUND UNRESTRICTED RESERVE FUND TOTAL RESTRICTED ASSETS FIXED ASSETS PRODUCTION LFG PROJECT TRANSMISSION DISTRIBUTION GENERAL FIXED ASSETS (COST) LESS ACCUMULATED DEPRECIATION TOTAL FIXED ASSETS, NET INTANGIBLE ASSETS POWER AGENCY MEMBERSHIP BUY-IN LOSS OF REVENUE INTANGIBLE LESS ACCUMULATED AMORTIZATION TOTAL INTANGIBLE ASSETS, NET OTHER ASSETS AND DEFERRED OUTFLOWS TOTAL ASSETS LIABILITIES AND FUND EQUITY CURRENT LIABILITIES ACCOUNTS PAYABLE SALARIES AND BENEFITS PAYABLE DUE TO CITY DUE TO OTHER FUNDS NOTES PAYABLE-CURRENT PORTION BONDS PAYABLE-CURRENT PORTION UNEARNED REVENUE TOTAL CURRENT LIABILITIES LONG TERM LIABILITIES LFG PROJECT DUE TO COUNTY BONDS PAYABLE, LESS CURRENT PORTION PENSION LIABILITIES
DEFERRED INFLOWS OF RESOURCES FUND EQUITY CAPITAL ACCOUNT CONST COST CONTRIBUTED CAPITAL RETAINED EARNINGS NET INCOME (LOSS) (THROUGH PREVIOUS MONTH) TOTAL FUND EQUITY TOTAL LIABILITIES & FUND EQUITY
122
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017
Electric Revenue Operating Revenue Elk River Otsego Rural Big Lake Dayton Public St & Hwy Lighting Generation and Sub Station Credit Dispersed Generation Credit Other Revenue/CIP/Rate Increase/AC Credit Total Operating Revenue
2017 DECEMBER
2017 YTD
2017 YTD BUDGET
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
2,623,514 205,785 17,036 17,730 17,977 400 (43,164) (422,160) 2,417,120
32,136,124 2,598,562 189,749 220,413 203,924 4,800 (779,598) (39,543) 34,534,433
32,153,517 2,557,710 201,671 242,372 195,715 9,800 (766,124) 384,357 34,979,021
32,153,517 2,557,710 201,671 242,372 195,715 9,800 (766,124) 384,357 34,979,021
0 2 (6) (9) 4 (51) 2 (110) (1)
2,307,401 164,590 13,556 15,671 16,518 400 (42,354) (816,528) 1,659,255
30,449,856 2,402,850 188,073 228,324 190,193 15,480 (757,527) (62,560) 32,654,690
1,686,267 195,712 1,676 (7,910) 13,730 (10,680) (22,070) 23,017 1,879,742
6 8 1 (3) 7 (69) 3 (37) 6
8,183 17,578 87,549 17,530 0 75,756 206,598
79,542 242,739 1,084,589 234,365 0 592,411 2,233,647
100,000 250,000 1,120,000 55,000 0 108,240 1,633,240
100,000 250,000 1,120,000 55,000 0 108,240 1,633,240
(20) (3) (3) 326 0 447 37
(1,787) 16,812 87,894 7,350 0 56,102 166,371
90,803 253,136 1,087,749 269,196 177,571 645,574 2,524,032
(11,261) (10,397) (3,159) (34,831) (177,571) (53,162) (290,385)
(12) (4) 0 (13) (100) (8) (12)
2,623,718
36,768,081
36,612,261
36,612,261
0
1,825,627
35,178,723
1,589,357
5
Expenses Purchased Power Operating & Mtce Expense Landfill Gas Transmission Expense Distribution Expense Maintenance Expense Depreciation & Amortization Interest Expense Security Other Operating Expense Customer Accounts Expense Administrative Expense General Expense Total Expenses(before Operating Transfers)
2,150,983 17,793 6,452 790 24,561 133,495 176,396 23,872 0 14,827 20,248 345,369 21,801 2,936,593
25,402,576 218,043 658,510 10,926 359,924 1,059,751 2,046,934 294,219 20 80,404 266,781 2,978,453 138,145 33,514,693
25,734,249 366,652 748,500 15,000 328,100 1,066,000 2,100,000 305,709 0 25,500 347,000 2,976,567 213,000 34,226,278
25,734,249 366,652 748,500 15,000 328,100 1,066,000 2,100,000 305,709 0 25,500 347,000 2,976,567 213,000 34,226,278
(1) (41) (12) (27) 10 (1) (3) (4) 0 215 (23) 0 (35) (2)
2,019,531 19,038 19,490 948 18,500 70,318 170,960 27,455 (549) 269,900 24,769 376,088 8,143 3,024,596
23,991,069 227,601 526,267 11,590 251,575 933,103 2,005,093 198,193 75,033 368,155 293,461 2,950,891 138,663 31,970,699
1,411,506 (9,557) 132,243 (663) 108,348 126,648 41,841 96,026 (75,013) (287,751) (26,679) 27,562 (518) 1,543,993
6 (4) 25 (6) 43 14 2 48 (100) (78) (9) 1 0 5
Operating Transfer Operating Transfer/Other Funds Utilities & Labor Donated Total Operating Transfer Net Income Profit(Loss)
89,668 18,167 107,835 (420,711)
1,113,263 202,421 1,315,685 1,937,702
1,165,000 232,000 1,397,000 988,982
1,165,000 232,000 1,397,000 988,982
(4) (13) (6) 96
81,291 19,344 100,636 (1,299,605)
1,089,287 230,312 1,319,599 1,888,424
23,976 (27,890) (3,914) 49,278
2 (12) 0 3
Other Operating Revenue Interest/Dividend Income Customer Penalties LFG Project Connection Fees Security Misc Revenue Total Other Revenue Total Revenue
123
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017
Water Revenue Operating Revenue Water Sales Total Operating Revenue
2017 DECEMBER
2017 YTD
2017 YTD BUDGET
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
129,061 129,061
2,252,750 2,252,750
2,160,950 2,160,950
2,160,950 2,160,950
4 4
117,115 117,115
2,121,380 2,121,380
131,370 131,370
6 6
2,474 1,081 11,408 26,281 41,246
32,171 19,262 797,572 289,673 1,138,680
25,000 15,000 160,000 149,060 349,060
25,000 15,000 160,000 149,060 349,060
29 28 398 94 226
(5,499) 1,083 19,782 389,971 405,337
25,735 17,142 393,682 569,935 1,006,495
6,436 2,120 403,889 (280,262) 132,184
25 12 103 (49) 13
170,308
3,391,430
2,510,010
2,510,010
35
522,453
3,127,876
263,554
8
Expenses Production Expense Pumping Expense Distribution Expense Depreciation & Amortization Interest Expense Other Operating Expense Customer Accounts Expense Administrative Expense General Expense Total Expenses(before Operating Transfers)
2,309 40,598 7,556 101,603 4,142 377 5,624 61,761 600 224,573
42,916 452,532 154,309 1,191,894 50,354 8,123 62,637 640,845 10,160 2,613,773
30,000 587,720 249,280 1,188,000 51,908 11,320 73,000 645,589 11,100 2,847,917
30,000 587,720 249,280 1,188,000 51,908 11,320 73,000 645,589 11,100 2,847,917
43 (23) (38) 0 (3) (28) (14) (1) (8) (8)
2,023 30,980 8,950 97,411 4,716 14,652 5,284 78,673 3,509 246,202
40,368 453,015 149,720 1,148,310 57,986 17,754 75,564 579,885 9,521 2,532,126
2,548 (482) 4,588 43,583 (7,632) (9,630) (12,927) 60,959 639 81,647
6 0 3 4 (13) (54) (17) 11 7 3
Operating Transfer Utilities & Labor Donated Total Operating Transfer Net Income Profit(Loss)
0 0 (54,265)
0 0 777,657
500 500 (338,406)
500 500 (338,406)
(100) (100) (330)
0 0 276,250
0 0 595,750
0 0 181,907
0 0 31
Other Operating Revenue Interest/Dividend Income Customer Penalties Connection Fees Misc Revenue Total Other Revenue Total Revenue
124
Elk River Municipal Utilities Monthly Electrical Demand 70.0 65.0
Demand in MW
60.0 55.0 50.0 45.0 40.0 35.0 30.0
Month
2017
2018
Elk River Municipal Utilities Monthly Energy Purchases 34,000
Energy Purchases in MWH
29,000
24,000
19,000
14,000
Month
2017
125
2018
Elk River Municipal Utilities Monthly Total Electric Load 35,000
Electric Load in MWH
30,000
25,000
20,000
15,000
10,000
Month
2017
2018
Elk River Municipal Utilities Monthly Electric Sales $4,000,000
$3,500,000
Sales in Dollars
$3,000,000
$2,500,000
$2,000,000
$1,500,000
$1,000,000
Month
2017
126
2018
Elk River Municipal Utilities Monthly Residential, Commercial & Industrial Loads 20,000 18,000 16,000
Loads in MWH
14,000 12,000 10,000 8,000 6,000 4,000 2,000 -
Month 2017 Residential
2018 Residential
2017 Commercial
2018 Commercial
2017 Industrial
2018 Industrial
Elk River Municipal Utilities Monthly Residential, Commercial & Industrial Sales $2,000,000 $1,800,000 $1,600,000
Sales in Dollars
$1,400,000 $1,200,000 $1,000,000 $800,000 $600,000 $400,000 $200,000 $0
2017 Residential
Month 2018 Residential
2017 Commercial
2018 Commercial
2017 Industrial
2018 Industrial
127
Elk River Municipal Utilities Monthly Water Pumpage
120
Pumpage in Million Gal.
100 80 60 40 20 0
Month
2017
2018
Elk River Municipal Utilities Peak Day Pumpage 6
Peak Day in Million Gal.
