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04-24-2019 HUCCPHUTCHINSON UTILITIES COMMISSION AGENDA REGULAR MEETING April 24, 2019 3:00 p.m. 1. CONFLICT OF INTEREST 2. APPROVE CONSENT AGENDA a. Approve Minutes b. Ratify Payment of Bills 3. APPROVE 2018 FINANCIAL AUDIT — PRESENTATION BY JUSTIN MCGRAW 4. APPROVE FINANCIAL STATEMENTS 5. OPEN FORUM 6. COMMUNICATION a. City Administrator b. Divisions C. Human Resources d. Legal e. General Manager 7. POLICIES a. Review Policies i. Section 4 of Exempt Handbook ii. Section 4 of Non -Exempt Handbook b. Approve Changes 8. UNFINISHED BUSINESS 9. NEW BUSINESS a. Unit #8 Control System Upgrade - Reject Bids from the April 2 bid opening and Approve Re -Advertisement for Bids b. Approve Requisition #7907 Unit 1 Steam Piping Repair C. Approve Requisition #7908 Unit 1 Painting d. Approve Requisition #7920 Purchase of Breakers e. Dissolve Current Distributed Generation Policies f. Adopt Distributed Energy Resource (DER) Resolution, Policy and Rules g. Adopt Distributed Energy Resource Resolution Interconnection Process h. Northern Natural Gas Capacity release to CenterPoint Energy Services 10. ADJOURN MINUTES Regular Meeting — Hutchinson Utilities Commission Wednesday, March 27, 2019 Call to order — 3:00 p.m. Vice President Matt Cheney called the meeting to order. Members present: Vice President Matt Cheney; Secretary Robert Wendorff; Commissioner Monty Morrow; Commissioner Anthony Hanson; GM Jeremy Carter Absent: President Don Martinez and Attorney Marc Sebora 1. Conflict of Interest 2. Approve Consent Agenda a. Approve Minutes b. Ratify Payment of Bills Motion by Commissioner Morrow, second by Commissioner Wendorff to approve the Consent Agenda. Motion carried unanimously. 3. Approve Financial Statements Jared Martig presented the financial statements. For the Electric Division, Purchased Power is up due to not being able to start an engine at Plant 2 during the Polar Vortex. For the Natural Gas Division, Natural Gas net income decreased by $277,557. The decrease is mostly due to the credit on customer bills that were missing in 2018. This is the last month of not being able to compare year to year due to the missing credits from 2018. GM Carter discussed how the Polar Vortex affected HUC and other Utilities in the Midwest. GM Carter added that there have been many conversations on how to mitigate the effects of extreme temperatures at the plants so this will not happen again. Commissioner Hanson inquired how many times extreme temperatures have prevented HUC from starting an engine. Mr. Blake informed the Commission that it has only happened one other time. HUC does have safe guards in place but it was so cold and the engine would not operate that day. GM Carter noted on the Electric Division, Large General is up from last year. The increase is due to Uponor ramping up. GM Carter added that Industrial is down for both HTI and 3M. HTI is ramping down and 3M has more energy efficiency in place. Motion by Commissioner Hanson, second by Commissioner Morrow to approve the financial statements. Motion carried unanimously. 4. Open Forum 5. Communication a. City Administrator —Matthew Jaunich — i. Middle of construction season 1 b. Divisions i. Dan Lang, Engineering Services Manager — Absent ii. Dave Hunstad, Electric Transmission/Distribution Manager — 1. Reviewed the 2018 Annual Benchmarking Report. HUC received another Excellence in Reliability Certificate. 2. Projects will be starting soon. iii. Randy Blake, Production Manager — 1 . Unit 1 auxiliary boiler has sprung a leak. Moorhead Boiler has already come to weld the repair. 2. Cooling Tower cleanup work. There were three cracks found, will be working with a local contractor to patch cracks inside and out. Excavating will start this month and the cost of the repair will be about $4K. 3. Construction down at Plant 1 is going well. 4. Quade's Electric has started on Units 6 & 7. Commissioner Hanson inquired about the completion date and if it was behind schedule. Mr. Blake noted the project is about one month behind. iv. John Webster, Natural Gas Division Manager- 1. Attended the MEA Energy Association's Board of Directors meeting in Austin Texas this month. Was elected to be an officer on the Board of Directors. v. Jared Martig, Financial Manager- Nothing to report c. Legal — Marc Sebora — Absent d. Human Resources - Brenda Ewing — Nothing to report e. General Manager — Jeremy Carter i. Catching up on Legislative bills ii. Had an MMUA meeting in Owatonna with Dave. Discussed the new law changes related to Distributed Energy Resources (DER) and the different processes coming forward. In the next month or two, the Commission will need to adopt new policies and rules to comply with the new State laws. iii. Continuing to work on strategic planning. Will be sending topics to managers this week. If the commissioners have anything to add, please send them soon. 6. Policies a. Review Policies i. Section 3 of Exempt Handbook ii. Section 3 of Non -Exempt Handbook No changes recommended at this time. b. Approve Changes No changes made to the policies under review. 7. Unfinished Business 2 8. New Business a. Approve Requisition #007878, Custom Dakota Aluminum Service Body Mr. Webster presented Requisition #007878, Custom Dakota Aluminum Service Body. Earlier in the year, two new pickup trucks were ordered without the service body. This requisition is for the service body, related work equipment, miscellaneous materials and labor required for installation on the 2019 Ford F250. A motion by Commissioner Morrow, second by Commissioner Hanson to Approve Requisition #007878, Custom Dakota Aluminum Service Body. Motion carried unanimously. b. Approve Requisition #007879, Custom Dakota Aluminum Service Body Mr. Webster presented Requisition #007879, Custom Dakota Aluminum Service Body. As above, the pickup for this body was ordered earlier in the year. This requisition is for the service body, related work equipment, miscellaneous materials and all labor required for installation on a 2019 Ford F350. A motion by Commissioner Wendorff, second by Commissioner Morrow to Approve Requisition #07879, Custom Dakota Aluminum Service Body. Motion carried unanimously. c. Approve Requisition #007887, Purchase of Lube Oil Mr. Blake presented Requisition #007887, Purchase of Lube Oil. The lube oil for units 6 & 7 was not included in the Caterpillar contract. In order to be compliant with the CAT warranty, HUC must use CAT1 NGEO Ultra 40 oil. This requisition will be sufficient for both engines needing 850 gallons each along with having 100 gallons for inventory when needed. A motion by Commissioner Hanson, second by Commissioner Wendorff to Approve Requisition #007887, Purchase of Lube Oil. Motion carried unanimously. d. Purchase of Natural Gas Commodity November 2026-October 2029 Mr. Webster presented Purchase of Natural Gas Commodity November 2026- October 2029. Natural gas commodity was purchased for HUC customers for the time period of November 2026 thru October 2029. Additionally, volumes not associated with the prepay deal were blended in the future months in order to reduce the price of the commodity. By blending the December 2024 thru October 2026 gas at $4.535 per Dth with the November 2026 thru October 2029 gas, HUC 3 was able to acquire the $4.535 down to a new price of $4.08 Dth. This is not a savings but a reduction in cost. 9. Adjourn There being no further business, a motion by Commissioner Morrow, second by Commissioner Wendorff to adjourn the meeting at 3:29p.m. Motion carried unanimously. ATTEST: Don Martinez, President 12 Robert Wendorff, Secretary 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Fund: 1 ELECTRIC 03/25/2019 GEN 345(E)*4 BP CANANDA ENERGY SOLUTIONS 03/25/2019 GEN 357(E)* PAS 03/25/2019 GEN 68666*4 ACE HARDWARE Generator 41 Natural Gas GENERATOR 41 NATURAL GAS Generator 41 Aux Boiler GENERATOR 43 NATURAL GAS GENERATOR 44 NATURAL GAS GENERATOR 45 NATURAL GAS GENERATOR 48 NATURAL GAS Generator 49 Natural Gas Utility Expenses - Water/Waste HECK GEN 345(E) TOTAL HEALTH INSURANCE-HRA FEES Maintenance Other - Materials Building & Grounds - Materials Power Equipment - Materials Grounds - Materials HECK GEN 68666 TOTAL 03/25/2019 GEN 68667* ALA AVIATION LLC DEP REFUND/APPLIED 03/25/2019 GEN 68668* ALEXANDER LAMP OR SARAH BENSON DEP REFUND/APPLIED 03/25/2019 GEN 68669 AMERICINN Cip- Commercial 03/25/2019 GEN 68670 ANDREW WILLCUTT OVERPAYMENTS 03/25/2019 GEN 68671 ANITA VANDERWEGE OVERPAYMENTS 03/25/2019 GEN 68672* BEN KING OR KELLY VANDERSTOEP DEP REFUND/APPLIED 03/25/2019 GEN 68673* BORDER STATES ELECTRIC SUPPLY Underground Conductor Underground Conductor KIT, T-OP, COMPLETE ASSEMBLY, 600A KIT, T-OP, COMPLETE ASSEMBLY, 600A Account Dept 401-547- 01 401-547- 01 401-547- 01 401-547- 01 401-547- 01 401-547- 01 401-547- 01 401-547- 01 401-930- 08 401-926- 08 402-554- 01 402-592- 02 402-598- 02 401-935- 08 235-000- 00 235-000- 00 401-916- 07 142-000- 00 142-000- 00 235-000- 00 107-367- 00 107-367- 00 154-000- 00 154-000- 00 Pag 1/30 Amount 368.20 23,192.04 1,067.71 28.32 28.32 56.65 99.13 177.03 679.46 35.87 60.97 3.20 296.08 396.12 35.75 162.50 526.50 99.73 25.23 139.75 342.94 848.06 2,156.32 288.07 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 2/30 Amount Fund: 1 ELECTRIC GREASE, LUBRICATING, SILICONE 154-000- 00 24.82 Sales Tax Receivable - New 186-000- 00 148.25 Sales Tax Receivable - New 186-000- 00 0.86 HECK GEN 68673 TOTAL 3,809.32 03/25/2019 GEN 68674 BRAUN INTERTEC CORPORATION Generators 107-344- 00 414.50 03/25/2019 GEN 68675* BRIAN DRESSEL OR MONA DRESSEL DEP REFUND/APPLIED 235-000- 00 71.50 03/25/2019 GEN 68677 CALYN LIESTMAN Cip - Residential 401-916- 07 25.00 03/25/2019 GEN 68678* CAMELIA YUNGK DEP REFUND/APPLIED 235-000- 00 48.75 03/25/2019 GEN 68679* CATHERINE STRAVINO BARNA DEP REFUND/APPLIED 235-000- 00 32.50 03/25/2019 GEN 686804 CHAMBERLAIN OIL COMPANY INC SHELL, TELLUS, S2V32 154-000- 00 2,120.75 Accessory Plant - Materials 402-554- 01 60.03 HECK GEN 68680 TOTAL 2,180.78 03/25/2019 GEN 68681*4 CINTAS CORPORATION 4470 Uniforms & Laundry 401-550- 01 324.33 Uniforms & Laundry 401-550- 01 324.33 UNIFORMS & LAUNDRY 401-588- 02 67.11 UNIFORMS & LAUNDRY 401-588- 02 217.11 HECK GEN 68681 TOTAL 932.88 03/25/2019 GEN 68682*4 CITY OF HUTCHINSON Generator 41 Water & Sewer 401-547- 01 213.04 Generator 41 Water & Sewer 401-547- 01 146.71 Waste Disposal 401-550- 01 8.38 Waste Disposal 401-550- 01 75.30 Waste Disposal 401-550- 01 478.07 Power Equipment - Materials 402-598- 02 8.38 IT ADMIN AND SUPPORT 750 401-921- 08 16, 693.05 Utility Expenses - Water/Waste 401-930- 08 54.56 Utility Expenses - Water/Waste 401-930- 08 394.40 Utility Expenses - Water/Waste 401-930- 08 8.46 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 3/30 Amount Fund: 1 ELECTRIC HECK GEN 68682 TOTAL 18,080.35 03/25/2019 GEN 68683 CITY OF HUTCHINSON Cip- Commercial 401-916- 07 496.26 03/25/2019 GEN 68684* CYNTHIA WATELAND DEP REFUND/APPLIED 235-000- 00 162.50 03/25/2019 GEN 68685 DAVID DICKERSON OVERPAYMENTS 142-000- 00 262.51 03/25/2019 GEN 68686* DON HANSEN Cip - Residential 401-916- 07 150.00 03/25/2019 GEN 686874 FASTENAL COMPANY Generators 107-344- 00 6.62 Supplies 401-550- 01 42.51 HECK GEN 68687 TOTAL 49.13 03/25/2019 GEN 686884 FERGUSON ENTERPRISES 4525 Sales Tax Receivable - Replace 186-000- 00 5.37 1" ballvalve - part # FNW420G 402-554- 01 78.15 HECK GEN 68688 TOTAL 83.52 03/25/2019 GEN 68689* FIRST CHOICE FOOD & BEVERAGE BREAKROOM/RECOGNITION BANQUET 401-926- 08 211.50 03/25/2019 GEN 68690 GREAT RIVER ENERGY TRANSMISSION EXPENSE 401-565- 03 92,345.01 03/25/2019 GEN 68692 HER ENGINEERING INC Generators 107-344- 00 4,533.47 Generators 107-344- 00 4,943.63 HECK GEN 68692 TOTAL 9,477.10 03/25/2019 GEN 68693 HUNTER TURNER OR CHLOE MORAWITZ OVERPAYMENTS 142-000- 00 49. 70 03/25/2019 GEN 68694*4 HUTCHINSON CO-OP Supplies 401-550- 01 12.47 Vehicles - Material 402-598- 02 429.74 Power Equipment - Materials 402-598- 02 51.80 HECK GEN 68694 TOTAL 494.01 03/25/2019 GEN 68695* JAMES OR MELISSA VAN DE too DEP REFUND/APPLIED 235-000- 00 117.00 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK Payee DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Account Pag Dept 4/30 Amount Fund: 1 ELECTRIC 03/25/2019 GEN 68696* JAMES OR MELISSA VAN DE too GET REFUND/APPLIED 235-000- 00 9.75 03/25/2019 GEN 68697* JAMES OR MELISSA VAN DE too GET REFUND/APPLIED 235-000- 00 48.75 03/25/2019 GEN 68698* JASON MAYER Cip - Residential 401-916- 07 150.00 Cip - Residential 401-916- 07 32.00 HECK GEN 68698 TOTAL 182.00 03/25/2019 GEN 68699* JAYSHERI MUELLER OR J MARTICHUSKI GET REFUND/APPLIED 235-000- 00 227.50 03/25/2019 GEN 68700* JENNIFER BASSLER GET REFUND/APPLIED 235-000- 00 195.00 03/25/2019 GEN 68701 JLR GARAGE DOOR SERVICE INC Generator 41 Material 402-554- 01 1,400.00 03/25/2019 GEN 68702* JOAN KRUEGER GET REFUND/APPLIED 235-000- 00 227.50 03/25/2019 GEN 68703 JODI LANSKA Cip - Residential 401-916- 07 25.00 03/25/2019 GEN 68704* JON MROSS GET REFUND/APPLIED 235-000- 00 71.50 03/25/2019 GEN 68705* JON WHEELER OR DAWN WHEELER GET REFUND/APPLIED 235-000- 00 130.00 03/25/2019 GEN 68706* JONNY WALLA JR GET REFUND/APPLIED 235-000- 00 26.00 03/25/2019 GEN 68707* JOSEPH GOSKESEN GET REFUND/APPLIED 235-000- 00 104.00 03/25/2019 GEN 68708* JOSHUA KAMRATH OR LEAH KAMRATH GET REFUND/APPLIED 235-000- 00 130.00 03/25/2019 GEN 68709* JOSHUA KAMRATH OR LEAH KAMRATH GET REFUND/APPLIED 235-000- 00 97.50 03/25/2019 GEN 68710 KEITH KAMRATH Cip- Commercial 401-916- 07 90.00 03/25/2019 GEN 68711 DRESSY FEILER OVERPAYMENTS 142-000- 00 16. 82 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Fund: 1 ELECTRIC 03/25/2019 GEN 68712* KYKESHIA SAVICH OR ZACH ALLEN 03/25/2019 GEN 68713* LAURA WEIKLE 03/25/2019 GEN 68714 LEIDOS ENGINEERING, LLC 03/25/2019 GEN 68715 LOCATORS & SUPPLIES INC 03/25/2019 GEN 68716 MAPLEWOOD PROPERTY MANAGEMENT 03/25/2019 GEN 68718 MCLEOD COUNTY TREASURER 03/25/2019 GEN 68719 MICHAEL REINER 03/25/2019 GEN 68720* MICHELLE HEINING 03/25/2019 GEN 68721 MIKE SWANSON 03/25/2019 GEN 68722* MN NCPERS 03/25/2019 GEN 68723* NOLAN COOK 03/25/2019 GEN 68724 OXYGEN SERVICE COMPANY INC 03/25/2019 GEN 68725* PIZZA RANCH 03/25/2019 GEN 68726* PLUMBING & HEATING BY CRAIG 03/25/2019 GEN 68727 PRECISION COOLING TOWERS INC. Pag 5/30 Account Dept Amount DEP REFUND/APPLIED 235-000- 00 81.25 DEP REFUND/APPLIED 235-000- 00 91.00 Cip- Commercial 401-916- 07 5,940.00 MARKER, EZ SEE, 3/8" X 5 WHITE ROD WITH 154-000- 00 190.00 MARKER, EZ SEE, 3/8" X 5 WHITE ROD WITH 154-000- 00 195.00 Sales Tax Receivable - New 186-000- 00 13.07 Sales Tax Receivable - New 186-000- 00 13.41 HECK GEN 68715 TOTAL 411.48 Cip- Commercial 401-916- 07 200.00 Street Lighting - Materials 402-596- 02 275.00 Cip - Residential 401-916- 07 25.00 Cip - Residential 401-916- 07 400.00 OVERPAYMENTS 142-000- 00 55.22 LIFE INSURANCE-PERA LIFE 242-000- 00 48.00 DEP REFUND/APPLIED 235-000- 00 227.50 BLADE, BAND SAW, 7' 9" X 3/4" 6/10, 154-000- 00 59.80 DEP REFUND/APPLIED 235-000- 00 2,275.00 DEP REFUND/APPLIED 235-000- 00 162.50 Cooling tower repair- Quote # PP-5061 107-343- 00 46,485.00 PRIME MOVERS/RENEWABLES-& FRIEGHT 107-343- 00 2,950.44 Sales Tax Receivable - Replace 186-000- 00 770.77 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Fund: 1 ELECTRIC HECK GEN 68727 TOTAL 03/25/2019 GEN 68728* PREMIER INVESTMENTS DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68729* PREMIUM WATERS INC OFFICE SUPPLIES -BOTTLED WATER 401-921- 08 03/25/2019 GEN 68730*4 PRO AUTO & TRANSMISSION REPAIR VEHICLES - MATERIAL-ELEC 402-598- 02 VEHICLES - MATERIAL-ADMIN 55/45 401-935- 08 HECK GEN 68730 TOTAL 03/25/2019 GEN 687314 PROCHASKA LLC CHLOR 125 (SANI-CHLOR) 154-000- 00 Accessory Plant - Materials 402-554- 01 Accessory Plant - Materials 402-554- 01 HECK GEN 68731 TOTAL 03/25/2019 GEN 68732 QUADE ELECTRIC Generators 107-344- 00 03/25/2019 GEN 68733 KID EQUIPMENT DRILL CLEAN 402-598- 02 GEOSWEEP-BAG 402-598- 02 PRODRILL 402-598- 02 PRODYNE 402-598- 02 POWER EQUIPMENT - MAT -FREIGHT & TAX 402-598- 02 Break out Device for the 402-598- 02 HECK GEN 68733 TOTAL 03/25/2019 GEN 68734* RHONDA KRAMER OR MIKE KRAMER DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68735* RIVER OAKS AT SHADY RIDGE DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68737* SHERRY FOSSUM DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68738* SHRED RIGHT OFFICE SUPPLIES -SHREDDING SERVICES 401-921- 08 Pag 6/30 Amount 50,206.21 390.00 17.75 959.57 175.37 1,134.94 1,150.10 500.00 0.05 1,650.15 54,900.00 51.80 257.20 142.50 90.30 87.54 130.00 2,372.50 32.50 12.48 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 7/30 Amount Fund: 1 ELECTRIC 03/25/2019 GEN 68739* SOUTHPOINT FINANCIAL CREDIT UNION GET REFUND/APPLIED 235-000- 00 1,950.00 03/25/2019 GEN 68741 STEARNSWOOD Cip- Commercial 401-916- 07 646.26 03/25/2019 GEN 68742* STEVEN JACKSON GET REFUND/APPLIED 235-000- 00 65.00 03/25/2019 GEN 68743* THOMAS COLEMAN OR PAIGE LARK GET REFUND/APPLIED 235-000- 00 104.00 03/25/2019 GEN 68744* UIS/SOURCECORP COLLECTION - MATERIALS 401-903- 06 406.63 COLLECTION - MATERIALS 401-903- 06 12.57 COLLECTION - MATERIALS 401-903- 06 1,464.47 HECK GEN 68744 TOTAL 1,883.67 03/25/2019 GEN 68746* WESLEY SOMMERFELD OR TERI WALKER GET REFUND/APPLIED 235-000- 00 26.00 03/25/2019 GEN 68747* WESLEY SOMMERFELD OR TERI WALKER GET REFUND/APPLIED 235-000- 00 32.50 03/25/2019 GEN 68748*4 WEST CENTRAL SANITATION INC GENERATOR 41 WATER & SEWER 401-547- 01 88.48 Waste Disposal 401-550- 01 142.85 UTILITY EXPENSES - WATER/WASTE 55/45 401-930- 08 215.86 HECK GEN 68748 TOTAL 447.19 03/25/2019 GEN 68749 WHITE CONSTRUCTION Generators 107-344- 00 4,800.00 03/25/2019 GEN 68750* WILD FLOWER PROPER Cip- Commercial 401-916- 07 700.00 03/25/2019 GEN 68751 PAC WIEWECK OVERPAYMENTS 142-000- 00 101.29 03/25/2019 GEN 68752* ZEE SERVICE COMPANY Grounds - Materials 401-935- 08 296.08 03/26/2019 GEN 355(E) MISO Deferred Energy Cost - Miso 174-000- 00 26,548.72 Deferred Energy Cost - Miso 174-000- 00 917.66 HECK GEN 355(E) TOTAL 27,466.38 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee Fund: 1 ELECTRIC 04/02/2019 GEN 366(E) MISO CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description 04/02/2019 GEN 68756* BOB WENDORFF 04/02/2019 GEN 68757* BORDER STATES ELECTRIC SUPPLY 04/02/2019 GEN 68758 04/02/2019 GEN 68759 04/02/2019 GEN 68760 04/02/2019 GEN 68761 04/02/2019 GEN 68762 04/02/2019 GEN 68763 04/02/2019 GEN 68764 BRANDON TIRE CENTRICK TYME COLONIAL SUPPLEMENTAL INS CO CREEKSIDE SOILS DONAVON WEBER FAGEN, INC FASTENAL COMPANY Pag 8/30 Account Dept Amount Deferred Energy Cost - Miso 174-000- 00 21,328.26 Deferred Energy Cost - Miso 174-000- 00 862.66 HECK GEN 366(E) TOTAL 22,190.92 Cip - Residential 401-916- 07 400.00 250 MCM tape shield powe 107-344- 00 20,919.85 THHN-SS-250-ELK-37ST-CU- 107-344- 00 11,747.20 CONDUCTOR, 44/0 600V URD TRIPLEX 154-000- 00 2, 994.00 SPLIT BOLT 48 KS-15 Cu BURNDY 154-000- 00 16.74 SPLIT BOLT 250 R-250 KS29 BURNDY 154-000- 00 24.30 TRANS GROUND LUG GC 207 1/0 HUBBELL 154-000- 00 86.00 TAPE, BLUE, 3/4" x 66, 3M SCOTCH 154-000- 00 38.80 TAPE, RED, 3/4" x 66, 3M SCOTCH 35 154-000- 00 38.80 GREASE, LUBRICATING, SILICONE 154-000- 00 24.82 WIPES, CLEANING, GRIM -AWAY, DISPENSER, 154-000- 00 79.07 PADLOCK, TRANSFORMER, STERLING 4019 154-000- 00 14.70 Sales Tax Receivable - New 186-000- 00 206.59 Sales Tax Receivable - New 186-000- 00 0.95 Sales Tax Receivable - New 186-000- 00 14.63 Sales Tax Receivable - New 186-000- 00 1.01 Sales Tax Receivable - Replace 186-000- 00 1,437.34 Sales Tax Receivable - Replace 186-000- 00 810.40 HECK GEN 68757 TOTAL 38,455.20 Vehicles - Material 402-598- 02 851.78 Cip - Residential 401-916- 07 36.00 COLONIAL INSURANCE 242-000- 00 113.76 Materials 401-588- 02 37.40 Cip - Residential 401-916- 07 25.00 Generators 107-344- 00 353,031.04 Maintenance Other - Materials 402-554- 01 56.98 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES Pag 9/30 User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Amount Fund: 1 ELECTRIC 04/02/2019 GEN 68765 GREAT RIVER ENERGY PURCHASED POWER 401-555- 02 834.00 04/02/2019 GEN 68766* GUARDIAN DENTAL INSURANCE -COBRA 242-000- 00 318.27 DENTAL INSURANCE-80o ELEC 242-000- 00 3,825.49 HECK GEN 68766 TOTAL 4,143.76 04/02/2019 GEN 68767 HILLYARD/HUTCHINSON Supplies 401-550- 01 87.90 04/02/2019 GEN 68769* INNOVATIVE OFFICE SOLUTIONS OFFICE SUPPLIES 401-921- 08 40.24 04/02/2019 GEN 68770 JAKOB BARTON OVERPAYMENTS 142-000- 00 51.06 04/02/2019 GEN 68771* JANET ANDERSON Cip - Residential 401-916- 07 150.00 04/02/2019 GEN 68774 JEREMY HARRIS OR JENNA HARTELT OVERPAYMENTS 142-000- 00 201.66 04/02/2019 GEN 68775* LOREN BANNOW Cip - Residential 401-916- 07 400.00 04/02/2019 GEN 68776* M-K GRAPHICS OFFICE SUPPLIES 401-921- 08 381.46 04/02/2019 GEN 68777* MARCO TECHNOLOGIES, LLC Office Supplies 401-921- 08 350.04 04/02/2019 GEN 68778* MEDICA HEALTH INSURANCE 85% ELEC 242-000- 00 55,706.81 04/02/2019 GEN 68779 MICHAEL PAULSON Cip - Residential 401-916- 07 25.00 04/02/2019 GEN 68780 MIDWEST OVERHEAD CRANE J-boltW/hardware for 40 X W1258 107-344- 00 276.37 Sales Tax Receivable - Replace 186-000- 00 19.01 HECK GEN 68780 TOTAL 295.38 04/02/2019 GEN 68781* MN NCPERS LIFE INSURANCE-PERA LIFE 242-000- 00 48.00 04/02/2019 GEN 68783* POSTMASTER Postage 401-921- 08 225.00 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 10/30 Amount Fund: 1 ELECTRIC 04/02/2019 GEN 6878414 PRO AUTO & TRANSMISSION REPAIR Vehicles - Material 402-554- 01 50.52 VEHICLES - MATERIAL-ELEC 402-598- 02 1,353.70 HECK GEN 68784 TOTAL 1,404.22 04/02/2019 GEN 68785* RELIANCE STANDARD LIFE -LIFE LTD INSURANCE-80o ELEC 242-000- 00 1, 400.26 LIFE INSURANCE-80o ELEC 242-000- 00 711.62 HECK GEN 68785 TOTAL 2,111.88 04/02/2019 GEN 68787 RONALD WAMBEKE Cip - Residential 401-916- 07 25.00 04/02/2019 GEN 68788*4 RUNNING'S SUPPLY INC Sales Tax Receivable - Replace 186-000- 00 3.84 Sales Tax Receivable - Replace 186-000- 00 0.28 Sales Tax Receivable - Replace 186-000- 00 1.27 Generator 41 Material 402-554- 01 3.79 Generator 49 Material 402-554- 01 52.05 Accessory Plant - Materials 402-554- 01 17.22 Maintenance Other - Materials 402-554- 01 25.74 Line - Materials 401-581- 02 37.30 Vehicles - Material 402-598- 02 55.28 HECK GEN 68788 TOTAL 196.77 04/02/2019 GEN 68789 RYAN FINNELL Cip - Residential 401-916- 07 25.00 04/02/2019 GEN 68790 STANDARD PRINTING & MAILING Supplies 401-550- 01 19.72 04/02/2019 GEN 68792 TRACY ASCHE Cip - Residential 401-916- 07 25.00 04/02/2019 GEN 68793* UNITED PARCEL SERVICE MAIL SERVICES - UPS, FEDEX 401-921- 08 87.00 04/02/2019 GEN 68794* VERIZON WIRELESS TELEPHONE 401-921- 08 1,217.89 04/03/2019 GEN 361(E)* CITIZENS BANK Office Supplies 401-921- 08 70.10 04/03/2019 GEN 362(E)* TASC Prepaid HBA 174-000- 00 3,688.80 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee Fund: 1 ELECTRIC 04/09/2019 GEN 367(E) MISO 04/12/2019 GEN 363(E) MISO 04/12/2019 GEN 364(E) MISO CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description 04/12/2019 GEN 365(E) MISO 04/12/2019 GEN 68796 ABM EQUIPMENT & SUPPLY INC 04/12/2019 GEN 68797*4 ACE HARDWARE 04/12/2019 GEN 68798 ANNA HALLMAN OR LUCAS HALLMAN 04/12/2019 GEN 687994 AUTOMATIONDIRECT.COM INC Account Dept Deferred Energy Cost - Miso 174-000- 00 Deferred Energy Cost - Miso 174-000- 00 HECK GEN 367(E) TOTAL SCHEDULE 1 401-565- 03 SCHEDULE 2 401-565- 03 SCHEDULE 11 401-565- 03 HECK GEN 363(E) TOTAL Transmission Expense 401-565- 03 Transmission Expense 401-565- 03 HECK GEN 364(E) TOTAL Transmission Expense 401-565- 03 Vehicles - Material 402-598- 02 Sales Tax Receivable - Replace 186-000- 00 Sales Tax Receivable - Replace 186-000- 00 Supplies 401-550- 01 Maint Power Prod Plant - Build 402-554- 01 Generator 41 Material 402-554- 01 Generator 41 Material 402-554- 01 Materials 401-588- 02 Other Equipment - Materials 402-598- 02 HECK GEN 68797 TOTAL OVERPAYMENTS 142-000- 00 Sales Tax Receivable - Replace 186-000- 00 Temp -transmitter part 4XTH-N40140E-PT1 402-554- 01 Temp -sensor - part # RTD1-006-03 402-554- 01 Thermowell - part # TW06-04 402-554- 01 HECK GEN 68799 TOTAL Pag 11/30 Amount 19,918.35 3,894.03 10,435.82 13,852.78 4,636.65 61.13 0.88 0.34 8.54 2.57 12.77 4.99 32.05 25.68 13.97 70.00 78.00 203.47 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Fund: 1 ELECTRIC 04/12/2019 GEN 68800*4 BORDER STATES ELECTRIC SUPPLY 04/12/2019 GEN 68802* CARD SERVICES 04/12/2019 GEN 68803 CARLY'S SHOE STORE 04/12/2019 GEN 68806*4 CINTAS CORPORATION 4470 04/12/2019 GEN 68807*4 CITY OF HUTCHINSON 04/12/2019 GEN 68808 CREEKSIDE SOILS 04/12/2019 GEN 68810 DARLA LEVERCOM 04/12/2019 GEN 68811 DAVID MARTEL Account Dept Pag 12/30 Amount TAPE, SUPER 33+ PROFESSIONAL GRADE 154-000- 00 85.70 TAPE, WHITE, 3/4" x 66, 3M SCOTCH 154-000- 00 41.46 GREASE, LUBRICATING, SILICONE 154-000- 00 26.53 TAPE, GREEN, 3/4" x 663M SCOTCH 35 154-000- 00 12.44 TAPE, BROWN, 3/4" x 663M SCOTCH 35 154-000- 00 12.44 TAPE, ORANGE, 3/4" x 66, 3M SCOTCH 35 154-000- 00 12.44 TAPE, YELLOW, 3/4" x 66, 3M SCOTCH 35 154-000- 00 12.44 Line - Materials 401-581- 02 274.39 HECK GEN 68800 TOTAL 477.84 BREAKROOM/RECOGNITION BANQUET 401-926- 08 250.60 Uniforms & Laundry 401-588- 02 615.85 Uniforms & Laundry 401-550- 01 432.85 Uniforms & Laundry 401-550- 01 317.17 UNIFORMS & LAUNDRY 401-588- 02 217.11 UNIFORMS & LAUNDRY 401-588- 02 219.61 HECK GEN 68806 TOTAL 1,186.74 Accounts Payable To City Of Hu 234-000- 00 276,569.75 VEHICLE/EQUIPMENT FUEL -POWER 401-550- 01 144.73 VEHICLES/EQUIPMENT FUEL-ELEC 401-588- 02 1,136.05 Roadway Lighting 408-000- 02 18,423.00 IT ADMIN AND SUPPORT 75/25 401-921- 08 17,972.25 LEGAL SERVICES 75/25 401-923- 08 7,875.00 HUMAN RESOURCES SERVICES 75/25 401-923- 08 6,201.57 VEHICLES/EQUIPMENT FUEL-ADMIN 55/45 401-935- 08 135.06 HECK GEN 68807 TOTAL 328,457.41 Materials 401-588- 02 28.70 OVERPAYMENTS 142-000- 00 60.05 OVERPAYMENTS 142-000- 00 86.50 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Fund: 1 ELECTRIC 04/12/2019 GEN 68813 GARY KRSIEAN Cip - Residential 401-916- 07 04/12/2019 GEN 68814*4 GOPHER STATE ONE -CALL INC LINE - MATERIALS 401-581- 02 04/12/2019 GEN 68815 GRAINGER INC Tempco terminal block - part # 2LRU1 402-554- 01 04/12/2019 GEN 68817 HILLYARD/HUTCHINSON Supplies 401-550- 01 04/12/2019 GEN 68819* HUTCHFIELD SERVICES INC Grounds - Outside Services 401-935- 08 04/12/2019 GEN 68820 HUTCHINSON CO-OP Line - Materials 402-594- 02 Other Equipment - Materials 402-598- 02 HECK GEN 68820 TOTAL 04/12/2019 GEN 68821* HUTCHINSON LEADER Cip - Marketing 401-916- 07 04/12/2019 GEN 68822*4 HUTCHINSON WHOLESALE SUPPLY CO Maintenance Other - Materials 402-554- 01 Vehicles - Material 402-598- 02 Other Equipment - Materials 402-598- 02 HECK GEN 68822 TOTAL 04/12/2019 GEN 68823 JAMES MCKAY Cip - Residential 401-916- 07 04/12/2019 GEN 68824 JENNY THOSTENSON OVERPAYMENTS 142-000- 00 04/12/2019 GEN 68825* MAILFINANCE LEASE/SERVICE AGREEMENTS 401-921- 08 LEASE/SERVICE AGREEMENTS 401-921- 08 HECK GEN 68825 TOTAL 04/12/2019 GEN 688264 MATHESON TRI-GAS INC Sales Tax Receivable - Replace 186-000- 00 Generator 41 Material 402-554- 01 HECK GEN 68826 TOTAL Pag 13/30 Amount 25.00 14.18 45.00 108.44 1,112.73 6.95 230.12 237.07 1,313.00 5.33 80.15 85.12 170.60 25.00 172.14 304.96 8.29 04/12/2019 GEN 688274 MCC ENERGY SOLUTIONS, LLC I AM MANAGEMENT FEES 401-555- 02 3, 900.00 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Fund: 1 ELECTRIC IAM USAGE FEES 401-556- 03 HECK GEN 68827 TOTAL 04/12/2019 GEN 68829 MINNESOTA POLLUTION CONTROL AGENCY Regulatory Expenses 401-928- 08 Regulatory Expenses 401-928- 08 HECK GEN 68829 TOTAL 04/12/2019 GEN 68830 MINNESOTA POLLUTION CONTROL AGENCY Permits And Rent 401-550- 01 04/12/2019 GEN 68831*4 MN MUNICIPAL UTILITIES ASSOCIATION Training - Expense 401-580- 02 MISC SERVICES-QTR SAFETY/MGMT 750 401-923- 08 DUES/MEMBERSHIP EXPENSE-QTR ELEC DUES 401-930- 08 HECK GEN 68831 TOTAL 04/12/2019 GEN 68832 MOORHEAD MACHINERY AND BOILER CO. Unilux boiler weld repair -service call 402-554- 01 04/12/2019 GEN 68834 NORTHERN STATES SUPPLY INC Line - Materials 401-581- 02 04/12/2019 GEN 68835 NUCRANE MFG WESTINGHOUSE EL OVERPAYMENTS 142-000- 00 04/12/2019 GEN 68836* NUVERA 04/12/2019 GEN 68837 O'REILLY AUTOMOTIVE INC 04/12/2019 GEN 68838*4 OXYGEN SERVICE COMPANY INC TELEPHONE Accessory Plant - Materials WELDING ROD, 1/8", 6011, 50LBS GLOVES, MID WELDING, REV-BM88-2XL WIRE BUFFING WHEEL. 413131 Supplies Supplies Materials HECK GEN 68838 TOTAL 401-921- 08 402-554- 01 154-000- 00 154-000- 00 154-000- 00 401-550- 01 401-550- 01 402-574- 03 Pag 14/30 Amount 3,050.00 6,950.00 4,260.73 1,378.75 5,639.48 7,765.00 225.00 4,762.50 1,562.59 70.74 26,299.88 1,875.49 6.17 119.52 25.81 142.41 88.89 86.04 131.12 593.79 04/12/2019 401-921- 08 17.75 402-554- 01 156.07 142-000- 00 37.06 GEN 68839* PREMIUM WATERS INC OFFICE SUPPLIES -BOTTLED WATER 04/12/2019 GEN 68840 QUADE ELECTRIC Maintenance Other - Materials 04/12/2019 GEN 68841 SAMANTHA YOUNG OR ZACHARY PORRAS OVERPAYMENTS 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 15/30 Amount Fund: 1 ELECTRIC 04/12/2019 GEN 68842 SHELBY WILLIAMS OVERPAYMENTS 142-000- 00 33.79 04/12/2019 GEN 68843*4 STANDARD PRINTING & MAILING Supplies 401-550- 01 41.45 OFFICE SUPPLIES 401-921- 08 32.06 HECK GEN 68843 TOTAL 73.51 04/12/2019 GEN 68844 SUBSURFACE SOLUTIONS radiodetection RD7100 RX-PL-TX5 401-581- 02 5,738.71 Line - Materials 401-581- 02 268.57 CHECK GEN 68844 TOTAL 6,007.28 04/12/2019 GEN 68846* VIK'S LANDSCAPING & LAWN CARE, INC GROUNDS - OUTSIDE SERVICES 401-935- 08 309.38 04/12/2019 GEN 68847 WARTSILA OF NORTH AMERICA, INC SENSOR, PRESSURE, 0-10 BAR, PT700 154-000- 00 11,413. 90 TRANSMITTER, PRESSURE, MIS 3350, PT301 154-000- 00 723.53 TRANSMITTER, PRESSURE, MIS 3350, 154-000- 00 723.53 TRANSMITTER, PRESSURE, MIS 3350, 154-000- 00 671.78 VALVE, STARTING, COMPLETE, 123 001 154-000- 00 1,275.53 VALVE, PRECHAMBER CONTROL, 124 044 154-000- 00 1,252.53 VALVE, GAS PRECHAMBER, COMPLETE, 124 154-000- 00 2,724.53 SENSOR, SPEED, (ST 1965), ST 1965 154-000- 00 1,120.28 SENSOR, SPEED, (ST 1975), ST 1975 154-000- 00 988.03 SENSOR, SPEED, (GS 79), ST 197P 154-000- 00 988.03 TRANSMITTER, PRESSURE, LUBE OIL, IT 201 154-000- 00 671.78 SENSOR, PRESSURE, PT401 154-000- 00 723.53 SENSOR, TEMPERATURE, TE201 154-000- 00 370.48 SENSOR, TEMPERATURE, TE402 154-000- 00 370.48 SENSOR, TEMPERATURE, EXHAUST GAS 154-000- 00 178.43 CONVERTER, I/P, 8064C00-AA 154-000- 00 884.14 Sales Tax Receivable - Replace 186-000- 00 1,849.68 HECK GEN 68847 TOTAL 26,930.19 04/12/2019 GEN 68848*4 WEST CENTRAL SANITATION INC GENERATOR 41 WATER & SEWER 401-547- 01 88.74 Waste Disposal 401-550- 01 143.25 UTILITY EXPENSES - WATER/WASTE 55/45 401-930- 08 216.49 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee Fund: 1 ELECTRIC 04/16/2019 GEN 356(E)14 VISA CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Account Dept HECK GEN 68848 TOTAL GENERATORS-CLAMPS/DOOR 107-344- 00 Sales Tax Receivable - Replace 186-000- 00 Sales Tax Receivable - Replace 186-000- 00 MEETINGS & TRAVEL - EXPENSE (S 401-546- 01 SUPPLIES -SAFETY HARNESS -USE TX 28.60 401-550- 01 ACCESSORY PLANT - GARAGE DOOR OPENER 402-554- 01 ACCESSORY PLANT - MAT -GARAGE DOOR 402-554- 01 ACCESSORY PLANT - MAT -FLASH LIGHTS 402-554- 01 Maintenance Other - Materials 402-554- 01 MEETINGS & TRAVEL - EXP-PARKING 401-580- 02 LINE - MATERIALS -LIGHTS 401-581- 02 LINE - MATERIALS -BURN GEL 401-581- 02 MATERIALS -I PAD TRUCK MOUNTS 401-588- 02 VEHICLES - MAT-PINTLE HOOK 402-598- 02 TRAINING - EXPENSE-APPA TRAINING 401-930- 08 Grounds - Materials 401-935- 08 Grounds - Materials 401-935- 08 GROUNDS - CABINET 401-935- 08 HECK GEN 356(E) TOTAL 04/16/2019 GEN 368(E) MISO Deferred Energy Cost - Miso Deferred Energy Cost - Miso HECK GEN 368(E) TOTAL 04/18/2019 GEN 68852 AHSLEY HOMESTORE Cip- Commercial 04/18/2019 GEN 68853 AMERICAN PUBLIC POWER ASSOCIATION It Admin And Support 04/18/2019 GEN 68854*4 BORDER STATES ELECTRIC SUPPLY BULB, TRAFFIC, 130VOLT, 116W SAFETY VEST, RVZ2410SEX2 Line - Materials HECK GEN 68854 TOTAL 04/18/2019 GEN 68855 BRANDON TIRE Vehicles - Material 174-000- 00 174-000- 00 401-916- 07 401-921- 08 154-000- 00 401-550- 01 401-581- 02 402-598- 02 Pag 16/30 Amount 448.48 2,961.68 3.90 2.95 436.26 416.00 39.95 52.89 259.25 64.41 8.00 163.24 39.50 54.72 131.69 109.00 6.36 25.68 32.85 4,808.33 16,636.89 861.86 17,498.75 195.00 680.40 12.64 9.51 851.78 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Fund: 1 ELECTRIC 04/18/2019 GEN 68856* BROTHERS FIRE PROTECTION 04/18/2019 GEN 68858*4 CINTAS CORPORATION 4470 04/18/2019 GEN 68859*4 CITY OF HUTCHINSON 04/18/2019 GEN 68860 CREEKSIDE SOILS 04/18/2019 GEN 68861 DELMAR COMPANY 04/18/2019 GEN 68862 FACTORY DIRECT 04/18/2019 GEN 688634 FASTENAL COMPANY 04/18/2019 GEN 68864 FERGUSON ENTERPRISES 4525 04/18/2019 GEN 68865* FIRST CHOICE FOOD & BEVERAGE 04/18/2019 GEN 68868 HDR ENGINEERING INC Account Dept Pag 17/30 Amount GROUNDS - OUTSIDE SERVICES 401-935- 08 715.00 Uniforms & Laundry 401-550- 01 319.67 Uniforms & Laundry 401-550- 01 314.16 UNIFORMS & LAUNDRY 401-588- 02 217.11 UNIFORMS & LAUNDRY 401-588- 02 217.11 HECK GEN 68858 TOTAL 1,068.05 Line - Materials 401-581- 02 8.38 IT ADMIN AND SUPPORT 750 401-921- 08 3,141.80 HECK GEN 68859 TOTAL 3,150.18 Materials 401-588- 02 19.00 Hi -temp gaskets- DIN 1300 order # 39428 107-344- 00 1,893.20 Hi -temp gaskets-DIN1400 order # 39428 107-344- 00 831.92 Sales Tax Receivable - Replace 186-000- 00 200.98 HECK GEN 68861 TOTAL 2,926.10 Cip- Commercial 401-916- 07 495.00 Sales Tax Receivable - Replace 186-000- 00 1.27 Supplies 401-550- 01 34.93 Generator 45 Material 402-554- 01 18.50 HECK GEN 68863 TOTAL 54.70 10"-1504 FLANGE -PART # DRFSOFIO& 402-554- 01 92.17 10"-1504 FLANGE -PART # DRFSOFIO& 402-554- 01 200.47 HECK GEN 68864 TOTAL 292.64 BREAKROOM/RECOGNITION BANQUET 401-926- 08 114.00 Generators 107-344- 00 3,497.31 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 18/30 Amount Fund: 1 ELECTRIC 04/18/2019 GEN 68869*4 HILLYARD/HUTCHINSON Supplies 401-550- 01 48.39 Supplies 401-550- 01 204.01 Grounds - Materials 401-935- 08 47.86 Grounds - Materials 401-935- 08 47.86 HECK GEN 68869 TOTAL 348.12 04/18/2019 GEN 68870 HINTZMAN ENVIRONMENTAL SERVICES Generator 41 Outside Services 402-554- 01 600.00 04/18/2019 GEN 68871* INNOVATIVE OFFICE SOLUTIONS OFFICE SUPPLIES 401-921- 08 24.77 04/18/2019 GEN 68872 JACK DRAPER Cip - Residential 401-916- 07 25.00 04/18/2019 GEN 68873 JACOB RUBY OVERPAYMENTS 142-000- 00 135.55 04/18/2019 GEN 68874 JANICE BLAYLOCK OVERPAYMENTS 142-000- 00 100.00 04/18/2019 GEN 68875 JON GOSSE Cip - Residential 401-916- 07 25.00 04/18/2019 GEN 68876 KIMBERLY LIGHTING LLC Cip- Commercial 401-916- 07 7,380.45 04/18/2019 GEN 68878 LOCATORS & SUPPLIES INC PAINT, LOCATING, INVERTED SURVEY 154-000- 00 537.84 Sales Tax Receivable - New 186-000- 00 37.03 HECK GEN 68878 TOTAL 574.87 04/18/2019 GEN 68881 MIDWAY FORD COMMERCIAL Ford F550 Chassis 107-392- 00 53,405.27 04/18/2019 GEN 68882 MIDWAY INC DBA-SUBWAY Cip- Commercial 401-916- 07 369.36 04/18/2019 GEN 68883* OLD REPUBLIC SURETY GROUP PROPERTY INSURANCE 401-924- 08 55.00 04/18/2019 GEN 68884 POWERGENICS BOARD, POWER DISTRIBUTION, SIMPLEX 154-000- 00 2, 540.00 Sales Tax Receivable - Replace 186-000- 00 171.53 HECK GEN 68884 TOTAL 2,711.53 04/18/2019 GEN 68885 PSI ENGINEERING LLC FILTER BAG, 50 MICRO, TOWER BY-PASS, 6" 154-000- 00 262.00 FILTER BAG, 50 MICRO, TOWER BY-PASS, 6" 154-000- 00 42.18 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee Fund: 1 ELECTRIC CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Account Dept HECK GEN 68885 TOTAL 04/18/2019 GEN 68886* SHRED RIGHT OFFICE SUPPLIES -SHREDDING SERVICES 401-921- 08 04/18/2019 GEN 68888 STERLING SYSTEMS INC. Asbestos panel abatement -cooling tower 107-343- 00 04/18/2019 GEN 68892 TRAFFIC CONTROL CORPORATION SIGNAL, LUMINATION ZEDS, RED TINTED 154-000- 00 04/18/2019 GEN 68894* VIK'S LANDSCAPING & LAWN CARE, INC GROUNDS - OUTSIDE SERVICES 401-935- 08 04/18/2019 GEN 68895 WHITE CONSTRUCTION PRIME MOVERS/RENEWABLES 107-343- 00 Generators 107-344- 00 HECK GEN 68895 TOTAL 04/19/2019 GEN 359(E) MRES Purchased Power 401-555- 02 04/19/2019 GEN 360(E)* POINT & PAY Collection - Materials 401-903- 06 Total for fund 1 ELECTRIC Pag 19/30 Amount 304.18 12.48 22,450.00 68.40 491.04 1,800.00 2,000.00 3,800.00 903,466.70 2,427.99 2,412,246.37 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES Pag 20/30 User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Amount Fund: 2 GAS 03/25/2019 GEN 345(E)*4 BP CANANDA ENERGY SOLUTIONS GAS FOR RETAIL 401-807- 04 1,386.60 GAS FOR RETAIL 401-807- 04 499,115.18 3M 401-807- 04 273,077.80 HTI 401-807- 04 27,793.78 UNG 401-807- 04 719.42 BROWNTON 401-807- 04 17,745.99 Utility Expenses - Water/Waste 401-930- 08 3,993.09 HECK GEN 345(E) TOTAL 823,831.86 03/25/2019 GEN 357(E)* TASC HEALTH INSURANCE-HRA FEES 401-926- 08 226.48 03/25/2019 GEN 68666*4 ACE HARDWARE Materials 401-874- 04 7.04 Materials 401-874- 04 9.81 Vehicles - Material 402-895- 04 19.54 Grounds - Materials 401-935- 08 242.23 HECK GEN 68666 TOTAL 278.62 03/25/2019 GEN 68667* ALA AVIATION LLC DEP REFUND/APPLIED 235-000- 00 19.25 03/25/2019 GEN 68668* ALEXANDER LAMP OR SARAH BENSON DEP REFUND/APPLIED 235-000- 00 87.50 03/25/2019 GEN 68672* BEN KING OR KELLY VANDERSTOEP DEP REFUND/APPLIED 235-000- 00 75.25 03/25/2019 GEN 68673* BORDER STATES ELECTRIC SUPPLY 1X2-1/2 ELK STL SMLS NIL XH DOM 107-380- 00 108.72 1X2-1/2 ELK STL SMLS NIL XH DOM 107-380- 00 0.03 VALVE, METER, 3/4", INS, LOCKWING, PLG 154-000- 00 5,280.60 VALVE, METER, 3/4", INS, LOCKWING, PLG 154-000- 00 0.09 ELL, WELD FITTING, 90 DEG, 4", SMLS, 154-000- 00 117.84 THREAD-0-LET, 1/4" X 2 1/2" X 1 1/4", 154-000- 00 49.92 THREAD-0-LET, 1/2" X 8" X 3", CLASS 154-000- 00 19.41 HECK GEN 68673 TOTAL 5,576.61 03/25/2019 GEN 68675* BRIAN DRESSEL OR MONA DRESSEL DEP REFUND/APPLIED 235-000- 00 38.50 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES Pag 21/30 User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Amount Fund: 2 GAS 03/25/2019 GEN 68676 BROWN COUNTY RURAL ELECTRIC Utilities (Electric, Satellite 401-856- 05 142.33 03/25/2019 GEN 68678* CAMELIA YUNGK DEP REFUND/APPLIED 235-000- 00 26.25 03/25/2019 GEN 68679* CATHERINE STRAVINO BARNA DEP REFUND/APPLIED 235-000- 00 17.50 03/25/2019 GEN 68681*4 CINTAS CORPORATION 4470 UNIFORMS & LAUNDRY 401-880- 04 143.17 UNIFORMS & LAUNDRY 401-880- 04 187.52 HECK GEN 68681 TOTAL 330.69 03/25/2019 GEN 68682*4 CITY OF HUTCHINSON IT ADMIN AND SUPPORT 250 401-921- 08 5,564.35 Utility Expenses - Water/Waste 401-930- 08 44.63 Utility Expenses - Water/Waste 401-930- 08 322.69 Utility Expenses - Water/Waste 401-930- 08 6.91 HECK GEN 68682 TOTAL 5,938.58 03/25/2019 GEN 68684* CYNTHIA WATELAND DEP REFUND/APPLIED 235-000- 00 87.50 03/25/2019 GEN 68686* DON HANSEN Cip - Residential 401-916- 07 400.00 03/25/2019 GEN 68689* FIRST CHOICE FOOD & BEVERAGE BREAKROOM/RECOGNITION BANQUET 401-926- 08 70.50 03/25/2019 GEN 68691 GROEBNER & ASSOCIATES INC GASKET, LINEBACKER, TYPE "E", FLAT 154-000- 00 112.13 03/25/2019 GEN 68694*4 HUTCHINSON CO-OP Vehicles - Material 402-895- 04 868.84 03/25/2019 GEN 68695* JAMES OR MELISSA VAN DE too DEP REFUND/APPLIED 235-000- 00 63.00 03/25/2019 GEN 68696* JAMES OR MELISSA VAN DE too DEP REFUND/APPLIED 235-000- 00 5.25 03/25/2019 GEN 68697* JAMES OR MELISSA VAN DE too DEP REFUND/APPLIED 235-000- 00 26.25 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 22/30 Amount Fund: 2 GAS 03/25/2019 GEN 68698* JASON MAYER Cip - Residential 401-916- 07 400.00 03/25/2019 GEN 68699* JAYSHERI MUELLER OR J MARTICHUSKI GET REFUND/APPLIED 235-000- 00 122.50 03/25/2019 GEN 68700* JENNIFER BASSLER GET REFUND/APPLIED 235-000- 00 105.00 03/25/2019 GEN 68702* JOAN KRUEGER GET REFUND/APPLIED 235-000- 00 122.50 03/25/2019 GEN 68704* JON MROSS GET REFUND/APPLIED 235-000- 00 38.50 03/25/2019 GEN 68705* JON WHEELER OR DAWN WHEELER GET REFUND/APPLIED 235-000- 00 70.00 03/25/2019 GEN 68706* JONNY WALLA JR GET REFUND/APPLIED 235-000- 00 14.00 03/25/2019 GEN 68707* JOSEPH GOSKESEN GET REFUND/APPLIED 235-000- 00 56.00 03/25/2019 GEN 68708* JOSHUA KAMRATH OR LEAH KAMRATH GET REFUND/APPLIED 235-000- 00 70.00 03/25/2019 GEN 68709* JOSHUA KAMRATH OR LEAH KAMRATH GET REFUND/APPLIED 235-000- 00 52.50 03/25/2019 GEN 68712* KYKESHIA SAVICH OR ZACH ALLEN GET REFUND/APPLIED 235-000- 00 43.75 03/25/2019 GEN 68713* LAURA WEIKLE GET REFUND/APPLIED 235-000- 00 49.00 03/25/2019 GEN 687174 MCLEOD COOPERATVIE POWER ASSN MISC EXPENSE -GAS LINE PUMP 401-880- 04 73.80 UTILITIES (ELECTRIC, SATELLITE-MCLEOD 401-856- 05 38.48 UTILITIES (ELECTRIC, SATELLITE -PIPELINE 401-856- 05 39.42 HECK GEN 68717 TOTAL 151.70 03/25/2019 GEN 68720* MICHELLE HEINING Cip - Residential 401-916- 07 400.00 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 23/30 Amount Fund: 2 GAS 03/25/2019 GEN 68722* MN NCPERS LIFE INSURANCE-PERA LIFE 242-000- 00 16.00 03/25/2019 GEN 68723* NOLAN COOK DEP REFUND/APPLIED 235-000- 00 122.50 03/25/2019 GEN 68725* PIZZA RANCH DEP REFUND/APPLIED 235-000- 00 1,225.00 03/25/2019 GEN 68726* PLUMBING & HEATING BY CRAIG DEP REFUND/APPLIED 235-000- 00 87.50 03/25/2019 GEN 68728* PREMIER INVESTMENTS DEP REFUND/APPLIED 235-000- 00 210.00 03/25/2019 GEN 68729* PREMIUM WATERS INC OFFICE SUPPLIES -BOTTLED WATER 401-921- 08 5.92 03/25/2019 GEN 68730*4 PRO AUTO & TRANSMISSION REPAIR VEHICLES - MATERIAL -GAS 402-895- 04 888.18 VEHICLES - MATERIAL-ADMIN 55/45 401-935- 08 143.48 HECK GEN 68730 TOTAL 1,031.66 03/25/2019 GEN 68734* RHONDA KRAMER OR MIKE KRAMER DEP REFUND/APPLIED 235-000- 00 70.00 03/25/2019 GEN 68735* RIVER OAKS AT SHADY RIDGE DEP REFUND/APPLIED 235-000- 00 1,277.50 03/25/2019 GEN 68736 RYAN ELLENSON Public Awareness - Material 401-856- 05 314.27 03/25/2019 GEN 68737* SHERRY FOSSUM DEP REFUND/APPLIED 235-000- 00 17.50 03/25/2019 GEN 68738* SHRED RIGHT OFFICE SUPPLIES -SHREDDING SERVICES 401-921- 08 4.16 03/25/2019 GEN 68739* SOUTHPOINT FINANCIAL CREDIT UNION DEP REFUND/APPLIED 235-000- 00 1,050.00 03/25/2019 GEN 68740 SPRINT Utilities (Electric, Satellite 401-856- 05 141.73 03/25/2019 GEN 68742* STEVEN JACKSON DEP REFUND/APPLIED 235-000- 00 35.00 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Fund: 2 GAS 03/25/2019 GEN 68743* THOMAS COLEMAN OR PAIGE LARK DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68744* UIS/SOURCECORP COLLECTION - MATERIALS 401-903- 06 COLLECTION - MATERIALS 401-903- 06 COLLECTION - MATERIALS 401-903- 06 HECK GEN 68744 TOTAL 03/25/2019 GEN 68745 VERIZON WIRELESS UTILITIES (ELECTRIC, SATELLITE-SCADA 401-856- 05 03/25/2019 GEN 68746* WESLEY SOMMERFELD OR TERI WALKER DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68747* WESLEY SOMMERFELD OR TERI WALKER DEP REFUND/APPLIED 235-000- 00 03/25/2019 GEN 68748*4 WEST CENTRAL SANITATION INC UTILITY EXPENSES - WATER/WASTE 45/55 401-930- 08 03/25/2019 GEN 68750* WILD FLOWER PROPER Cip- Commercial 401-916- 07 03/25/2019 GEN 68752* ZEE SERVICE COMPANY Grounds - Materials 401-935- 08 04/02/2019 GEN 68755 B & C PLUMBING AND HEATING Materials 401-874- 04 04/02/2019 GEN 68756* BOB WENDORFF Cip - Residential 401-916- 07 04/02/2019 GEN 68757* BORDER STATES ELECTRIC SUPPLY 1X2-1/2 ELK STL SMLS NIL XH DOM 107-380- 00 1X2-1/2 ELK STL SMLS NIL XH DOM 107-380- 00 FLANGE, WELD NECK, FLAT FACED , 150 154-000- 00 FLANGE, WELD NECK, FLAT FACED , 150 154-000- 00 VALVE, NEEDLE, 1/4", O-RING STYLE, 154-000- 00 REDUCER, CONY, WELD FITTING, 4" X 2", 154-000- 00 NIPPLE, 1/4" X 2", BM, STD, SMLS, TEE 154-000- 00 HECK GEN 68757 TOTAL Pag 24/30 Amount 56.00 332.69 10.28 1,198.20 1,541.17 117.06 14.00 17.50 176.61 800.00 242.25 167.16 400.00 117.78 0.04 155.60 137.53 428.80 175.77 04/02/2019 GEN 68766* GUARDIAN DENTAL INSURANCE-20o GAS 242-000- 00 956.37 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 25/30 Amount Fund: 2 GAS 04/02/2019 GEN 68768 HUTCHINSON WHOLESALE SUPPLY CO Vehicles - Material 402-895- 04 62.38 04/02/2019 GEN 68769* INNOVATIVE OFFICE SOLUTIONS OFFICE SUPPLIES 401-921- 08 13.41 04/02/2019 GEN 68771* JANET ANDERSON Cip - Residential 401-916- 07 400.00 04/02/2019 GEN 68772 JANINE GEHLEN Cip - Residential 401-916- 07 300.00 04/02/2019 GEN 68773 JEFF FRASER Cip - Residential 401-916- 07 325.00 04/02/2019 GEN 68775* LOREN RANNOW Cip - Residential 401-916- 07 400.00 04/02/2019 GEN 68776* M-K GRAPHICS OFFICE SUPPLIES 401-921- 08 127.16 04/02/2019 GEN 68777* MARCO TECHNOLOGIES, LLC OFFICE SUPPLIES 401-921- 08 116.68 04/02/2019 GEN 68778* MEDICA HEALTH INSURANCE 15% GAS 242-000- 00 9,830.61 04/02/2019 GEN 68781* MN NCPERS LIFE INSURANCE-PERA LIFE 242-000- 00 16.00 04/02/2019 GEN 68782 OXYGEN SERVICE COMPANY INC Materials 401-874- 04 15.55 Other Equipment - Materials 402-895- 04 232.24 HECK GEN 68782 TOTAL 247.79 04/02/2019 GEN 68783* POSTMASTER Postage 401-921- 08 75.00 04/02/2019 GEN 68784*4 PRO AUTO & TRANSMISSION REPAIR VEHICLES - MATERIAL -GAS 402-895- 04 257.76 04/02/2019 GEN 68785* RELIANCE STANDARD LIFE -LIFE LTD INSURANCE-20o GAS 242-000- 00 350.06 LIFE INSURANCE-20o GAS 242-000- 00 177.90 HECK GEN 68785 TOTAL 527.96 04/02/2019 GEN 68786 RICHARD PAUL Cip - Residential 401-916- 07 325.00 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Fund: 2 GAS 04/02/2019 GEN 68788*4 RUNNING'S SUPPLY INC 04/02/2019 GEN 68791 STEVEN PRICE 04/02/2019 GEN 68793* UNITED PARCEL SERVICE 04/02/2019 GEN 68794* VERIZON WIRELESS 04/02/2019 GEN 68795 WEBSTER, JOHN C 04/03/2019 GEN 361(E)* CITIZENS BANK 04/03/2019 GEN 362(E)* TASC 04/12/2019 GEN 68797*4 ACE HARDWARE 04/12/2019 GEN 68800*4 BORDER STATES ELECTRIC SUPPLY 04/12/2019 GEN 68801 BROWN COUNTY RURAL ELECTRIC 04/12/2019 GEN 68802* CARD SERVICES 04/12/2019 GEN 68804 CENTRAL HYDRAULICS 04/12/2019 GEN 68805 CENTURYLINK 04/12/2019 GEN 68806*4 CINTAS CORPORATION 4470 Account Dept Pag 26/30 Amount Materials 401-874- 04 9.08 Power Equipment - Materials 402-895- 04 10.76 Other Equipment - Materials 402-895- 04 80.52 HECK GEN 68788 TOTAL 100.36 Cip - Residential 401-916- 07 300.00 MAIL SERVICES - UPS, FEDEX 401-921- 08 29. 