REGULAR MEETING OF THE September 10, 2013, 3:30 P.M. …96bda424cfcc34d9dd1a-0a7f10f87519dba22d2dbc6233a731e5.r41.… · 4.0 OLD BUSINESS . 4.1 Freeport Water Tower Rehabilitation

REGULAR MEETING OF THE UTILITIES COMMISSION

September 10, 2013, 3:30 P.M. Utilities Conference Room

Mission Statement: To provide our customers with safe, reliable, cost effective and quality long

term electric and water utility service. To communicate and educate our customers in the use of

utility services, programs, policies, and future plans. These products and services will be

provided in an environmentally and financially responsible manner.

AGENDA ITEM ACTION TAKEN 1.0 CALL MEETING TO ORDER 1.1 Pledge of Allegiance 1.2 Consider the Agenda 2.0 CONSENT AGENDA (Approved by one motion.) 2.1 Check Register 2.2 Previous Meeting Minutes 2.3 Financial Statements 2.4 Minnesota Municipal Utilities Association 2013-2014 Safety Program Contract 2.5 Resolution Accepting NISC’s MIC Invitation 3.0 OPEN MIC (Non-agenda items from guests, no action taken.) 4.0 OLD BUSINESS 4.1 Freeport Water Tower Rehabilitation Project Update 4.2 North Substation Upgrade Project Update 5.0 NEW BUSINESS 5.1 2014 Budget: 10-Year Capital Project Projections, 2014 Capital Projects and

Equipment Purchases, and 2014 Conservation Improvement Program (CIP) 5.2 Minnesota Municipal Utilities Association Annual Summer Conference Update 5.3 Triple Feeder Rebuild Contractor Bids 5.4 Integrity Testing and Demand Bill

6.0 OTHER BUSINESS 6.1 Staff Updates 6.2 Set Date for Next Meeting 6.3 Closing of Meeting: “Meeting to be Closed pursuant to MN Statute

13D.05, Subd. 3(c)(3) to develop or consider offers or counteroffers for the purchase or sale of real or personal property.”

a Call Closed Session to Order b Discussion c Adjourn Closed Session

6.4 Adjourn Regular Meeting 13069 Orono Parkway, P.O. Box 430, Elk River, MN 55330-0430 ▪ 763-441-2020 ▪ www.elkriverutilities.com

http://www.elkriverutilities.com/

AUG 2013 PAYROLL REGISTER

HOURS $ AMOUNT

8/2/2013 2957.50 REGULAR HOURS $94,866.7836.00 OVERTIME HOURS $1,729.57

1.00 DOUBLE TIME HOURS $56.1848.00 ON-CALL $1,364.66

0.00 BONUS PAY $0.002.00 FLSA $53.631.50 REST TIME $58.35

TOTAL $98,129.17




TOTAL $99,589.42




TOTAL $98,227.25

Grand Total $295,945.84

1

ELK RIVER MUNICIPAL UTILITIESCheck Register - Detail

9/5/2013 2:43:50 PM Page 1 of 11

Check # Date Acct# Name Amount648 8/2/2013 JUDY MCSPADDEN 517.4761-0001-3419 HOME COMPUTER PURCHASE COMPUTER 517.47

649 8/9/2013 MICHELLE MARTINDALE 64.6361-0920-9305 EXPENSES FOR RTS WELLNESS TRAINING EXPENSE 64.63

650 8/22/2013 SELECTACCOUNT 36.6061-0920-9261 PARTICIPANT FEE FOR FLEX BENEFITS 008217 29.2862-0920-9261 PARTICIPANT FEE FOR FLEX BENEFITS 008217 7.32

651 8/23/2013 ELK RIVER MUNICIPAL UTILITIES DEBIT CARD 10.13DEBIT CARD61-0920-9269 SUPPLIES FOR CIP LOW INCOME DEBIT 10.13

652 8/30/2013 BETTY BELANGER 102.0061-0001-3323 SICK TIME PAY OUT SICK 102.00

653 8/27/2013 ELK RIVER MUNICIPAL UTILITIES DEBIT CARD 18.00DEBIT CARD61-0920-9305 FUEL FOR COMPASS FOR TRIP TO ALBERT LEA-NISC SOFTWAREDEBIT 18.00

654 8/22/2013 ELK RIVER MUNICIPAL UTILITIES DEBIT CARD 108.36DEBIT CARD61-0920-9305 HOTEL ROOM FOR M. PRICE DEBIT 86.6962-0920-9305 HOTEL ROOM FOR M. PRICE DEBIT 21.67

*64668 8/1/2013 AMERICAN SAFETY UTILITY CORP 114.87 *61-0580-5881 SUNSCREEN 54536 114.87

64669 8/1/2013 BADGER STATE INSPECTION, LLC 19,963.0062-0001-1071 FREEPORT WATER TOWER RECONDITIONING PROJECT100132 19,963.00

64670 8/1/2013 BLUE WATER PLUMBING, INC. 650.0062-0730-7315 MTC OF IRRIGATION SYSTEM 5258 650.00

64671 8/1/2013 CITY OF ELK RIVER 227,564.6361-0001-1671 ARMER RADIO ANNUAL FEE 201307123432 2,700.0062-0001-1671 ARMER RADIO ANNUAL FEE 201307123432 675.0061-0001-3371 10A GO IMP BOND INTEREST 201307123431 13,920.0062-0001-3371 10A GO IMP BOND INTEREST 201307123431 3,480.0061-0590-5995 ELECTRIC DEPT FUEL USAGE - MAY 2013 201307123433 2,560.4062-0730-7395 WATER DEPT FUEL USAGE - MAY 2013 201307123433 791.1761-0597-8172 SECURITY FUEL USAGE - MAY 2013 201307123433 424.0262-0730-7395 PARTS & LABOR TO REPAIR UNIT #14 201307123434 207.5361-0590-5995 PARTS & LABOR TO REPAIR UNIT #20 201307123435 58.8062-0710-7220 PARTS & LABOR TO REPAIR WELL #6 GENERATOR 201307123436 189.9561-0597-8172 PARTS & LABOR TO REPAIR UNIT #19 201307123437 39.5362-0710-7220 PARTS & LABOR TO REPAIR WELL #5 GENERATOR 201307123438 307.0462-0730-7395 PARTS & LABOR TO REPAIR UNIT #14 201307123439 265.9461-0001-3324 SEWER BILLED - JUNE 2013 JUNE 2013 132,215.5261-0597-8262 REVENUE TRANSFER - JUNE 2013 JUNE 2013 71,031.0861-0001-3416 SALES TAX FOR DONATED ELECTRICITY - JUNE 2013JUNE 2013 (1,301.35)

*64673 8/1/2013 ELK RIVER WINLECTRIC CO 102.57 *61-0001-1551 PVC CONNECTORS, BUSHINGS & LICK RINGS 194256 00 28.9361-0540-5491 FUSE 194433 00 22.0961-0540-5491 FUSE 194496 00 51.55

64674 8/1/2013 FASTENAL COMPANY 402.2361-0590-5995 PART FOR TRUCK #11 MNELK46162 402.23

64675 8/1/2013 GRANITE ELECTRONICS INC 131.0061-0590-5995 REPAIR PAGER 247227 131.00

64676 8/1/2013 HD SUPPLY WATERWORKS, LTD. 501.4062-0730-7302 VALVE BOX RISERS B200131 501.40

64677 8/1/2013 HOME DEPOT #2821 96.00ER61-0920-9269 COUPONS (CFL-8x$2.00) (LED - 16x$5.00) COUPONS 96.00

64678 8/1/2013 INNOVATIVE OFFICE SOLUTIONS, LLC 60.2762-0920-9211 OFFICE SUPPLIES IN0318674 60.27

64679 8/1/2013 KMS COMPANIES INC 144.95

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9/5/2013 2:43:50 PM Page 2 of 11

Check # Date Acct# Name Amount61-0920-9269 POSTAGE FOR MAILING COMMERCIAL REBATE BROCHURES120 144.95

64680 8/1/2013 M. R. DANIELSON ADVERTISING 580.0061-0920-9211 WEBSITE UPDATES 3-13 THRU 7-13 ELK/WW-14 464.0062-0920-9211 WEBSITE UPDATES 3-13 THRU 7-13 ELK/WW-14 116.00

64681 8/1/2013 MCGRANN SHEA CARNIVAL STRAUGHN & LAMB 1,550.0061-0920-9221 LEGAL FEES FOR SERVICE TERRITORY 99312 1,550.00

64682 8/1/2013 MINUTEMAN PRESS 1,510.2061-0920-9269 COMMERCIAL REBATE BROCHURES 12234 765.2361-0920-9211 CONNECTOR 12206 583.8862-0920-9211 CONNECTOR 12206 145.9661-0920-9211 ONLINE BILLING FLYER 12211 15.13

64683 8/1/2013 MMUA 113.5961-0920-9303 2013 MMUA MEMBERSHIP DIRECTORY 41602 113.59

64684 8/1/2013 SPEEDCUTTERS OUTDOOR MAINTENANCE LLC 850.7361-0580-5881 LAWN MOWING SERVICES - JULY 2013 3480 170.1562-0730-7341 LAWN MOWING SERVICES - JULY 2013 3480 680.58

64685 8/1/2013 STUART C. IRBY CO. 1,620.2961-0580-5881 GLOVES & TESTING S007504802.0011,620.29

64686 8/1/2013 TENSION ENVELOPE CORPORATION 4,505.2661-0900-9051 ECO ENVELOPES 656639 3,604.2162-0900-9051 ECO ENVELOPES 656639 901.05

64687 8/1/2013 WESCO RECEIVABLES CORP. 156.7561-0580-5881 BUSHING ADAPTER FOR TOOLS 566105 156.75

64688 8/1/2013 ODLAND PROTECTIVE COATINGS, INC. 300,152.5062-0001-1071 RECONDITIONING OF FREEPORT WATER TOWER 1 300,152.50

64689 8/8/2013 AMARIL UNIFORM COMPANY 1,051.0562-0730-7341 FR CLOTHING FOR: A. HAUGE IV41764 1,051.05

64690 8/8/2013 AMERICAN EXPRESS 2,073.7061-0920-9305 MMUA SUMMER MTG 8/13/2013 31006 2,073.70

64691 8/8/2013 BATTERIES PLUS 206.1761-0001-1552 BATTERIES 033-860693 136.2761-0597-8172 BATTERIES 033-860693 23.7361-0001-1552 BATTERIES 033-860756 46.17

64692 8/8/2013 BLUE EGG BAKERY 6.0061-0920-9305 COOKIES FOR MEETINGS 0568 6.00

64693 8/8/2013 CARTRIDGE WORLD 277.8361-0920-9211 REFILL FOR PRINTER INK CARTRIDGES 127866 277.83

64694 8/8/2013 CITY OF ELK RIVER **VOID**61-0001-3325 GARBAGE BILLED - JULY 2013 JULY 2013 109,270.0961-0001-3328 FRANCHISE FEE - JULY 2013 JULY 2013 (60,710.56)

64695 8/8/2013 CUB FOODS - ELK RIVER 175.4361-0920-9269 COUPONS (CFL 2x$2.00) STMT 0.0461-0540-5484 PLANT SUPPLIES STMT 175.39

64696 8/8/2013 ELK RIVER MUNICIPAL UTILITIES 27,999.8861-0920-9212 ELECTRICITY FOR: ORONO PARKWAY 6172 1,640.8762-0920-9212 ELECTRICITY FOR: ORONO PARKWAY 6172 410.2261-0540-5483 ELECTRICITY FOR: 1705 MAIN ST BY DAM 15499 53.5662-0710-7181 ELECTRICITY FOR: GARY ST WATER TOWER 21243 56.2261-0580-5881 ELECTRICITY FOR: UTILITIES GARAGE 182 354.6261-0540-5483 ELECTRICITY FOR: POWER PLANT SUB FANS 6812 44.8961-0540-5483 ELECTRICITY FOR: 1705 MAIN ST POWER PLANT 183 3,247.6861-0540-5483 ELECTRICITY FOR: 1697 MAIN ST 3251 586.1862-0710-7181 ELECTRICITY FOR: 268 ELK HILLS WATER BOOSTER2706 98.2062-0710-7181 ELECTRICITY FOR: WATER TOWER #3 2719 203.62

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Check # Date Acct# Name Amount62-0710-7181 ELECTRICITY FOR: WATER TOWER #3 REPEATER 25188 63.2862-0710-7181 ELECTRICITY FOR: 12955 MEADOWVALE RD WATER BOOSTER9605 91.2762-0710-7181 ELECTRICITY FOR: WATER TOWER #4 11001 63.4161-0540-5483 ELECTRICITY FOR: 1705 MAIN ST 27601 62.7962-0710-7181 ELECTRICITY FOR: WELL #3 239 1,371.6561-0550-5052 LFG PLANT GENERATION 2125 44.8962-0710-7181 ELECTRICITY FOR: WELL #5 8318 2,696.7762-0710-7181 ELECTRICITY FOR: WELL #4 118 2,613.8062-0710-7181 ELECTRICITY FOR: WELL #2 1990 1,148.6662-0710-7181 ELECTRICITY FOR: WELL #7 8606 4,198.3062-0710-7181 ELECTRICITY FOR: WELL #6 227 3,449.2762-0710-7181 ELECTRICITY FOR: WELL #8 13535 2,581.7462-0710-7181 ELECTRICITY FOR: WELL #9 20795 2,917.99

*64698 8/8/2013 G & K SERVICES SERVICES 93.41 *61-0920-9211 MATS & TOWELS 1043494888 74.7362-0920-9211 MATS & TOWELS 1043494888 18.68

64699 8/8/2013 GRAND RENTAL STATION 492.6161-0590-5995 CHAIN FOR CHAINSAW 194738-1 11.7361-0590-5995 CHAINSAW FOR TRUCK #4 194737-1 480.88

64700 8/8/2013 GRANITE ELECTRONICS INC 52.9061-0580-5881 CHARGER 453498 52.90

64701 8/8/2013 HAWKINS, INC. 2,683.9162-0710-7183 WATER TREATMENT CHEMICALS 3491471 RI 2,683.91

64702 8/8/2013 HD SUPPLY WATERWORKS, LTD. 48.8462-0730-7315 FLANGE AND GASKET B224546 48.84

64703 8/8/2013 JT SERVICES 6,123.9461-0001-1551 FIBERCRETE BOXPAD JT13-199-09 5,664.3861-0590-5941 FIBERCRETE BOXPAD JT13-199-09 459.56

64704 8/8/2013 LEHMANN'S OUTDOOR POWER EQUIPMENT 35.0061-0590-5995 REPAIR CHAIN SAW 177184 35.00

64705 8/8/2013 MARTIES FARM SERVICE INC 48.0961-0590-5933 GRASS SEED STMT 48.09

64706 8/8/2013 MENARDS 502.8761-0001-1071 PARTS & SUPPLIES STMT 11.9861-0540-5484 PARTS & SUPPLIES STMT 85.3161-0590-5992 PARTS & SUPPLIES STMT 14.3362-0710-7181 PARTS & SUPPLIES STMT 249.7262-0710-7220 PARTS & SUPPLIES STMT 10.5862-0730-7301 PARTS & SUPPLIES STMT 36.4462-0730-7331 PARTS & SUPPLIES STMT 94.51

64707 8/8/2013 MINNESOTA PIPE & EQUIPMENT 328.9462-0730-7331 GALLON FOR HYDRANT OIL AND PAINT 0301096 328.94

64708 8/8/2013 MMUA 1,100.0061-0920-9303 2013 MMUA MEMBERSHIP DIRECTORY BALANCE 41602 20.0061-0920-9305 ANNUAL SUMMER CONFERENCE AT MADDEN'S RESORT41625 1,080.00

64709 8/8/2013 MUELLER CO 9,947.4062-0001-1561 WATER METERS W/ERT'S & CONNECTIONS 2664473 9,947.40

64710 8/8/2013 NAPA AUTO PARTS 10.6861-0590-5995 PARTS & SUPPLIES FOR TRUCKS STMT 10.68

64711 8/8/2013 O'REILLY AUTOMOTIVE STORES, INC 57.6861-0590-5995 PARTS & SUPPLIES FOR TRUCKS STMT 57.68

64712 8/8/2013 OFFICE MAX INCORPORATED 76.48OFFICE61-0920-9211 OFFICE SUPPLIES 825140 76.48

64713 8/8/2013 PLAISTED COMPANIES, INC. 383.4661-0001-1071 PULVERIZED BLACK DIRT 49088 191.73

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Check # Date Acct# Name Amount61-0590-5933 PULVERIZED BLACK DIRT 49088 191.73

64714 8/8/2013 POSTMASTER 12,000.0061-0001-1671 POSTAGE FOR PERMIT # 38 POSTAGE 9,600.0062-0001-1671 POSTAGE FOR PERMIT # 38 POSTAGE 2,400.00

64715 8/8/2013 PRIME ADVERTISING & DESIGN, INC. 375.2561-0597-8172 ADVERTISING FOR SECURITY DEPT - 2013 417 375.25

64716 8/8/2013 RANDY'S SANITATION, INC. 1,449.0661-0920-9211 DOCUMENT RECYCLING 1-192934-5 15.1861-0580-5881 TRASH SERVICE 1-38546-5 1,433.88

64717 8/8/2013 RESCO 6,795.0561-0001-1551 COMPRESSION SLEEVES 542299-01 259.9261-0001-1551 CLAMP HOT LINE 547122-00 499.1161-0001-1551 CABLE URD 2/0 TRIPLEX 547218-00 6,036.02

64718 8/8/2013 RIKE-LEE ELECTRIC INC. 540.6261-0001-1071 PARTS & SUPPLIES FOR RIVERVIEW HEIGHTS REBUILD140-4776 540.62

64719 8/8/2013 SPEEDCUTTERS OUTDOOR MAINTENANCE LLC 698.9661-0580-5881 LAWN FERTILIZING SERVICES - JULY 2013 M1119 117.5762-0730-7341 LAWN FERTILIZING SERVICES - JULY 2013 M1119 581.39

64720 8/8/2013 SUMMIT SAFETY LLC 32.1762-0710-7181 COOLING HATS FOR WATER DEPARTMENT 37272A 32.17

64721 8/8/2013 TW HIPSAG ELECTRIC INC 330.0061-0920-9269 WIRED OFF PEAK AIR CONDITIONERS 23900 330.00

64722 8/8/2013 TRANSAMERICA LIFE INS. CO. 776.5261-0001-3425 LTC FOR ERMU EMPLOYEES -AUGUST 2013 GB59001080 776.52

64723 8/8/2013 TRI STATE SURPLUS CO. 147.0161-0920-9211 SHELVING AT PLANT 22097 147.01

64724 8/8/2013 UNITED SERVICES GROUP 623.1261-0590-5985 ENGINEERING SERVICES U1301E067 498.5062-0730-7325 ENGINEERING SERVICES U1301E067 124.62

64725 8/8/2013 UPS STORE #5093 68.2661-0920-9211 SHIPPING STMT 9.6761-0920-9211 SHIPPING STMT 58.59

64726 8/8/2013 WAL-MART 01-3209 50.0061-0920-9269 COUPONS (CFL- 25x$2.00) 439511 50.00

64727 8/8/2013 WINDSTREAM 545.7961-0920-9301 TELEPHONE 011702889 436.6462-0920-9301 TELEPHONE 011702889 109.15

64728 8/8/2013 ZIMMERMAN TODAY 158.0061-0597-8172 SECURITY ADVERTISING - JULY 2013 1085 79.0061-0597-8172 SECURITY ADVERTISING - AUGUST 2013 1086 79.00

64729 8/8/2013 CITY OF ELK RIVER 169,980.6561-0001-3325 GARBAGE BILLED - JULY 2013 JULY 2013 109,270.0961-0001-3328 FRANCHISE FEE - JULY 2013 JULY 2013 60,710.56

64730 8/13/2013 CHAD & ALINA BROSKI 81.722229961-0001-1421 Credit balance owed refund for 12456 194TH LN (Customer# 22299) 92.6462-0001-1421 Credit balance owed refund for 12456 194TH LN (Customer# 22299) (10.92)

64731 8/13/2013 BURNET TITLE 70.5361-0001-1421 Credit balance owed refund for 18239 DENVER ST (Customer# 28205) 76.0162-0001-1421 Credit balance owed refund for 18239 DENVER ST (Customer# 28205) (5.48)

64732 8/13/2013 CHASE HOME FINANCE 207.572891361-0001-1421 Credit balance owed refund for 10260 180TH CT (Customer# 28913) 307.5762-0001-1421 Credit balance owed refund for 10260 180TH CT (Customer# 28913) (100.00)

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Check # Date Acct# Name Amount64733 8/13/2013 EDINA REALTY 162.3725088

61-0001-1421 Credit balance owed refund for 11049 196TH AVE (Customer# 21026) 171.7362-0001-1421 Credit balance owed refund for 11049 196TH AVE (Customer# 21026) (9.36)

64734 8/13/2013 GARY & CYNTHIA GERVAIS 14.542627261-0001-1421 Credit balance owed refund for 10460 172ND LN (Customer# 26272) 14.54

64735 8/13/2013 JEFF HARRISON 23.622479361-0001-1421 Credit balance owed refund for 11978 191 1/2 AVE APT 104 (Customer# 24793)23.62

64736 8/13/2013 HOME TITLE, INC. 25.6961-0001-1421 Credit balance owed refund for 18559 OLSON ST (Customer# 25323) 47.5362-0001-1421 Credit balance owed refund for 18559 OLSON ST (Customer# 25323) (21.84)

64737 8/13/2013 LORIE & JIM IRWIN 10.062502561-0001-1421 Credit balance owed refund for 13701 214TH CT (Customer# 25025) 10.06

64738 8/13/2013 SCOTT & LORI PETERSON 10.06260761-0001-1421 Credit balance owed refund for 19839 NAPLES ST (Customer# 2607) 10.06

64739 8/13/2013 RYAN & ROBERTA RINTOUL 204.101840861-0001-1421 Credit balance owed refund for 17558 JOHNSON ST (Customer# 18408) (5.78)62-0001-1421 Credit balance owed refund for 17558 JOHNSON ST (Customer# 18408) 209.88

64740 8/13/2013 DARYL THOMPSON 55.3761-0920-9304 MILEAGE FOR MMPA ANNUAL MTG EXPENSE 55.37

64741 8/16/2013 ADI 1,383.8761-0001-1552 SECURITY MATERIALS XNGB5402 107.9961-0597-8172 SECURITY MATERIALS XNGB5402 13.4961-0001-1552 SECURITY MATERIALS XNGB5401 1,229.9561-0597-8172 SECURITY MATERIALS XNGB5401 32.44

64742 8/16/2013 ADVANTAGE BILLING CONCEPTS 100.0061-0597-8172 CODING FOR MED ALERT BILLING 9598 100.00

64743 8/16/2013 BATTERIES PLUS 85.2361-0001-1552 BATTERIES 033-802077-01 85.23

64744 8/16/2013 BECK LAW OFFICE 1,000.0061-0920-9221 GENERAL ADVICE AND COUNSEL JULY 2013 800.0062-0920-9222 GENERAL ADVICE AND COUNSEL JULY 2013 200.00

64745 8/16/2013 BORDER STATES ELECTRIC 14,590.3361-0001-1551 10 FT FIBERGLASS X-ARMS 905900481 1,571.7061-0001-1551 #500 15KV T-BODY ELBOWS 905933024 9,542.1261-0001-1551 2" PIPE STRAPS 905939992 11.8161-0001-1071 TRACER WIRE 905979613 2,582.4761-0580-5881 KELLEM GRIPS 905986080 94.5061-0580-5881 DRY TOWELS FOR URD MATERIAL 905992717 388.9261-0001-1551 COLD SHRINK SPLICES 906007308 104.1061-0580-5881 CABLE SEALING KITS & AQUA SEALS 906007309 294.71

64746 8/16/2013 CENTURYLINK 135.7461-0920-9301 TELEPHONE 612 E39-1065 436 108.5962-0920-9301 TELEPHONE 612 E39-1065 436 27.15

64747 8/16/2013 MICHAEL & LYNN CLASEN 180.912131061-0001-1421 Credit balance owed refund for 10937 177TH CT (Customer# 21310) 180.91

64748 8/16/2013 CROW RIVER FARM EQUIP CO 17.9061-0590-5995 PARTS & SUPPLIES STMT 17.90

64749 8/16/2013 DAKOTA SUPPLY GROUP, INC. 14,152.3861-0001-1551 240 VOLT PHOTO EYE 787318 232.4561-0001-1551 30' FIBERGLASS POLES & 6' MAST ARMS 7831667 13,992.6161-0920-9211 FREIGHT - OFFSETS ITRONS INVOICE 017600 7963707 (72.68)

64750 8/16/2013 GRAINGER 85.7461-0580-5881 URINAL SCREEN FOR PLANT 9198816184 85.74

64751 8/16/2013 HD SUPPLY WATERWORKS, LTD. 299.92

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9/5/2013 2:43:50 PM Page 6 of 11

Check # Date Acct# Name Amount62-0730-7311 CURB STOP COVER B242184 90.5762-0730-7301 WATER MAIN REPAIR KIT B249331 209.35

64752 8/16/2013 INNOVATIVE OFFICE SOLUTIONS, LLC 159.4661-0920-9211 OFFICE SUPPLIES IN0326598 159.46

64753 8/16/2013 MMUA 506.0061-0920-9305 NORTHWEST LINEMAN TRAINING: M. SCHWARTZ 41645 506.00

64754 8/16/2013 NORTHSTAR CHAPTER - APA 250.0061-0920-9305 2013 FALL CONFERENCE - K. SANDSTROM CONFERENCE 250.00

64755 8/16/2013 PLANT & FLANGED EQUIPMENT CO. 272.6162-0730-7321 WATER METER PARTS 0061295-IN 272.61

64756 8/16/2013 RESCO 464.9161-0001-1551 GROUNDING LUGS 547565-00 464.91

64757 8/16/2013 RESOURCE TRAINING & SOLUTIONS/BCBS 41,118.00BCBS61-0001-3415 HEALTH INSURANCE PREMIUMS FOR SEPT 2013 GA175-10 5 6,853.0061-0001-1671 HEALTH INSURANCE PREMIUMS FOR SEPT 2013 GA175-10 5 20,559.0062-0001-1671 HEALTH INSURANCE PREMIUMS FOR SEPT 2013 GA175-10 5 6,853.0062-0001-1671 HEALTH INSURANCE PREMIUMS FOR SEPT 2013 GA175-10 5 6,853.00

64758 8/16/2013 SPX TRANSFORMER SOLUTIONS, INC. 177,585.0061-0001-1071 TRANSFORMER FOR NORTH SUBSTATION 90008911 177,585.00

64759 8/16/2013 STUART C. IRBY CO. 698.3261-0001-1551 BUSHING INSERT S007690261.001 698.32

64760 8/16/2013 TRI CAP 560.392817761-0920-9269 LOW INCOME - CLOTHES WASHER 1787 560.39

64761 8/16/2013 UMMA 75.0061-0920-9305 2013 UMMA SUMMER MEETING 2013 75.00

64762 8/16/2013 WATER CONSERVATION SERVICE, INC. 276.8862-0730-7310 LOCATE LEAK AT ANGEL & MORTON 4152 276.88

64763 8/16/2013 WATER LABORATORIES INC 350.0062-0710-7182 WATER TESTING FOR JULY 2013 3773 350.00

64764 8/16/2013 WESCO RECEIVABLES CORP. 682.9361-0001-1551 SERVICE SLEEVES 570577 32.0661-0001-1551 LED PHOTO CELL 570578 650.87

64765 8/16/2013 WRIGHT HENNEPIN INT'L RESPONSE CENTER 6,908.3561-0597-8172 MONTHLY MONITORING 329000 6,908.35

64766 8/16/2013 YP 115.7661-0597-8172 ADVERTISING 18197131 115.76

64767 8/21/2013 ALARM.COM INCORPORATED 9.0061-0597-8172 MONITORING FEES FOR VIDEOFIED SYSTEMS 314522 9.00

64768 8/21/2013 ALTERNATIVE DRY CLEANING CONSULTANTS 150.022901661-0001-3340 Deposit refunded for 10905 181ST LN (Customer# 29016) 150.0061-0001-3340 Deposit interest refunded for 10905 181ST LN (Customer# 29016) 0.02

64769 8/21/2013 AMERI-CORP 255.2461-0001-1421 ELECTRIC BILL REFUND FOR 12401 - 196TH CIR, ELK RIVER, MNREFUND 255.24

64770 8/21/2013 BARBARA BICKLEY 100.132722361-0001-3340 Deposit refunded for 11940 191 1/2 AVE APT 203 (Customer# 27223) 100.0061-0001-3340 Deposit interest refunded for 11940 191 1/2 AVE APT 203 (Customer# 27223) 0.13

64771 8/21/2013 SCOTT & ANN BREUER 250.142873361-0001-3340 Deposit refunded for 12245 194TH AVE (Customer# 28733) 250.0061-0001-3340 Deposit interest refunded for 12245 194TH AVE (Customer# 28733) 0.14