5
4
3
2
1
0
Month
2017
128
2018
Elk River Municipal Utilities Monthly Water Sales 120
Sales in Million Gal.
100 80 60 40 20 0
Month
2017
2018
Elk River Municipal Utilities Monthly Water Sales
$400,000 $350,000
Sales in Dollars
$300,000 $250,000 $200,000 $150,000 $100,000 $50,000 $0
Month
2017
129
2018
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric Revenue Operating Revenue Elk River 440.4411 ELECT SALES/ELK RIVER RES
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
962,963
10,856,611
11,356,268
11,356,268
(4)
766,790
10,603,507
253,103
2
279,170
3,218,485
2,867,833
2,867,833
12
216,721
2,802,240
416,244
15
1,381,380
18,061,027
17,929,415
17,929,415
1
1,323,889
17,044,108
1,016,919
6
2,623,514
32,136,124
32,153,517
32,153,517
0
2,307,401
30,449,856
1,686,267
6
103,650
1,193,247
1,210,254
1,210,254
(1)
77,291
1,131,843
61,403
5
440.4417 ELECT SALES/OTSEGO NON-DEM
31,168
430,346
452,738
452,738
(5)
28,260
442,984
(12,637)
(3)
440.4418 ELECT SALES/OTSEGO DEMAND
70,967
974,968
894,717
894,717
9
59,037
828,022
146,946
18
205,785
2,598,562
2,557,710
2,557,710
2
164,590
2,402,850
195,712
8
16,879
185,620
198,050
198,050
(6)
13,425
184,481
1,138
1
440.4412 ELECT SALES/ER NON-DEMAND 440.4413 ELECT SALES/ER DEMAND Total For Elk River: Otsego 440.4416 ELECT SALES/OTSEGO RES
Total For Otsego: Rural Big Lake 440.4421 ELECT SALES/BIG LAKE RES 440.4422 ELECT SALES/BL NON-DEMAND
157
4,129
3,620
3,620
14
130
3,592
537
15
17,036
189,749
201,671
201,671
(6)
13,556
188,073
1,676
1
15,100
184,882
207,505
207,505
(11)
13,288
194,237
(9,355)
(5)
440.4432 ELECT SALES/DAYTON NON-DEM
2,629
35,531
34,867
34,867
2
2,383
34,086
1,444
4
Total For Dayton:
17,730
220,413
242,372
242,372
(9)
15,671
228,324
(7,910)
(3)
Public St & Hwy Lighting 440.4414 ELECT SALES/ELK RIVER SEC LTS
17,977
203,924
195,715
195,715
4
16,518
190,193
13,730
7
Total For Public St & Hwy Lighting:
17,977
203,924
195,715
195,715
4
16,518
190,193
13,730
7
Generation and Sub Station Credit 440.4550 SUB-STATION CREDIT
400
4,800
4,800
4,800
0
400
4,800
0
0
440.4551 GENERATION CREDIT
0
0
0
0
0
0
10,680
(10,680)
(100)
470.4720 GRE GENERATION - PEAKING PLA
0
0
5,000
5,000
(100)
0
0
0
0
Total For Generation and Sub Station Credit:
400
4,800
9,800
9,800
(51)
400
15,480
(10,680)
(69)
Dispersed Generation Credit 440.4552 DISPERSED GENERATION CREDIT
(43,164)
(779,598)
(766,124)
(766,124)
2
(42,354)
(757,527)
(22,070)
3
Total For Dispersed Generation Credit:
(43,164)
(779,598)
(766,124)
(766,124)
2
(42,354)
(757,527)
(22,070)
3
(422,160)
0
444,357
444,357
(100)
(816,528)
0
0
0
Total For Rural Big Lake: Dayton 440.4431 ELECT SALES/DAYTON RES
Other Revenue/CIP/Rate Increase/AC Credit 440.4554 RATE INCREASE
130
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric 440.4555 A/C CREDIT
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
0
(39,543)
(60,000)
(60,000)
(34)
0
(62,560)
23,017
(37)
(422,160)
(39,543)
384,357
384,357
(110)
(816,528)
(62,560)
23,017
(37)
2,417,120
34,534,433
34,979,021
34,979,021
(1)
1,659,255
32,654,690
1,879,742
6
8,183
79,542
100,000
100,000
(20)
(1,787)
90,803
(11,261)
(12)
Total For Interest/Dividend Income:
8,183
79,542
100,000
100,000
(20)
(1,787)
90,803
(11,261)
(12)
Customer Penalties 470.4701 CUSTOMER DELINQUENT PENALT
17,578
242,739
250,000
250,000
(3)
16,812
253,136
(10,397)
(4)
Total For Customer Penalties:
17,578
242,739
250,000
250,000
(3)
16,812
253,136
(10,397)
(4)
87,549
1,084,589
1,120,000
1,120,000
(3)
87,894
1,087,749
(3,159)
0
Total For LFG Project:
87,549
1,084,589
1,120,000
1,120,000
(3)
87,894
1,087,749
(3,159)
0
Connection Fees 470.4702 DISCONNECT & RECONNECT CHA
17,530
234,365
55,000
55,000
326
7,350
269,196
(34,831)
(13)
Total For Connection Fees:
17,530
234,365
55,000
55,000
326
7,350
269,196
(34,831)
(13)
0
0
0
0
0
0
177,571
(177,571)
(100)
0
0
0
0
0
0
177,571
(177,571)
(100)
Total For Other Revenue/CIP/Rate Increase/AC Credit: Total Operating Revenue Other Operating Revenue Interest/Dividend Income 460.4691 INTEREST & DIVIDEND INCOME
LFG Project 470.4721 LFG PROJECT
Security 470.4700 SECURITY REVENUE Total For Security: Misc Revenue 470.4703 MISC ELEC REVENUE - TEMP CHG 470.4704 STREET LIGHT 470.4715 TRANSMISSION INVESTMENTS 470.4722 MISC NON-UTILITY 470.4723 GAIN ON DISPOSITION OF PROP 470.4725 SALE OF BUSINESS LINE 470.4750 RENTAL PROPERTY INCOME 470.4770 CONTRIBUTIONS FROM CUSTOME 470.4780 CONTRIBUTIONS FROM GRANTS Total For Misc Revenue:
0
6,572
0
0
0
300
450
6,122
1,360
4,850
24,700
0
0
0
0
22,050
2,650
12
28,905
159,589
65,000
65,000
146
32,977
140,471
19,118
14
7,099
151,246
35,000
35,000
332
7,718
104,905
46,340
44
10,000
15,152
0
0
0
20,921
21,400
(6,248)
(29)
0
0
0
0
0
(7,574)
330,922
(330,922)
(100)
2,060
26,100
8,240
8,240
217
1,760
25,374
725
3
3,200
169,051
0
0
0
0
0
169,051
0
19,641
40,000
0
0
0
0
0
40,000
0
75,756
592,411
108,240
108,240
447
56,102
645,574
(53,162)
(8)
Total Other Revenue
131
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
206,598
2,233,647
1,633,240
1,633,240
37
166,371
2,524,032
(290,385)
(12)
206,598
2,233,647
1,633,240
1,633,240
37
166,371
2,524,032
(290,385)
(12)
2,623,718
36,768,081
36,612,261
36,612,261
0
1,825,627
35,178,723
1,589,357
5
2,150,983
25,402,576
25,734,249
25,734,249
(1)
2,019,531
23,991,069
1,411,506
6
2,150,983
25,402,576
25,734,249
25,734,249
(1)
2,019,531
23,991,069
1,411,506
6
7,280
98,581
155,152
155,152
(36)
7,819
99,369
(787)
(1)
419
11,383
25,000
25,000
(54)
209
14,801
(3,418)
(23)
540.5472 NATURAL GAS
3,821
22,999
25,000
25,000
(8)
2,789
23,745
(746)
(3)
540.5483 STATION PWR & WTR CONSP/PLA
3,042
29,874
35,000
35,000
(15)
(204)
27,382
2,491
9
540.5484 OTHER EXP/PLANT SUPPLIES-ETC
198
1,905
6,500
6,500
(71)
30
2,096
(191)
(9)
540.5491 MISC OTHER PWR GENERATION E
384
4,718
15,000
15,000
(69)
659
10,347
(5,629)
(54)
540.5521 MAINTENANCE OF STRUCTURE/P
1,422
20,749
50,000
50,000
(58)
2,404
23,607
(2,857)
(12)
540.5531 MTCE OF ENGINES/GENERATORS-
294
22,148
35,000
35,000
(37)
957
13,925
8,223
59
540.5541 MTCE OF PLANT/LAND IMPROVE
928
5,682
20,000
20,000
(72)
4,372
12,325
(6,642)
(54)
17,793
218,043
366,652
366,652
(41)
19,038
227,601
(9,557)
(4)
Total For Total Other Revenue:
Total Revenue Expenses Purchased Power 540.5551 PURCHASED POWER Total For Purchased Power: Operating & Mtce Expense 540.5461 OPERATING SUPERVISION 540.5471 DIESEL OIL FUEL
Total For Operating & Mtce Expense: Landfill Gas 550.5050 LFG PURCHASED GAS 550.5051 LANDFILL GAS O&M 550.5052 LFG ADMIN
12,594
156,612
170,000
170,000
(8)
0
48,063
108,548
226
(32,251)
451,488
550,000
550,000
(18)
15,040
457,210
(5,722)
(1)
25,149
32,838
10,000
10,000
228
3,062
4,354
28,483
654
550.5053 LFG INSURANCE
1,312
16,199
17,500
17,500
(7)
1,387
16,638
(439)
(3)
550.5054 LFG MTCE
(352)
1,372
1,000
1,000
37
0
0
1,372
0
6,452
658,510
748,500
748,500
(12)
19,490
526,267
132,243
25
790
10,926
15,000
15,000
(27)
948
11,590
(663)
(6)
Total For Transmission Expense:
790
10,926
15,000
15,000
(27)
948
11,590
(663)
(6)
Distribution Expense 580.5801 REMOVE EXISTING SERV & METE
0
642
2,500
2,500
(74)
0