00 TELEPHONE 401-921- 08 405.96 Meetings & Travel - Expense (S 401-870- 04 475.76 Office Supplies 401-921- 08 70.10 Prepaid HRA 174-000- 00 922.20 Materials 401-874- 04 51.27 Vehicles - Material 402-895- 04 20.28 Other Equipment - Materials 402-895- 04 10.87 HECK GEN 68797 TOTAL 82.42 TEE, TAPPING, 2" X 3/4" IPS, SIR 11, 154-000- 00 180.21 Utilities (Electric, Satellite 401-856- 05 141.16 BREAKROOM/RECOGNITION BANQUET 401-926- 08 83.53 Materials 401-874- 04 9.28 Utilities (Electric, Satellite 401-856- 05 56.09 UNIFORMS & LAUNDRY 401-880- 04 188.33 UNIFORMS & LAUNDRY 401-880- 04 143.17 04/19/2019 08:16 AM CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES User: JMartig CHECK DATE FROM 03/22/2019 - 04/19/2019 DE: Hutchinson Utili Check Date Bank Check # Payee Description Account Dept Fund: 2 GAS HECK GEN 68806 TOTAL 04/12/2019 GEN 6880714 CITY OF HUTCHINSON Accounts Payable To City Of Hu 234-000- 00 VEHICLE/EQUIPMENT FUEL -GAS 401-880- 04 IT ADMIN AND SUPPORT 75/25 401-921- 08 LEGAL SERVICES 75/25 401-923- 08 HUMAN RESOURCES SERVICES 75/25 401-923- 08 VEHICLES/EQUIPMENT FUEL-ADMIN 55/45 401-935- 08 HECK GEN 68807 TOTAL 04/12/2019 GEN 68809 CURT GANDER Cip - Residential 401-916- 07 04/12/2019 GEN 68812 DOT/PHMSA Regulatory Expenses 401-928- 08 04/12/2019 GEN 68814*4 GOPHER STATE ONE -CALL INC MATERIALS 401-874- 04 MATERIALS 401-856- 05 HECK GEN 68814 TOTAL 04/12/2019 GEN 68816 GROEBNER & ASSOCIATES INC GAS, CALIBRATION, 2.5% BY VOL.(50oLEL) 154-000- 00 04/12/2019 GEN 68818 HUGHES NETWORK SYSTEMS UTILITIES -NEW ULM COMMUNICATIONS 401-856- 05 04/12/2019 GEN 68819* HUTCHFIELD SERVICES INC Grounds - Outside Services 401-935- 08 04/12/2019 GEN 68821* HUTCHINSON LEADER CIP - MARKETING 401-916- 07 04/12/2019 GEN 68822*4 HUTCHINSON WHOLESALE SUPPLY CO Vehicles - Material 402-895- 04 04/12/2019 GEN 68825* MAILFINANCE LEASE/SERVICE AGREEMENTS 401-921- 08 LEASE/SERVICE AGREEMENTS 401-921- 08 HECK GEN 68825 TOTAL 04/12/2019 GEN 68828 MICRO MOTION 5700C12ABAAllZZAAllMV, MICRO MOTION 107-369- 00 5700C12ABAAllZZAAllMV, MICRO MOTION 107-369- 00 5700C12ABAAllZZAAllMV, MICRO MOTION 107-369- 00 Pag 27/30 Amount 331.50 123,786.25 925.77 5,990.75 2,625.00 2,067.IS 110.49 135,505.44 25.00 31,840.41 14.17 148.91 106.94 910.41 437.66 92.66 101.66 5,459.11 5,459.11 5,459.11 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Pag Dept 28/30 Amount Fund: 2 GAS 5700C12ABAAllZZAAllMV, MICRO MOTION 107-369- 00 5,459.11 5700R12ABAAllZZAAllMV, MICRO MOTION 107-369- 00 4,402.13 HECK GEN 68828 TOTAL 26,238.57 04/12/2019 GEN 6883114 MN MUNICIPAL UTILITIES ASSOCIATION MISC SERVICES-QTR SAFETY/MGMT 250 401-923- 08 1,587.50 04/12/2019 GEN 68833 NORTHERN BORDER PIPELINE CO LINE - OUTSIDE SERVICES -INTERCONNECT 401-856- 05 2,000.00 04/12/2019 GEN 68836* NUVERA TELEPHONE 401-921- 08 625.16 04/12/2019 GEN 68838*4 OXYGEN SERVICE COMPANY INC Materials 401-874- 04 88.88 Materials 401-874- 04 86.04 HECK GEN 68838 TOTAL 174.92 04/12/2019 GEN 68839* PREMIUM WATERS INC OFFICE SUPPLIES -BOTTLED WATER 401-921- 08 5.92 04/12/2019 GEN 68843*4 STANDARD PRINTING & MAILING OFFICE SUPPLIES 401-921- 08 10.69 04/12/2019 GEN 68845 TWIN CITIES & WESTERN RAILROAD RAILROAD LICENSES 401-856- 05 2,752.76 04/12/2019 GEN 68846* VIK'S LANDSCAPING & LAWN CARE, INC GROUNDS - OUTSIDE SERVICES 401-935- 08 253.12 04/12/2019 GEN 68848*4 WEST CENTRAL SANITATION INC UTILITY EXPENSES - WATER/WASTE 45/55 401-930- 08 177.12 04/16/2019 GEN 356(E)*4 VISA TRAINING - EXPENSE -PIPELINE SAFETY MTG 401-870- 04 1,517.48 MEETINGS & TRAVEL - EXP-PARKING 401-870- 04 193.55 MATERIAL -HARD HAT 401-874- 04 63.90 MATERIALS -BURN GEL 401-874- 04 39. 50 MATERIALS-WINDOT GAS REGS-USE TX 73.5 401-874- 04 1, 069. 00 VEHICLES - MAT-PINTLE HOOK 402-895- 04 131.70 LINE - OUTSIDE AM INNOVATIONS REMOTE 401-856- 05 88.00 GROUNDS - CABINET 401-935- 08 32.85 HECK GEN 356(E) TOTAL 3,135.98 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # Payee CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Description Fund: 2 GAS 04/18/2019 GEN 68854*4 BORDER STATES ELECTRIC SUPPLY 04/18/2019 GEN 68856* BROTHERS FIRE PROTECTION 04/18/2019 GEN 68857 BRYCE RUSCH 04/18/2019 GEN 68858*4 CINTAS CORPORATION 4470 04/18/2019 GEN 68859*4 CITY OF HUTCHINSON 04/18/2019 GEN 68865* FIRST CHOICE FOOD & BEVERAGE 04/18/2019 GEN 68866 GERALD KACZMAREK 04/18/2019 GEN 68867 GROEBNER & ASSOCIATES INC 04/18/2019 GEN 68869*4 HILLYARD/HUTCHINSON 04/18/2019 GEN 68871* INNOVATIVE OFFICE SOLUTIONS 04/18/2019 GEN 68877 LEE TEICHERT 04/18/2019 GEN 688794 MCLEOD COOPERATVIE POWER ASSN Account Dept Pag 29/30 Amount TEE, WELD FITTING, STRAIGHT, 2", SMLS, 154-000- 00 56.45 GROUNDS - OUTSIDE SERVICES 401-935- 08 585.00 Training - Expense 401-870- 04 168.20 UNIFORMS & LAUNDRY 401-880- 04 141.78 UNIFORMS & LAUNDRY 401-880- 04 213.36 HECK GEN 68858 TOTAL 355.14 IT ADMIN AND SUPPORT 250 401-921- 08 1,047.26 IT ADMIN AND SUPPORT-IPAD GAS DEPT 401-921- 08 601.29 HECK GEN 68859 TOTAL 1,648.55 BREAKROOM/RECOGNITION BANQUET 401-926- 08 38.00 Cip - Residential 401-916- 07 325.00 Sensus AMi Module 700GM 107-381- 00 2,832.87 Sensus Smart Gateway for Pressure, 107-387- 00 2,365.43 HECK GEN 68867 TOTAL 5,198.30 Grounds - Materials 401-935- 08 39.15 Grounds - Materials 401-935- 08 39.15 HECK GEN 68869 TOTAL 78.30 OFFICE SUPPLIES 401-921- 08 8.25 Cip - Residential 401-916- 07 300.00 MISC EXPENSE -GAS LINE PUMP 401-880- 04 69.58 UTILITIES (ELECTRIC, SATELLITE-MCLEOD 401-856- 05 38.48 UTILITIES (ELECTRIC, SATELLITE -PIPELINE 401-856- 05 39.49 04/19/2019 08:16 AM User: JMartig DE: Hutchinson Utili Check Date Bank Check # CHECK DISBURSEMENT REPORT FOR HUTCHINSON UTILITIES CHECK DATE FROM 03/22/2019 - 04/19/2019 Payee Description Account Dept Pag 30/30 Amount Fund: 2 GAS HECK GEN 68879 TOTAL 147.55 04/18/2019 GEN 68880 MICRO MOTION Cable, 9 wire, Teflon, 100ft. 107-369- 00 614.60 Cable, 9 wire, Teflon, 100ft. 107-369- 00 6.48 HECK GEN 68880 TOTAL 621.08 04/18/2019 GEN 68883* OLD REPUBLIC SURETY GROUP PROPERTY INSURANCE 401-924- 08 45.00 04/18/2019 GEN 68886* SHRED RIGHT OFFICE SUPPLIES -SHREDDING SERVICES 401-921- 08 4.16 04/18/2019 GEN 68887 SPRINT Utilities (Electric, Satellite 401-856- 05 141.52 04/18/2019 GEN 68889 STEVE RICK Cip - Residential 401-916- 07 25.00 04/18/2019 GEN 68890 SWAGELOK MINNESOTA TUBING, 1/2" X .049" WALL, 316 SS, 154-000- 00 603.60 TUBING, 1/2" X .049" WALL, 316 SS, 154-000- 00 349.40 HECK GEN 68890 TOTAL 953.00 04/18/2019 GEN 68891 TIM WEBER Training - Expense 401-870- 04 176.32 04/18/2019 GEN 68893 VERIZON WIRELESS UTILITIES (ELECTRIC, SATELLITE-SCADA 401-856- 05 117.12 04/18/2019 GEN 68894* VIK'S LANDSCAPING & LAWN CARE, INC GROUNDS - OUTSIDE SERVICES 401-935- 08 401.76 04/19/2019 GEN 358(E) DEPARTMENT OF EMPLOYMENT & WORKERS COMPENSATION 401-870- 04 410.80 04/19/2019 GEN 360(E)* POINT & PAY METER READING - MATERIALS 401-903- 06 1, 986.54 Total for fund 2 GAS 1,087,431.15 TOTAL - ALL FUNDS 3,499,677.52 '*'-INDICATES CHECK DISTRIBUTED TO MORE THAN ONE FUND '#'-INDICATES CHECK DISTRIBUTED TO MORE THAN ONE DEPARTMENT HUTCHINSON UTILITIES COMMISSION MANAGEMENT LETTER DECEMBER 31, 2018 CONWAY, DEUTH & SCHMIESING, PLLP CPAS & ADVISORS LITCHFIELD, MINNESOTA This page intentionally left blank HUTCHINSON UTILITIES COMMISSION TABLE OF CONTENTS DECEMBER 31, 2018 9TTL40 Required Communications 1-3 Comparative Financial Data 4 Graphical Information 5-12 Schedule of Findings on Accounting Issues and Internal Controls 13-14 This page intentionally left blank REQUIRED COMMUNICATIONS Members of the Hutchinson Utilities Commission Hutchinson, Minnesota We have audited the financial statements of Hutchinson Utilities Commission, a fund of the City of Hutchinson, Minnesota, as of and for the year ended December 31, 2018. Professional standards require that we provide you with information about our responsibilities under generally accepted auditing standards and Government Auditing Standards, as well as certain information related to the planned scope and timing of our audit. We have communicated such information in our letter to you dated January 22, 2019. Professional standards also require that we communicate to you the following information related to our audit. Significant Audit Findings Qualitative Aspects of Accounting Practices Management is responsible for the selection and use of appropriate accounting policies. The significant accounting policies used by the City are described in Note 1 to the financial statements. The City implemented Governmental Accounting Standards Board Statement No. 75, Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions. Adoption of the provisions of this statement results in additional note disclosures related to postemployment benefits other than pensions shown in Note 10. We noted no transactions entered into by the City during the year for which there is a lack of authoritative guidance or consensus. All significant transactions have been recognized in the financial statements in the proper period. Accounting estimates are an integral part of the financial statements prepared by management and are based on management's knowledge and experience about past and current events and assumptions about future events. Certain accounting estimates are particularly sensitive because of their significance to the financial statements and because of the possibility that future events affecting them may differ significantly from those expected. The most sensitive estimates affecting the financial statements were: Management's estimate of the allowance for doubtful accounts is based on historical electric and natural gas revenues, historical loss levels, and an analysis of the collectability of individual accounts. We evaluated the key factors and assumptions used to develop the allowance in determining that it is reasonable in relation to the financial statements taken as a whole. Management's estimate of depreciation is based on the number of years an asset is in service. We evaluated the key factors and assumptions used to develop the depreciation estimate in determining that it is reasonable in relation to the financial statements taken as a whole. o il �w w Litchfield Office 820 Sibley Ave N Litchfield, MN 55355 (320) 693-7975 Sartetl Office Ste 110 2351 Connecticut Ave SarteL, MN 56377 (320) 252-7565 (800) 862-1337 Members; American Institute of Certified Public Accountants, Minnesota Society of Certified Public Accountants Management's estimate of pension liabilities and other postemployment benefits are based on actuarial valuations performed by consultants specializing in those areas. We evaluated the key factors and assumptions used to develop those estimates in determining that it is reasonable in relation to the financial statements taken as a whole. Qualitative Aspects of Accounting Practices (Cont'd) Management's estimate of pension and other post -employment benefit liabilities is based on actuarial valuations performed by consultants specializing in those areas. We evaluated the key factors and assumptions used to develop those estimates in determining that it is reasonable in relation to the financial statements taken as a whole. The financial statement disclosures are neutral, consistent, and clear. Difficulties Encountered in Performing the Audit We encountered no significant difficulties in dealing with management in performing and completing our audit. Corrected and Uncorrected Misstatements Professional standards require us to accumulate all known and likely misstatements identified during the audit, other than those that are clearly trivial, and communicate them to the appropriate level of management. Management has corrected all such misstatements. Disagreements with Management For purposes of this letter, a disagreement with management is a financial accounting, reporting, or auditing matter, whether or not resolved to our satisfaction, that could be significant to the financial statements or the auditor's report. We are pleased to report that no such disagreements arose during the course of our audit. Management Representations We have requested certain representations from management that are included in the management representation letter dated April 24, 2019. Management Consultations with Other Independent Accountants In some cases, management may decide to consult with other accountants about auditing and accounting matters, similar to obtaining a "second opinion" on certain situations. If a consultation involves application of an accounting principle to the Commission's financial statements or a determination of the type of auditor's opinion that may be expressed on those statements, our professional standards require the consulting accountant to check with us to determine that the consultant has all the relevant facts. To our knowledge, there were no such consultations with other accountants. Other Audit Findings or Issues We generally discuss a variety of matters, including the application of accounting principles and auditing standards, with management each year prior to retention as the Commission's auditors. However, these discussions occurred in the normal course of our professional relationship and our responses were not a condition to our retention. 2 Other Matters We applied certain limited procedures to Management's Discussion and Analysis, the Schedule of Proportionate Share of the Net Pension Liability, the Schedule of Employer Contributions, the Schedule of Changes in the Commission's Total OPEB Liability and the related notes, which is required supplementary information that supplements the basic financial statements. Our procedures consisted of inquiries of management regarding the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We did not audit the required supplementary information and do not express an opinion or provide any assurances on the required supplementary information. We were engaged to report on the statements and schedules listed in the table of contents as supplementary information, which accompany the financial statements but are not required supplementary information. With respect to this supplementary information, we made certain inquiries of management and evaluated the form, content, and methods of preparing the information to determine that the information complies with accounting principles generally accepted in the United States of America, the method of preparing it has not changed from the prior period, and the information is appropriate and complete in relation to our audit of the financial statements. We compared and reconciled the supplementary information to the underlying accounting records used to prepare the financial statements or to the financial statements themselves. We were not engaged to report on the Organizational Data, which accompany the financial statements but are not RSI. We did not audit or perform other procedures on this other information and we do not express an opinion or provide any assurance on it. Restriction on Use This information is intended solely for the use of the Commission and management of Hutchinson Utilities Commission and is not intended to be and should not be used by anyone other than these specified parties. (_.-fir"U'al, Z)ea,% ca err S/%' ;PzzP CONWAY, DEUTH & SCHMIESING, PLLP CPAS & ADVISORS LITCHFIELD, MINNESOTA April 24, 2019 3 This page intentionally left blank ELECTRIC DIVISION Residential General Service Industrial Street Lighting Resale Total Electric Sales Other Operating Revenues Total Operating Revenues Purchased Power - Electric Other Operating Expenses Total Operating Expenses Net Nonoperating Revenues (Expenses) Change in Net Position GAS DIVISION Residential Commercial Industrial Total Gas Revenues Gas Transportation Total Operating Revenues Purchased Power - Gas Other Operating Expenses Total Operating Expenses Net Nonoperating Revenues (Expenses) HUTCHINSON UTILITIES COMMISSION COMPARATIVE FINANCIAL DATA 2014 2015 2016 2017 2018 $ 5,162,073 $ 5,080,964 $ 5,269,261 $ 5,341,820 $ 5,601,482 8,787,907 8,763,091 8,567,839 9,050,034 9,523,924 11,001,396 11,399,155 10,941,617 10, 778,629 10,218,577 139,532 146,931 144,641 147,484 147,470 678,293 1,114,918 1,931,859 2,171,853 3,071,099 25,769,201 26,505,059 26,855,217 27,489,820 28,562,552 304,095 297,007 293,294 167,159 182,837 26,073,296 26,802,066 27,148,511 27,656,979 28,745,389 15, 034, 661 15, 429, 451 14, 568, 448 15,062,252 15, 680, 416 12,072,182 11,739,870 12,837, 733 12,863, 710 12,955,488 27,106,843 27,169,321 27,406,181 27,925,962 28,635,904 (451,322) (201,467) 52,536 (8,337) (283,198) $ (1,484,869) $ (568,722) $ (205,134) $ (277,320) $ (173,713) $ 4,706,388 $ 3,731,066 $ 3,839,034 $ 3,937,048 $ 4,139,639 3,853,504 2,748,161 2,824,329 3,019,230 3,070,904 6,066,290 3,444,273 3,215,714 3,842,863 3,870,184 14,626,182 9,923,500 9,879,077 10,799,141 11,080,727 1,508,575 1,417,997 1,479,135 1,579,495 1,667,019 16,134,757 11,341,497 11,358,212 12,378,636 12,747,746 10,460,268 5,988,821 5,697,867 6,883,154 6,084,090 3,541,750 3,145,695 3,346,056 3,242,875 3,238,914 14,002,018 9,134,516 9,043,923 10,126,029 9,323,004 (605,361) (536,019) (269,688) (403,706) (192,296) Change in Net Position $ 1,527,378 $ 1,670,962 $ 2,044,601 $ 1,848,901 $ 3,232,446 HUTCHINSON UTILITIES COMMISSION ELECTRIC DIVISION Operating Revenues & Expenses and Net Nonoperating Revenues (Expenses) $35,000,000 $30,000,000 $28,745,389 $26,073,296 $26,802,066 $27,148,511 $27,656,979 Change in Net Position $o -$200,000 $ (205,134) $ (173, 713) $ (277, 320) -$400,000 - A -$600,000 $(568,722) -$800,000 -$1,000,000 -$1,200,000 -$1,400,000 -$1 , 600, 000 $ 1 484 869 2014 2015 2016 2017 2018 BChange in Net Position 5 5 HUTCHINSON UTILITIES COMMISSION ELECTRIC DIVISION Major Revenue by Source $12,000,000 $11,000,000 $10,000,000 $9,000,000 $8,000,000 $7,000,000 $6,000,000 $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 2014 2015 2016 2017 2018 ■Residential ®General Service Glndustrial Purchased Power & Fuel Costs Compared to Total Sales $30,000,000 $25,000,000 $20,000,000 $15,000,000 $10,000,000 $5,000,000 $0 2014 2015 2016 2017 2018 ■Purchased Power- Electric ®Total Electric Sales n u HUTCHINSON UTILITIES COMMISSION ANALYSIS OF OPERATIONS ELECTRIC DIVISION YEARS ENDED DECEMBER 31, 2018 AND 2017 The Statement of Revenues and Expenses set forth the results of the operations in detail for the years ended December 31, 2018 and 2017. Operating revenues, kilowatt hours (KWH) sold, and average revenue per kilowatt hour sold by class of service are as follows: Year Ended December 31, 2018 Revenue Per Amount KWH Sold KWH CLASS Residential $ 5,336,482 51,777,707 $ 0.1031 All Electric 265,000 2,610,277 0.1015 Small General Service 1,934,682 19,106,510 0.1013 Large General Service 7,589,242 79,540,430 0.0954 Industrial 10,218,577 127,675,000 0.0800 Sale for Resale 3,071,099 27,160,000 0.1131 Street Lighting 147,470 98,302 1.5002 $ 28,562,552 307,968,226 0.0927 Year Ended December 31, 2017 Revenue Per Amount KWH Sold KWH CLASS Residential $ 5,093,852 49,389,408 $ 0.1031 All Electric 247,968 2,440,785 0.1016 Small General Service 1,814,703 17,896,264 0.1014 Large General Service 7,235,331 75,176,663 0.0962 Industrial 10,778,629 133,130,000 0.0810 Sale for Resale 2,171,853 13,000,000 0.1671 Street Lighting 147,484 102,156 1.4437 $ 27,489,820 291,135,276 0.0944 7 HUTCHINSON UTILITIES COMMISSION ANALYSIS OF OPERATIONS ELECTRIC DIVISION YEARS ENDED DECEMBER 31, 2018 AND 2017 KWH Sold 98,302 Street Lighting 102,156 27,160,000 Sale for Resale 13,000,000 127,675,000 Industrial 133,130,000 79,540,430 Large General Service 75,176,663 19,106,510 Small General Service 17,896,264 2,610,277 All Electric 2,440,785 51,777,707 Residential 49,389,408 zzzzzzzzzzzzzzzz Street Lighting Sale for Resale Industrial Large General Service Small General Service All Electric Residential 0 50,000,000 100,000,000 150,000,000 200,000,000 2018 KWH Sold 132017 KWH Sold Average $/KWH $1.5002 iiiiiiiiiiiiiiiiiiiiiillillillillillillilliillillillillillillillillillilliilliillillillillillillilliillillillillillillilliilillillillillillillillillilliilliillillilillilip $1.4437 0.1131 $0.1671 $0.0800 $0.0810 $0.0954 $0.0962 $0.1013 $0.1014 $0.1015 $0.1016 $0.1031 $0.1031 »»,, rrrrrrrrrrsf>��i�i�i�i�i�i�i�i�i�i�i�c°,ii�� rrrrr�rrrrrrrrrrrrrn�r�� rr�r�r�r�r��r°� :�is�s�s�s�sssss �»»»»»»>i��rrrrr�i�,�sss��r�r�r�r�r�wwwwwwrrr��r�r�r�r�r�rrrrrrrrrrr��s I.00 $0.50 $1.00 $1.50 $2.00 2018 Revenue Per KWH M2017 Revenue Per KWH HUTCHINSON UTILITIES COMMISSION NATURAL GAS DIVISION $18,000,000 Operating Revenues & Expenses and Net Nonoperating Revenues (Expenses) $16,000,000 $16,134, 757 $14, 002, 018 Change in Net Position $3, 500, 000 $3,232,446 $3, 000, 000 $2, 500, 000 $2,044,601 $1,848,901 $2, 000, 000 $1,670,962 $1,527,378 $1,500,000 $1,000,000 $500,000 $0 2014 2015 2016 2017 2018 ■Change in Net Position HUTCHINSON UTILITIES COMMISSION NATURAL GAS DIVISION Major Revenue by Source $7,000,000 $6,000,000 $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 2014 2015 2016 2017 2018 ■Residential ®Commercial Olndustrial Purchased Gas Compared to Total Sales $16,000,000 $14,000,000 $12,000,000 $10,000,000 $8, 000, 000 $6, 000, 000 $4, 000, 000 $2, 000, 000 $0 2014 2015 2016 2017 2018 ■ Purchased Power - Gas ®Total Gas Revenues 10 HUTCHINSON UTILITIES COMMISSION ANALYSIS OF OPERATIONS NATURAL GAS DIVISION YEARS ENDED DECEMBER 31, 2018 AND 2017 The Statement of Revenues and Expenses set forth the results of the operations in detail for the years ended December 31, 2018 and 2017. Operating revenues, cubic feet sold, and average revenue per thousand cubic feet sold by class of service are as follows: Year Ended December 31, 2018 Revenue Per Thousand Amount CF Sold MCF CLASS Residential $ 4,139,639 446,223,775 $ 9.2770 Commercial 3,070,904 349,805,617 8.7789 Large industrial 3,870,184 857,732,882 4.5121 $ 11,080,727 1,653,762,274 $ 6.7003 Year Ended December 31, 2017 Revenue Per Thousand Amount CF Sold MCF CLASS Residential $ 3,937,048 396,761,756 $ 9.9230 Commercial 3,019,230 325,983,624 9.2619 Large industrial 3,842,863 859,892,970 4.4690 $ 10,799,141 1,582,638,350 $ 6.8235 11 HUTCHINSON UTILITIES COMMISSION ANALYSIS OF OPERATIONS NATURAL GAS DIVISION YEARS ENDED DECEMBER 31, 2018 AND 2017 CF Sold Average $/MCF ........................................................................................................................................................................................................................................................ IdL $4.5121 Large industrial $4.4690 $8.7789 Commercial $9.2619 $9.2770 Residential $9.9230 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 $11.00 M2018 Revenue per 1000 MCF M2017 Revenue Per 1000 MCF 12 This page intentionally left blank HUTCHINSON UTILITIES COMMISSION SCHEDULE OF FINDINGS ON ACCOUNTING ISSUES AND INTERNAL CONTROLS DECEMBER 31, 2018 We noted certain matters involving the internal control structure and its operation that we consider being deficiencies in internal control under standards established by the American Institute of Certified Public Accountants. A deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent, or detect and correct misstatements on a timely basis. INTERNAL CONTROL The objective of internal accounting control is to provide reasonable, but not absolute, assurance as to the safeguarding of assets against loss from unauthorized use or disposition, and the reliability of financial records for preparing financial statements and maintaining accountability for assets. The concept of reasonable assurance recognizes that the cost of a system of internal accounting control should not exceed the benefits derived and also recognizes that the valuation of these factors necessarily requires estimates and judgments by management. It should be recognized that within the Commission, an inherent risk is present with certain positions. It is very common for entities such as Hutchinson Utilities Commission, to assign many major responsibilities to a few key individuals in an attempt to operate within limited budgets. The inherent risk is again addressed only to maintain the awareness of the internal control structure and to encourage the Commission's continual review of financial information at monthly meetings. GENERAL RECOMMENDATIONS Throughout the course of the audit, we spoke with management regarding certain items that we see as an opportunity to improve. None of these were considered significant within the scope of the audit. The items discussed requiring action have been resolved or are in the process of resolution. We would like to acknowledge the assistance and courtesies extended to us by the personnel of the Hutchinson Utilities Commission. CROSS -TRAINING In small public entities, it is common for one person to be primarily responsible for handling all financial matters (payroll, disbursements, receiving, recording transactions, etc.). This concentration of duties in one person is not desirable for a sound control environment and contingency planning. One measure to help counter this weakness involves training a second person in specific duties related to the entities finances. Cross -training has numerous benefits. It allows a second person to perform the duties when the employee primarily responsible is unavailable. Having someone else perform the job duties also provides a method of detecting errors and/or irregularities created by the person primarily responsible for those duties. Finally, cross -training provides continuity during periods of employee transitions. Cross -training offers advantages from both an accounting and a managerial point of view. We recommend the review of various responsibilities and cross -train other staff to perform non -routine duties on a timely basis in the absence of the individual typically responsible for such duties. Other remedies would be to have an outside source familiar in these specific areas be contracted when deemed necessary to keep the Commission current in the financial area. CAPITAL ASSET ACCOUNTING The Commission maintains its capital asset activity and balances using spreadsheet software (Microsoft Excel). While Excel is an automated software program, it is not the most effective and efficient program for capital asset accounting. A relational database program would operate more effectively and efficiently to manage and account for capital asset inventory. Because the Commission segregates capital assets by activity and function, the complexity of the spreadsheets increases annually and is very susceptible to human error. 13 HUTCHINSON UTILITIES COMMISSION SCHEDULE OF FINDINGS ON ACCOUNTING ISSUES AND INTERNAL CONTROLS DECEMBER 31, 2018 CAPITAL ASSET ACCOUNTING (Cont'd) We recommend the Commission use relational database software to maintain and account for its capital asset inventory. Implementation of this type of software will strengthen internal controls over capital asset accounting and provide efficiencies in the perpetual maintenance of capital assets. 14 HUTCHINSON UTILITIES COMMISSION AUDITED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION DECEMBER 31, 2018 CONWAY, DEUTH & SCHMIESING, PLLP CPAS & ADVISORS LITCHFIELD, MINNESOTA This page intentionally left blank HUTCHINSON UTILITIES COMMISSION TABLE OF CONTENTS DECEMBER 31, 2018 ORGANIZATIONAL DATA INDEPENDENT AUDITOR'S REPORT REQUIRED SUPPLEMENTARY INFORMATION Management's Discussion and Analysis BASIC FINANCIAL STATEMENTS Statement of Net Position Statement of Revenues, Expenses and Changes in Net Position Statement of Cash Flows Notes to the Financial Statements REQUIRED SUPPLEMENTARY INFORMATION Schedule of Proportionate Share of Net Pension Liability Schedule of Employer Contributions Schedule of Changes in the Commissions's Total OPEB Liability Notes to Required Supplementary Information SUPPLEMENTARY INFORMATION Combining Statement of Net Position Combining Schedule of Revenues and Expenses Schedule of Division Cash Flows Statement of Net Position - Electric Division Detailed Schedule of Revenues, Expenses and Changes in Net Position - Budget and Actual - Electric Division Statement of Net Position - Natural Gas Division Detailed Schedule of Revenues, Expenses and Changes in Net Position - Budget and Actual - Natural Gas Division PAGE 1 2-4 5-9 10 11 12-13 14-35 36 37 38 39-40 41 42 43-44 45 46-49 50 51-53 HUTCHINSON UTILITIES COMMISSION TABLE OF CONTENTS DECEMBER 31, 2018 COMPLIANCE SECTION Independent Auditor's Report on Minnesota Legal Compliance Independent Auditor's Report on Internal Control Over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards Summary Schedule of Prior Audit Findings I2_[el9 54 55-56 57 HUTCHINSON UTILITIES COMMISSION ORGANIZATIONAL DATA DECEMBER 31, 2018 A Light and Power Commission was formed under the provisions of an amendment to the Hutchinson City Charter in 1935; the Commission was charged with the operation of the Municipal Electric Plant. Charter amendments approved December 17, 1954, provided for a change in the name to Hutchinson Utilities Commission. Additional duties under that amendment provided for the control and management of a municipal gas distribution system. A revised city charter was adopted at a special election September 17, 1987. Some of the pertinent sections of this new charter are briefly summarized in the following paragraphs. The Commission shall have control and management of the Light Plant, the Light Plant distribution system, the Gas Plant and the Gas Plant distribution system. The Commission shall consist of five persons, qualified voters of the City, who shall be appointed by the Council. A member shall be appointed every year for a term of five years, to fill the place of the member whose term has expired. No member shall be appointed to more than two successive terms. The members of the Commission shall receive compensation for their services as determined annually by the Council. The Commission shall provide for its own organization and rules of procedure and annually shall elect a president and vice president from among its members. It shall also appoint a secretary who may or may not be a member of the Commission. The Commissioners and their official titles were as follows: Monty Morrow Anthony Hanson Robert Wendorff Don Martinez Matt Cheney President Vice President Secretary Commissioner Commissioner This page intentionally left blank INDEPENDENT AUDITOR'S REPORT Members of the Hutchinson Utilities Commission Hutchinson, Minnesota Report on the Financial Statements We have audited the accompanying financial statements of Hutchinson Utilities Commission, a fund of the City of Hutchinson, Minnesota, as of and for the year ended December 31, 2018 and the related notes to the financial statements, which collectively comprise the Commission's basic financial statements as listed in the table of contents. Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. Auditor's Responsibility Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. 2 lulls! 111 WMI,. www, rdscp a,c,orn Office Ste 110 Members: American Institute of Certified Public Accountants, Minnesota Society of Certified Public Accountaints Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the respective financial position of Hutchinson Utilities Commission, a fund of the City of Hutchinson, Minnesota, as of December 31, 2018, and the changes in financial position, and cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America. Report on Partial Comparative Information We have previously audited the Commission's 2017 financial statements, and we expressed an unmodified audit opinion on those audited financial statements in our report dated June 15, 2018. In our opinion, the partial comparative information presented herein as of and for the year ended December 31, 2017 is consistent, in all material respects, with the audited financial statements from which it has been derived. Other Matters Required Supplementary Information Accounting principles generally accepted in the United States of America require that the Management's Discussion and Analysis, the Schedule of Proportionate Share of Net Pension Liability, the Schedule of Employer Contributions, and the Schedule of Changes in the Comission's Total OPEB Liability as listed in the table of contents be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance. Supplementary and Other Information Our audit was conducted for the purpose of forming an opinion on the financial statements that collectively comprise the Commission's basic financial statements. The statements and schedules listed in the table of contents as supplementary information and the Organizational Data section are presented for purposes of additional analysis and are not a required part of the basic financial statements. The supplementary information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the basic financial statements. Such information has been subjected to the auditing procedures applied in the audit of the basic financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the basic financial statements or to the basic financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the supplementary information is fairly stated, in all material respects, in relation to the basic financial statements as a whole. The Organizational Data section has not been subjected to the auditing procedures applied in the audit of the basic financial statements and, accordingly, we do not express an opinion or provide any assurance on the information presented. 3 Other Reporting Required by Government Auditing Standards In accordance with Government Auditing Standards, we have also issued our report dated April 24, 2019 on our consideration of the Commission's internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards in considering Hutchinson Utilities Commission's internal control over financial reporting and compliance. Cori, Z)% c �iesl , 7,/ CONWAY, DEUTH & SCHMIESING, PLLP CPAS & ADVISORS LITCHFIELD, MINNESOTA April 24, 2019 4 This page intentionally left blank REQUIRED SUPPLEMENTARY INFORMATION This page intentionally left blank HUTCHINSON UTILITIES COMMISSION MANAGEMENT'S DISCUSSION AND ANALYSIS DECEMBER 31, 2018 Overview of the Financial Statements Hutchinson Utilities Commission is a fund of the City of Hutchinson, Minnesota, and is responsible for the full operation and management of the electric and natural gas systems of the City. The annual report of Hutchinson Utilities Commission includes the financial statements, the independent auditor's report, and notes detailing the financial statements and this management's discussion and analysis report. The report also includes supplementary information for each of Hutchinson Utilities Commission's divisions. Financial Statements Required The financial statements report information about Hutchinson Utilities Commission using accounting methods similar to those used by private sector companies. These statements offer short-term and long-term financial information about its activities. The Statement of Net Position includes all of the Commission's assets and deferred outflows of resources, liabilities and deferred inflows of resources, and net position and provides information regarding the nature and amount of investments in various assets and obligations to the Commission's creditors. They also provide the basis for computing rate of return, evaluating the capital structure, and determining the liquidity and financial flexibility of the Commission. The Statement of Revenues, Expenses and Changes in Net Position accounts for all the current year's revenues and expenses. This statement measures the success of operations over the past year and can be used to determine whether all costs are recovered through user fees and other charges. This statement measures the Commission's profitability and credit worthiness. The Statement of Cash Flows provides information about the Commission's cash receipts and cash payments during the reporting period. This statement reports cash receipts, cash payments, and net changes in cash resulting in cash balances during the reporting period. Financial Statement Analvsis Total gross investment in capital assets increased to $149,338,768 in 2018 from $138,365,918 in 2017. Capital assets increased $10,972,850 primarily because of upgrades and improvements to the generating plant and distribution systems as well as equipment purchases. Operating revenues and operating income increased from 2017 by $1,457,520 and $1,550,603, respectively. Operating expenses decreased from 2017 by $93,083. The primary increase in operating revenues was due to an increase in electric and gas sales in 2018, which increased by $1,072,732 and $281,586, respectively, from 2017 due to increased sales and higher energy cost adjustments. The primary area of the increase in operating expenses was due to an increase in purchased power expenses caused by increased sales. Payment in Lieu of Taxes increased by $202,522 due to current agreement with the City of Hutchinson. HUTCHINSON UTILITIES COMMISSION MANAGEMENT'S DISCUSSION AND ANALYSIS DECEMBER 31, 2018 Significant Transactions In 2018, the Commission transferred $1,398,853 per agreement to the City of Hutchinson. Condensed Financial Statements A summary of the Statement of Net Position is presented in Table 1. Table 1 Condensed Statement of Net Position Net Capital Assets Restricted Assets Current Assets Total Assets Deferred Outflows of Resources Total Assets and Deferred Outflows of Resources Current Liabilities Noncurrent Liabilities Total Liabilities Deferred Inflows of Resources Net Position Net Investment in Capital Assets Restricted Unrestricted Total Net Position Increase 2018 2017 (Decrease $ 78,080,974 $ 70,830,339 $ 8,037,130 17,983,727 25,291,981 21,917,436 111,410,085 110,731,502 658,738 1,003,849 $ 112,068,823 $ 111,735,351 $ $ 6,438,985 $ 6,518,979 $ 34,720,080 37,296,051 _ 41,159,065 43,815,030 1,073,067 1,059,160 7,250,635 (9,946,597) 3,374,545 678,583 333,472 1 (79,994) (2,575,971) (2,655,965) 13,907 49,966,247 51,060,879 (1,094,632) 2,353,590 3,561,829 (1,208,239) 17,516,854 12,238,453 5,278,401 69,836,691 66,861,161 2,975,530 Total Liabilities, Deferred Inflows of Resources and Net Position $ 112,068,823 $ 111,735,351 333,472 1 HUTCHINSON UTILITIES COMMISSION MANAGEMENT'S DISCUSSION AND ANALYSIS DECEMBER 31, 2018 Condensed Financial Statements (Cont'd) A summary of the Statement of Revenues, Expenses and Changes in Net Position is presented in Table 2. Table 2 Condensed Statement of Revenues, Expenses and Changes in Net Position Increase 2018 2017 (Decrease Operating Revenues Operating Expenses Cost of Operations Depreciation Total Operating Expenses Operating Income (Loss) Nonoperating Revenues (Expenses) Change in Net Position Net Position, Beginning of Year, As Originally Stated Prior Period Adjustment Net Position, Beginning of Year As Restated Net Position, End of Year Budgetary Highlights $ 41,493,135 $ 40,035,615 $ 1,457,520 1 34,154,423 34,199,317 (44,894) 3,804,485 3,852,674 (48,189) 37,958,908 38,051,991 (93,083) 3,534,227 1,983,624 1,550,603 (475,494) (412,043) (63,451) 3,058,733 1,571,581 1,487,152 66,861,161 65,289,580 1,571,581 (83,203) (83,203) 66,777,958 65,289,580 1,488,378 $ 69,836,691 $ 66,861,161 $ 2,975,530 The Commission adopts an annual Operating Budget and a Capital Improvement Budget. Because of its enterprise nature and in order to comply with Federal Energy Regulatory Commission accounting and reporting requirements, the budgets are not operated as statutory budgets. The Commission and Utilities staff review budget results monthly and the budget is used as a financial management tool. A summary of the 2018 Budget Analysis is presented in Table 3. 7 HUTCHINSON UTILITIES COMMISSION MANAGEMENT'S DISCUSSION AND ANALYSIS DECEMBER 31, 2018 Budgetary Highlights (Cont'd) Operating Revenues Operating Expenses Cost of Operations Depreciation Expense Total Operating Expenses Operating Income (Loss) Nonoperating Revenues (Expenses) Change in Net Position Table 3 Condensed Budget Analysis 2018 Budget 2018 Actual Over $ 39,958,811 $ 41,493,135 $ 1,534,324 33,931,156 34,154,423 223,267 3,908,000 3,804,485 (103,515 37,839,156 37,958,908 119,752 2,119,655 3,534,227 1,414,572 1,021,255) (475,494) 545,761 1,098,400 3,058,733 1,960,333 Net Position, Beginning of Year, As Originally Stated 66,861,161 66,861,161 Prior Period Adjustment Net Position, Beginning of Year As Restated Net Position, End of Year (83,203) (83,203) 66,777,958 66,777,958 $ 67,876,358 $ 69,836,691 $ 1,960,333 Actual operating revenues were $1,534,324 over budgeted revenues while operating income (loss) was over budget by $1,414,572. The actual operating revenues for the Commission had a variance of approximately 3.84% from budgeted operating revenues. Operating expenses were $119,752 higher than budgeted. This is mainly due to purchased power and purchased natural gas operating expense were higher than anticipated while being under budgeted on other operating expenses. In 2018, the Commission entered into an agreement for a specific Payment in Lieu of Taxes (PILOT). The agreement requires the Commission to make payments equaling $1,398,853. Starting in calendar year 2007, the Commission reallocated its common expenses between the two divisions. Formulas were developed and used to establish the common expenses between the two utilities, in particular, Customer Service and Collection Accounts and the Administrative and General Accounts. Capital Assets and Long -Term Liability Activity The Commission's investment in capital assets increased to $149,338,768 in 2018. This is an increase of $10,972,850 from 2017. Refer to Note 5 of the Notes to the Financial Statements for the Commission's 2018 capital asset activity. At year-end, the Commission had $30,575,000 in bonds outstanding and $584,082 in compensated absences. Refer to Note 6 of the Notes to the Financial Statements for a schedule showing the Commission's long-term liability activity. 0 HUTCHINSON UTILITIES COMMISSION MANAGEMENT'S DISCUSSION AND ANALYSIS DECEMBER 31, 2018 Economic Factors and Next Year's Budget The Commission considered many local community and external energy industry factors when setting the Electric & Gas Division fiscal year 2019 budgets, rates, and fees that will be charged to customers. Of significance was the continual increase in costs associated with purchased electrical wholesale power and transmission fees. Conversely, the Gas Division continues to see favorable prices for the procurement of the natural gas commodity. Both divisions continue to see consistent energy consumption forecasts in the near future. In addition, the Payment in Lieu of Taxes (PILOT) was set for 2019 based on a three year phase in up to 4.50%, starting with 3.25% in 2018. The Commission continued to "bundle" its electric wholesale rate to its retail customers. What this means is the operating income the Commission receives from its wholesale KWHR sales is applied to the wholesale rate it charges its retail customers. This "bundling" effect reduces the overall blended cost of wholesale power which aids in retail rate pricing stability. Contact Information Any questions regarding information contained in this report and requests for additional information should be addressed to the Hutchinson Utilities Commission, 225 Michigan Street SE, Hutchinson, MN 55350 or by phone at (320) 587-4746. 