64772 8/21/2013 CENTRAL HYDRAULICS, INC. 47.2761-0590-5995 HOSE FOR 560 PLOW 0026735 47.27

7


9/5/2013 2:43:50 PM Page 7 of 11

Check # Date Acct# Name Amount64773 8/21/2013 CITY OF ELK RIVER **VOID**

61-0001-3324 SEWER BILLED - JULY 2013 JULY 2013 138,146.8461-0597-8262 REVENUE TRANSFER - JULY 2013 JULY 2013 69,473.83

64774 8/21/2013 COLDWELL BANKER VISION 150.122861661-0001-3340 Deposit refunded for 13182 RANCH RD (Customer# 28616) 150.0061-0001-3340 Deposit interest refunded for 13182 RANCH RD (Customer# 28616) 0.12

64775 8/21/2013 CONNEXUS ENERGY 2,535,572.24PUR PWR61-0540-5551 PURCHASED POWER 383399-1592772,536,740.1061-0440-4550 SUBSTATION CREDIT 383399-159277(1,167.86)

64776 8/21/2013 COOPER POWER SYSTEMS 66,259.2961-0001-1551 PADMOUNT SWITHGEAR 917138834 33,291.5661-0001-1551 PADMOUNT SWITHGEAR 917138835 32,967.73

64777 8/21/2013 CRC 1,963.6361-0900-9051 CUSTOMER SERVICE FOR AFTER HOURS 0080857 1,570.9162-0900-9051 CUSTOMER SERVICE FOR AFTER HOURS 0080857 392.72

64778 8/21/2013 DAKOTA SUPPLY GROUP, INC. 5,780.2361-0001-1551 SINGLE PHASE J-BOXES 7913293 5,780.23

64779 8/21/2013 ECM PUBLISHERS INC 552.7561-0597-8172 SECURITY ADVERTISING STMT 420.7561-0920-9302 JOB POSTING ADVERTISING STMT 132.00

64780 8/21/2013 EDINA REALTY 150.142848461-0001-3340 Deposit refunded for 9351 NASON CT NE (Customer# 28484) 150.0061-0001-3340 Deposit interest refunded for 9351 NASON CT NE (Customer# 28484) 0.14

64781 8/21/2013 EDINA REALTY 150.112857561-0001-3340 Deposit refunded for 9179 PACKARD LN (Customer# 28575) 150.0061-0001-3340 Deposit interest refunded for 9179 PACKARD LN (Customer# 28575) 0.11

64782 8/21/2013 ELK RIVER PRINTING 148.5661-0900-9051 RESIDENTAL CUSTOMER INFO SHEETS 033789 118.8562-0900-9051 RESIDENTAL CUSTOMER INFO SHEETS 033789 29.71

64783 8/21/2013 ELK RIVER WINLECTRIC CO 57.7561-0580-5881 CABLE TIES 195517 00 15.9261-0001-1551 2" PIPE STRAPS 195517 00 20.7962-0001-1071 PHOTOCONTROL FOR FREEPORT TOWER 195351 00 21.04

64784 8/21/2013 LEANNA BARUCCI & BRYON ENZLER 250.322046461-0001-3340 Deposit refunded for 11320 196TH LN (Customer# 20464) 250.0061-0001-3340 Deposit interest refunded for 11320 196TH LN (Customer# 20464) 0.32

64785 8/21/2013 FASTENAL COMPANY 24.3762-0730-7321 BOLTS FOR WATER METERS MNELK46566 24.37

64786 8/21/2013 G & K SERVICES SERVICES 93.4161-0920-9211 MATS & TOWELS 1043505331 74.7362-0920-9211 MATS & TOWELS 1043505331 18.68

64787 8/21/2013 ELIZABETH GITCHEL-HUSETH 7.382580261-0001-3340 Deposit refunded for 10978 178TH AVE (Customer# 25802) 7.38

64788 8/21/2013 JORDAN GOLDEN 64.622752261-0001-3340 Deposit refunded for 379 BALDWIN AVE APT G1 (Customer# 27522) 64.62

64789 8/21/2013 GOPHER STATE ONE-CALL 680.8561-0590-5943 LOCATES - JULY 2013 76217 340.4361-0590-5993 LOCATES - JULY 2013 76217 340.42

64790 8/21/2013 GREAT RIVER ENERGY 1,264.0061-0001-1071 WIRE FOR WACO SUBSTATION F1 4172 1,264.00

64791 8/21/2013 LYNDSAY GRELL 100.132207961-0001-3340 Deposit refunded for 1001 SCHOOL ST APT 117 (Customer# 22079) 100.0061-0001-3340 Deposit interest refunded for 1001 SCHOOL ST APT 117 (Customer# 22079) 0.13

8


9/5/2013 2:43:50 PM Page 8 of 11

Check # Date Acct# Name Amount64792 8/21/2013 HAWKINS, INC. 530.34

62-0710-7183 WATER TREATMENT CHEMICALS 3499555 RI 530.34

64793 8/21/2013 HD SUPPLY WATERWORKS, LTD. 121.2062-0730-7302 VALVE BOX RISERS B307766 121.20

64794 8/21/2013 FRANCINE & RODGER KEHN 250.322366061-0001-3340 Deposit refunded for 14253 184TH AVE NW (Customer# 23660) 250.0061-0001-3340 Deposit interest refunded for 14253 184TH AVE NW (Customer# 23660) 0.32

64795 8/21/2013 KENNEDY & GRAVEN, CHARTERED 350.0061-0920-9291 REDEMPTION OF 2004A ERMU BONDS EMAIL 350.00

64796 8/21/2013 EMILY KORHONEN 150.192572861-0001-3340 Deposit refunded for 10867 181ST LN (Customer# 25728) 150.0061-0001-3340 Deposit interest refunded for 10867 181ST LN (Customer# 25728) 0.19

64797 8/21/2013 SHIRLEE LANSING 250.322591461-0001-3340 Deposit refunded for 18149 GARY ST (Customer# 25914) 250.0061-0001-3340 Deposit interest refunded for 18149 GARY ST (Customer# 25914) 0.32

64798 8/21/2013 MINNESOTA RURAL WATER ASSOC 250.0062-0920-9305 TRAINING FOR A. HAUGE & P. NIELSEN TRAINING 250.00

64799 8/21/2013 MINNESOTA UNEMPLOYMENT INSURANCE 308.5261-0920-9241 UNEMPLOYMENT BENEFITS PAID 07991961 308.52

64800 8/21/2013 NETWORK TITLE, INC. 46.7461-0001-1421 ELECTRIC BILL REFUND FOR 19309 UPLAND ST., ELK RIVER, MNREFUND 46.74

64801 8/21/2013 NEW INNOVATIONS REALTY 250.272840561-0001-3340 Deposit refunded for 10228 180TH LN (Customer# 28405) 250.0061-0001-3340 Deposit interest refunded for 10228 180TH LN (Customer# 28405) 0.27

64802 8/21/2013 OFFICE MAX INCORPORATED 196.55OFFICE62-0730-7330 BATTERY BACK-UP FOR WELL #6 SCADA 062644 196.55

64803 8/21/2013 OLIVER SURVEYING & ENGINEERING, INC. 750.0061-0001-1071 STAKING PROPERTY LINES AND EASEMENT LINES 42489 750.00

64804 8/21/2013 PEARL PROPERTY INVESTMENTS 250.322801061-0001-3340 Deposit refunded for 1815 MEADOWVALE RD (Customer# 28010) 250.0061-0001-3340 Deposit interest refunded for 1815 MEADOWVALE RD (Customer# 28010) 0.32

64805 8/21/2013 ERIC & JENNIFER PEDERSON 100.132472861-0001-3340 Deposit refunded for 10214 175TH LN (Customer# 24728) 100.0061-0001-3340 Deposit interest refunded for 10214 175TH LN (Customer# 24728) 0.13

64806 8/21/2013 RDO EQUIPMENT 42.6261-0590-5995 TOGGLE SWITCH FOR BORE RIG P66817 42.62

64807 8/21/2013 MARTY RICHTER 42.422460961-0001-3340 Deposit refunded for 10866 181ST LN (Customer# 24609) 42.42

64808 8/21/2013 RUSSELL SECURITY RESOURCE INC. 307.1662-0001-1071 DOOR HANDLE & LOCK FOR FREEPORT TOWER A21980 307.16

64809 8/21/2013 SAFEGUARD PROPERTIES 250.012884761-0001-3340 Deposit refunded for 18572 TYLER DR (Customer# 28847) 250.0061-0001-3340 Deposit interest refunded for 18572 TYLER DR (Customer# 28847) 0.01

64810 8/21/2013 SAFEGUARD PROPERTIES LLC 250.102891761-0001-3340 Deposit refunded for 18281 TYLER ST (Customer# 28917) 250.0061-0001-3340 Deposit interest refunded for 18281 TYLER ST (Customer# 28917) 0.10

64811 8/21/2013 SAFEGUARD PROPERTIES 100.002834161-0001-3340 Deposit refunded for 10017 179TH AVE (Customer# 28341) 100.00

64812 8/21/2013 SCHARBER & SONS, INC. 360.4461-0590-5995 STREET PAD FOR JD BACK HOE P25069 360.44

64813 8/21/2013 BEN SCHULTZE 80.972552961-0001-3340 Deposit refunded for 8393 PARKVIEW AVE NE (Customer# 25529) 80.97

9


9/5/2013 2:43:50 PM Page 9 of 11

Check # Date Acct# Name Amount64814 8/21/2013 SHERBURNE COUNTY GOV. CENTER 15,549.00ZONING

61-0001-3210 PROMISSORY NOTE AND SECURITY AGREEMENT SEPT 2013 15,549.00

64815 8/21/2013 DONNIE & NICOLLE SOUNTHALA 100.132520061-0001-3340 Deposit refunded for 10201 180TH LN (Customer# 25200) 100.0061-0001-3340 Deposit interest refunded for 10201 180TH LN (Customer# 25200) 0.13

64816 8/21/2013 HOLLY SPIKE 28.462729661-0001-3340 Deposit refunded for 18594 GARY ST APT 3 (Customer# 27296) 28.46

64817 8/21/2013 SPRINT 367.9461-0920-9301 AIR CARDS FOR LAPTOPS 486255511-012 266.6262-0920-9301 AIR CARDS FOR LAPTOPS 486255511-012 66.6561-0597-8172 AIR CARD FOR LAPTOP 486255511-012 34.67

64818 8/21/2013 STUART C. IRBY CO. 560.1161-0580-5881 PROTECTORS S007727099.001 240.7861-0580-5881 RETURNING PROTECTORS S007703987.002 (233.74)61-0580-5881 GLOVE PROTECTORS FOR LINEMAN S007703987.001 507.8061-0001-1551 PIN FOR TERMINATOR S007690261.002 45.27

64819 8/21/2013 SUPERIOR SIGNALS, INC. 509.5561-0590-5961 ARROW LIGHT FOR TRAFFIC CONTROL 334580 509.55

64820 8/21/2013 DONNA SWANSON 80.102559761-0001-3340 Deposit refunded for 375 EVANS AVE APT 303 (Customer# 25597) 80.0061-0001-3340 Deposit interest refunded for 375 EVANS AVE APT 303 (Customer# 25597) 0.10

64821 8/21/2013 TOSHIBA FINANCIAL SERVICES 143.9761-0920-9211 MONTHLY CONTRACT FOR TOSHIBA COPIER 234168789 115.1862-0920-9211 MONTHLY CONTRACT FOR TOSHIBA COPIER 234168789 28.79

64822 8/21/2013 SHARON TREJO 250.322061661-0001-3340 Deposit refunded for 232 2ND ST (Customer# 20616) 250.0061-0001-3340 Deposit interest refunded for 232 2ND ST (Customer# 20616) 0.32

64823 8/21/2013 USA BLUEBOOK 93.8662-0710-7220 DEHUMIDIFIER FILTER FOR WELLS 115040 93.86

64824 8/21/2013 WASTE MANAGEMENT 44,463.96PAYMENT61-0550-5051 ERMU GAS GENERATOR SERVICE AGREEMENT FOR JULY 20130701-A 30,505.3361-0550-5050 GAS PURCHASED FOR JULY 2013 0700-A 13,958.63

64825 8/21/2013 JASON WENTLAND 250.552813161-0001-3340 Deposit refunded for 705 AUBURN PL (Customer# 28131) 250.2361-0001-3340 Deposit interest refunded for 705 AUBURN PL (Customer# 28131) 0.32

64826 8/21/2013 WESCO RECEIVABLES CORP. 265.0661-0001-1551 LED PHOTO CONTROL 572423 123.9861-0001-1551 400W HPS BULB 573590 141.08

64827 8/21/2013 ZEP SALES & SERVICE 89.7861-0580-5881 HAND SOAP 9000439881 89.78

64828 8/27/2013 SCOTT NELSON 165.0061-0001-1421 REFUND ON ELECTRIC BILLING REFUND 165.00

64829 8/28/2013 AMERICAN PAYMENT CENTERS 260.0061-0900-9051 DROP BOX SERVICE FOR: SEPT, OCT & NOV 2013 51808 195.0062-0900-9051 DROP BOX SERVICE FOR: SEPT, OCT & NOV 2013 51808 65.00

64830 8/28/2013 AT & T MOBILITY 988.0361-0920-9301 CELL PHONE & IPAD BILLING 877733161X08202013790.4362-0920-9301 CELL PHONE & IPAD BILLING 877733161X08202013197.60

64831 8/28/2013 BATTERIES PLUS 204.1361-0590-5995 BATTERY FOR TRUCK #10 033-861702 204.13

64832 8/28/2013 BIFFS, INC. 160.6561-0597-8263 PORT-A-POTTY AT PLANT BY BRIDGE W498901-IN 53.5561-0597-8263 PORT-A-POTTY AT PLANT BY BRIDGE W502175-IN 53.5561-0597-8263 PORT-A-POTTY AT PLANT BY BRIDGE W495750-IN 53.55

10


9/5/2013 2:43:50 PM Page 10 of 11

Check # Date Acct# Name Amount

64833 8/28/2013 CENTERPOINT ENERGY 881.64467161-0540-5472 NATURAL GAS 8000014607-8 845.3062-0710-7181 IRON REMOVAL 8000014607-8 36.34

64834 8/28/2013 CITY OF ELK RIVER 202,289.8661-0001-3416 SALES TAX FOR DONATED ELECTRICITY - JULY 2013JULY 2013 (1,250.81)61-0001-3324 SEWER BILLED - JULY 2013 JULY 2013 138,146.8461-0597-8262 REVENUE TRANSFER - JULY 2013 JULY 2013 69,473.8361-0001-1430 FRANCHISE FEE FROM CITY'S METERED ELECTRIC ACCT - JUNE 2013JUNE 2013 (2,030.00)61-0001-1430 FRANCHISE FEE FROM CITY'S METERED ELECTRIC ACCT - JULY 2013JULY 2013 (2,050.00)

64835 8/28/2013 CONNEXUS ENERGY 88.54TYLER ST.62-0710-7181 ELECTRIC FOR TYLER ST. 383399-267404 88.54

64836 8/28/2013 CROSSBRIDGE SOLUTIONS, INC. 96.1361-0597-8172 VIDEOFIED MONITORING SYSTEM 2289497 96.13

64837 8/28/2013 ELITE MEDIA DESIGN - ELK RIVER 1,950.0061-0920-9211 NEW WEBSITE DESIGN - 50 % DOWN 1606 1,560.0062-0920-9211 NEW WEBSITE DESIGN - 50 % DOWN 1606 390.00

64838 8/28/2013 GRANITE ELECTRONICS INC 52.9061-0590-5995 CHARGER 453579 52.90

64839 8/28/2013 HOME DEPOT CREDIT SERVICES 423.55CREDIT61-0540-5484 PARTS & SUPPLIES STMT 223.8161-0597-8172 PARTS & SUPPLIES STMT 37.4562-0710-7181 PARTS & SUPPLIES STMT 140.9561-0590-5992 PARTS & SUPPLIES STMT 21.34

64840 8/28/2013 JT SERVICES 196.6561-0590-5995 PULLING EYE FOR BORE RIG JT13-220-09 196.65

64841 8/28/2013 MINNESOTA COMPUTER SYSTEMS INC 744.4461-0920-9211 CONTRACTS & COPIES FOR COPIERS 117905 595.5662-0920-9211 CONTRACTS & COPIES FOR COPIERS 117905 148.88

64842 8/28/2013 NCPERS MINNESOTA 208.0061-0001-3419 EXTRA LIFE INSURANCE PREMIUMS - SEPT 2013 4452913 208.00

64843 8/28/2013 PETTY CASH 61.6861-0590-5995 FUEL FOR BORE RIG PETTY CASH 49.4261-0920-9211 OFFICE SUPPLIES PETTY CASH 8.7961-0920-9305 LUNCH FOR MEETING PETTY CASH 3.47

64844 8/28/2013 MICHAEL PRICE 198.6661-0920-9305 EXPENSES FOR UMMA MEETING EXPENSE 40.4661-0920-9304 MILEAGE FOR UMMA MEETING EXPENSE 158.20

64845 8/28/2013 PRINCIPAL LIFE INSURANCE CO GRAND ISLAND 5,205.0961-0001-3415 DENTAL INSURANCE - SEPT 2013 1023642-10001 855.2761-0001-1671 DENTAL INSURANCE - SEPT 2013 1023642-10001 2,052.6362-0001-1671 DENTAL INSURANCE - SEPT 2013 1023642-10001 513.1661-0001-1671 LIFE & LTD INSURANCE - SEPT 2013 1023642-10001 1,427.2262-0001-1671 LIFE & LTD INSURANCE - SEPT 2013 1023642-10001 356.81

64846 8/28/2013 RESCO 530.1061-0580-5881 STERLING SHACKLE LOCKS 547567-00 530.10

64847 8/28/2013 SHOE MENDERS & SADDLERY 207.4061-0580-5881 BOOTS FOR: M. SCHWARTZ 4103-31 207.40

64848 8/28/2013 STAPLES ADVANTAGE 160.2161-0920-9211 OFFICE SUPPLIES 8026529740 160.21

64849 8/28/2013 WESCO RECEIVABLES CORP. 352.6961-0580-5881 BLACK ELECTRICAL TAPE 574217 352.69

11


9/5/2013 2:43:50 PM Page 11 of 11

Check # Date Acct# Name Amount

3,970,393.88Total Non-Void ChecksReport Setup Report selection: Check Register - Detail updated2/2006 Bank Account: FIRST NATIONAL BANK ELK RIVER Starting Date: 8/1/2013 Ending Date: 8/31/2013

12

Aug-13

SALES TAX 258,724.78 **FED/FICA WITHHELD 48,024.77 STATE WITHHELD 8,084.30 DEF COMP 10,188.74 PERA 26,692.09

351,714.68

** Sales tax monthly remittance was $188,624 and $70,100.78 was the additional 10% liability due 8/20 from June early prepayment requirement

Electronic Transfers

13

Page 1 Regular meeting of the Elk River Municipal Utilities Commission August 13, 2013

ELK RIVER MUNICIPAL UTILITIES REGULAR MEETING OF THE

UTILITIES COMMISSION HELD AT UTILITIES CONFERENCE ROOM

August 13, 2013

Members Present: John Dietz, Chair; Al Nadeau, Vice Chair; Daryl Thompson, Trustee ERMU Staff Present: Troy Adams, General Manager; Theresa Slominski, Finance and Office Manager; Mark Fuchs, Line Superintendent; David Berg, Water Superintendent;

Wade Lovelette, Technical Services Superintendent; Tom Sagstetter, Conservation & Key Accounts Manager; Jennie Nelson, Executive Administrative Assistant

Others Present: Cal Portner, City Administrator; Peter Beck, Attorney 1.0 CALL MEETING TO ORDER John Dietz called the August 13, 2013 meeting to order at 3:30 p.m. 1.1 Pledge of Allegiance The Pledge of Allegiance was recited. 1.2 Consider Utilities Agenda John Dietz had questions about the financials and check register, staff responded. 2.0 CONSENT AGENDA (Approved By One Motion) Al Nadeau moved to approve the Consent Agenda as follows:

2.1 July Check Register 2.2 July 2, 2013 Previous Meeting Minutes 2.3 Financial Statements 2.4 Sick Leave Policy update, per legislative 2013 session 2.5 Service Availability Charge Deferment Policy Daryl Thompson seconded the motion. Motion carried 3-0

3.0 OPEN MIC

No one appeared for open mic.

14


4.0 OLD BUSINESS

There is no old business.

5.0 NEW BUSINESS

5.1 2014 Budget: Schedule, Travel and Training, Dues/Subscriptions/Fees, Personnel

The Travel and Training budget has less than a 1% increase over the prior year. Staff has established a schedule for training so all employees would get a more consistent training opportunity. Discussion followed.

The Dues, Subscriptions, and Fees budget has a 4% increase reflecting various known and projected increases for 2014. Troy Adams also presented a proposed organizational chart through the year 2018 as well as a chart for next year's proposed personnel additions. Staff is looking to hire two new positions next year especially with potential territory acquisition. Daryl Thompson requested that whenever we hire a new person, they come to the first commission meeting so everyone can meet them. Discussion followed.

5.2 Wage and Benefits Committee Update

In June 2013, one of ERMU’s Journeyman Lineworkers gave notice to leave to work for Xcel Energy. This was the 6th lineworker to leave for Xcel in 2 years. Of the 11 lineworkers that were working in the field in 2008, there are only 3 still working in the field. And currently over 50% of ERMU lineworkers have 2 years or less experience. At the recommendation of staff at the July Utilities Commission Meeting, the Commission gave direction for the Wage and Benefits Committee to analyze the issue and bring back a recommendation at the August meeting. The minimum qualifications for our lineworker position require the completion of a one year lineworker vocational program. Once hired, the apprentice lineworker is required to complete a four year apprentice program to become a journeyman lineworker. The apprentice program involves bookwork that is completed afterhours, examinations, and hours of experience. Once completed, the apprentice program is equivalent to a four-year degree. Troy Adams pointed out that the lineworkers were not getting credit for their education when the points system was initially calculated. Once the calculation was made including the education, the lineworkers automatically moved up one pay grade. Staff also proposed splitting staff into four separate groups: Lineman, Field Staff, Office, and Management so everyone does not always follow the same trend as they are all

15


different industries. The commissioners supported breaking the company into different groups as it will give them more flexibility to change each category as needed. Discussion followed.

Al Nadeau made a motion to approve the pay increase for the lineman retroactive to August 1, 2013 and approve the pay plan structure as proposed with the four separate groups. Daryl Thompson seconded the motion. Motion carried 3-0.

5.3 Triple Feeder Rebuild Contractor Bids

Staff recently went out to bid for a Triple Feeder Rebuild project. This project includes removing an overhead line that runs from the wastewater treatment plant to Sonic on Main Street and replacing with underground. This process requires using a much bigger bore rig so staff had to bid this project out.

The bid opening was on August 12, 2013. Three contractors bid the project and two of them were present at the opening. After the bid opening, staff discovered two of the contractors did not sign the bid or get it notarized. Staff had conversations with our legal counsel and it was determined that we cannot legally accept the bids that are not signed. Troy Adams said re-bidding the project would set us back, but we could do other projects in the meantime. Discussion followed.

Daryl Thompson made a motion to re-bid the Triple Feeder Rebuild. Al Nadeau seconded the motion. Motion carried 3-0.

6.0 OTHER BUSINESS There was no other business. 6.1 Staff Updates Troy Adams added to his staff update that the old utilities office on King Ave. is torn down now and the spot where it used to be is now a parking lot owned by the City of Elk River. From time to time the City hosts events in that parking lot. ERMU need something to release us of liability if there is an event there. At a minimum, the commission could approve a blanket letter agreement with the City so when they host an event, they have us listed on their form for insurance coverage. Discussion followed.

Theresa pointed out that we have two staff members that we want to recognize who have reached their 5 year mark. Plaques will be presented to these employees at the commission meeting recap. John Dietz wanted to thank all of the staff for their help answering franchise fee calls.

16


Cal Portner mentioned that a potential business wanting to go into the Nature’s Edge Business Park would possibly not be able to build there since Sherburne County did not approve their full loan. The City is going to see what types of financing they could present to help this business. This area is included in the utilities potential territory acquisition. John Dietz asked Tom Sagstetter about Project Conserve. This program has always been shared by the City and ERMU. The next phase will be primarily run by the utilities.

6.2 Set Date for Next Meeting The next regularly scheduled Commission meeting will be on September 10, 2013. The Commission recessed the regular meeting at 4:30pm. 6.3 Closing of Meeting: “Meeting to be closed pursuant to MN Statute 13D.05, Subd. 3(c)(3) to develop or consider offers or counteroffers for the purchase or sale of real or personal property.”

a. Call Closed Session to Order b. Discussion c. Adjourn Closed Session

6.5 Adjourn Regular Meeting Al Nadeau moved to adjourn the regular meeting of the Elk River Municipal Utilities Commission at 4:46. Daryl Thompson seconded the motion. Motion carried 3-0. Minutes prepared by Jennie Nelson. ___________________________ John J. Dietz Chair, ERMU Commission ___________________________ Tina Allard City Clerk

17

FINANCIAL INDEX

Jul-13 PAGE

P & L NARRATIVE 19

COMBINED BALANCE SHEET ………….. 20

ELECTRIC INCOME STATEMENT ………….. 21

WATER INCOME STATEMENT ………….. 22

CASH FLOW BY MONTH ………….. 23

CASH FLOW DETAIL ELECTRIC ………….. 24

CASH FLOW DETAIL WATER ………….. 25

GRAPH #1 ELECTRICAL PURCHASES ………….. 26

GRAPH #2 ELECTRIC SALES ………….. 27

GRAPH #3 ELECTRIC SALES/CUSTOMER CLASS ………….. 28

GRAPH #4 WATER PRODUCTION ………….. 29

GRAPH #5 WATER SALES ………….. 30

DETAILED ELECTRIC P & L WITH BUDGET INFORMATION……. 31

………….. 32

………….. 33

………….. 34

DETAILED WATER P & L WITH BUDGET INFORMATION………. 35

………….. 36

………….. 37

………….. 38

18

PROFIT AND LOSS NARRATIVE

July 2013 Electric P&L July Operating Revenue of $2,575,968 is behind budgeted numbers, and behind the prior year 9%. Last year July had excessive heat and humidity, with temperatures above 75 degrees 21 out of 31 days out of the month. The average temperature was 75 degrees, which is the normal high for July. Comparably, in 2013 the average temperature in July was 70 degrees, with less than 10 days above 75 degrees. Other Operating Revenue is above the budgeted numbers and above the prior year numbers 6%. Interest income is up sharply this month, coming in at twice the budgeted amount. This is a semi-rebound from the drop in market values the previous month. The other revenue items are fairly consistent with the prior year. Purchased Power of $2,258,559 is just under the prior year and in line with budgeted numbers. The remaining expenses are very close to the prior year with the exception of Distribution Expense (which is down as uniforms were purchased in July 2012 but June 2013), and Other Operating Expense that is higher because of a credit in the prior year due to mutual aid reimbursement for services provided to Grand Rapids. For July, the Electric Department has a Net Loss of ($135,189), which is behind budget by $126,102, but behind the prior year by $252,709. (Remember, July was an exceptionally good month last year.) Water P&L Water Operating Revenues are behind last year by 30% at $201,844, and also behind budget. The decrease in water sales in directly related to the weather items discussed above. Other Revenue of $34,542 is ahead of budget and the prior year due to Connection Fees. For expenses, the decrease in Pumping Expense is almost exactly offset by the increase in Distribution Expense. Expenses are in line with budget, and the prior year. For July, the Water Department has a net profit of $47,932, approximately half of the budgeted amount and 61% behind last year. (Again, keep in mind July was an exceptional month last year (favorable), and we have an opposing unexceptional (poor) July this year.) However, the water projections for the remainder of the year combining with actual year-to-date numbers still have the water department on track with budgeted numbers.