1,323
(681)
(52)
580.5821 SCADA EXPENSES
150
22,001
5,500
5,500
300
0
5,225
16,775
321
580.5831 TRANSFORMER EX/OVERHD & UN
729
17,431
32,000
32,000
(46)
1,303
20,206
(2,775)
(14)
Total For Landfill Gas: Transmission Expense 560.5620 TRANSMISSION MTCE AND EXPE
132
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric 580.5851 MTCE OF SIGNAL SYSTEMS 580.5861 METER EXP - REMOVE & RESET 580.5871 TEMP SERVICE-INSTALL & REMO
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
494
2,982
1,600
1,600
86
97
1,415
1,566
111
0
748
5,000
5,000
(85)
0
2,124
(1,375)
(65)
82
5,866
1,500
1,500
291
175
617
5,248
849
20,688
307,836
280,000
280,000
10
14,508
218,246
89,590
41
580.5890 INTERCONNECTION CARRYING C
2,416
2,416
0
0
0
2,416
2,416
0
0
Total For Distribution Expense:
24,561
359,924
328,100
328,100
10
18,500
251,575
108,348
43
0
3,169
10,000
10,000
(68)
426
2,353
815
35
1,650
18,752
25,000
25,000
(25)
1,096
19,387
(635)
(3)
580.5881 MISC DISTRIBUTION EXPENSE
Maintenance Expense 590.5911 MTCE OF STRUCTURES 590.5921 MTCE OF SUBSTATIONS 590.5922 MTCE OF SUBSTATION EQUIPME 590.5931 MTCE OF OVERHD LINES/TREE TR 590.5932 MTCE OF OVERHD LINES/STANDB 590.5933 MTCE OF OVERHEAD 590.5941 MTCE OF UNDERGROUND/DISTRI 590.5943 LOCATE UNDERGROUND PRIMAR
1,644
4,184
35,000
35,000
(88)
119
25,002
(20,818)
(83)
28,086
100,279
100,000
100,000
0
4,059
37,211
63,067
169
2,118
27,286
30,000
30,000
(9)
1,357
26,906
379
1
11,443
138,893
130,000
130,000
7
9,789
120,236
18,656
16
1,606
76,695
90,000
90,000
(15)
(5,991)
87,889
(11,193)
(13)
2,338
61,684
35,000
35,000
76
3,426
34,488
27,195
79
12,606
56,010
48,000
48,000
17
3,683
46,981
9,028
19
590.5961 MTCE OF STREET LIGHTING
7,236
38,947
40,000
40,000
(3)
4,963
40,439
(1,491)
(4)
590.5962 MTCE OF SECURITY LIGHTING
2,922
15,339
10,000
10,000
53
5,969
10,423
4,915
47
15,590
131,071
110,000
110,000
19
8,019
102,682
28,389
28
0
5,908
8,000
8,000
(26)
737
4,703
1,204
26
590.5951 MTCE OF LINE TRANSFORMERS
590.5971 MTCE OF METERS 590.5972 VOLTAGE COMPLAINTS 590.5981 SALARIES/TRANS & DISTRIBUTIO
2,767
36,360
40,000
40,000
(9)
2,993
37,866
(1,506)
(4)
11,588
69,735
100,000
100,000
(30)
7,435
105,231
(35,496)
(34)
590.5991 MTCE OF OVERHEAD SERVICE/2N
882
17,465
15,000
15,000
16
771
15,128
2,337
15
590.5992 MTCE OF UNDERGROUND ELEC S
1,930
37,402
40,000
40,000
(6)
4,837
42,277
(4,875)
(12)
590.5993 LOCATE UNDERGROUND SECOND
1,268
33,628
20,000
20,000
68
1,186
18,135
15,493
85
27,814
186,936
180,000
180,000
4
15,439
155,755
31,180
20
133,495
1,059,751
1,066,000
1,066,000
(1)
70,318
933,103
126,648
14
176,396
2,046,934
2,100,000
2,100,000
(3)
170,960
2,005,093
41,841
2
Total For Depreciation & Amortization:
176,396
2,046,934
2,100,000
2,100,000
(3)
170,960
2,005,093
41,841
2
Interest Expense 596.8071 INTEREST ON BONDS/LONG TERM
28,105
345,014
356,557
356,557
(3)
31,400
231,874
113,139
49
(276)
(3,316)
(3,370)
(3,370)
(2)
11
(2,987)
(329)
11
590.5985 ELECTRIC MAPPING
590.5995 TRANSPORTATION EXPENSE Total For Maintenance Expense: Depreciation & Amortization 595.8031 DEPRECIATION
596.8075 INTEREST ON DEFEASED BONDS
133
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
597.8281 AMORTIZATION OF DEBT DISCOU
(3,956)
(47,477)
(47,478)
(47,478)
0
(3,956)
(30,693)
(16,783)
55
Total For Interest Expense:
23,872
294,219
305,709
305,709
(4)
27,455
198,193
96,026
48
0
20
0
0
0
(549)
75,033
(75,013)
(100)
0
20
0
0
0
(549)
75,033
(75,013)
(100)
Security 597.8172 SECURITY EXPENSE Total For Security: Other Operating Expense 597.8161 COST & EXP MERCH JOBBING/ELE
0
0
0
0
0
0
346
(346)
(100)
14,938
15,404
0
0
0
0
0
15,404
0
597.8213 LOSS ON DISPOSITION OF PROP (C
0
0
7,500
7,500
(100)
0
72,883
(72,883)
(100)
597.8214 LOSS ON DISPOSITION (NON-CAPI
0
0
7,500
7,500
(100)
19,588
28,642
(28,642)
(100)
597.8263 OTHER DONATIONS
0
53,584
5,000
5,000
972
0
2,860
50,723
1,774
(323)
0
0
0
0
105
382
(382)
(100)
0
0
1,500
1,500
(100)
249,994
249,994
(249,994)
(100)
597.8165 EV CHARGING EXPENSE
597.8264 DAM MAINTENANCE EXPENSE 597.8302 PENSION EXPENSE 597.8341 INTEREST PD ON METER DEPOSIT 597.8400 RENTAL PROPERTY EXPENSE Total For Other Operating Expense: Customer Accounts Expense 900.9021 METER READING EXPENSE 900.9030 COLLECTING EXP DISC/RECONNE
69
786
1,000
1,000
(21)
52
565
221
39
144
10,629
3,000
3,000
254
160
12,481
(1,852)
(15)
14,827
80,404
25,500
25,500
215
269,900
368,155
(287,751)
(78)
1,995
27,066
40,000
40,000
(32)
2,689
31,922
(4,855)
(15)
457
13,812
12,000
12,000
15
420
12,116
1,696
14
900.9051 MISC CUSTOMER ACCTS EXP-CO
21,393
228,181
250,000
250,000
(9)
18,431
257,958
(29,777)
(12)
900.9061 CUST BLGS NOT PD/SENT FOR CO
(3,597)
(2,279)
45,000
45,000
(105)
3,227
(8,537)
6,257
(73)
Total For Customer Accounts Expense:
20,248
266,781
347,000
347,000
(23)
24,769
293,461
(26,679)
(9)
Administrative Expense 920.9201 SALARIES/OFFICE & COMMISSION
99,655
736,429
708,000
708,000
4
160,015
717,476
18,953
3
920.9205 TEMPORARY STAFFING
0
0
4,000
4,000
(100)
0
0
0
0
920.9211 OFFICE SUPPLIES & EXPENSE
2,665
75,045
115,500
115,500
(35)
7,680
70,516
4,529
6
920.9212 LT & WATER CONSUMPTION/OFFI
1,942
36,559
25,000
25,000
46
11,827
28,609
7,949
28
351
2,825
3,500
3,500
(19)
241
2,872
(47)
(2)
920.9221 LEGAL FEES
1,834
27,230
50,000
50,000
(46)
1,791
25,893
1,337
5
920.9231 AUDITING FEES
1,688
26,972
14,652
14,652
84
2,800
14,864
12,108
81
920.9241 INSURANCE
7,897
146,855
145,000
145,000
1
(3,427)
154,981
(8,126)
(5)
920.9260 UTILITY SHARE DEF COMP
57,805
109,686
57,000
57,000
92
0
55,032
54,654
99
920.9261 UTIL SH OF MEDICAL/DENTAL/DI
50,140
660,754
609,464
609,464
8
47,145
573,713
87,041
15
920.9213 BANK CHARGES
134
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
920.9262 UTILITY SHARE OF PERA
15,771
212,634
245,000
245,000
(13)
26,978
221,167
(8,532)
(4)
920.9263 UTILITY SHARE OF FICA
15,514
201,094
215,000
215,000
(6)
25,759
211,122
(10,027)
(5)
920.9264 EMPLOYEES SICK PAY
11,270
102,654
100,000
100,000
3
11,230
96,668
5,986
6
920.9266 EMP VACATION/HOLIDAY PAY
42,563
309,671
275,000
275,000
13
39,298
286,677
22,994
8
0
49,511
85,000
85,000
(42)
13,803
115,129
(65,617)
(57)
920.9291 CONSULTING FEES 920.9301 TELEPHONE 920.9302 ADVERTISING 920.9303 DUES & SUBSCRIPTIONS - FEES 920.9304 TRAVEL EXPENSE 920.9305 SCHOOLS & MEETINGS
1,805
21,075
27,000
27,000
(22)
3,685
22,703
(1,628)
(7)
14,039
24,111
3,000
3,000
704
0
1,776
22,334
1,258
7,045
86,233
78,000
78,000
11
8,145
203,739
(117,505)
(58)
0
23,832
15,000
15,000
59
1,334
8,585
15,247
178
12,831
116,900
178,450
178,450
(34)
11,219
131,923
(15,023)
(11)
920.9321 MTCE OF GEN PLANT/OFF HEATIN
547
8,373
23,000
23,000
(64)
6,558
7,439
934
13
Total For Administrative Expense:
345,369
2,978,453
2,976,567
2,976,567
0
376,088
2,950,891
27,562
1
General Expense 920.9269 CIP REBATES - RESIDENTIAL
(2,673)
8,994
185,000
185,000
(95)
(367)
110,838
(101,843)
(92)
920.9270 CIP REBATES - COMMERCIAL
15,717
35,541
0
0
0
0
0
35,541
0
5,923
6,418
0
0
0
0
0
6,418
0
59
9,778
0
0
0
0
0
9,778
0
3,857
50,796
0
0
0
0
0
50,796
0
920.9271 CIP - ADMINISTRATION 920.9272 CIP - MARKETING 920.9273 CIP - LABOR 920.9274 CIP REBATES - LOW INCOME