0 This page intentionally left blank BASIC FINANCIAL STATEMENTS This page intentionally left blank HUTCHINSON UTILITIES COMMISSION STATEMENT OF NET POSITION DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS AS OF DECEMBER 31, 2017 2018 2017 ASSETS AND DEFERRED OUTFLOWS OF RESOURCES Assets Current Assets Cash and Investments $ 19,858,735 $ 16,027,769 Receivables Accounts Receivable (Net of Allowance for Doubtful Accounts of $66,253 and $71,132, Respectively) 3,633,866 4,113,840 Interest Receivable 47,264 38,078 Sales Tax Receivable 33,090 34,743 Inventory 1,658,750 1,565,580 Prepaid Items 60,276 137,426 Total Current Assets 25,291,981 21,917,436 Noncurrent Assets Restricted Assets Cash and Investments 8,037,130 17,983,727 Capital Assets Assets Not Being Depreciated 17,451,198 7,473,188 Other Capital Assets, Net of Depreciation 60,629,776 63,357,151 Net Capital Assets 78,080,974 70,830,339 Total Noncurrent Assets 86,118,104 88,814,066 Total Assets 111,410,085 110,731,502 Deferred Outflows of Resources 658,738 1,003,849 Total Assets and Deferred Outflows of Resources $ 112,068,823 $ 111,735,351 LIABILITIES, DEFERRED INFLOWS OF RESOURCES AND NET POSITION Liabilities Current Liabilities Current Portion of Other Noncurrent Liabilities $ 2,237,938 $ 1,535,391 Accounts Payable 3,465,537 4,239,847 Customer Deposits 450,355 437,920 Accrued Expenses Interest 97,334 146,728 Salaries Payable 187,821 159,093 Total Current Liabilities 6,438,985 6,518,979 Noncurrent Liabilities Net Pension Liability 3,600,387 4,111,253 Total OPEB Liability 96,256 Other Noncurrent Liabilities 31,023,437 33,184,798 Total Noncurrent Liabilities 34,720,080 37,296,051 Total Liabilities 41,159,065 43,815,030 Deferred Inflows of Resources 1,073,067 1,059,160 Net Position Net Investment in Capital Assets 49,966,247 51,060,879 Restricted 2,353,590 3,561,829 Unrestricted 17,516,854 12,238,453 Total Net Position 69,836,691 66,861,161 Total Liabilities, Deferred Inflows of Resources and Net Position $ 112,068,823 $ 111,735,351 See Accompanying Notes to the Financial Statements IN HUTCHINSON UTILITIES COMMISSION STATEMENT OF REVENUES, EXPENSES AND CHANGES IN NET POSITION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 OPERATING REVENUES Electric Energy Sales Natural Gas Sales Other Operating Revenues Total Operating Revenues OPERATING EXPENSES Production Operations Maintenance Purchased Power/Gas Other Power Supply Transmission Operations Maintenance Distribution Operations Maintenance Customer Accounts Expense Sales Expense Administrative and General Depreciation Contribution to City of Hutchinson Total Operating Expenses Operating Income (Loss) NONOPERATING REVENUES (EXPENSES) Interest Income Merchandise and Contract Work, Net Miscellaneous Income Gain (Loss) on Disposal of Assets Bond Premium Interest Expense Total Nonoperating Revenues (Expenses) Change in Net Position NET POSITION, BEGINNING OF YEAR, AS ORIGINALLY STATED PRIOR PERIOD ADJUSTMENT NET POSITION, BEGINNING OF YEAR, AS RESTATED NET POSITION, END OF YEAR See Accompanying Notes to the Financial Statements 2018 2017 $ 28,562,552 $ 27,489,820 11,080,727 10,799,141 1,849,856 1,746,654 41,493,135 40,035,615 3,462,933 2,670,073 421,012 401,731 20,717,624 21,141,106 528,831 376,398 2,772,324 2,747,938 28,686 86,959 1,582,276 1,013,466 577,195 504,137 415,522 480,196 412,607 324,749 1,836,560 3,256,233 3,804,485 3,852,674 1,398,853 1,196,331 37,958,908 38,051,991 3,534,227 1,983,624 408,994 145,409 12,512 48,772 105,444 160,158 17,852 62,027 219,065 191,184 (1,239,361) (1,019,593) (475,494) (412,043) 3,058,733 1,571,581 66,861,161 65,289,580 (83,203) 66,777,958 65,289,580 $ 69,836,691 $ 66,861,161 11 HUTCHINSON UTILITIES COMMISSION STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 CASH FLOWS FROM OPERATING ACTIVITIES Receipts from Customers Payments Received from Other Sources Payments to Suppliers Payments to Employees Net Cash Provided (Used) by Operating Activities CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES Other Noncapital Income CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES Additions to Utility Plant Proceeds on Issuance of Long -Term Debt Principal Payments on Long -Term Debt Proceeds from Sale of Assets Interest Paid on Long -Term Debt Net Cash Provided (Used) by Capital and Related Financing Activities CASH FLOWS FROM INVESTING ACTIVITIES Interest Income Net Increase (Decrease) in Cash and Cash Equivalents CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR CASH AND CASH EQUIVALENTS, END OF YEAR RECONCILIATION OF CASH AND CASH EQUIVALENTS Current Assets - Cash and Investments Restricted Assets - Cash and Investments Total Cash and Cash Equivalents See Accompanying Notes to the Financial Statements 12 2018 2017 $ 40,135,688 $ 37,710,249 1,851,509 1,857,497 (30,456,185) (30,512,189) (4,543,382) (4,025,882) 6,987,630 5,029,675 117,956 208,930 (11,055,122) (4,110,022) 17,346,927 (1,295,000) (1,810,000) 17,852 62,027 (1,288,755) (936,247) (13,621,025) 10,552,685 399,808 138,747 (6,115,631) 15,930,037 34,011,496 18,081,459 $ 27,895,865 $ 34,011,496 $ 19,858,735 $ 16,027,769 8,037,130 17,983,727 $ 27,895,865 $ 34,011,496 HUTCHINSON UTILITIES COMMISSION STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 RECONCILIATION OF OPERATING INCOME (LOSS) TO CASH FLOWS FROM OPERATING ACTIVITIES Operating Income (Loss) Adjustments to Reconcile Operating Income (Loss) to Net Cash Provided (Used) by Operating Activities Depreciation Pension Related Adjustments OPEB Related Adjustments (Increase) Decrease in Assets Accounts Receivable Sales Tax Receivable Inventory Prepaid Items Increase (Decrease) in Liabilities Accounts Payable Due to Other Governments Customer Deposits Salaries Payable Compensated Absences Net Cash Provided (Used) by Operating Activities See Accompanying Notes to the Financial Statements 2018 2017 $ 3,534,227 $ 1,983,624 3,804,485 3,852,674 (148,693) 99,828 9,900 479,974 (560,392) 1,653 110,843 (93,170) (119,005) 77,150 (35,103) (774,310) 1,384,651 (1,757,601) 12,435 (18,320) 28,728 30,639 55,251 57,837 $ 6,987,630 $ 5,029,675 13 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. REPORTING ENTITY Hutchinson Utilities Commission, a fund of the City of Hutchinson, Minnesota, is governed by five members who are appointed by the Council of the City of Hutchinson, Minnesota. The accompanying financial statements present only the Hutchinson Utilities Commission fund and are not intended to present fairly the financial position of the City of Hutchinson, Minnesota. The financial statements present the Commission and its component units. The Commission includes all funds, organizations, institutions, agencies, departments and offices that are not legally separate from such. Component units are legally separate entities for which the Commission is financially accountable, or for which the exclusion of the component unit would render the financial statements of the Commission misleading. The criteria used to determine if the Commission is financially accountable for a component unit includes whether or not 1) the Commission appoints the voting majority of the potential component unit's governing body and is able to impose its will on the potential component unit or is in a relationship of financial benefit or burden with the potential component unit, or 2) the potential component unit is fiscally dependent on and there is a potential for the potential component unit to provide specific financial benefits to, or impose specific financial burdens on, the Commission. As a result of applying the component unit definition criteria above, the Commission does not have any component units. B. FUND ACCOUNTING The operations of the Commission are recorded as a proprietary fund. The proprietary fund is used to account for operations (a) that are financed and operated in a manner similar to private business enterprises - where the intent of the governing body is that the costs (expenses, including depreciation) of providing goods or services to the general public on a continuing basis be financed or recovered primarily through user charges; or (b) where the governing body has decided that periodic determination of revenues earned, expenses incurred, and/or net income is appropriate for capital maintenance, public policy, management control, accountability or other purposes. C. MEASUREMENT FOCUS. BASIS OF ACCOUNTING AND FINANCIAL STATEMENT PRESENTATION The financial statements include the operations of the City of Hutchinson Municipal Utilities. The Electric and Natural Gas divisions are treated as a single enterprise fund of the City of Hutchinson, Minnesota. The Utilities are governed by the Hutchinson Utilities Commission, which is appointed by the City Council. No other operations are controlled by the Hutchinson Utilities Commission. The accounts of the Commission are organized on the basis of fund accounting. The operation of the fund is accounted for with a separate set of self -balancing accounts that comprise its assets, liabilities, net position, revenues, and expenses. Government resources are allocated to and accounted for in the individual fund based upon the purposes for which they are to be spent and the means by which spending activities are controlled. Basis of accounting refers to when revenues and expenses are recognized in the accounts and reported in the financial statements. Basis of accounting relates to the timing of the measurements made, regardless of the measurement focus applied. 14 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Cont'd) C. MEASUREMENT FOCUS, BASIS OF ACCOUNTING AND FINANCIAL STATEMENT PRESENTATION (Cont'd) The proprietary fund is accounted for using the accrual basis of accounting and economic resources measurement focus. Revenues are recognized when earned, and expenses are recognized when incurred. Revenue from electricity and gas sales is reflected in the accounts only at the time such revenue is actually billed to customers. Accordingly, no recognition is given in the accounts for revenue from sales between established cycle billing dates. The proprietary fund distinguishes operating revenues and expenses from nonoperating items. Operating revenues and expenses generally result from providing services and producing and delivering goods in connection with a proprietary fund's principal ongoing operations. The principal operating revenues of the enterprise funds are charges to customers for sales and services. Operating expenses for enterprise funds include the cost of sales and services, administrative expenses, and depreciation of capital assets. All revenues and expenses not meeting this definition are reported as nonoperating revenues and expenses. It is generally the Commission's policy to use restricted resources first, then unrestricted resources as they are needed when an expense is incurred for purposes for which both restricted and unrestricted net position is available. D. DEPOSITS AND INVESTMENTS The Commission's cash and cash equivalents are considered to be cash on hand, deposits and highly liquid debt instruments purchased with original maturities of three months or less from the date of acquisition. The Commission may invest in the following types of investments as authorized by Minn. Stat. §§118A.04 and 118A.05: (1) securities which are direct obligations or are guaranteed or insured issues of the United States, its agencies, its instrumentalities, or organizations created by an act of Congress, except mortgage - backed securities defined as "high risk" by Minn. Stat. §118A.04, subd. 6; (2) mutual funds through shares of registered investment companies provided the mutual fund receives certain ratings depending on its investments; (3) general obligations of the State of Minnesota and its municipalities, and in certain state agency and local obligations of Minnesota and other states provided such obligations have certain specified bond ratings by a national bond rating service; (4) time deposits that are fully insured by the Federal Deposit Insurance Corporation or bankers acceptances of United States banks; (5) commercial paper issued by United States corporations or their Canadian subsidiaries that is rated in the highest quality category by at least two nationally recognized rating agencies and matures in 270 days or less; and 15 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Cont'd) D. DEPOSITS AND INVESTMENTS (Cont'd) (6) with certain restrictions, in repurchase agreements, securities lending agreements, joint powers investment trusts, and guaranteed investment contracts. Cash and investments were comprised of a deposit account, a money market account, municipal bonds, agency bonds, and negotiable certificates of deposit. The Commission categorizes its fair value measurements within the fair value hierarchy established by accounting principles generally accepted in the United States of America. The hierarchy is based on the valuation inputs used to measure the fair value of the asset. Level 1 inputs are quoted prices in active markets for identical assets. Level 2 inputs are significant other observable inputs. Level 3 inputs are significant unobservable inputs. The Commission has an investment policy in place that addresses interest rate risk, credit risk, concentration of credit risk and custodial risk as follows: Custodial Credit Risk - Deposits: For deposits, this is the risk that in the event of bank failure, the Commission's deposits may not be returned to it. Minnesota Statutes requires that all Commission deposits be protected by insurance, surety bond, or collateral. The market value of collateral pledged must equal 110 percent. The Commission's investment policy states the collateralization level will be 110% of the market value of principal and accrued interest. When the pledged collateral consists of notes secured by first mortgages, the collateral level will be 140% of the market value of principal and accrued interest. Authorized collateral includes the obligations of the U.S. Treasury, agencies, and instrumentalities, shares of investment companies whose only investments are in the aforementioned securities, obligations of the State of Minnesota or its municipalities, bankers' acceptances, futures contracts, repurchase and reverse repurchase agreements, and commercial paper of the highest quality with a maturity of no longer than 270 days, as well as certain first mortgage notes, and certain other state or local government obligations. Minnesota statutes require that securities pledged as collateral be held in safekeeping by the Commission treasurer or in a financial institution other than that furnishing the collateral. Interest Rate Risk - This is the risk that market values of securities in a portfolio would decrease due to changes in market interest rates. The Commission's investment policy states the Commission should manage their interest rates based on safety, liquidity and the overall rate of return on the investment. The portfolio should contain both short-term and long-term investments to meet anticipated cash flow requirements. Extended maturities may be utilized to take advantage of higher yields; however, no investment shall be made with a term of more than ten years. Credit Risk - Credit risk is the risk that an issuer or other counterparty to an investment will not fulfill its obligations. State law limits investments in commercial paper and corporate bonds to the top two ratings issued by nationally recognized statistical rating organizations. The Commission's investment policy states it will comply with Minnesota Statutes Chapter 118A. T HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Cont'd) D. DEPOSITS AND INVESTMENTS (Cont'd) Concentration of Credit Risk: This is the risk of loss attributed to the magnitude of an investment in a single issuer. Investments should be diversified to avoid incurring unreasonable risk inherent in over investing in specific instruments, individual financial institutions or maturities. The Commission's investment policy states the Commission will attempt to diversify its investments according to type and maturity. Custodial Credit Risk - Investments: For an investment, this is the risk that in the event of the failure of the counterparty, the Commission will not be able to recover the value of its investments or collateral securities that are in the possession of an outside party. The Commission's investment policy states when investments purchased by the Commission are held in safekeeping by a broker/dealer, they must provide asset protection of $500,000 through the Securities Investor Protection Corporations (SIPC) and at least another $2,000,000 Supplemental Insurance Protection, provided by the broker dealer. E. RECEIVABLES AND OPERATING REVENUES AND EXPENSES An allowance for doubtful accounts is recorded based on historical electric and natural gas revenues, historical loss levels, and an analysis of the collectability of individual accounts. Meters are read throughout the month and revenues are recognized when utility services are billed to customers. Hutchinson Utilities Commission did not accrue revenues for services provided but not billed at the end of the year. Monthly billings from the wholesale power and natural gas suppliers, which are for power and natural gas costs to the last day of the month, are reflected in the accounts. F. INVENTORY Inventories of materials and supplies are recorded at average cost, which does not exceed market. G. PREPAID ITEMS Certain payments to vendors reflect costs applicable to future accounting periods and are recorded as prepaid items in the financial statements. H. CAPITAL ASSETS Capital assets, both tangible and intangible, which include property, plant, equipment and infrastructure assets (e.g., roads, sidewalks and similar items) and easements, are recorded at cost. The cost of additions to capital assets includes contracted work, direct labor, and materials. Major outlays for capital assets and improvements are capitalized as projects are constructed. Repairs, replacement, and the renewal of items determined to be less than units of property are charged to maintenance. 17 HUTCHINSON UTILITIES COMMISSION NOTE 1 NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Cont'd) H. CAPITAL ASSETS (Cont'd) Tangible and intangible assets of the Commission are depreciated using the straight-line, full month convention method over the following estimated useful lives: Buildings 35-60 years Transmission plant (electric) 20-35 years Distribution plant (electric) 20-35 years Building improvement 15-30 years Transmission plant (gas) 10-45 years Distribution plant (gas) 10-45 years Generation plant 10-30 years General plant 5-10 years Vehicles 5-10 years Office equipment 3-5 years Computer equipment 3-5 years Capital assets not being depreciated include land, easements and construction in progress, if any. I. DEFERRED OUTFLOWS OF RESOURCES In addition to assets, the statement of financial position will sometimes report a separate section for deferred outflows of resources. Deferred outflows of resources represents a consumption of net position that applies to a future reporting period. During that future period, it will be recognized as an outflow of resources (expense). The Commission has two items that qualifies for reporting in this category on the financial statements which is related to pensions and other post -employment benefits. J. COMPENSATED ABSENCES The liability for compensated absences reported in the financial statements consists of unpaid, accumulated vacation and sick leave balances. The liability has been calculated using the vesting method, in which leave amounts for both employees who currently are eligible to receive termination payments and other employees who are expected to become eligible in the future to receive such payments upon termination are included. Compensated absences are accrued when incurred in the financial statements. The Statement of Net Position reports both current and noncurrent portions of compensated absences using full accrual accounting. The current portion consists of an amount based on a trend analysis of current usage of vacation and vested sick leave. The noncurrent portion consists of the remaining amount of vacation and total vested sick leave. Both union and nonunion employees can accrue a maximum of 200 hours per year of vacation pay. A nonunion employee may carry over a maximum of one time their annual accrual of vacation into the next year. Each permanent nonunion full-time employee must use at least 40 hours of vacation per year. A union employee may carry over up to forty hours of accrued vacation into the next year. Vacation pay is 100% payable at severance of employment. A maximum of 720 hours can be accrued for sick leave. After accumulation of 720 hours, a payback of one-third of the amount over 720 hours will be made annually. Upon retirement or death before retirement, severance payable is paid back at one-third of the amount over 240 hours will be made. 18 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Cont'd) K. PENSIONS For purposes of measuring the net pension liability, deferred outflows of resources and deferred inflows of resources related to pensions, and pension expense, information about the fiduciary net position of the Public Employees Retirement Association (PERA) and additions to/deductions from PERA's fiduciary net position have been determined on the same basis as they are reported by PERA. For this purpose, plan contributions are recognized as of employer payroll paid dates and benefit payments and refunds are recognized when due and payable in accordance with the benefit terms. Investments are reported at fair value. The Commission participates in various pension plans; total pension expense for the fiscal year ended was $189,042. The components of pension expense are noted in the plan summaries. L. POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS Employees of the Commission pay premiums based on a negotiated schedule. Since the insurance rate is not based on age, the Commission has an implicit rate subsidy factor in postemployment health care expenses. Additionally, Minnesota Statutes require the Commission to allow retired employees to stay on the health care plan with the retiree responsible to pay the entire premium for continuation coverage. The Commission's bargaining agreement and personnel policy do not provide for any contributions upon employee retirement. Any liability for other postemployment benefits is considered immaterial and not recognized in the financial statements. M. LONG-TERM OBLIGATIONS Long-term debt and other long-term obligations are reported as liabilities in the financial statements. Bond discounts and bond premiums are amortized over the terms of the related bond issues. N. DEFERRED INFLOWS OF RESOURCES In addition to liabilities, the statement of financial position will sometimes report a separate section for deferred inflows of resources. Deferred inflows of resources represents an acquisition of net position that applies to a future reporting period. During that future period, it will be recognized as an inflow of resources (revenue). The Commission has one item that qualify for reporting in this category on the financial statements which is related to pensions and OPEB. O. NET POSITION Net position represents the difference between assets plus deferred outflows of resources and liabilities plus deferred inflows of resources in the financial statements. Net investment in capital assets consists of capital assets, net of accumulated depreciation, reduced by the outstanding balance of any long-term debt used to build or acquire the capital assets. Net position is reported as restricted in financial statements when there are limitations on its use through external restrictions imposed by creditors, grantors or laws or regulations of other governments. Unrestricted net position consists of all other net position that does not meet the definition of restricted or net investment in capital assets. 19 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Cont'd) P. BUDGETS AND BUDGETARY ACCOUNTING The General Manager is responsible for preparing and submitting an annual budget. Budgets are adopted on a basis consistent with accounting principles generally accepted in the United States of America. Q. USE OF ESTIMATES The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and deferred outflows of resources, and liabilities and deferred inflows of resources and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. R. PRIOR YEAR INFORMATION The basic financial statements include certain prior -year partial comparative information in total but not at the level of detail required for a presentation in conformity with accounting principles generally accepted in the United States of America. Accordingly, such information should be read in conjunction with the Commission's financial statements for the year ended December 31, 2017, from which the partial information was derived. NOTE 2. DEPOSITS AND INVESTMENTS A. DEPOSITS In accordance with applicable Minnesota Statutes, Hutchinson Utilities Commission maintains deposits at depository banks authorized by the Commission. Custodial Credit Risk - Deposits: The Commission's bank balances were not exposed to custodial credit risk because they were fully insured through the Federal Deposit Insurance Corporation as well as collateralized with securities held by the pledging financial institution's trust department or agent and in the Commission's name. Deposits in Bank $ 15,901,998 Money Market Accounts 82,027 Petty Cash 850 Total Deposits $ 15,984,875 elm HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 2. DEPOSITS AND INVESTMENTS (Cont'd) B. INVESTMENTS The Commission had the following investments: Interest Rate Risk Fair Value Maturity Date Municipal Bonds $ 3,999,432 1-6 years Agency Bonds 6,460,531 1-6 years Negotiable Certificates of Deposit 1,451,027 1-5 years Total Investments $ 11,910,990 The Municipal Bonds were rated A2/AA-. The Agency Bonds were rated Aaa/AA+. The Negotiable Certificates of Deposit were not rated. Investments' fair value measurements are as follows: Fair Value Measuring Unit Fair Level Level Level Value Inputs Inputs Inputs Municipal Bonds $ 3,999,432 $ $ 3,999,432 $ Agency Bonds 6,460,531 6,460,531 Negotiable Certificates of Deposit 1,451,027 1,451,027 Total Investments $ 11,910,990 $ 0 $ 11,910,990 $ 0 The following is a summary total of deposits and investments: Deposits (Note 3.A.) $ 15,984,875 Investments (Note 3.B.) 11,910,990 Total Deposits and Investments $ 27,895,865 Deposits and investments are presented in the basic financial statements as follows: Current Assets Cash and Investments $ 19,858,735 Noncurrent Assets Restricted Assets Cash and Investments 8,037,130 Total Deposits and Investments $ 27,895,865 21 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 3. DEPOSITS AND INVESTMENTS - RESTRICTED Restricted cash and investments are designated by bond covenants for specific purposes. Restricted cash consisted of the following: Public Utility Revenue Refunding Bonds, Series 2012A Funds required to be held in a debt service reserve account based on criteria set aside in the bond issuance document. $ 2,353,590 Public Utility Revenue Bonds, Series 2017B Funds required to be held in a debt service reserve account based on criteria set aside in the bond issuance document. 1,120,974 Invested Unspent Bond Proceeds 4,562,566 Total Cash and Investments - Restricted $ 8,037,130 The following items have been designated by the Commission for the following purposes: Rate Stabilization - Electric $ 372,737 Rate Stabilization - Gas 651,307 Payment in Lieu of Taxes 1,601,424 Catastrophic 500,000 Expansion and Development Reserve Account Funds designated for the expansion and development of the utility. 3,450,000 Total Cash and Investments - Designated $ 6,575,468 The above Commission designated amounts are included in the Current Assets -Cash and Investments total. 22 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 4. INVENTORY Inventory consists of the following: Electric Division Fuel Oil and Lubricants $ 97,261 Plant Systems Material 5,919 Engine Parts 572,244 Distribution Materials 370,187 Transformers 149,676 Total Electric Division 1,195,287 Natural Gas Division Fittings 159,893 Transmission Line Gas 303,570 Total Natural Gas Division 463,463 Total Inventory $ 1,658,750 23 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 5. CAPITAL ASSETS Capital asset activity was as follows: Capital Assets, Not Being Depreciated Land Easements Construction in Progress Total Capital Assets, Not Being Depreciated Capital Assets, Being Depreciated Beginning Ending Balance Increase Decrease Balance $ 559,528 $ $ $ 559,528 4,030,760 4,030,760 2,882,900 10,128,582 (150,572) 12,860,910 7,473,188 10,128,582 (150,572) 17,451,198 Structures and Improvements 114,628,999 808,733 115,437,732 Equipment 16,055,099 268,379 (82,272) 16,241,206 Software 208,632 208,632 Total Capital Assets, Being Depreciated 130,892,730 1,077,112 (82,272) 131,887,570 Less Accumulated Depreciation for Structures and Improvements 57,534,130 3,293,075 60,827,205 Equipment 9,839,787 509,320 (82,272) 10,266,835 Software 161,662 2,092 163,754 Total Accumulated Depreciation 67,535,579 3,804,487 (82,272) 71,257,794 Total Capital Assets, Being Depreciated, Net 63,357,151 (2,727,375) 0 60,629,776 Net Capital Assets $ 70,830,339 $ 7,401,207 $ (150,572) $ 78,080,974 24 HUTCHINSON UTILITIES COMMISSION NOTE 6. NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 LONG-TERM LIABILITIES A. COMPONENTS OF LONG-TERM LIABILITIES Interest Rates Public Utility Revenue Refunding Bonds, Series 2012A 4.00-5.00% Public Utility Revenue Bonds, Series 2017B 2.50-4.00% Bond Premium Compensated Absences Total Long -Term Liabilities Final Balance Maturity Outstanding 12/01/2026 $ 13,900,000 12/01 /2037 16,675,000 2,102,293 584,082 $ 33,261,375 On July 19, 2012, Hutchinson Utilities Commission issued Public Utility Revenue Refunding Bonds, Series 2012A for $20,720,000, with an interest rate of 4.00% to 5.00%. The Commission issued the bonds to advance refund a portion of the 2013 through 2025 maturities of the Public Utility Revenue Bonds, Series 2003B. The Commission completed the refunding to reduce its debt service payment over the next 14 years by $1,638,277. This results in an economic gain (difference between the present values of the debt service payments on the old and new debt) of $1,245,620. On October 31, 2017, the Hutchinson Utilities Commission issued Public Utility Revenue Bonds of 2017 for $16,675,000. The proceeds of the issue were used to purchase and install new generators for the expansion of electric generation. B. MINIMUM DEBT PAYMENTS Annual debt service requirements to maturity for bonded debt is as follows: Year Ending December 31 Revenue Refunding Bonds, Series 2012A Principal Interest Revenue Bonds, Series 2017B Principal Interest 2019 $ 1,370,000 $ 609,350 $ 625,000 $ 558,656 2020 1,455,000 540,850 645,000 533,656 2021 1,565,000 482,650 675,000 507,856 2022 1,730,000 420,050 700,000 480,856 2023 1,825,000 333,550 730,000 452,856 2024-2028 5,955,000 585,800 4,105,000 1,802,280 2029-2033 4,810,000 1,101,658 2034-2037 4,385,000 339,326 $ 13,900,000 $ 2,972,250 $ 16,675,000 $ 5,777,144 25 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 6. LONG-TERM LIABILITIES (Cont'd) C. CHANGES IN LONG-TERM LIABILITIES Beginning Ending Due Within Balance Additions Reductions Balance One Year Revenue Bonds $ 16,675,000 $ $ $ 16,675,000 $ 625,000 Revenue Refunding Bonds 15,195,000 (1,295,000) 13,900,000 1,370,000 Bond Premium 2,321,358 (219,065) 2,102,293 219,065 Compensated Absences 528,831 391,048 (335,797) 584,082 23,873 Total Long -Term Liabilities $ 34,720,189 $ 391,048 $ (1,849,862) $ 33,261,375 $ 2,237,938 D. PLEDGED REVENUES Future revenue pledged for the payment of long-term debt is as follows: Bond Issue/ Percent Use of Proceeds/ of Total Term of Type Debt Service Pledge Revenue Refunding Bonds, Series 2012A Natural Gas Utility Charges 100% 2012-2026 Revenue Bonds, Series 2017B Electric Utility Charges 100% 2017-2037 NOTE 7. RISK MANAGEMENT Remaining Principal Pledged Principal and Interest Revenue and Interest Paid Received $ 16,872,250 $ 1,969,100 $ 11,080,727 22,452,144 606,763 28,562,552 The Commission purchases commercial insurance coverage through the League of Minnesota Cities Insurance Trust (LMCIT), which is a public entity risk pool currently operating as a common risk management and insurance program, with cities in the state. The Commission pays an annual premium to the LMCIT for its insurance coverage. The LMCIT is self-sustaining through commercial companies for excess claims. The Commission is covered through the pool for any claims incurred but unreported, but retains risk for the deductible portion of its insurance policies. The amount of these deductibles is considered immaterial to the financial statements. There were no significant reductions in insurance from the previous year or settlements in excess of insurance coverage for any of the past three fiscal years. 91 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 7. RISK MANAGEMENT (Cont'd) The Commission's workers' compensation insurance policy is retrospectively rated. With this type of policy, final premiums are determined after loss experience is known. The amount of premium adjustment for 2018 is estimated to be immaterial based on workers' compensation rates and salaries for the year. There are no other claims liabilities reported in the funds based on the requirements of accounting standards, which requires that a liability for claims be reported if information prior to the issuance of the financial statements indicates it is probable that a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. NOTE 8. DEFINED BENEFIT PENSION PLANS -STATEWIDE A. PLAN DESCRIPTION The Commission participates in the following cost -sharing multiple -employer defined benefit pension plans administered by the Public Employees Retirement Association of Minnesota (PERA). PERA's defined benefit pension plans are established and administered in accordance with Minnesota Statutes, Chapters 353 and 356. PERA's defined benefit pension plans are tax qualified plans under Section 401(a) of the Internal Revenue Code. General Employees Retirement Plan (GERP; General Employees Plan; accounted for in the General Employees Fund): All full-time and certain part-time employees of the Commission are covered by the General Employees Plan. General Employees Plan members belong to the Coordinated Plan. Coordinated Plan members are covered by Social Security. B. BENEFITS PROVIDED PERA provides retirement, disability, and death benefits. Benefit provisions are established by state statute and can only be modified by the state Legislature. Vested Terminated employees who are entitled to benefits, but are not receiving them yet, are bound by the provisions in effect at the time they last terminated their public service. GERP Benefits: General Employees Plan benefits are based on a member's highest average salary for any five successive years of allowable service, age, and years of credit at termination of service. Two methods are used to compute benefits for PERA's Coordinated Plan members. Members hired prior to July 1, 1989, receive the higher of Method 1 or Method 2 formulas. Only Method 2 is used for members hired after June 30, 1989. Under Method 1, the accrual rate for Coordinated members is 1.2% for each of the first 10 years of service and 1.7% for each additional year. The rates are 2.2% and 2.7%, respectively, for Basic members. Under Method 2, the accrual rate for Coordinated members is 1.7% for all years of service, and 2.7% for Basic members. The accrual rates for former MERF members is 2.0% for each of the first 10 years of service and 2.5% for each additional year. For members hired prior to July 1, 1989 a full annuity is available when age plus years of service equal 90 and normal retirement age is 65. For members hired on or after July 1, 1989 normal retirement age is the age for unreduced Social Security benefits capped at 66. 27 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 8. DEFINED BENEFIT PENSION PLANS - STATEWIDE (Cont'd) B. BENEFITS PROVIDED (Cont'd) GERP Benefits: (Cont'd) Beginning January 1, 2019, benefit recipients will receive a future annual increase equal to 50 percent of the Social Security Cost of Living Adjustment, not less than 1.0 percent and not more than 1.5 percent. For retirements on or after January 1, 2024, the first benefit increase is delayed until the retiree reaches Normal Retirement Age (not applicable to Rule of 90 retirees, disability benefit recipients, or survivors). A benefit recipient who has been receiving a benefit for at least 12 full months as of June 30 will receive a full increase. Members receiving benefits for at least one month but less than 12 full months as of June 30 will receive a pro rata increase. C. CONTRIBUTIONS Minnesota Statutes Chapter 353 sets the rates for employer and employee contributions. Contribution rates can only be modified by the state legislature. GERP Contributions: Coordinated Plan members were required to contribute 6.50 percent of their annual covered salary in fiscal year 2018; the Commission was required to contribute 7.50 percent for Coordinated Plan members. The Commission's contributions to the General Employees Fund for the year ended December 31, 2018 were $337,735. The Commission's contributions were equal to the required contributions as set by state statute. D. PENSION COSTS GERP Pension Costs: At December 31, 2018 the Commission reported a liability of $3,600,386 for its proportionate share of the General Employees Fund's net pension liability. The Commission net pension liability reflected a reduction due to the State of Minnesota's contribution of $16 million to the fund in 2019. The State of Minnesota is considered a non -employer contributing entity and the state's contribution meets the definition of a special funding situation. The State of Minnesota's proportionate share of the net pension liability associated with the Commission totaled $118,224. The net pension liability was measured as of June 30, 2018 and the total pension liability used to calculate the net pension liability was determined by an actuarial valuation as of that date. The Commission's proportion of the net pension liability was based on the Commission's contributions received by PERA during the measurement period for employer payroll paid dates from July 1, 2017 through June 30, 2018 relative to the total employer contributions received from all of PERA's participating employers. At June 30, 2018 the Commission's proportion share was 0.0649% which was an increase of 0.0005% from its proportion measured as of June 30, 2017. Post -retirement benefit increases were changed from 1.0% per year with a provision to increase to 2.5% upon attainment of 90% funding ratio to 50% of the Social Security Cost of Living Adjustment, not less than 1.0% and not more than 1.5%, beginning January 1, 2019; For the year ended December 31, 2018, the Commission recognized pension expense of $67,141 for its proportionate share of GERP's pension expense. In addition, the Commission recognized an additional $27,570 as pension expense (and grant revenue) for its proportionate share of the State of Minnesota's contribution of $6 million to the General Employees Fund. 28 HUTCHINSON UTILITIES COMMISSION NOTE 8 NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 DEFINED BENEFIT PENSION PLANS - STATEWIDE (Cont'd) D. PENSION COSTS (Cont'd) GERP Pension Costs: (Cont'd) At December 31, 2018, the Commission reported its proportionate share of GERP's deferred outflows of resources and deferred inflows of resources from the following sources: Differences between expected and actual economic experience Changes in actuarial assumptions Differences between projected and actual investment earnings Changes in proportion Contributions paid to PERA subsequent to measurement date Totals Deferred Deferred Outflows of Inflows of Resources Resources 94,595 $ 112,289 367,776 402,409 23,940 329,469 228,900 169,272 $ 655,583 $ 1,073,067 $169,272 reported as deferred outflows of resources related to pensions resulting from Commission contributions to subsequent to the measurement date will be recognized as a reduction of the net pension liability in the year ended December 31, 2019. Other amounts reported as deferred outflows and inflows of resources related to pensions will be recognized in pension expense as follows: Year ended December 31 2019 2020 2021 2022 E. ACTUARIAL ASSUMPTIONS Pension Expense Amount $ 44,171 (272,976) (282,806) (75,146) The total pension liability in the June 30, 2018 actuarial valuation was determined using the entry age normal actuarial cost method and the following actuarial assumptions: Actuarial Assumptions Inflation Salary Growth Investment Rate of Return GERP 2.50% per year 3.25% after 26 years of service 7.50% The total pension liability for each of the defined benefit cost -sharing plans was determined by an actuarial valuation as of June 30, 2018, using the entry age normal actuarial cost method. Inflation is assumed to be 2.50 percent for the General Employees Plan. Salary growth assumptions in the General Employees Plan decrease in annual increments from 11.25 percent after one year of service, to 3.25 percent after 26 years of service. 29 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 8. DEFINED BENEFIT PENSION PLANS - STATEWIDE (Cont'd) E. ACTUARIAL ASSUMPTIONS (Cont'd) Mortality rates for all plans are based on RP-2014 mortality tables. The tables are adjusted slightly to fit PERA's experience. Actuarial assumptions for the General Employees Plan are reviewed every four to six years. The most recent six -year experience study for the General Employees Plan was completed in 2015. Economic assumptions were updated in 2014 based on a review of inflation and investment return assumptions. The following changes in actuarial assumptions occurred in 2018: GERP: The morality projection scale was changed from MP-2015 to MP-2017. The assumed benefit increase was changed from 1.00 percent per year through 2044 and 2.50 percent per year thereafter to 1.25 percent per year. The State Board of Investment, which manages the investments of PERA, prepares an analysis of the reasonableness on a regular basis of the long-term expected rate of return using a building-block method in which best -estimate ranges of expected future rates of return are developed for each major asset class. These ranges are combined to produce an expected long-term rate of return by weighting the expected future rates of return by the target asset allocation percentages. The target allocation and best estimates of geometric real rates of return for each major asset class are summarized in the following table: Long -Term Expected Asset Class Target Allocation Real Rate of Return Domestic Stocks 39.00% 5.10% International Stocks 19.00% 5.30% Bonds 20.00% 0.75% Alternative Assets 20.00% 5.90% Cash 2.00% 0.00% Total: 100.00% F. DISCOUNT RATE The discount rate used to measure the total pension liability in 2018 was 7.50 percent. The projection of cash flows used to determine the discount rate assumed that contributions from plan members and employers will be made at rates set in Minnesota Statutes. Based on these assumptions, the fiduciary net positions of the General Employees Fund. Therefore, the long-term expected rate of return on pension plan investments was applied to all periods of projected benefit payments to determine the total pension liability. 30 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 G. PENSION LIABILITY SENSITIVITY The following presents the Commission's proportionate share of the net pension liability for all plans it participates in, calculated using the discount rate disclosed in the preceding paragraphs, as well as what the Commission's proportionate share of the net pension liability would be if it were calculated using a discount rate 1 percentage point lower or 1 percentage point higher than the current discount rate: GERF 1 % Lower 6.50% $ 5,851,088 Current Discount Rate 7.50% 3,600,386 1 % Higher 8.50% 1,742,496 H. PENSION PLAN FIDUCIARY NET POSITION Detailed information about each pension plan's fiduciary net position is available in a separately -issued PERA financial report that includes financial statements and required supplementary information. That report may be obtained on the Internet at www.mnpera.org. NOTE 9. DEFERRED COMPENSATION PLAN The Commission offers its employees a deferred compensation plan created in accordance with Internal Revenue Code Section 457. The plan, available to all Commission employees, permits them to defer a portion of their salary into future years. Participation in the plan is optional. The deferred compensation is not available to employees until termination, retirement, death or unforeseeable emergency. Investments are managed by the plan's trustee under one of four investment options, or a combination thereof. The choice of the investment option(s) is made by the participants. NOTE 10. OTHER POST -EMPLOYMENT BENEFITS (OPEB) PLAN The Commission adopted Governmental Accounting Standards Board (GASB) Statement No. 75, Accounting and Financial Reporting for Postemployment Benefits Other than Pensions. This implementation allows the Commission to report its total OPEB liability, deferred inflows of resources and deferred outflows of resources, and OPEB expense and to reflect an actuarially determined liability for the present value of projected future benefits for retired and active employees less the OPEB plan's fiduciary net position on the financial statements. A. PLAN DESCRIPTION The Commission operates a single -employer retiree benefit plan the Plan that provides health, dental, and life insurance to eligible employees and their spouses through the Commission's commercial insurance plans. There are 50 active participants and 0 retired participants. Benefit and eligibility provisions are established through negotiations between the Commission and employee groups including a union. The union contract is renegotiated each two-year bargaining period. The Plan does not issue a publicly available financial report. No assets are accumulated in a trust that meets all of the criteria in GASB Statement No. 75, paragraph 4. 