19

COMBINED BALANCE SHEETS

July 2013

ASSETS ELECTRIC WATER

CURRENT ASSETSCASH & TEMPORARY INVESTMENTS 8,526,368 1,633,338 ACCOUNTS RECEIVABLE 3,085,924 379,185 INVENTORIES 1,153,502 26,962 PREPAID ITEMS 119,292 30,036 CONSTRUCTION IN PROGRESS 941,160 347,889

TOTAL CURRENT ASSETS 13,826,245 2,417,410

RESTRICTED ASSETSBOND RESERVE FUND 724,500 - EMERGENCY RESERVE FUND 2,240,510 1,134,438 UNRESTRICTED RESERVE FUND 125,867 135,569

TOTAL RESTRICTED ASSETS 3,090,877 1,270,007

FIXED ASSETSPRODUCTION 2,441,903 10,687,043 LFG PROJECT 4,336,112 - TRANSMISSION 474,335 - DISTRIBUTION 35,515,017 22,057,189 GENERAL 11,449,699 939,616

FIXED ASSETS (COST) 54,217,065 33,683,847 LESS ACCUMULATED DEPRECIATION (29,140,304) (12,606,338) TOTAL FIXED ASSETS, NET 25,076,761 21,077,509

OTHER ASSETS AND DEFFERED OUTFLOWS (31,345) (7,836)

TOTAL ASSETS 41,962,538 24,757,090

LIABILITIES AND FUND EQUITY

CURRENT LIABILITIESACCOUNTS PAYABLE 3,554,442 446,971 SALARIES AND BENEFITS PAYABLE 224,460 83,169 DUE TO CITY 22,573 - DUE TO OTHER FUNDS - - BONDS PAYABLE-CURRENT PORTION 225,000 - UNEARNED REVENUE 3,442 85,896

TOTAL CURRENT LIABILITIES 4,029,918 616,036 LONG TERM LIABILITIES

LFG PROJECT 1,789,224 DUE TO COUNTY - BONDS PAYABLE, LESS CURRENT PORTION 5,313,834 2,602,208

TOTAL LONG TERM LIABILITIES 7,103,058 2,602,208

TOTAL LIABILITIES 11,132,976 3,218,244

FUND EQUITYCAPITAL ACCOUNT CONST COST 724,500 CONTRIBUTED CAPITALRETAINED EARNINGS 30,105,062 21,538,846

TOTAL FUND EQUITY 30,829,562 21,538,846

TOTAL LIABILITIES & FUND EQUITY 41,962,538 24,757,090

20

ELECTRIC INCOME STATEMENT

ERMU Income Statement 2013 2013 2013 TOTAL 2012 2012 Delta

July YEAR TO DATE BUDGET July YEAR TO DATE YTD to LYTD

Electric CommentsREVENUE

Operating Revenue

Elk River 2,408,939.92 14,711,247.54 26,661,308.00 2,604,972.52 14,192,882.03 518,365.51 Partially offset by Dispersed Generation Credit and by Rural Big Lake route that was reclassified to ER route.

Elk River-City Donated 17,716.23 110,305.71 205,000.00 20,075.15 105,091.12 5,214.59 Otsego 204,215.23 1,286,832.25 2,304,982.00 253,275.52 1,275,315.96 11,516.29 Rural Big Lake 15,750.68 109,749.99 286,400.00 32,745.48 166,051.42 (56,301.43) Dayton 19,638.23 132,306.87 259,200.00 27,921.00 132,673.61 (366.74) Public St & Hwy Lighting 22,732.81 168,780.05 268,038.00 21,442.21 152,010.15 16,769.90

Generation and Sub Station Credit 2,847.86 47,669.02 - 30,581.86 214,074.02 (166,405.00) Jan includes 29K of Substation credit under the previous agreement. Feb - Dec amounts are significantly less based on the new agreement.

Dispersed Generation Credit (105,072.24) (529,608.24) (981,698.00) (147,490.00) (379,457.00) (150,151.24) YTD June 2013 includes higher Dispersed Generation CR to our customers than 2012 based on Target's participation through May.

Other Revenue/CIP/Rate Increase/AC Credit (10,800.00) (21,519.17) (35,986.00) (10,729.00) (21,242.00) (277.17) AC credits budgeted here, actuals for 2013 are posting here beginning in June.

Total Operating Revenue 2,575,968.72 16,015,764.02 28,967,244.00 2,832,794.74 15,837,399.31 178,364.71

Other Operating RevenueInterest/Dividend Income 10,477.56 41,530.93 80,000.00 7,174.68 66,879.74 (25,348.81) Investment performance YTD is positive, but lower than 2012.Customer Penalties 22,295.45 129,186.48 245,000.00 18,168.50 123,763.64 5,422.84 LFG Project 86,546.34 615,677.88 1,052,000.00 79,754.66 603,126.78 12,551.10 Connection Fees 6,100.00 55,074.37 50,000.00 14,823.10 96,051.52 (40,977.15) Jan 2012 included Sportech and Agg Industries projectsSecurity 28,662.81 165,110.90 265,000.00 26,627.47 160,469.76 4,641.14 Misc Revenue 20,736.69 80,463.92 117,500.00 17,580.38 77,570.97 2,892.95 YTD July 24K of income from scrapped transformers.

Total Other Revenue 174,818.85 1,087,044.48 1,809,500.00 164,128.79 1,127,862.41 (40,817.93)

REVENUE TOTAL 2,750,787.57 17,102,808.50 30,776,744.00 2,996,923.53 16,965,261.72 137,546.78

EXPENSESPurchased Power 2,258,559.48 11,478,454.66 21,658,687.97 2,264,972.93 11,369,797.48 108,657.18 Operating & Mtce Expense 14,491.02 131,290.22 219,775.00 12,865.53 117,862.27 13,427.95 Landfill Gas 57,394.88 377,224.85 713,308.00 55,420.47 392,994.40 (15,769.55) Distribution Expense 8,068.86 100,028.00 203,925.00 13,492.76 110,257.51 (10,229.51)

Maintenance Expense 29,631.18 394,129.98 734,050.00 27,742.04 343,903.34 50,226.64

Category is at 54% of total yr budget at end of July, but spending is ahead of 2012. Drivers are vehicle repairs and transformer maintenance.

Depreciation 179,575.00 1,256,823.30 2,154,900.00 180,000.00 1,260,000.00 (3,176.70) Interest Expense 18,130.49 128,018.85 217,660.80 20,135.59 141,989.13 (13,970.28) Security 18,857.14 127,274.52 225,000.00 23,493.28 130,902.42 (3,627.90) Other Operating Expense 4,696.02 12,155.82 27,500.00 (9,848.55) 1,698.90 10,456.92 Services to the City 109,988.21 709,473.20 1,271,000.00 115,756.12 677,767.34 31,705.86 Donated to city is up over 2013 as is the 3% revenue payment.

Customer Accounts Expense 16,843.90 93,464.46 283,000.00 10,916.73 105,729.45 (12,264.99) Expenses for YTD 2013 are partially offset by recovery of bad debt that was already written off to the Income Statement.

Administrative & General Expense 169,741.28 1,198,192.28 2,673,106.75 164,456.05 1,189,348.58 8,843.70

Legal fees YTD +10K, Insurance YTD +23K, Salaries/Office planned staff increase + 24K, Dues, Subscriptions YTD -8K, Schools and Meetings YTD -10K, Office supplies YTD -10K, timing of Conservation IMP -25K.

Total Expenses (before Operating Transfers) 2,885,977.46 16,006,530.14 30,381,913.52 2,879,402.95 15,842,250.82 164,279.32

TOTAL REVENUES 2,750,787.57 17,102,808.50 30,776,744.00 2,996,923.53 16,965,261.72 137,546.78 TOTAL EXPENSES 2,885,977.46 16,006,530.14 30,381,913.52 2,879,402.95 15,842,250.82 164,279.32 OPERATING TRANSFER -

NET INCOME PROFIT (LOSS) (135,189.89) 1,096,278.36 394,830.48 117,520.58 1,123,010.90 (26,732.54)

21

WATER

INCOME STATEMENT

ERMU Income Statement 2013 2013 2013 TOTAL 2012 2012 Delta

July YEAR TO DATE BUDGET July YEAR TO DATE YTD to LYTD

Water CommentsREVENUE

Operating Revenue

Water Sales 201,844.03 874,173.18 2,041,234.00 291,941.80 949,057.51 (74,884.33)

July water billing for June usage was below 2012 for the same period. Looking ahead to August billing for July usage, much of this shortage to last year will recover.

Total Operating Revenue 201,844.03 874,173.18 2,041,234.00 291,941.80 949,057.51 (74,884.33)

Other Operating Revenue

Interest/Dividend Income 3,011.65 10,793.63 30,000.00 2,283.09 17,227.29 (6,433.66) Investment performance YTD is positive, but lower than 2012.

Customer Penalties 2,042.08 8,591.59 17,000.00 1,793.07 8,028.22 563.37

Connection Fees 20,482.20 125,835.05 83,666.00 5,841.60 124,089.62 1,745.43 YTD Connection Fees are well ahead of budget for year.

Misc Revenue 9,006.00 59,607.35 100,000.00 6,237.79 46,961.72 12,645.63 Water Tower lease higher than 2012 YTD due to additional lease (modification)

Total Other Revenue 34,541.93 204,827.62 230,666.00 16,155.55 196,306.85 8,520.77

REVENUE TOTAL 236,385.96 1,079,000.80 2,271,900.00 308,097.35 1,145,364.36 (66,363.56)

EXPENSES

Production Expense 529.77 9,480.35 22,910.00 1,090.92 3,640.84 5,839.51

Replaced doors at well #4 2K, Fiber Optic Line 1K. Payroll for employee time inspecting towers is accounted for here.

Pumping Expense 31,774.14 229,843.70 402,100.00 41,723.19 209,116.87 20,726.83

Electricity for wells higher than 2012. 6K for Well #7 Meter. Payroll for employee time maintaining wells is accounted for here.

Distribution Expense 20,952.82 166,372.12 188,300.00 11,608.19 101,294.92 65,077.20

2012 included emergency repair at 12K, 2013 emergency repair at Main and Jackson 13K. Cost of pressure reducer valves is included YTD 2013 - 64K expense, this was budgetted 25K in March.

Depreciation 90,000.00 630,000.00 1,083,998.00 85,000.00 615,000.00 15,000.00 Consistent with Operating Budget.Interest Expense 7,342.72 52,726.54 109,182.20 8,738.37 62,381.72 (9,655.18) Other Operating Expense 98.30 25,767.46 26,500.00 957.73 32,660.96 (6,893.50) Customer Accounts Expense 4,329.53 27,420.79 62,500.00 3,677.42 29,393.76 (1,972.97) Administrative & General Expense 33,426.64 271,620.29 516,747.00 30,583.38 263,753.33 7,866.96

Total Expenses (before Operating Transfers) 188,453.92 1,413,231.25 2,412,237.20 183,379.20 1,317,242.40 95,988.85

TOTAL REVENUES 236,385.96 1,079,000.80 2,271,900.00 308,097.35 1,145,364.36 (66,363.56)

TOTAL EXPENSES 188,453.92 1,413,231.25 2,412,237.20 183,379.20 1,317,242.40 95,988.85 64K is expenses for pressure reducer valves expensed YTD.

OPERATING TRANSFER - - - - - -

NET INCOME PROFIT (LOSS) 47,932.04 (334,230.45) (140,337.20) 124,718.15 (171,878.04) (162,352.41)

22

2013 CASH FLOWS BY MONTH WITH COMPARISONS TO YEAR END 2012

Jul-13 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13

ELECTRIC

TEMPORARY CASH & INVESTMENTS

61-0001-1211(1361) TEMP CASH/SAVINGS 11,784,595.60 10,598,617.35 11,317,877.03 9,711,870.68 9,997,774.25 10,251,351.19 10,218,429.36 10,640,644.02

61-0001-1312(1321)(1341) CHECKING (3,512,001.35) (2,572,851.17) (1,981,701.17) (1,909,773.09) (1,843,723.11) (1,977,146.85) (2,135,343.46) (2,114,676.47)

61-0001-1311 PETTY CASH 400.00 400.00 400.00 400.00 400.00 400.00 400.00 400.00

TOTAL 8,272,994.25 8,026,166.18 9,336,575.86 7,802,497.59 8,154,451.14 8,274,604.34 8,083,485.90 8,526,367.55

RESTRICTED FUNDS/OR DESIGNATED

61-0001-1271 UNRESTRICTED DESIGNATED RESERVES 2,224,854.22 2,227,259.77 2,231,907.66 2,233,271.69 2,231,158.36 2,231,910.78 2,234,234.34 2,240,510.25

61-0001-1275 UNRESTRICTED RESERVE 125,866.88 125,866.88 125,866.88 125,866.88 125,866.88 125,866.88 125,866.88 125,866.88

61-0001-1282 BOND RESERVE 724,500.00 724,500.00 724,500.00 724,500.00 724,500.00 724,500.00 724,500.00 724,500.00

TOTAL 3,075,221.10 3,077,626.65 3,082,274.54 3,083,638.57 3,081,525.24 3,082,277.66 3,084,601.22 3,090,877.13

TOTAL 11,348,215.35 11,103,792.83 12,418,850.40 10,886,136.16 11,235,976.38 11,356,882.00 11,168,087.12 11,617,244.68

INCREASE/DECREASE PER MONTH (244,422.52) 1,070,635.05 (462,079.19) (112,238.97) 8,666.65 (180,128.23) 269,029.33

FROM YR END 2012

WATER

TEMPORARY CASH & INVESTMENTS

62-0001-1312(1341) CHECKING 2,586,442.76 2,589,156.22 2,011,915.09 1,984,154.16 1,957,802.00 2,085,431.38 2,112,767.27 2,227,396.82

62-0001-1211 SAVINGS (603,872.07) (602,186.58) (600,861.07) (599,340.93) (598,072.46) (596,674.88) (595,456.72) (594,058.94)

TOTAL 1,982,570.69 1,986,969.64 1,411,054.02 1,384,813.23 1,359,729.54 1,488,756.50 1,517,310.55 1,633,337.88

RESTRICTED FUNDS/OR DESIGNATED

62-0001-1271 UNRESTRICTED DESIGNATED RESERVES 1,130,590.18 1,131,125.34 1,132,287.31 1,132,630.14 1,132,099.96 1,132,288.07 1,132,868.97 1,134,437.93

62-0001-1275 UNRESTRICTED RESERVE 135,509.32 135,569.33 135,569.33 135,569.33 135,569.33 135,569.33 135,569.33 135,569.33

62-0001-1342 BOND RESERVE/ESCROW - - - - - - - -

TOTAL 1,266,099.50 1,266,694.67 1,267,856.64 1,268,199.47 1,267,669.29 1,267,857.40 1,268,438.30 1,270,007.26

TOTAL 3,248,670.19 3,253,664.31 2,678,910.66 2,653,012.70 2,627,398.83 2,756,613.90 2,785,748.85 2,903,345.14

INCREASE/DECREASE PER MONTH 4,994.12 (569,759.53) (595,657.49) (621,271.36) (492,056.29) (462,921.34) (345,325.05)

FROM YR END 2012

23

2013 Cash Flow Detail

Cash Flows 2013Actual Actual Actual Actual Actual Actual Actual Projection Projection Projection Projection Projection YTD Totals YTD Totals

Electric Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec Actual/Projected Operating PlanREVENUE

Operating RevenueElectric Sales 2,179,650.91 2,428,667.22 2,105,276.44 2,110,563.78 2,240,958.61 2,640,512.03 2,666,260.29 3,315,706.00 3,162,374.00 2,306,670.00 2,255,892.00 2,264,285.00 29,676,816.28 29,730,904.00 Public St & Hwy Lighting 24,315.91 24,714.12 24,385.23 23,694.34 23,516.04 25,421.60 22,732.81 21,405.00 22,782.00 24,392.00 25,243.00 25,626.00 288,228.05 268,038.00 Generation Credit 30,581.86 1,167.86 4,527.86 2,847.86 2,847.86 2,847.86 2,847.86 47,669.02 Dispersed Generation Credit (88,890.00) (92,870.00) (90,100.00) (54,822.00) (54,240.00) (43,614.00) (105,072.24) (163,437.00) (161,533.00) (70,370.00) (64,685.00) (64,850.00) (1,054,483.24) (981,698.00) AC Credit /CIP & Rate Increase - - - - 8.81 (10,728.00) (10,800.00) (9,983.00) (9,975.00) (10,008.00) - - (51,485.19) (50,000.00) Projection Adjustment - - - - - - - (212,000.00) - - - - (212,000.00) -

Total Operating Revenue 2,145,658.68 2,361,679.20 2,044,089.53 2,082,283.98 2,213,091.32 2,614,439.49 2,575,968.72 2,951,691.00 3,013,648.00 2,250,684.00 2,216,450.00 2,225,061.00 28,694,744.92 28,967,244.00

Other Operating RevenueInterest/Dividend Income 10,220.71 5,784.90 10,857.49 6,896.97 8,607.03 (11,313.73) 10,477.56 7,252.00 6,119.00 4,301.00 6,808.00 10,084.00 76,094.93 80,000.00 Customer Penalties 20,086.21 18,942.89 19,257.68 15,326.29 17,088.54 16,189.42 22,295.45 28,369.00 28,851.00 30,937.00 19,852.00 9,755.00 246,950.48 245,000.00 LFG Project 93,116.07 92,469.48 83,472.87 91,660.65 83,339.56 85,072.91 86,546.34 92,979.00 90,500.00 88,637.00 89,103.00 88,689.00 1,065,585.88 1,052,000.00 Connection Fees 3,950.00 16,676.96 6,952.86 11,902.01 8,776.25 716.29 6,100.00 5,843.00 1,148.00 1,504.00 4,350.00 6,408.00 74,327.37 50,000.00 Security 26,245.14 23,042.60 20,276.09 20,942.76 19,154.20 26,787.30 28,662.81 31,138.00 21,121.00 29,304.00 21,606.00 17,974.00 286,253.90 265,000.00 Misc Revenue 7,257.36 12,804.46 10,934.20 16,812.57 3,822.76 8,105.88 20,736.69 7,882.00 9,408.00 26,655.00 7,380.00 12,702.00 144,500.92 117,500.00 Projection Adjustment - - - - - - - - - - - - -

Total Other Revenue 160,875.49 169,721.29 151,751.19 163,541.25 140,788.34 125,558.07 174,818.85 173,463.00 157,147.00 181,338.00 149,099.00 145,612.00 1,893,713.48 1,809,500.00

REVENUE TOTAL 2,306,534.17 2,531,400.49 2,195,840.72 2,245,825.23 2,353,879.66 2,739,997.56 2,750,787.57 3,125,154.00 3,170,795.00 2,432,022.00 2,365,549.00 2,370,673.00 30,588,458.40 30,776,744.00

EXPENSESPurchased Power 1,631,748.34 1,662,304.40 1,603,457.29 1,417,054.28 1,376,065.60 1,529,265.27 2,258,559.48 2,708,610.00 2,445,486.00 1,574,773.00 1,390,150.00 1,527,101.97 21,124,575.63 21,658,687.97 Operating & Mtce Expense 14,988.04 22,707.04 22,185.00 18,388.54 20,438.92 18,091.66 14,491.02 24,076.00 14,493.00 15,239.00 15,082.00 20,791.00 220,971.22 219,775.00 Landfill Gas 55,370.56 43,989.20 60,798.17 54,963.19 54,933.86 49,774.99 57,394.88 57,813.00 57,376.00 57,503.00 48,336.00 81,192.00 679,444.85 713,308.00 Distribution Expense 12,330.54 16,459.17 14,808.51 12,841.80 13,524.84 21,989.98 8,068.86 10,932.00 11,067.00 13,904.00 17,413.00 23,637.00 176,976.70 203,925.00 Maintenance Expense 6,553.80 61,397.12 100,093.49 79,981.10 66,528.05 49,945.24 29,631.18 67,251.00 65,566.00 56,029.00 37,282.00 69,933.00 690,190.98 734,050.00 Depreciation 179,373.30 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 122,749.00 2,097,872.30 2,154,900.00 Interest Expense 19,235.91 18,130.49 18,130.49 18,130.49 18,130.49 18,130.49 18,130.49 17,989.00 17,989.00 17,989.00 17,989.00 14,769.80 214,744.65 217,660.80 Security 12,476.99 18,091.58 21,799.37 17,558.96 16,739.86 21,750.62 18,857.14 15,273.00 20,142.00 19,808.00 14,588.00 20,603.00 217,688.52 225,000.00 Other Operating Expense 107.96 179.28 73.23 649.47 3,154.69 3,295.17 4,696.02 1,485.00 (15,775.00) (18.00) 3,128.00 4,266.00 5,241.82 27,500.00 Services to the City 95,892.75 103,916.80 93,514.90 94,256.11 97,074.44 114,829.99 109,988.21 129,889.00 126,101.00 105,186.00 101,458.00 111,106.00 1,283,213.20 1,271,000.00 Customer Accounts Expense 11,469.04 14,475.35 13,305.86 10,672.59 12,498.53 14,199.19 16,843.90 13,119.00 26,866.00 9,220.00 26,088.00 98,575.00 267,332.46 283,000.00 Administrative & General Expense 124,087.77 169,930.31 219,134.91 151,259.07 153,810.43 210,228.51 169,741.28 207,350.00 221,106.00 179,778.00 180,685.00 338,161.75 2,325,273.03 2,673,106.75 Projection Adjustment - - - - - - - - 100,000.00 100,000.00 100,000.00 100,000.00 400,000.00 -

EXPENSES TOTAL 2,163,635.00 2,311,155.74 2,346,876.22 2,055,330.60 2,012,474.71 2,231,076.11 2,885,977.46 3,433,362.00 3,269,992.00 2,328,986.00 2,131,774.00 2,532,885.52 29,703,525.36 30,381,913.52

TOTAL REVENUES 2,306,534.17 2,531,400.49 2,195,840.72 2,245,825.23 2,353,879.66 2,739,997.56 2,750,787.57 3,125,154.00 3,170,795.00 2,432,022.00 2,365,549.00 2,370,673.00 30,588,458.40 30,776,744.00 TOTAL EXPENSES 2,163,635.00 2,311,155.74 2,346,876.22 2,055,330.60 2,012,474.71 2,231,076.11 2,885,977.46 3,433,362.00 3,269,992.00 2,328,986.00 2,131,774.00 2,532,885.52 29,703,525.36 30,381,913.52

NET INCOME PROFIT (LOSS) 142,899.17 220,244.75 (151,035.50) 190,494.63 341,404.95 508,921.45 (135,189.89) (308,208.00) (99,197.00) 103,036.00 233,775.00 (162,212.52) 884,933.04 394,830.48

Other Cash Items

Depreciation 179,373.30 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 179,575.00 2,154,698.30 2,154,900.00 Accrued Interest 4,635.91 (81,024.51) 18,130.49 18,130.49 18,130.49 18,130.49 18,130.49 (89,133.50) 17,989.00 17,989.00 17,989.00 14,769.80 (6,132.85) (23,216.70) Payroll Liabilities (80,314.75) (7,112.42) 51,651.89 (30,194.97) (22,781.29) 10,956.07 (12,503.25) 87,000.00 (3,298.72) - Accounts Payable (104,415.62) 1,569,063.42 (1,708,950.37) 259,535.08 41,721.01 (172,896.06) 597,922.40 (100,000.00) (100,000.00) (100,000.00) (100,000.00) (39,600.00) 42,379.86 - Capitalized Items (10,108.44) (31,838.69) (246,345.62) (282,076.92) (269,603.86) (77,162.09) (231,786.92) (694,800.00) (600,000.00) (60,000.00) (200,000.00) (200,000.00) (2,903,722.54) (2,894,800.00) LTD & Bond Principal (83,287.00) (310,287.00) (15,548.50) (15,548.50) (15,548.50) (15,548.50) (15,548.50) (240,548.50) (15,548.50) (15,548.50) (115,555.00) (15,548.50) (874,065.50) (774,582.00) Accounts Receivable (293,920.12) (255,893.87) 346,410.61 54,664.91 (86,131.73) (651,442.50) 161,012.37 350,000.00 400,000.00 (100,000.00) (200,000.00) (275,300.33) Prepaid Accounts/Unearned Revenue 3,511.18 25,587.00 (12,754.53) (3,519.37) 21,256.05 38,157.02 (16,713.67) (29,000.00) 26,523.68 - Bond Amortization 276.74 276.74 549.34 549.34 549.34 549.34 549.34 3,300.18 - Inventory Purchases (3,072.89) 6,467.15 5,602.95 (21,769.47) (87,665.84) (28,035.10) (96,289.81) 11,366.22 (213,396.79) 11,366.22

Change in Cash Balances (244,422.52) 1,315,057.57 (1,532,714.24) 349,840.22 120,905.62 (188,794.88) 449,157.56 (903,115.00) (217,181.50) 25,051.50 (184,216.00) (153,650.00) (1,164,081.67) (1,131,502.00)

Cash Balance 11,103,792.83 12,418,850.40 10,886,136.16 11,235,976.38 11,356,882.00 11,168,087.12 11,617,244.68 10,714,129.68 11,400,063.18 11,642,296.18 11,433,028.68 11,279,378.68 10,216,713.35

24

2013 Cash Flow Detail

Cash Flows 2013Actual Actual Actual Actual Actual Actual Actual Projection Projection Projection Projection Projection YTD Totals YTD Totals

Water Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec Actual/Projected Operating PlanREVENUE

Operating RevenueWater Sales 89,378.34 102,733.57 97,287.95 107,466.60 101,240.37 174,521.32 201,844.03 297,999.00 393,235.00 244,897.00 143,593.00 88,538.00 2,042,734.18 2,041,234.00 Projection Adjustment - - - - - - - - (20,000.00) - - - (20,000.00) -

Total Operating Revenue 89,378.34 102,733.57 97,287.95 107,466.60 101,240.37 174,521.32 201,844.03 297,999.00 373,235.00 244,897.00 143,593.00 88,538.00 2,022,734.18 2,041,234.00

Other Operating RevenueInterest/Dividend Income 2,558.38 1,449.10 2,717.57 1,727.33 2,155.15 (2,825.55) 3,011.65 2,510.00 2,118.00 1,490.00 2,356.00 5,299.00 24,566.63 30,000.00 Customer Penalties 1,263.55 829.22 1,064.20 1,047.29 1,350.60 994.65 2,042.08 2,019.00 3,179.00 2,106.00 2,048.00 1,026.00 18,969.59 17,000.00 Connection Fees 12,783.60 20,261.20 12,544.80 12,905.80 25,039.05 21,818.40 20,482.20 8,102.00 4,110.00 5,107.00 1,622.00 13,315.00 158,091.05 83,666.00 Misc Revenue 6,219.33 6,518.23 9,134.78 8,591.23 11,131.78 9,006.00 9,006.00 8,659.00 8,300.00 8,300.00 8,440.00 8,299.00 101,605.35 100,000.00 Projection Adjustment - - - - - - - - - - - - - -

Total Other Revenue 22,824.86 29,057.75 25,461.35 24,271.65 39,676.58 28,993.50 34,541.93 21,290.00 17,707.00 17,003.00 14,466.00 27,939.00 303,232.62 230,666.00

Total Revenue 112,203.20 131,791.32 122,749.30 131,738.25 140,916.95 203,514.82 236,385.96 319,289.00 390,942.00 261,900.00 158,059.00 116,477.00 2,325,966.80 2,271,900.00

EXPENSESProduction Expense 3,537.49 2,137.01 1,386.48 547.62 417.33 924.65 529.77 5,081.00 699.00 10,336.00 (826.00) 3,387.00 28,157.35 22,910.00 Pumping Expense 32,059.32 34,407.00 36,665.68 33,594.16 30,512.56 30,830.84 31,774.14 39,099.00 42,821.00 29,966.00 28,769.00 62,940.00 433,438.70 402,100.00 Distribution Expense 18,227.08 8,213.66 43,685.45 15,642.67 24,741.64 34,908.80 20,952.82 13,936.00 12,027.00 11,180.00 11,198.00 18,795.00 233,508.12 188,300.00 Depreciation 90,000.00 90,000.00 90,000.00 90,000.00 90,000.00 90,000.00 90,000.00 89,579.00 89,579.00 89,579.00 89,579.00 77,553.00 1,065,869.00 1,083,998.00 Interest Expense 8,670.22 7,342.72 7,342.72 7,342.72 7,342.72 7,342.72 7,342.72 9,062.00 9,062.00 9,062.00 9,062.00 8,242.20 97,216.74 109,182.20 Other Operating Expense 28,014.69 37.00 18.00 48.60 3,061.18 (30,510.31) 98.30 42.00 42.00 42.00 42.00 81.00 1,016.46 1,500.00 Customer Accounts Expense 3,223.64 3,422.05 5,645.65 3,832.53 3,520.89 3,446.50 4,329.53 3,996.00 6,722.00 3,695.00 4,232.00 6,431.00 52,496.79 62,500.00 Administrative & General Expense 27,457.95 40,155.06 44,725.10 35,965.52 43,730.11 46,159.91 33,426.64 49,566.00 40,336.00 36,714.00 41,892.00 55,135.00 495,263.29 516,747.00

Projection Adjustment - - - - - - - - - - - - - -

Total Expenses 211,190.39 185,714.50 229,469.08 186,973.82 203,326.43 183,103.11 188,453.92 210,361.00 201,288.00 190,574.00 183,948.00 232,564.20 2,406,966.45 2,387,237.20

Operating Transfer 25,000.00 - - - - - - 25,000.00 25,000.00 TOTAL REVENUES 112,203.20 131,791.32 122,749.30 131,738.25 140,916.95 203,514.82 236,385.96 319,289.00 390,942.00 261,900.00 158,059.00 116,477.00 2,325,966.80 2,271,900.00 TOTAL EXPENSES 211,190.39 185,714.50 229,469.08 186,973.82 203,326.43 183,103.11 188,453.92 210,361.00 201,288.00 190,574.00 183,948.00 232,564.20 2,406,966.45 2,387,237.20

NET INCOME PROFIT (LOSS) (123,987.19) (53,923.18) (106,719.78) (55,235.57) (62,409.48) 20,411.71 47,932.04 108,928.00 189,654.00 71,326.00 (25,889.00) (116,087.20) (105,999.65) (140,337.20)

Other Cash Items

Depreciation 90,000.00 90,000.00 90,000.00 90,000.00 90,000.00 90,000.00 90,000.00 89,579.00 89,579.00 89,579.00 89,579.00 77,553.00 1,065,869.00 1,083,998.00 Accrued Interest 5,020.22 (40,613.53) 7,342.72 7,342.72 7,342.72 7,342.72 7,342.72 (34,579.25) 9,062.00 9,062.00 9,062.00 8,242.20 1,969.24 13,934.70 Payroll Liabilities (16,255.77) 4,145.52 6,073.21 (1,938.60) (1,293.91) (4,476.25) 851.49 - - - - 12,000.00 (894.31) - Accounts Payable 45,156.25 (30,385.52) 26,386.32 (48,371.15) 30,536.60 (21,291.16) 346,731.78 (200,000.00) (100,000.00) (25,000.00) (14,000.00) 9,763.12 - Capitalized Items (1,490.89) (1,141.95) (52,308.47) (2,779.86) (16,505.04) (3,014.67) (323,021.46) (125,000.00) (250,000.00) (100,000.00) (50,000.00) (49,125.00) (974,387.34) (974,125.00) LTD & Bond Principal (17,000.00) (525,000.00) - - - - - - - - - - (542,000.00) (542,000.00) Accounts Receivable 23,906.14 (19,956.73) (6,495.03) (2,788.79) 6,389.75 (66,267.06) (29,128.91) 100,000.00 5,659.37 Prepaid Accounts/Unearned Revenue (1,500.00) 3,456.87 15,966.42 (12,062.61) 73,572.06 3,987.67 (15,759.19) (40,000.00) (40,000.00) (12,338.78) Bond Amortization 137.33 137.33 137.33 137.33 137.33 686.65 Inventory Purchases 1,145.36 (1,335.13) (6,280.68) 82.66 1,445.04 2,304.66 (7,489.51) (16,621.50) (26,749.10) (23,621.50)

Change in Cash Balances 4,994.12 (574,753.65) (25,897.96) (25,613.87) 129,215.07 29,134.95 117,596.29 (161,072.25) (61,705.00) 69,967.00 57,752.00 (138,038.50) (578,421.80) (582,151.00)

Cash Balance 3,253,664.31 2,678,910.66 2,653,012.70 2,627,398.83 2,756,613.90 2,785,748.85 2,903,345.14 2,742,272.89 2,680,567.89 2,750,534.89 2,808,286.89 2,670,248.39 2,666,519.19

25

))

20

25

30

35

40

45

50

55

60

65

De

ma

nd

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MW

Month

Elk River Municipal Utilities Monthly Electrical Demand

2013 2012

14,000

19,000

24,000

29,000

34,000

En

erg

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urc

ha

se

s i

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WH

Month

Elk River Municipal Utilities Monthly Energy Purchases

2012

2013

26

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

Ele

ctr

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oad

in

MW

H

Month

Elk River Municipal Utilities Monthly Total Electric Load

2012

2013

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

Sale

s i

n D

olla

rs

Month

Elk River Municipal Utilities Monthly Electric Sales

2012

2013

27

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

Lo

ad

s in

MW

H

Month

Elk River Municipal Utilities Monthly Residential, Commercial & Industrial Loads

Residential

Industrial

Commercial

2013

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

$1,600,000

$1,800,000

Sale

s i

n D

ollars

Month

Elk River Municipal Utilities Monthly Residential, Commercial & Industrial Sales

Residential

Commercial

2012

2013

Industrial

2012

28

0

20

40

60

80

100

120

140

Pu

mp

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Elk River Municipal Utilities Monthly Water Pumpage

2013

2012

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2

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8

Peak D

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Elk River Municipal Utilities Peak Day Pumpage

2012 2013

29

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20

40

60

80

100

120

140

Sale

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on

Ga

l.