(5,609)
0
0
0
0
0
0
0
0
920.9281 ENVIRONMENTAL COMPLIANCE
1,982
24,334
27,000
27,000
(10)
1,869
21,248
3,085
15
920.9306 MISC GENERAL EXPENSE
2,543
2,280
1,000
1,000
128
6,641
6,575
(4,295)
(65)
21,801
138,145
213,000
213,000
(35)
8,143
138,663
(518)
0
2,936,593
33,514,693
34,226,278
34,226,278
(2)
3,024,596
31,970,699
1,543,993
5
Operating Transfer Operating Transfer/Other Funds 597.8262 TRANSFER TO CITY 4% ER REVEN
89,668
1,113,263
1,165,000
1,165,000
(4)
81,291
1,089,287
23,976
2
Total For Operating Transfer/Other Funds:
89,668
1,113,263
1,165,000
1,165,000
(4)
81,291
1,089,287
23,976
2
Total For General Expense: Total Expenses(before Operating Transfers)
Utilities & Labor Donated 597.8261 UTILITIES & LABOR DONATED
18,167
202,421
232,000
232,000
(13)
19,344
230,312
(27,890)
(12)
Total For Utilities & Labor Donated:
18,167
202,421
232,000
232,000
(13)
19,344
230,312
(27,890)
(12)
Total Operating Transfer Total For Total Operating Transfer:
107,835
1,315,685
1,397,000
1,397,000
(6)
100,636
1,319,599
(3,914)
0
135
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Electric Net Income Profit(Loss)
(420,711)
2017 YTD 1,937,702
2017 YTD BUDGET 988,982
136
2017 ANNUAL BUDGET 988,982
2017 YTD Bud Var% 96
2016 DECEMBER (1,299,605)
2016 YTD 1,888,424
YTD VARIANCE 49,278
2016 v. 2017 Actual Var% 3
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Water Revenue
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
Operating Revenue Water Sales 610.6101 WATER SALES COMM & RES/COM
129,061
2,252,750
2,160,950
2,160,950
4
117,115
2,121,380
131,370
6
Total For Water Sales:
129,061
2,252,750
2,160,950
2,160,950
4
117,115
2,121,380
131,370
6
129,061
2,252,750
2,160,950
2,160,950
4
117,115
2,121,380
131,370
6
129,061
2,252,750
2,160,950
2,160,950
4
117,115
2,121,380
131,370
6
2,045
31,313
25,000
25,000
25
1,796
24,917
6,396
26
428
857
0
0
0
(7,295)
818
39
5
2,474
32,171
25,000
25,000
29
(5,499)
25,735
6,436
25
1,081
19,262
15,000
15,000
28
1,083
17,142
2,120
12
Total For Customer Penalties:
1,081
19,262
15,000
15,000
28
1,083
17,142
2,120
12
Connection Fees 620.6401 WATER/ACCESS/CONNECTION FE
9,549
743,341
150,000
150,000
396
16,975
358,684
384,657
107
620.6402 CUSTOMER CONNECTION FEES
1,859
54,230
10,000
10,000
442
2,807
34,998
19,232
55
11,408
797,572
160,000
160,000
398
19,782
393,682
403,889
103
0
102
0
0
0
(196)
5,542
(5,440)
(98)
515
6,525
2,060
2,060
217
440
6,343
181
3
0
0
0
0
0
300,000
300,000
(300,000)
(100)
7,000
7,448
0
0
0
1,050
1,050
6,398
609
0
598
0
0
0
0
2,354
(1,755)
(75)
Total Operating Revenue Total For Total Operating Revenue: Other Operating Revenue Interest/Dividend Income 460.4691 INTEREST & DIVIDEND INCOME 460.4692 OTHER INT/MISC REVENUE Total For Interest/Dividend Income: Customer Penalties 620.6301 CUSTOMER PENALTIES
Total For Connection Fees: Misc Revenue 470.4722 MISC NON-UTILITY 470.4750 RENTAL PROPERTY INCOME 620.6260 TRANSFER IN FROM CITY 620.6323 GAIN ON DISPOSITION OF PROP 620.6403 MISCELLANEOUS REVENUE 620.6404 HYDRANT MAINTENANCE PROGR
974
9,197
7,000
7,000
31
971
8,646
551
6
620.6405 CONTRIBUTIONS FROM DEVELOP
0
55,882
0
0
0
73,002
73,002
(17,120)
(23)
17,792
209,920
140,000
140,000
50
14,704
172,997
36,923
21
26,281
289,673
149,060
149,060
94
389,971
569,935
(280,262)
(49)
41,246
1,138,680
349,060
349,060
226
405,337
1,006,495
132,184
13
620.6406 WATER TOWER LEASE Total For Misc Revenue: Total Other Revenue
137
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Water Total For Total Other Revenue:
Total Revenue Expenses Production Expense 700.7021 MTCE OF STRUCTURES 700.7022 TOWER & GROUNDS INSPECTION Total For Production Expense: Pumping Expense 710.7101 SUPERVISION
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
41,246
1,138,680
349,060
349,060
226
405,337
1,006,495
132,184
13
170,308
3,391,430
2,510,010
2,510,010
35
522,453
3,127,876
263,554
8
2,309
42,916
30,000
30,000
43
2,023
40,228
2,688
7
0
0
0
0
0
0
140
(140)
(100)
2,309
42,916
30,000
30,000
43
2,023
40,368
2,548
6
4,137
52,845
49,220
49,220
7
4,370
53,995
(1,150)
(2)
18,243
202,240
230,000
230,000
(12)
14,085
206,234
(3,993)
(2)
710.7182 SAMPLING
1,089
15,386
16,000
16,000
(4)
(140)
14,910
476
3
710.7183 CHEMICAL FEED
1,901
27,375
30,000
30,000
(9)
1,669
23,796
3,579
15
710.7181 SUPPLIES & EXPENSE/MISC
710.7201 MTCE OF ELECTRIC PUMPING EQ 710.7220 MTCE OF WELLS 710.7230 SCADA - PUMPING Total For Pumping Expense: Distribution Expense 730.7301 MTCE OF WATER MAINS 730.7309 LOCATE WATER SVC
0
27
0
0
0
0
0
27
0
15,012
148,937
250,000
250,000
(40)
10,817
147,254
1,683
1
214
5,717
12,500
12,500
(54)
178
6,823
(1,105)
(16)
40,598
452,532
587,720
587,720
(23)
30,980
453,015
(482)
0
1,582
37,029
107,500
107,500
(66)
1,682
41,639
(4,609)
(11)
437
13,150
9,000
9,000
46
898
10,842
2,308
21
730.7310 LOCATE WATER MAIN
16
33
0
0
0
0
154
(120)
(79)
730.7311 MTCE OF WATER SERVICES
30
387
0
0
0
0
0
387
0
730.7312 WATER METER SERVICE
809
7,294
8,000
8,000
(9)
1,605
10,648
(3,354)
(31)
1,682
20,169
25,000
25,000
(19)
1,677
20,077
92
0
730.7325 WATER MAPPING
855
16,971
20,000
20,000
(15)
237
5,026
11,944
238
730.7331 MTCE OF WATER HYDRANTS - PU
868
26,461
31,000
31,000
(15)
283
29,487
(3,026)
(10)
35
3,859
12,000
12,000
(68)
150
3,739
119
3
730.7321 MTCE OF CUSTOMERS SERVICE
730.7341 WATER CLOTHING/PPE 730.7391 WAGES/WATER
390
5,714
6,780
6,780
(16)
407
5,661
53
1
730.7395 TRANSPORTATION EXPENSE
846
11,842
15,000
15,000
(21)
767
10,474
1,367
13
0
11,396
15,000
15,000
(24)
1,240
11,968
(572)
(5)
7,556
154,309
249,280
249,280
(38)
8,950
149,720
4,588
3
101,603
1,191,894
1,188,000
1,188,000
0
97,411
1,148,310
43,583
4
730.7399 GENERAL EXP/WATER PERMIT Total For Distribution Expense: Depreciation & Amortization 595.8031 DEPRECIATION
138
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Water
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
Total For Depreciation & Amortization:
101,603
1,191,894
1,188,000
1,188,000
0
97,411
1,148,310
43,583
4
Interest Expense 596.8071 INTEREST ON BONDS/LONG TERM
4,211
51,183
52,750
52,750
(3)
4,714
58,733
(7,549)
(13)
(69)
(829)
(842)
(842)
(2)
2
(746)
(82)
11
4,142
50,354
51,908
51,908
(3)
4,716
57,986
(7,632)
(13)
596.8075 INTEREST ON DEFEASED BONDS Total For Interest Expense: Other Operating Expense 597.8213 LOSS ON DISPOSITION OF PROP (C 597.8264 DAM MAINTENANCE EXPENSE 597.8302 PENSION EXPENSE 597.8341 INTEREST PD ON METER DEPOSIT 597.8400 RENTAL PROPERTY EXPENSE Total For Other Operating Expense: Customer Accounts Expense 900.9021 METER READING EXPENSE
0
5,099
1,000
1,000
410
0
0
5,099
0
339
339
7,800
7,800
(96)
0
0
339
0
0
0
1,500
1,500
(100)
14,610
14,610
(14,610)
(100)
2
27
20
20
40
2
23
3
17
36
2,657
1,000
1,000
166
40
3,120
(463)
(15)
377
8,123
11,320
11,320
(28)
14,652
17,754
(9,630)
(54)
599
9,272
7,000
7,000
32
971
7,809
1,462
19
5,025
52,999
65,000
65,000
(18)
4,313
67,754
(14,755)
(22)
900.9061 CUST BLGS NOT PD/SENT FOR CO
0
365
1,000
1,000
(63)
0
0
365
0
Total For Customer Accounts Expense:
5,624
62,637
73,000
73,000
(14)
5,284
75,564