31 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 10. OTHER POST -EMPLOYMENT BENEFITS (OPEB) PLAN (Cont'd) B. TOTAL OPEB LIABILITY The Commission's total OPEB liability of $96,256 was measured as of December 31, 2017, and was determined by an actuarial valuation as of that date. Update procedures were used to roll forward the total OPEB liability to December 31, 2018. C. CHANGES IN TOTAL OPEB LIABILITY Changes in the total OPEB liability were as follows: Total OPEB Liability Balance at December 31, 2017 $ 83,203 Changes for the year Service Cost 5,475 Interest 3,379 Changes of assumptions or other inputs 4,199 Net changes 13,053 Balance at December 31, 2018 $ 96,256 Changes of assumptions and other inputs reflect a change in the discount rate from 3.81 % in 2017 to 3.31 % in 2018. Sensitivity of the total OPEB liability to changes in the discount rate. The following presents the total OPEB liability of the Commission, as well as what the Commission's total OPEB liability would be if it were calculated using a discount rate that is 1-percentage-point lower (2.31%) or 1-percentage-point higher (4.31 %) than the current discount rate: Total OPEB Liability 1.0% Decrease 1.0% Increase in Discount Discount Rate in Discount Rate (2.31 %) (3.31 %) Rate (4.31 %) $ 105,019 $ 96,256 $ 87,990 Sensitivity of the total OPEB liability to changes in the healthcare cost trend rates. The following presents the total OPEB liability of the Commission, as well as what the Commission's total OPEB liability would be if it were calculated using healthcare cost trend rates that are 1-percentage-point lower (5.30% decreasing to 3.40%) or 1-percentage-point higher (7.30% decreasing to 5.40%) than the current healthcare cost trend rates: Healthcare Cost 1.0% Decrease Trend Rates 1.0% Increase (5.30% (6.30% (7.30% decreasing decreasing decreasing to 3.40%) to 4.40%) to 5.40%) Total OPEB Liability $ 83,873 $ 96,256 $ 110,939 32 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 10. OTHER POST -EMPLOYMENT BENEFITS (OPEB) PLAN (Cont'd) D. OPEB EXPENSE. DEFERRED OUTFLOWS OF RESOURCES AND DEFERRED INFLOWS OF RESOURCES RELATED TO OPEB For the year ended December 31, 2018, the Commission recognized OPEB expense of $9,898. At December 31, 2018, the Commission reported deferred outflows of resources and deferred inflows of resources related to OPEB from the following sources: Contributions paid subsequent to measurement date Deferred Deferred Outflows of Inflows of Resources Resources 3,155 $ 0 $3,155 reported as deferred outflows of resources related to OPEB resulting from Commission contributions to subsequent to the measurement date will be recognized as a reduction of the total OPEB liability in the year ended December 31, 2019. E. ACTUARIAL METHODS AND ASSUMPTIONS The total OPEB liability in the December 31, 2017 actuarial valuation was determined using the following actuarial assumptions and other inputs, applied to all periods included in the measurement, unless otherwise specified: Inflation Salary Increases Retiree's Share of Benefit -Related Costs 2.75% Based on the most recently disclosed assumptions for the pension plan in which the employee participates. Assumed to increase with healthcare trend rates. A discount rate of 3.31 % was applied in the measurement of the total OPEB liability. The discount rate is based on the index rate for 20-year, tax-exempt general obligation municipal bonds with an average rating of AA/Aa or higher. Mortality rates were based on the RP-2000 Healthy Annuitant Mortality Table for Males or Females, as appropriate, with adjustments for mortality improvements based on Scale AA. NOTE 11. MAJOR CUSTOMERS The Electric Division derived approximately 60.22% of utility revenue from the top five major customers. The Natural Gas Division derived approximately 46.35% of its utility revenue from the top five major customers. NOTE 12. RECLASSIFICATIONS Certain immaterial prior year financial statement amounts have been reclassified to conform to the current year's presentation. There was no affect on total net position. 33 HUTCHINSON UTILITIES COMMISSION NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 NOTE 13. COMMITMENTS A. PURCHASED POWER The Commission is committed to purchase 25 MW of its power requirements from Missouri River Energy Services pursuant to the Power Sale Agreement dated April 28, 2010. This contract is effective through January 1, 2046. B. PAYMENT IN LIEU OF TAXES The Commission is committed to contribute a portion of its total operating revenue to the City of Hutchinson in lieu of the payment of taxes pursuant to the Resolution No. 14853 dated February 10, 2018. C. CONSTRUCTION PROJECTS The Commission has the following active construction projects: Vendor Caterpillar Power Generation Systems, LLC Fagen, Inc. Quade Electric, Inc. Project Units 6 & 7 Generators Units 6 & 7 Mechanical Work Units 6 & 7 Electrical Work NOTE 14. DEFERRED OUTFLOWS AND INFLOWS OF RESOURCES Contract Amount $ 9,141,362 3,425,884 396,730 Remaining Commitment $ 273,705 2,047,096 372,223 The following is a summary of the major components of deferred outflows and inflows as presented in the Statement of Net Position: Related to Pensions Related to OPEB Total Deferred Deferred Outflows of Inflows of Resources Resources $ 655,583 $ 1,073,067 3,155 $ 658,738 $ 1,073,067 34 HUTCHINSON UTILITIES COMMISSION NOTE 15 NOTES TO THE FINANCIAL STATEMENTS DECEMBER 31, 2018 PRIOR PERIOD ADJUSTMENT The beginning net position of the Commission has been decreased to reflect a change in accounting principle. As mentioned in Note 10, the Commission implemented GASB 75 which records the Commission's total other post -employment benefits liability, deferred inflows of resources and deferred outflows of resources, and other post -employment benefits expense on the Commission's financial statements. Prior year partial comparative information does not reflect this change in accounting principle because the benefit plan in which the Commission participates has not made this information available. The net position, beginning of year, as originally stated, prior period adjustment, and net position, beginning of year, as restated as of December 31, 2018 are summarized in the following table: Net Position, Beginning of Net Position, Year, as Beginning of Originally Prior Period Year, as Stated Adjustment Restated $ 66,777,958 $ (83,203) $ 66,694,755 35 REQUIRED SUPPLEMENTARY INFORMATION This page intentionally left blank HUTCHINSON UTILITIES COMMISSION SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY DECEMBER 31, 2018 Employer's Proportionate Share of the Net Pension Liability (Asset) Employer's State's and the State's Proportionate Proportionate Proportionate Share of the Employer's Share of the Share of the Net Pension Plan Fiduciary Employer's Proportionate Net Pension Net Pension Employer's Liability (Asset) Net Position Proportion Share of the Liability (Asset) Liability (Asset) Covered- as a Percentage of as a Percentage Fiscal of the Net Net Pension Associated with Associated with Employee its Covered- of the Total Year Pension Liability (Asset) the Employer the Employer Payroll Employee Payroll Pension Ending Liability (Asset) (a) (b) (a+b) (c) ((a+b)/c) Liability Pensions GERP 6/30/2018 0.0649% $ 3,600,386 $ 118,224 $ 3,718,610 $ 4,376,690 84.96% 79.53% 6/30/2017 0.0644% 4,111,253 51,661 4,162,914 4,146,010 100.41% 75.90% 6/30/2016 0.0694% 5,634,936 73,588 5,708,524 4,334,384 131.70% 68.90% 6/30/2015 0.0714% 3,700,319 3,700,319 4,241,304 87.24% 78.20% The Commission implemented GASB Statement No. 68 for fiscal year ended December 31, 2015. Information for prior years is not available. 36 HUTCHINSON UTILITIES COMMISSION SCHEDULE OF EMPLOYER CONTRIBUTIONS DECEMBER 31, 2018 Contributions Contributions in Relation as a Percentage Statutorily to the Statutorily Contribution Covered- of Covered - Required Required Deficiency Employee Employee Fiscal Year Contribution Contribution (Excess) Payroll Payroll Ending (a) (b) (a-b) (d) (b/d) Pensions GERP 12/31/2018 $ 337,735 $ 337,735 $ $ 4,503,133 7.50% 12/31/2017 314,977 314,977 4,201,039 7.50% 12/31/2016 310,915 310,915 4,145,538 7.50% 12/31/2015 327,065 327,065 4,360,868 7.50% The Commission implemented GASB Statement No. 68 for fiscal year ended December 31, 2015. Information for prior years is not available. 37 HUTCHINSON UTILITIES COMMISSION SCHEDULE OF CHANGES IN THE COMMISSION'S TOTAL OPEB LIABILITY DECEMBER 31, 2018 Service Cost Interest Changes in Assumptions Net Change in Total OPEB Liability Total OPEB Liability - Beginning of Year Total OPEB Liability - End of Year Covered Employee Payroll Total OPEB Liability as a % of Covered Employee Payroll Measurement Date 12/31 /2017 $ 5,475 3,379 4,199 13,053 83,203 $ 96,256 $ 4,206,868 2.29% The Commission implemented GASB Statement No. 75 for fiscal year ended December 31, 2018. Information for prior years is not available. W HUTCHINSON UTILITIES COMMISSION NOTES TO REQUIRED SUPPLEMENTARY INFORMATION DECEMBER 31, 2018 NOTE 1. CHANGES IN PLAN PROVISIONS A. GENERAL EMPLOYEE RETIREMENT PLAN 2018 Changes: No changes. 2017 Changes: No changes. 2016 Changes: No changes. 2015 Changes: On January 1, 2015 the Minneapolis Employees Retirement Fund was merged into the General Employees Fund, which increased the total pension liability by $1.1 billion and increased the fiduciary plan net position by $892 million. Upon consolidation, state and employer contributions were revised. B. OTHER POST -EMPLOYMENT BENEFITS (OPEB) PLAN NOT ADMINISTRATED IN A TRUST 2018 Changes: No changes. 2017 Changes: No changes. NOTE 2. CHANGES IN ACTUARIAL ASSUMPTIONS A. GENERAL EMPLOYEE RETIREMENT PLAN (GERP) 2018 Changes: The mortality projection was changes from MP-2015 to MP-2017. The assumed benefit increase was changed from 1.00% per year through 2044 and 2.50% per year thereafter to 1.25% per year. 2017 Changes: The Combined Service Annuity (CSA) loads were changed from 0.8% for active members and 60% for vested and non -vested deferred members. The revised CSA loads are now 0.0% for active member liability, 15.0% for vested deferred member liability and 3.0% for non -vested deferred member liability. The assumed post -retirement benefit increase rate was changed from 1.0% per year for all years to 1.0% per year through 2044 and 2.5% per year thereafter. 2016 Changes: The assumed post -retirement benefit increase rate was changed from 1.0% per year through 2035 and 2.5% per year thereafter to 1.0% per year for all years. The assumed investment return was changed from 7.9% to 7.5%. The single discount rate was changed from 7.9% to 7.5%. 39 HUTCHINSON UTILITIES COMMISSION NOTES TO REQUIRED SUPPLEMENTARY INFORMATION DECEMBER 31, 2018 NOTE 2. CHANGES IN ACTUARIAL ASSUMPTIONS (Cont'd) A. GENERAL EMPLOYEE RETIREMENT PLAN (GERP) (Cont'd) 2016 Changes: (Cont'd) Other assumptions were changed pursuant to the experience study dated June 30, 2015. The assumed future salary increases, payroll growth, and inflation were decreased by 0.25% to 3.25% for payroll growth and 2.50% for inflation. 2015 Changes: The assumed post -retirement benefit increase rate was changed from 1.0% per year through 2030 and 2.5% per year thereafter to 1.0% per year through 2035 and 2.5% per year thereafter. B. OTHER POST -EMPLOYMENT BENEFITS (OPEB) PLAN NOT ADMINISTRATED IN A TRUST 2018 Changes: No changes. 2017 Changes: No changes. 40 This page intentionally left blank SUPPLEMENTARY INFORMATION This page intentionally left blank HUTCHINSON UTILITIES COMMISSION COMBINING STATEMENT OF NET POSITION DECEMBER 31, 2018 ASSETS AND DEFERRED OUTFLOWS OF RESOURCES Assets Current Assets Cash and Investments Receivables Accounts Receivable (Net of Allowance for Doubtful Accounts of $34,280 and $31,973, Respectively) Interest Receivable Sales Tax Receivable Inventory Prepaid Items Total Current Assets Noncurrent Assets Restricted Assets Cash and Investments Capital Assets Assets Not Being Depreciated Other Capital Assets, Net of Depreciation Net Capital Assets Total Noncurrent Assets Total Assets Deferred Outflows of Resources Total Assets and Deferred Outflows of Resources LIABILITIES, DEFERRED INFLOWS OF RESOURCES AND NET POSITION Liabilities Current Liabilities Current Portion of Long -Term Liabilities Bonds Payable Bond Premium Accrued Vacation Accounts Payable Customer Deposits Accrued Expenses Interest Salaries Payable Total Current Liabilities Noncurrent Liabilities Net Pension Liability Total OPEB Liability Bonds Payable Bond Premium Accrued Vacation Accrued Severance Total Long -Term Liabilities Total Liabilities Deferred Inflows of Resources Net Position Net Investment in Capital Assets Restricted Unrestricted Total Net Position Total Liabilities, Deferred Inflows of Resources and Net Position Natural Electric Gas Division Division Total 9,971,568 $ 9,887,167 $ 19,858,735 2,056,148 1,577,718 3,633,866 23,632 23,632 47,264 33,090 33,090 1,195, 287 463,463 1,658,750 798 59,478 60,276 13,280,523 12,011,458 25,291,981 5,683,540 2,353,590 8,037,130 13,551,279 3,899,919 17,451,198 35, 031, 971 25, 597, 805 60, 629, 776 48,583,250 29,497,724 78,080,974 54,266,790 31,851,314 86,118,104 67,547,313 43,862,772 111,410,085 494,053 164,685 658,738 $ 68,041,366 $ 44,027,457 $ 112,068,823 $ 625,000 $ 1,370,000 $ 1,995,000 33,457 185,608 219,065 18,320 5,553 23,873 2,496,679 968,858 3,465,537 292,731 157,624 450,355 46,555 50,779 97,334 149,615 38,206 187,821 3,662,357 2,776,628 6,438,985 2,700,290 900,097 3,600,387 72,192 24,064 96,256 16,050,000 12,530,000 28,580,000 599,437 1,283,791 1,883,228 348,071 105,508 453,579 77,139 29,491 106,630 19,847,129 14,872,951 34,720, 080 23,509,486 17,649,579 41,159,065 804,800 268,267 1,073,067 35,837,922 14,128,325 49,966,247 2,353,590 2,353,590 7,889,158 9,627,696 17,516,854 43,727,080 26,109,611 69,836,691 $ 68,041,366 $ 44,027,457 $ 112,068,823 41 HUTCHINSON UTILITIES COMMISSION COMBINING SCHEDULE OF REVENUES AND EXPENSES YEAR ENDED DECEMBER 31, 2018 OPERATING REVENUES Electric Energy Sales Natural Gas Sales Other Operating Revenues Total Operating Revenues OPERATING EXPENSES Production Operations Maintenance Purchased Power/Gas Other Power Supply Transmission Operations Maintenance Distribution Operations Maintenance Customer Accounts Expense Sales Expense Administrative and General Depreciation Contribution to City of Hutchinson Total Operating Expenses Operating Income (Loss) NONOPERATING REVENUES (EXPENSES) Interest Income Merchandise and Contract Work, Net Miscellaneous Income Gain (Loss) on Disposal of Assets Bond Premium Interest Expense Total Nonoperating Revenues (Expenses) Change in Net Position NET POSITION, BEGINNING OF YEAR, AS ORIGINALLY STATED PRIOR PERIOD ADJUSTMENT NET POSITION, BEGINNING OF YEAR, AS RESTATED NET POSITION, END OF YEAR Electric Natural Gas Division Division Total $ 28,562,552 $ $ 28,562,552 11,080,727 11,080,727 182,837 1,667,019 1,849,856 28,745,389 12,747,746 41,493,135 3,462,933 3,462,933 421,012 421,012 14,633,534 6,084,090 20,717,624 528,831 528,831 2,624,276 148,048 2,772,324 27,843 843 28,686 917,378 664,898 1,582,276 403,834 173,361 577,195 223,038 192,484 415,522 286,185 126,422 412,607 1,306,632 529,928 1,836,560 2,770,697 1,033,788 3,804,485 1,029,711 369,142 1,398,853 28,635,904 9,323,004 37,958,908 109,485 3,424,742 3,534,227 204,498 204,496 408,994 (36,558) 49,070 12,512 71,834 33,610 105,444 11,789 6,063 17,852 33,457 185,608 219,065 (568,218) (671,143) (1,239,361) (283,198) (192,296) (475,494) (173,713) 3,232,446 3,058,733 43,963,195 22,897,966 66,861,161 (62,402) (20,801) (83,203) 43,900,793 22,877,165 66,777,958 $ 43,727,080 $ 26,109,611 $ 69,836,691 42 HUTCHINSON UTILITIES COMMISSION SCHEDULE OF DIVISIONS CASH FLOWS YEAR ENDED DECEMBER 31, 2018 CASH FLOWS FROM OPERATING ACTIVITIES Receipts from Customers Payments Received from Other Sources Payments to Suppliers Payments to Employees Net Cash Provided (Used) by Operating Activities CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES Other Noncapital Income CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES Additions to Utility Plant Principal Payments on Long -Term Debt Proceeds from Sale of Assets Interest Paid on Long -Term Debt Net Cash Provided (Used) by Capital and Related Financing Activities CASH FLOWS FROM INVESTING ACTIVITIES Interest Income Net Increase (Decrease) in Cash and Cash Equivalents CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR CASH AND CASH EQUIVALENTS, END OF YEAR RECONCILIATION OF CASH AND CASH EQUIVALENTS Current Assets - Cash and Investments Restricted Assets - Cash and Investments Total Cash and Cash Equivalents See Accompanying Notes to the Financial Statements 43 Electric Natural Gas Division Division Total $ 28,565,659 $ 11,570,029 $ 40,135,688 184,490 1,667,019 1,851,509 (21,762,459) (8,693,726) (30,456,185) (3,620,656) (922,726) (4,543,382) 3,367,034 3,620,596 6,987,630 35,276 82,680 117,956 (10,627,649) (427,473) (11,055,122) (1,295,000) (1,295,000) 11,789 6,063 17,852 (612,216) (676,539) (1,288,755) (11,228,076) (2,392,949) (13,621,025) 199,905 199,903 399,808 (7,625,861) 1,510,230 (6,115,631) 23,280,969 10,730,527 34,011,496 $ 15,655,108 $ 12,240,757 $ 27,895,865 $ 9,971,568 $ 9,887,167 $ 19,858,735 5,683,540 2,353,590 8,037,130 $ 15,655,108 $ 12,240,757 $ 27,895,865 HUTCHINSON UTILITIES COMMISSION SCHEDULE OF DIVISIONS CASH FLOWS YEAR ENDED DECEMBER 31, 2018 Electric Natural Gas Division Division Total RECONCILIATION OF OPERATING INCOME (LOSS) TO CASH FLOWS FROM OPERATING ACTIVITIES Operating Income (Loss) $ 109,485 $ 3,424,742 $ 3,534,227 Adjustments to Reconcile Operating Income (Loss) to Net Cash Provided (Used) by Operating Activities Depreciation 2,770,697 1,033,788 3,804,485 Pension Related Adjustments (111,520) (37,173) (148,693) OPEB Related Adjustments 7,424 2,476 9,900 (Increase) Decrease in Assets Accounts Receivable (4,976) 484,950 479,974 Sales Tax Receivable 1,653 1,653 Inventory (34,240) (58,930) (93,170) Prepaid Items 5,798 71,352 77,150 Increase (Decrease) in Liabilities Accounts Payable 541,133 (1,315,443) (774,310) Customer Deposits 8,083 4,352 12,435 Salaries Payable 27,443 1,285 28,728 Compensated Absences 46,054 9,197 55,251 Net Cash Provided (Used) by Operating Activities $ 3,367,034 $ 3,620,596 $ 6,987,630 See Accompanying Notes to the Financial Statements 44 HUTCHINSON UTILITIES COMMISSION STATEMENT OF NET POSITION ELECTRIC DIVISION DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS AS OF DECEMBER 31. 2017 2018 2017 ASSETS AND DEFERRED OUTFLOWS OF RESOURCES Assets Current Assets Cash and Investments $ 9,971,568 $ 7,650,028 Receivables Accounts Receivable (Net of Allowance for Doubtful Accounts of $34,280 and $46,236, Respectively) 2,056,148 2,051,172 Interest Receivable 23,632 19,039 Sales Tax Receivable 33,090 34,743 Inventory 1,195,287 1,161,047 Prepaid Items 798 6,596 Total Current Assets 13,280,523 10,922,625 Noncurrent Assets Restricted Assets Cash and Investments 5,683,540 15,630,941 Capital Assets Assets Not Being Depreciated 13,551,279 3,573,269 Other Capital Assets, Net of Depreciation 35,031,971 37,153,029 Net Capital Assets 48,583,250 40,726,298 Total Noncurrent Assets 54,266,790 56,357,239 Total Assets 67,547,313 67,279,864 Deferred Outflows of Resources 494,053 752,887 Total Assets and Deferred Outflows of Resources $ 68,041,366 $ 68,032,751 LIABILITIES, DEFERRED INFLOWS OF RESOURCES AND NET POSITION Liabilities Current Liabilities Current Portion of Long -Term Liabilities Bonds Payable $ 625,000 $ Bond Premium 33,457 33,457 Accrued Vacation 18,320 16,187 Accounts Payable 2,496,679 1,955,546 Customer Deposits 292,731 284,648 Accrued Expenses Interest 46,555 90,553 Salaries Payable 149,615 122,172 Total Current Liabilities 3,662,357 2,502,563 Noncurrent Liabilities Net Pension Liability 2,700,290 3,083,440 Total OPEB Liability 72,192 Bonds Payable 16,050,000 16,675,000 Bond Premium 599,437 632,894 Accrued Vacation 348,071 307,549 Accrued Severance 77,139 73,740 Total Noncurrent Liabilities 19,847,129 20,772,623 Total Liabilities 23,509,486 23,275,186 Deferred Inflows of Resources 804,800 794,370 Net Position Net Investment in Capital Assets 35,837,922 37,806,845 Restricted 1,209,043 Unrestricted 7,889,158 4,947,307 Total Net Position 43,727,080 43,963,195 Total Liabilities, Deferred Inflows of Resources and Net Position $ 68,041,366 $ 68,032,751 45 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - ELECTRIC DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 OPERATING REVENUES Utility Revenues Residential General Service Industrial Street Lighting Resale Total Utility Revenues Other Operating Revenues Penalties/Fees Security Lights Total Other Operating Revenues Total Operating Revenues OPERATING EXPENSES Production Operations Supervision and Engineering Other Employee Benefits Fuels Station Gas for Generation Transportation Waste Disposal Total Operations Maintenance Structures Generating Units Other Equipment Total Maintenance Total Production Power Costs Purchased Power 2018 2017 Over(Under) Budget Actual Budget Actual $ 5,358,325 $ 5,601,482 $ 243,157 $ 5,341,820 9,057,026 9,523,924 466,898 9,050,034 10,762,454 10,218,577 (543,877) 10,778,629 147,384 147,470 86 147,484 2,519,200 3,071,099 551,899 2,171,853 27,844,389 28,562,552 718,163 27,489,820 198,800 171,832 (26,968) 155,879 10,000 11,005 1,005 11,280 208,800 182,837 (25,963) 167,159 28,053,189 28,745,389 692,200 27,656,979 1,199,394 1,043,938 (155,456) 986,955 585,124 598,282 13,158 93,913 31,376 7,620 (23,756) 12,149 129,500 83,001 (46,499) 98,675 831,306 1,046,882 215,576 804,300 656,366 656,366 651,699 26,000 26,844 844 22,382 3,459,066 3,462,933 3,867 2,670,073 10,000 9,583 (417) 8,938 533,881 304,956 (228,925) 285,528 40,000 106,473 66,473 107,265 583,881 421,012 (162,869) 401,731 4,042,947 3,883,945 (159,002) 3,071,804 14,000,000 14,633,534 633,534 14,257,952 46 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - ELECTRIC DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 2018 2017 Over(Under) Budget Actual Budget Actual OPERATING EXPENSES (Cont'd) Other Power Supply Supervision and General Salaries $ 403,557 $ 491,967 $ 88,410 $ 337,455 Training 1,000 264 (736) 2,343 Professional Services 36,600 36,600 36,600 Total Other Power Supply 441,157 528,831 87,674 376,398 Transmission Operations Transmission 2,630,000 2,454,965 (175,035) 2,462,733 Station 145,000 169,311 24,311 162,394 Total Operations 2,775,000 2,624,276 (150,724) 2,625,127 Maintenance Plant and Equipment 52,155 27,843 (24,312) 82,311 Total Transmission 2,827,155 2,652,119 (175,036) 2,707,438 Distribution Operations Supervision and Engineering 599,520 328,705 (270,815) 301,448 Other Employee Benefits 380,000 338,285 (41,715) Line 72,082 86,928 14,846 76,930 Meter 49,847 37,315 (12,532) 37,189 Territory Service Agreement 5,000 3,485 (1,515) 12,210 Other 56,000 122,660 66,660 120,219 Total Operations 1,162,449 917,378 (245,071) 547,996 Maintenance Station Equipment 12,605 67,706 55,101 18,689 Underground Lines 210,552 161,456 (49,096) 189,034 Lines Transformers 13,876 22,483 8,607 13,062 Street Lighting 75,440 97,816 22,376 81,510 Other Equipment 45,862 54,373 8,511 43,120 Total Maintenance 358,335 403,834 45,499 345,415 Total Distribution 1,520,784 1,321,212 (199,572) 893,411 Customer Accounts Expense Meter Reading 23,299 19,421 (3,878) 51,216 Collection 164,299 142,486 (21,813) 141,677 Other Employee Benefits 600 9,392 8,792 9,980 Uncollectible Accounts 5,500 (4,247) (9,747) 30,612 Customer Services 59,720 55,986 (3,734) 41,557 Meetings and Training 2,750 (2,750) Total Customer Accounts Expense 256,168 223,038 (33,130) 275,042 47 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - ELECTRIC DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 2018 2017 Over(Under) Budget Actual Budget Actual OPERATING EXPENSES (Cont'd) Sales Expense Salaries $ 67,392 $ 38,788 $ (28,604) $ 46,640 Conservation 279,050 247,397 (31,653) 184,450 Total Sales Expense 346,442 286,185 (60,257) 231,090 Administrative and General Supervision and General Salaries 449,079 454,452 5,373 427,182 Office Supplies 277,400 257,839 (19,561) 362,898 Outside Services Employed 80,306 120,425 40,119 118,129 Property Insurance 86,000 114,394 28,394 111,072 Medical Insurance 167,000 138,747 (28,253) 611,838 Other Employee Benefits 11,250 71,326 60,076 684,291 Regulatory 30,000 21,573 (8,427) 20,912 Commissioners Salaries 15,836 15,650 (186) 16,140 Travel 9,000 4,586 (4,414) 3,719 Miscellaneous 78,000 62,222 (15,778) 57,668 Maintenance of General Plant 46,938 45,418 (1,520) 39,142 Total Administrative and General 1,250,809 1,306,632 55,823 2,452,991 Depreciation 2,900,000 2,770,697 (129,303) 2,830,636 Contribution to City of Hutchinson Payment in Lieu of Taxes 882,327 882,327 681,816 Roadway Lighting 147,384 147,384 147,384 Total Contribution to City of Hutchinson 1,029,711 1,029,711 0 829,200 Total Operating Expenses 28,615,173 28,635,904 20,731 27,925,962 Operating Income (Loss) (561,984) 109,485 671,469 (268,983) 48 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - ELECTRIC DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 2018 2017 Over(Under) Budget Actual Budget Actual NONOPERATING REVENUES (EXPENSES) Interest Income $ 50,000 $ 204,498 $ 154,498 $ 78,873 Merchandise and Contract Work, Net (36,558) (36,558) 5,171 Miscellaneous Income 71,834 71,834 142,012 Gain (Loss) on Disposal of Assets 11,789 11,789 48,295 Bond Premium 33,457 33,457 5,576 Interest Expense (609,163) (568,218) 40,945 (288,264) Total Nonoperating Revenues (Expenses) (559,163) (283,198) 275,965 (8,337) Change in Net Position $ (1,121,147) (173,713) $ 947,434 (277,320) NET POSITION, BEGINNING OF YEAR, AS ORIGINALLY STATED 43,963,195 44,240,515 PRIOR PERIOD ADJUSTMENT (62,402) NET POSITION, BEGINNING OF YEAR, AS RESTATED 43,900,793 NET POSITION, END OF YEAR $ 43,727,080 44,240,515 $ 43,963,195 49 HUTCHINSON UTILITIES COMMISSION STATEMENT OF NET POSITION NATURAL GAS DIVISION DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS AS OF DECEMBER 31. 2017 2018 2017 ASSETS AND DEFERRED OUTFLOWS OF RESOURCES Assets Current Assets Cash and Investments $ 9,887,167 $ 8,377,741 Receivables Accounts Receivable (Net of Allowance for Doubtful Accounts of $31,973 and $24,896, Respectively) 1,577,718 2,062,668 Interest Receivable 23,632 19,039 Inventory 463,463 404,533 Prepaid Items 59,478 130,830 Total Current Assets 12,011,458 10,994,811 Noncurrent Assets Restricted Assets Cash and Investments 2,353,590 2,352,786 Capital Assets Assets Not Being Depreciated 3,899,919 3,899,919 Other Capital Assets, Net of Depreciation 25,597,805 26,204,122 Net Capital Assets 29,497,724 30,104,041 Total Noncurrent Assets 31,851,314 32,456,827 Total Assets 43,862,772 43,451,638 Deferred Outflows of Resources 164,685 250,962 Total Assets and Deferred Outflows of Resources $ 44,027,457 $ 43,702,600 LIABILITIES, DEFERRED INFLOWS OF RESOURCES AND NET POSITION Liabilities Current Liabilities Current Portion of Long -Term Liabilities Bonds Payable $ 1,370,000 $ 1,295,000 Bond Premium 185,608 185,608 Accrued Vacation 5,553 5,139 Accounts Payable 968,858 2,284,301 Customer Deposits 157,624 153,272 Accrued Expenses Interest 50,779 56,175 Salaries Payable 38,206 36,921 Total Current Liabilities 2,776,628 4,016,416 Noncurrent Liabilities Net Pension Liability 900,097 1,027,813 Total OPEB Liability 24,064 Bonds Payable 12,530,000 13,900,000 Bond Premium 1,283,791 1,469,399 Accrued Vacation 105,508 97,635 Accrued Severance 29,491 28,581 Total Noncurrent Liabilities 14,872,951 16,523,428 Total Liabilities 17,649,579 20,539,844 Deferred Inflows of Resources 268,267 264,790 Net Position Net Investment in Capital Assets 14,128,325 13,254,034 Restricted 2,353,590 2,352,786 Unrestricted 9,627,696 7,291,146 Total Net Position 26,109,611 22,897,966 Total Liabilities, Deferred Inflows of Resources and Net Position $ 44,027,457 $ 43,702,600 50 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - NATURAL GAS DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 OPERATING REVENUES Utility Revenues Residential Commercial Industrial Total Utility Revenues Other Operating Revenues Gas Transportation Contract - New Ulm Transportation - Electric Division Penalties/Fees Total Other Operating Revenues Total Operating Revenues OPERATING EXPENSES Purchased Natural Gas Transmission Operations Supervision and Engineering Other Total Operations Maintenance Supervision and Engineering Other Total Maintenance Total Transmission Distribution Operations Supervision and Engineering Other Employee Benefits Mains and Services Meters Other Total Operations Maintenance Mains and Services Meters Other Equipment Total Maintenance Total Distribution 2018 2017 Over(Under) Budget Actual Budget Actual $ 3,812,700 $ 4,139,639 $ 326,939 $ 3,937,048 3,388,924 3,070,904 (318,020) 3,019,230 3,236,792 3,870,184 633,392 3,842,863 10,438,416 11,080,727 642,311 10,799,141 739,440 940,990 201,550 902,042 656,366 656,366 651,699 71,400 69,663 (1,737) 25,754 1,467,206 1,667,019 199,813 1,579,495 11,905,622 12,747,746 842,124 12,378,636 5,600,000 6,084,090 484,090 6,883,154 124,765 100,946 (23,819) 77,029 51,000 47,102 (3,898) 45,782 175,765 148,048 (27,717) 122,811 1,742 75 (1,667) 1,124 10,000 768 (9,232) 3,524 11,742 843 (10,899) 4,648 187,507 148,891 (38,616) 127,459 287,917 177,109 (110,808) 171,082 252,571 331,919 79,348 112,666 171,270 95,477 (75,793) 124,749 872 18,415 17,543 19,765 70,250 41,978 (28,272) 37,208 782,880 664,898 (117,982) 465,470 179,698 110,324 (69,374) 116,256 25,266 (25,266) 1,412 201,759 63,037 (138,722) 41,054 406,723 173,361 (233,362) 158,722 1,189,603 838,259 (351,344) 624,192 51 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - NATURAL GAS DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 OPERATING EXPENSES (Cont'd) Customer Accounts Expense Meter Reading Collection Other Employee Benefits Uncollectible Accounts Customer Services Meetings and Training Total Customer Accounts Expense Sales Expense Salaries Conservation Total Sales Expense Administrative and General Supervision and General Salaries Office Supplies Outside Services Employed Property Insurance Medical Insurance Other Employee Benefits Regulatory Commissioners Salaries Travel Miscellaneous Maintenance of General Plant Total Administrative and General Depreciation Contribution to City of Hutchinson Payment in Lieu of Taxes Total Operating Expenses Operating Income (Loss) 2018 2017 Over(Under) Budget Actual Budget Actual $ 19,062 $ 15,136 $ (3,926) $ 41,664 123,516 114,363 (9,153) 116,506 8,194 8,194 8,650 4,500 8,983 4,483 4,333 48,861 45,808 (3,053) 34,001 2,250 (2,250) 198,189 192,484 (5,705) 205,154 22,464 38,687 16,223 30,085 140,725 87,735 (52,990) 63,574 163,189 126,422 (36,767) 93,659 150,184 154,594 4,410 143,981 90,800 84,274 (6,526) 120,613 26,769 51,316 24,547 46,744 59,000 32,870 (26,130) 30,723 58,000 51,700 (6,300) 153,415 3,750 32,055 28,305 200,773 20,000 35,313 15,313 16,097 10,558 10,435 (123) 10,761 6,000 2,069 (3,931) 3,030 52,000 42,544 (9,456) 47,182 31,292 32,758 1,466 29,923 508,353 529,928 21,575 803,242 1,008,000 1,033,788 25,788 1,022,038 369,142 369,142 367,131 9,223,983 9,323,004 99,021 10,126,029 2,681,639 3,424,742 743,103 2,252,607 52 HUTCHINSON UTILITIES COMMISSION DETAILED SCHEDULE OF REVENUES, EXPENSES AND CHANGES IN NET POSITION BUDGET AND ACTUAL - NATURAL GAS DIVISION YEAR ENDED DECEMBER 31, 2018 WITH PARTIAL COMPARATIVE AMOUNTS FOR THE YEAR ENDED DECEMBER 31, 2017 2018 NONOPERATING REVENUES (EXPENSES) Interest Income Merchandise and Contract Work, Net Miscellaneous Income Gain (Loss) on Disposal of Assets Bond Premium Interest Expense Total Nonoperating Revenues (Expenses) Change in Net Position NET POSITION, BEGINNING OF YEAR, AS ORIGINALLY STATED PRIOR PERIOD ADJUSTMENT NET POSITION, BEGINNING OF YEAR, AS RESTATED NET POSITION, END OF YEAR Over(Under) Budget Actual Budget 2017 Actual $ 50,000 $ 204,496 $ 154,496 $ 66,536 (23,500) 49,070 72,570 43,601 33,610 33,610 18,146 6,063 6,063 13,732 185,608 185,608 185,608 (674,200) (671,143) 3,057 (731,329) (462,092) (192,296) 269,796 (403,706) $ 2,219,547 3,232,446 $ 1,012,899 1,848,901 22,897,966 (20,801) 22,877,165 $ 26,109,611 21,049,065 21,049,065 $ 22,897,966 53 This page intentionally left blank COMPLIANCE SECTION This page intentionally left blank INDEPENDENT AUDITOR'S REPORT ON MINNESOTA LEGAL COMPLIANCE Members of the Hutchinson Utilities Commission Hutchinson, Minnesota We have audited, in accordance with auditing standards generally accepted in the United States of America, and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States, the financial statements of Hutchinson Utilities Commission, a fund of the City of Hutchinson, Minnesota, as of and for the year ended December 31, 2018, and the related notes to the financial statements, which collectively comprise the Hutchinson Utilities Commission's basic financial statements, and have issued our report thereon dated April 24, 2019. The Minnesota Legal Compliance Audit Guide for Cities, promulgated by the State Auditor pursuant to Minn. Stat. § 6.65, contains seven categories of compliance to be tested: contracting and bidding, deposits and investments, conflicts of interest, public indebtedness, claims and disbursements, miscellaneous provisions, and tax increment financing. Our audit considered all of the listed categories, except that we did not test for compliance in tax increment financing because Hutchinson Utilities Commission does not have any tax increment financing. In connection with our audit, nothing came to our attention that caused us to believe that the Commission failed to comply with the provisions of the Minnesota Legal Compliance Audit Guide for Cities. However, our audit was not directed primarily toward obtaining knowledge of such noncompliance. Accordingly, had we performed additional procedures, other matters may have come to our attention regarding the Commission's noncompliance with the above referenced provisions. The purpose of this report is solely to describe the scope of our testing of compliance and the results of that testing, and not to provide an opinion on compliance. Accordingly, this communication is not suitable for any other purpose. Con , Z)c i ial , ��ZP CONWAY, DEUTH & SCHMIESING, PLLP CPAS & ADVISORS LITCHFIELD, MINNESOTA April 24, 2019 54 "4"'wi'iittxmair Office Benson Office Morris Office Litchif ietd Off ice Sartett Office 3311 Third St SW, Ste 2 1209 Pacific Ave, Ste 3 401 Atlantic Ave 820 Siibtey Ave N Ste 110 PO Box 570 Benson, MN 56215 Morris, MIN 56267 Litchfield, MN 55355 2'351 Connecticut Ave WiUtrnar, MN 56201 (320) 843-2302 (320) 589--2602 (320) 693-7975 Sartetl, MN 56377 (320)2 5- 311 (320)252-7565 (888) 388-1040 wwwxAscpaccom (800) 862-11337 Members! American Institute of Certified Public Accountants, Minnesota Society of Certified Public Accountants This page intentionally left blank INDEPENDENT AUDITOR'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING AND ON COMPLIANCE AND OTHER MATTERS BASED ON AN AUDIT OF FINANCIAL STATEMENTS PERFORMED IN ACCORDANCE WITH GOVERNMENT AUDITING STANDARDS Members of the Hutchinson Utilities Commission Hutchinson, Minnesota We have audited in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards issued by the Comptroller General of the United States, the financial statements of Hutchinson Utilities Commission, a fund of the City of Hutchinson, Minnesota, as of and for the year ended December 31, 2018, and the related notes to the financial statements, which collectively comprise the Commission's basic financial statements, and have issued our report thereon dated April 24, 2019. Internal Control Over Financial Reporting In planning and performing our audit of the financial statements, we considered the Commission's internal control over financial reporting (internal control) to determine the audit procedures that are appropriate in the circumstances for the purpose of expressing our opinion on the financial statements, but not for the purpose of expressing an opinion on the effectiveness of the Commission's internal control. Accordingly, we do not express an opinion on the effectiveness of the Commission's internal control. A deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent, or detect and correct misstatements on a timely basis. A material weakness is a deficiency, or a combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of the entity's financial statements will not be prevented, or detected and corrected on a timely basis. A significant deficiency is a deficiency, or combination of deficiencies, in internal control that is less severe than a material weakness, yet important enough to merit attention by those charged with governance. Our consideration of internal control was for the limited purpose described in the first paragraph of this section and was not designed to identify all deficiencies in internal control that might be material weaknesses or significant deficiencies. Given these limitations, during our audit we did not identify any deficiencies in internal control that we consider to be material weaknesses. However, material weaknesses may exist that have not been identified. . r a : A IN .r 1 1 :,� 0 55 Morris Office 401 Atlantic Ave Morris, MIN 56267 (320) 589-2602 MMIMM Litchfietd Office 820 Siibley Ave N Litchfield, MN 55355 (320) 693-7975 Sartett Office Ste 110 2'351 Connecticut Ave Sartell, MN 56377 (320) 2'52-7565 (800) 862-1337 Mernbers: American Institute of Certified Public Accountants, Minnesota Society of Certified Public Accountants Compliance and Other Matters As part of obtaining reasonable assurance about whether Hutchinson Utilities Commission's financial statements are free from material misstatement, we performed tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements, noncompliance with which could have a direct and material effect on the determination of financial statement amounts. However, providing an opinion on compliance with those provisions was not an objective of our audit, and accordingly, we do not express such an opinion. The results of our tests disclosed no instances of noncompliance or other matters that are required to be reported under Government Auditing Standards. Purpose of this Report The purpose of this report is solely to describe the scope of our testing of internal control and compliance and the result of that testing, and not to provide an opinion on the effectiveness of the Commission's internal control or on compliance. This report is an integral part of an audit performed in accordance with Government Auditing Standards in considering the Commission's internal control and compliance. Accordingly, this communication is not suitable for any other purpose. Cori, Z)c �iesl , 7,/ CONWAY, DEUTH & SCHMIESING, PLLP CPAS & ADVISORS LITCHFIELD, MINNESOTA April 24, 2019 56 HUTCHINSON UTILITIES COMMISSION Finding Reference SUMMARY SCHEDULE OF PRIOR AUDIT FINDINGS DECEMBER 31, 2018 Year Finding If Not Corrected, Provide Planned Finding Title Status Initially Occurred Corrective Action or Other Explanation Financial Statement Findings: None Minnesota Legal Compliance Findings: None 57 December 31, 2018 Independent Auditor's Report Pages 2-4: Financial statements are the responsibility of the Commission's management Our responsibility is to express an opinion on these financial statements based on our audit Conducted audit in accordance with Generally Accepted Auditing Standards and Government Auditing Standards Obtain reasonable assurance financials are free from material misstatement Financial statements of the Commission are presented fairly in our opinion Independent Auditor's Report (Cont"d) Pages2-4: • Required Supplementary Information —Management's Discussion and Analysis (pages 5-9) •Additional Required Supplementary Information (pages 36-40) •Internal control letter on pages 55 and 56 BE Statement of Net Position 2018 2017 ASSETS AND DEFERRED OUTFLOWS OF RESOURCES Current $ 25,291,981 $ 21,917,436 Restricted 8,037,130 17, 983, 727 Net Capital Assets 78,080,974 70,830,339 Total Assets 111,410,085 110,731,502 Deferred Outflows of Resources 658,738 1,003,849 Total Assets and Deferred Ouflows of Resources $ 112,068,823 $ 111,735,351 LIABILITIES, DEFERRED INFLOWS OF RESOURCES AND NET POSITION Liabilities Current Liabilities $ 6,438,985 $ 6,518,979 Noncurrent Liabilities 34,720,080 37,296,051 Total Liabilities 41,159,065 43,815,030 Deferred Inflows of Resources Net Position Net Inestment in Capital Assets Restricted Unrestricted Total Net Position Total Liabilities, Deferred Inflows of Resources and Net Position 1,073,067 1,059,160 49, 966, 247 51, 060, 879 2,353,590 3,561,829 17,516,854 12,238,453 69, 836, 691 66, 861,161 $ 112,068,823 $ 111,735,351 M Cash and Investment Balances $20,000,000 $18,000,000 $16,000,000 $14,000,000 $12,000,000 $10,000,000 $8,000,000 $6,000,000 $4,000,000 $2,000,000//// $0 2014 ■ Operating $4,036,077 IN Restricted 2,577,815 IIIIII Designated 3,750,094 2015 2016 $8,605,434 $10,185,906 2,567,940 2,539,625 4,034,789 5,355,928 2017 $10,311,734 17,983,727 5,716,035 2018 $13,283,267 8,037,130 6,575,468 UDS 4 Statement of Revenues, Expenses and Changes in Net Position 2018 2017 OPERATING REVENUES $ 41,493,135 $ 40,035,615 OPERATING EXPENSES Production 3,883,945 3,071,804 Purchased Power/Gas 20,717,624 21,141,106 Other Operating Expense 6,317,441 5,533,843 Administrati\,e and General 1,836,560 3,256,233 Depreciation 3,804,485 3,852,674 Contribution to City of Hutchinson 1,398,853 1,196,331 Total Operating Expenses 37,958,908 38,051,991 Operating Income (Loss) 3,534,227 1,983,624 NET NONOPERATING REVENUES (E)(PENSES) (475,494) (412,043) Change in Net Position 3,058,733 1,571,581 NET POSITION, BEGINNING OF YEAR 66,861,161 65,289,580 PRIOR PERIOD ADJUSTMENT (83,203) NET POSITION, BEGINNING OF YEAR, AS RESTATED 66,777,958 65,289,580 NET POSITION, END OF YEAR $ 69,836,691 $ 66,861,161 Electric Division $35,000,000 $30,000,000 $25,000,000 $20,000,000 $15,000,000 $10,000,000 $5,000,000 $0 $(5,000,000) 2014 ■Total Operating Revenues $26,073,296 IN Total Operating Expenses 27,106,843 IIIIII Net Nonoperating Revenues (Expenses) (451,322) 2015 $26,802,066 27,169,321 (201,467) 2016 $27,148,511 27,406,181 52,536. 