Month

Elk River Municipal Utilities Monthly Water Sales

2012

2013

$0

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

$350,000

$400,000

$450,000

Sale

s i

n D

ollars

Month

Elk River Municipal Utilities Monthly Water Sales

2013 2012

30

Year To DateAccount Account Name Current %Used Current Total RemainingBudget

Year To Date TotalFiscal Year 2012Fiscal Year 2013

ELK RIVER MUNICIPAL UTILITIESPrinted September 4, 2013 8:39:03 PM Page 1 of 5

RevenueELECTRICELECTRIC OPERATING R

5,060,539.4761-0440-4411 ELECT SALES/ELK RIVER RES 794,506.45 55.77 % 953,954.00 9,073,687.00 4,013,147.53 4,826,366.51 8,783,805.021,407,859.1561-0440-4412 ELECT SALES/ER NON-DEMAND 242,885.74 56.34 % 247,443.00 2,498,800.00 1,090,940.85 1,262,999.58 2,325,330.088,223,760.5461-0440-4413 ELECT SALES/ER DEMAND 1,368,780.55 54.62 % 1,494,007.00 15,055,921.00 6,832,160.46 8,084,999.29 14,598,135.41

19,088.3861-0440-4414 ELECT SALES/ELK RIVER SEC LTS 2,767.18 58.02 % 2,724.00 32,900.00 13,811.62 18,516.65 31,993.23110,305.7161-0440-4415 ELECT SALES/ER CITY DONATED 17,716.23 53.81 % 21,200.00 205,000.00 94,694.29 105,091.12 194,126.53605,651.9161-0440-4416 ELECT SALES/OTSEGO RES 94,196.89 53.96 % 132,730.00 1,122,482.00 516,830.09 602,069.67 1,088,696.09259,324.2061-0440-4417 ELECT SALES/OTSEGO NON-DEMAND 43,571.96 74.73 % 38,165.00 347,000.00 87,675.80 215,413.06 415,317.21415,803.6861-0440-4418 ELECT SALES/OTSEGO DEMAND 65,581.74 50.40 % 82,517.00 825,000.00 409,196.32 451,844.06 779,884.65

6,052.4661-0440-4419 ELECT SALES/OTSEGO SEC LTS 864.64 57.64 % 878.00 10,500.00 4,447.54 5,989.17 10,247.77107,900.8861-0440-4421 ELECT SALES/BIG LAKE RES 15,478.88 39.09 % 33,166.00 276,000.00 168,099.12 159,288.22 261,793.34

774.6961-0440-4422 ELECT SALES/BL NON-DEMAND 117.11 9.11 % 1,218.00 8,500.00 7,725.31 5,678.79 7,904.600.0061-0440-4423 ELECTRIC SALES/BL DEMAND 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

1,074.4261-0440-4424 ELECT SALES/BIG LAKE SEC LTS 154.69 56.55 % 160.00 1,900.00 825.58 1,084.41 1,833.33109,972.2561-0440-4431 ELECT SALES/DAYTON RES 16,144.95 49.76 % 26,830.00 221,000.00 111,027.75 111,658.90 198,041.2619,368.5161-0440-4432 ELECT SALES/DAYTON NON-DEMAND 3,069.55 58.69 % 3,583.00 33,000.00 13,631.49 18,050.94 31,818.85

0.0061-0440-4433 ELECT SALES/DAYTON DEMAND 0.00 0.00 % 0.00 0.00 0.00 0.00 0.002,966.1161-0440-4434 ELECT SALES/DAYTON SEC LTS 423.73 57.04 % 434.00 5,200.00 2,233.89 2,963.77 5,082.42

168,780.0561-0440-4441 PUBLIC ST & HWY LIGHTING/CITY 22,732.81 62.97 % 20,960.00 268,038.00 99,257.95 152,010.15 274,208.880.0061-0440-4511 SERVICE CHARGE 0.00 0.00 % 1,168.00 14,014.00 14,014.00 0.00 0.00

8,175.0261-0440-4550 SUB-STATION CREDIT 1,167.86 0.00 % 0.00 0.00 (8,175.02) 8,176.02 14,015.3239,494.0061-0440-4551 GENERATION CREDIT 1,680.00 0.00 % 0.00 0.00 (39,494.00) 205,898.00 352,968.00

(529,608.24)61-0440-4552 DISPERSED GENERATION CREDIT (105,072.24) 53.95 % (131,600.00) (981,698.00) (452,089.76) (379,457.00) (815,441.00)0.0061-0440-4553 ADDITIONAL REVENUE/CIP 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0061-0440-4554 RATE INCREASE 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

(21,519.17)61-0440-4555 A/C CREDIT (10,800.00) 43.04 % (10,119.00) (50,000.00) (28,480.83) (21,242.00) (53,015.00)2,575,968.72 16,015,764.02 2,919,418.00 28,967,244.00 12,951,479.98 15,837,399.31 28,506,745.99TOTAL ELECTRIC OPERATING R 55.29 %

INTEREST INCOME41,530.9361-0460-4691 INTEREST & DIVIDEND INCOME 10,477.56 51.91 % 4,874.00 80,000.00 38,469.07 66,879.74 117,757.31

10,477.56 41,530.93 4,874.00 80,000.00 38,469.07 66,879.74 117,757.31TOTAL INTEREST INCOME 51.91 %

OTHER OPERATING REVE165,110.9061-0470-4700 SECURITY REVENUE 28,662.81 62.31 % 23,871.00 265,000.00 99,889.10 160,469.76 295,600.06129,186.4861-0470-4701 CUSTOMER DELINQUENT PENALTIES 22,295.45 52.73 % 18,678.00 245,000.00 115,813.52 123,763.64 238,313.9555,074.3761-0470-4702 DISCONNECT & RECONNECT CHARGE 6,100.00 110.15 % 4,745.00 50,000.00 (5,074.37) 96,051.52 156,203.69

150.0061-0470-4703 MISC ELEC REVENUE - TEMP CHG 0.00 6.00 % 333.00 2,500.00 2,350.00 600.00 750.000.0061-0470-4704 STREET LIGHT 0.00 0.00 % 6,920.00 7,500.00 7,500.00 7,400.00 8,019.770.0061-0470-4711 MERCH JOBBING & CONTRACT WORK 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

34,217.9061-0470-4715 NON-UTILITY OPERATIONS 10,214.63 52.64 % 0.00 65,000.00 30,782.10 19,838.53 53,040.707,000.0061-0470-4720 GRE GENERATION - PEAKING PLANT 7,000.00 100.00 % 7,000.00 7,000.00 0.00 7,000.00 7,000.00

615,677.8861-0470-4721 LFG PROJECT 86,546.34 58.52 % 79,618.00 1,052,000.00 436,322.12 603,126.78 1,053,806.5231,116.0261-0470-4722 MISC NON-UTILITY 1,662.06 88.90 % 1,288.00 35,000.00 3,883.98 31,145.12 83,725.31

0.0061-0470-4723 GAIN ON DISPOSITION OF PROP 0.00 0.00 % 0.00 0.00 0.00 11,471.00 11,471.000.0061-0470-4724 SALES OF MERCHANDISE 0.00 0.00 % 0.00 500.00 500.00 116.32 262.96

7,980.0061-0470-4750 RENTAL PROPERTY INCOME 1,860.00 0.00 % 0.00 0.00 (7,980.00) 0.00 0.000.0061-0470-4760 TRANSFER IN FROM CITY 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0061-0470-4799 PRIOR PERIOD ADJUSTMENT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

31




Revenue (Continued)ELECTRICOTHER OPERATING REVE

0.0061-0470-9998 PRIOR PERIOD ADJUSTMENT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00164,341.29 1,045,513.55 142,453.00 1,729,500.00 683,986.45 1,060,982.67 1,908,193.96TOTAL OTHER OPERATING REVE 60.45 %

2,750,787.57 13,673,935.5017,102,808.50 3,066,745.00 30,776,744.00 16,965,261.72 30,532,697.26TOTAL ELECTRIC 55.57 %

30,532,697.2616,965,261.7213,673,935.5030,776,744.003,066,745.002,750,787.57 17,102,808.50TOTAL Revenue 55.57 %

ExpenseELECTRICOPERATING & MTCE EXP

0.0061-0540-5054 LFG MTCE (1,760.00) 0.00 % 0.00 0.00 0.00 0.00 0.0038,716.2161-0540-5461 OPERATING SUPERVISION 5,352.74 53.20 % 5,721.00 72,775.00 34,058.79 37,648.83 68,206.98

0.0061-0540-5462 INTERNAL COMBUST OPER/SALARIES 0.00 0.00 % 0.00 0.00 0.00 0.00 0.0011,122.2461-0540-5471 DIESEL OIL FUEL 2,076.15 61.79 % 1,049.00 18,000.00 6,877.76 6,737.19 12,850.1212,811.7361-0540-5472 NATURAL GAS 775.52 58.24 % 1,047.00 22,000.00 9,188.27 9,389.12 14,414.85

0.0061-0540-5481 LUBE OIL 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0061-0540-5482 CHEMICALS 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

33,513.1361-0540-5483 STATION PWR & WTR CONSP/PLANT 6,749.46 67.03 % 4,166.00 50,000.00 16,486.87 23,611.43 48,126.983,434.2761-0540-5484 OTHER EXP/PLANT SUPPLIES-ETC 552.40 38.16 % 236.00 9,000.00 5,565.73 5,406.46 7,318.344,577.3461-0540-5491 MISC OTHER PWR GENERATION EXP 73.64 65.39 % 54.00 7,000.00 2,422.66 4,608.49 7,439.03

13,859.2761-0540-5521 MAINTENANCE OF STRUCTURE/PLANT 198.49 77.00 % 1,015.00 18,000.00 4,140.73 13,117.43 19,550.22(2,054.51)61-0540-5531 MTCE OF ENGINES/GENERATORS-PL 0.00 -11.41 % 0.00 18,000.00 20,054.51 12,894.08 14,067.2915,310.5461-0540-5541 MTCE OF PLANT/LAND IMPROVEMENT 472.62 306.21 % 363.00 5,000.00 (10,310.54) 4,449.24 10,777.37

11,478,454.6661-0540-5551 PURCHASED POWER 2,258,559.48 53.00 % 2,393,019.00 21,658,687.97 10,180,233.31 11,369,797.48 20,499,773.480.0061-0540-5552 LFG PURCHASED GAS 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0061-0540-5561 PLANT STANDBY 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

2,273,050.50 11,609,744.88 2,406,670.00 21,878,462.97 10,268,718.09 11,487,659.75 20,702,524.66TOTAL OPERATING & MTCE EXP 53.06 %

LANDFILL GAS91,577.0861-0550-5050 LFG PURCHASED GAS 13,958.63 57.24 % 14,378.00 160,000.00 68,422.92 91,325.22 159,143.18

274,749.4061-0550-5051 LANDFILL GAS O&M 40,505.33 54.45 % 42,707.00 504,588.00 229,838.60 280,298.75 472,198.35597.2461-0550-5052 LFG ADMIN 44.89 3.80 % 42.00 15,720.00 15,122.76 43.50 16,277.50

7,909.1561-0550-5053 LFG INSURANCE 1,394.05 60.84 % 1,058.00 13,000.00 5,090.85 7,251.93 12,731.042,391.9861-0550-5054 LFG MTCE 1,491.98 11.96 % 66.00 20,000.00 17,608.02 14,075.00 22,896.27

57,394.88 377,224.85 58,251.00 713,308.00 336,083.15 392,994.40 683,246.34TOTAL LANDFILL GAS 52.88 %

DISTRIBUTION EXPENSE127.5461-0580-5801 REMOVE EXISTING SERV & METERS 0.00 0.00 % 0.00 0.00 (127.54) 73.57 1,521.66

0.0061-0580-5821 SCADA EXPENSES 0.00 0.00 % 667.00 8,000.00 8,000.00 0.00 0.007,011.7261-0580-5831 TRANSFORMER EX/OVERHD & UNDERG 1,104.82 35.06 % 2,023.00 20,000.00 12,988.28 8,980.77 26,311.27

642.3261-0580-5851 MTCE OF SIGNAL SYSTEMS 147.63 21.41 % 654.00 3,000.00 2,357.68 1,604.91 1,745.54707.6461-0580-5861 METER EXP - REMOVE & RESET 60.02 5.05 % 1,859.00 14,000.00 13,292.36 6,479.50 7,080.28

0.0061-0580-5871 TEMP SERVICE-INSTALL & REMOVE 0.00 0.00 % 88.00 1,000.00 1,000.00 591.29 926.5991,538.7861-0580-5881 MISC DISTRIBUTION EXPENSE 6,756.39 57.96 % 10,116.00 157,925.00 66,386.22 92,527.47 147,201.42

8,068.86 100,028.00 15,407.00 203,925.00 103,897.00 110,257.51 184,786.76TOTAL DISTRIBUTION EXPENSE 49.05 %

MAINTENANCE EXPENSE32




Expense (Continued)ELECTRICMAINTENANCE EXPENSE

12,747.9561-0590-5911 MTCE OF STRUCTURES 1,432.30 50.99 % 2,646.00 25,000.00 12,252.05 12,913.55 21,758.887,367.9661-0590-5921 MTCE OF SUBSTATIONS 553.05 29.47 % 1,892.00 25,000.00 17,632.04 8,932.66 16,369.912,482.1161-0590-5922 MTCE OF SUBSTATION EQUIPMENT 0.00 24.82 % 99.00 10,000.00 7,517.89 3,259.23 13,348.14

50,573.5261-0590-5931 MTCE OF OVERHD LINES/TREE TRIM 246.02 56.19 % 698.00 90,000.00 39,426.48 51,131.22 53,696.8112,474.7961-0590-5932 MTCE OF OVERHD LINES/STANDBY 1,959.94 41.58 % 2,918.00 30,000.00 17,525.21 14,702.16 26,144.4933,161.1961-0590-5933 MTCE OF OVERHEAD 5,050.38 55.27 % 4,369.00 60,000.00 26,838.81 31,042.01 52,507.2527,129.0761-0590-5941 MTCE OF UNDERGROUND/DISTRIB (7,911.68) 36.17 % 6,423.00 75,000.00 47,870.93 30,474.48 92,066.5213,811.5861-0590-5943 LOCATE UNDERGROUND PRIMARY 1,948.66 47.63 % 2,306.00 29,000.00 15,188.42 15,027.28 26,971.2739,925.8561-0590-5951 MTCE OF LINE TRANSFORMERS 7,914.01 399.26 % 1,027.00 10,000.00 (29,925.85) 6,040.79 16,495.4612,745.0261-0590-5961 MTCE OF STREET LIGHTING 2,148.83 36.41 % 2,784.00 35,000.00 22,254.98 14,801.17 34,699.633,534.3661-0590-5962 MTCE OF SECURITY LIGHTING 443.19 70.69 % 1,001.00 5,000.00 1,465.64 3,658.18 5,952.73

37,097.0461-0590-5971 MTCE OF METERS 3,213.21 88.33 % 1,893.00 42,000.00 4,902.96 31,696.59 60,108.174,292.2361-0590-5972 VOLTAGE COMPLAINTS 603.76 53.65 % 401.00 8,000.00 3,707.77 3,523.46 5,531.96

17,397.2461-0590-5981 SALARIES/TRANS & DISTRIBUTION 2,381.69 48.26 % 2,713.00 36,050.00 18,652.76 16,937.67 30,732.499,434.4261-0590-5985 ELECTRIC MAPPING 3,683.34 31.45 % 219.00 30,000.00 20,565.58 6,322.66 7,803.121,327.4461-0590-5991 MTCE OF OVERHEAD SERVICE/2NDRY (2,238.31) 8.85 % 871.00 15,000.00 13,672.56 3,500.33 6,491.14

14,809.4261-0590-5992 MTCE OF UNDERGROUND ELEC SERV 704.52 42.31 % 1,605.00 35,000.00 20,190.58 16,329.65 33,193.5911,069.2961-0590-5993 LOCATE UNDERGROUND SECONDARY 1,474.12 46.12 % 2,079.00 24,000.00 12,930.71 13,555.52 21,543.2582,749.5061-0590-5995 TRANSPORTATION EXPENSE 6,024.15 55.17 % (11,827.00) 150,000.00 67,250.50 60,054.73 95,272.86

29,631.18 394,129.98 24,117.00 734,050.00 339,920.02 343,903.34 620,687.67TOTAL MAINTENANCE EXPENSE 53.69 %

DEPRECIATION/ELECTRI1,256,823.3061-0595-8031 DEPRECIATION/ELECTRIC 179,575.00 58.32 % 184,741.00 2,154,900.00 898,076.70 1,260,000.00 2,099,593.76

179,575.00 1,256,823.30 184,741.00 2,154,900.00 898,076.70 1,260,000.00 2,099,593.76TOTAL DEPRECIATION/ELECTRI 58.32 %

INTEREST EXPENSE129,927.0561-0596-8071 INTEREST ON BONDS/LONG TERM 18,403.09 58.82 % 18,568.00 220,878.00 90,950.95 141,989.13 239,531.68(1,908.20)61-0596-8075 INTEREST ON DEFEASED BONDS (272.60) 59.31 % 0.00 (3,217.20) (1,309.00) 0.00 (3,271.20)

18,130.49 128,018.85 18,568.00 217,660.80 89,641.95 141,989.13 236,260.48TOTAL INTEREST EXPENSE 58.82 %

OTHER OPERATING EXPE0.0061-0597-8161 COST & EXP MERCH JOBBING/ELEC 0.00 0.00 % 0.00 0.00 0.00 93.76 93.76

127,274.5261-0597-8172 SECURITY EXPENSE 18,857.14 56.57 % 24,154.00 225,000.00 97,725.48 130,902.42 218,840.797,273.1061-0597-8213 LOSS ON DISPOSITION OF PROP 0.00 36.37 % 0.00 20,000.00 12,726.90 6,681.21 9,211.45

0.0061-0597-8231 COST OF MERCHANDISE SOLD 0.00 0.00 % 0.00 0.00 0.00 0.00 308.580.0061-0597-8260 TRANSFER TO CITY FOR 99 BOND 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

279,390.6861-0597-8261 UTILITIES & LABOR DONATED 40,514.38 56.33 % 42,746.00 496,000.00 216,609.32 259,141.53 481,907.18430,082.5261-0597-8262 TRANSFER TO CITY 3% ER REVENUE 69,473.83 55.49 % 76,338.00 775,000.00 344,917.48 418,625.81 753,553.20

387.6961-0597-8263 OTHER DONATIONS 2,908.71 15.51 % 20,498.00 2,500.00 2,112.31 (10,132.21) (1,289.44)1,382.2561-0597-8264 DAM MAINTENANCE EXPENSE 1,382.25 0.00 % 0.00 0.00 (1,382.25) 0.00 0.00

0.0061-0597-8266 2004 AMORTIZATION ISSUANCE 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0061-0597-8267 2004 BOND DISCOUNT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0061-0597-8281 AMORTIZATION OF DEBT DISCOUNT 0.00 0.00 % 0.00 0.00 0.00 5,038.60 0.000.0061-0597-8311 OTHER INTEREST EXPENSE 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

42.9061-0597-8341 INTEREST PD ON METER DEPOSITS 11.86 0.86 % 61.00 5,000.00 4,957.10 17.54 335.520.0061-0597-8399 OPERATING TRANSFER/OTHER FUNDS 0.00 0.00 % 0.00 0.00 0.00 0.00 63,310.84

3,069.8861-0597-8400 RENTAL PROPERTY EXPENSE 393.20 0.00 % 0.00 0.00 (3,069.88) 0.00 84.44

33




Expense (Continued)ELECTRICOTHER OPERATING EXPE

133,541.37 848,903.54 163,797.00 1,523,500.00 674,596.46 810,368.66 1,526,356.32TOTAL OTHER OPERATING EXPE 55.72 %

CUSTOMER ACCOUNTS EX11,109.7861-0900-9021 METER READING EXPENSE 1,433.69 71.68 % 1,048.00 15,500.00 4,390.22 8,115.12 15,970.916,626.8861-0900-9030 COLLECTING EXP DISC/RECONNECT 1,028.24 57.62 % 1,016.00 11,500.00 4,873.12 6,094.53 10,806.74(880.00)61-0900-9041 CUSTOMER CHECKS RETURNED -NSF 0.00 -88.00 % 209.00 1,000.00 1,880.00 73.70 706.37

88,387.5861-0900-9051 MISC CUSTOMER ACCTS EXP-COMP 15,415.90 57.02 % 8,852.00 155,000.00 66,612.42 88,761.21 155,753.48(11,779.78)61-0900-9061 CUST BLGS NOT PD/SENT FOR COLL (1,033.93) -11.78 % (378.00) 100,000.00 111,779.78 2,684.89 42,394.67

16,843.90 93,464.46 10,747.00 283,000.00 189,535.54 105,729.45 225,632.17TOTAL CUSTOMER ACCOUNTS EX 33.03 %

ADMINISTRATIVE & GEN241,226.0561-0920-9201 SALARIES/OFFICE & COMMISSION 35,093.41 48.14 % 35,542.00 501,080.00 259,853.95 217,155.88 428,200.23

0.0061-0920-9205 TEMPORARY STAFFING 0.00 0.00 % 0.00 5,000.00 5,000.00 0.00 8,316.9735,953.8461-0920-9211 OFFICE SUPPLIES & EXPENSE 4,174.80 44.39 % 2,568.00 81,000.00 45,046.16 45,575.71 72,277.0010,692.9361-0920-9212 LT & WATER CONSUMPTION/OFFICE 1,640.87 53.46 % 1,531.00 20,000.00 9,307.07 7,371.80 17,933.86

755.9861-0920-9213 BANK CHARGES 266.18 18.90 % 294.00 4,000.00 3,244.02 2,221.17 3,757.2025,447.0161-0920-9221 LEGAL FEES 2,574.14 63.62 % 6,390.00 40,000.00 14,552.99 14,756.20 48,890.4211,050.4061-0920-9231 AUDITING FEES 0.00 55.25 % 0.00 20,000.00 8,949.60 11,050.40 11,050.40

101,350.1061-0920-9241 INSURANCE 14,533.66 55.38 % 17,000.00 183,000.00 81,649.90 78,195.12 139,018.3437,493.0761-0920-9260 UTILITY SHARE DEF COMP 0.00 63.55 % 0.00 59,000.00 21,506.93 38,598.41 38,598.41

191,868.0961-0920-9261 UTIL SH OF MEDICAL/DENTAL/DISA 26,801.36 49.84 % 34,343.00 385,000.00 193,131.91 196,537.02 317,081.4691,977.0161-0920-9262 UTILITY SHARE OF PERA 11,454.94 57.13 % 11,396.00 161,000.00 69,022.99 89,873.40 153,750.8193,959.6261-0920-9263 UTILITY SHARE OF FICA 13,834.07 56.95 % 13,656.00 165,000.00 71,040.38 89,844.51 155,510.5929,366.0461-0920-9264 EMPLOYEES SICK PAY 3,023.80 29.37 % 4,679.00 100,000.00 70,633.96 28,571.34 71,095.95

110,671.5861-0920-9266 EMP VACATION/HOLIDAY PAY 26,905.12 56.75 % 22,497.00 195,000.00 84,328.42 102,160.44 210,980.570.0061-0920-9268 MISCELLANEOUS - WELLHEAD PROT 0.00 0.00 % 0.00 0.00 0.00 0.00 (81.92)

55,216.5061-0920-9269 CONSERVATION IMP PROGRAM 11,742.47 19.50 % 12,013.00 283,227.00 228,010.50 80,546.68 143,111.2012,805.1361-0920-9281 ENVIRONMENTAL COMPLIANCE 1,762.04 42.68 % 2,646.00 30,000.00 17,194.87 15,457.15 25,383.061,390.0061-0920-9291 CONSULTING FEES 0.00 1.39 % 0.00 100,000.00 98,610.00 4,983.23 5,771.45

0.0061-0920-9292 LFG PROJECT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.0010,851.7961-0920-9301 TELEPHONE 1,895.93 60.29 % 1,303.00 18,000.00 7,148.21 9,638.72 18,766.563,464.8861-0920-9302 ADVERTISING 421.00 115.50 % 48.00 3,000.00 (464.88) 2,887.99 4,109.30

52,762.4061-0920-9303 DUES & SUBSCRIPTIONS - FEES 5,402.33 30.15 % 19,214.00 175,000.00 122,237.60 60,783.57 96,775.93625.4861-0920-9304 TRAVEL EXPENSE 0.00 6.25 % 454.00 10,000.00 9,374.52 2,997.28 3,441.19

79,264.3861-0920-9305 SCHOOLS & MEETINGS 8,215.16 61.54 % 7,938.00 128,799.75 49,535.37 89,928.75 145,613.170.0061-0920-9306 MISC GENERAL EXPENSE 0.00 0.00 % 22.00 1,000.00 1,000.00 213.81 10,159.120.0061-0920-9321 MTCE OF GEN PLANT/OFF HEATING 0.00 0.00 % 0.00 5,000.00 5,000.00 0.00 4,050.65