(12,927)
(17)
Administrative Expense 920.9201 SALARIES/OFFICE & COMMISSION
21,934
177,818
176,000
176,000
1
37,181
167,573
10,245
6
0
0
1,000
1,000
(100)
0
0
0
0
920.9211 OFFICE SUPPLIES & EXPENSE
982
24,006
27,000
27,000
(11)
3,568
24,162
(155)
(1)
920.9212 LT & WATER CONSUMPTION/OFFI
485
9,134
5,000
5,000
83
2,956
7,152
1,981
28
87
711
1,000
1,000
(29)
60
718
(6)
(1)
358
4,896
5,000
5,000
(2)
447
5,146
(250)
(5)
900.9051 MISC CUSTOMER ACCTS EXP-CO
920.9205 TEMPORARY STAFFING
920.9213 BANK CHARGES 920.9221 LEGAL FEES 920.9231 AUDITING FEES 920.9241 INSURANCE 920.9260 UTILITY SHARE DEF COMP
422
6,743
3,663
3,663
84
700
3,716
3,027
81
1,105
24,110
30,000
30,000
(20)
(868)
23,358
752
3
8,635
18,317
4,600
4,600
298
0
4,436
13,881
313
10,426
139,028
153,576
153,576
(9)
9,050
135,484
3,544
3
920.9262 UTILITY SHARE OF PERA
2,873
40,952
23,750
23,750
72
2,646
22,136
18,815
85
920.9263 UTILITY SHARE OF FICA
2,817
38,988
25,250
25,250
54
2,993
22,507
16,480
73
920.9264 EMPLOYEES SICK PAY
2,018
20,602
25,750
25,750
(20)
2,545
21,923
(1,320)
(6)
920.9266 EMP VACATION/HOLIDAY PAY
6,960
55,557
60,000
60,000
(7)
8,793
64,919
(9,361)
(14)
0
80
1,000
1,000
(92)
0
1,038
(958)
(92)
920.9261 UTIL SH OF MEDICAL/DENTAL/DI
920.9268 MISCELLANEOUS - WELLHEAD P
139
ELK RIVER MUNICIPAL UTILITIES ELK RIVER, MINNESOTA STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION FOR PERIOD ENDING DECEMBER 2017 2017 DECEMBER
Water 920.9291 CONSULTING FEES 920.9301 TELEPHONE 920.9302 ADVERTISING
2017 YTD BUDGET
2017 YTD
2017 ANNUAL BUDGET
2017 YTD Bud Var%
2016 DECEMBER
2016 YTD
YTD VARIANCE
2016 v. 2017 Actual Var%
0
7,933
20,000
20,000
(60)
3,450
3,450
4,482
130
440
5,549
7,500
7,500
(26)
1,002
5,835
(285)
(5)
490
4,620
4,000
4,000
16
0
3,086
1,533
50
1,191
39,322
38,000
38,000
3
1,456
40,477
(1,154)
(3)
0
4,177
3,000
3,000
39
176
1,607
2,569
160
920.9305 SCHOOLS & MEETINGS
395
16,218
28,000
28,000
(42)
873
19,295
(3,077)
(16)
920.9321 MTCE OF GEN PLANT/OFF HEATIN
137
2,076
2,500
2,500
(17)
1,639
1,859
216
12
Total For Administrative Expense:
61,761
640,845
645,589
645,589
(1)
78,673
579,885
60,959
11
General Expense 920.9269 CIP REBATES - RESIDENTIAL
225
3,939
10,000
10,000
(61)
3,463
8,940
(5,001)
(56)
920.9270 CIP REBATES - COMMERCIAL
25
125
0
0
0
0
0
125
0
920.9271 CIP - ADMINISTRATION
0
731
0
0
0
0
0
731
0
920.9272 CIP - MARKETING
0
480
0
0
0
0
0
480
0
308
4,369
0
0
0
0
0
4,369
0
41
516
600
600
(14)
44
532
(16)
(3)
0
(3)
500
500
(101)
1
47
(50)
(106)
600
10,160
11,100
11,100
(8)
3,509
9,521
639
7
224,573
2,613,773
2,847,917
2,847,917
(8)
246,202
2,532,126
81,647
3
0
0
500
500
(100)
0
0
0
0
0
0
500
500
(100)
0
0
0
0
(54,265)
777,657
(338,406)
(338,406)
(330)
276,250
595,750
181,907
31
920.9303 DUES & SUBSCRIPTIONS - FEES 920.9304 TRAVEL EXPENSE
920.9273 CIP - LABOR 920.9281 ENVIRONMENTAL COMPLIANCE 920.9306 MISC GENERAL EXPENSE Total For General Expense: Total Expenses(before Operating Transfers) Operating Transfer Utilities & Labor Donated 597.8261 WATER AND LABOR DONATED Total Operating Transfer Total For Total Operating Transfer: Net Income Profit(Loss)
140
UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13, 2018 SUBJECT: 2017 Annual Safety Report ACTION REQUESTED: No action is requested.
FROM: Troy Adams, P.E. – General Manager AGENDA ITEM NUMBER: 5.2
BACKGROUND: Minnesota Rules Chapter 7826 Public Utilities Commission Electric Utility Standards cover safety, reliability, service, and reporting requirements. Per 7826.0100(A), municipal utilities are exempt from these requirements. However, the Elk River Municipal Utilities Commission adopted a number of parts of this chapter as a Distribution Reliability Standard policy. This policy includes an Annual Safety Report requirement. The policy requires ERMU to “file an annual safety performance report with its local governing body. The report will include summaries of all reports files with OSHA and the Occupational Safety and Health Division of the Minnesota Department of Labor and Industry during the calendar year.” DISCUSSION: In 2017, there were four recordable cases which resulted in 0 days away from work. Attached is the OSHA Form 300A that has been filed. It is a summary of work related first report of injuries and illnesses. Also attached is the OSHA Form 300A from 2016 for reference. FINANCIAL IMPACT: None ATTACHMENTS: 2017 OHSA Form 300A – 1/08/2018 2016 OHSA Form 300A – 1/20/2017
______________________________________________________________________________ Page 1 of 1 141
142
143
UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Theresa Slominski - Finance & Office Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2017 5.3 SUBJECT: 2018 Bank Signatories ACTION REQUESTED: Adopt, by motion, a resolution appointing the bank signatories for 2018. BACKGROUND: We require two signatures on all our checks and have always had all three commissioners with signing authority, in case one is unavailable. Now that we have five commissioners we still have only three commissioners with signing authority, however, with an exiting commissioner a new signor is necessary. DISCUSSION: The current signors are John Dietz, Daryl Thompson, and Al Nadeau. As the Finance and Accounting Specialist, I am also a signor on the account but only to facilitate wire transfers for bond payments, renew our Letter of Credit and the annual charge for the Letter of Credit that comes directly out of the bank checking account, and set up users for online ACH transactions to occur. We use signature stamps to sign the checks and all are under lock and key. An individual stamp is in the possession of the Payroll and Accounts Payable Specialist for the first signature on all checks. An individual stamp is also in the possession of the General Manager and the Finance and Accounting Manager for the second signature. With the term of Daryl Thompson expiring, and in order to have the smoothest transition of signors, I would like to determine the replacement check signor from the existing current commissioners and have the new signatures on file with the bank and another stamp made before the new commissioner starts in March. We will also need to adopt by resolution the authorized signors for 2018. ATTACHMENTS: Resolution No. 18.3 – Appointing the Bank Signatories for 2018
______________________________________________________________________________ Page 1 of 1 144
RESOLUTION NO. 18-3 BOARD OF COMMISSIONERS ELK RIVER MUNICIPAL UTILITIES A RESOLUTION OF THE BOARD OF COMMISSIONERS OF ELK RIVER MUNICIPAL UTILITIES APPOINTING THE BANK SIGNATORIES FOR 2018. WHEREAS, ERMU policy requires two signatures on all ERMU checks; and WHEREAS, ERMU policy is to designate three members of the ERMU Board of Commissioners to have signing authority. NOW, THEREFORE, BE IT RESOLVED that the following three members of the ERMU Board of Commissioners shall have authority to sign checks on behalf of ERMU during the calendar year 2018. 1. John Dietz 2. Al Nadeau 3. This Resolution Passed and Adopted this 13th day of February, 2018.