2017 $27,656,979 27,925,962 (8,337) 2018 $28,745,389 28,635,904 (283,198) Electric Division $500,000 $0 $(500,000) $(1,000,000) $(1,500,000) $(2,000,000) 2014 2015 ■ Change in Net $(1,484,869) $(568,722) Position 2016 $(205,134) 2017 $(277,320) 2018 $(173,713) Revenue per KWH Year Ended December 31, 2018 Revenue Per CLASS Amount KWH Sold KWH Residential $ 5,336,482 51,777,707 $ 0.1031 All Electric 265,000 2,610,277 0.1015 Small General Service 1,934,682 19,106,510 0.1013 Large General Service 7,589,242 79,540,430 0.0954 Industrial 10,218,577 127,675,000 0.0800 Sale for Resale 3,071,099 27,160,000 0.1131 Street Lighting 147,470 98,302 1.5002 $ 28,562,552 307,968,226 0.0927 Year Ended December 31, 2017 Revenue Per CLASS Amount KWH Sold KWH Residential $ 5,093,852 49,389,408 $ 0.1031 All Electric 247,968 2,440,785 0.1016 Small General Service 1,814,703 17,896,264 0.1014 Large General Service 7,235,331 75,176,663 0.0962 Industrial 10,778,629 133,130,000 0.0810 Sale for Resale 2,171,853 13,000,000 0.1671 Street Lighting 147,484 102,156 1.4437 $ 27,489,820 291,135,276 0.0944 UDS 8 Natural Gas Division $18,000,000 $16,000,000 $14,000,000 $12,000,000 $10,000,000 $8,000,000 a $6,000,000 $4,000,000 $2,000,000 $0 IIIIIIIIIIIIIIIII IIIIIIIIIIIIIIII '""""""'"' � 2014 2016 2016 2017 2018 ■Total Operating Revenues $16,134,767 $11,341,497 $11,368,212 $12,378,636 $12,747,746 IN Total Operating Expenses 14,002,018 9,134,616 9,043,923 10,126,029 9,323,004 IIIIII Net Nonoperating Revenues (Expenses) (606,361) (636,019) (269,688) (403,706) (192,296) Natural Gas Division $3,500,000 $3,000,000 $2,500,000 $2,000,000 $1,500,000 $1,000,000 $500,000 $0 2014 ■ Change in Net Position $1,627,378 2016 2016 2017 2018 $1,670,962 $2,044,601 $1,848,901 $3,232,446 UDS Revenue per MCF Year Ended December 31, 2018 Revenue Per Thousand Amount CF Sold MCF CLASS Residential $ 4,139,639 446,223,775 $ 9.2770 Commercial 3,070,904 349, 805, 617 8.7789 Large industrial 3,870,184 857,732,882 4.5121 $ 11, 080, 727 1, 653, 762, 274 $ 6.7003 Year Ended December 31, 2017 Revenue Per Thousand Amount CF Sold MCF CLASS Residential $ 3,937,048 396,761,756 $ 9.9230 Commercial 3,019,230 325,983,624 9.2619 Large industrial 3,842,863 859,892,970 4.4690 $ 10, 799,141 1, 582, 638, 350 $ 6.8235 Communications •Accounting Practices •Difficulties Encountered • Corrected and Uncorrected Misstatements • Disagreements with Management • Management Representations • Management Consultations with Other Accountants • Other Audit Findings or Issues so General Recommendations •Cross -training •Capital Asset Accounting Questions or Comments? Contact information: Paul Harvego, CPA CFE pharve91o@cdscpa.com 320-693-7975 Justin McGraw, CPA 320-693-7975 UDS HUTCHINSON UTILITIES COMMISSION COMBINED DIVISIONS FINANCIAL REPORT FOR MARCH, 2019 2019 2018 Di %Chng 2019 2018 Di %Chng Full YrBud %of Bud Combined Division Customer Revenue $ 3,129,182 $ 3,218,997 $ (89,815) (2.8%) $ 10,536,715 $ 10,792,322 $ (255,607) (2.4%) $ 36,285,018 29.0% Sales for Resale $ 196,708 $ 149,520 $ 47,188 31.6% $ 647,437 $ 661,278 $ (13,840) (2.1%) $ 2,951,500 21.9% NU Transportation $ 81,147 $ 71,903 $ 9,244 12.9% $ 245,961 $ 214,417 $ 31,545 14.7% $ 885,452 27.8% Electric Division Transfer $ 54,982 $ 54,697 $ 285 0.5% $ 164,946 $ 164,091 $ 854 0.5% $ 659,783 25.0% Other Revenues $ 44,801 $ 55,760 $ (10,959) (19.7%) $ 137,845 $ 146,405 $ (8,560) (5.8%) $ 490,208 28.1% Interest Income $ 51,195 $ 29,187 $ 22,008 75.4% $ 126,115 $ 76,194 $ 49,920 65.5% $ 283,456 44.5% TOTAL REVENUES $ 3,558,015 $ 3,580,064 $ (22,049) (0.6%) $ 11,859,019 $ 12,054,708 $ (195,688) (1.6%) $ 41,555,417 28.5% Salaries & Benefits $ 463,525 $ 505,892 $ (42,367) (8.37%) $ 1,484,695 $ 1,502,272 $ (17,577) (1.2%) $ 6,252,888 Purchased Commodities $ 1,772,135 $ 1,718,549 $ 53,586 3.1% $ 6,234,897 $ 6,023,009 $ 211,889 3.5% $ 19,155,179 Transmission $ 228,440 $ 184,071 $ 44,370 24.1% $ 564,537 $ 544,592 $ 19,945 3.7% $ 3,380,000 Generator Fuel/Chem. $ 40,583 $ 19,279 $ 21,304 110.5% $ 76,490 $ 164,247 $ (87,757) (53.4%) $ 1,139,850 Depreciation $ 327,083 $ 325,667 $ 1,417 0.4% $ 981,250 $ 977,000 $ 4,250 0.4% $ 3,925,000 Transfers (Elect./City) $ 188,434 $ 158,986 $ 29,448 18.5% $ 565,302 $ 476,959 $ 88,343 18.5% $ 2,261,207 Operating Expense $ 209,012 $ 150,827 $ 58,185 38.6% $ 667,633 $ 455,992 $ 211,641 46.4% $ 3,215,236 Debt Interest $ 97,334 $ 103,551 $ (6,218) (6.0%) $ 292,002 $ 310,654 $ (18,653) jLg%j $ 1,168,007 TOTAL EXPENSES $ 3,326,547 $ 3,166,822 $ 159,724 5.0% $ 10,866,806 $ 10,454,725 $ 412,082 3.9% $ 40,497,367 NET PROFIT/(LOSS) $ 231,468 $ 413,242 $ (181,774) (44.0%)l 992,213 $ 1,599,983 $ (607,770) (38.0%) $ 1,058,050 March March YTD YTD 2019 2018 Change 2019 2018 Change Gross Margin % 32.9% 38.2% -5.3% 33.2% 37.5% -4.4% Operating Income Per Revenue $ (%) 7.3% 12.9% -5.6% 9.3% 14.7% -5.4% Net Income Per Revenue $ (%): 6.5% 11.5% -5.0% 8.4% 13.3% -4.9% 2019 HUC Budget Target 4.2% 2.5% 23.7% 32.5% 16.7% 6.7% 25.0% 25.0% 20.8% 25.0% 26.8% 93.8% HUTCHINSON UTILITIES COMMISSION ELECTRIC DIVISION FINANCIAL REPORT FOR MARCH, 2019 2019 2018 pi . Electric Division Customer Revenue $ 1,853,310 $ 1,926,332 $ (73,023) Sales for Resale $ 196,708 $ 149,520 $ 47,188 Other Revenues $ 14,798 $ 19,152 $ (4,354) Interest Income $ 26,992 $ 15,988 $ 11,004 TOTAL REVENUES $ 2,091,807 $ 2,110,992 $ (19,184) Chng 2019 2018 Pi . (3.8%) $ 6,001,484 $ 5,987,006 $ 14,479 31.6% $ 647,437 $ 661,278 $ (13,840) (22.7%) $ 55,210 $ 50,719 $ 4,491 68.8% $ 67,622 $ 42,279 $ 25,343 (0.9%)l $ 6,771,753 $ 6,741,281 $ 30,472 Chng 25% of Year Full Yr Bud $ 26,118,530 Comp. % of Bud 23.0% 0.2% (2.1%) $ 2,951,500 21.9% 8.9% $ 203500 27.1% 59.9% $ 158:456 42.7% 0.5% $ 29,431,986 23.0% Salaries & Benefits $ 351,689 $ 389,310 $ (37,620) (9.7%) $ 1,128,740 $ 1,167,291 $ (38,551) (3.3%) $ 4,541,091 24.9% Purchased Power $ 1,024,378 $ 1,069,256 $ (44,878) (4.2%) $ 3,566,826 $ 3,563,782 $ 3,044 0.1% $ 13,640,000 26.1% Transmission $ 228,440 $ 184,071 $ 44,370 24.1% $ 564,537 $ 544,592 $ 19,945 3.7% $ 3,380,000 16.7% Generator Fuel/Chem. $ 40,583 $ 19,279 $ 21,304 110.5% $ 76,490 $ 164,247 $ (87,757) (53.4%) $ 1,139,850 6.7% Depreciation $ 241,667 $ 241,667 $ - 0.0% $ 725,000 $ 725,000 $ - 0.0% $ 2,900,000 25.0% Transfers (Elect./City) $ 147,172 $ 128,224 $ 18,947 14.8% $ 441,515 $ 384,673 $ 56,842 14.8% $ 1,766,062 25.0% Operating Expense $ 142,343 $ 102,465 $ 39,878 38.9% $ 465,845 $ 300,133 $ 165,712 55.2% $ 2,173,291 21.4% Debt Interest $ 46,555 $ 47,376 $ (822) (1.7%) $ 139,664 $ 142,129 $ (2,465) 1.7% $ 558,657 25.0% TOTAL EXPENSES $ 2,222,827 $ 2,181,648 $ 41,179 1.9% $ 7,108,617 $ 6,991,847 $ 116,771 1.7% $ 30,098,951 23.6% NET PROFIT/(LOSS) $ (131,020) $ (70,656) $ (60,364) 85.4% $ (336,864) $ (250,565) $ (86,299) 34.4% $ (666,965) 50.5% 2019 2018 Di . %Chna 2019 2018 Di . %Chna Full YrBud %of Bud Electric Division Residential 3,892,722 3,904,658 (11,936) (0.31%) 12,381,927 12,013,877 368,050 3.06% 50,327,925 24.6% All Electric 265,522 264,222 1,300 0.49% 1,005,829 947,708 58,121 6.13% 2,504,213 40.2% Small General 1,550,513 1,552,526 (2,013) (0.13%) 4,876,480 4,690,088 186,392 3.97% 17,687,385 27.6% Large General 6,065,000 5,971,600 93,400 1.56% 19,234,380 17,897,960 1,336,420 7.47% 77,713,164 24.8% Industrial 8,956,000 10,415,000 (1,459,000) (14.01%) 27,525,000 30,233,000 (2,708,000) (8.96%) 135,502,800 20.3% Total KWH Sold 20,729,757 22,108,006 (1,378,249) (6.23%)l 65,023,616 65,782,633 (759,017) (1.15%)l 283,735,487 22.9% March March YTD YTD 2019 HUC 2019 2018 Change 2019 2018 Change Budget Target Gross Margin % 23.6% 27.6% -4.0% 24.1% 26.2% -2.1% 25.3% Operating Income Per Revenue $ (%) -5.4% -2.1% -3.3% -4.1% -2.3% -1.8% -0.9% 0%-5% Net Income Per Revenue $ (%): -6.3% -3.3% -2.9% -5.0% -3.7% -1.3% -2.3% 0%-5% Customer Revenue per KWH: $0.0876 $0.0855 $0.0022 $0.0917 $0.0905 $0.0013 $0.0915 Total Power Supply Exp. per KWH: $0.0761 $0.0684 $0.0076 $0.0781 $0.0751 $0.0030 $0.0771 $0.0771 Electric Divison Net Loss increased by $60,364 mostly due to higher transmission, PILOT, and operating expenses. Customer Revenue also saw a decrease of $73,023 with a decline in usage. Sales for Resale of $196,708 consisted of $9,109 in market sales, $36,400 in the monthly tolling fee from Transalta, $35,199 in Transalta energy sales, and $116,000 in capacity sales to SMMPA. March 2018 Sales for Resale of $149,250 consisted of $6,297 in market sales, $35,600 in monthly tolling fees from Transalta, $11,623 in Transalta energy sales, and $96,000 in capacity sales to SMMPA. March 2017 Sales for Resale of $130,012 consisted of $1,565 in market sales, $34,400 in Transalta tolling fees, $27,547 in Transalta energy sales, and capacity sales to SMMPA for $66,500. Overall Purchased Power decreased by $44,878. MRES purchases decreased by $28,890 and market purchases/MISO costs decreased by $15,988. March power cost adjustment was $.00247/kwhr bringing in an additional $51,482 in revenue for the month and $455,158 YTD. Last year's power cost adjustment for March 2018 generated $40,709 in additional revenue for the month and $418,899 YTD. HUTCHINSON UTILITIES COMMISSION GAS DIVISION FINANCIAL REPORT FOR MARCH, 2019 04, lllllllllllllll�� flll�l��IIIIIIIIIIII�� RRR�� illl �� 25% oj' Year Comp 2019 2018 Di %Chng 2019 2018 Di %Chng Full YrBud %of Bud Gas Division Customer Revenue $ 1,275,872 $ 1,292,665 $ (16,793) (1.3%) $ 4,535,231 $ 4,805,317 $ (270,085) (5.6%) $ 10,166,488 44.6% Transportation $ 81,147 $ 71,903 $ 9,244 12.9% $ 245,961 $ 214,417 $ 31,545 14.7% $ 885,452 27.8% Electric Div. Transfer $ 54,982 $ 54,697 $ 285 0.5% $ 164,946 $ 164,091 $ 854 0.5% $ 659,783 25.0% Other Revenues $ 30,003 $ 36,608 $ (6,605) (18.0%) $ 82,635 $ 95,686 $ (13,051) (13.6%) $ 286,708 28.8% Interest Income $ 24,204 $ 13,200 $ 11,004 83.4% $ 58,493 $ 33,915 $ 24,578 72.5% $ 125,000 46.8% TOTAL REVENUES $ 1,466,208 $ 1,469,072 $ (2,865) (0.2%) $ 5,087,266 $ 5,313,426 $ (226,160) (4.3%) $ 12,123,431 42.0% Salaries & Benefits $ 111,836 $ 116,582 $ (4,746) (4.1%) $ 355,955 $ 334,982 $ 20,974 6.3% $ 1,711,797 20.8% Purchased Gas $ 747,757 $ 649,293 $ 98,464 15.2% $ 2,668,072 $ 2,459,227 $ 208,845 8.5% $ 5,515,179 48.4% Operating Expense $ 66,669 $ 48,363 $ 18,306 37.9% $ 201,788 $ 155,859 $ 45,929 29.5% $ 1,041,945 19.4% Depreciation $ 85,417 $ 84,000 $ 1,417 1.7% $ 256,250 $ 252,000 $ 4,250 1.7% $ 1,025,000 25.0% Transfers (City) $ 41,262 $ 30,762 $ 10,500 34.1% $ 123,786 $ 92,285 $ 31,501 34.1% $ 495,145 25.0% Debt Interest $ 50,779 $ 56,175 $ (5,396) 0.0% $ 152,338 $ 168,525 $ (16,188) ja.6% $ 609,350 25.0% TOTAL EXPENSES $ 1,103,720 $ 985,175 $ 118,545 12.0% $ 3,758,189 $ 3,462,878 $ 295,311 8.5% $ 10,398,416 36.1% NET PROFIT/(LOSS) $ 362,488 $ 483,898 $ (121,410) (25.1%)l $ 1,329,077 $ 1,850,548 $ (521,471) (28.2%) $ 1,725,015 77.0% 2019 2018 Di %Chng 2019 2018 Di %Chng Full YrBud %of Bud Gas Division Residential 59,999,023 54,735,875 5,263,148 9.62% 165,440,853 155,656,183 9,784,670 6.29% 421,716,000 39.2% Commercial 43,480,571 40,789,743 2,690,828 6.60% 116,876,245 115,850,239 1,026,006 0.89% 330,746,000 35.3% Industrial 89,367,378 92,356,879 (2,989,501) (3.24%) 209,433,589 205,250,519 4,183,070 2.04% 822,478,000 25.5% Total CF Sold 192,846,972 187,882,497 4,964,475 2.64% 491,750,687 476,756,941 14,993,746 3.14% 1,574,940,000 31.2% March March YTD YTD 2019 HUC 2019 2018 Change 2019 2018 Change Budget Target Gross Margin % 46.3% 53.6% -7.3% 45.4% 52.1% -6.8% 51.5% Operating Income Per Revenue $ (%) 25.7% 34.8% -9.1% 27.4% 36.7% -9.3% 16.9% Net Income Per Revenue $ (%): 25.7% 34.1% -8.4% 26.9% 35.7% -8.8°% 14.7°% Contracted Customer Rev. per CF: $0.0042 $0.0037 $0.0005 $0.0063 $0.0062 $0.0001 $0.0038 Customer Revenue per CF: $0.0085 $0.0096 -$0.0011 $0.0112 $0.0127 -$0.0015 $0.0090 Total Power Supply Exp. per CF: $0.0040 $0.0035 $0.0004 $0.0055 $0.0052 $0.0003 $0.0036 $0.0036 Natural Gas net income decreased by $121,410. This is mostly due to the credit on customer bills that was absent in 2018. Expense increases include PILOT and Purchased Gas. Purchased Gas was up due to paying more on the spot market for our swing gas over March 2018. March's fuel cost credit adjustment was $.88391/MCF totalling $95,527 for the month and $388,102 YTD. There was no credit in March 2018 due to building the rate stabilization fund back up after the gas price spike in December 2017. Current Assets UnrestrictedlUndesignated Cash Cash Petty Cash Designated Cash Capital Expenditures - Five Yr. CIP Payment in Lieu of Taxes Rate Stabilization - Electric Rate Stabilization - Gas Catastrophic Funds Restricted Cash Bond Interest Payment 2017 Bond Interest Payment 2012 Debt Service Reserve Funds Total Current Assets Receivables Accounts (net of uncollectible allowances) Interest Total Receivables Other Assets Inventory Prepaid Expenses Sales Tax Receivable Deferred Outflows - Electric Deferred Outflows - Gas Total Other Assets Total Current Assets Capital Assets Land & Land Rights Depreciable Capital Assets Accumulated Depreciation Construction - Work in Progress Total Net Capital Assets Total Assets HUTCHINSON UTILITIES COMMISSION BALANCE SHEET - CONSOLIDATED MARCH 31, 2019 Electric Gas Total Division Division 2019 8,602,562.96 9,250,715.78 17,853,278.74 680.00 170.00 850.00 2,750,000.00 700,000.00 3,450,000.00 1,106,279.00 495,145.00 1,601,424.00 372,736.68 - 372,736.68 - 651,306.61 651,306.61 400,000.00 100,000.00 500,000.00 Total Net Change 2018 Total (YTD) 24,738,659.54 (6,885,380.80) 850.00 - 3,450,000.00 1,251,469.00 349,955.00 314, 539.41 58,197.27 651,306.61 - 500,000.00 - 894,552.03 - 894,552.03 847,574.40 46,977.63 - 657,170.83 657,170.83 656,366.64 804.19 522,335.64 2,188,694.02 2,711,029.66 2,711,029.66 - 14,649,146.31 14,043,202.24 28,692,348.55 35,121,795.26 (6,429,446.71) 1,961,320.55 1,497,379.50 3,458,700.05 3,436,889.17 21,810.88 23,632.29 23,632.29 47,264.58 38,078.98 9,185.60 1,984,952.84 1,521,011.79 3,505,964.63 3,474,968.15 30,996.48 1,216,563.42 462,267.00 1,678,830.42 1,574,173.72 104,656.70 97,423.77 34,996.08 132,419.85 99,017.12 33,402.73 39,574.41 - 39,574.41 38,084.94 1,489.47 494,053.00 - 494,053.00 752,887.00 (258,834.00) - 164,685.00 164,685.00 250,962.00 (86,277.00) 1,847,614.60 661,948.08 2,509,562.68 2,715,124.78 (205,562.10) 18,481,713.75 16,226,162.11 34,707,875.86 41,311,888.19 (6,604,012.33) 690,368.40 3,899,918.60 4,590,287.00 4,590,287.00 - 90,203,964.98 41,684,214.28 131,888,179.26 130,893,296.51 994,882.75 (55,896,384.23) (16,342,656.19) (72,239,040.42) (68,512,578.54) (3,726,461.88) 14,654,991.22 51,518.13 14,706,509.35 3,743,070.52 10,963,438.83 49,652,940.37 29,292,994.82 78,945,935.19 70,714,075.49 8,231,859.70 68,134,654.12 45,519,156.93 113,653,811.05 112,025,963.68 1,627,847.37 Current Liabilities Current Portion of Long-term Debt Bonds Payable Bond Premium Accounts Payable Accrued Expenses Accrued Interest Accrued Payroll Total Current Liabilities Long -Term Liabilities Noncurrent Portion of Long-term Debt 2017 Bonds 2012 Bonds 2003 Bonds Bond Premium 2012 Pension Liability- Electric Pension Liability - Electric OPEB Pension Liability - Nat Gas Pension Liability - Nat Gas OPEB Accrued Vacation Payable Accrued Severance Deferred Outflows - Electric Deferred Outflows - Nat Gas Total Long -Term Liabilities Net Position Retained Earnings Total Net Position HUTCHINSON UTILITIES COMMISSION BALANCE SHEET - CONSOLIDATED MARCH 31, 2019 Electric Gas Total Division Division 2019 625,000.00 3,151,897.13 186,218.75 85,981.77 4,049,097.65 16,050,000.00 624,529.92 2,700,290.00 72,192.00 366,391.02 77,139.06 804,800.00 20,695,342.00 1,370,000.00 185,608.32 1,195, 854.51 203,116.66 25,520.70 2,980,100.19 12,530,000.00 1,237,388.43 900,097.00 24,064.00 111, 060.50 29,491.28 268,267.00 15,100,368.21 1,995,000.00 185,608.32 4,347,751.64 389,335.41 111, 502.47 7,029,197.84 16,050,000.00 12,530,000.00 1,861,918.35 2,700,290.00 72,192.00 900,097.00 24,064.00 477,451.52 106,630.34 804,800.00 268,267.00 35,795,710.21 Total 2018 1,295,000.00 185,608.32 3,161,732.58 457,382.00 109,868.32 5,209,591.22 16,675,000.00 13,900,000.00 2,080,983.63 3,083,440.00 1,027,813.00 426, 510.04 102, 320.61 794,370.00 264,790.00 38,355,227.28 Net Change Total (YTD) 700,000.00 1,186, 019.06 (68, 046.59) 1,634.15 1,819,606.62 (625,000.00) (1,370,000.00) (219,065.28) (383,150.00) 72,192.00 (127,716.00) 24,064.00 50,941.48 4,309.73 10,430.00 3,477.00 (2,559,517.07) 43,390,214.47 27,438,688.53 70,828,903.00 68,461,145.18 2,367,757.82 43,390,214.47 27,438,688.53 70,828,903.00 68,461,145.18 2,367,757.82 Total Liabilities and Net Position 68,134,654.12 45,519,156.93 113,653,811.05 112,025,963.68 1,627,847.37 Hutchinson Utilities Commission Cash -Designations Report, Combined 3/31/2019 Change in Financial Annual Balance, Balance, Cash/Reserve Institution Current Interest Rate Interest March 2019 February 2019 Position Savings, Checking, Investments varies Total Operating Funds varies varies 28,692,348.55 28,263,374.21 428,974.34 Debt Reserve Requirements Bond Covenants - sinking fund Debt Reserve Requirements Bond Covenants -1 year Max. P & I Total Restricted Funds 28,692,348.55 28,263,374.21 428,974.34 1,551,722.86 1,288,993.16 262,729.70 2,711,029.66 2,711,029.66 - 4,262,752.52 4,000,022.82 262,729.70 Operating Reserve Min 60 days of 2019 Operating Bud. 6,086,812.00 6,086,812.00 Rate Stabalization Funds 1,024,043.29 1,024,043.29 PILOT Funds Charter (Formula Only) 1,601,424.00 1,601,424.00 Catastrophic Funds Risk Mitigation Amount 500,000.00 500,000.00 Capital Reserves 5 Year CIP ( 2019-2023 Fleet & Infrastructure Maintenance) 3,450,000.00 3,450,000.00 Total Designated Funds 12,662,279.29 12,662,279.29 YE YE YE YE YTD HUC 2015 2016 2017 2018 2019 Target Debt to Asset 32.4% 32.2% 40.2% 37.7% 37.7% Current Ratio 2.52 3.06 3.36 3.93 4.24 RONA 1.31% 2.17% 1.82% 3.43% 0.98% Notes/Graphs: Change in Cash Balance (From 12131114 to 313112019) Month End Electric Elec. Change Natural Gas Gas Change Total Total Change 3/31/2019 14,649,146 14,043,202 28,692,349 12/31/2017 23,213,245 (8,564,099) 10,702,689 3,340,513 33,915,934 (5,223,585) 12/31/2016 8,612,801 14,600,444 9,500,074 1,202,615 18,112,875 15,803,059 12/31/2015 6,170,790 2,442,011 9,037,373 462,701 15,208,163 2,904,712 12/31/2014 3,598,821 2,571,969 6,765,165 2,272,208 10,363,986 4,844,177 * 2017's Signifcant increase in cash balance is due to issuing bonds for the generator project. Hutchinson Utilities Commission Cash -Designations Report, Electric 3/31/2019 Change in Financial Annual Balance, Balance, Cash/Reserve Institution Current Interest Rate Interest March 2019 February 2019 Position Savings, Checking, Investments varies varies Total HUC Operating Funds Debt Restricted Requirements Bond Covenants - sinking fund Debt Restricted Requirements Bond Covenants -1 year Max. P & I Total Restricted Funds varies 28,692,348.55 28,263,374.21 428,974.34 28,692,348.55 28,263,374.21 428,974.34 894,552.03 795,914.00 98,638.03 522,335.64 522,335.64 - 1,416,887.67 1,318,249.64 98,638.03 Operating Reserve Min 60 days of 2019 Operating Bud. 4,532,992.00 4,532,992.00 Rate Stabalization Funds $400K-$1.2K 372,736.68 372,736.68 PILOT Funds Charter (Formula Only) 1,106,279.00 1,106,279.00 Catastrophic Funds Risk Mitigation Amount 400,000.00 400,000.00 Capital Reserves 5 Year CIP ( 2019-2023 Fleet & Infrastructure Maintenance) 2,750,000.00 2,750,000.00 Total Designated Funds 9,162,007.68 9,162,007.68 YE YE YE YE YTD APPA Ratio HUC 2015 2016 2017 2018 2019 SK-10K Cust. Target Debt to Asset Ratio (* w/Gen.) 13.9% 16.7% 35.4% 35.7% 36.3% 50.1% Current Ratio 2.95 3.57 4.36 3.63 4.09 2.43 RONA -1.2% -0.4% -0.6% -0.3% -0.5% NA >0% Hutchinson Utilities Commission Cash -Designations Report, Gas 3/31/2019 Change in Financial Annual Balance, Balance, Cash/Reserve Institution Current Interest Rate Interest March 2019 February 2019 Position Savings, Checking, Investments varies varies Total HUC Operating Funds Debt Restricted Requirements Bond Covenants - sinking fund Debt Restricted Requirements Bond Covenants -1 year Max. P & I Total Restricted Funds varies 28,692,348.55 28,263,374.21 428,974.34 28,692,348.55 28,263,374.21 428,974.34 657,170.83 493,079.16 164,091.67 2,188,694.02 2,188,694.02 - 2,845,864.85 2,681,773.18 164,091.67 Operating Reserve Min 60 days of 2019 Operating Bud. 1,553,820.00 1,553,820.00 Rate Stabalization Funds $200K-$600K 651,306.61 651,306.61 PILOT Funds Charter (Formula Only) 495,145.00 495,145.00 Catastrophic Funds Risk Mitigation Amount 100,000.00 100,000.00 Capital Reserves 5 Year CIP ( 2019-2023 Fleet & Infrastructure Maintenance) 700,000.00 700,000.00 Total Designated Funds 3,500,271.61 3,500,271.61 YE YE YE YE YTD HUC 2015 2016 2017 2018 2019 APGA Ratio Target Debt to Asset 55.0% 51.2% 47.6% 40.7% 39.7% TBD Current Ratio 2.17 2.59 2.74 4.33 4.43 TBD RONA 4.7% 5.6% 5.0% 8.3% 3.4% TBD HUTCHINSON UTILITIES COMMISSION Investment Report For the Month Ended March 31, 2019 Interest Current Date of Date of Par Current Purchase Unrealized Premium Next Institution Description Rate YTM Purchase Maturity Value Value Amount Gainl(Loss) (Discount) Call Date Wells Fargo Money Market 1.630% 1.630% NA NA - 109,240.90 - - - N/A Wells Fargo CD's 2.550% 2.550% 08/21/2018 02/21/2020 245,000.00 245,176.40 245,000.00 176.40 - N/A Wells Fargo CD's 2.450% 2.450% 03/27/2019 03/27/2020 245,000.00 244,919.15 245,000.00 (80.85) - N/A Wells Fargo CD's 2.100% 2.100% 02/21/2018 08/21/2019 245,000.00 244,718.25 245,000.00 (281.75) - N/A Wells Fargo CD's 2.500% 2.500% 04/02/2019 04/05/2021 245,000.00 245,000.00 245,000.00 - - N/A Wells Fargo CD's 2.000% 2.000% 04/07/2016 10/07/2021 245,000.00 241,268.65 245,000.00 (3,731.35) - 04/07/2019 Wells Fargo CD's 2.150% 2.150% 06/27/2017 06/27/2022 245,000.00 240,210.25 245,000.00 (4,789.75) - 04/27/2019 Wells Fargo CD's 2.600% 2.600% 03/29/2019 03/29/2021 245,000.00 245,237.65 245,000.00 237.65 - 09/29/2019 Wells Fargo FHLMC - Step 2.000% 2.192% 06/29/2017 06/29/2022 275,000.00 273,592.00 275,000.00 (1,408.00) - 06/29/2019 Wells Fargo FHLMC - Step 2.000% 2.256% 10/27/2016 10/27/2023 1, 025,000.00 1, 020,131.25 1, 025,000.00 (4,868.75) 04/27/2019 Broker Total 25.6% 3,015,000.00 3,109,494.50 3,015,000.00 (14,746.40) - Cetera Investment Services Money Market 0.200% 0.200% N/A N/A - 20,905.08 - - - N/A Cetera Investment Services U.S. Treasury Bill 2.120% 2.120% 02/19/2019 04/18/2019 1,500,000.00 1,498,320.00 1,494,961.26 3,358.74 (5,038.74) N/A Cetera Investment Services U.S. Treasury Bill 2.230% 2.230% 02/19/2019 08/15/2019 1,615,600.00 1,601,059.60 1,598,315.24 2,744.36 (17,284.76) N/A Cetera Investment Services U.S. Treasury Bill 2.170% 2.170% 12/06/2018 04/11/2019 1,616,000.00 1,614,933.44 1,605,195.70 9,737.74 (10,804.30) N/A Cetera Investment Services Municipal Bonds 2.995% 2.073% 03/07/2016 07/01/2020 250,000.00 251,320.00 260,835.21 (9,515.21) 10,835.21 N/A Cetera Investment Services Municipal Bonds 2.750% 1.881% 03/07/2016 08/01/2020 250,000.00 251,810.00 259,820.00 (8,010.00) 9,820.00 N/A Cetera Investment Services Municipal Bonds 2.163% 1.779% 03/08/2016 07/01/2019 500,000.00 499,470.00 506,145.00 (6,675.00) 6,145.00 N/A Cetera Investment Services Municipal Bonds 1.886% 1.886% 04/29/2016 04/15/2019 250,000.00 249,712.50 236,327.50 13,385.00 (13,672.50) N/A Cetera Investment Services Municipal Bonds 5.000% 1.610% 10/11/2016 01/01/2020 250,000.00 256,340.00 276,500.00 (20,160.00) 26,500.00 N/A Cetera Investment Services Municipal Bonds 2.875% 2.121% 04/29/2016 09/01/2021 250,000.00 252,300.00 259,467.50 (7,167.50) 9,467.50 N/A Cetera Investment Services Municipal Bonds 3.751% 2.399% 04/29/2016 11/01/2021 250,000.00 254,135.00 267,330.00 (13,195.00) 17,330.00 N/A Cetera Investment Services Municipal Bonds 3.139% 2.190% 12/11/2017 09/01/2021 300,000.00 301,869.00 310,116.00 (8,247.00) 10,116.00 N/A Cetera Investment Services Municipal Bonds 2.655% 2.208% 12/11/2017 03/01/2022 300,000.00 301,029.00 305,314.92 (4,285.92) 5,314.92 N/A Cetera Investment Services Municipal Bonds 2.300% 1.715% 12/11/2017 10/01/2020 100,000.00 99,884.00 101,595.00 (1,711.00) 1,595.00 N/A Cetera Investment Services Municipal Bonds 3.240% 3.240% 11/17/2017 02/15/2023 80,000.00 70,277.60 69,633.48 644. 12 (10,366.52) N/A Cetera Investment Services Municipal Bonds 3.436% 3.436% 12/20/2018 12/15/2021 50,000.00 45,680.00 45,155.00 525.00 (4,845.00) N/A Cetera Investment Services Municipal Bonds 3.000% 3.118% 12/20/2018 08/01/2022 50,000.00 50,554.50 50,377.67 176.83 377.67 N/A Cetera Investment Services Municipal Bonds 3.633% 3.116% 12/20/2018 09/01/2022 250,000.00 254,540.00 257,217.48 (2,677.48) 7,217.48 N/A Cetera Investment Services Municipal Bonds 3.650% 3.004% 12/20/2018 02/01/2023 250,000.00 257,050.00 256,165.00 885.00 6,165.00 N/A Cetera Investment Services Municipal Bonds 3.075% 3.236% 12/20/2018 06/01/2023 50,000.00 50,027.00 49,746.15 280.85 (253.85) N/A Cetera Investment Services Municipal Bonds 2.500% 3.181 % 12/20/2018 08/01/2023 35,000.00 34,638.80 34,320.05 318. 75 (679.95) N/A Cetera Investment Services Municipal Bonds 3.400% 3.148% 12/20/2018 11/01/2023 125,000.00 125,945.00 126,376.25 (431.25) 1,376.25 N/A Cetera Investment Services Municipal Bonds 3.400% 3.148% 12/20/2018 11/01/2023 65,000.00 65,491.40 65,715.65 (224.25) 715.65 N/A Cetera Investment Services Municipal Bonds 2.854% 3.173% 12/20/2018 02/01/2024 100,000.00 100,264.00 99,605.96 658.04 (394.04) N/A Cetera Investment Services Municipal Bonds 2.977% 3.246% 12/20/2018 03/15/2024 250,000.00 249,462.50 248,743.99 718.51 (1,256.01) N/A Cetera Investment Services Municipal Bonds 3.922% 3.429% 12/20/2018 12/01/2024 250,000.00 260,795.00 257,122.49 3,672.51 7,122.49 N/A Broker Total 74.4% 8,986,600.00 9,017,813.42 9,042,102.50 (45,194.16) 55,502.50 TOTAL INVESTMENTS 100.0% $ 12,001,600.00 $ 12,127,307.92 $ 12,057,102.50 $ (59,940.56) $ 55,502.50 IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII� Product Tme *�. a .*:.. ° : Total Value Total .add.. Total Value Total Change IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII��gd:Thw . :: d . K:: Less than I year $6,584,795 32 543% QIQIu Money Marketyears 1 jj ELECTRIC DIVISION Operating Revenue March 2019 CLASS AMOUNT KWH /KWH Street Lights $0.77 14 $0.05500 Electric Residential Service $396,060.03 3,892,722 $0.10174 All Electric Residential Service $25,658.63 265,522 $0.09663 Electric Small General Service $151,723.25 1,550,513 $0.09785 Electric Large General Service $554,765.57 6,065,000 $0.09147 Electric Large Industrial Service $688,255.32 8,956,000 $0.07685 Total $1,816,463.57 20,729,771 $0.08763 Power Adjustment $0.00247 Rate Without Power Adjustment $0.08516 Electric Division Year -to -Date M2019$A--t 02018$A--t ■2019KWH110 02018 KWH110 7,400,000 7,200,000 7,000,000 6,800,000 6,600,000 6,400,000 6,200,000 6,000,000 5,800,000 5,600,000 5,400,000 5,200,000 5,000,000 4,800,000 4,600,000 4,400,000 4,200,000 4,000,000 3,800,000 3,600,000 3,400,000 3,200,000 3,000,000 2,800,000 2,600,000 2,400,000 2,200,000 2,000,000 1,800,000 1,600,000 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 0 Street Lights Residential All Elec. Small Gen. Large Gen. Large For Resale Total Resid. Srv. Srv. Industrial NOTE: Sales for resale includes capacity sales, market sales and Transalta sales. NATURAL GAS DIVISION Operating Revenue MARCH 2O19 CLASS AMOUNT MCF /$ MCF Residential $512,612.64 59,999 $8.54369 Commercial $362,675.19 43,481 $8.34100 Large Industrial $44,029.92 4,916 $8.95645 Large Industrial Contracts $356,554.22 84,451 $4.22202 Total $1,275,871.97 192,847 $6.61598 ® 2019 $ Amount 10,000,000 9,000,000 8,000,000 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 1,000,000 0 Fuel Adjustment-$0.88000 Rate Without Fuel Adjustment $7.49598 Natural Gas Division Year -to -Date 0 2018 $ Amount ■ 2019 MCF 132018 MCF Gas Residential Gas Commercial Large Industrial Large Industrial Total Contracts eReliability I Monthly Statistics Page 1 of 6 Monthly Report - Hutchinson Utilities Hutchinson Utilities Commission Commission Year Minimum duration Substation 2019 R ----- Month Maximum duration Circuit 03 - March R ----- H Annual Report? Top-level Cause Remove Major Events? 0 Yes Unscheduled ----- No https://reliability.publicpower.org/reports/monthly/utility/9l /?year=2019&month=3&is_an... 4/17/2019 eReliability I Monthly Statistics Page 2 of 6 IEEE 1366 Statistics Metric Mar 2019 Mar 2018 SAIDI 0.875 35.292 SAIFI 0.00868 0.84 CAI DI 100.806 42.002 ASAI 99.9979% 99.9183% Momentary Interruptions 0 0 Sustained Interruptions 2 2 Circuit Ranking - Worst Performing Ranked by Outage Count Circuit Substation Fdr#17 Plant 1 Fdr#18 Plant 1 Ranked by Customer Interruptions Circuit Substation Fdr#17 Plant 1 Fdr#18 Plant 1 Number of Outages Customer Interruptions 56 6 Ranked by Customer Minutes of Duration Circuit Substation Customer Minutes of Duration Fdr#17 Plant 1 6,160 Fdr#18 Plant 1 90 https://reliability.publicpower.org/reports/monthly/utility/9l /?year=2019&month=3&is_an... 4/17/2019 eReliability I Monthly Statistics Page 4 of 6 Historical Monthly SAIDI Chart 7 6 5 4 3 2 1 SAIDI values 0° Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 2018 2018 2018 2018 2018 2018 2018 2018 2018 2019 2019 2019 Historical Monthly SAIFI Chart 0.07 0.06 0.05 0.04 0.03 0.02 0.01 SAIFI values u.W_� Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 2018 2018 2018 2018 2018 2018 2018 2018 2018 2019 2019 2019 https:Hreliability.publicpower.org/reports/monthly/utility/9l /?year=2019&month=3&is_an... 4/17/2019 eReliability I Monthly Statistics Page 5 of 6 Causes Ranked by Count Cause Vehicle Accident Causes Ranked by Duration Cause Vehicle Accident Count 2 Duration 6,250 https://reliability.publiepower.org/reports/monthly/utility/91 /?year=2019&month=3&is_an... 4/17/2019 eReliability I Monthly Statistics Page 6 of 6 Top 2 Outages for the Month Customers Address Interrupted 640 Lakewood Dr 56 SW 1110 Hwy 7 West 6 Customer Minutes of Duration Interruption 110 6,160 15 90 Total Customers Affected for the Month: Average Customers Affected per Outage: Start Date 03/01/2019 03/08/2019 62 31 https://reliability.publicpower.org/reports/monthly/utility/9l/?year=2019&month=3&is an... 4/17/2019 Work Order Description 11708 Units 6 & 7 11901 Plant 1 Heating/Air Conditioning 11902 East Engine Room Shop Floor Epoxy 11903 Plant 1 Cooling Tower Upgrade 11904 Unit 8 Controls Upgrade 11905 Lube Oil and Glycol Maintenance Plant 1 11906 Replacement Hoist in East Engine Room Electric Production Total Total Percentage Materials Labor Budgeted Actual Difference Comp„I„eted, $ 14,369,702.00 $ - $ 14,369,702.00 $ 14,338,868.38 $ (30,833.62) 85% 10,000.00 2,000.00 $ 12,000.00 - $ (12,000.00) 35,000.00 $ 35,000.00 - $ (35,000.00) 80,000.00 $ 80,000.00 1,145.75 $ (78,854.25) 270,000.00 35,000.00 $ 305,000.00 - $ (305,000.00) 40,000.00 10,000.00 $ 50,000.00 2,961.68 $ (47,038.32) 30,000.00 $ 30,000.00 - $ (30,000.00) $ 14,834,702.00 $ 47,000.00 $ 14,881,702.00 $ 14,342,975.81 $ (538,726.19) Work Order Description 21901 Pole Repair or Replacement 21902 Station Equipment 21903 Step Up Transformer Unit 3 21904 Duct for Reconductor 21905 Century Court Apartments 21906 Highfield Apartments 21907 Feeder 15 and 16 Reconductor 21908 New Developments 21909 City Road Projects 21910 Century Court Apartments 21911 Transformer Replacements 21912 Transformer New Developments 21913 Highfield Apartments 21914 Meters Electric Distribution Total Materials Labor B„ud;eted 15,000.00 - 15,000.00 10,000.00 10,000.00 100,000.00 5,000.00 105,000.00 15,000.00 65,000.00 80,000.00 20,000.00 15,000.00 35,000.00 20,000.00 15,000.00 35,000.00 50,000.00 100, 000.00 150, 000.0 0 50,000.00 50,000.00 50,000.00 20,000.00 70,000.00 20,000.00 5,000.00 25,000.00 40,000.00 14,000.00 54,000.00 50,000.00 - 50,000.00 15,000.00 3,000.00 18,000.00 30,000.00 - 30,000.00 $ 485,000.00 $ 242,000.00 $ 727,000.00 $ Total Actual Difference - $ (15,000.00) - $ (10,000.00) - $ (105,000.00) - $ (80,000.00) 323.92 $ (34,676.08) - $ (35,000.00) 893.40 $ (149,106.60) 2,409.96 $ (47,590.04) 714.72 $ (69,285.28) - $ (25,000.00) 242.94 $ (53,757.06) 893.40 $ (49,106.60) - $ (18,000.00) - $ (30,000.00) m WWW 5,478.34 $ (721,521 .66) Percentage Completed 5% Administrative Total Work Order Descri tion Budgeted, 51901 Replace #542 2008 Silverado 26,523.00 51902 Replace #573 2008 Super Duty Truck 60,000.00 51903 Replace #827 Tahoe 30,000.00 51904 Replace #651 38,192.00 51905 Replace Vehicle #623 66,837.00 $ 221,552.00 $ Total Actual Difference 26,523.00 - 60,000.00 - 30,000.00 - 38,192.00 - 66,837.00 - $ (221,552.00) Percentage Com�let_ed Work Order Description 61901 Replace Regulators Station 2 61902 Misc Developments and Improvements 61903 5Th Ave (Lynn to Ontario) 61904 SCD Trunk Storm 61905 South Grade Corridor (Dale to Hwy 15) 61906 Clinton Ave SW (Harrington to Merrill) 61907 South Grade Road (School Road to Dale) 61908 Trunk Hwy 7 Pedestrian Trail Improvements 61909 Century Court Apartments 61910 Waller Drive (Feed to HTI) 61911 Isolated Main Replacement (btn Barley and Glenda) 61912 Regulator Station Improvements 61913 Service Lines 61914 Meters, AMI, and all Fittings 61915 Residential Regulators 61916 Trunk Hwy 15 State Improvement Project 61917 Industrial Metering and Regulation 61918 Pressure Monitors- AMI System, Laser Gas Detector Natural Gas Total Total Percentage Materials Labor Budgeted Actual Difference Completed $ 28,000.00 $ 2,000.00 $ 30,000.00 $ 26,238.57 $ (3,761.43) 50% 100,000.00 25,000.00 125,000.00 7,377.04 $ (117,622.96) 300,000.00 20,000.00 320,000.00 - $ (320,000.00) - $ 1,399.80 $ 1,399.80 50,000.00 5,500.00 $ 55,500.00 - $ (55,500.00) 20,000.00 2,750.00 $ 22,750.00 $ (22,750.00) 5,000.00 2,000.00 $ 7,000.00 $ (7,000.00) 10,000.00 4,000.00 $ 14,000.00 $ (14,000.00) 5,000.00 2,000.00 $ 7,000.00 558.85 $ (6,441.15) 95,000.00 25,000.00 $ 120,000.00 - $ (120,000.00) 20,000.00 3,000.00 $ 23,000.00 - $ (23,000.00) 57,000.00 35,000.00 $ 92,000.00 12,803.03 $ (79,196.97) 15% 95,000.00 4,000.00 $ 99,000.00 2,042.60 $ (96,957.40) 35,000.00 - $ 35,000.00 - $ (35,000.00) 225,000.00 5,000.00 $ 230,000.00 1,058.22 $ (228,941.78) 80,000.00 7,000.00 $ 87,000.00 - $ (87,000.00) 20,000.00 3,500.00 $ 23,500.00 - $ (23,500.00) $ 1,145,000.00 $ 145,750.00 $ 1,290,750.00 $ 51,478.11 $ (1,239,271.89) HUTCHINSON UTILITIES COMMISSION ,c�,« Board Action Form 'AlUTlt Agenda Item: Review Policies Jeremv Carter Review Policies BACKGROUND/EXPLANATION OFAGENDA ITEM: es As part of HUC's standard operating procedures, a continual policy review is practiced. This month, the following policies were reviewed and no changes are recommended on these policies at this time: Section 4 of Exempt Handbook Section 4 of Non -Exempt Handbook BOARD ACTION REQUESTED: None EXEMPT SECTION 4 — WAGE AND SALARY INFORMATION PAY PERIOD, PAYDAYS All employees are paid every other Thursday for the two -week period ending the preceding Sunday at 12:00 midnight. Should a payday fall on a holiday, paychecks/direct deposits will be available the preceding day. PAYROLL DEDUCTIONS HUC is required to deduct federal and state income taxes, Social Security tax, and any court - ordered deductions such as child support from paychecks/direct deposits. HUC is also required to deduct the employee's contribution to the Public Employee Retirement Association (PERA). Other deductions may be made from a paycheck/direct deposit such as deferred compensation, and insurance premiums. These payroll deductions may be made only with the employee's written consent. OVERTIME Exempt employees may earn compensatory time on an hour -for -hour basis for all hours worked in excess of 40 hours per week. Exempt employees must use their compensatory time by December 31 of the year in which it is earned or it will be forfeited. Accrued compensatory time shall not be paid out to exempt employees upon separation from employment. COMPENSATION PLAN The Hutchinson Utilities Commission (HUC) has considered the existing positions for HUC and the current economic conditions. For each position there shall be a title, job description, and a pay scale level assigned. This plan covers all regular full-time, exempt positions/employees only. Plan Objectives To establish and maintain a compensation plan that enables HUC to be highly competitive within our defined industry. To lead or exceed the market in attracting and retaining qualified, reliable and motivated employees who are committed to quality and excellence for those we serve. To ensure, subject to the financial condition of HUC, that employees receive fair and equitable compensation in relation to their individual contributions to HUC's success. To follow the principles of pay equity in establishing and maintaining pay relationships among positions. To ensure program flexibility necessary to meet changing economic, competitive, technological, and regulatory conditions encountered by HUC. To balance compensation and benefit needs with available resources. Open Salary Range HUC shall adopt an Open Salary Range compensation plan that will allow for maximum flexibility since there are not defined or pre -calculated "steps". Employee movement is based solely on performance. The open salary range concept rewards good and exceptional performers and advances employees to the market rate more quickly. Allocation of New Positions When a new position is created for which no appropriate description exists or when the duties of an existing position are sufficiently changed so that no appropriate description exists, the Commission, after recommendation of the Customer/HR Manager, shall cause an appropriate job description -specification to be written for said position. Pay Scales Pay scales will be adjusted on an annual basis in accordance with adjustments made in the labor agreement. Exempt Employees Each position will have a nine -month probationary period. After satisfactory completion of the probationary period, an increase may be granted as warranted by the annual performance appraisal. Thereafter, consideration for increases will be given annually at the first of the year. The General Manager reserves the discretion to adjust individual rates as required. The Commission will determine any pay increase for the General Manager. Consideration for market adjustment will be made each January 1. The General Manager shall maintain the discretion to hire at any point based on the qualifications, experience, market conditions or other relevant factors, to secure the best candidate for the position. Performance Evaluations For all regular full-time employees, a performance appraisal or evaluation will be made on an annual basis. An evaluation made by the employee's director, manager or supervisor shall be submitted in writing to the employee and the General Manager. All evaluations will be forwarded to the Customer/HR Manager for filing in the employee files. Evaluations shall be based upon the performance of the individual in the position measured against established job performance criteria. Such criteria may include level of knowledge, skills, ability, quality of work, personal work traits, compliance with established HUC or departmental rules and regulations or any other criteria that is indicative of performance. The performance appraisal process is the application of performance standards to past performance. In appraising an employee, these are the basic levels of performance: 5 — Outstanding — Performance is exceptional in all areas and is recognizable as being far superior to others. 4 — Exceeds Job Requirements — Results clearly exceed most positions requirements. Performance is of high quality and is achieved on a consistent basis. 3 — Meets Job Requirements — Competent and dependable level of performance. Meets performance standards of the job. 2 — Needs Improvement — Performance is deficient in certain area(s). Improvement is necessary. 1— Unsatisfactory — Results are generally unacceptable and require immediate improvement. Results - The results of the exempt employee's evaluation will normally have the following effect on his/her salary per the following Merit Increase Guide: Oto1.0— 0% 1.1 to 1.99 — Straight 1% increase 2.0 to 2.75 — -1% of Union % increase 2.76 to 3.5 — Union % increase 3.51 to 4.25 — +1% of Union % increase 4.26 to 5.0 — +2% of Union % increase Market Conditions Notwithstanding any language to the contrary, HUC retains the right to deviate from the pay plan when, in the sole judgment of the Commission, market conditions or other circumstances dictate such a decision. Market conditions are defined as the availability of a particular position. Eligible employees include all non -represented employees except those who have been subject to disciplinary action per the HUC Employee Handbook as follows: An additional consequence of disciplinary action more severe than oral reprimand will be the permanent loss of the January 1 market adjustment in the calendar year following such disciplinary action. This will occur unless the Director in charge and the General Manager decide otherwise. Annual Market Adjustment Consideration On an annual basis, a market survey will be reviewed. As a result of the current year marketplace, an additional increase may be deemed necessary. The General Manager maintains final approval responsibility for salary increases. Any market adjustment on January 1 of any year shall be separate and apart from the individual merit increases. In determining a recommendation for an annual market adjustment, the General Manager shall consider, at least the following information: 1. U.S. and Minneapolis/St. Paul consumer -priced index changes (CPIU & CPIW) 2. Social Security calculation of cost of living increase 3. Unemployment rate 4. Employee turnover rate 5. Area wage survey 6. Legislative growth factor constraints 7. Bargaining Unit Increase Modification of the Plan HUC reserves the right to modify any or all of the components or to vary from any of the components of the Compensation Plan at its discretion and at any time. Review of the Plan It is recommended that HUC's Customer/HR Manager annual review and maintain its Position Classification Plan. As deemed necessary, the Customer/HR Manager would recommend any changes to the Commission. It is further recommended that a comprehensive review be completed every five years. TRAVEL EXPENSES Business Related Vehicle Operation Travel within the State shall be by HUC vehicle if possible. If a HUC vehicle is not available for in -State travel, or is not practical to use, then an employee may seek approval from Director or Manager to use a personal vehicle for transportation. The following rules shall apply: • The employee shall be reimbursed for mileage at the current IRS mileage reimbursement rate. • HUC is not liable for damage to personally owned vehicles used for HUC business. • HUC may request proof of insurance from employees who use personally owned vehicles on HUC business. • Travel to and from events should be by the most direct route possible. • Employees are expected to return in a timely manner. Travel outside of the State must be approved by the employee's Director or Manager. If it is appropriate to drive, the employee shall follow the same rules as travel within the State. Whether a HUC vehicle, or a personal vehicle is used, the employee is responsible for any traffic or parking citations the employee receives while operating such vehicle on HUC business. Employees who drive a HUC vehicle home may use the vehicle only for HUC business purposes. Employees who are members of the Hutchinson Fire Department or Rescue Squad may use a HUC vehicle to travel to the fire station to respond to a call when the firefighter or rescue squad member is on the job with HUC at the time of the call_ If the firefighter or rescue squad member is at HUC, they must use a personal vehicle to respond to the call. Air Travel and Rental Vehicles It is recognized that air travel may be a necessary part of conducting business for HUC. In the circumstances of air travel, the following rules shall apply: • Commercial carriers shall be used. • Tickets should be at "standard" or "coach" class. • Travel to and from the airports shall follow the Business Related Vehicle Operation section. • Travel outside of the State must be approved by the employee's Director or Manager. • Only employee's air travel expenses shall be prepaid, charged, or reimbursed at cost. Rental vehicles may be used when traveling outside of the State. Reservations of a rental vehicle shall be made at the same time air travel is arranged. Renting a vehicle must be approved by the employee's Director or Manager. Overnight Stays, Meals and Entertainment Expenses Hotel reservations shall be made prior to the employee leaving for out of town travel. The following items shall apply to overnight stays: • Hotel accommodations for the employee must be approved by the employee's Director or Manager. • In the event the employee is traveling on HUC business and experiences inclement weather, to the extent that it is not safe to travel, or the employee is not able to travel due to some circumstance that is beyond their control, then no prior approval for hotel accommodations are necessary. • Hotel rooms at convention or seminar sites are approved accommodations. • Reimbursement is limited to employees and business related guests, and must be directly related to business. The following shall apply to expenses associated with meals: • Meals shall be limited to a maximum of $50 per day, including meal tips. The $50 per day is a maximum and not an allowance. • Meal reimbursement is limited to employees. • Expenses associated with alcoholic beverages shall not be reimbursed. Expense Report An expense report shall be filled out for all reimbursement requests for purchases using personal funds. Unsupported expenses using personal funds shall not be reimbursed by HUC. An expense report shall also be filled out for all company travel purchases. Unsupported expenses on an HUC credit card shall be reimbursed to HUC by the employee. The expense report must state the type of expense (meal, travel, hotel, etc.), the date and the business purpose. Alcohol is not a reimbursable expense. It is the employee's responsibility to obtain an itemized receipt. The expense report shall be approved by your Director, Manager, or Supervisor before submitting to the Financial Manager. WORKER'S COMPENSATION An employee who is injured on the job or becomes ill due to job -related reasons is eligible for worker's compensation benefits. HUC's worker's compensation insurance provider shall pay the employee approximately 2/3 of the weekly gross wage or salary lost due to injury or illness and HUC shall pay the additional 1/3 of the weekly gross wage for up to 120 work days. Thereafter, the employee may use accrued sick leave, vacation leave, or compensatory time to pay the additional 1/3 lost wage or salary. PERA and FICA are not deducted from the worker's compensation portion of the paycheck. NON-EXEMPT SECTION 4 — WAGE AND SALARY INFORMATION PAY PERIOD, PAYDAYS All employees are paid every other Thursday for the two -week period ending the preceding Sunday at 12:00 midnight. Should a payday fall on a holiday, paychecks/direct deposits will be available the preceding day. PAYROLL DEDUCTIONS HUC is required to deduct federal and state income taxes, Social Security tax, and any court - ordered deductions such as child support from paychecks/direct deposits. HUC is also required to deduct the employee's contribution to the Public Employee Retirement Association (PERA). Other deductions may be made from a paycheck/direct deposit such as union dues, deferred compensation, and insurance premiums. These payroll deductions may be made only with the employee's written consent. OVERTIME See Union Contract. COMPENSATION PLAN Performance Evaluations For all regular full-time employees, a performance appraisal or evaluation will be made on an annual basis. An evaluation made by the employee's director, manager, or supervisor will be submitted in writing to the employee and the General Manager. All evaluations will be forwarded to the Customer/HR Manager for filing in the employee files. Evaluations shall be based upon the performance of the individual in the position measured against established job performance criteria. Such criteria may include level of knowledge, skills, ability, quality of work, personal work traits, compliance with established HUC or departmental rules and regulations or any other criteria that is indicative of performance. The performance appraisal process is the application of performance standards to past performance. In appraising an employee, these are the basic levels of performance: 5 — Outstanding — Performance is exceptional in all areas and is recognizable as being far superior to others. 