February 13, 2018


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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

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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

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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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9:44:26 AM

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:

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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

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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

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

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150.00 4,795.00 1,277.92 50,439.50

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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

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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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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

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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

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

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1,197.00

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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 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

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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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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

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11,990.59

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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

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32.85

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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

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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

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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

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

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480.00

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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

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6,603.50 6,803.94

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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

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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

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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

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5,591.76 9,028.69 -950.00 100.78 218,165.84

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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

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

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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

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-1.99 -20.29

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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

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

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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

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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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

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80.00 -105.22

Elk River Municipal Utilities 02/05/2018

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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

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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

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125.03 819.31

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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

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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.

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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.

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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

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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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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES

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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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES

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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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES

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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SCHEDULE 3 – INTERCONNECTION PROCESS, TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES

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.

Interconnection Process for Distributed Generation 98 Systems

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

______________________________________________________________________________ Page 2 of 3 120

    

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

______________________________________________________________________________ Page 3 of 3 121

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

163

164

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

Elk River Municipal Utilities EV Suitability Assessment

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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



169

Maximize their electric driving as a proportion of total utilization by ensuring vehicles get pluggedin

Fleet Benchmark to Evaluate EV Adoption Scenarios

Elk River Municipal Utilities EV Suitability Assessment

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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