169,741.28 1,198,192.28 193,534.00 2,673,106.75 1,474,914.47 1,189,348.58 2,133,561.92TOTAL ADMINISTRATIVE & GEN 44.82 %

2,885,977.46 14,375,383.3816,006,530.14 3,075,832.00 30,381,913.52 15,842,250.82 28,412,650.08TOTAL ELECTRIC 52.68 %

28,412,650.0815,842,250.8214,375,383.3830,381,913.523,075,832.002,885,977.46 16,006,530.14TOTAL Expense 52.68 %

(135,189.89) 1,096,278.36 (9,087.00) 394,830.48 (701,447.88) 1,123,010.90 2,120,047.18PROFIT / (LOSS) :

34




RevenueWATERINTEREST INCOME

10,404.5762-0460-4691 INTEREST & DIVIDEND INCOME 2,622.59 35.88 % 1,688.00 29,000.00 18,595.43 16,740.97 30,871.43389.0662-0460-4692 OTHER INT/MISC REVENUE 389.06 38.91 % 500.00 1,000.00 610.94 486.32 972.64

3,011.65 10,793.63 2,188.00 30,000.00 19,206.37 17,227.29 31,844.07TOTAL INTEREST INCOME 35.98 %

OTHER OPERATING REVE1,995.0062-0470-4750 RENTAL PROPERTY INCOME 465.00 0.00 % 0.00 0.00 (1,995.00) 0.00 0.00

0.0062-0470-4799 PRIOR PERIOD ADJUSTMENT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0470-9998 PRIOR PERIOD ADJUSTMENT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

465.00 1,995.00 0.00 0.00 (1,995.00) 0.00 0.00TOTAL OTHER OPERATING REVE 0.00 %

SALES OF WATER874,173.1862-0610-6101 WATER SALES COMM & RES/COMPUT 201,844.03 42.83 % 268,537.00 2,041,234.00 1,167,060.82 949,057.51 2,219,144.55

0.0062-0610-6171 UNMETERED SALES 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00201,844.03 874,173.18 268,537.00 2,041,234.00 1,167,060.82 949,057.51 2,219,144.55TOTAL SALES OF WATER 42.83 %

OTHER WATER REVENUE0.0062-0620-6260 TRANSFER IN FROM CITY 0.00 0.00 % 0.00 0.00 0.00 1,371.99 1,371.990.0062-0620-6300 SERVICES DONATED BY CITY 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

8,591.5962-0620-6301 CUSTOMER PENALTIES 2,042.08 50.54 % 1,479.00 17,000.00 8,408.41 8,028.22 20,610.432,325.0062-0620-6323 GAIN ON DISPOSITION OF PROP 0.00 0.00 % 0.00 0.00 (2,325.00) 0.00 0.00

110,265.6062-0620-6401 WATER/ACCESS/CONNECTION FEES 16,927.20 160.58 % 1,276.00 68,666.00 (41,599.60) 110,875.50 174,606.7815,569.4562-0620-6402 MISC CONNECTION FEES 3,555.00 103.80 % 1,535.00 15,000.00 (569.45) 13,214.12 25,386.62

296.7062-0620-6403 MISCELLANEOUS REVENUE 0.00 14.84 % 9.00 2,000.00 1,703.30 3,251.00 4,330.620.0062-0620-6405 CONTRIBUTIONS FROM DEVELOPERS 0.00 0.00 % 0.00 0.00 0.00 0.00 218,845.00

54,990.6562-0620-6406 WATER TOWER LEASE 8,541.00 56.11 % 8,300.00 98,000.00 43,009.35 42,338.73 73,435.3831,065.28 192,038.99 12,599.00 200,666.00 8,627.01 179,079.56 518,586.82TOTAL OTHER WATER REVENUE 95.70 %

236,385.96 1,192,899.201,079,000.80 283,324.00 2,271,900.00 1,145,364.36 2,769,575.44TOTAL WATER 47.49 %

2,769,575.441,145,364.361,192,899.202,271,900.00283,324.00236,385.96 1,079,000.80TOTAL Revenue 47.49 %

ExpenseWATEROTHER OPERATING EXPE

25,000.0062-0597-8260 TRANSFER TO CITY FOR 99 BOND 0.00 100.00 % 0.00 25,000.00 0.00 25,000.00 25,000.000.0062-0597-8399 OPERATING TRANSFER/OTHER FUNDS 0.00 0.00 % 0.00 0.00 0.00 0.00 15,827.71

767.4662-0597-8400 RENTAL PROPERTY EXPENSE 98.30 0.00 % 0.00 0.00 (767.46) 0.00 21.1098.30 25,767.46 0.00 25,000.00 (767.46) 25,000.00 40,848.81TOTAL OTHER OPERATING EXPE 103.07 %

WATER PRODUCTION EXP6,218.1862-0700-7021 MTCE OF STRUCTURES 106.65 34.53 % 106.00 18,010.00 11,791.82 2,238.82 19,210.523,262.1762-0700-7022 TOWER & GROUNDS INSPECTION 423.12 66.57 % 1,489.00 4,900.00 1,637.83 1,402.02 3,218.50

529.77 9,480.35 1,595.00 22,910.00 13,429.65 3,640.84 22,429.02TOTAL WATER PRODUCTION EXP 41.38 %

PUMPING EXPENSE

35




Expense (Continued)WATERPUMPING EXPENSE

5,653.5362-0710-7101 SUPERVISION 842.99 54.89 % 854.00 10,300.00 4,646.47 5,464.77 9,869.71135,814.3362-0710-7181 SUPPLIES & EXPENSE 21,231.16 55.43 % 22,897.00 245,000.00 109,185.67 132,187.32 244,919.89

4,097.9362-0710-7182 SAMPLING 472.00 81.96 % 443.00 5,000.00 902.07 2,726.42 6,596.7422,025.9262-0710-7183 CHEMICAL FEED 3,557.51 50.63 % 4,581.00 43,500.00 21,474.08 22,752.92 40,587.09

(179.18)62-0710-7201 MTCE OF ELECT PUMPING EQUIP 57.71 -2.56 % 4,994.00 7,000.00 7,179.18 8,618.43 8,921.5856,900.3762-0710-7220 MTCE OF WELLS 5,012.54 63.93 % 5,000.00 89,000.00 32,099.63 37,254.51 121,719.15

0.0062-0710-7225 GENERATION 0.00 0.00 % 116.00 200.00 200.00 112.50 194.325,530.8062-0710-7230 SCADA - PUMPING 600.23 263.37 % 0.00 2,100.00 (3,430.80) 0.00 3,496.62

31,774.14 229,843.70 38,885.00 402,100.00 172,256.30 209,116.87 436,305.10TOTAL PUMPING EXPENSE 57.16 %

WATER DISTRIBUTION E33,045.0262-0730-7301 MTCE OF WATER MAINS 7,591.02 236.04 % 538.00 14,000.00 (19,045.02) 19,668.18 27,504.80

962.3862-0730-7302 WATER VALVE REPAIR 537.55 24.06 % 133.00 4,000.00 3,037.62 2,031.00 2,795.263,097.0662-0730-7309 LOCATE WATER SVC 374.67 61.94 % 488.00 5,000.00 1,902.94 2,933.63 5,084.081,102.5962-0730-7310 LOCATE WATER MAIN 416.53 44.10 % 361.00 2,500.00 1,397.41 630.49 1,178.55

65,615.5062-0730-7311 MTCE OF WATER SERVICES 1,790.42 158.11 % 2,210.00 41,500.00 (24,115.50) 10,856.53 22,883.354,689.2162-0730-7312 WATER METER SERVICE 227.36 66.99 % 122.00 7,000.00 2,310.79 9,135.53 15,033.571,878.6262-0730-7315 INSTALL & MTC IRRIG METERS 895.47 37.57 % 473.00 5,000.00 3,121.38 2,736.57 6,111.24

12,890.2762-0730-7321 MTCE OF CUSTOMERS SERVICE 2,341.16 42.97 % 2,198.00 30,000.00 17,109.73 15,569.09 25,869.910.0062-0730-7322 WATER SERVICE INSPECTIONS 0.00 0.00 % 17.00 200.00 200.00 0.00 0.00

1,945.3562-0730-7325 WATER MAPPING 377.43 7.63 % 1,668.00 25,500.00 23,554.65 2,513.51 2,917.854,123.6162-0730-7330 SCADA - DISTRIBUTION 676.74 196.36 % 0.00 2,100.00 (2,023.61) 0.00 4,334.942,903.4162-0730-7331 MTCE OF WATER HYDRANTS 1,538.33 29.03 % 3,814.00 10,000.00 7,096.59 9,265.48 9,702.227,727.3762-0730-7341 MISC WATER EXPENSE/INVENTORY 2,488.80 64.39 % 1,316.00 12,000.00 4,272.63 6,559.80 10,973.042,806.2962-0730-7391 WAGES/WATER 421.50 51.02 % 456.00 5,500.00 2,693.71 2,732.38 4,934.859,002.9962-0730-7395 TRANSPORTATION EXPENSE 1,275.84 90.03 % 300.00 10,000.00 997.01 4,405.73 11,199.43

14,582.4562-0730-7399 GENERAL EXP/WATER PERMIT 0.00 104.16 % 0.00 14,000.00 (582.45) 12,257.00 12,257.0020,952.82 166,372.12 14,094.00 188,300.00 21,927.88 101,294.92 162,780.09TOTAL WATER DISTRIBUTION E 88.35 %

WATER ACCOUNTING EXP3,156.7162-0740-7431 METER READING EXPENSE 514.28 48.56 % 843.00 6,500.00 3,343.29 3,167.61 6,225.05

514.28 3,156.71 843.00 6,500.00 3,343.29 3,167.61 6,225.05TOTAL WATER ACCOUNTING EXP 48.56 %

DEPRECIATION EXPENSE630,000.0062-0745-7451 DEPRECIATION - WATER 90,000.00 58.12 % 89,579.00 1,083,998.00 453,998.00 615,000.00 1,028,593.07

90,000.00 630,000.00 89,579.00 1,083,998.00 453,998.00 615,000.00 1,028,593.07TOTAL DEPRECIATION EXPENSE 58.12 %

INTEREST EXPENSE53,203.5962-0748-7481 INTEREST ON BONDS/LONG TERM 7,410.87 48.37 % 9,062.00 110,000.00 56,796.41 62,381.72 106,073.57

(477.05)62-0748-7485 INTEREST ON DEFEASED BONDS (68.15) 58.33 % 0.00 (817.80) (340.75) 0.00 (817.80)7,342.72 52,726.54 9,062.00 109,182.20 56,455.66 62,381.72 105,255.77TOTAL INTEREST EXPENSE 48.29 %

OTHER OPERATING EXPE

36




Expense (Continued)WATEROTHER OPERATING EXPE

0.0062-0750-7562 COST & EXP MERCH JOBBING 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0750-7563 AMORTIZATION 1993 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0750-7564 AMORTIZATION 1994 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0750-7565 AMORTIZATION 1997 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0750-7566 AMORTIZATION 1998 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0750-7567 AMORTIZATION 2001 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0750-7568 AMORTIZATION 2003 0.00 0.00 % 0.00 0.00 0.00 2,747.50 0.000.0062-0750-7569 AMORTIZATION 2008 0.00 0.00 % 0.00 0.00 0.00 4,334.47 0.000.0062-0750-7581 2010 GO BONDS AMORT DISCOUNT 0.00 0.00 % 0.00 0.00 0.00 (377.86) (0.20)0.0062-0750-8213 LOSS ON DISPOSITION OF PROP 0.00 0.00 % 0.00 1,000.00 1,000.00 956.85 999.61

0.00 0.00 0.00 1,000.00 1,000.00 7,660.96 999.41TOTAL OTHER OPERATING EXPE 0.00 %

NONOPERATING REV&EXP0.0062-0790-7900 OPERATING TRANSFER FROM CITY 0.00 0.00 % 0.00 0.00 0.00 0.00 0.000.0062-0790-8261 UTILITIES & LABOR DONATED 0.00 0.00 % 42.00 500.00 500.00 0.00 0.00

0.00 0.00 42.00 500.00 500.00 0.00 0.00TOTAL NONOPERATING REV&EXP 0.00 %

CUSTOMER ACCOUNTS EX0.0062-0900-9030 COLLECTING EXP DISC/RECONNECT 0.00 0.00 % 0.00 6,000.00 6,000.00 372.00 372.00

23,951.4462-0900-9051 MISC CUSTOMER ACCTS EXP-COMP 3,815.25 53.23 % 3,105.00 45,000.00 21,048.56 25,848.36 41,602.17312.6462-0900-9061 CUST BLGS NOT PD/SENT FOR COLL 0.00 6.25 % 0.00 5,000.00 4,687.36 5.79 186.19

3,815.25 24,264.08 3,105.00 56,000.00 31,735.92 26,226.15 42,160.36TOTAL CUSTOMER ACCOUNTS EX 43.33 %

ADMINISTRATIVE & GEN

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Expense (Continued)WATERADMINISTRATIVE & GEN

62,481.6962-0920-9201 SALARIES/OFFICE & COMMISSION 8,773.35 50.63 % 8,838.00 123,420.00 60,938.31 55,934.49 110,250.030.0062-0920-9205 TEMPORARY STAFFING 0.00 0.00 % 0.00 2,000.00 2,000.00 0.00 2,079.19

12,124.9062-0920-9211 OFFICE SUPPLIES & EXPENSE 856.30 37.89 % (2,728.00) 32,000.00 19,875.10 17,761.58 28,262.992,673.2062-0920-9212 LT & WATER CONSUMPTION/OFFICE 410.22 76.38 % 292.00 3,500.00 826.80 1,473.57 4,114.07

469.4862-0920-9213 BANK CHARGES 66.54 46.95 % 72.00 1,000.00 530.52 544.54 965.302,422.5362-0920-9222 LEGAL FEES 207.91 44.05 % 312.00 5,500.00 3,077.47 1,437.80 3,524.752,762.6062-0920-9231 AUDITING FEES 0.00 89.12 % 0.00 3,100.00 337.40 2,762.60 2,762.60

16,308.7462-0920-9241 INSURANCE 2,122.69 49.42 % 3,835.00 33,000.00 16,691.26 12,600.10 18,343.270.0062-0920-9251 WATER UTILITY CONTRIBUTION 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

9,373.2762-0920-9260 UTILITY SHARE DEF COMP 0.00 93.73 % 0.00 10,000.00 626.73 9,649.60 9,649.6060,930.5962-0920-9261 UTIL SH OF MEDICAL/DENTAL/DISA 8,647.59 55.90 % 9,765.00 109,000.00 48,069.41 63,297.68 101,822.7811,675.3562-0920-9262 UTILITY SHARE OF PERA 1,069.54 64.86 % 1,025.00 18,000.00 6,324.65 10,142.49 17,192.8412,246.7262-0920-9263 UTILITY SHARE OF FICA 1,526.26 64.46 % 1,496.00 19,000.00 6,753.28 10,582.34 18,054.847,341.5162-0920-9264 EMPLOYEES SICK PAY 755.95 36.71 % 925.00 20,000.00 12,658.49 7,142.82 17,982.33

27,667.9062-0920-9267 EMP VACATION/HOLIDAY PAY 6,726.28 55.34 % 5,772.00 50,000.00 22,332.10 25,542.60 52,731.98802.4562-0920-9268 MISCELLANEOUS - WELLHEAD PROT 56.18 40.12 % 254.00 2,000.00 1,197.55 9,925.06 10,245.49

5,670.9562-0920-9269 CONSERVATION IMP PROGRAM 317.00 56.71 % 191.00 10,000.00 4,329.05 2,417.26 4,645.43379.2462-0920-9281 ENVIRONMENTAL COMPLIANCE 36.35 379.24 % 0.00 100.00 (279.24) 0.00 210.98

0.0062-0920-9292 LFG PROJECT 0.00 0.00 % 0.00 0.00 0.00 0.00 0.006,760.0062-0920-9293 CONSULTING 0.00 75.11 % 0.00 9,000.00 2,240.00 2,334.57 3,441.632,725.3662-0920-9301 TELEPHONE 473.97 60.56 % 325.00 4,500.00 1,774.64 2,365.64 4,702.56

194.4062-0920-9302 ADVERTISING 0.00 6.48 % 15.00 3,000.00 2,805.60 2,515.98 3,230.1815,094.5862-0920-9303 DUES & SUBSCRIPTIONS - FEES 220.67 40.80 % 538.00 37,000.00 21,905.42 14,673.35 29,093.14

0.0062-0920-9304 TRAVEL EXPENSE 0.00 0.00 % 137.00 2,000.00 2,000.00 439.32 390.8211,443.6762-0920-9305 SCHOOLS & MEETINGS 1,159.84 65.86 % 1,765.00 17,377.00 5,933.33 10,008.55 16,882.58

71.1662-0920-9307 MISC GENERAL EXPENSE 0.00 14.23 % 0.00 500.00 428.84 201.39 (550.35)0.0062-0920-9321 MTCE OF GEN PLANT/OFF HEATING 0.00 0.00 % 0.00 1,750.00 1,750.00 0.00 1,012.66

33,426.64 271,620.29 32,829.00 516,747.00 245,126.71 263,753.33 461,041.69TOTAL ADMINISTRATIVE & GEN 52.56 %

OPERATING TRANSFER O0.0062-0999-9999 RESTATE BEGINNING RETAINED EAR 0.00 0.00 % 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00TOTAL OPERATING TRANSFER O 0.00 %

188,453.92 999,005.951,413,231.25 190,034.00 2,412,237.20 1,317,242.40 2,306,638.37TOTAL WATER 58.59 %

2,306,638.371,317,242.40999,005.952,412,237.20190,034.00188,453.92 1,413,231.25TOTAL Expense 58.59 %

47,932.04 (334,230.45) 93,290.00 (140,337.20) 193,893.25 (171,878.04) 462,937.07PROFIT / (LOSS) :

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UTILITIES COMMISSION MEETING TO: Elk River Municipal Utilities Commission John Dietz – Chair Daryl Thompson – Vice Chair Al Nadeau – Trustee

FROM: Troy Adams, P.E. – General Manager

MEETING DATE: September 10, 2012

AGENDA ITEM NUMBER: 2.4

SUBJECT: Minnesota Municipal Utilities Association Safety Management Program Contract Renewal BACKGROUND: Elk River Municipal Utilities (ERMU) contracts with Minnesota Municipal Utilities Association (MMUA) to provide safety training through their Safety Management Program and Job Training and Safety (JTS) Program. The Safety Management Program provides required trainings on topics such as blood borne pathogens and right to know. The program also provides customer specific trainings like Pole Top Rescue training and OSHA compliance inspections for water and electric facilities. Elk River Municipal Utilities is one of ten municipals in the Central Group of the Safety Management Program. The JTS program provides training more specifically for the electric and technical service departments. Elk River Municipal Utilities is one of six in our JTS group. The contract period runs from October – September. DISCUSSION: In the 2012-2013 contract period for the MMUA Safety Management Program, ERMU’s cost was $18,950. For the 2013-2014 contract period, ERMU’s cost would increase by $300 for a total of $19,250. Since 2009, the MMUA JTS Program’s cost for ERMU was $6,000 annually. For the 2013-2014 contract period, ERMU’s cost would again remain the same. ACTION REQUESTED: Staff recommends approving the renewal of the MMUA Safety Management Program and JTS Program for the 2013-2014 contract period for a total cost of $25,250. ATTACHMENTS:

2013-2014 Minnesota Municipal Utilities Association Safety Management Program Memo and Amendment to Services Agreement – dated August 26, 2013.

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UTILITIES COMMISSION MEETING TO: Elk River Municipal Utilities Commission John Dietz – Chair Al Nadeau – Vice Chair Daryl Thompson – Trustee

FROM: Theresa Slominski – Finance and Office Manager



SUBJECT: Resolution Accepting NISC invitation BACKGROUND: A committee of staff has been researching software vendors for a new customer utility billing software and have been focused on the National Information Solution Cooperative (NISC) software this past month. We have participated in conference calls and webinars, conducted reference checks, visited a current user site, and had an onsite demo September 4th and 5th for all staff to have the opportunity to see the software. DISCUSSION: Our current software vendor (PowerManager) has an annual user’s group conference each year that we have participated in. The user group conferences have always provided valuable learning experiences as well as insight with how other users are maximizing the software and managing the customer information to best serve the customer. We have sent a minimum of two people every year, and sometimes have been able to coordinate schedules so most staff can attend at some point during the three day conference. NISC offers an annual conference as well in St. Louis, Missouri – the MIC (Member Information Conference). They would like for us to be able to fully evaluate their software product and have offered four conference tickets (a $600 per ticket value) to our staff to be able to attend this year. The budget for attending the PowerManager conference would be re-allocated to the NISC conference, providing the commission is willing to accept the four tickets offered. This provides a valuable opportunity to obtain training and interact with other users that we would not otherwise be able to take advantage of. The attached resolution is a standard procedure recommended by our legal counsel to be able to accept the tickets at a discounted price, in furthering the purpose of Elk River Municipal Utilities through the training of customer service staff and utilization of customer service products. ACTION REQUESTED: Staff requests adoption of Resolution to accept NISC invitation for four tickets to annual Member Information Conference. ATTACHMENTS:

Resolution Accepting NISC’s MIC Invitation

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RESOLUTION No. 13-8

BOARD OF COMMISSIONERS

ELK RIVER MUNICIPAL UTILITIES A RESOLUTION OF THE BOARD OF COMMISSIONERS OF ELK RIVER MUNICIPAL UTILITIES ACCEPTING AN INVITATION TO ATTEND THE 2013 NATIONAL INFORMATION SOLUTIONS COOPERATIVE MEMBER INFORMATION CONFERENCE WHEREAS, National Information Solution Cooperative has invited ERMU to send four ERMU employees to NISC’s 2013 Member Information Conference in St. Louis, Missouri without paying the normal $600 per attendee charge; and WHEREAS, The Board finds that it is in the best interests of ERMU to accept this invitation so that ERMU staff can learn more about NISC and its products from presentations at the conference and from interacting with other users of NISC products. NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF COMMISSIONERS OF ELK RIVER MUNICIPAL UTILITIES:

A. To accept the invitation of NISC to send four ERMU employees to the 2013 NISC Member Information Conference.

This Resolution Passed and Adopted this 10th day of September, 2013.

John J. Dietz, Chair

Troy Adams, P.E., General Manager

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FROM: David Berg – Water Superintendent



SUBJECT: Freeport Water Tower Rehabilitation Project Update BACKGROUND: The Freeport Water Tower Rehabilitation project started back in April 2013. The crew has sandblasted, painted, and fixed structural repairs on the inside and outside of the tower. DISCUSSION: The water tower is almost completed. Due to rigorous inspection standards, we have had to ask the crew to go back and touch up some areas, which has set us back time wise. We will be showing a picture timeline during the meeting and will explain the process further. ACTION REQUESTED: There is no action requested.

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FROM: Wade Lovelette – Superintendent of Technical Services



SUBJECT: North Substation Upgrade Update DISCUSSION: The preliminary work for the upgrade at the North Substation has begun. Granite City Construction has started the excavation work for widening the driveway to the substation and expanding the parking area. A temporary fence had to be put in place for the landowner’s cattle until the dirt work was complete. After that was completed, the permanent fence was put back up and a new gate was installed for him. We have five substation meters inside the meter building that have to be moved to an outside wall. Our meter technicians took care of this project on August 28th. We are scheduled to switch out the North Substation on September 24th, remove the 10.5 MVA transformer on September 25th and install the new substation transformer on September 26th. We are planning for a two week outage on that substation to get everything wired and installed. The North Substation should be back online by October 8th. I have a slide show of some preliminary photos of how the substation looks before the upgrade takes place. We will show this during the meeting.

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UTILITIES COMMISSION MEETING TO: Elk River Municipal Utilities Commission John Dietz – Chair Daryl Thompson – Vice Chair Al Nadeau – Trustee




SUBJECT: 2014 Budget: 10-Year Capital Project Projections, Capital Purchases and Equipment, and the Conservation Improvement Program BACKGROUND: In preparation for submittal in November, staff continues to work through the 2014 budget process. The first cut of the capital budget portion of the 2014 budget has been completed for commission review. The capital budget may change as the complete 2014 budget is assembled and when the wholesale power costs, rate changes, and cash flow become more definite. DISCUSSION: Attached is the following information for your review:

1. Electric Department Capital Budget – This includes large non-recurring capital construction projects, recurring capital construction projects and asset preservation, and capital equipment purchases. Notable items for 2014 are a new feeder from 75 to 194th, replacing a bucket truck, and a cable plow. The Admin and Tech share of the budgets is a larger item this year with the new software.

2. Electric Department Projects Time Schedule 10-year Projection – This highlights large non-recurring capital construction projects, recurring capital construction projects, and asset preservation.

3. Water Department Capital Budget – This includes large non-recurring capital

construction projects, recurring capital construction projects and asset preservation, and capital equipment purchases. Notable items for 2014 are a water main construction project for filter 9 and replacing a pickup truck. The Admin and Tech share of the budgets is a larger item this year with the new software.

4. Water Department Project Time Schedule – This highlights large non-recurring capital construction projects, recurring capital construction projects, and asset preservation.

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5. Technology Services and Administrative Capital Budgets – This includes capital

equipment purchases as well as some noteworthy non-recurring expenses purchases. Notable items for 2014 include the new software and the Landfill scheduled replacement of 3 engines.

6. Conservation Improvement Program (CIP) Budget – This includes detailed information about the cost of the specific programs as well as the historic participation numbers.

Additional information on the vehicle evaluations is available upon request. ACTION REQUESTED: No action requested.