John J. Dietz, Chair
Troy Adams, P.E., General Manager
145
UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Theresa Slominski - Finance & Office Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2017 5.4 SUBJECT: 2017 Fourth Quarter Delinquent Items ACTION REQUESTED: Approve the 2017 Fourth Quarter Delinquent Amounts Listing. BACKGROUND: Fourth quarter delinquent items are presented for your review. We have previously reported on four different categories of delinquents as follows: Assessments are delays in collecting the money owed and is assessed to the property taxes in the fall. Please note this number will only be presented for the 4th quarter. Collections amounts are those we send to the collection agency to try and collect after we have exhausted all our internal collection efforts. We receive 70% of amounts collected after the agency receives their split. Revenue Recapture (RR) is the program through the state where funds are collected from individuals’ tax refunds and remitted to us, with the balance (if any) remitted to the individual. It presents an opportunity to collect funds rather than splitting with a collection agency or having to write them off completely. There is a maximum of six years accounts may be placed with RR and after the six years, they are written off. Write-Offs are amounts removed from the books with no further collection efforts being extended. This is the category with the most impact to the bottom line. DISCUSSION: I have for review the color-coded recap comparisons with last year (2017 Fourth Quarter Delinquent Items Comparisons), identifying the categories and the running totals. The amounts listed for assessments culminates in the fourth quarter and includes items previously submitted to other collection services, and if not collected, is removed and assessed. The assessment amount for 2017 is shown in blue at $8,352.84. The attached report listing (2017 Fourth Quarter Delinquent Items Submitted) shows those dollars submitted to the collection agency (A), those submitted to both the collection agency and revenue recapture (B), and those submitted to revenue recapture (R). The amounts submitted for the quarter to the collection agency (A) are $180.40. Amounts submitted for the quarter to Revenue Recapture (R) are $10,344.56. Note that assessable items are also included here as mentioned above.
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The fourth quarter totals submitted to the Collection Agencies and Revenue Recapture are $10,524.96. To break these totals down by provider, it is $9,622.57 for Electric, $108.78 for Water, $81.62 for Sewer, $15.99 for Trash, $675.92 for Franchise Fees, and $20.08 for Storm Water. The amount for fourth quarter Write-Offs is $2,272.12; which includes small balances of $56.32, bankruptcies $673.18, deceased parties of $647.20, and RR items meeting six year maximum placement of $895.42. Note that this is the first year we have met the six year maximum and have had to remove accounts from RR and Write-Off. Our budgeted amount for collections and write-offs are $105,000, or .27% uncollectible accounts per revenue dollar. According to APPA’s most recent published standard ratios (2015), the industry standard is between .17% and .37%. Interestingly, the Northern/Central Plains average is .09%. Our totals for the year are below the national average, at .00659% for the write-off category. Our total in the GL is a credit, due to balances being collected that were previously written off, effectively a negative, or 0%, for the ratio. ATTACHMENTS: 2017 Fourth Quarter Delinquent Items Comparisons 2017 Fourth Quarter Delinquent Items Submitted
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Delinquent Items Comparisons
Quarter First YTD Total
2017 Assessments -
2016 Assessments
Second
2017 Collection Agency -
-
2016 Collection Agency 1,560.08 1,560.08
2017 Revenue Recapture 5,739.46 5,739.46
2016 Revenue Recapture 6,646.36 6,646.36
2017 Write-Offs (18.07) (18.07)
2016 Write-Offs (927.42) (927.42)
2017 Totals 5,721.39
2016 Totals 7,279.02
730.50 730.50
2,411.07 3,971.15
8,617.58 14,357.04
8,785.97 15,432.33
358.05 339.98
(338.07) (1,265.49)
10,858.97
-
-
9,706.13
YTD Total
730.50
3,819.34 7,790.49
8,319.80 22,676.84
10,896.75 26,329.08
(34.28) 305.70
659.16 (606.33)
15,375.25
-
-
8,285.52
YTD Total
180.40 910.90
9,317.61 17,108.10
10,344.56 33,021.40
13,147.28 39,476.36
2,272.12 2,577.82
3,513.66 2,907.33
21,149.92 44,862.96 33,021.40 8,352.84 3,488.72 (1,913.86)
Third
Fourth
8,352.84 8,352.84
YTD Total
14,762.86 14,762.86
Less RR Less Assessments Totals excluding RR & Assessments GL Totals
2016 Delinquent Items Comparisons
2017 Delinquent Items Comparisons 16,000.00
14,000.00
14,000.00
12,000.00
12,000.00
10,000.00
Collection Agency
8,000.00
6,000.00 4,000.00 2,000.00
8,000.00
Revenue Recapture
Write-Offs
6,000.00
Write-Offs
Assessments
4,000.00
Assessments
2,000.00
(2,000.00)
Collection Agency
10,000.00
Revenue Recapture
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
(2,000.00)
148
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
25,978.55 59,491.79 GRAND TOTALS 39,476.36 14,762.86 5,252.57 (8,537.02)
Agency R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R
Account 17840 17840 17840 19748 19748 21772 21772 22140 22140 26301 26301 29196 29196 29219 29219 29647 29647 30205 30205 30614 30614 30756 31065 31065 31111 31111 31111 31182 31182 31465 31465 31531 31531 32530 32530 32722 32722 32722 32722 32722 32902 32902 33012 33012 33639 33639 33730 33730
Serv Addr 22822 BALDWIN ST HOUSE 22822 BALDWIN ST HOUSE 22822 BALDWIN ST HOUSE 379 BALDWIN AVE APT 206 379 BALDWIN AVE APT 206 1105 LIONS PARK DR APT 205 1105 LIONS PARK DR APT 205 10081 179TH LN 10081 179TH LN 18078 VANCE CIRCLE 18078 VANCE CIRCLE 11931 191 1/2 AVE APT 206 11931 191 1/2 AVE APT 206 12456 194TH LN 12456 194TH LN 241 MAIN ST APT 4 241 MAIN ST APT 4 847 FREEPORT AVE APT 204 847 FREEPORT AVE APT 204 803 FREEPORT AVE 803 FREEPORT AVE 8346 PARKVIEW AVE NE 379 BALDWIN AVE APT 207 379 BALDWIN AVE APT 207 10591 171ST AVE 10591 171ST AVE 10591 171ST AVE 1227 SCHOOL ST APT 109 1227 SCHOOL ST APT 109 19157 IVANHOE DR 19157 IVANHOE DR 831 FREEPORT AVE 831 FREEPORT AVE 543 5TH ST APT 2 543 5TH ST APT 2 19507 AUBURN ST 19507 AUBURN ST 19507 AUBURN ST 19507 AUBURN ST 19507 AUBURN ST 345 EVANS AVE APT 205 345 EVANS AVE APT 205 325 EVANS AVE APT 206 325 EVANS AVE APT 206 17250 TWIN LAKES RD 301 17250 TWIN LAKES RD 301 17250 TWIN LAKES RD 402 17250 TWIN LAKES RD 402
Provider 1ERUE 6CTYF 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 1ERUE 6CTYF 1ERUE 6CTYF 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 2ERUW 3CTYS 6CTYF 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF
149
Total AR $ 99.63 $ 5.70 $ 2.00 $ 118.92 $ 22.07 $ 148.12 $ 28.85 $ 720.29 $ 27.76 $ 178.16 $ 11.40 $ 223.69 $ 23.49 $ 437.61 $ 12.64 $ 163.48 $ 11.74 $ 174.51 $ 18.50 $ 150.48 $ 29.01 $ 678.38 $ 138.68 $ 19.22 $ 183.89 $ 9.96 $ 1.78 $ 23.95 $ 6.41 $ 319.67 $ 21.17 $ 127.43 $ 16.55 $ 51.90 $ 14.60 $ 220.94 $ 50.09 $ 22.30 $ 5.53 $ 3.00 $ 243.44 $ 11.40 $ 37.02 $ 10.86 $ 127.01 $ 17.08 $ 174.03 $ 24.20
R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R R
34469 34469 34503 34503 34843 34843 34942 34942 35172 35172 35192 35192 35248 35248 35248 35248 35248 35248 35341 35341 35493 35493 35505 35505 35505 35505 35881 35881 35920 35920 35974 35974 36024 36024 36024 36263 36263 36356 36356 36666 36818 36818 37027 37027
20295 TWIN LAKES RD - GUEST HOME 20295 TWIN LAKES RD - GUEST HOME 1227 SCHOOL ST APT 316 1227 SCHOOL ST APT 316 1227 SCHOOL ST APT 105 1227 SCHOOL ST APT 105 238 8TH ST 238 8TH ST 11981 191 1/2 AVE APT 201 11981 191 1/2 AVE APT 201 10867 181ST LN 10867 181ST LN 1414 5TH ST NW 1414 5TH ST NW 1414 5TH ST NW 1414 5TH ST NW 1414 5TH ST NW 1414 5TH ST NW 1105 LIONS PARK DR APT 204 1105 LIONS PARK DR APT 204 10860 181ST LN 10860 181ST LN 19265 DODGE ST 19265 DODGE ST 19265 DODGE ST 19265 DODGE ST 633 MAIN ST APT 415 633 MAIN ST APT 415 1105 LIONS PARK DR APT 223 1105 LIONS PARK DR APT 223 300 3RD ST APT 302 300 3RD ST APT 302 17165 POLK CIR 17165 POLK CIR 17165 POLK CIR 1001 SCHOOL ST APT 308 1001 SCHOOL ST APT 308 9754 VIKING BLVD UPSTAIRS 9754 VIKING BLVD UPSTAIRS 18450 ROBINSON ST 11755 191 1/2 AVE APT 201 11755 191 1/2 AVE APT 201 847 FREEPORT AVE APT 207 847 FREEPORT AVE APT 207
A A
36449 325 EVANS AVE APT 302 36449 325 EVANS AVE APT 302
150
1ERUE 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 2ERUW 3CTYS 4CTYT 6CTYF 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 2ERUW 3CTYS 6CTYF 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 6CTYF 7CTYS 1ERUE 6CTYF 1ERUE 6CTYF 1ERUE 1ERUE 6CTYF 1ERUE 6CTYF
$ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $
661.13 2.00 258.29 18.69 85.85 27.22 326.59 17.08 101.49 21.70 159.36 18.33 500.41 34.78 28.10 15.99 13.17 6.30 72.71 11.21 229.23 11.93 23.91 31.22 13.89 3.00 409.08 16.20 202.42 25.09 328.48 23.67 84.83 13.17 2.00 159.15 17.27 225.73 24.23 453.37 220.91 14.07 239.18 23.59 $ 10,344.56
1ERUE 6CTYF TOTAL
$ 163.13 $ 17.27 $ 180.40 $ 10,524.96 $ 10,524.96
HANDOUT AT MEETING - PROVIDED BY CHAIR DIETZ
UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13, 2018 SUBJECT: Staff Update ACTION REQUESTED: None
FROM: Troy Adams, P.E. – General Manager AGENDA ITEM NUMBER: 6.1a
DISCUSSION: The Board of Directors of the Minnesota Municipal Power Agency (MMPA) met on January 23, 2018 at the offices of Shakopee Public Utilities in Shakopee, Minnesota. Commissioner Al Nadeau and I were both able to attend. Participation in MMPA’s residential Clean Energy Choice program increased 4.5% over December, with 60 new customers signing up for the program. Customer penetration of MMPA’s Clean Energy Choice program for residential customers increased to 2.6%, with a range of market penetration by member of 1.5% to 5.6%. The Board approved Eagle Creek Elementary School in Shakopee as a recipient of a Hometown Solar grant as part of the Agency’s 2018 Energy Education program. The Buffalo Solar project is now in service and producing energy. MMPA has a longterm purchased power agreement for all of the output of the 7 MW facility. The Board discussed the status of a renewable project that the Agency is pursuing.