4 — Exceeds Job Requirements — Results clearly exceed most positions requirements. Performance is of high quality and is achieved on a consistent basis. 3 — Meets Job Requirements — Competent and dependable level of performance. Meets performance standards of the job. 2 — Needs Improvement — Performance is deficient in certain area(s). Improvement is necessary. 1— Unsatisfactory — Results are generally unacceptable and require immediate improvement. TRAVEL EXPENSES Business Related Vehicle Operation Travel within the State shall be by HUC vehicle if possible. If a HUC vehicle is not available for in -State travel, or is not practical to use, then an employee may seek approval from Director or Manager to use a personal vehicle for transportation. The following rules shall apply: • The employee will be reimbursed for mileage at the current IRS mileage reimbursement rate. • HUC is not liable for damage to personally owned vehicles used for HUC business. • HUC may request proof of insurance from employees who use personally owned vehicles on HUC business. • Travel to and from events should be by the most direct route possible. • Employees are expected to return in a timely manner. Travel outside of the State must be approved by the employee's Director or Manager. If it is appropriate to drive, the employee shall follow the same rules as travel within the State. Whether a HUC vehicle, or a personal vehicle is used, the employee is responsible for any traffic or parking citations the employee receives while operating such vehicle on HUC business. Employees who drive a HUC vehicle home may use the vehicle only for HUC business purposes. Employees who are members of the Hutchinson Fire Department or Rescue Squad may use a HUC vehicle to travel to the fire station to respond to a call when the firefighter or rescue squad member is on the job with HUC at the time of the call_ If the firefighter or rescue squad member is at HUC, they must use a personal vehicle to respond to the call. Air Travel and Rental Vehicles It is recognized that air travel may be a necessary part of conducting business for HUC. In the circumstances of air travel, the following rules shall apply: • Commercial carriers shall be used. • Tickets should be at "standard" or "coach" class. • Travel to and from the airports shall follow the Business Related Vehicle Operation section. • Travel outside of the State must be approved by the employee's Director or Manager. • Only employee's air travel expenses will be prepaid, charged, or reimbursed at cost. Rental vehicles may be used when traveling outside of the State. Reservations of a rental vehicle shall be made at the same time air travel is arranged. Renting a vehicle must be approved by the employee's Director or Manager. Overnight Stays and Meals Hotel reservations shall be made prior to the employee leaving for out of town travel. The following items shall apply to overnight stays: • Hotel accommodations for the employee must be approved by the employee's Director or Manager. • In the event the employee is traveling on HUC business and experiences inclement weather, to the extent that it is not safe to travel, or the employee is not able to travel due to some circumstance that is beyond their control, then no prior approval for hotel accommodations are necessary. • Hotel rooms at convention or seminar sites are approved accommodations. • Reimbursement is limited to employees and business related guests, and must be directly related to business. The following shall apply to expenses associated with meals: • Meals shall be limited to a maximum of $50 per day, including meal tips. The $50 per day is a maximum and not an allowance. • Meal reimbursement is limited to employees. • Expenses associated with alcoholic beverages will not be reimbursed. Expense Report An expense report shall be filled out for all reimbursement requests for purchases using personal funds. Unsupported expenses using personal funds will not be reimbursed by HUC. An expense report shall also be filled out for all company travel purchases. Unsupported expenses on an HUC credit card shall be reimbursed to HUC by the employee. The expense report must state the type of expense (meal, travel, hotel, etc.), the date and the business purpose. Alcohol is not a reimbursable expense. It is the employee's responsibility to obtain an itemized receipt. The expense report shall be approved by your Director, Manager, or Supervisor before submitting to the Financial Manager. WORKER'S COMPENSATION An employee who is injured on the job or becomes ill due to job -related reasons is eligible for worker's compensation benefits. WC's worker's compensation insurance provider will pay the employee approximately 2/3 of the weekly gross wage or salary lost due to injury or illness and HUC shall pay the additional 1/3 of the weekly gross wage for up to 120 work days. Thereafter, the employee may use accrued sick leave, vacation leave, or compensatory time to pay the additional 1/3 lost wage or salary. PERA and FICA are not deducted from the worker's compensation portion of the paycheck. HUTCHINSON UTILITIES COMMISSION��` Board Action Form 41ri ars mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Unit #8 Control System Upgrade - Reject Bids and Approve Re -Advertisement Presenter: JC Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments; Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: Staff is requesting Board approval to reject bids from the April 2nd bid opening for the Unit #8 Control System upgrade project. HUC received four bid submittals but all bids contained errors due to missing or incomplete information as required by the Advertisement for Bids and Bid Specifications. HUC legal recommends that all bid submittals be rescinded and to re -advertise for bids. Staff is also requesting Board approval to re -advertise for bids for the Unit #8 Control System upgrade project. HUC will receive sealed bids at the Hutchinson Utilities office until 2pm on May 14th, 2019 and then publicly open and read aloud such Bids on the following construction: "Control System Replacement for General Electric Frame 3 Combustion Turbine Balance of Plant Equipment". BOARD ACTION REQUESTED: Reject bids from the April 2 bid opening of Unit #8 Control System Upgrade and Approve Re -Advertisement for Bids of Unit #8 Control System Upgrade. Fiscal Impact: None Included in current budget:' No Budget Change: No PROJECT SECTION:' Total Project Cost: Remaining Cost; Advertisement for Bids for "Control System Replacement for General Electric Frame 3 Combustion Turbine Balance of Plant Equipment" Hutchinson Utilities Commission Hutchinson, Minnesota Notice is hereby given that the Hutchinson Utilities Commission of the City of Hutchinson, 225 Michigan Street SE, Hutchinson, Minnesota, hereinafter referred to as the Owner, will receive sealed Bids at the Hutchinson Utilities office until 2pm (CDT) on the 14t" day of May 2019, and will publicly open and read aloud such Bids at 2pm (CDT) on the 14t" day of May 2019, at the same location on the following equipment: "Control System Replacement for General Electric Frame 3 Combustion Turbine Balance of Plant Equipment" Proposals shall be properly endorsed and delivered in an envelope marked, "Control System Replacement for General Electric Frame 3 Combustion Turbine Balance of Plant Equipment" and shall be addressed to: Randy Blake, Production Manager, Hutchinson Utilities Commission, 225 Michigan Street SE, Hutchinson, Minnesota. Bids shall be supplied in both hardcopy and electronic format. The name and address of the Bidder shall be clearly indicated on the outside of the package containing the bid. Bidder shall provide one (1) original (clearly marked as such) and two (2) copies of the bid along with 2 flash drives containing electronic PDF files of their bid. Each bid should be accompanied by a Bid Bond, made payable to the Hutchinson Utilities Commission of the City of Hutchinson, Hutchinson, Minnesota, in the amount of five per cent (5%) of the Bid, as a guarantee that the Bidder will enter into the proposed Contract and provide a Performance and Payment Bond after the Bid has been accepted. The successful Bidder shall furnish a Performance Bond and Payment Bond in an amount equal to one hundred per cent (100%) of the Contract price to the Owner prior to the approval of the Contract. No Bidder may withdraw their Bid or Proposal for a Period of sixty (60) days after date of opening of Bids. At the aforementioned time and place, or at such later time and place as the Owner then may fix, the Owner will act upon Proposals received and with its sole discretion may award Contract(s) for the furnishing of said equipment. A site visit to HUC's facility prior to bid submittal is optional and will be held on May 6t" at 2pm (CDT) for interested Bidders. Bidders that do not attend the optional site visit waive any claim for contract price increases when encountering items that, in the engineer's opinion, would have been revealed through a visit to the site. For questions or to arrange a site visit contact Dan Lang, Hutchinson Utilities Commission Engineering Manager, at 320-234-0564. The Hutchinson Utilities Commission of the City of Hutchinson, Hutchinson, Minnesota reserves the right to reject any and all bids, or bid irregularities. In . President Date ATTESTED , Secretary Date HUTCHINSON UTILITIES COMMISSION��` Board Action Form rMturit mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Approve Requisition #007907 Presenter: Randy Blake Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments: Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: In July of 2018 the Production Operations staff made an attempt to operate unit 1 in combined cycle mode to exercise the boiler and perform the steam turbine over speed tests. While bringing the steam turbine up to warming speed a leak was discovered on the superheat line between the boiler and steam turbine. Staff aborted the testing and when the pipe cooled down insulation was removed to find the leaks. There were multiple spots that had leaks. Braun Intertec was contacted to x-ray test the affected piping area. The test results indicated that the pitting in the pipes was caused by poor drainage meaning the original install of that section of piping was incorrect and would not allow the condensate to completely drain. 3 quotes were received for this repair. All 3 contractors stated that the newly installed pipes will have the correct fall for complete condensate drainage. All quotes included re -insulating the pipes. The repair involves the welding of 40' of 6" pipe and four 6" elbows. This item will be covered by the Production area's operating budget. The quotes are as follows: Southern Minnesota High Pressure Piping - $49,960.17 Plaas Inc. $48,375.00 Mechanical Systems Inc. $44,803.43 BOARD ACTION REQUESTED: Approve requisition # 007907 to Mechanical Systems Inc. in the amount of $44,803.43 Fiscal Impact: $44,803.43 Included in current budget:Yes Budget Change: No PROJECT SECTION:' Total Project Cost: $44,803.43 Remaining Cost: 0 HUTCHINSON UTILITIES ra,�itiak° tt ni'i ni'it II Ewa s�io ni MECHANICAL SYSTEMS INC. 800 WEAVER LANE SUITE A DUNDAS, MN 55019 Note Description: PURCHASE REQUISITION HUTCHINSON UTILITIES COMMISSION 225 MICHIGAN ST SE HUTCHINSON, MN 55350 Phone:320-587-4746 Fax:320-587-4721 Date Requisition No. 04/09/2019 007907 Required by: Requested by: RBlake Item No. part No. Description Qty Unit Due Date Unit Price Ext. Amount UNIT 1 - 6" SUPERHEAT PIPING REPAIR - UNIT 1- 6" SUPERHEAT PIPE REPAIR AND 1 INSULATION 1.00 EA 06/08/2019 $44,803.430 $44,803.43 MFG. PART: Total: 44,803.43 Date Printed: 04/15/2019 Requisitioned By: RBlake Page: 1/1 SO VTNdtN YfNNB SOFA 92_ __ — 0 320 Adams Ave. NE PO Box 212 Madelia MN 56062 Name / Address Hutchinson Utilities Commission 225 Michigan Street SE Hutchinson MN 55350-1905 Description Replacement of 6" High Pressure Steam Line Option 1: Insulation NOTES: - Estimate is NOT to exceed - Estimate includes: Labor, consumables, x-ray, Superheat, Scaffolding, Insulation (see Option 1), Permit and Sales Tax - Project time frame is 1st part of April - If project is tax exempt, please provide a ST3 We look forward to doing business with you! Estimate Date Estimate # 2/25/2019 1916 Qty Rate Total 1 42,425.17 42,425.17 1 � 7,535.001 7,535.00 Subtotal $49,960.17 Sales Tax (7.375%) $0.00 Total $49,960.17 March 27, 2019 Randy Blake iL la e �ci.hut hiin on nn.0 Hutchinson Utilities Commission - Hutchinson, MN Unit #1, 6" Sch 40 P11 Superheat Line Dear Randy, We are pleased to submit for your consideration the following proposal: All labor, materials (excluding pipe/fittings), consumables, MNN HPP Permit, equipment, ,NDE (X-Ray), and Pre/Post Heat to complete demo and install of the Unit #1 Superheat 6" Sch40 P11 line. Mechanical Systems Incorporated will complete the above project for the following bid amounts: UNIT #1 SUPERHEATER LINE '6" SCH 40, P11 ........ -.... ..... ....._..�.. ww.... Exclusions: 1. 6" Sch 40, P11 Pipe & Fittings (Supplied by Customer) 2. Disposal of Demoed Pipe, Fittings, and Consumables. Cost Sales Tax Total Cost Material/Equipment $9,062.00 $368.00 $9,430.00 Cost Labor Cost � $30,446.00 $0.00 $30,446.00 ........ _._. m$39 Total Cost $39,508.00 $368.00 876.00 UNIT #1 SUPERHEATER LINEINSULATION} Cost Sales Tax Total Cost Material_ .. $2,096.45 IT $157.23 $2,253 68 Labor/E u�......... ment mm $0.00_$2,673.75 Total Cost ww$2,673.75 ' $4 770.20 $157.23 $ 4 927.43 TOTAL BID AMOUNT= $44,803.43 Please contact me with any questions or concerns we appreciate the opportunity to quote this project! Sincerely, Zac Maslowski Mechanical Engineer ,acirn h t rm! iron.. o laas Incorporatea 1427 Old West Main Red Wing Minnesota 55066 651-388-8881 Fax 651-388-1621 March 281, 2019 Randy Blake Production Manager Office-320-234-0551 Cell-320-582-1565 Sent via email: �b1lal,c°i„r Project: Chrome Piping Repair Dear Randy, Plaas Incorporated appreciates the opportunity to submit the following price quotes for the piping repair projects. The following price quote includes all necessary labor, equipment, permits, and materials for a complete installation per specifications provided in the RFQ. Proposal Includes: • State HPP Permit $1,200 • Labor with licensed HPP journeymen $12,750 • Heat Treat Subcontractor $8,500 • NDE (X-ray) Subcontractor $4,300 • Equipment $500 • Consumables $965 • Scaffolding rental, installation and disassembly $13,360 Insulation Repair and install $6,800 Project Price: $48,375 Schedule Based on Issue of a PO: • Timing shall be within the next 4 months, preferably summer or warmer weather. • We estimate that the piping will take 2 weeks to complete. 1 day to erect scaffolding 4 days to install and fix the piping, and teardown of scaffolding and heat treat with NDE the remaining days. • Proposal is based on a field schedule of (5) 10 hour work days per week. Price Does NOT Include: • Any required electrical work. • Liquidated, consequential or other damages. Clarifications: • For further reference, Hutchison Utilities Commission shall be referred to as the Buyer, and Plaas Incorporated shall be referred to as the Seller. • Buyer to provide a copy of your Certificate of Exemption. Otherwise taxes are included in the proposal. • It is the responsibility of the Buyer to specify the process conditions, materials of construction and corrosion allowance. • Proposal based on OSHA Safety Standards for Construction (29 CFR Part 1926). Any additional site requirements will be evaluated for cost impact and invoiced on a cost plus 10%, plus overhead. • Buyer will provide copies of the SDS's for the product contained in the tank for review prior to beginning work. • Staging area for delivered materials and fabrication is in close proximity to the work site. Location for a crane set-up is in close proximity to the lift area. • Seller's proposal assumes initial site orientation and safety meeting at mobilization. Additional attendance to extra orientation and safety meetings will be invoiced on a cost plus 10%, plus overhead. Dedicated attendant (hole -watch) is included — fulfilled by Foreman as needed. Fire watch is included — fulfilled by crew personnel as needed — not dedicated. • Our proposal excludes any extra personnel such as extra operating engineers etc. if required on your site. • Material ordered (quantity, size and specification) are based on information provided by the Buyer. • Buyer will coordinate final review by the tank inspectors prior to Seller leaving the job site. • Price covers all consumables (welding filler metals and gases, oxy-acetylene carts, grinding wheels, equipment fuel, PPE, Seller supplied scaffolding, rigging, etc.). Consumables are estimated at 10% of the total project man hours cost. Seller will only be charging for large equipment such as cranes, generators, man -lifts, welding machines, forklifts, light towers, compressors, etc. • Scaffolding shall be supplied and erected by Seller trained personnel or Seller's subcontractor in accordance with OSHA regulations and inspected prior to use as needed by such. • All welding shall be in accordance with Seller's weld procedures. The welding processes that may be used in reference to this proposal are SMAW, GTAW. FCAW or GMAW. • All MT and PT examinations performed directly by Seller shall be in accordance with Sellers NDE procedures. • Subcontractor's estimates are budgetary only. Any additional cost the project that may incur due to weather delays, drain down times, or reasons beyond Sellers control, will be billed at cost plus 10%, plus overhead. • Weather Impact: base proposal includes (0) weather loss days of rain/snow, or combination 0 degrees F or less and 20 mph wind delay. Seller will bill (2) hours per employee show up time per occurrence invoiced separately on monthly basis. • Any additional cost the Seller may incur due to down times resulting from the expediting of material supplied by Buyer, engineering or routing conflicts, extra orientation and safety meetings, unscheduled operations interruptions, delays in equipment turn -over, other Buyer contractor interruptions or reasons beyond the Sellers control by the Buyer, will be billed at cost plus 10%, plus overhead. • Site and work area maintenance (i.e. dust control, snow/ice removal, gravel/drainage) by the Buyer at no cost to Seller. • Seller may elect to provide a site office trailer and/or tool trailer. Buyer will connect and disconnect temporary power to the site office trailer and/or tool trailer at the Buyers expense. Site office trailer and/or tool trailer shall be located as close to the worksite as possible. • Delivery dates, if specified are not guaranteed. Seller will use its best efforts to make delivery at the earliest possible time, but Seller shall not be liable in the event of delays in delivery or failure to deliver when caused by acts of nature, fire, civil or military authority, insurrection, riot, delays in transportation, inability to obtain supplied or materials or any cause beyond its reasonable control. • Cancellation or Modification of Delivery Date(s): Any order accepted by Seller may be canceled or specified delivery dates modified by Buyer only with specific approval of Seller. Any cancellations shall be subject to termination charges payable by Buyer to Seller, which charges shall include, among other things, expenses and commitments already incurred or made in connection with deliveries to be made to Buyer and a reasonable allowance for loss of Seller's anticipated profit according to Seller's standard accounting practices, any modification of delivery dates shall be subject to modification charges payable by Buyer to Seller, which charges shall include among other things, compensation to Seller for removal from Seller's manufacturing schedule, special handling and the like. • Change Orders: Buyer will issue a change order for additionally requested services beyond the original scope prior to beginning the work. Change order will include compensation and schedule. • Warranty and Disclaimer: Seller warrants only that each product to be delivered under an order accepted by Seller shall, at the time of delivery and for a period of one year thereafter, be free from defects in materials and workmanship. Seller's liability shall be limited, at its option and expense, to repair or replacement of any defective or nonconforming product. This express warrant is in lieu of all other warranties, express or implied. Including the implied warranties of fitness for a particular purpose and merchantability. • Governing Law: All orders accepted by Seller shall be governed by and construed in accordance with the laws of the State of Minnesota with all disputes resolved in the State of Minnesota. • Liability of Seller: (a) Any provision contained herein to the contrary notwithstanding, the maximum liability of Seller to any person whatsoever arising out of or in connection with any sale, use or other employment of any product sold to Buyer under any order accepted by Seller, whether such liability arises from any claim based upon contract, warranty tort or otherwise, shall in no cases exceed the actual amount paid to Seller by Buyer for the products delivered hereunder. (b) In no event shall Seller be liable to Buyer or to anyone else for incidental or consequential damages. • Terms of Payment, Net 30 days. No retainage. • Our Proposal assumes the exclusion or revision of the provided Terms and Conditions prior to order acceptance. • Our Proposal must be made a part of any resulting Purchase Order or Contract, and in the event of a conflict, our Proposal takes precedence over all other documents and agreements. If you should have any questions, please call me at 651-388-8881. Thank you again for this opportunity. If the above is acceptable, please remit a Purchase Order to Plaas via email: a�N.�;.�s'�1::1� a xu. i.I.�.a (29-p Sincerely, �ZGtCi eW V"&% Andrew Boster Project Manager, QC, Safety HUTCHINSON UTILITIES COMMISSION��` Board Action Form rMturit mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Approve Requisition #007908 Presenter: Randy Blake Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments: Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: HUC's Unit 1 gas turbine/generator modules were installed in 1993. The paint on several areas has deteriorated and needs to be cleaned and repainted. 3 quotes for this work were received as follows: Precision Iceblast Corporation-$116,875.00 R & H Painting LLC-$94,000.00 Elevation Coating LLC-$59,750.00 This work was budgeted for in the Production areas operating budget for 2019. BOARD ACTION REQUESTED: Approve requisition # 007908 to Elevation Coatings LLC for the amount of $59,750.00 Fiscal Impact: $59,750.00 Included in current budget:Yes Budget Change: No PROJECT SECTION:' Total Project Cost: $59,750.00 Remaining Cost: 0 HUTCHINSON UTILITIES ra,�itiak° tt ni'i ni'it II Ewa s�io ni ELEVATION COATING LLC. 7391 43RD AVE SAINT CLOUD, MN 56304 Note Description: PURCHASE REQUISITION HUTCHINSON UTILITIES COMMISSION 225 MICHIGAN ST SE HUTCHINSON, MN 55350 Phone:320-587-4746 Fax:320-587-4721 Date Requisition No. 04/09/2019 007908 Required by: Requested by: RBlake Item No. part No. Description Qty Unit Due Date Unit Price Ext. Amount PAINTING OF UNIT 1 ENGINED MODULES - PAINTING UNIT 1 ENGINE/GENERATOR 1 MODULES 1.00 EA 09/06/2019 $59,750.000 $59,750.00 MFG. PART: Total: 59,750.00 Date Printed: 04/15/2019 Requisitioned By: RBlake Page: 1/1 LEVATION g COATINGLI.C. COMMERCIAL AND INDIPSTMAI. niiviiiiw Painting Proposal For: Hutchinson Utilities Commission Structure March 26, 2019 To: RANDY BLAKE Via Email We propose to furnish all labor and materials for the cleaning, surface preparation and coating application of the power plant structure (per the meeting on March 21, 2019) located at 1100 Industrial Blvd in Hutchinson, MN. Surface Preparation All Surfaces - hot water pressure wash to clean surface and expose any weak coating areas not already visible *3,500psi @ 150T with turbo nozzles Rust/Failed Coating Areas - spot blast (dry abrasive blast) these areas to bare metal and feather edges into existing sound coating *areas will be blast cleaned to a near -white metal, SSPC-SP10 standard Coating Application Rust/Failed Coating Areas - 2 coats, Tnemec Chembuild, Series 135 @ 4-6 mils (Dry Film Thickness) All Surfaces - 1 "tie -coat," Tnemec Chembuild Series 135 @ 4-6 mils *we call it a tie -coat because this specific epoxy has excellent adhesive properties when applied over existing coatings ....... we have had years of success with this product for overcoating water towers, tank farms etc. All Surfaces -1 topcoat, Tnemec Endura-Shield, Series 1075 @ 3-5 mils (Dry Film Thickness) *this is an aliphatic acrylic polyurethane with UV inhibitors that assure the coating will retain its color and semi gloss finish '7391. 43rd Ave, SE Stu Cloud, MN 5630476 -1 2-2067 ELEVATION N 1CO3AT1,1L0LLC. COMMEIRC AL AND IN MURK . PAINTWO --------------- TOTAL Base Bid Lump Sum of- fiftv nine thousand seven hundr d fifty and zero 1 00 Dollars ($59,750.00) Please contact us if you have any questions regarding this proposal, our process etc.. Sincerely, Brian J. Minkler Co-Owner/Project Specialist Elevation Coating, LLC NACE Certified Coating Inspector Level 2, #47019 Brian@elevationcoating.com 612-400-4695 7391 43rd Ave, SE St. Cloud, MN 56304 761,,742a,.2067 RECISION CEBLAST CORPORATION ................. _. ....... 801 Maple Street Peshtigo, Wisconsin 54157 Phone 906-864-2421 Fax 906-864-2425 Ice blasting does a superior job preparing surfaces for painting. Our system is the most aggressive system in the country. We blast at up to 350 psi which ensures that all loose paint is removed from the surface and further paint failure will not occur underneath the new coating. Also, the dry ice particle penetrates any pores or crevices on steel surfaces, thereby removing contaminants. Ice blasting removes all microorganisms and oils as well which can contribute to paint failure if they are not removed. Collectively, these characteristics of ice blasting provide the cleanest possible surface for applying a coating. Coatings can be applied immediately after the surface is ice blasted because it is completely clean and dry. If the surface is already wet, ice blasting will dry out the wet surface. Our technology creates the best surface for the paint to bond, therefore, providing the greatest longevity for the paint's lifespan. This application will require the use of two high pressure ice blasting guns, one abrasive blasting gun, needle guns, two compressors and four laborers per shift. Areas will be blasted at pressures between 150 — 350 psi in order to ensure that all loose failing paint is removed. Areas will be accessed via boom lifts. Precision Iceblast Corporation agrees to furnish trained labor, materials, consumables, diesel, transportation, safety equipment, paint sprayers and blasting equipment to clean in preparation for recoating the exterior of Unit # 1 at your Hutchinson, Minnesota facility. Area to be coated is from the Inlet to the start of the HRSG. PIC will needle gun and abrasive blast all heavy scaled areas before ice blasting to ensure all impacted rust is removed. PIC will remove dirt, pulp, loose paint, scale, and other build-up in preparation for recoating. Upon completion of blasting, PIC will mask off and contain all surfaces that are currently not coated. We will then apply one coat (4.0-6.0 DFT) of Carboline Carboguard 890 to all of the bare surfaces and then apply one coat of Carboline Carbothane 134 (3.0-5.0 DFT) over the entire unit. Coating color will be matched to existing coating. Work will take place in the spring of 2019 and will be performed in twelve single 12- hour shifts. Work can be completed around -the -clock to shorten the downtime to six days for an additional cost. PIC will be responsible for providing a broom clean up upon completion of blasting and accessing all areas. Hutchinson Utilities Commission will be responsible for disposal of all wastes materials. Price will include travel, per diems, site specific safety training, set up, clean up, blasting, compressor, dry ice, diesel, paint, paint sprayers and paint materials. Changes to that scope of work will change the below Price for above stated work: 1I $ 116,875.00 Terms are 25% with Purchase Order, due 30 days prior to start of project. The remaining 75% will be Net 15 days upon job completion A 2% penalty will occur after the initial 5 days of the due date of each invoice and then every 30 days thereafter. Extra costs will occur if Precision Iceblast Corporation's work is delayed as a result of the customer's actions or reasons beyond Precision Iceblast Corporation's control including but not limited to weather. If for any reason work is terminated early, Precision Iceblast Corporation will receive a mobilization charge plus be compensated for work that has already been performed and material costs for work that was not performed. A change order will need to be signed for any change from the original scope of work. "This non -binding quote is provided for informational purposes only, and neither Customer nor PIC will have any obligation to the other (contractual or otherwise) with respect to the work described herein. If Customer and PIC wish to proceed, PIC will provide Customer a separate definitive written agreement to be signed by the parties that sets forth their respective rn hts and oblnations." HUTCHINSON UTILITIES COMMISION AftwRANDYBIAKE 1106 Industrial Blvd Hutchinson, MN Contact: Randy 320.582.1565 Onsite Evaluation Date: Thursday, February 7' 2019 Note: This quote may be withdrawn by us if not accepted within 60 days of 02-11-2019 Proposal Summary: R & H Painting inspected the Unit One exterior steel surfaces pictured above located in Hutchinson, Minnesota. The unit surfaces are deteriorating and would benefit from High Performance Coatings to help protect its long term integrity. We propose to properly prepare and refinish the exterior painted steel surfaces as described in the following pages. Customer: Sign & return one copy, retain one copy for your files. 1 I Page Exterior Services Provided by R&H Painting ® Surface Preparation * Coordinate Scheduling with Randy and or other plant personnel. * Sensitive equipment and specified components will be masked off and protected. R&H will remove & reinstall signage and galvanized steel as necessary. Surfaces to be prepared using a combination of hot high pressure washing with an I I III 1�� i WINE! iii i I! i I ii Ii i I Farm cost if necessary. ® Coatin , I I I I I 1 11 1 11 Pill! illi FIT 1 1 , Ell Tim, o Material IT, a All Unit One Exterior Painted Steel Surfaces (see picture above) Color — To Match. C l' Full Coat: Sherwin Williams, Devoe, or Induron High Performance Coatings, 0 2 d Full Coat: Sherwin Williams, Devoe, or Induron High Performance Coatings. —Estimated 20 Plus Year Service Life — Completion cleanup at project completion. R&H Painting has safely produced excellent results time and again in the industrial & commercial environments over the past forty-four years. R&H Painting provides long-term cost saving solutions. Customer: Sign & return one copy, retain one copy for your files. 2 1 P a g e Price Incl!gding, Labor and Materials Installed• • All Unit One Exterior Painted Steel Surfaces- Properly prepare the Unit One exterior painted steel surfaces by handtooling, hot high pressure washing, an abrasive blasting as necessary and refinish i o full coats of Sherwin Williams, Devoe, or Induron highperformance coatings as described above - $ 94,000 Project Notes: 1. Project schedule: Year 2019 as weather and schedule permits. Customers are scheduled in the order that signed contracts are received. Owner required to provide a water supply. 2. Owner to reinstall any and all stickers necessary after project completion unless otherwise specified. 3. Quote does not include any lead abatement, lead disposal, full containment, steel repair, or welding. 4. This quote includes all items necessary to safely complete coatings as described: materials, labor, harnesses, equipment, workers compensation insurance, and general liability insurance. 5. R&H trains to work safely. R&H's third party safety contractor is Veriforce. As of 2018 we have an EMR rating of 0.91. The R&HPainting Employee Safety Program is available via email. 6. This proposal includes a standard one year warranty [see below]. 7. This proposal must be signed and dated by both parties prior to starting work. ACCEPTANCE The undersigned hereby accepts R&H's proposal and authorizes R&H to furnish all materials and labor required to complete the work set forth in the proposal, and therefore agrees to the following payment terms: Our invoices are NET 30 DAYS, no retainage. A 1.5% per month finance charge will be assessed to all accounts over 30 days past due. Per MN statutes, we are required to notify you that any person or company supplying labor or materials for this improvement to your property may file a lien against your property if that person or company is not paid for the contributions. MN statute 514.011. Respectfully, Date BY, Title-- 3 1 P a g e R&H Painting, LLC. By Title Customer: Sign c& return one copy, retain one copy for your files. IIIIII INDIISTRIAL PROTECTIVE COATINGS 320.286.2471 15725 us Hwy 12 sw Cokato, MN 55321 Awm—Aantill wati gM.N cat . ...... Standard One Year Warranty & Notarization For One year after installation, R&H warrants only to the original Owner that materials have been applied or installed as required by this contract. R&H will repair defective work of which R&H is notified in writing within a period of One year after application, provided the work has not been damaged by Owner or used for a purpose for which it was not intended. R&H is not responsible for conditions beyond its control including but not limited to hydrostatic pressure, vapor, moisture, frost, ice, groundwater, water and/or moisture pressure or emissions, capillary action, soil or slab stability, substrate cracking, the absence or presence or condition of vapor or moisture barriers and/or weather barriers, fork truck or other traffic damage, or use for which the work is not intended. Coatings are not considered a failure if concrete or old existing coatings are attached to the delaminated materials; this is a substrate failure. R&H specifically disclaims any and all other warranties, including implied warranties or warranties of merchantability or fitness for a particular purpose, and owner agrees that its sole remedy for defective work or any damage resulting from such defect, whether or not caused by the negligence of R&H, shall be repaired by R&H upon the notice provided herein. Owner further agrees that in no event shall R&H be liable for consequential damages of any nature, including without limitation, damages for loss of use or lost revenues, loss of reputation, costs of financing, lost business, business interruption, damage to the structure, damage to or loss of contents, ground or groundwater contamination, damage resulting from spillage or leakage, or damage resulting from pollution or release of hazardous materials. The foregoing warranty is the only warranty made by R&H and is expressly made in lieu of any and all other warranties guarantees or representations, whether expressed or implied. This warranty runs between R&H and the owner only: it is not assignable or transferable to a successor, assign or another owner, and any such assignment is void and unenforceable. PROJECT COMPLETION DATE: R&H OFFICER DATE & SIGN: This instrument was acknowledged before me on as (type of authority) of (Signature of notarial officer) (date) by (company name). (names) of person(s) (Seal if any) My commission expires: R&H has serviced the commercial & industrial coatings market since 1974. Questions can be directed to our office @ 320.286.2471, or sales @ 320.237.1292 and sales @ RandHpaintingMN.com. Websites: . ndHpaintin ,MN&, au evoke m tumt� Smm�,olm Shy;.. nWi!wfia �:.�. m indu on.corr� .. t S Utilities Si ., We appreciate the opportunity, Thank you! Kind Regards, Gregory B. Raisanen Industrial Sales Painting, LLC. — Est. 1974 320.237.1292 Cell 320.286.2471 Office 320.286.2795 Fax gregrand➢i g ail...coirn. 4j"you want it rijht.., Customer: Sign & return one copy, retain one copy for your files. 4 1 P a g e HUTCHINSON UTILITIES COMMISSION��` Board Action Form 41ri ars mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Requisition 7920 for Unit 1 Generator Breaker and Hutchinson Substation Breakers Presenter: Dave Agenda Item Type: Time Requested (Minutes); New Business Attachments; Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: Unit 1 Generator Breaker failed on Wednesday April 17th. In the process of locating a replacement we were able to find Utility Transformer Brokers (UTB), a company that has three breakers that were purchased new in 2017 and unused. UTB opted to go to a different type of breaker and have these to sell. They were purchased new in 2017 for $47,000.00 each and are selling them today for $37,000.00 each. We are looking to buy one for the Generator breaker replacement and since they have two others available we feel this is a good opportunity to replace two existing oil filled breakers at our Hutchinson Substation. These are the last two oil breakers left in place at our Hutchinson Substation and are currently 40 plus years old. BOARD ACTION REQUESTED: Approve Requisition 7920 for three 69KV Breakers FiscalImpact: 116,500.00 Included in current budget;' Budget Change: PROJECT SECTION:' Total Project Cost: Remaining Cost; HUTCHINSON UTILITIES ra,�itiak° tt ni'i ni'it II Ewa s�io ni Note PURCHASE REQUISITION HUTCHINSON UTILITIES COMMISSION 225 MICHIGAN ST SE HUTCHINSON, MN 55350 Phone:320-587-4746 Fax:320-587-4721 UTILITY TRANSFORMER BROKERS PO BOX 724 SALEM, UT 84653 Description: 69 KV Breakers Date Requisition No. 04/17/2019 007920 Required by: Requested by: dhunstad Item No. part No. Description Qty Unit Due Date Unit Price Ext. Amount 69 KV BREAKER 1200 AMP GENERATOR 1 - DESCRIPTION: . 72.5KV NOMINAL VOLTAGE . 40KA MAXIMUM SYMMETRICAL INTERRUPTING CAPABILITY O AT SPECIFIED 20KA SHORT CIRCUIT REQUIREMENT, EACH PHASE IS CAPABLE OF 55 OPERATIONS! . 3000A MAXIMUM CONTINUOUS CURRENT (LIMITED TO 1200A DUE TO BCT) . CAPABLE OF -40°C OPERATION WITHOUT TANK HEATERS .73 INCH CREEP PORCELAIN BUSHINGS RATED 350KV BIL @ 3300 FEET ASL . 3-CYCLE, 60HZ, SPRING -SPRING OPERATED . GANG OPERATION, FRAME MOUNTED OUTDOOR CIRCUIT BREAKER . BUSHING CURRENT TRANSFORMERS (TOTAL 12 BCT'S): 1 BUSHINGS 1-3-5: (6) 600:5 1.00 EA $37,000.000 $37,000.00 MR C400 RELAY ACCURACY, RF 2.0 BUSHINGS 2-4-6: (6) 600:5 MR C400 RELAY ACCURACY, RF 2.0 CONTROL AND OPERATOR POWER REQUIREMENTS: CONTROL SUPPLY VOLTAGE: 125 VDC SPRING CHARGE MOTOR SUPPLY VOLTAGE: 120 VAC / 125 VDC ACCESSORY SUPPLY VOLTAGE: 120 VAC HEATER SUPPLY VOLTAGE: 240 VAC CLARIFICATIONS: Date Printed: 04/17/2019 Reauisitioned Bv: dhunstad Paae: 1/4 HUTCHINSON UTILITIES ra,�itiaa° oni'initIIIEwasrioI'll Note PURCHASE REQUISITION HUTCHINSON UTILITIES COMMISSION 225 MICHIGAN ST SE HUTCHINSON, MN 55350 Phone:320-587-4746 Fax:320-587-4721 UTILITY TRANSFORMER BROKERS PO BOX 724 SALEM, UT 84653 Description: 69 KV Breakers Date Requisition No. 04/17/2019 007920 Required by: Requested by: dhunstad Item No. part No. Description Qty Unit Due Date Unit Price Ext. Amount PROPOSED 40KA CIRCUIT BREAKER IS RATED FOR 55 OPERATIONS AT THE SPECIFIED 20KA SHORT CIRCUIT CURRENT CONDITION. Date Printed: 04/17/2019 Requisitioned By: dhunstad Page: 2/4 HUTCHINSON UTILITIES ra,�itiaa° oni'initIIIEwasrioI'll Note PURCHASE REQUISITION HUTCHINSON UTILITIES COMMISSION 225 MICHIGAN ST SE HUTCHINSON, MN 55350 Phone:320-587-4746 Fax:320-587-4721 UTILITY TRANSFORMER BROKERS PO BOX 724 SALEM, UT 84653 Description: 69 KV Breakers Date Requisition No. 04/17/2019 007920 Required by: Requested by: dhunstad Item No. part No. Description Qty Unit Due Date Unit Price Ext. Amount 69 KV BREAKER 1200 AMP FOR HUTCH SUB - DESCRIPTION: . 72.5KV NOMINAL VOLTAGE . 40KA MAXIMUM SYMMETRICAL INTERRUPTING CAPABILITY O AT SPECIFIED 20KA SHORT CIRCUIT REQUIREMENT, EACH PHASE IS CAPABLE OF 55 OPERATIONS! . 3000A MAXIMUM CONTINUOUS CURRENT (LIMITED TO 1200A DUE TO BCT) . CAPABLE OF -40°C OPERATION WITHOUT TANK HEATERS .73 INCH CREEP PORCELAIN BUSHINGS RATED 350KV BIL @ 3300 FEET ASL . 