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Elk River Municipal Utilities

2014 Electric Department Capital Budget

Capital Construction Projects - Non-Recurring Normal Distribution, Feeders, and Substations

Priority Cost Description4 100,000$ Rebuild River Ranch

-$ Rebuild Sandpiper Estates delay 2015 100,000$ 8 75,000$ Single Phase OH Baldwin and Line Ave2 300,000$ New Feeder 75 to 194th1 100,000$ Triple Deck Feeders 93, 94, 95 Underground3 100,000$ Feeder 42 and 71 Feeder Tie9 50,000$ Country Crossing III

New Feeder to Court House delay 2015 1,500,000$ 6 25,000$ Tescom Rebuild7 75,000$ Rebuild Feeder 62 OH North of 33

10 150,000$ Rebuild Feeder 42 OH South of 33 to County garage5 200,000$ Garage addition

Subtotal 1,175,000$

Capital Construction Projects - Recurring

Cost Description100,000$ Transformers and Meters200,000$ New Development Distribution Installation

50,000$ Ongoing OH Equip Replacement (Poles, Switches, Cut-Outs)200,000$ Ongoing URD Equip Replacement (Switches, J-Boxes, Fuse Pads)

12,000$ Street Lighting Replacement8,000$ Territory Acquisition - compensation on future customers 10 yrs pmt

Future Territory Acquisition12,000$ Painting poles to extend life

-$ Additional FeedersSubtotal 582,000$

Administration Noteworthy Non-Recurring Expenses

Cost Description20,000$ Mapping Consultant

Subtotal 20,000$

Capital Equipment Needs

Cost Description11,400$ Laptop Computers, Software, Accessories

1,000$ Lunchroom chairs2,000$ SCADA equipment

Replace Digger Truck #10 with new delay 2016 250,000$ 200,000$ Replace Bucket Truck #11 with new107,000$ Cable Plow - delayed from 2013

Replace Bucket Truck #21 with new 2015 210,000$ 37,000$ Mini Excavator80,000$ Vactron

1,500$ Concrete Saw15,000$ Wire Trailer (share with water department)

151,760$ 80% share of Admin and Tech budgets (excluding LFG engine replacement)

Subtotal 606,660$

Total 2,383,660$

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1234

363738394041424344454647484950515253545556575859606162636465666768697071727374757677787980

A B J K L M N O P Q R SElk River Municipal Utilities2014 Electric Department Capital Projects Time Schedule

Description 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Rebuild River Ranch $100,000 $100,000Co Rd 30 Rebuild Troy & Union StreetsRebuild Sandpiper Estates $100,000Rebuild Riverview Heights Front lot lineRebuild Irving 4,5,6 7 to front lot line & Presidential EstatesRebuild 6th & QuinnFeeder 94 Rebuild $0

Power Plant Sub Upgrade $500,000

Waco II Substation 1,500,000$

Convert Islandview to 7200Feeder 23 Reconductor Meadowvale

Feeder 23 Convert to 7200

New Feeder 75 to 194th $300,000

Feeder on Co Rd 1 from Co Rd 33 to 221st $300,000

Baldwin Rebuild OH to URD $75,000 $50,000New Feeder to Court House $1,500,000

Dayton Rebuild 2400 OH to 7200 URD $150,000 $150,000 $150,000Rebuild Feeder 42 OH South of 33 to County garage 150,000$ Feeder 42 OH to URD $1,000,000

New Feeder to tie Sub14-4 to Otsego Sub $500,000

Co Rd 39 Otsego Sub to Nashua - OH to URD $500,000Co Rd 39 Nashua to Naber - OH to URD $150,000Feeder 65 Rebuild OH from Landfill to North Sub ( Finance w/ LFG Project?) $500,000

North Substation Upgrade

Triple Deck Feeders 93, 94, 95 Underground $100,000

Tescom Rebuild $25,000Rebuild Feeder 62 OH North of 33 $75,000Rebuild GRE driveField Services Building addition $280,000 $1,200,000 $1,450,000Country Crossing III $50,000Feeder 42 and 71 Feeder Tie $100,000

Garage addition $200,000 $200,000 $300,000

Transformers and Meters $100,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000New Development Distribution Installation $200,000 $200,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000Ongoing OH Equip Replacement (Poles, Switches, Cut-Outs) $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000Ongoing URD Equip Replacement (Switches, J-Boxes, Fuse Pads) $200,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000Additional Feeders $750,000 $750,000 $750,000 $750,000 $750,000 $750,000

Total Substation Additions $0 $1,500,000 $0 $0 $500,000 $0 $0 $0 $0 $0Total Feeder Additions $400,000 $800,000 $1,000,000 $500,000 $750,000 $750,000 $750,000 $750,000 $750,000 $750,000Total Normal Distribution Construction $1,325,000 $2,150,000 $1,550,000 $1,030,000 $1,250,000 $1,800,000 $600,000 $600,000 $2,050,000 $600,000Total $1,725,000 $4,450,000 $2,550,000 $1,530,000 $2,500,000 $2,550,000 $1,350,000 $1,350,000 $2,800,000 $1,350,000

Total less substation additions $1,725,000 $2,950,000 $2,550,000 $1,530,000 $2,000,000 $2,550,000 $1,350,000 $1,350,000 $2,800,000 $1,350,000

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2014 Water Department Capital Budget

Water Capital Construction Needs

Cost Description300,000$ Water Main Construction Filter 9 project150,000$ Reclaim Backwash Water project

65,000$ Re-casing of Well #265,000$ New Chemical and Flouride Feed Pumps10,000$ Meters/ERTs

-$ New Well Construction 25,000$ Roof Repair Well #5, General Well House maintenance

Subtotal 615,000$

Water Noteworthy Non-Recurring Expenses

Cost Description70,000$ Repairs & Maintenance10,000$ Miscellaneous

5,000$ Water Main Repair6,500$ Computers/GIS/SCADA

20,000$ Auburn Tower sandblast/paint repair

35,000$ Jackson Water Tower10,000$ Mapping Consultant

1,500$ Generator1,500$ Concrete Saw4,000$ Line Tracer and Locator1,000$ Locator for Line Tracer

Subtotal 164,500$

Capital Equipment Needs

Cost Description

35,000$ Replace Pickup Truck #12 with new F2505,000$ Leak Detector

37,940$ 20% share of Admin & Tech budgets (excluding LFG engine replacement)5,000$ SCADA

Subtotal 82,940$

Total 862,440$

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Projects Project No 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Wells

Well 2

Rehab/Reconstruction 65,000 500,000 Pull Well 50,000 Well 3

Rehab/Reconstruction 100,000 VFD Pull WellWell 4

Rehab/Reconstruction Pull WellWell 5

Rehab/Reconstruction Pull Well - Well 6

Rehab/Reconstruction Pull Well xxx Liquid Chlorine Transition Roof Well 7

Rehab/Reconstruction Pull WellWell 8

Rehab/Reconstruction Pull Well 24,000Well 9

Rehab/Reconstruction Pull Well 24,000Other

Construction of Filter Plant 2, 7, 9 3,500,000 New Chemical and Flouride Feed Pumps 65,000 General Well Maintenance 3,000 3,000 3,000 3,000 New Well Construction/Placeholder 25,000 25,000 25,000 25,000 25,000 25,000 25,000 (4) Well Dehumidifiers 20,000 3,000 Facility Repair 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 Well Generators 20,000 Miscellaneous 10,000 10,000 10,000 10,000 15,000 15,000 15,000

Towers

Jackson Tower

Paint/Sandblast Structural Mtc.Gary St. Tower

Paint/Sandblast 4,500 1,225,500 Structural Mtc.Freeport Tower

Paint/Sandblast 1,225,500 Structural Mtc. 3,500 4,500Auburn Tower

Paint/Sandblast 20,000 800,000 1,300,000 Structural Mtc. 3,500Johnson Tower

Paint/Sandblast 300,000 Structural Mtc. Placeholder 15,000 15,000 15,000 15,000

System

Rate Study (delayed)Removal Booster Station 20,000High Zone Low Zone ConversionWater Main Construction 300,000 200,000 200,000 200,000 200,000 200,000 200,000Reclaim Backwash Water project 150,000 150,000 150,000 150,000 150,000Water Main Repair 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000

Inventory/Equipment

Meters/ERTs 10,000 10,000 10,000 10,000 10,000 10,000 5,000 5,000 5,000 5,000 5,000Hydrants/Valves 40,000 5,000 5,000 5,000Leak Detector 5,000Trucks 35,000 35,000 35,000 35,000SCADA 5,000 5,000 5,000 5,000 5,000Computers/GIS 6,500 2,000 2,000 2,000 2,000

Misc.

20% share of Admin & Tech budgets 37,940 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000

Less amounts budgeted as repairs and maintenance (101,500) (47,000) (18,000) (10,000) (20,000) (8,000) (22,000) (13,000) (20,000) (7,000) (22,000)Less amounts from trunk funds (280,000.00) (100,000.00) (400,000.00)

Total WATER CIP (2011 Dollars) 417,940 851,500 121,500 346,500 3,768,000 1,083,000 1,448,000 253,000 1,438,500 268,000 1,568,000

Inflated Dollars @ 3% 877,045 128,899 378,630 4,240,917 1,255,494 1,728,988 332,931 1,968,687 381,448 2,321,023

0 877,045 128,899 378,630 4,240,917 1,255,494 1,728,988 332,931 1,968,687 381,448 2,321,023-417,940 25,545 7,399 32,130 472,917 172,494 280,988 79,931 530,187 113,448 753,023

Assessments - 5 yrs, 7%)Assessments - 5 yrs, 7%)Assessments - 5 yrs, 7%)Total Assessment Income 0 0 0 0 0 0 0 0 0 0 0

Notes:


Water Utility

Capital Projects (2014-2024)

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2014 Administration and Technical Services Departments Capital Budgets

Administration Capital Equipment Needs

Cost Description6,000$ Computer, Software, Accessories - Upgrades

90,000$ New company-wide software

Subtotal 96,000$

Administration Noteworthy Non-Recurring Expenses

Cost Description4,000$ Website

6,000$ Office Furniture

Subtotal 10,000$

Total 106,000$

Technical Services Capital Equipment Needs

Cost Description8,000$ Computers, Software, Accessories - Upgrades new elect tech hire computer included5,000$ Office workspace for new elect tech hire

35,000$ Replace Pickup Truck #22 - delayed from 2013-$ Diesel Engines Emission Retrofit Currently designated as emergency standby, retrofit on hold until further notice-$ Replace Pickup Truck #23 with new F250 - delayed 2015-$ Replace Pickup Truck #24 with new F250 - delayed 2015

35,000$ New Pickup Truck for new Electric Technician delayed 2015?625,000$ Landfill scheduled replacement of 3 engines

Subtotal 708,000$

Technical Services Noteworthy Non-Recurring Expenses

Cost Description700$ tools, pager, cell phone, etc for new position

Subtotal 700$

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SUBJECT: Minnesota Municipal Utilities Association Annual Summer Conference Update BACKGOUND: Minnesota Municipal Utilities Association (MMUA) held their 81st Annual Summer Conference August 21-23, 2013. The conference attendance was up from last year and is the largest annual gathering of Minnesota municipal utilities personnel and elected officials. DISCUSSION: This year’s conference had over 200 in attendance and nearly 100 trade show vendors. This conference not only provides timely and important information during the seminars, but also provides the opportunity to brainstorm industry issues with many utility managers and commissions all at one place. Seminar topics included: 21st Century Leadership, CAPX, Washington DC legislative update, Minnesota legislative update, Affordable Care Act, MN Conservation Improvement Program, and Municipal Bonds. Attached is MMUA’s MN legislative report and flyer for a new MMUA financing option for local governments. Staff will provide an update of key topics and highlights at the time of the Commission meeting. During this summer conference, the MMUA Board of Directors also holds a meeting. At this meeting, the 2014 MMUA budget was approved to be voted on by the membership during the MMUA Business meeting on the last day of the conference. The total dues increase for MMUA was approved at 1.5%. The application of the increase to individual members is based on a formula involving a number of factors and for ERMU results in only a 1.12% increase. I was elected to the Board of Directors in Aug 2012 for a 3 year term. Typically, board members serve two terms. The board is comprised of 11 directors that represent the 125 electric utility members. This year I was elected to be the MMUA Secretary-Treasurer, which is one of 4 members of the Executive Committee. The Secretary-Treasurer also serves as a member of the MMUA Nomination and Awards Committee. This position is in a line of succession for the MMUA President Elect and then MMUA President. It was a great honor to be nominated and elected to the board by the MMUA members at such an early stage of my utility management

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career. And now after only one year on the Board of Directors, to be elected to the Executive Committee to be in line for the MMUA President is an even greater honor. It is very rewarding to know that what we have done in Elk River over the past four years while I was acting in the capacity of General Manager, has elevated ERMU to this level in the eyes of our public power community. ACTION REQUESTED: No action required. ATTACHMENTS:

MMUA 2013 Legislative Report MMUA Municipal Lease Program – Financing for State and Local Governments

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2013 LEGISLATIVE REPORT

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Our Mission:

To unify and serve as a common voice for municipal utilities, and to provide them with the support they need

to provide quality service to their customers and community.

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CCOONNTTEENNTTSS

Session Summary ...............................................................................................................................2

New Laws ..........................................................................................................................................3

Omnibus Energy bill .................................................................................................................................. 3

Utility Regulation .............................................................................................................................. 6

PACE – Property-Assessed Clean Energy ......................................................................................... 6

Distributed Generation .................................................................................................................... 7

Solar Energy ..................................................................................................................................... 9

Made in Minnesota ........................................................................................................................ 10

Energy Policy Development ........................................................................................................... 11

Miscellaneous ................................................................................................................................ 12

Omnibus Environment, Natural Resources & Agriculture Finance and Policy bill.................................. 13

Groundwater assistance, monitoring and analysis ......................................................................... 13

Various Energy Provisions ....................................................................................................................... 14

LEA Power Purchase Agreement Change ....................................................................................... 14

Increased Need Threshold for Xcel Transmission Line Approval ................................................... 14

Omnibus Tax bill ...................................................................................................................................... 15

Sales Tax Exemption for Cities and Counties .................................................................................. 15

Personal Property Tax Exemption for MMPA Electric Generating Plant ........................................ 15

Payments in Aid of Construction .................................................................................................... 16

CIP Changes and “Buy the Farm” ............................................................................................................ 16

Low-income program spending for gas utilities ............................................................................. 16

IOU CIP incentive and cost-effectiveness ....................................................................................... 16

Nonrenewable Facilities Approval Conditions ................................................................................ 16

“Buy-the-farm” changes ................................................................................................................. 17

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Unsuccessful Legislation ................................................................................................................... 18

Interim Rates Prohibition .................................................................................................................... 18

Private Data Protection ....................................................................................................................... 18

Curbs on Wind Power Production....................................................................................................... 18

Curbs on Community Based Energy Development ............................................................................. 19

Nuclear Waste Fund Payments Cessation .......................................................................................... 19

Up-Front Capital Equipment Tax Exemption ...................................................................................... 19

Up-Front Capital Equipment Tax Exemption ...................................................................................... 19

Renewable Energy Standard Repeal ................................................................................................... 19

School Energy Conservation Loans ..................................................................................................... 20

PERA Social Security Leveling Option Repeal ...................................................................................... 20

PERA Salary Definition Modification ................................................................................................... 20

Hydroelectric Revitalization Loans ...................................................................................................... 20

Wastewater Re-use Incentive ............................................................................................................. 20

Lake Zumbro Dredging ........................................................................................................................ 20

Transmission Routing Study by LEC ................................................................................................... 21

Transmission Adjoining Land Valuation .............................................................................................. 21

Utility Crossing Fee Exemption ........................................................................................................... 21

Stormwater Program Funding ............................................................................................................ 21

Co-op or Municipal Commissioner on MPUC ..................................................................................... 21

Transmission Route Alternatives ........................................................................................................ 22

Groundwater Sustainability ................................................................................................................ 22

State and Local Groundwater Data Combination ............................................................................... 22

Partial Easement Lawsuits .................................................................................................................. 22

Solar Energy Jobs Act .......................................................................................................................... 23

Excess CIP Spending Allocation ........................................................................................................... 23

IREE Funding........................................................................................................................................ 23

40% Renewable Energy Standard ....................................................................................................... 23

Municipal Utility Territory Extension Compensation Limit ................................................................. 24

Net Metering Size Limit Increase ........................................................................................................ 24

Telecommunications Regulation Overhaul ......................................................................................... 24

Utility Disconnection Reporting .......................................................................................................... 24

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Nuclear Waste Storage Payment Increase .......................................................................................... 25

RES Credit for Geothermal Energy Savings ......................................................................................... 25

Distributed Generation Study ............................................................................................................. 25

Standard Renewable Rates ................................................................................................................. 26

“Solar Power Cost Reduction Act” ...................................................................................................... 26

Local Governments Energy Improvements Program Expansion ........................................................ 27

Net Metering and Feed-in Tariff ......................................................................................................... 27

Distributed Generation Interconnection Tariff Changes .................................................................... 27

CIP Savings Goal Sunset ...................................................................................................................... 28

Groundwater Conference ................................................................................................................... 28

Utility Franchise Agreements .............................................................................................................. 28

Cost of Service ..................................................................................................................................... 28

Farm Tap Excavation Notice ............................................................................................................... 29

Large Hydropower Renewable Energy Credit ..................................................................................... 29

Water Appropriation Permit Fee Increase .......................................................................................... 29

Recovered Energy Generation Incentive ............................................................................................ 29

INDEX .............................................................................................................................................. 30

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SSEESSSSIIOONN SSUUMMMMAARRYY In 2013, the Minnesota Legislature convened for its annual session on January 8 and adjourned on May 20. The Democratic-Farmer-Labor (DFL) party retook control of both chambers from Republicans following the November 2012 election. Ballot measures to require voter ID and to formally ban same sex marriage were widely seen as backfiring on proponents and bringing DFL voters to the polls. With Mark Dayton as Governor, it was the first time in 20 years that one party held the majority of seats in both the House and Senate while a member of the same party sat in the chief executive’s chair. The new majority’s one essential job during the session was to enact a balanced budget for the 2013-14 biennium. Facing a forecasted $627 million deficit, it fulfilled its duty, raising taxes by $2 billion and making additional funding available for new and existing programs. In addition to those budget bills that fund the state government agencies, more policy bills were introduced this year that would affect municipal utilities than in any session since 2007 when the “Next Generation Energy Act” passed. In the six years since enactment of “NextGen,” Minnesota utilities increased wind power generation and purchasing by more than 12%, on pace to achieve a 25% total by 2025 (or 30% by 2020 in Xcel’s case). They improved and tracked electric and gas consumer efficiency and reduced CO2 emissions all while balancing revenue declines and large fuel cost fluctuations. Still, some legislators introduced measures in 2013 to mandate more renewable energy or increase the amounts utilities pay for it. Mostly though, legislators at the capitol were repeating one sentiment in particular. “It’s time to do something for solar,” they said. An explanation of what the Legislature and the Governor “did for solar” begins on page 4 of this Legislative Report. From that long explanation, the one thing that must be noted in this Session Summary is that municipal utilities are relatively unaffected by the 2013 law changes. State-regulated investor-owned utilities will have to make major adjustments in the way they do business. Municipal and cooperative utility representatives made a coordinated and sustained lobbying effort throughout the session to educate legislators about significant negative impacts that would result from many of the proposals and disproportionately hurt consumer-owned utilities. But in the end, it was the phone calls and e-mails of MMUA members as well as co-op members that put the brakes on a legislative train that was headed down the wrong track. Report compiled by MMUA Senior Government Relations Representative Bill Black. Questions and comments welcome at [email protected] or 800-422-0119.

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mailto:[email protected]

NNEEWW LLAAWWSS The following pages with red headings summarize new laws passed during the 2013 legislative session. Each law or individual provision applies to Minnesotans beginning on the “effective date” following its summary. Some of these laws will be codified within Minnesota’s permanent statutes while others (such as those that assign studies to be completed) will be found only in the state’s official yearly session law compilations under the indicated chapter number. Editorial comments appear as italicized text.

OMNIBUS ENERGY BILL 2013 Session Laws Chapter 85, Articles 7-13 (HF 729 – Omnibus Jobs, Economic Development, Housing, Commerce and Energy Finance bill, also called the Jobs bill) HF 956 Rep. Melissa Hortman (DFL – Brooklyn Park) SF 901 Sen. John Marty (DFL – Roseville) Just as “omnibus” bills at the legislature typically evolve, the 2013 House and Senate Omnibus Energy bills were put together separately and more or less simultaneously over several weeks and through the course of several committee hearings from collections of bills introduced individually by various legislators. The separate bills were amended through the committee process onto core bills introduced by the two energy committee chairs. Those core bills contained proposals from the Governor’s administration with the goal of increasing the amount of solar electricity throughout the state. Near the beginning of the legislative session, leadership at the state’s Division of Energy Resources (D.E.R.) laid out the administration proposal in separate meetings with groups of lobbyists from the various electric utility sectors. MMUA met with the D.E.R. Director on behalf of the municipal sector. Under part one of the proposal, the cap on net metered facilities would be increased from 40kW to 1,000kW. That is, the eligibility size limit for customer-owned solar panel systems that could earn compensation for their excess generation would increase by a factor of 25. And compensation for energy from systems within the new size range would be at a rate equal to the utility’s avoid cost. Part two of the proposal would set an alternative rate that utilities could choose to pay for such energy. That rate would be set by the D.E.R. according to a formula that would supposedly calculate the true “value of solar,” or “solar value” as referred to in the law as enacted. (See ARTICLE 9 below for details.) The proposal’s base “value of solar” power purchasing rate model was devised by the municipal utility serving Austin, Texas and went into effect there two months prior to its introduction in this Minnesota legislative session. Intended to encapsulate all of the benefits of solar as a generating resource, the “value of solar” model would quantify factors including avoided line loss, avoided energy and transmission capacity payments, environmental benefits

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and other considerations that a utility’s retail rate or typical avoided cost rate does not reflect. This logical approach gave the utility lobbies hope that the state could in fact develop a rate that accurately and transparently reflects the true value of extra energy sold by solar generating customers to their utilities. One particularly significant question arose, however, as details of the proposed formula could be analyzed. The legislation would give the state authority to “incorporate other values into the methodology” without clear limitation. Specifically included among those other factors could be “credit for locally manufactured or assembled systems.” Furthermore, the proposal set an arbitrary price floor whereby utilities would pay no less than their retail rates – a rate equal to or higher than what they previously paid. These provisions begged the question “Value of solar to whom?” It was clear the state had broader public policy benefits in mind that it intended to add to the solar producers’ side of the rate equation at the expense of the utilities and their customers who would pay for this energy. And so it became evident throughout the course of proceedings that behind those solar generating customers stood the true beneficiaries of the supposed “true value of solar” model – the manufacturers and installers of solar generation equipment. In the most general sense, the legislation’s main thrust would have grossly undermined municipal authority to operate and regulate city utilities for the benefit of their customer-owners and their communities. It also simply ignored the immense differences among the state’s various utilities, treating the very large and the very small identically. Amazingly, however, the misguided core proposal was perhaps not even the most egregious aspect of the legislation as it continued to grow into what would become the omnibus energy bill. From the outset and throughout the course of committee proceedings, MMUA voiced steady opposition to the overall legislative package, specifically identifying and explaining its many problems. Certain aspects of the omnibus bill would have allowed unregulated electricity sales by private non-utility companies throughout Minnesota, directly circumventing the extremely important regulatory framework of exclusive service rights and accompanying responsibilities of the state’s established, regulated utilities. The bill would have upended the existing renewable energy standard’s foundational premise that allows utilities to meet it with whatever eligible generation resources best match their needs. It would have required municipal utilities to produce and submit annually detailed maps of their distribution systems, identifying locations where solar installers could best target the utilities’ customers. For these and other reasons, MMUA strongly opposed this legislation. As a direct result, the authors of the bills in the House and Senate amended their respective bills in ways that significantly limited objectionable aspects for all utility sectors (particularly third-party retail electric sales as noted above). Realizing that the bill still would not pass votes by their respective full bodies over continued opposition by municipal and cooperative utilities, the authors accepted demands to remove applicability of the omnibus energy law on municipal and cooperative utilities. Thus, the following provision summaries pertain only to investor-owned utilities, unless otherwise identified by underlined text.

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- Provisions MMUA objected to that were removed from the omnibus bills - The following proposals were in some version of the House or Senate omnibus energy bill at some time during the legislation development stage but did not make it into the final law. An increase in the Renewable Energy Standard to 40% by 2030.

A new solar energy standard of 4% by 2025. (IOUs must meet a new solar standard of

1.5%. See below.) Authority for unregulated businesses to install and own solar devices on the properties

of people, businesses and other utility customers and sell the electric output to those property owners. (“Third-party ownership.”)

An exemption from all limitations on net metering facilities for wind turbine systems of

up to 3.5 megawatts placed on properties with buildings that are wholly or partially financed with public funds.

A prohibition on municipal and cooperative utilities from charging standby fees to

generating customers. A virtual prohibition on municipal and cooperative utilities against limiting the amount

of distributed generation on their electric systems. A provision requiring municipal and cooperative utilities to allow entities to

interconnect solar arrays to the utilities’ systems and sell subscriptions for the solar output to the utilities’ customers using the utilities’ conducting lines for power delivery. (“Community Solar.”)

Annual assessments on municipal and cooperative utilities equal to 5% of their

previous year’s spending requirement under the Conservation Improvement Program. A fee (tax) on all electric utilities of up to 1.33% of their annual gross retail sales for

deposit into a state fund dedicated to subsidizing solar energy producers.

- Provisions that became law - The following provisions were enacted as articles 7-13 of the 2013 Session Laws, Chapter 85. The effective date of each provision is July 1, 2013, unless otherwise stated at the end of the provision summary.

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PLEASE NOTE: Nearly all of this law affects only investor-owned utilities. While some provisions will have an indirect or general effect on the state’s energy regulatory environment, ONLY THE UNDERLINED TEXT IN THE PROVISIONS BELOW APPLIES DIRECTLY TO MUNICIPAL UTILITIES OR MUNICIPAL POWER AGENCIES.

Utility Regulation (Article 7) Section 1 – Allows utilities to recover the costs of facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed. Amends Minn. Stat. §216.16, subd. 7b. Effective Date: July 1, 2013. Sections 2, 9 – Makes minor changes to non-municipal gas utility rate setting statutes. Amends Minn. Stat. §216B.1635. Effective Date: May 22, 2013. Section 3 – Requires the Minnesota Public Utilities Commission, in consultation with the Division of Energy Resources, to establish a uniform template for municipal power agencies, G&Ts and IOUs to follow when they report, as part of their integrated resource plans, on the impact of the Renewable Energy Standard on their rates. Amends Minn. Stat. §216.1691, subd. 2e. Effective Date: July 1, 2013. Sections 4-8 – Allows the Minnesota Public Utilities Commission to approve an emissions reduction rate rider for an out-of-state power plant owned by Ottertail Power and makes related statutory changes. Amends Minn. Stat. §216B.1692 and §216B.1695. Effective Date: May 22, 2013. From HF 1326 by Rep. Jay McNamar (DFL – Elbow Lake) and SF 1104 by Sen. Lyle Koenen (DFL – Clarissa).

PACE – Property-Assessed Clean Energy (Article 8) Section 1 – Defines “cost-effective energy improvements” as “energy improvements that have been identified in an energy audit or renewable energy system feasibility study as repaying their purchase and installation costs in 20 years or less, based on the amount of future energy saved and estimated future energy prices.” Amends Minn. Stat. §216C.435 by adding a subdivision 3a. Section 2 – Changes the definition of “qualifying real property” to require that it be capable of benefiting from energy improvements “that are cost-effective.” Amends Minn. Stat. §216C.435, subd. 8. Section 3 – Requires that any financing program under PACE must not prohibit the financing of other cost-effective energy improvements. Amends Minn. Stat. §216C.436, subd. 2. Sections 4, 6 – Allows financers to make assessments be payable in up to 20 equal annual installments. Amends Minn. Stat. §216C.436, subd. 7 and §429.101, subd. 2.

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Section 5 – Limits to 20 years the allowable payback period for revenue bonds under the Energy Improvements for Local Governments Program. Amends Minn. Stat. §216C.436, subd. 8. Each section under Article 8 is effective beginning May 22, 2013.

Distributed Generation (Article 9) Article 9 is the core of the omnibus energy bill and came primarily from the Governor’s administration through the Division of Energy Resources. As introduced, the legislative proposal would have applied to all electric utilities, including municipals and cooperatives. The new law, however, applies only to investor-owned utilities. That is, the net metering laws have not changed for municipal and cooperative utilities, and those utilities are not required to adopt the Solar Value rate described below although they are, as always, free to incorporate or borrow from this or other compensation models through local decision making. Net metering Utility customers have the option of receiving compensation for their excess power generation from their net metered renewable or high efficiency distributed generation so long as their generating facilities have a nameplate capacity of 1,000kW or less. Previously, the cap was 40kW. If the capacity is 40kW or less, the customer can choose to receive compensation at a rate equal to the utility’s average retail rate just as before this law passed. If the capacity is between 40kW and 1,000kW, the customer can receive compensation at a rate equal to the utility’s calculated avoided cost. Those customers may elect to be compensated in the form of a kWh credit on their electric bills equal to the rate they would otherwise receive as payment. Utilities may not impose standby charges on customer generating facilities with a nameplate capacity of 1,00kW or less. For facilities with a nameplate capacity greater than 1,000kW, a standby charge may only be imposed in accordance with a PUC order establishing the costs to be recovered. Utilities are required to aggregate meters for billing upon customer request. Utilities may request that the PUC limit the cumulative amount of distributed generation on a utility’s system once it has reached 4% of the utility’s annual retail sales. The PUC may grant further limits upon proof of certain conditions by the utility and after a period for public comment.

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Utilities may limit distributed generation systems with a nameplate capacity greater than 40kW as follows. Wind generation facilities may be limited to 120% of on-site maximum electric demand. Solar and other generation facilities may be limited to 120% of on-site annual electric consumption. Solar Value Rate (“Alternative tariff”) “(a) A public utility may apply for commission approval for an alternative tariff that compensates customers through a bill credit mechanism for the value to the utility, its customers, and society for operating distributed solar photovoltaic resources interconnected to the utility system and operated by customers primarily for meeting their own energy needs.

(b) If approved, the alternative tariff shall apply to customers' interconnections occurring after the date of approval. The alternative tariff is in lieu of the applicable rate under subdivisions 3 and 3a.

(c) The commission shall after notice and opportunity for public comment approve the alternative tariff provided the utility has demonstrated the alternative tariff:

(1) appropriately applies the methodology established by the department and approved by the commission under this subdivision; (2) includes a mechanism to allow recovery of the cost to serve customers receiving the alternative tariff rate; (3) charges the customer for all electricity consumed by the customer at the applicable rate schedule for sales to that class of customer; [“Sell-all”] (4) credits the customer for all electricity generated by the solar photovoltaic device at the distributed solar value rate established under this subdivision; [“Buy-all”] (5) applies the charges and credits in clauses (3) and (4) to a monthly bill that includes a provision so that the unused portion of the credit in any month or billing period shall be carried forward and credited against all charges. In the event that the customer has a positive balance after the 12-month cycle ending on the last day in February, that balance will be eliminated and the credit cycle will restart the following billing period beginning on March 1; (6) complies with the size limits specified in subdivision 3a; (7) complies with the interconnection requirements under section 216B.1611; and (8) complies with the standby charge requirements in subdivision 3a, paragraph (b).

(d) A utility must provide to the customer the meter and any other equipment needed to provide service under the alternative tariff.

(e) The department must establish the distributed solar value methodology in paragraph (c), clause (1), no later than January 31, 2014. The department must submit the

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methodology to the commission for approval. The commission must approve, modify with the consent of the department, or disapprove the methodology within 60 days of its submission. When developing the distributed solar value methodology, the department shall consult stakeholders with experience and expertise in power systems, solar energy, and electric utility ratemaking regarding the proposed methodology, underlying assumptions, and preliminary data.

(f) The distributed solar value methodology established by the department must, at a minimum, account for the value of energy and its delivery, generation capacity, transmission capacity, transmission and distribution line losses, and environmental value. The department may, based on known and measurable evidence of the cost or benefit of solar operation to the utility, incorporate other values into the methodology, including credit for locally manufactured or assembled energy systems, systems installed at high-value locations on the distribution grid, or other factors.