I have continued to work with Great River Energy (GRE) and MMPA on wholesale power transition action items. At the front of those conversations is the Landfill Gas to Electric Generation Plant (LFG Plant) contract. Because the LFG Plant contract covers energy and capacity in the GRE Midcontinent Independent System Operator (MISO) zone and ERMU is transitioning to MMPA, this issues resolution also plays in the timing of how ERMU’s load is registered in MISO. Basically, there are a number of moving parts that are all interconnected. Discussion between all parties currently appears to be amiable with aligned goals being completed within the required schedule. ERMU, GRE, and MMPA have another conference call regarding these action items on Monday February 12.
On January 16, I attended the first ever joint meeting of the board of directors for the Minnesota Municipal Utilities Association (MMUA) and the board of directors of the Minnesota Rural Electric Association (MREA). This historic event has been in the make
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since my term as MMUA President and was directly associated with the hiring a new MREA CEO, Darrick Moe. The meeting was without agenda, and held as an opportunity to develop better awareness of common ground and identify aligned goals. The primary objective of this meeting was a huge success. Additionally, I established connections with cooperatives utilizing Nation Information Solutions Cooperative (NISC) software, discussed legislative advocacy, talked metering and billing, and discussed leadership development.
On January 19, I was elected by a vote of my peers as the MMUA Government Relations Committee Chair. The Committee holds conference calls preceding and during the legislative session to organize positions on critical topics. I’ve succeeded Bill Schwandt, General Manager from Moorhead Public Service.
On January 26, I sat in on an interview panel for the MMUA Government Relations Director. The panel also included Jack Kegel (MMUA Executive Director), John Crooks (Shakopee Public Utilities GM and MMUA President), and Doug Carnival (Attorney at McGrannShea Carnival Straughn & Lamb, MMUA’s legal counsel). Kent Sulem has accepted an offer for the position and has already started working. Kent worked with the League of Minnesota Cities and the Minnesota Association of Townships during the past 25 years. And this will be his 20th session of lobbying at the Capitol.
Last year Minnesota Representative Cal Bahr of District 31B had authored a bill that would allow large electrical customers to purchase electricity from any supplier. The intent is basically third party sales under the cover of customer choice. This did not pass. In a proactive effort to provide Rep Bahr and others with “main street” examples of how this type of legislation would impact communities and Minnesota, representatives from Xcel, Connexus, Minnesota Power, GRE, MREA, MMUA, MMPA, and ERMU met with Rep Bahr on February 5. It was intentionally a small and informal meeting with few than a dozen people in attendance. The meeting was successful in delivering our concerns with the past bill language. I feel that our message was well received by Rep Bahr.
The Minnesota Public Utilities Commission filing for the electric service territory boundary change resulting from the September 2017 Connexus Areas 3& 4 transfer has been completed. I’ll bring back the formal response letter from the MPUC for the Commission to receive at a future meeting. It is expected to be approved without question as this is non-controversial, mutually filed by ERMU and Connexus, and similar to the past boundary changes for Areas 1 & 2 previously approved.
I have completed annual Performance Evaluations for my direct reports.
Mark Fuchs and I conducted interviews for the Inventory & Procurement Foreperson position on February 7, five interviews in total. The position is expected to be filled before the March Commission meeting.
I have worked with staff on the final distribution vs transmission allocations for costs associated with the Waco 2 Substation project. This allocation plays a significant part in future revenues associated with our MISO Attachment O filing. Theresa Slominski, our
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accountants, Mark Fuchs, and Mike Tietz put in many hours with this allocation as well as our recent entire MISO Attachment O initiative.
Mike Tietz, Jennie Nelson, and I have held our initial internal meeting to review the Cyber and Physical Security report from FRSecure. The information was analyzed for needs as we develop the IT position job description in addition to developing next steps for resolving identified issues. Yet in 1Q2018 the Information Security Committee will schedule a meeting to review the report and develop action items preceding the beginning of the budget process for 2019.
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UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13, 2018 SUBJECT: Staff Update ACTION REQUESTED: None
FROM: Theresa Slominski – Finance & Office Manager AGENDA ITEM NUMBER: 6.1b
DISCUSSION: As a follow-up from last month, the running PCA balance at December 31, 2017 was a credit of $150,405. We had a large credit of $485,625 at the beginning of 2017 with the balance brought forward from the prior year. We decided to retain part of it to offset 2017 anticipated PCA charges and returned $245,799 to customers in March 2017. Accumulated PCA charges and credits for 2017 totaled a charge of $89,421.
Our first full month of cycled billings completed and we are now in our second month. The processes occurring each week have gone smoothly and staff seems to be settling in well to the change. The biggest hurdle was the volume of phone calls from customers who were unaware of the change, and therefore, confused, or who were just upset that the change was occurring and their payment date was moving. We did also hear from some individuals who were pleased with their billing and related payment date(s) moving. This has been a long planning process of almost a full year to implement the change to cycled billing, and a huge commendation goes to Jennie Nelson for its success upon rollout. MANY people helped with the implementation and so efforts of Michelle V., Michelle M., Mike Tietz, the CSR group, and the metering group should also be commended.
With the cycle change, it was noticed that the payments outstanding at the due date were much higher than normal (almost twice) in the early cycles. We speculated this was due to the short duration between billings, and given the heightened sensitivity to the change in payment dates, decided to not apply penalties this month. Penalties average around $20,000 per month and so that will be a slight change in January’s financials when comparing year to year.
Melissa, our Accountant, had a baby boy January 24, 2018 and will be out on maternity leave for twelve weeks. Our Purchasing Specialist, Geri, has given her notice and so we will be bringing in a temporary staff member until that position is replaced.
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UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13, 2018 SUBJECT: Staff Update ACTION REQUESTED: None
FROM: Mark Fuchs – Electric Superintendent AGENDA ITEM NUMBER: 6.1c
DISCUSSION: Had six new house services. Continue working on collecting data with the GPS for our ArcView maps as time permits. Finished working in Connexus acquisition Areas 3&4. Continue rebuilding the overhead line south of 197th Avenue to 190 ½ Lane on the east side of Highway 169. Carr’s tree trimming service is helping out with tree trimming this year to help get caught up with the areas we acquired from Connexus. We are also tree trimming. Due to slippery road conditions, a vehicle hit a three phase pole on County Road 39 in Otsego. We also had a few other incidents due to the road conditions which resulted in some street light poles being hit. Working on testing the overhead and underground protective grounds. We are also testing the fiberglass hot sticks. Both of these are done annually. Changed out a single phase angle pole on 201st Avenue; this pole had tested bad last year but due to the wet ground conditions, we had to wait until it froze up to get in there to change it out. Energized the three phase pad mount transformer for the new addition at the Sherburne County Courthouse. The bore rig operators put a new set of tracks on the bore rig. The rubber on the old tracks had worn off and the steel was starting to damage the asphalt and curbs. Working on getting equipment ordered that was in the 2018 budget. The 550 truck has been ordered and the utility box will get put on once we receive the chassis, triple bunk self-loading trailer has been ordered and getting specs together for the bucket truck so the Altec engineers can put drawing together for us to review. I recently attended the MMUA Job Training and Safety Committee (JTS) Annual Planning Meeting held January 17-18 in Brainerd, MN. The JTS Committee assists in setting up the upcoming schools that MMUA puts on.
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UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13th, 2018 SUBJECT: Staff Update ACTION REQUESTED: None
FROM: Mike Tietz –Technical Services Superintendent AGENDA ITEM NUMBER: 6.1d
DISCUSSION: In January, the Locating department had a total of 103 locate tickets consisting of six emergency tickets, 3 cancellations, 5 meetings, 67 normal tickets and 18 updated tickets. This is a 4% increase in volume of tickets from the previous month. The locators are continuing to gather GPS points, averaging about 50 data points per day.
Electric Technicians continue with updating power bill, substation checks, disconnects, reconnects, dealing with meter and off-peak issues, as well as installing new meters for commercial customers. Staff completed the reprogramming of all non-demand meters within their appropriate billing cycles.
The weekly meter reads have been going very well according to staff. We have implemented a backup computer into a rotation schedule as well as cross-training staff to have a redundancy in the reading process. Staff continues to perform meter audits around the system as time allows.
On January 17, the power plant staff worked with Princeton Public Utilities staff to resolve our issue with engine #4. Staff performed the monthly run on January 30. All engines ran well, however we developed a coupling leak on engine #1’s fuel rail. We will replace the coupling gaskets on engines 1 & 2 proactively. Also during the run, it was discovered that we had developed a leak in one of the oil cooling pipes for engine #4. Staff welded a patch onto it to seal it up.