3-CYCLE, 60HZ, SPRING -SPRING OPERATED . GANG OPERATION, FRAME MOUNTED OUTDOOR CIRCUIT BREAKER . BUSHING CURRENT TRANSFORMERS (TOTAL 12 BCT'S): 2 BUSHINGS 1-3-5: (6) 600:5 2.00 EA $37,000.000 $74,000.00 MR C400 RELAY ACCURACY, RF 2.0 BUSHINGS 2-4-6: (6) 600:5 MR C400 RELAY ACCURACY, RF 2.0 CONTROL AND OPERATOR POWER REQUIREMENTS: CONTROL SUPPLY VOLTAGE: 125 VDC SPRING CHARGE MOTOR SUPPLY VOLTAGE: 120 VAC / 125 VDC ACCESSORY SUPPLY VOLTAGE: 120 VAC HEATER SUPPLY VOLTAGE: 240 VAC CLARIFICATIONS: Date Printed: 04/17/2019 Reauisitioned Bv: dhunstad Paae: 3/4 HUTCHINSON UTILITIES ra,�itiaa° oni'initIIIEwasrioI'll Note PURCHASE REQUISITION HUTCHINSON UTILITIES COMMISSION 225 MICHIGAN ST SE HUTCHINSON, MN 55350 Phone:320-587-4746 Fax:320-587-4721 UTILITY TRANSFORMER BROKERS PO BOX 724 SALEM, UT 84653 Description: 69 KV Breakers Date Requisition No. 04/17/2019 007920 Required by: Requested by: dhunstad Item No. part No. Description Qty Unit Due Date Unit Price Ext. Amount PROPOSED 40KA CIRCUIT BREAKER IS RATED FOR 55 OPERATIONS AT THE SPECIFIED 20KA SHORT CIRCUIT CURRENT CONDITION. SHIPPING - MFG. PART: 3 1.00 EA $5,500.000 $5,500.00 Total: 116,500.00 Date Printed: 04/17/2019 Requisitioned By: dhunstad Page: 4/4 PO Box 724 Salem, UT 84653 Office Phone: 855-214-0975 Fax: 855-845J497 Quote For 1 0 HUTCHIN ON UTILITIES eratu�Na 4" III'1IIIiniIIIs ;i0III Date: 4/17/19 Customer: Hutchinson Utilities Attu: Dave Hunstad Projed Name: Siemens Breakers Freight Terms: Pre -Paid FOB: Destination QTY IINNIJ'I"TIJ'II1 11311111TI04 UNIT I IEXT. IIIC°,I 3 Siemens Sulfer Hexaflouride Circuit Breaker— Type SPS2-72.5-20-2 $37,000.00 $111,000.00 1 Freight $5500 $5,500.00 PAYMENTTERMS Payment Due On Receipt & Prior To Shipment NOTES: BY ORDERING THIS MATERIAL YOU ACCEPT THE TERMS & CONDITIONS OF THIS BID. TOTAL: $116,500.00 DAYS. Terms & Conditions Pricing is good for 30 days. All equipment quoted subject to availability. UTB is not responsible for consequential, special, incidental, or indirect damages of any nature or kind, including but not limited to delays in delivery, loss of production, loss of profit, and cost of power purchases, whiter those damages are claimed in contract, negligence, strict or products liability, or otherwise. Any resulting litigation associated with theses terms & conditions shall be conducted in the State of Utah Prices are subject to change without notice. Unless otherwise specified, prices will be the prices in effect at the time of written order acknowledgement by UTB subject to adjustment for subsequent changes directed by the Customer and/or mutually agreed upon escalation formula. All orders are non cancellable, non returnable unless an agreement is worked out by the Customer and UTB. Conditions of any returns will be specified by UTB. Buyer may delay or reschedule shipment without penalty if the delay is within 30 days of the original scheduled delivery date. Delays beyond 30 days may require invoicing, payment and storage charges. Seller will make a good faith effort to complete delivery of the products and services on the scheduled date, but seller assumes no responsibility or liability for inability to deliver for reasons beyond the control of the Seller, unless otherwise agreed in writing. The seller is not liable for any incidental, consequential or liquidated damages arising from delays or failure to give notice of delay. Pricing is good for items specifically listed in the above/attached bills of material only. Discrepancies between the drawings/specifications provided by the customer, and this bill of material, are the responsibility of the customer. This sale is expressly conditioned upon Customer's acceptance of the terms and conditions stated above. If not previously given, Customer's payment or acceptance of Product, whichever occurs first, is conclusive to this acceptance. UTB makes no warranty, express or implied, whether of merchantability, suitability, or fitness for a particular purpose, application or otherwise. HUTCHINSON UTILITIES COMMISSION��` Board Action Form 41ri ars mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Dissolve Distributed Generation Policies 0 Presenter: Jeremy/Dave Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments; Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: The State of Minnesota currently has interconnection process standards in effect to address the interconnection of distributed energy resources (DER) to the distribution grid. Minnesota Statute §216B.1611, cooperatives and municipals shall adopt an interconnection process that addresses the same issues as the interconnection process approved by the Minnesota Public Utilities Commission. MMUA put together a Resolution, Policy, and Rules for all Minnesota Municipals to adopt that will replace our existing policies and create a more uniform process for DER. Therefore, we would like to dissolve our current Distributed Generation Policies. Attached: Distributed Generation (40KW or Less) Net Energy Billing Distributed Generation (Over 40KW) Policy BOARD ACTION REQUESTED: Dissolve Existing Distributed Generation Policies Fiscal Impact: none Included in current budget;Budget Change: PROJECT SECTION:' Total Project Cost: Remaining Cost; Hutchinson Utilities Commission Distributed Generation (40 kW or Less) — Net Energy Billing Amended February 27, 2019 1. Effective In All territories served by Hutchinson Utilities Commission (HUC). 2. Availability Available to single-phase and three-phase customers where a part or all of the electrical requirements of the customer are supplied by the customer's generating facilities, where such facilities have a total generating capability of 40 kW or less, where such facilities are connected in parallel with HUC and where such facilities are approved by HUC. The budget payment plan shall not be available to customers with parallel generation. 3. Rate The customer shall be billed monthly on a net energy basis and shall pay the fixed charge and energy charge as specified in HUC's rate schedule under which the customer is served. If, in any month, the Customer's bill has a credit balance of $100 or less, the amount shall be credited to subsequent bills until a debit balance is reestablished. If the credit balance is more than $100, the utility shall reimburse the customer by check upon request. Monthly credits shall be computed by taking the net excess kilowatt-hours produced times the average annual wholesale cost of power from the previous year. 4. Metering and Services Facilities HUC shall utilize an electric meter capable of measuring electric energy in both the forward and reverse direction. 5. Contract Required A contract (Contract for Parallel Generation Facilities (40 KW or Less)) is required between HUC and the customer -owned generation facility. The contract shall specify safety, system protection, and power quality requirements that generators 1 Hutchinson Utilities Commission Distributed Generation (40 kW or Less) — Net Energy Billing must comply with. Contracts with customer -owned generation facilities selling energy under the standard (non -negotiated) rate have no specific term or length. 6. Customer Obligation a. Metering Facilities The customer shall furnish, install and wire the necessary service entrance equipment, meter sockets, meter enclosure cabinets, or meter connection cabinets that may be required by HUC to properly meter usage and sales to HUC b. Interconnection Costs The owner of the generating facility shall be required to pay all interconnection costs, incurred by HUC. The owner shall pay said costs prior to the final service connection to the Utility's electrical system C. Insurance Hold Harmless and Government Approval The customer shall keep in force a policy of liability insurance, of at least $300,000.00, against personal or property damage to the utility's system, equipment and personnel arising from the installation, interconnection, and operation of the customer's generating facility. The customer shall provide proof of insurance to HUC on an annual basis with said policy specifically naming HUC as an insured. The customer shall indemnify and hold HUC harmless from all claims of damage whatsoever. The customer is responsible for obtaining all governmental permits and approvals. d. Interconnection and Operational (Safety and Power Quality) Requirements Electric Service to a customer -owned electric generation installation may be disconnected for failure to comply with the following requirements. 1) Interconnection of a generating facility with the HUC system shall not be permitted until application has been made to and approval received from HUC. The Utility may withhold approval only for good reason such as failure to comply with applicable HUC or governmental rules or laws. HUC shall require a contract specifying 2 Hutchinson Utilities Commission Distributed Generation (40 kW or Less) — Net Energy Billing reasonable technical connection and operating aspects for the parallel generating facility. 2) HUC may require that for each generating facility there is provided, between the generator/s and the utility system, a lockable load -break disconnect switch. For installations interconnected at greater than 600 volts, a fused cutout switch may be substituted, where practicable. The switches shall be accessible to HUC for the purpose of isolating the parallel generating facility from the HUC system when necessary. 3) HUC shall require a separate distribution transformer, where necessary, for a customer having a generating facility for reasons of public and employee safety or where the potential exists for the generating facility causing problems with the service of other customers. 4) HUC shall require that each generating facility have a system for automatically isolating the generator from HUC's system upon loss of the HUC supply, unless HUC desires that the local generation be continued to supply isolated load. 5) HUC shall require that the customer discontinue parallel generation operations when it so requests and HUC may isolate the generating installation from its system at times. During such times, HUC shall not be liable for revenue lost by the customer. Parallel generation may be disconnected: a) When considered necessary to facilitate maintenance or repair of HUC's facilities. b) When considered necessary during system emergencies. c) When considered necessary during such times as the generating facility is operating in a hazardous manner, or is operating such that it adversely affects service to other customers or to nearby communication systems or circuits. 6) The owner of the generating facility shall be required to make the equipment available and permit entry upon the property by electric and communication utility personnel at reasonable times for the purpose of testing isolation and protective equipment, evaluating the quality of power delivered to HUC's system and testing to determine 3 Hutchinson Utilities Commission Distributed Generation (40 kW or Less) — Net Energy Billing whether the local generating facility is the source of any electric service or communication systems problems. 7) The power output of the generating facility shall be maintained such that the frequency and voltage are compatible with normal HUC service and do not cause that HUC service to fall outside the prescribed limits of Commission rules and other standard limitations. 8) The generating facility shall be operated so that variations from acceptable voltage levels and other service impairing disturbances do not result in adverse effects on the service or equipment of other customers, and in a manner that does not produce undesirable levels of harmonics in the HUC power supply. The customer agrees to disconnect the generating facility from HUC's distribution system or reimburse HUC for the cost of necessary system modifications if operation of the generating facility causes radio, television, internet, or electrical service interference to other customers, or interference with the operation of HUC's electrical system. 9) The owner of the generating facility shall be responsible for providing protection for the owner's equipment and for adhering to all applicable national, state and local codes. 10) Customer agrees to locate the generating facility so as to not interfere with HUC's distribution system. Customer agrees that the installation shall be in compliance with all applicable electric codes and the generating facility shall be operated only after the installation has been inspected and approved by appropriate authorities. Customer agrees to obtain all required permits, abide by all building and zoning requirements and applicable inspections. 11) The customer agrees to reimburse HUC for any addition, modification, or replacement of distribution components made necessary by the customer's installation. 12) Customer agrees to effectively install grounding and provide surge arrestor protection to prevent lightning damage to HUC's distribution system. 12 Hutchinson Utilities Commission Distributed Generation (40 M or Less) — Net Energy Billing 7. Utility Obligation a. Metering Facilities HUC shall own and install an appropriate meter in order to record all flows of energy necessary to bill in accordance with the charges and credits of the rate schedule. b. Notice to Communication Firms HUC shall notify telephone utility and cable television firms in the area when it knows that a customer -owned generating facility is to be interconnected with its system. This notification shall be as early as practicable to permit coordinated analysis and testing in advance of interconnection. 8. Right to Appeal The owner of the generating facility interconnected, or proposed to be interconnected, with HUC's system may appeal to the Commission should any requirement of HUC's service rules or the required contract be considered to be excessive or unreasonable. Such appeal shall be reviewed and the customer notified of the Commission's determination. 5 Contract for Distributed Generation Facilities (40 kW or Less) This contract is entered into by Hutchinson Utilities Commission (hereafter called "Utility") and (hereafter called "Customer"). RECITALS Per MN Statute 216B.1611, the Utility shall request the following information for interconnection of distributed renewable generation. 1) The name plate capacity of the facility (kW) 2) The pre -incentive installed cost of the generating facility 3) The energy source of the facility (Solar, Wind, etc.) 4) Location of the facility The Customer is prepared to generate electricity in parallel with the Utility. The Customer meets the requirements of the Utility's rules on parallel generation and any technical standards for interconnection the Utility has established that are authorized by those rules. The Utility is obligated under Federal and Minnesota law to interconnect with the Customer and to purchase electricity offered for sale by the Customer. AGREEMENTS The Customer and the Utility agree: 1. The Utility shall sell electricity to the Customer under the rate schedule in force for the class of customer to which the Customer belongs. 2. Payment per KWH for energy delivered to the Utility, in excess of energy used by the Customer. $ see #3, Rate, Hutchinson Utilities Commission Parallel Generation (40 kW or Less) — Net Energy Billing policy. 3. The rates for sale and purchase of electricity may change over the time this contract is in force, due to actions of the Utility. The Customer and the Utility agree that sales and purchases shall be made under the rates in effect each month during the time this contract is in force. 4. The Customer must operate its electric generating facilities within any rules, regulations, and policies adopted by the Utility, which provide reasonable technical 1 connection and operating specifications for the customer (Hutchinson Utility Commission's rules and regulations applicable to parallel generation are attached). 5. The Customer will operate its electric generating facilities so that they conform to the national, state, and local electric and safety codes, and will be responsible for the costs of conformance. 6. The Customer is responsible for the actual, reasonable costs of interconnection which are estimated to be $ The customer shall pay the Utility in this manner: 7. The Customer shall provide the Utility reasonable access to its property and electric generating facilities in the event the configurations of those facilities do not permit disconnection or testing from the Utility's side of the interconnection. If the Utility enters the Customer's property, the Utility shall remain responsible for its personnel. 8. The Utility may discontinue providing electricity to the Customer during a system emergency. The Utility shall not discriminate against the Customer when it discontinues providing electricity or when it resumes providing electricity. 9. The Utility may discontinue purchasing electricity from the Customer when necessary for the Utility to construct, install, maintain, replace, remove, investigate, or inspect equipment or facilities within its electrical system. The Utility shall notify the Customer prior to discontinuing the purchase of electricity in this manner: 10. The customer shall keep in force a policy of liability insurance, of at least $300,000.00, against personal or property damage to the Utility's system, equipment and personnel arising from the installation, interconnection, and operation of customer's generating facility and shall provide annual proof of the insurance to the Utility with said policy specifically naming the Utility as an insured. The customer agrees to indemnify and hold harmless the Utility from all claims whatsoever arising from customer's generating system. 11. This contract becomes effective when signed by the Customer and the Utility. This contract will remain in force until either the Customer or the Utility provides written notice to the other that the contract is canceled. This contract shall be canceled 30 days after notice is given. 12. This contract does not serve as an approval of the Customer's generating system for planning, zoning or permit purposes. The Customer shall have the responsibility to obtain proper approval and permits from the City of Hutchinson or other governmental entities pertaining to the construction and operation of the Customer's generating system. 2 13. This contract contains all the agreements made between the Customer and the Utility. The Customer and the Utility are not responsible for any agreements other than those stated in this contract. THE CUSTOMER AND THE UTILITY HAVE READ THIS CONTRACT AND AGREE TO BE BOUND BY ITS TERMS. AS EVIDENCE OF THEIR AGREEMENT, THEY HAVE EACH SIGNED THIS CONTRACT BELOW ON THE DATE WRITTEN AT THE BEGINNING OF THIS CONTRACT. Customer In Date: 3 HUTCHINSON UTILITIES COMMISSION go Hutchinson Utilities Commission Distributed Generation (Over 40 M Policy Amended: July 29, 2015 1. Effective In All territories served by Hutchinson Utilities Commission (HUC or Utility). 2. Availability Available to single-phase and three-phase customers when- (1) a part or all of the electrical requirements of the customer are supplied by the customer's generating facility that satisfies the requirements of qualifying facilities under the federal Public Utility Regulatory Policies Act (Customer QF); (2) the Customer QF has a total generating capability of greater than 40 kW; and (3) the Customer QF is connected in parallel with HUC. 3. Approval Process The customer shall provide information to HUC, as early as practicable, concerning the proposed Customer QF, including, but not limited to- 1 ) The name plate capacity of the QF (kW) 2) The pre -incentive installed cost of the QF 3) The energy source of the QF (Solar, Wind, etc.) 4) Location of the QF (the "Location") 5) Sufficient technical information to evaluate the proposed interconnection of the QF and how the QF will satisfy the HUC interconnection criteria; 6) Any additional information to evaluate the design, safety, financial factors, and supporting detail for the proposed QF; 7) Other information reasonably requested by HUC. HUC shall consider the customer's application. HUC shall require a contract specifying reasonable technical connection and operating aspects for the Customer QF. The Customer QF shall not interconnect with HUC unless and until HUC has issued its approval, and the Customer QF has obtained all applicable governmental approvals. Hutchinson Utilities Commission Distributed Generation (Over 40 M Policy 4. Separate Contract Required A separate contract is required between HUC and the customer concerning the Customer QF. The contract shall specify safety, system protection, and power quality rules that generators must comply with, as well as rate and financial provisions. The contract shall otherwise comply with the requirements of this Policy. 5. Financial Provisions The separate contract shall address the appropriate payment terms for the purchase of any electrical output supplied by the Customer QF to HUC, as well as the customer's purchase of power and energy, standby services, and other services from HUC. At a minimum, the customer rate shall encompass the HUC distribution rate components, the actual costs incurred by HUC under its wholesale supplier rate(s), and applicable transmission rate(s), all of which will be applied under the rates as they then exist, and shall be automatically updated in the event of any changes. The contract shall consider all applicable costs of HUC. The contract may include a minimum rate for delivery of power and energy to the customer. The budget payment plan will not be available to customers with distributed generation. 6. Other Customer Obligations a. Metering Facilities The customer shall furnish, install, and wire, at customer's sole expense, the necessary service entrance equipment, meter sockets, meter enclosure cabinets, or meter connection cabinets that may be required by HUC to properly meter usage and sales to HUC. b. Interconnection Costs The Customer QF shall be required to pay all interconnection costs, including actual costs incurred by HUC. The Customer QF shall pay said costs prior to the final service connection to the Utility's electrical system. C. Power Factor The customer shall operate on a net power factor of not less than 94 percent. A power factor penalty will apply if the power factor drops below 94 percent. Hutchinson Utilities Commission Distributed Generation (Over 40 M Policy d. Insurance Hold Harmless and Government Approvals The customer shall keep in force a policy of liability insurance, of at least $2 Million per occurrence, against personal or property damage to HUC's system, equipment, and personnel arising from the installation, interconnection, and operation of the Customer QF. The customer shall provide proof of insurance to HUC on an annual basis with said policy specifically naming HUC as an additional insured. The customer shall indemnify, defend, and hold HUC harmless from all claims and loss whatsoever arising directly or indirectly from the Customer QF. The customer is responsible for obtaining and maintaining all governmental permits and approvals for the construction and operation of the QF, at customer's sole expense. e. Interconnection and Operational (Safety and Power Quality) Requirements 1) HUC may, in its discretion, disconnect electric service to a Customer QF, for reasons of safety, system emergency, prudent utility practices, or failure to comply with HUC policies, regulations, and service rules. 2) Interconnection of a Customer QF with the HUC system shall not be permitted until application has been made to and approval received from HUC. HUC may withhold approval for good cause, including, but not limited to failure to comply with applicable HUC or governmental rules or laws, or failure to enter a separate agreement concerning the Customer QF. HUC shall require a contract specifying reasonable technical connection and operating aspects for the Customer QF. 3) HUC may require that for each Customer QF there is provided, between the generator/s and the Utility system, a lockable load - break disconnect switch. For installations interconnected at greater than 600 volts, a fused cutout switch may be substituted, where practicable. The switches shall be accessible to HUC for the purpose of isolating the parallel generating facility from the HUC system when necessary. 4) HUC shall require a separate distribution transformer, where necessary, for reasons of public and employee safety or where the potential exists for the Customer QF causing problems with the service of other customers. Hutchinson Utilities Commission Distributed Generation (Over 40 M Policy 5) HUC shall require that each Customer QF have a system for automatically isolating the generator from HUC's system upon loss of the HUC supply, unless HUC desires that the local generation be continued to supply isolated load. 6) HUC shall require that the customer discontinue QF operations when HUC so requests and HUC may isolate the generating installation from its system at times. During such times, HUC shall not be liable for any revenue lost by the customer. The Customer QF may be disconnected: a) When considered necessary to facilitate maintenance or repair of HUC's facilities. b) When considered necessary during system emergencies. c) When considered necessary during such times as the QF is operating in a hazardous manner, or is operating such that it adversely affects service to other customers or to nearby communication systems or circuits. 6) The Customer QF shall be required to make the equipment available and permit entry upon the property by electric and communication utility personnel at reasonable times for the purpose of testing isolation and protective equipment, evaluating the quality of power delivered to HUC's system, and testing to determine whether the Customer QF is the source of any electric service or communication systems problems. 7) The power output of the Customer QF shall be maintained such that the frequency and voltage are compatible with normal HUC service and do not cause that HUC service to fall outside the prescribed limits of Commission rules and other standard limitations. 8) The Customer QF shall be operated so that variations from acceptable voltage levels and other service impairing disturbances do not result in adverse effects on the service or equipment of other customers, and in a manner that does not produce undesirable levels of harmonics in the HUC power supply. The customer agrees to disconnect the QF from HUC's distribution system or reimburse HUC for the cost of necessary system modifications if QF operation causes radio, television, internet, or electrical service interference to other customers, or interference with the operation of HUC's electrical system. Hutchinson Utilities Commission Distributed Generation (Over 40 M Policy 9) The Customer QF shall be responsible for providing protection for its equipment and for adhering to all applicable national, state, and local codes. 10) Customer agrees to locate the QF so as to not interfere with HUC's distribution system. Customer agrees that the installation shall be in compliance with all applicable electric codes and the QF shall be operated only after the installation has been inspected and approved by appropriate authorities. Customer agrees to obtain, at customer's sole cost, all required permits, as well as abide by all building and zoning requirements, and applicable inspections. 11) The customer agrees to reimburse HUC for any addition, modification, or replacement of distribution components made necessary by the Customer's QF. 12) Customer agrees to effectively install grounding and provide surge arrestor protection to prevent lightning damage to HUC's distribution system. 13) Customer shall provide HUC reasonable access to the customer's property and the Customer QF for purposes of inspection, testing, and disconnection. 7. Utility Obligation a. Metering Facilities HUC shall own and install an appropriate meter in order to record all flows of energy necessary to bill in accordance with the separate contract. b. Notice to Communication Firms HUC shall notify telephone utility and cable television firms in the area when it knows that a Customer QF is to be interconnected with its system. This notification shall be as early as practicable to permit coordinated analysis and testing in advance of interconnection. 8. Right to Appeal The customer interconnected, or proposed to be interconnected, with HUC's system may appeal to the Commission should any requirement of HUC's service rules or the required contract be considered to be excessive or unreasonable. Such appeal shall be reviewed and the customer notified of the Commission's determination. HUTCHINSON UTILITIES COMMISSION��` Board Action Form rMturit mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Adopt Resolution, Policy, and Rules for Distributed Energy Resources Presenter: Jeremy/Dave Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments; Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: Policy regarding Distributed Energy Resources and Net Metering and Rules Governing the Interconnection of Co -generation and Small Power Production Facilities. The Policy and Rules were created by MMUA for all Municipal Utilities to have a consistent process to establish the application procedure and qualification criteria for all customers for the delivery, interconnection, metering and purchase of electricity from distributed energy resource facilities and to comply with applicable laws and rules governing distributed energy resources. The only change from our current Policies is the Rate for which we buy back excess power. We currently state it as "wholesale rate". In the new Policy it will be at "Average retail energy rate". This will not effect any of our existing contracts as we have yet to buy back energy over month billing period. We will notify our existing DER customers of the change. Attached: 1) Resolution 2) Policy Regarding Distributed Energy Resources and Net Metering 3) Rules Governing the Interconnection of Co -generation and Small Power Production Facilities. BOARD ACTION REQUESTED: Approve Resolution, Policy, and Rules for Distributed Energy Resources Fiscal Impact: None Included in current budget;Budget Change: PROJECT SECTION:' Total Project Cost: Remaining Cost; RESOLUTION 19-01 A resolution adopting Hutchinson Utilities Commission's Policy Regarding Distributed Energy Resources and Net Metering and Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities. WHEREAS, the City is served by Hutchinson Utilities Commission, which is committed to providing customers with reliable and affordable power. WHEREAS, the purpose of this Distributed Energy Resources and Net Metering Policy is to establish the qualification criteria and certain responsibilities for the delivery, interconnection, metering, and purchase of electricity from distributed generation facilities. WHEREAS, this policy, in accordance with Minnesota Statutes §216B.164, shall be implemented to give the maximum possible encouragement to cogeneration and small power production consistent with protection of the utility's ratepayers and the public. WHEREAS, the purpose of the Cogeneration and Small Power Production Rules is for Hutchinson Utilities Commission to implement certain provisions of Minnesota Statutes §216B.164, the Public Utility Regulatory Policies Act of 1978, and Federal Energy Regulatory Commission regulations related to customer -owned distributed energy resources. WHEREAS, the adoption of these rules establishes that the Hutchinson Utilities Commission is the interpreting body and arbiter of the provisions of Minnesota Statutes §216B.164for Hutchinson Utilities Commission. WHEREAS, Hutchinson Utilities Commission shall annually file a cogeneration and small power production tariff with Hutchinson Utilities Commission Board of Commissioners under these rules. WHEREAS, the cogeneration and small power production tariff shall include a calculation of average retail utility energy rates, standard contracts to be used with qualifying facilities, interconnection process and technical requirements, and Hutchinson Utilities Commission's estimated average incremental energy costs and net annual avoided capacity costs. WHERAS, all filings under these rules shall be maintained at the Hutchinson Utilities Commission offices and shall be made available for public inspection during normal business hours. THEREFORE, BE IT RESOLVED that the Hutchinson Utilities Commission adopts the following Policy Regarding Distributed Energy Resources and Net Metering and Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities. Adopted by the Hutchinson Utilities Commission on April 24, 2019. President Date Secretary Date Hutchinson Utilities Commission Policy Regarding Distributed Energy Resources and Net Metering To establish the application procedure and qualification criteria for all customers for the delivery, interconnection, metering and purchase of electricity from distributed energy resource facilities and to comply with applicable laws and rules governing distributed energy resources. The utility recognizes its obligation to provide interconnection to eligible qualifying facilities and will comply with all applicable laws and rules governing distributed energy resources. For purposes of this policy, the following terms have the meanings given them: A. Average retail energy rate - the average of the retail energy rates, exclusive of special rates based on income, age, or energy conservation, according to the applicable rate schedule of the utility for sales to the class of customer of which the customer/qualifying facility belongs. B. Avoided costs - the incremental costs to the utility of electric energy or capacity or both which, but for the purchase from the qualifying facility, the utility would generate itself or purchase from another source. C. Contract -the written agreement between the customer/qualifying facility and the utility, as established in the utility's Rules Governing Interconnection of Cogeneration and Small Power Production. D. Distributed energy resource (DER) - a distributed generation system incorporated with or without an electric storage system. E. Interconnection application - the form to be used by the customer to submit its formal request for interconnection to the utility and which shall be substantially similar in form to that contained in the Distributed Energy Resources Interconnection Process adopted by the utility. F. Interconnection rules - any applicable rules developed in accordance with Minnesota Statutes §§216B.164 and 21613.1611. This includes the utility's Rules Governing Interconnection of Cogeneration and Small Power Production. It also includes the utility's Distributed Energy Resources Interconnection Process which includes its Simplified Process, Fast Track Process, and Study Process as well as the technical requirements incorporated therein or any future technical requirements adopted by the utility. G. Measured capacity - for purposes of determining capacity, it shall be measured based on the highest fifteen (15) minute average demand of the unit in any one billing period. H. Net metering/net billing -the process whereby the customer and the utility compensate each other based on the difference in the amount of energy each sells to the other at the net metered facility. I. Net metered facility - an electric generation facility constructed for the purpose of offsetting energy use through the use of renewable energy or high efficiency generation sources with a capacity of less than 40 kilowatts that has elected in writing to be compensated for excess generation through net metering/net billing. J. Total generator nameplate capacity - the nominal voltage (V), current (A), maximum active power (kWac), apparent power (WA), and reactive power (kvar) at which a distributed energy resource (DER), is capable of sustained operation. For a qualifying facility with multiple units, the total generator capacity is equal to the sum of all individual DER units' nameplate rating in the qualifying facility. The DER system's total generation capacity may, with the utility's agreement, be limited thought use of control systems, power relays or similar device settings or adjustments as identified in IEEE 1547. The customer must fully, accurately and completely disclose in its interconnection application to the utility, the technical specifications for any capacity limiting device contemplated and the customer shall furnish the utility with any factory manuals or other similar documents requested from the utility regarding such limiting or other control devices which factor into the calculation of total generator capacity. K. Qualifying facility - a cogeneration or small power production facility which satisfies the conditions established in Code of Federal Regulations, title 18, part 292. The qualifying facility must be owned by a customer of the utility and located in the utility service area. L. Utility— Hutchinson Utilities Commission. In the event an inconsistency exists between terms in this policy and those established by applicable statute, rule or court order, then the definition so established shall supersede the definition used in this policy and shall govern. All customers are eligible for distributed generation, interconnection with the utility's distribution system and application of net metering upon the following terms and conditions. 1. The customer must meet the eligibility requirements set forth in the federal Public Utility Regulatory Policies Act of 1978 (PURPA) *18 C.F.R. 292.303, 292.304 and Minnesota's distributed generation laws. Minn. Stat. §216B.164. 2. The customer shall complete, sign and return to utility either the Interconnection Application or the Simplified Process Application in the form prescribed in the utility's Distributed Energy Resources Interconnection Process. The application shall be approved by the utility prior to the customer beginning the project. The customer signature on the application indicates the customer shall follow the steps outlined in the utility's interconnection rules. 3. The customer shall enter into a written contract with the utility using the uniform contract contained in the utility's Rules Governing Interconnection of Cogeneration and Small Power Production. 4. The qualifying facility shall pay the utility for all reasonable costs of interconnection including those costs outlined in Minnesota Statute 21613.164, the utility's DER Interconnection Process, and the State of Minnesota Interconnection Technical Requirements. 5. The qualifying facility's total generator nameplate capacity shall be less than 40 kW and the facility shall operate at a measured capacity of less than 40 kW at all times to qualify for net metering/net billing or roll over credit compensation. 6. The utility may limit the capacity and operating characteristics of qualifying facility single phase generators in a manner consistent with the utility limitations for single phase motors, when necessary to avoid a qualifying facility from causing problems with the service of other customers. 7. The utility may require the qualifying facility to discontinue parallel generation operations when necessary for system safety. 2 8. The power output from the qualifying facility must be maintained so that frequency and voltage are compatible with normal utility service and do not cause that service to fall outside the prescribed limits of interconnection rules and other standard limitations. 9. The qualifying facility shall keep in force liability insurance against personal or property damage due to the installation, interconnection, and operation of its electric generating facilities. The amount of insurance coverage shall be the maximum amount of said insurance for a qualifying facility or net metered facility as outlined in the utility's DER Interconnection Process. 10. Failure of the qualifying facility to operate its distributed energy resource at a measured capacity below the 40 kW AC capacity limit established by Minn. Stat. §216B.164, Sub. 3 and as contemplated by this policy, shall result in the following. The utility will notify the customer/qualifying facility of the fact that its generating equipment has failed to operate below the 40 kW AC maximum capacity and will provide the customer/qualifying facility with the date, time and kW reading that substantiate this finding. 11. The utility shall compensate the customer/qualifying facility for all metered electricity produced by said qualifying facility during the thirty (30) day period during which the failure occurred, at the utility's wholesale power supplier's avoided cost rate. 12. The utility shall continue to pay the customer/qualifying facility for subsequent electricity produced and delivered pursuant to the contract, at the utility's wholesale power supplier's avoided cost rate until: 1. The problem with the generator that caused it to operate at or above the statutory maximum capacity has been remedied; and 2. The utility has been provided documentation adopted by a Minnesota Professional Engineer that confirms the problem with the generator has been remedied. 13. Any customer account eligible for net metering/net billing is not eligible for any other load management discounts unless agreed to by the utility. 14. Payment for the purchase of the qualifying facility's electricity herein shall be in the form of a credit on the customer's monthly billing invoice or paid by check or electronic payment to the customer within fifteen (15) days of the billing date, whichever is selected and indicated in the contract. 15. The customer must be, and continue to be, current with payment on its electric account with utility. 16. The customer must not enter into any arrangement that violates the utility's exclusive right to provide electric service in its service area under Minnesota Statutes §§216B.37-44. 17. In the event that the distributed generator fails to meet the requirements of this policy for a total distributed generation capacity of less than 40 kW AC, and fails to satisfy the corrective requirements set forth in Section 12 above, then the utility will have the right to (1) cancel the contract with the owner of the qualifying facility, and (2) enter into a new contract with the owner of the qualifying facility that, among other changes, adjusts the qualifying facility's rated capacity and specifies avoided cost pricing for the qualifying facility's output. To the extent that the utility does not have the obligation to make purchases from qualifying facilities of 40 kW or greater due to transfer of the obligation to the utility's wholesale supplier that has been approved by the Federal Energy Regulatory Commission, the new agreement will be between the utility's wholesale supplier and the qualifying facility. In either case, the utility (and, as applicable, the utility's wholesale supplier) and the owner of the qualifying facility will cooperate in the transition from the form of contract set forth in the utility's Rules Governing Interconnection of Cogeneration and Small Power Production to a new form of contract appropriate to a qualifying facility with a capacity of 40 kW or greater. 