(g) The credit for distributed solar value applied to alternative tariffs approved under this section shall represent the present value of the future revenue streams of the value components identified in paragraph (f).

(h) The utility shall recalculate the alternative tariff on an annual cycle, and shall file the recalculated alternative tariff with the commission for approval.

(i) Renewable energy credits for solar energy credited under this subdivision belong to the electric utility providing the credit.

(j) The commission may not authorize a utility to charge an alternative tariff rate that is lower than the utility's applicable retail rate until three years after the commission approves an alternative tariff for the utility.

(k) A utility must enter into a contract with an owner of a solar photovoltaic device receiving an alternative tariff rate under this section that has a term of at least 20 years, unless a shorter term is agreed to by the parties.

(l) An owner of a solar photovoltaic device receiving an alternative tariff rate under this section must be paid the same rate per kilowatt-hour generated each year for the term of the contract.”

Solar Energy (Article 10) Solar Mandate (for investor-owned utilities only) - By the end of 2020, at least 1.5% of total retail electric sales made by investor-owned utilities must come from solar energy. At least 10% of the 1.5% must come from solar facilities with capacities of less than 20kW. Sales to mining and paper mill customers are not counted as part of total retail sales.

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State Solar Goal (for all utilities) - “It is an energy goal of the state of Minnesota that by 2030, 10% of the retail electric sales in Minnesota be generated by solar energy.” While not a mandate, this “goal” applies to all retail electric sales and, therefore, to all electric utility sectors, including public power. Xcel Solar Energy Incentive Program – Xcel must operate a program to provide solar energy production incentives for solar energy systems. The program must be operated for 5 consecutive calendar years commencing in 2014. $5 million per year must be allocated for each of the 5 years from the Renewable Development Fund (RDF). To be eligible, systems must be 20kW or smaller in nameplate capacity and sized to less than 120% of the customer’s on-site annual energy consumption. The incentive must be paid for 10 years. Community Solar Garden – Xcel must file with the Public Utilities Commission a plan to operate a community solar garden program to begin 90 days after the commission approves the plan. Other public utilities may apply with the commission to file and operate similar programs. The program must be designed to offset the energy use of not less than 5 subscribers, and no subscriber may have more than a 40% interest. The owner of the community solar garden may be a public utility or any other entity or organization that contracts to sell the output from the community solar garden to the utility. The maximum size for a solar garden is 1 megawatt, and the minimum subscription must be 200 watts of the garden’s generating capacity. Subscribers must be customers of the utility, must receive their portion of the solar project’s generation as a credit on their electric bill and must live in the county where the facility is located or a contiguous county.

Made in Minnesota (Article 11) Solar Energy Production Incentive - Each investor-owned utility must contribute 5% of their CIP spending requirement for 10 years to a new Made in Minnesota Solar Energy Production Incentive account. Each contributing utility receives energy savings credit “based on its payment to the commissioner.” Xcel must fill the fund up to $15 million after all other annual receipts are received. The Division of Energy Resources must attempt to distribute incentive payments among utility customers in proportion to the amounts contributed by the utilities. Rebates for Photovoltaic Systems - Eligible systems must be 40kW or smaller, installed on residential or commercial property and receive a “Made in Minnesota” certificate from the DER. The owner receives payments for 10 years, provided that funding is available. No new customers may be added to the 10-year program beginning in January 2025.

Rebates for Solar thermal projects - For 10 years, beginning in 2014, the Department of Commerce must allocate $250,000 from the Made in Minnesota account to be spent on rebates for solar thermal systems. The maximum rebate shall be 25% of the installed cost of a completed system or $2,500 for a single family residence, $5,000 for a multiple family

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residence or $25,000 for a commercial installation. Each year, rebates must be split evenly between solar thermal hot water and solar thermal air projects. From HF 567 and HF 1167 by Rep. Carly Melin (DFL – Hibbing) and SF 750 and SF 936 by Sen. David Tomassoni (DFL – Chisolm).

Energy Policy Development (Article 12) Planning strategy for a sustainable energy future (Section 1) “(a) The Legislative Energy Commission, in consultation with the commissioner of commerce and other state agencies shall develop a framework for the state of Minnesota to transition to a renewable energy economy that ends Minnesota’s contribution to greenhouse gases from burning fossil fuels within the next few decades. The framework and strategy should aim to make Minnesota the first state in the nation to use only renewable energy. (b) In developing the framework for this transition, the commission must consult with stakeholders, including, but not limited to, representatives from cooperative, municipal, and investor-owned utilities, natural resources and environmental advocacy groups, labor and industry, and technical and scientific experts to examine the challenges and opportunities involved to develop a strategy and timeline to protect the environment and create jobs. The timeline must establish goals and strategies to reach the state's renewable energy standards and prepare for the steps beyond reaching those standards. The Department of Commerce, Division of Energy Resources shall provide technical support. (c) The commission and its stakeholders must consider the following in creating the framework:

(1) the economic and environmental costs of continued reliance on fossil fuels; (2) the creation of jobs and industry in the state that result from moving ahead of other states in transitioning to a sustainable energy economy; (3) the appropriate energy efficiency and renewable energy investments in Minnesota to reduce the economic losses to the Minnesota economy from importation of fossil fuels; and (4) the new technologies for energy efficiency, storage, transmission, and renewable generation needed to reliably meet the demand for energy.

(d) The framework shall be modified as needed to take advantage of new technological developments to facilitate ending fossil fuel use in power generation, heating and cooling, industry, and transportation.

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(e) The commission shall report to the legislative committees and divisions with jurisdiction over energy policy by January 15, 2014, and annually thereafter, on progress towards achieving the framework goals.” CIP changes (Sections 2-3) The state’s overall energy savings goal is changed to "at least" 1.5% of energy sales per year. In addition to energy savings by utilities, “energy efficiency achieved by energy consumers without direct utility involvement” is added as a source of savings toward achieving the state’s overall goal. (The savings goal of 1.5% for utilities is not changed.) Amends Minn. Stat. §216B.2401. From HF 1301 by Rep. Melissa Hortman (DFL – Brooklyn Park) and SF 1135 by Sen. Scott Dibble (DFL – Minneapolis). Transmission and renewable energy integration study (Section 4) The Minnesota Public Utilities Commission is required to order all Minnesota electric utilities that are subject to the Renewable Energy Standard (i.e., investor-owned utilities, municipal power agencies, consumer power districts and G&T cooperatives) and all transmission companies “to conduct an engineering study of the impacts on reliability and costs of, and to study and develop plans for the transmission network enhancements necessary to support, increasing the renewable energy standard . . . to 40% by 2030, and to higher proportions thereafter, while maintaining system reliability.” Studies by the Division of Energy Resources (Sections 5-8) The Division of Energy Resources is required to:

study and report findings on the value of on-site energy storage (Sec. 5); study and report findings on the value of solar thermal (Sec. 6); develop the scope for the sustainable energy future study (Sec. 7); and conduct public meetings and report on various policy subjects relating to

utilities and energy savings (Sec. 8). These public meetings will be particularly important. MMUA will participate. MMUA members are encouraged to participate as well.

Miscellaneous (Article 13) Guaranteed Energy Savings – Under Guaranteed Energy Savings contracts entered into by the Department of Administration, the energy savings period is extended from 15 years to 25 years during which the amount of energy savings is added up and counted against the cost of an energy cost savings measure. (Sec. 1)

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Waste Heat, Cogeneration & CHP (Sec. 2, 4) - Demand side natural gas or electric energy displaced by the use of waste heat recovered and used as thermal energy, including the recovered thermal energy from a cogeneration or combined heat and power facility may be counted toward a utility’s natural gas or electric energy savings goal, subject to department approval. “Waste heat recovered and used as thermal energy means capturing heat energy that would otherwise be exhausted or dissipated to the environment from machinery, buildings, or industrial processes and productively using such recovered thermal energy where it was captured or distributing it as thermal energy to other locations where it is used to reduce demand side consumption of natural gas, electric energy, or both.” (Current law requires that recovered waste heat must be converted into electricity to qualify.) Amends Minn. Stat. §216B.241 by amending subdivision 1 and by adding a subdivision 10. From HF 780 by Rep. Tim Mahoney (DFL – St. Paul) and SF 642 by Sen. Scott Dibble (DFL – Minneapolis). CERTs Funding (Sec. 3) - The Community Energy Resource Teams will receive $500,000 per year from the Research and Development Fund under the Conservation Improvement Program on an ongoing basis. Previously, CERTs funding, if any, required specific appropriations to be made. Effective date: For assessments for state fiscal years commencing on or after July 1, 2013. From HF 1000 by Rep. Tim Kelly (R – Red Wing) and SF 1011 by Sen. Scott Dibble (DFL – Minneapolis). Miscellaneous Xcel cost recovery (Sec. 6) - Minnesota Statutes Section 216B.1637 is repealed. It allowed Xcel to recover through its rates the costs associated with replacing cast iron natural gas distribution and service lines and replacing breakers that contain sulfur hexafluoride.

OMNIBUS ENVIRONMENT, NATURAL RESOURCES & AGRICULTURE FINANCE AND POLICY BILL 2013 Session Laws Chapter 114 HF 976 Rep. Jean Wagenius (DFL – Minneapolis) SF 1170 Sen. David Tomassoni (DFL – Chisolm)

Groundwater assistance, monitoring and analysis From the general fund, $1.6 million is appropriated in fiscal year 2014 and $6 million in 2015 for the following purposes:

(1) increased financial reimbursement and technical support to soil and water conservation districts or other local units of government for groundwater level monitoring;

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(2) additional surface water monitoring and analysis, including installation of monitoring gauges; (3) additional groundwater analysis to assist with water appropriation permitting decisions; (4) additional permit application review incorporating surface water and groundwater technical analysis; (5) enhancement of precipitation data and analysis to improve the use of irrigation; (6) enhanced information technology, including electronic permitting and integrated data systems; and (7) increased compliance and monitoring.

Introduced as HF 682 by Rep. Peter Fischer (DFL – Maplewood) and SF 244 by Sen. Charles Wiger (DFL – Maplewood) and with support from influential Rep. Jean Wagenius (DFL – Minneapolis), the initial legislative proposals to fund greater groundwater monitoring would have greatly increased fees for water appropriation permits. The Senate did not concur with the House’s support for such fee increases. Instead, the law allocates funding from the state’s general fund.

VARIOUS ENERGY PROVISIONS 2013 Session Laws Chapter 57 HF 623 Rep. Carly Melin (DFL – Hibbing) SF 521 Sen. David Tomassoni (DFL – Chisolm)

LEA Power Purchase Agreement Change (Section 1) Requires an amendment to the power purchase agreement between Xcel and the Laurentian Energy Authority (LEA) establishing an average energy price of no more than $109.20 per megawatt hour. The amendment must also allow the LEA to collect an adjustment for fuel costs that exceed $3.40 per MMBTU. Amends Minn. Stat. §216B.2424, subd. 5a. Effective date: For fuel costs incurred and prices after January 1, 2014.

Increased Need Threshold for Xcel Transmission Line Approval (Section 2) Restricts the Minnesota Public Utilities Commission from approving a certificate of need for upgrading an 8-mile Xcel transmission line in Minneapolis unless the commission finds “by clear and convincing evidence that there is no feasible and available distribution level alternative to the transmission line.” Effective date: May 14, 2013. From HF 1205 by Rep. Sarah Anderson (DFL – Plymouth) and SF 716 by Sen. Terri Bonoff (DFL – Minnetonka).

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OMNIBUS TAX BILL 2013 Session Laws Chapter 143 HF 677 Rep. Ann Lenczewski (DFL – Bloomington) SF 552 Sen. Rod Skoe (R – Clearbrook) Sales Tax Exemption for Cities and Counties (Art. 8, Sec. 29) Exempts cities and counties from the state sales tax on most purchases. (The same exemption was established for towns in 2011.) Excluded from the exemption are purchases of certain building construction or reconstruction materials, prepared food, candy, soft drinks, alcoholic beverages, motor vehicle leases and lodging accommodations. The exemption also does NOT apply to purchases by cities or counties of goods or services that are used as inputs to certain goods or services provided by the local government to its citizens, including, specifically, municipal electric or gas utility service. Under the law, electric or gas service is considered to be a service “generally provided by a private business.” However, purchases of inputs to “sewer, water service and wastewater treatment” DO qualify for the new sales tax exemption. As of the printing of this Legislative Report, MMUA was lobbying the Department of Revenue for an interpretation of the exemption carveout for municipal utilities that would still exempt from the sales tax purchases by utilities of goods and services that are not inputs to the utility services they provide (e.g., office supplies, etc.). Amends Minn. Stat. §297A.70, subd. 2. Effective date: For sales and purchases made after December 31, 2013. From HF 295 by Rep. Nick Zerwas (R – Elk River) and SF 329 by Sen. David Senjem (R – Rochester) and HF 469 by Rep. Peter Fischer (DFL – Maplewood) and SF 104 by Sen. Charles Wiger (DFL – Maplewood). Personal Property Tax Exemption for MMPA Electric Generating Plant (Art. 4, Sec. 14) To exempt from personal property tax an electric generating plant with a capacity exceeding 5 megawatts that utilizes natural gas in a reciprocating engine in a Twin Cities metropolitan county and is owned by a municipal power agency. The plant must be designed so that the power it generates will be consumed in the municipal utility service territory in which it is located. Amends Minn. Stat. §272.02. Effective date: Assessment year 2013, taxes payable in 2014 and thereafter. From HF 337 by Rep. Leon Lillie (DFL – North St. Paul) and SF 161 by Sen. Charles Wiger (DFL – Maplewood).

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Payments in Aid of Construction (Art. 8, Sec. 3) Clarifies that payments made as contributions in aid of construction to a cooperative electric association or public utility are contracts for improvement to real property and not retail sales. Thus no sales tax is due to the state. This issue arose from inconsistent application of sales tax requirements by state auditors in different regions. Amends Minn. Stat. §297A.61, subd. 4. Effective date: For sales and purchases made after June 30, 2013.

CIP CHANGES AND “BUY THE FARM” 2013 Session Laws Chapter 132 HF 854 Rep. Joe Atkins (DFL – Inver Grove Heights) SF 695 Sen. Scott Dibble (DFL – Minneapolis)

Low-income program spending for gas utilities The amount that non-municipal gas utilities must spend on low-income programs under the Conservation Improvement Program is increased from 0.2% to 0.4% of their most recent three-year average gross operating revenue from residential customers. Amends Minn. Stat. §216B.241, subd. 7. Effective date: May 25, 2013.

IOU CIP incentive and cost-effectiveness For low-income programs that are not cost-effective, investor-owned utilities have the option of counting the savings while excluding the costs and benefits from their incentive calculations. Amends Minn. Stat. §216B.241, subd. 7. Effective date: May 25, 2013.

Nonrenewable Facilities Approval Conditions When considering an Integrate Resource Plan and determining whether a nonrenewable energy facility is in the public interest, the Minnesota Public Utilities Commission must now consider “whether the resource plan helps the utility achieve the greenhouse gas reduction goals under section 216H.02, the renewable energy standard under section 216B.1691, or the solar energy standard under section 216B.1691, subdivision 2f.” Amends Minn. Stat. §216B.2422, subd. 4. Effective date: August 1, 2013.

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“Buy-the-farm” changes For transmission lines with capacities greater than 200kV, constructors have 60 days to object to a landowner’s exercise of his or her “buy-the-farm” option. Within 120 days of the utility’s objection, the district court with jurisdiction over the eminent domain proceeding must hold a hearing to uphold or reject the utility’s objection. The utility has the burden to prove by a preponderance of the evidence that the property in question is not commercially viable and therefore not eligible for the “buy-the-farm” option. (Thus the utility would not be required to buy out the entire parcel rather than pay for an easement across it.) If the court rejects the utility’s objection, the utility must make a written offer to acquire the land within 120 days. Amends Minn. Stat.§ 216E.12, subd. 4. Effective date: May 25, 2013. From HF 338 by Rep. David Bly (DFL – Northfield) and SF 183 by Sen. Kevin Dahle (DFL – Northfield). This controversial provision went through various changes through the committee process and was amended to a bill that never made it to final passage. In its initial form, the legislation would also have severely limited the authority of municipalities to condemn easements for any utility purposes. The provision that was ultimately enacted into law (as summarized above) was attached to this Atkins/Dibble bill late on a Saturday night two days before the end of session and quietly passed.

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UUNNSSUUCCCCEESSSSFFUULL LLEEGGIISSLLAATTIIOONN The following pages with blue headings summarize bills that were introduced or heard in the Legislature this year but failed to proceed all the way to enactment. These bills could be reintroduced during future legislative sessions, possibly affecting legislative debate and even passing into law. Editorial comments appear as italicized text.

INTERIM RATES PROHIBITION HF 158 Rep. Debra Hilstrom (DFL – Brooklyn Center) SF 92 Sen. Chris Eaton (DFL – Brooklyn Center) To prohibit the Minnesota Public Utilities Commission from authorizing the utilities it regulates to charge interim rates, unless an “immediate and compelling necessity exists.”

PRIVATE DATA PROTECTION HF 183 Rep. Mary Liz Holberg (R – Lakeville) SF 211 Sen. Scott Dibble (R – Minneapolis) To require greater security of private data on individuals (such as municipal utility customer data) and reporting of unauthorized access and to allow for immediate dismissal and gross misdemeanor charges for public employees who access such data for unauthorized purposes.

CURBS ON WIND POWER PRODUCTION HF 190 Rep. Tim Kelly (R – Red Wing) SF 203 Sen. Matt Schmit (DFL – Red Wing) To allow counties to prohibit by zoning ordinance large wind energy conversion projects and to allow the MPUC to modify or delay the implementation of a renewable energy standard obligation if it finds there is a lack of available suitable sites for eligible technology facilities, considering local land use restrictions.

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CURBS ON COMMUNITY BASED ENERGY DEVELOPMENT HF 191 Rep. Tim Kelly (R – Red Wing) SF 204 Sen. Matt Schmit (DFL – Red Wing) To repeal the requirement that the MPUC must consider ways to encourage the aggregation of C-BED projects; to repeal the flexibility that C-BED developers currently have to force IOUs, G&Ts and municipal power agencies to negotiate a different PPA than the one offered; to require all C-BED projects to re-certify their eligibility with the MPUC annually.

NUCLEAR WASTE FUND PAYMENTS CESSATION HF 255 Rep. Joe Atkins (DFL – Inver Grove Heights) SF 1233 Sen. James Metzen (DFL – South St. Paul) To require Xcel to stop collecting payments from customers to send to the U.S. government for the federal nuclear waste fund.

UP-FRONT CAPITAL EQUIPMENT TAX EXEMPTION HF 288 Rep. Peter Fischer (DFL – Maplewood) SF 95 Sen. Charles Wiger (DFL – Maplewood) To apply the capital equipment sales tax exemption at the time of purchase. (Same as below.)

UP-FRONT CAPITAL EQUIPMENT TAX EXEMPTION HF 304 Rep. Mary Franson (R – Alexandria) SF 309 Sen. Bill Ingebrigtsen (R – Alexandria) To apply the capital equipment sales tax exemption at the time of purchase. (Same as above.)

RENEWABLE ENERGY STANDARD REPEAL HF 306 Rep. Michael Beard (R – Shakopee) SF 97 Sen. Bill Ingebrigtsen (R – Alexandria) To repeal the law currently requiring all municipal power agencies, G&Ts and IOUs to furnish 25% renewable energy by 2025. (30% by 2020 for Xcel.)

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SCHOOL ENERGY CONSERVATION LOANS HF 320 Rep. Jay McNamar (DFL – Elbow Lake) SF 601 Sen. Kari Dziedzic (DFL – Minneapolis) To establish an energy conservation revolving loan program for schools and authorize school districts to repay such loans from the proceeds of tax levies without further voter approval.

PERA SOCIAL SECURITY LEVELING OPTION REPEAL HF 341 Rep. Michael Nelson (DFL – Brooklyn Park) SF 275 Sen. Sandy Pappas (DFL – St. Paul) To repeal the Social Security leveling option under the Public Employees Retirement Association (PERA) program.

PERA SALARY DEFINITION MODIFICATION HF 343 Rep. Michael Nelson (DFL – Brooklyn Park) SF 273 Sen. Sandy Pappas (DFL – St. Paul) To make various changes to the definition of “salary” in statutes governing the Public Employees Retirement Association (PERA) program.

HYDROELECTRIC REVITALIZATION LOANS HF 421 Rep. Duane Quam (R – Byron) SF 691 Sen. David Senjem (R – Rochester) To establish a hydroelectric revitalization revolving loan program and fund.

WASTEWATER RE-USE INCENTIVE HF 436 Rep. Jean Wagenius (DFL – Minneapolis) SF 1260 Sen. Bev Scalze (DFL – Little Canada) To establish financial assistance priority for wastewater treatment projects that would treat wastewater for reuse.

LAKE ZUMBRO DREDGING HF 422 Rep. Duane Quam (R – Byron) SF 37 Sen. David Senjem (R – Rochester) To appropriate $2 million from the Clean Water Fund for dredging Lake Zumbro. The initiative’s purpose would be “to improve the recreational economy, water quality, and

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habitat and increase water storage capacity within the lake to achieve renewable energy goals by optimizing long-term hydroelectric operations.”

TRANSMISSION ROUTING STUDY BY LEC HF 438 Rep. Jeff Howe (R - Rockville) SF 454 Sen. Michelle Fischbach (R - Paynesville) To require the Legislative Energy Commission (LEC) to study issues related to high-voltage transmission line routing.

TRANSMISSION ADJOINING LAND VALUATION HF 439 Rep. Jeff Howe (R - Rockville) SF 674 Sen. Michelle Fischbach (R - Paynesville) To require the MPUC when designating high-voltage transmission line routes to consider the reduction in value of land adjoining and in close proximity to a proposed route.

UTILITY CROSSING FEE EXEMPTION HF 520 Rep. David Dill (DFL – Crane Lake) SF 333 Sen. David Tomassoni (DFL – Chisolm) To exempt utilities from fees for crossing public lands when the crossing is on an existing right-of-way of a public road.

STORMWATER PROGRAM FUNDING HF 581 Rep. Rick Hansen (DFL – South St. Paul) SF 436 Sen. James Metzen (DFL – South St. Paul) To authorize the use of the Clean Water Fund to support local inflow and infiltration reduction programs.

CO-OP OR MUNICIPAL COMMISSIONER ON MPUC HF 643 Jeff Howe (R – Rockville) SF 456 Sen. Michelle Fischbach (R - Paynesville) To require that at least one commissioner on the Minnesota Public Utilities Commission must live in the service territory of either an electric cooperative or a municipal electric utility, beginning with the next appointment.

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TRANSMISSION ROUTE ALTERNATIVES HF 655 Jeff Howe (R – Rockville) SF 455 Sen. Michelle Fischbach (R - Paynesville) To require that no proposed high-voltage transmission routes be designated as preferred, but rather that all proposed routes be designated as alternatives.

GROUNDWATER SUSTAINABILITY HF 683 Rep. Peter Fischer (DFL – Maplewood) SF 243 Sen. Charles Wiger (DFL – Maplewood) To require water utilities’ demand reduction measures to include conservation rates, unless the supplier knows the recharge rate for all groundwater sources being utilized. The bill was amended to establish a Legislative Water Commission comprised of five Senators and five Representatives and to allow the DNR to require permits for all water users within designated groundwater management areas. The DNR would also be required to develop recommendations on additional tools needed to fully implement the groundwater sustainability requirements in statute and submit them to the environment and natural resources committees.

STATE AND LOCAL GROUNDWATER DATA COMBINATION HF 701 Rep. John Ward (DFL – Baxter) SF 892 Sen. Matt Schmit (DFL – Red Wing) To appropriate money from the Clean Water Fund to synthesize available groundwater quantity and quality data from state agencies and political subdivisions.

PARTIAL EASEMENT LAWSUITS HF 752 Rep. Debra Hilstrom (DFL – Brooklyn Center) SF 480 Sen. Warren Limmer (R – Maple Grove) To allow property owners to challenge that a portion of an easement is not being used for the purpose for which it was taken. Current law allows challenges for whole easements only.

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SOLAR ENERGY JOBS ACT HF 773 Rep. Will Morgan (DFL – Burnsville) SF 680 Sen. Chris Eaton (DFL – Brooklyn Center) To do the following: establish a “Value of Solar” rate that utilities must pay to owners of solar

photovoltaic systems for their excess generation; establish a 10% by 2030 solar energy standard for all utilities; establish a renewable energy production incentive account and make certain solar

photovoltaic systems eligible to receive payments from it; require each utility to provide to the DER an assessment of the capacity available on

its distribution systems for interconnecting solar photovoltaic devices on or adjacent to nonresidential buildings;

require the Commerce Department to study: 1) the potential for solar installations on public buildings, 2) the value of on-site energy storage, and 3) the potential value of expanding solar thermal installations in commercial and residential buildings in Minnesota.

(Some of these provisions were enacted. See Omnibus Energy bill above in New Laws.)

EXCESS CIP SPENDING ALLOCATION HF 843 Rep. Pat Garofalo (R – Farmington) No Senate companion bill To allow utilities to keep two-thirds of any funds remaining under their CIP spending requirement once their energy savings requirement is met if they contribute the other third to a low-income home energy assistance program.

IREE FUNDING HF 879 Rep. Andrew Falk (DFL – Murdock) SF 1454 Sen. Matt Schmit (DFL – Red Wing) To re-establish $5 million in annual funding from the Renewable Development Fund for the Initiative for Renewable Energy and the Environment at the U of M. (Funding was discontinued under legislation enacted in 2012.)

40% RENEWABLE ENERGY STANDARD HF 880 Rep. Frank Hornstein (DFL – Minneapolis) SF 763 Sen. Kevin Dahle (DFL – Northfield) To increase the Rewnewable Energy Standard to 40% by 2030. The legislation would also establish a solar energy standard of an unstated percentage of total sales, exempt

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renewable energy projects from the certificate of need requirement, require uniform reporting of RES rate impacts (See Omnibus Energy bill above), limit the lives of Renewable Energy Credits (RECs) to one year and limit REC trading to states that have RES requirements comparable to Minnesota’s and that allow the purchase of Minnesota-generated RECs.

MUNICIPAL UTILITY TERRITORY EXTENSION COMPENSATION LIMIT HF 945 Rep. Frank Hornstein (DFL – Minneapolis) SF 911 Sen. Jeff Hayden (DFL – Minneapolis) To remove “loss of revenue” as a calculation factor when determining compensation that a municipal utility must pay when buying out another utility. (This bill was introduced in support of threats by renewable energy advocates to municipalize Minneapolis electric service.)

NET METERING SIZE LIMIT INCREASE HF 955 Rep. Melissa Hortman (DFL – Brooklyn Park) No Senate companion bill To increase the customer facility size limit for net metering facilities from 40kW to 1,000kW for customers of investor-owned, municipal and cooperative utilities. (See Article 9 of the Omnibus Energy bill above.)

TELECOMMUNICATIONS REGULATION OVERHAUL HF 985 Rep. Sheldon Johnson (DFL – St. Paul) SF 584 Sen. Dan Sparks (DFL – Austin) To completely restructure the state’s regulatory framework for providing telephone, cable and Internet services. (This bill would potentially prohibit public entities from owning any telecommunications infrastructure except traditional telephone wire and restrict them to providing only traditional telephone service.)

UTILITY DISCONNECTION REPORTING HF 1001 Rep. John Ward (DFL – Baxter) SF 903 Sen. Susan Kent (DFL – Woodbury) To require electric and gas utilities, upon written request from cities in their service areas, to make daily reports to the cities with the addresses and dates of any newly disconnected properties throughout the year. (Currently, utilities must make such reports upon request only between October 15 and April 15.)

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NUCLEAR WASTE STORAGE PAYMENT INCREASE HF 1075 Rep. Andrew Falk (DFL – Murdock) No Senate companion bill To increase the amount Xcel pays into the Renewable Development Fund (RDF) each year from $500,000 to $3 million per Prairie Island cask and from $350,000 to $3 million per Monticello cask.

RES CREDIT FOR GEOTHERMAL ENERGY SAVINGS HF 1079 Rep. John Benson (DFL – Minnetonka) No Senate companion bill To allow utilities to apply net electrical consumption reductions from geothermal heating and cooling systems toward their Renewable Energy Standard requirements.

DISTRIBUTED GENERATION STUDY HF 1093 Rep. Pat Garofalo (R – Farmington) SF 972 Sen. Julie Rosen (R – Fairmont) To require the Minnesota Public Utilities Commission to open a public docket for the purpose of analyzing the costs and benefits in Minnesota of distributed solar generation and strategies to maximize the benefits and minimize the costs. The analysis of distributed solar generation must include, without limitation, the following:

(1) its use to address transmission constraints and strategies to optimize that use; (2) its affect on grid reliability and strategies to improve that affect; (3) cost-effective strategies for deployment; (4) appropriate sizing of solar projects and economies of scale; (5) the cost-effectiveness of competing solar technologies and trends for that

cost-effectiveness; (6) comprehensive assessments of its direct and indirect costs and benefits; (7) comparison of its costs and benefits to the cost and benefits of other strategies to

meet the state's electric generation needs; and (8) the effect of a comparable expenditure on energy conservation on both the

demand and supply side. MMUA testified in favor of this bill before the Senate Energy and Environment

Committee as an alternative to passing the omnibus energy bill.