Mapping department continues to enter GPS points and attribute points for all of our systems assets within the ESRI ArcView GIS system. Electronic CAD maps continue to be updated as well as the 2018 paper map books have been printed for field staff use. The budgeted ArcGIS Server software has been quoted from ESRI and we are looking to have it in production by the end of 1st quarter.
An order has been placed for the replacement locator pickup truck. This budgeted vehicle was ordered from Midway Ford as they had quoted the lowest State Contract price. Cornerstone Automotive also submitted a quote, but was substantially higher.
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UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13, 2018 SUBJECT: Staff Update ACTION REQUESTED: None
FROM: Eric Volk – Water Superintendent AGENDA ITEM NUMBER: 6.1e
DISCUSSION: Delivered eleven new water meters. Sealed the water meter, and took curb stop ties from eleven water services. Completed 25 BACTI/Total Chlorine Residual Samples o All confirmed negative for Coliform Bacteria o Bacteriological/Disinfectant Residual Monthly Report submitted to the MDH Completed 20 routine fluoride samples o All samples met MDH standards o Submitted MDH Fluoride Report Submitted MPCA Discharge Monitoring Report (DMR) for the Diesel Generation Plant Completed and submitted the Annual Withdrawal Report for the Water Department to the Minnesota Department of Natural Resources. Completed and submitted the Annual Usage Report for lake water cooling usage to the Minnesota Department of Natural Resources. WTP #5 is in the process of getting sandblasted and painted. We expect to have the painting done and the well back online by April 1. The water operators have been working on making repairs to the water treatment plants in anticipation of the upcoming pumping season. The initial site plan for the field services expansion went to the site plan review committee on February 5 for comments. We will be meeting with Kodet Architectural on February 21 at 10 a.m. in the ERMU Conference Room. The City received their updated ISO Fire Protection Classification. The overall rating was increased from 5/10, to 4/10. The increase was due to efficiencies in maintenance and operations. ATTACHMENTS: January 2018 Pumping by Well January 2018 Accumulated Precipitation Graph January 2018 Daily Temperature Graph
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January 2018 Monthly Pumping By Well
Well #2, 9.633, 20% Well #9, 19.448, 40% Well #3, 6.493, 13%
Well #4, 10.49, 22%
Well #8, 0, 0% Well #7, 0.136, 0% Well #6, 2.194, 5%
Well #5, 0, 0%
Values Are Displayed in Millions of Gallons (Well #, Gallons Pumped, Percentage of Pumping)
158
159
160
UTILITIES COMMISSION MEETING TO: ERMU Commission MEETING DATE: February 13, 2018 SUBJECT: Staff Update ACTION REQUESTED: None
FROM: Tom Sagstetter – Conservation & Key Accounts Manager AGENDA ITEM NUMBER: 6.1f
DISCUSSION: Reviewed the FleetCarma study results with the Great Plains Institute (GPI). Based on the results from the ERMU EV Suitability Assessment, the Minnesota Drive Electric organization along with GPI have organized a meeting with Xcel Energy to aid in their decision making process to offer an EV fleet program to Minnesota customers. Also attended a meeting at the Minnesota Pollution Control Agency to learn about how the VW Settlement funds may be distributed in Minnesota. The level two charger downtown has had 31 charging sessions, providing customers with 141 kWh of green energy; and the DC fast charger at the Coborn’s fuel station has had 41 sessions providing 319 kWh of green energy to customers. There has been a communication issue with the Combo charging plug on the DC fast charger over the past two weeks resulting in it not being able to charge. ChargePoint is dispatching a technician to correct issue and may need to replace the combination charging portal.
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UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Tom Sagstetter – Conservation and Key Accounts Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2018 6.2 SUBJECT: Landfill Gas Plant to Electric Generation Facility Performance for 2017 ACTION REQUESTED: None BACKGROUND: Consistent with contractual provisions, each year ERMU can provide bonus payments to Sherburne County and Waste Management/Elk River Landfill provided the financial means and plant capacity factors are met. DISCUSSION: For the calendar year of 2017 the landfill gas plant had a capacity factor of 93.3% and generated approximately 25 million kWh. The production was steady and the overall costs of the plant were manageable. The production level fell below the 95% capacity factor threshold; therefore no bonus payment will be made to Waste Management. The overall operating costs for the landfill gas plant acceptable for 2017 with no extra ordinary expenses or failures. Also, Waste Management was very efficient in the routine maintenance for 2017 and kept the operation and maintenance costs very reasonable. Based on the 2017 overall performance of the landfill gas plant project Sherburne County will receive a payment of $25,000. The landfill gas plant produced approximately 25 million kWh which is enough electricity to supply 2,850 average residential customers in Elk River for one year. The landfill gas to electric plant generated the equivalent of 8% of ERMU total sales for 2017. The bonus payments are not guaranteed and can change or be eliminated based on the variability of labor, material, unexpected or increased maintenance costs, or loss of production for various reasons. FINANCIAL IMPACT: As outlined above. ATTACHMENTS: Letter to Waste Management – LFG to Electric Generation Facility Performance for 2017 Letter to Sherburne County – LFG to Electric Generation Facility Performance for 2017 ______________________________________________________________________________ Page 1 of 1 162
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UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Tom Sagstetter – Conservation and Key Accounts Manager MEETING DATE: AGENDA ITEM NUMBER: February 13, 2018 6.3 SUBJECT: Electric Vehicle Suitability Assessment Presentation ACTION REQUESTED: None BACKGROUND: In 2017, ERMU received a grant from the American Public Power Association. As part of the grant, ERMU was to work with the City of Elk River to do an Electric Vehicle Assessment Study. This study was conducted by FleetCarma. The study period was from March 2017 through November 2017. The study evaluated 20 vehicles including 8 from the Utilities and 12 from the city fleet. The results were presented in December to both City of Elk River and ERMU staff. DISCUSSION: Staff will present the Electric Vehicle Suitability Assessment presentation. FINANCIAL IMPACT: N/A ATTACHMENTS: Electric Vehicle Suitability Assessment Presentation
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Elk River Municipal Utilities Electric Vehicle Suitability Assessment Presentation
166
The world is transitioning to electric vehicles. This transition must be done quickly and effectively. FleetCarma is a telematics platform, uniquely capable of supporting the transition to electric vehicles, focused on successful adoption & ownership experience.
FleetCarma Telematics Platform
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Planning for EV Adoption with Confidence What will my electricity costs be?
What will my fuel economy be?
What is my operating cost per mile?
What’s my payback using my criteria? How long will my EV fleet need to charge for?
What about my maintenance costs? What charging infrastructure will we need?
… by taking a data-driven and customized approach
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Will we need BEVs or PHEVs?
The EV Utilization Challenge for Fleet Operators
Battery Electric Vehicles (BEV) need to: •
Plug-In Hybrid Electric Vehicles (PHEV) need to:
Be range capable for their fleet application, while keeping vehicle utilization high
Elk River Municipal Utilities EV Suitability Assessment
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Maximize their electric driving as a proportion of total utilization by ensuring vehicles get pluggedin
Fleet Benchmark to Evaluate EV Adoption Scenarios
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Benchmarking ICE Vehicle Utilization
2010 Ford Fusion
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Sample Fleetwide Dashboard in Web-Portal
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Fleet Daily Utilization and Fuel Economy Benchmark
•
80% drove less than 50 miles per day
•
97% drove less than 100 miles per day Many duty cycles that are range capable for BEVs & PHEVs
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Driver Behaviour Benchmark
•
62% of drivers have less than a 15% hard acceleration score
•
33% of drivers have less than a 15% hard braking score
These Eco-Driver Behaviour scores indicate an opportunity within your fleet to review safe driving practices. Smooth braking and smooth acceleration can help reduce maintenance costs over the life of the vehicle. For an electric vehicle, smooth braking allows for more energy to be captured via the regenerative braking process.
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TCO Savings Potential and Environmental Impact
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Optimal EV Deployment
Assuming the baseline measured range gives enough flexibility for your drivers needs – this is the recommended EV deployment.
This would reduce your total cost of ownership by $76,607 over approximately a 7 year service life.
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Best Fit Duty Cycles for EV Replacement
The assessment revealed that 8 of the baseline vehicles included in the program are suitable to be replaced with an electric vehicle based on economic and operational feasibility
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TCO Scenario Analysis Current TCO: $812,344 Recommend EV Deployment TCO: $735,737 $76,607 in savings across 8 vehicles with an average service life of 7 years
Nissan Leaf
Ford C-Max Energi
The Nissan Leaf 2017 model has a range of 107 miles and the 2018 model will have a range of 150 miles.
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Range = 19 miles electric 550 miles combined
Size Comparable EV Deployment
The assessment revealed that 8 of the baseline vehicles included in the program are suitable to be replaced with an electric vehicle based on economic and size comparability
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Size Comparable EV Deployment Looking at the best size comparable options for the vehicles that could not be downsized, we found that your fleet would be best suited to: 7 Mitsubishi Outlanders PHEV 1 Kia Soul EV This would see an additional TCO Savings of $81,708, saving $158,315 across 16 vehicles in your fleet.
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2018 Recommendations
• Recommend Purchase 2017 Chevy Bolt – Range of 238 miles is best in class for BEV – MN State Bid contract price $33,620 • • • •
7.2 kW high voltage charging 200 hp (150 kW) electric drive 60 kWh lithium-ion battery Regenerative braking to extend range
– Second year on State Bid • Recommendation from MN Office of Enterprise Sustainability is for the Chevy Bolt over Nissan Leaf for pricing, performance, and range. Elk River Municipal Utilities EV Suitability Assessment
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HANDOUT AT MEETING