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STANDARD RENEWABLE RATES HF 1130 Rep. Andrew Falk (DFL – Murdock) No Senate companion bill To establish standard rates that all utilities would pay for electrical energy from various types of renewable sources. In addition, the bill would establish a surcharge on all retail electricity bills and a fund in which to collect the surcharge. From the fund, incentive payments would be made to renewable electricity generators.

“SOLAR POWER COST REDUCTION ACT” HF 1146 Rep. Will Morgan (DFL – Burnsville) SF 1054 Sen. Chris Eaton (DFL – Brooklyn Center) To allow non-utility companies to put photovoltaic panels on the homes or other property of people, businesses, and public entities, sell those property owners the electrical output of those devices and sell excess electricity to the local utility. (Third party ownership.) The bill would also require the Minnesota Public Utilities Commission to establish new interconnection standards and requirements for distributed generation under “at least four categories that vary by nameplate capacity and level of complexity” that address, for each category, the following issues:

1) applicable technical standards; 2) timelines with specific deadlines for all utility decisions and actions; 3) screening criteria; 4) insurance; 5) metering and monitoring; 6) facility testing, controls, and inspections; 7) permissible interconnection fees and charges that may be fixed or based on

approved formulas or rates; and 8) other issues determined by the commission.

The bill would also require all electric utilities to allow third-party owned community solar generating facilities of up to 2 megawatts capacity onto their systems. The facilities would sell subscriptions for the energy they produce and sell excess generation to the utility at the utility’s avoided cost for generation. The bill would also prohibit contracts and homeowners association rules that restrict property owners from installing solar energy systems. Parties that win lawsuits to enforce this provision would be entitled for reimbursement of their attorney fees.

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LOCAL GOVERNMENTS ENERGY IMPROVEMENTS PROGRAM EXPANSION HF 1147 Rep. Raymond Dehn (DFL – Minneapolis) SF 1121 Sen. Scott Dibble (DFL – Minneapolis) To make the state’s Energy Improvements Program for Local Governments available for financing renewable energy feasibility studies. Currently only energy efficiency improvement projects are eligible for financing. This program requires governments to place liens on properties in order to collect payments from property taxes if the property owner defaults. After the law passed that created the program, Fannie Mae and Freddie Mac issued guidance to banks stating that the banks should not give mortgages in places where such type of lien might be taken on mortgaged properties. Because of this, the program has not been utilized by local governments, but it remains in statute.

NET METERING AND FEED-IN TARIFF HF 1170 Rep. Andrew Falk (DFL – Murdock) No Senate companion bill To increase the maximum size of net-metering facilities to 105kW and require utilities to pay net-metering customers a premium on top of the retail rate that comes from a surcharge on customers who elect to purchase electricity from renewable resources.

DISTRIBUTED GENERATION INTERCONNECTION TARIFF CHANGES HF 1174 Rep. Andrew Falk (DFL – Murdock) SF 1362 Sen. John Marty (DFL – Roseville) To require the Minnesota Public Utilities Commission to establish generic standards for utility tariffs for the interconnection and parallel operation of distributed generation projects, including cogeneration projects interconnected with investor-owned utilities’ distributions systems. The tariff standards would have to: establish a procedure whereby, when the size of a distributed generation resource

causes power to flow intermittently into transmission facilities operated by the Midwest Independent Systems Operator (MISO), a local load-serving utility may coordinate with MISO to conduct the interconnection transmission system analysis and transmission system usage reservations, as needed;

include payments for ancillary services and other system benefits provided by a distributed generation resource;

reflect the savings that accrue to the public utility's distribution system resulting from avoided demand charges and avoided transmission and transmission infrastructure costs; and

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recognize the role played by the regional wholesale electricity market and demand side and storage resources as a source of standby power for a distributed energy resource.

CIP SAVINGS GOAL SUNSET HF 1271 Rep. Roger Erickson (DFL – Baudette) SF 1358 Sen. Tom Saxhaug (DFL – Grand Rapids) To repeal the requirement that utilities meet an annual energy savings goal, beginning in 2016. In the meantime, all utility infrastructure improvements would count toward a utility’s CIP savings goal regardless of whether it has met 1% savings on customer-side improvements. The bill would also set compensation for all customer-generated electricity at a rate equal to the utility’s avoided cost.

GROUNDWATER CONFERENCE HF 1373 Rep. Peter Fischer (DFL – Maplewood) SF 988 Sen. Charles Wiger (DFL – Maplewood) To appropriate money from the Clean Water Fund to pay for a metropolitan groundwater management conference. (See Omnibus Environment, Natural Resources & Agriculture Finance and Policy bill in New Laws above.)

UTILITY FRANCHISE AGREEMENTS HF 1450 Rep. Raymond Dehn (DFL – Minneapolis) SF 1490 Sen. Kari Dziedzic (DFL – Minneapolis) To set requirements relating to franchise agreements between cities and non-municipal utilities to promote renewable energy and energy efficiency.

COST OF SERVICE HF 1515 Rep. Michael Beard (R – Shakopee) SF 545 Sen. David Tomassoni (DFL – Chisolm) To require the Minnesota Public Utilities Commission to consider the respective costs of serving the separate classes of electric customers (residential, commercial, industrial) as a primary factor in allocating revenue among customer classes in its rate cases.

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FARM TAP EXCAVATION NOTICE HF 1564 Rep. John Petersburg (R – Waseca) No Senate companion bill To require utilities to mark “private facilities and farm taps” as they do other underground facilities when people call the state excavation notice system (“Gopher State One Call”) for locates.

LARGE HYDROPOWER RENEWABLE ENERGY CREDIT HF 1640 Rep. Peggy Scott (R – Andover) SF 1488 Sen. Michelle Benson (R – Ham Lake) To allow energy from all hydropower sources to count toward the state’s Renewable Energy Standard.

WATER APPROPRIATION PERMIT FEE INCREASE HF 1679 Rep. Jean Wagenius (DFL – Minneapolis) SF 1549 Sen. Bev Scalze (DFL – Little Canada) To increase water appropriation permit fees to pay for regional groundwater resource research. (See Omnibus Environment, Natural Resources & Agriculture Finance and Policy bill in New Laws above.)

RECOVERED ENERGY GENERATION INCENTIVE HF 1852 Rep. Tim Mahoney (DFL – St. Paul) SF 1677 Sen. Dan Sparks (DFL – Austin) To allow recovered energy generation to be eligible for the state’s existing renewable energy production incentive. Recovered energy generation is defined as: “electricity generated by either: a) converting exhaust heat from engines or from manufacturing, industrial, commercial, or institutional sites whose primary purpose is not the generation of electricity; or b) reducing pressure in gas pipelines before gas is distributed through the pipeline, provided the conversion of energy to electricity is achieved without using additional fossil fuels.”

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IINNDDEEXX

HHoouussee FFiilleess

HF 158 ............................................................. 17 HF 183 ............................................................. 17 HF 190 ............................................................. 17 HF 191 ............................................................. 17 HF 255 ............................................................. 18 HF 288 ............................................................. 18 HF 295 ............................................................. 15 HF 304 ............................................................. 18 HF 306 ............................................................. 18 HF 320 ............................................................. 18 HF 337 ............................................................. 15 HF 338 ............................................................. 14 HF 341 ............................................................. 19 HF 343 ............................................................. 19 HF 421 ............................................................. 19 HF 422 ............................................................. 19 HF 436 ............................................................. 19 HF 438 ............................................................. 19 HF 439 ............................................................. 20 HF 469 ............................................................. 15 HF 520 ............................................................. 20 HF 567 ............................................................. 10 HF 581 ............................................................. 20 HF 623 ............................................................. 15 HF 643 ............................................................. 20 HF 655 ............................................................. 20 HF 677 ............................................................. 14 HF 682 ............................................................. 13 HF 683 ............................................................. 20 HF 701 ............................................................. 21 HF 729 ............................................................... 2 HF 752 ............................................................. 21 HF 773 ............................................................. 21

HF 780 ............................................................. 22 HF 843 ............................................................. 22 HF 854 ............................................................. 13 HF 879 ............................................................. 22 HF 880 ............................................................. 22 HF 945 ............................................................. 22 HF 955 ............................................................. 23 HF 956 ............................................................... 2 HF 976 ............................................................. 12 HF 985 ............................................................. 23 HF 1000 ........................................................... 12 HF 1001 ........................................................... 23 HF 1075 ........................................................... 23 HF 1079 ........................................................... 24 HF 1093 ........................................................... 24 HF 1130 ........................................................... 24 HF 1146 ........................................................... 24 HF 1147 ........................................................... 25 HF 1167 ........................................................... 10 HF 1170 ........................................................... 26 HF 1174 ........................................................... 26 HF 1205 ........................................................... 16 HF 1271 ........................................................... 26 HF 1301 ........................................................... 11 HF 1326 ............................................................. 5 HF 1373 ........................................................... 27 HF 1450 ........................................................... 27 HF 1515 ........................................................... 27 HF 1564 ........................................................... 27 HF 1640 ........................................................... 27 HF 1679 ........................................................... 27 HF 1852 ........................................................... 28

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SSeennaattee FFiilleess

SF 37 ................................................................ 19 SF 92 ................................................................ 17 SF 95 ................................................................ 18 SF 97 ................................................................ 18 SF 104 .............................................................. 15 SF 161 .............................................................. 15 SF 183 .............................................................. 14 SF 203 .............................................................. 17 SF 204 .............................................................. 17 SF 211 .............................................................. 17 SF 243 .............................................................. 20 SF 244 .............................................................. 13 SF 273 .............................................................. 19 SF 275 .............................................................. 19 SF 309 .............................................................. 18 SF 329 .............................................................. 15 SF 333 .............................................................. 20 SF 436 .............................................................. 20 SF 454 .............................................................. 19 SF 455 .............................................................. 20 SF 456 .............................................................. 20 SF 480 .............................................................. 21 SF 521 .............................................................. 15 SF 545 .............................................................. 27 SF 552 .............................................................. 14 SF 584 .............................................................. 23 SF 601 .............................................................. 18 SF 642 .............................................................. 22 SF 674 .............................................................. 20

SF 680.............................................................. 21 SF 691.............................................................. 19 SF 695.............................................................. 13 SF 716.............................................................. 16 SF 750.............................................................. 10 SF 763.............................................................. 22 SF 892.............................................................. 21 SF 901................................................................ 2 SF 903.............................................................. 23 SF 911.............................................................. 23 SF 936.............................................................. 10 SF 972.............................................................. 24 SF 988.............................................................. 27 SF 1011 ........................................................... 12 SF 1054 ........................................................... 24 SF 1104 ............................................................. 5 SF 1121 ........................................................... 25 SF 1135 ........................................................... 11 SF 1170 ........................................................... 12 SF 1233 ........................................................... 18 SF 1260 ........................................................... 19 SF 1358 ........................................................... 26 SF 1362 ........................................................... 26 SF 1454 ........................................................... 22 SF 1488 ........................................................... 27 SF 1490 ........................................................... 27 SF 1549 ........................................................... 27 SF 1677 ........................................................... 28

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3025 Harbor Lane N, Suite 400 Plymouth, MN 55447

www.mmua.org

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FROM: Mark Fuchs – Electric Superintendent



SUBJECT: Triple Feeder Rebuild Contractor Bids BACKGROUND: In September bids were received for the Triple Feeder Rebuild Project. This project will replace the triple deck overhead electric feeders that run from the wastewater treatment plant north to Main Street near Sonic. Only one of the bids was complete and the Commission rejected all the bids and directed staff to request new bids. ATTACHMENTS: The bid opening was held on Monday September 9 at 10:00 am. Staff will provide the bid results and make a recommendation at the Utilities Commission meeting.

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FROM: Tom Sagstetter – Conservation and Key Accounts Manager



SUBJECT: Integrity Testing and Demand Bill BACKGROUND: In January 2009, the ERMU Commission approved the Integrity Testing Policy that allowed for large industrial customers to test equipment during off-peak hours and would not receive a demand charge on the testing demand. The off-peak hours in the policy are from 12 midnight to 6:00 a.m. Monday through Friday, and 12 midnight to 10:00 a.m. on Saturday and Sunday. The policy also states that the testing dates and times are to be communicated to ERMU staff 24 hours prior to the integrity testing. The Integrity Testing Policy is included for reference. DISCUSSION: On May 24th, 2013, a large industrial customer, who is required to follow this policy, performed integrity testing of equipment that caused the demand to exceed their normal on-peak demand for the month by 1,459 kW. While the customer did not provide 24 hours of notice of integrity testing and the testing was outside the off-peak hours outlined in the integrity testing policy, staff is looking for a discussion on providing relief for the demand charges for testing in May. The testing period was only 45 minutes, did not occur during the demand billing peak even though it was not during off-peak hours, and causes no additional cost burden to other rate classes of customers. ACTION REQUESTED: Staff is looking for discussion on an exception to the policy, options for resolution, and desired direction from the Commission. ATTACHMENTS:

Integrity Testing Policy

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AGENDA ITEM NUMBER: 6.1a

SUBJECT: Staff Updates – General Manager DISCUSSION:

After over a year of legal and engineering work, it appears we have come to agreeable terms for Sprint’s upgrades to equipment at our Johnson Street and Gary Street water towers. The amendments to the two agreements should be ready for execution at the October Commission meeting.

Verizon continues to work through their analysis of our Johnson Street and Gary Street

water tower sites as potential locations for their 4G system upgrades. Template non-exclusive tower attachment agreements have been provided to Verizon for review.

I’ve been working with Minnesota Municipal Utilities Association (MMUA) and the

other Minnesota municipal utilities that submitted 3 year notice for Mid-Continent Area Power Pool (MAPP) membership withdrawal last month. We are working on terms for an early buy out without having to continue membership for 3 more years.

The Lineworker position opening that had been advertised closed on August 30.

Management is currently reviewing the applicants and will be setting up interview for the week of September 16-20. Management is also working to fill a vacant Meter Technician position. This position was posted internally. This will create a need to backfill another position as a result of filling the Meter Technician position. The interviews for the Meter Technician position will be conducted the week of September 9-10 and the vacated position will be advertised externally and fill as soon as possible.

Over the past year I’ve been working to schedule a strategic planning session for the

Utilities that would include the Commission and Management. The strategic planning was intended to develop some general long term goals to help make better informed short term policy decisions. Topics were to include but not limited to: identifying threats; financial positioning; long term power and transmission goals; the right to grow with our

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city; policy direction; governance; future personnel needs; future facility needs; customer service and local accountability expectations; partnership with the city to promote economic development; safety; and reliability.

At a minimum, we’d need to have 8 hours which could be split over multiple days. We had also planned on having MMUA facilitate the strategic planning session(s). Scheduling this time has proven problematic. After discussion with our legal counsel, the strategic planning session(s) would be subject to the open meeting laws; therefore it would not be an issue to conduct any or all of the strategic planning during the regular commission meetings. So to be respectful of the Commission’s time, I’d like to bring strategic planning topics to the regular Commission meetings and work through them one by one. If the Commission has no objection to this method, I’ll plan to put this on the October Commission agenda to establish expectations, refine the list of topics, and create a tentative long range schedule to start working through these strategic issues.

ATTACHMENTS:

American Public Power Association - Public Power Weekly article “Boulder City Council authorizes purchase of local distribution system from Xcel Energy.” – August 26, 2013

American Public Power Association - Public Power Weekly article “Proposal to cap or end municipal bond tax exemption would harm the economy and issuers, S&P warns.” – August 26, 2013

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Public Power WeeklyAugust 26, 2013: No. 34

Boulder City Council authorizes purchase of local distribution system from Xcel Energy

The Boulder City Council on Aug. 20 took another step toward the possible creation of a city-owned electric utility, voting to move forward with efforts to buy the local distribution system from Xcel Energy. Members of the City Council also decided to give voters an opportunity to set an upper limit of $214 million on key costs, in addition to the limits previously set forth by the City Charter. Both measures passed on a vote of 6-3.

The vote will allow city staff to conduct a formal appraisal of the parts of Xcel’s system that serve Boulder and enter into negotiations with the investor-owned utility "in hopes of reaching an agreement about the value of the system," the city said.

The vote also gives attorneys for the city authority to file a condemnation lawsuit in Boulder District Court, if the negotiations are unsuccessful. Such a condemnation action would not occur, however, before January 2014, the city said.

In July, an independent evaluator said Boulder is likely to be able to offer rate parity with Xcel at the outset and also over a 20-year period. (See Public Power Weekly, July 29.)

The effort to create a municipal utility in Boulder is driven in large part by a desire for cleaner, more renewable sources of energy. Residents of the Colorado community approved two ballot measures in November 2011 that authorized the city to continue to explore the possibility of purchasing Xcel Energy’s distribution system and forming a city-owned utility. (See the Nov. 3, 2011 Public Power Daily.)

"We appreciate City Council providing the opportunity to take the next steps in evaluating how we can achieve our community goal of accessing clean, reliable and local energy in a cost-effective way," said Heather Bailey, the city's executive director of energy strategy and electric utility development. "The information we gather over the next several months will be critical to helping us understand all that is possible."

Attorneys have indicated that a court case, if necessary, is likely to take 12 to 18 months from the time legal action is filed.

A video featuring statements from council members about their positions prior to voting on whether to move forward with potential acquisition is available at http://vimeo.com/72287823.

Council also approved the language of a November 2013 ballot item related to the issuance of debt. The ballot item will give Boulder voters an option of setting a $214 million limit on the amount the city can take on in debt in order to buy Xcel’s assets, and for stranded costs.

"Stranded costs are costs that an existing utility, in this case, Xcel, may be able to recoup from customers who are leaving its system to cover investments it made in generation facilities, like coal plants, in order to serve them," the city said in a news release. "There are limitations in Xcel’s ability

Page 1 of 2Boulder City Council authorizes purchase of local distribution system from Xcel Energy

8/26/2013http://www.naylornetwork.com/app-ppw/articles/print-V2.asp?aid=23131898

to claim these costs, and the city recently received clarification from the Federal Energy Regulatory Commission that it is possible to mitigate these types of costs, if they apply at all, by continuing to buy some power from Xcel for a limited time."

If approved by voters, the $214 million limit would be in addition to existing City Charter provisions that require the city to meet specific financial, service delivery and environmental requirements before issuing debt.

The City Council-backed measure is designed to conflict with a citizen-petitioned initiative that is also related to the municipalization effort, the city said. The petitioned measure "limits the city’s ability to carry out the direction it received from voters in 2011 by requiring additional voter approval by all utility customers before the issuance of any debt, regardless of whether the charter requirements can be met," Boulder said.

The petitioned initiative "also seeks to limit these types of elections to every two years and require that all customers, including those who are not city voters, be included in any city election related to utility debt," the city said. "The measure does not establish a legal procedure for allowing this type of an out-of-jurisdiction vote."

More information about the two ballot measures, including a Boulder Channel 8 video of the Aug. 20 City Council meeting, is available at BoulderEnergyFuture.com.

The November ballot measures are in conflict with one another, so the following three outcomes are possible, the city said:

• One measure passes and the other one fails;• Both measures pass; or• Both measures fail.

If the City Council-backed measure has the most votes, the petitioned initiative will not take effect. If the petitioned initiative has the most votes, both measures will be in effect, but where they conflict, the measure with the most votes will prevail.

If both measures fail, the City Council would have authority to issue bonds to create a local electric utility if certain conditions can be met. However, the council "has said it would seek to understand the intentions of voters and determine how to proceed at that time," the city said.

The election will be Tuesday, Nov. 5. —JEANNINE ANDERSON

Copyright © 2013, American Public Power Association

Page 2 of 2Boulder City Council authorizes purchase of local distribution system from Xcel Energy


Public Power WeeklyAugust 26, 2013: No. 34

Proposals to cap or end municipal bond tax exemption would harm the economy and issuers, S&P warns

Proposals to eliminate or reduce three tax programs — the exemption of municipal bond interest, the deductibility of property taxes, and the mortgage interest deduction — "would have broad and mostly negative consequences on the economy and on the credit quality of state and local governments and other tax-exempt issuers," Standard & Poor’s Ratings Services said in a new report. That "is especially true of the exemption of municipal bond interest," S&P said in the report, "Cutting Popular U.S. Tax Programs Could Harm Tax-Exempt Bond Issuers."

Policymakers "should consider the critical role these tax provisions play in the municipal finance sector, the housing industry, and the overall economy," S&P said. The report said the three tax provisions help grow the economy, make the tax code fairer, and effectively promote important policy objectives—three key criteria cited by Senate Finance Committee Chairman Max Baucus, D-Mont., and Ranking Member Orrin Hatch, R-Utah, in a letter asking their colleagues to help identify tax expenditures that should be retained.

Proposals to reduce or eliminate these provisions "would cause a significant disruption to the market and increase the cost of borrowing for municipal entities," said Steven Murphy, senior managing director and head of U.S. Public Finance at Standard & Poor's. "Investors can be expected to seek to be compensated for a reduced tax benefit, leading to an increase in the cost of debt issuance. If the change were retroactive, interest rates on outstanding variable-rate debt would escalate. Refinancings, which continue to be an important fiscal tool, particularly as municipal entities try to recover, replenish balances, and invest in infrastructure, would become much less viable, if viable at all," he added.

Without the tax exemption for municipal bond interest, municipal borrowers "would face higher interest rates with the inevitable result that many state and local governments would need to impose higher taxes, do less capital investment, or some combination of both," the report said. Low-income taxpayers could be hit disproportionately hard, since state and local tax structures tend to be less progressive than federal taxes. "In our view, such an outcome would be at odds with any suggestion that the tax exemption should end because it unfairly benefits the wealthy," the report said.

These effects "would come at a time when municipal entities continue to struggle to recover from the Great Recession; when the real estate market is making a tenuous recovery; and when capital investment needs are at an all-time high," S&P said. If the proposed changes to tax law were retroactive, interest rates on outstanding variable-rate debt would escalate, the report said.

"Increased debt service costs would force issuers to make difficult choices between capital investment, reserve maintenance, taxation and user fee levels, and key services," S&P said. "This, again, would be at a point where infrastructure needs are significant and growing, as the impact of projects deferred during the recession are combined with ongoing maintenance, upgrade and growth-oriented projects." Municipal issuers who fail to maintain and invest sufficiently in new infrastructure "undermine their economic competitiveness, attractiveness for commercial, residential and nonprofit investment, and, most importantly, their potential for growth," the report said. The inability to address

Page 1 of 2Proposals to cap or end municipal bond tax exemption would harm the economy and issu...


capital needs adequately engenders risks similar to other deferred liabilities, including underfunded pensions and other post-employment benefits, S&P said. —ROBERT VARELA

Copyright © 2013, American Public Power Association

Page 2 of 2Proposals to cap or end municipal bond tax exemption would harm the economy and issu...


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FROM: Theresa Slominski – Finance and Office Manager



SUBJECT: Staff Update DISCUSSION: We had 2,206 credit card payment transactions in August, compared to 2,197 in July. The fee for August should be $4,963.50 The software research team has been active in exploring the NISC iVUE software as an option for Elk River Municipal Utilities. We have had a number of conference calls and website demos, have made reference calls, and have visited a utility in Albert Lea, MN to see the software in action and ask questions of the users. We are having an onsite demo on September 4th and 5th to expose more staff to its functionality, and then assess if it truly is a good fit. If this is determined to be the software of choice, we want to send four staff to the annual conference to be able to ask more questions of their current users, as well as NISC team members, to best prepare for the conversion. (We would be sending staff to this conference in place of the PMan Users Group conference we usually attend in September.) We received our health insurance renewal for 2014. We have had minimal increases the past four years, at 4.5%, 0%, and 0% and even a 9.5% decrease in 2012 (see graph attached). However this year, with some increased utilization and all of the changes in the industry, our rates are going up 22%. (As a bit of history, we had a 20.6% increase in 2005.) Our insurance broker is working with Blue Cross and Blue Shield to gather information for our options. I should have that this week and then the Wage and Benefit Committee will need to meet and review this information to bring back to the Commission. In July, the City issued an RFP for Financial Advisory Services to commence on October 1st. Interviews were held on Friday, August 19th with the three finalist firms: Ehlers (the current provider), Northland Securities, and Springsted. Participating in the interviews was a committee of Cal Portner, Tim Simon, Lorrie Ziemer, Brian Beeman, Stuart Wilson and myself. The committee decided upon Springsted and this will be going the City Council on September 16th.

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FROM: Mark Fuchs – Line Superintendent



SUBJECT: Staff Update DISCUSSION:

Had four new services. Finished Riverview Heights rebuild. There are some poles that need to be pulled after

cable TV removes their wire off the poles. Finished changing out rusty junction boxes. This is an ongoing project and we try to get

the worst ones changed out each year. Continue working on changing out fuse pads. This has been an ongoing project that had

to be done because of our high fault current. Started rebuilding Troy and Union Street. This is an overhead 2400 volt line that we are

changing to underground and upgrading the voltage to 7200. We buried a single phase overhead line on 4th Street. The City was working on the roads

and sidewalks in that area and asked if we could remove some poles and anchors that were in the sidewalk.

Started working on feeder 94 rebuild. The first part of this job is removing the overhead three phase rear lot line that is located between School St. and Gates Ave.

Started working on getting things ready to change out the substation transformer at the north substation site.

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FROM: Wade Lovelette – Superintendent of Technical Services


AGENDA ITEM NUMBER: 6.1d


The Locating department had a total of 404 locate tickets in August; three of them being emergency tickets, 10 cancelations, 12 meets, 340 normal, 36 updated tickets and three boundary surveys.

In August, the Security Systems Department had a total of 80 phone contacts, five systems quoted, seven system sales made, seven installs completed, 38 service calls and five personal visits.

Meter Technicians continue with the meter reading, power bill, substation checks and off-peak issues. They continue to change out the three phase meters to radio read meters. They are also moving the substation meters to the outside of the North Substation meter building.

The power plant staff did the monthly run of the engines. The engines ran good with no problems.

Two of our staff continues to collect data with the GPS for our ArcView maps as time permits.

Steve and Jeff continue directional boring on 4th St. street project. Michael Price attended the UMMA (Upper Minnesota Metering Association)

meeting in Duluth last month.

ATTACHMENTS:

Thank You Letter for Night To Unite

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FROM: David Berg – Water Superintendent



SUBJECT: Staff Update DISCUSSION: Angela and Pete have been working on hydrant maintenance and helping Bolton and Menk find water valves that have been covered with dirt or black top. We are doing this to bring our water maps up-to-date with coordinates for all valves. Some of the valves were unable to be located as the GPS crew was shooting points, however we will continue to work to find the coordinates. Angela has been training Mike and Gene on GPS to assist them with the long-term mapping project. She has also approved another customer to the SMART Irrigation Rebate. The Freeport Water Tower painting is nearly finished. Eric deserves a lot of credit as he has put in significant amounts of time to make sure all of the specs have been followed.

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FROM: Tom Sagstetter - Conservation and Key Accounts Manager




Attended a Conservation Improvement Program presentation at the MMUA Summer Annual Meeting. Jessica Burdett from the Minnesota Division of Energy Resources (MNDER) presented on the changes to CIP in the coming years. After 30 years of conservation programs, there are many opportunities for changes. MNDER is developing more online tools for utilities to utilize to help account for and track energy savings. They are also updating the technical resources that assist in program development and quantifying energy savings of programs.

Working with Tri-County Community Action Program (Tri-CAP) to increase participation in weatherization and energy assistance programs that they offer to income eligible customers. Developed informational posters that will be displayed in local businesses (currently displayed at City Hall, ERMU lobby, two locations at Sherburne County Government Center, Cub Foods, Coborns, Goodwill, and CAER). Other locations that will be considered include Salvation Army, Otsego City Hall, Post Office, and the Elk River Library. The information will also be displayed on the Elk River cable channel.

Met with Tri-Cap to discuss ERMU’s participation in the Energy Resource Fair that Tri-Cap is sponsoring with other utilities including Xcel Energy, Center Point Energy, and Stearns County Electric Cooperative. ERMU has committed to just under $1,000 of low income funds to sponsor the event that will be held from 11 a.m. to 6 p.m. on September 25th at the St. Cloud Public Library.

The protective barriers are in place at the landfill and it is now in compliance with the recommendations provided by the Elk River Fire Marshall.

Participating in the utilities portion of the City of Elk River’s Comprehensive Plan update.

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Documents

REGULAR MEETING OF THE September 10, 2013, 3:30 P.M. …96bda424cfcc34d9dd1a-0a7f10f87519dba22d2dbc6233a731e5.r41.… · 4.0 OLD BUSINESS . 4.1 Freeport Water Tower Rehabilitation