18. Fully executed interconnection contracts for distributed energy resources may be canceled in the event the distributed energy resource fails to interconnect to the utility's distribution system within twelve (12) months of signing of the interconnection contract by the qualifying facility and the utility. M Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities with Hutchinson Utilities Commission Part A. DEFINITIONS Subpart 1. Applicability. For purposes of these rules, the following terms have the meanings given them below. Subp. 2. Average retail utility energy rate. "Average retail utility energy rate" means, for any class of utility customer, the quotient of the total annual class revenue from sales of electricity minus the annual revenue resulting from fixed charges, divided by the annual class kilowatt-hour sales. The computation shall use data from the most recent 12- month period available. Subp. 3. Backup power. "Backup power" means electric energy or capacity supplied by the utility to replace energy ordinarily generated by a qualifying facility's own generation equipment during an unscheduled outage of the facility. Subp. 4. Capacity. "Capacity" means the capability to produce, transmit, or deliver electric energy, and is measured by the number of megawatts alternating current at the point of common coupling between a qualifying facility and the utility's electric system during a 15-minute interval period. Subp. 5. Capacity costs. "Capacity costs" means the costs associated with providing the capability to deliver energy. The utility capital costs consist of the costs of facilities from the utility and the utility's wholesale provider used to generate, transmit, and distribute electricity and the fixed operating and maintenance costs of these facilities. Subp. 6. Customer. "Customer" means the person named on the utility electric bill for the premises. Subp. 7. Energy. "Energy" means electric energy, measured in kilowatt-hours. Subp. 8. Energy costs. "Energy costs" means the variable costs associated with the production of electric energy. They consist of fuel costs and variable operating and maintenance expenses. Subp. 9. Firm power. "Firm power" means energy delivered by the qualifying facility to the utility with at least a 65 percent on -peak capacity factor in the month. The capacity factor is based upon the qualifying facility's maximum metered capacity delivered to the utility during the on -peak hours for the month. Subp. 10. Governing body. "Governing body" means Hutchinson Utilities Commission. Subp. 11. Interconnection costs. "Interconnection costs" means the reasonable costs of connection, switching, metering, transmission, distribution, safety provisions, and administrative costs incurred by the utility that are directly related to installing and maintaining the physical facilities necessary to permit interconnected operations with a qualifying facility. Costs are considered interconnection costs only to the extent that they exceed the costs the utility would incur in selling electricity to the qualifying facility as a nongenerating customer. Subp. 12. Interruptible power. "Interruptible power" means electric energy or capacity supplied by the utility to a qualifying facility subject to interruption under the provisions of the utility's tariff applicable to the retail class of customers to which the qualifying facility would belong irrespective of its ability to generate electricity. Subp. 13. Maintenance power. "Maintenance power" means electric energy or capacity supplied by a utility during scheduled outages of the qualifying facility. Subp. 14.On-peak hours. "On -peak hours" means either those hours formally designated by the utility as on -peak for ratemaking purposes or those hours for which its typical loads are at least 85 percent of its average maximum monthly loads. Subp. 15. Point of distributed energy resource (DER) connection. "Point of DER connection" means the point where the qualifying facility's generation system, including the point of generator output, is connected to the customer's electric system and meets the current definition of IEEE 1547. Subp. 16. Purchase. "Purchase" means the purchase of electric energy or capacity or both from a qualifying facility by the utility. Subp. 17. Qualifying facility. "Qualifying facility" means a cogeneration or small power production facility which satisfies the conditions established in Code of Federal Regulations, title 18, part 292. The initial operation date or initial installation date of a cogeneration or small power production facility must not prevent the facility from being considered a qualifying facility for the purposes of this chapter if it otherwise satisfies all stated conditions. The qualifying facility must be owned by a Customer and located in the utility service area. Subp. 18. Sale. "Sale" means the sale of electric energy or capacity or both by the utility to a qualifying facility. Subp. 19a. Standby charge. "Standby charge" means the charge imposed by the utility upon a qualifying facility for the recovery of costs for the provision of standby services necessary to make electricity service available to the qualifying facility. Subp. 19b. Standby service. "Standby service" means the service to potentially provide electric energy or capacity supplied by the utility to a qualifying facility greater than 40 kW. Subp. 20. Supplementary power. "Supplementary power" means electric energy or capacity supplied by the utility which is regularly used by a qualifying facility in addition to that which the facility generates itself. Subp. 21. System emergency. "System emergency" means a condition on the utility's system which is imminently likely to result in significant disruption of service to customers or to endanger life or property. Subp. 22. Utility. "Utility" means Hutchinson Utilities Commission. Part B. SCOPE AND PURPOSE The purpose of these rules is to implement certain provisions of Minnesota Statutes, §216B.164; the Public Utility Regulatory Policies Act of 1978, United States Code, title 16, §824a-3; and the Federal Energy Regulatory Commission regulations, Code of Federal Regulations, title 18, part 292. These rules shall be applied in accordance with their intent to give the maximum possible encouragement to cogeneration and small power production consistent with protection of the ratepayers and the public. Part C. FILING REQUIREMENTS 2 Annually the utility shall file for review and approval, a cogeneration and small power production tariff with the governing body. The tariff must contain schedules 1— 4. SCHEDULE 1. Schedule 1 shall contain the calculation of the average retail utility energy rates to be updated annually. SCHEDULE 2. Schedule 2 shall contain all standard contracts to be used with qualifying facilities, containing applicable terms and conditions. SCHEDULE 3. Schedule 3 shall contain the utility's adopted interconnection process, safety standards, technical requirements for distributed energy resource systems, required operating procedures for interconnected operations, and the functions to be performed by any control and protective apparatus. SCHEDULE 4. Schedule 5 shall contain the estimated average incremental energy costs by seasonal, peak and off-peak periods for the utility's power supplier from which energy purchases are first avoided. Schedule 4 shall also contain the net annual avoided capacity costs, if any, stated per kilowatt-hour and averaged over the on -peak hours and over all hours for the utility's power supplier from which capacity purchases are first avoided. Both the average incremental energy costs and net annual avoided capacity costs shall be increased by a factor equal to 50 percent of the utility and the utility's power supplier's overall line losses due to distribution, transmission and transformation of electric energy. Part D. AVAILABILITY OF FILINGS All filings shall be maintained at the utility's general office and any other offices of the utility where rate tariffs are kept. The filings shall be made available for public inspection during normal business hours. The utility shall supply the current year's distributed generation rates, interconnection procedures and application form on the utility website, if practicable, or at the utility office. Part E. REPORTING REQUIREMENTS Annually the utility shall report to the governing body for its review and approval an annual report including information in subparts 1-3. The utility shall still comply with other federal and state reporting of distributed generation to federal and state agencies expressly required by statute. Subpart 1. Summary of average retail utility energy rate. A summary of the qualifying facilities that are currently served under average retail utility energy rate. Subp. 2. Other qualifying facilities. A summary of the qualifying facilities that are not currently served under average retail utility energy rate. Subp. 3. Wheeling. A summary of the wheeling undertaken with respect to qualifying facilities. Part F. CONDITIONS OF SERVICE Subpart 1. Requirement to purchase. The utility shall purchase energy and capacity from any qualifying facility which offers to sell energy and capacity to the utility and agrees to the conditions in these rules. Subp. 2. Written contract. A written contract shall be executed between the qualifying facility and the utility. Part G. ELECTRICAL CODE COMPLIANCE Subpart 1. Compliance; standards. The interconnection between the qualifying facility and the utility must comply with the requirements in the most recently published edition of the National Electrical Safety Code issued by the Institute of Electrical and Electronics Engineers. The interconnection is subject to subparts 2 and 3. Subp. 2. Interconnection. The qualifying facility is responsible for complying with all applicable local, state, and federal codes, including building codes, the National Electrical Code (NEC), the National Electrical Safety Code (NESC), and noise and emissions standards. The utility shall require proof that the qualifying facility is in compliance with the NEC before the interconnection is made. The qualifying facility must obtain installation approval from an electrical inspector recognized by the Minnesota State Board of Electricity. Subp. 3. Generation system. The qualifying facility's generation system and installation must comply with the American National Standards Institute/Institute of Electrical and Electronics Engineers (ANSI/IEEE) standards applicable to the installation. Part H. RESPONSIBILITY FOR APPARATUS The qualifying facility, without cost to the utility, must furnish, install, operate, and maintain in good order and repair any apparatus the qualifying facility needs in order to operate in accordance with schedule 3. Part I. TYPES OF POWER TO BE OFFERED; STANDBY SERVICE Subpart 1. Service to be offered. The utility shall offer maintenance, interruptible, supplementary, and backup power to the qualifying facility upon request. Subp. 2. Standby service. The utility shall offer a qualifying facility standby power or service at the utility's applicable standby rate schedule. Part J. DISCONTINUING SALES DURING EMERGENCY The utility may discontinue sales to the qualifying facility during a system emergency, if the discontinuance and recommencement of service is not discriminatory. Part K. RATES FOR UTILITY SALES TO A QUALIFYING FACILITY Rates for sales to a qualifying facility are governed by the applicable tariff for the class of al electric utility customers to which the qualifying facility belongs or would belong were it not a qualifying facility. Such rates are not guaranteed and may change from time to time at the discretion of the utility. Part L. STANDARD RATES FOR PURCHASES FROM QUALIFYING FACILITIES Subpart 1. Qualifying facilities with 100-kilowatt capacity or less. For qualifying facilities with capacity of 100 kilowatts or less, standard purchase rates apply. The utility shall make available four types of standard rates, described in parts M, N, O, and P. The qualifying facility with a capacity of 100 kilowatts or less must choose interconnection under one of these rates, and must specify its choice in the written contract required in part V. Any net credit to the qualifying facility must, at its option, be credited to its account with the utility or returned by check or comparable electronic payment service within 15 days of the billing date. The option chosen must be specified in the written contract required in part V. Qualifying facilities remain responsible for any monthly service charges and demand charges specified in the tariff under which they consume electricity from the utility. Subp. 2. Qualifying facilities over 100-kilowatt capacity. A qualifying facility with more than 100- kilowatt capacity has the option to negotiate a contract with the utility or, if it commits to provide firm power, be compensated under standard rates Subp. 3. Grid access charge. A qualifying facility shall be assessed a monthly grid access charge to recover the fixed costs not already paid by the customer through the customer's existing billing arrangement. The additional charge shall be reasonable and appropriate for the class of customer based on the most recent cost of service study defining the grid access charge. The cost of service study for the grid access charge shall be made available for review by the customer of the utility upon request. Part M. AVERAGE RETAIL UTILITY ENERGY RATE Subpart 1. Applicability. The average retail utility energy rate is available only to customer -owned qualifying facilities with capacity of less than 40 kilowatts which choose not to offer electric power for sale on either a time -of -day basis, a simultaneous purchase and sale basis or roll-over credit basis. Subp. 2. Method of billing. The utility shall bill the qualifying facility for the excess of energy supplied by the utility above energy supplied by the qualifying facility during each billing period according to the utility's applicable retail rate schedule. Subp. 3. Additional calculations for billing. When the energy generated by the qualifying facility exceeds that supplied by the utility to the customer at the same site during the same billing period, the utility shall compensate the qualifying facility for the excess energy at the average retail utility energy rate. Part N. SIMULTANEOUS PURCHASE AND SALE BILLING RATE Subpart 1. Applicability. The simultaneous purchase and sale rate is available only to qualifying facilities with capacity of less than 40 kilowatts which choose not to offer electric power for sale on average retail utility energy rate basis, time -of -day basis or roll- over credit basis. Subp. 2. Method of billing. The qualifying facility must be billed for all energy and capacity it consumes during a billing period according to the utility's applicable retail rate schedule. Subp. 3. Compensation to qualifying facility; energy purchase. The utility shall purchase all energy which is made available to it by the qualifying facility. At the option of the qualifying facility, its entire generation must be deemed to be made available to the utility. Compensation to the qualifying facility must be the energy rate shown on schedule 4. Subp. 4. Compensation to qualifying facility; capacity purchase. If the qualifying facility provides firm power to the utility, the capacity component must be the utility's net annual avoided capacity cost per kilowatt-hour averaged over all hours shown on schedule 4, divided by the number of hours in the billing period. If the qualifying facility does not provide firm power to the utility, no capacity component may be included in the compensation paid to the qualifying facility. Part O. TIME -OF -DAY PURCHASE RATES Subpart 1. Applicability. Time -of -day rates are required for qualifying facilities with capacity of 40 kilowatts or more and less than or equal to 100 kilowatts, and they are optional for qualifying facilities with capacity less than 40 kilowatts. Time -of -day rates are also optional for qualifying facilities with capacity greater than 100 kilowatts if these qualifying facilities provide firm power. Subp. 2. Method of billing. The qualifying facility must be billed for all energy and capacity it consumes during each billing period according to the utility's applicable retail rate schedule. Subp. 3. Compensation to qualifying facility; energy purchases. The utility shall purchase all energy which is made available to it by the qualifying facility. Compensation to the qualifying facility must be the energy rate shown on schedule 4. Subp. 4. Compensation to qualifying facility; capacity purchases. If the qualifying facility provides firm power to the utility, the capacity component must be the capacity cost per kilowatt shown on schedule 4 divided by the number of on -peak hours in the billing period. The capacity component applies only to deliveries during on -peak hours. If the qualifying facility does not provide firm power to the utility, no capacity component may be included in the compensation paid to the qualifying facility. Part P. ROLL-OVER CREDIT PURCHASE RATES Subpart 1. Applicability. The roll-over credit rate is available only to qualifying facilities with capacity of less than 40 kilowatts which choose not to offer electric power for sale on average retail utility energy rate basis, time -of -day basis or simultaneous purchase and sale basis. Subp. 2. Method of billing. The utility shall bill the qualifying facility for the excess of energy supplied by the utility above energy supplied by the qualifying facility during each billing period according to the utility's applicable retail rate schedule. 6 Subp. 3. Additional calculations for billing. When the energy generated by the qualifying facility exceeds that supplied by the utility during a billing period, the utility shall apply the excess kilowatt hours as a credit to the next billing period kilowatt hour usage. Excess kilowatt hours that are not offset in the next billing period shall continue to be rolled over to the next consecutive billing period. Any excess kilowatt hours rolled over that are remaining at the end of each calendar year shall cancel with no additional compensation. Part Q. CONTRACTS NEGOTIATED BY CUSTOMER A qualifying facility with capacity greater than 100 kilowatts must negotiate a contract with the utility setting the applicable rates for payments to the customer of avoided capacity and energy costs. Subpart 1. Amount of capacity payments. The qualifying facility which negotiates a contract under part Q must be entitled to the full avoided capacity costs of the utility. The amount of capacity payments will be determined by the utility and the utility's wholesale power provider. Subp. 2. Full avoided energy costs. The qualifying facility which negotiates a contract under part Q must be entitled to the full avoided energy costs of the utility. The costs must be adjusted as appropriate to reflect line losses Part R. WHEELING Qualifying facilities with capacity of 30 kilowatts or greater, are interconnected to the utility's distribution system and choose to sell the output of the qualifying facility to any other utility, must pay any appropriate wheeling charges to the utility. Within 15 days of receiving payment from the utility ultimately receiving the qualifying facility's output, the utility shall pay the qualifying facility the payment less the charges it has incurred and its own reasonable wheeling costs. Part S. NOTIFICATION TO CUSTOMERS Subpart 1. Contents of written notice. Following each annual review and approval by the utility of the cogeneration rate tariffs the utility shall furnish in the monthly newsletter or similar mailing, written notice to each of its customers that the utility is obligated to interconnect with and purchase electricity from cogenerators and small power producers. Subp. 2. Availability of information. The utility shall make available to all interested persons upon request, the interconnection process and requirements adopted by the utility, pertinent rate schedules and sample contractual agreements. Part T. DISPUTE RESOLUTION In case of a dispute between a utility and a qualifying facility or an impasse in the negotiations between them, either party may request the governing body to determine the issue. Part U. INTERCONNECTION CONTRACTS 7 Subpart 1. Interconnection standards. The utility shall provide a customer applying for interconnection with a copy of, or electronic link to, the utility's adopted interconnection process and requirements. Subp. 2. Existing contracts. Any existing interconnection contract executed between the utility and a qualifying facility with capacity of less than 40 kilowatts remains in force until terminated by mutual agreement of the parties or as otherwise specified in the contract. The governing body has assumed all dispute responsibilities as listed in existing interconnection contracts. Disputes are resolved in accordance with Part T. Subp. 3. Renewable energy credits; ownership. Generators own all renewable energy credits unless other ownership is expressly provided for by a contract between a generator and the utility. Part V. UNIFORM CONTRACT The form for uniform contract that shall be used between the utility and a qualifying facility having less than 40 kilowatts of capacity is as shown in subpart 1. Subpart 1. Uniform Contract for Cogeneration and Small Power Production Facilities. (See attached contract form.) UNIFORM CONTRACT FOR COGENERATION AND SMALL POWER PRODUCTION FACILITIES THIS CONTRACT is entered into 7 , by "Utility") and , a municipal utility under Minnesota law, (hereafter called RECITALS The QF has installed electric generating facilities, consisting of of electricity, on property located at (hereafter called " QF"). (Description of facilities), rated at kilowatts AC The QF is a customer of the Utility located within the assigned electric service territory of the Utility. The QF is prepared to generate electricity in parallel with the Utility. The QF's electric generating facilities meet the requirements of the rules adopted by the Utility on Cogeneration and Small Power Production and any technical standards for interconnection the Utility has established that are authorized by those rules. The Utility is obligated under federal and Minnesota law to interconnect with the QF and to purchase electricity offered for sale by the QF. A contract between the QF and the Utility is required. AGREEMENTS The QF and the Utility agree- 1. The Utility will sell electricity to the QF under the rate schedule in force for the class of customer to which the QF belongs. 2. The Utility will buy electricity from the QF under the current rate schedule filed with the city council or city -appointed governing body of the utility. The QF elects the rate schedule category hereinafter indicated: a. Average retail utility energy rate. 1 • QF capacity must be less than 40 kW. _ b. Simultaneous purchase and sale billing rate. • QF capacity must be less than 40 kW. c. Roll-over credits. • QF capacity must be less than 40 kW. d. Time -of -day purchase rates. • QF capacity must be 40 kW or more and less than or equal to 100 kW. A copy of the presently approved rate schedule is attached to this contract. 3. The rates for sales and purchases of electricity may change over the time this contract is in force, due to actions of the Utility or the State of Minnesota, and the QF and the Utility agree that sales and purchases will be made under the rates in effect each month during the time this contract is in force. 4. The Utility will compute the charges and payments for purchases and sales for each billing period. Any net credit to the QF, other than kilowatt-hour credits under clause 2(c), will be made under one of the following options as chosen by the QF. a. Credit to the QF's account with the Utility. b. Paid by check or electronic payment service to the QF within fifteen (15) days of the billing date. 5. Renewable energy credits associated with generation from the facility are owned by: 6. The QF must operate its electric generating facilities within any rules, regulations, and policies adopted by the Utility not prohibited by the rules governing Cogeneration and Small Power Production on the Utility's system which provide reasonable technical connection and operating specifications for the QF and are consistent with the Minnesota Public Utilities Commission's rules on Cogeneration and Small Power Production, as required under Minnesota Statutes §216B.164, subdivision 9. 7. The QF will not enter into an arrangement whereby electricity from the generating facilities will be sold to an end user in violation of the Utility's exclusive right to provide electric service in its service area under Minnesota Statutes, §216B.37-44 2 8. The QF will operate its electric generating facilities so that they conform to the national, state, and local electric and safety codes, and will be responsible for the costs of conformance. 9. The QF is responsible for the actual, reasonable costs of interconnection which are estimated to be $ The QF will pay the Utility in this way: 10. The QF will give the Utility reasonable access to its property and electric generating facilities if the configuration of those facilities does not permit disconnection or testing from the Utility 's side of the interconnection. If the Utility enters the QF's property, the Utility will remain responsible for its personnel. 11. The Utility may stop providing electricity to the QF during a system emergency. The Utility will not discriminate against the QF when it stops providing electricity or when it resumes providing electricity. 12. The Utility may stop purchasing electricity from the QF when necessary for the Utility to construct, install, maintain, repair, replace, remove, investigate, or inspect any equipment or facilities within its electric system. The Utility may stop purchasing electricity from the QF in the event the generating facilities listed in this contract are documented to be causing power quality, safety or reliability issues to the Utility's electric distribution system. The Utility will notify the QF before it stops purchasing electricity in this way: 13. The QF will keep in force general liability insurance against personal or property damage due to the installation, interconnection, and operation of its electric generating facilities. The amount of insurance coverage will be $ (The amount must be consistent with the distributed generation tariff adopted by the Utility pursuant to Minnesota Statutes §216B.1611, subdivision 3, clause 2.) 14. The QF and the Utility agree to attempt to resolve all disputes arising hereunder promptly and in a good faith manner. 15. The city council or city -appointed body governing the Utility has authority to consider and determine disputes, if any, that arise under this contract in accordance with procedures in the rules it adopts implementing Minnesota Statute §216B.164, pursuant to §216B.164, subdivision 9. 16. This contract becomes effective as soon as it is signed by the QF and the Utility. This contract will remain in force until either the QF or the Utility gives written notice to the other that the contract is canceled. This contract will be canceled thirty (30) days after notice is given. If the listed electric generating facilities are not interconnected to the Utility's distribution system within twelve months of the contract being signed by the QF and the Utility, the contract terminates. The QF and the Utility may delay termination by mutual agreement. 17. Neither the QF nor the Utility will be considered in default as to any obligation if the QF or the Utility is prevented from fulfilling the obligation due to an act of God, labor disturbance, act of public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, an order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or other cause beyond the QF's or Utility's control. However, the QF or Utility whose performance under this contract is hindered by such an event shall make all reasonable efforts to perform its obligations. 18. This contract can only be amended or modified by mutual agreement in writing signed by the QF and the Utility. 19. The QF must notify the Utility prior to any change in the electric generating facilities' capacity size or generating technology according to the interconnection process adopted by the Utility. 20. Termination of this contract is allowed (i) by the QF at any time without restriction; (ii) by Mutual Agreement between the Utility and the QF; (iii) upon abandonment or removal of electric generating facilities by the QF; (iv) by the Utility if the electric generating facilities are continuously non -operational for any twelve (12) consecutive month period; (v) by the Utility if the QF fails to comply with applicable interconnection design requirements or fails to remedy a violation of the interconnection process; or (vi) by the Utility upon breach of this contract by the QF unless cured with notice of cure received by the Utility prior to termination. 21. In the event this contract is terminated, the Utility shall have the rights to disconnect its facilities or direct the QF to disconnect its generating facilities. 22. This contract shall continue in effect after termination to the extent necessary to allow either the Utility or the QF to fulfill rights or obligations that arose under the contract. 23. Transfer of ownership of the generating facilities shall require the new owners and the Utility to execute a new contract. Upon the execution of a new contract with the new owners this contract shall be terminated. 24. The QF and the Utility shall at all times indemnify, defend, and save each other harmless from any and all damages, losses, claims, including claims and actions 0 relating to injury or death of any person or damage to property, costs and expenses, reasonable attorneys' fees and court costs, arising out of or resulting from the QF's or the Utility's performance of its obligations under this contract, except to the extent that such damages, losses or claims were caused by the negligence or intentional acts of the QF or the Utility. 25. The Utility and the QF will each be responsible for its own acts or omissions and the results thereof to the extent authorized by law and shall not be responsible for the acts or omissions of any others and the results thereof. 26. The QF's and the Utility's liability to each other for failure to perform its obligations under this contract shall be limited to the amount of direct damage actually occurred. In no event, shall the QF or the Utility be liable to each other for any punitive, incidental, indirect, special, or consequential damages of any kind whatsoever, including for loss of business opportunity or profits, regardless of whether such damages were foreseen. 27. The Utility does not give any warranty, expressed or implied, to the adequacy, safety, or other characteristics of the QF's interconnected system. 28. This contract contains all the agreements made between the QF and the Utility. The QF and Utility are not responsible other than those stated in this contract. THE QF AND THE UTILITY HAVE READ THIS CONTRACT AND AGREE TO BE BOUND BY ITS TERMS. AS EVIDENCE OF THEIR AGREEMENT, THEY HAVE EACH SIGNED THIS CONTRACT BELOW ON THE DATE LISTED BY SIGNER. QF By: Printed Name- DATE - UTILITY By: Printed Name- DATE - Contract Version: February 2019 E HUTCHINSON UTILITIES COMMISSION��` Board Action Form rMturit mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Adopt Distributed Energy Resource Resolution Interconnection Process Presenter: Jeremy/Dave Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments; Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: The State of Minnesota currently has interconnection process standards in effect to address the interconnection of distributed energy resources (DER) to the distribution grid. Minnesota Statute §21613.1611, cooperatives and municipals shall adopt an interconnection process that addresses the same issues as the interconnection process approved by the Minnesota Public Utilities Commission. The Municipal Minnesota Distributed Energy Resources Interconnection Process (Interconnection Process or M-MIP) applies to any DER no larger than 10-megawatt (MW) AC interconnecting to and operating in parallel with Hutchinson Utilities Commission's distribution system. This interconnection process document is designed to be customer -centric when explaining the steps and details to interconnect DER systems to the distribution grid. See attached: Resolution BOARD ACTION REQUESTED: Adopt Resolution Fiscal Impact: None Included in current budget;Budget Change: PROJECT SECTION:' Total Project Cost: Remaining Cost; RESOLUTION 19-02 A resolution adopting the Hutchinson Utilities Commission Distributed Energy Resource Interconnection Process. WHEREAS, by order on September 28, 2004, the Minnesota Public Utilities Commission adopted Generic Standards for Utility Tariffs for Interconnection and Operation of Distributed Generation Facilities; and WHEREAS, Minnesota Statutes Section 216B.1611, subdivision 3 required municipal utilities to adopt a generation tariff that addressed the issues included in the commission's order; and WHEREAS, under Minnesota Statutes Section 21613.25, any order of the commission rescinding, altering, amending, or reopening a prior order shall have the same effect as an original order; and WHEREAS, by order on August 13, 2018, the Minnesota Public Utilities Commission adopted an updated interconnection process for distributed energy resources replacing the standards adopted in 2004; and WHEREAS, the Hutchinson Utilities Commission Distributed Energy Resource Interconnection Process addresses the issues included in the commission's 2018 order; and WHEREAS, this Distributed Energy Resource Interconnection Process functions in concert with the Hutchinson Utilities Commission Policy Regarding Distributed Energy Resources and Net Metering as well as its Rules Governing the Interconnection of Cogeneration and Small Power Production; THEREFORE, BE IT RESOLVED that the Hutchinson Utilities Board of Commissioners adopts the Hutchinson Utilities Commission's Distributed Energy Resources Interconnection Process. Adopted by the Hutchinson Utilities Board of Commissioners on April 24, 2019. President Date Secretary Date Detroit Lakes Public Utility's 29.3 KW Select Solar Community Solar Garden Detroit Lakes, MN INTERCONNECTION PROCESS Process Overview B STRACT Interconnection Process for Distributed Energy Resources less than 10 megawatt (MW) interconnected to the Distribution System of a Municipal in the State of Minnesota. Contents Foreword.................................................................. 1 Key Terminology .......................................... 1.1. Distributed Energy Resource .................... 1.2. Point of Coupling/Connection .................. 1.3. Capacity .................................................... 2 Roles............................................................. 2.1. Overview ................................................... 2.2. DER Interconnection Coordinator ............ 2.3. Interconnection Customer ........................ 2.4. Application Agent ..................................... 2.5. Engineering Roles ..................................... 3 Processes...................................................... 3.1. Overview ................................................... 3.2. Importance of Process Timelines ............. 3.3. Simplified Process ..................................... 3.4. Fast Track Process ..................................... 3.5. Study Process ............................................ 3.6. Process Assistance .................................... 4 Interconnection Application ........................ 4.1. Overview ................................................... 4.2. Availability of Information ........................ 4.3. Interconnection Application Process Fees 4.4. Application Review Timelines ................... 4.5. Comparability ........................................... 4.6. Changing Process Queues ......................... 4.7. Queue Position ......................................... 4.8. Site Control ............................................... 5 Pre -Application Report ................................ 5.1. Pre -Application Report Requests ............. 5.2. Information Provided ............................... 1 2 2 2 2 2 2 3 3 3 3 3 3 4 5 5 6 6 6 6 7 7 7 8 i 5.3. Pre -Application Report Components............ 6 Capacity of the Distributed Energy Resources 6.1. Existing DER System Expansion .................... 6.2. New DER Systems ......................................... 6.3. Limited Capacity ........................................... 7 Modification to Interconnection Applications 7.1. Procedures.................................................... 8 Interconnection Agreements ........................... 8.1. Timelines....................................................... 8.2. Types of Agreements .................................... 9 Interconnection................................................ 9.1. Metering....................................................... 9.2. Inspection, Testing and Commissioning....... 9.3. Interconnection Costs ................................... 9.4. Non -Warrantee ............................................. 9.5. Technical Requirements ............................... 9.6. Authorization for Parallel Operations........... 10 Extension of Timelines ................................. 10.1. Reasonable Efforts .................................... 10.2. Extensions ................................................. 11 Disputes........................................................ 11.1. Procedures ................................................ 12 Clauses.......................................................... 12.1. Confidentiality ........................................... 12.2. Non -Warranty ........................................... 12.3. Indemnification ......................................... 12.4. Limitation of Liability ................................ 13 Glossary........................................................ 14 Certification of DER Equipment ................... 15 Certification Codes and Standards .............. 10 11 11 11 11 12 12 12 12 13 13 13 14 14 14 14 15 15 15 15 15 15 16 16 17 17 18 19 25 27 Foreword The State of Minnesota currently has interconnection process standards in effect to address the interconnection of distributed energy resources (DER) to the distribution grid. Under Minnesota Statute §216B.1611, cooperatives and municipals shall adopt an interconnection process that addresses the same issues as the interconnection process approved by the Minnesota Public Utilities Commission. The Municipal Minnesota Distributed Energy Resources Interconnection Process (Interconnection Process or M-MIP) applies to any DER no larger than 10-megawatt (MW) AC interconnecting to and operating in parallel with Hutchinson Utilities Commission's distribution system in Minnesota. This interconnection process document is designed to be customer -centric when explaining the steps and details to interconnect DER systems to the distribution grid. The interconnection process document is broken into five parts: Process Overview, Simplified Process, Fast Track Process, Study Process and Interconnection Agreement. For the majority of DER interconnection, only the Process Overview and the Simplified Process parts will apply. For larger and more complex DER interconnections, the Fast Track Process and the Study Process may apply. In addition to the interconnection process documents, interconnection agreement(s) are to be executed prior to the DER system being interconnected to the distribution grid. For most DER interconnection, the Hutchinson Utilities Commission's Contract for Cogeneration and Small Power Production Facilities (Uniform Contract) will be used. For DER systems that do not fall under the terms of the Uniform Contract, the M-MIP Interconnection Agreement will apply. The process to interconnect a DER system to the distribution grid starts with the submission of an Interconnection Application. Each track has different information that is requested in the application and the non-refundable interconnection application fees will vary. Both the electric utility and the interconnecting customer have timelines that are enforced to ensure a timely application review, contract execution and interconnection commissioning. The key to a successful interconnection of a DER system is communication between all parties. Timely submission of the Interconnection Application prior to the purchase and installation of a DER system is strongly recommended. The Utility encourages customers to ask questions throughout the interconnection process. Interconnecting DER system to the distribution grid is not an effortless process, but it does not need to be a problematic process either. 1 Key Terminology 1.1. Distributed Energy Resource Distributed Energy Resources, DER, was often referred to in past interconnection processes as Distributed Generation, DG, and on occasion also interchanged with the term Qualifying Facility, QF. This Interconnection Process uses the term DER to address all types of generation and energy resources that can be interconnected to the electric distribution system. DER technologies can include photovoltaic solar systems, wind turbines, storage batteries or diesel generators and are not limited to renewable types of technologies. 1.2. Point of Coupling/Connection DER systems often reside behind the utility's revenue meter of a residence or business. The meter is normally the point of demarcation between the utility -owned equipment and the customer -owned equipment. The term Point of Common Coupling, PCC, is the demarcation location between the utility and the customer. The Point of DER Connection, PoC, can be different from the PCC. The PoC is the location where a DER system(s) would interconnect to the electrical system normally owned by the customer. For example, the PoC for a rooftop photovoltaic solar system may the main electrical panel in a customer's home. 1.3. Capacity Throughout the Interconnection Process will be references to capacity of the DER system. In most cases, the capacity listed is referring to the Nameplate Capacity of the DER system. All capacity reference will be in alternating current, AC. There can be multiple DER systems with different PoCs that all have the same PCC submitted on a single interconnection application. The capacity for this type of interconnection would be the aggregate Nameplate Capacity of all DER systems at the individual PoCs. Additional examples of DER system arrangements can be seen in Section 13 under the definition of Point of Common Coupling. 2 Roles 2.1. Overview During the interconnection process for a proposed DER system, there are multiple entities involved in the application, approval and commissioning processes. The main entities that are involved during the Interconnection Process for a proposed DER system are the Interconnection Customer, the Application Agent and the DER Interconnection Coordinator. Official definitions of each entity are defined in the Glossary (Section 13). Additional details are explained in the subsections below. 2.2. DER Interconnection Coordinator The utility is referred to as the Area Electric Power Supply Operator in this Interconnection Process. The Area EPS Operator shall designate a DER Interconnection Coordinator(s) to serve as a single point of contact from which general information on the application process may be obtained. The DER Interconnection Coordinator shall be available to provide coordination assistance with the Interconnection Customer but is not responsible to directly answer or resolve all of the issues involved in review and implementation of the interconnection process and standards. The contact information of the DER Interconnection Coordinator will be posted on the Area EPS Operator's website when feasible. 2.3. Interconnection Customer The owner of the proposed DER system and the entity requesting interconnection to the distribution system. 2.4. Application Agent The Interconnection Customer may designate, on the Interconnection Application or in writing after the application has been submitted, an Application Agent to serve as a single point of contact to coordinate with the DER Interconnection Coordinator on their behalf. Designation of an Application Agent does not absolve the Interconnection Customer from signing application documents and the responsibilities outlined in the Interconnection Process or in interconnection agreements. DER vendors, project managers or electricians are common entities that the Interconnection Customer may designate to perform this role. 2.5. Engineering Roles Either party may designate a specific person to be a single point of contact to provide technical expertise during the Interconnection Process for their organization. The person to supply engineering expertise may be a third party such as an engineering consultant or manufacturer's engineer. 3 Processes 3.1. Overview The Interconnection Process applies to any DER no larger than 10 MW AC interconnecting to and operating in parallel with an Area EPS distribution system in Minnesota. Interested parties with plans to interconnect DER systems larger than 10 MW AC to the distribution system should contact the Area EPS Operator for the specific interconnection process. Federal Energy Regulatory Commission's (FERC) interconnection process will supersede any interconnection process the Area EPS Operator has for DER system interconnections that fall under the jurisdiction of FERC. The Interconnection Process for DER is broken into three different tracks; the Simplified Process, the Fast Track Process, and the Study Process. The general classification of each track is summarized in Table 3.1 below. Table 3.1. Interconnection Process Tracks Track DER Technology Size Limitations Simplified Process Certified Inverter only 20 kW AC Fast Track Process All types 5 MW AC Study Process All types 10 MW AC If engineering screens are failed during the application process, a proposed DER interconnection may be moved into a different track. When a proposed DER interconnection is moved into a different track, additional information may be requested and additional fees may apply. 3.2. Importance of Process Timelines It is very important to pay attention to timelines listed for each process track. The timelines exist for an orderly and efficient process to interconnect DER systems to the Distribution System. If a timeline is missed by an Interconnection Customer, without the Interconnection Customer requesting a Timeline Extension explained in Section 10, the Interconnection Application will be deem withdrawn by the Area EPS Operator. The Area EPS Operator also need to abided to the timelines listed for each process track. The process for an Area EPS Operator to request Timeline Extensions is also addressed in Section 10. Unless otherwise state, all time frames are measured in Business Days. For purpose of measuring these time intervals, the time shall be computed so as to exclude the first and include the last day of the prescribed duration of time. Any communication sent or received after 4:30 p.m. Central Prevailing Time or on a Saturday, Sunday or Holiday shall be considered to be sent on the next Business Day. 3.3. Simplified Process An application to interconnect a certified', inverter -based DER system no larger than 20 kilowatts (kW) shall be evaluated under the Simplified Process. A common form of DER inverter certification is UL 1741. Proposed DER systems that require Area EPS system modifications to accommodate the interconnection do not qualify for the Simplified Process. A transformer change, fusing upgrades or line extensions are common examples of Area EPS system modification. Simplified Process eligibility does not imply or indicate the Interconnection Application will pass the initial review screens. Failure to pass the screens will route the Interconnection Application to the Fast Track Process. 3.4. Fast Track Process An application to interconnect a DER shall be evaluated under the Fast Track Process if the eligibility requirements are not exceeded in Table 3.2 and the application does not qualify for the Simplified Process. Fast Track eligibility for DERs is determined based upon the generator type, the size of the generator, voltage of the line, and the location of and the type of line at the Point of Common Coupling, (PCC). All synchronous and induction machines must be no larger than 2 MW to be eligible for Fast Track Process consideration. Table 3.2. Fast Track Eligibility for DER Fast Track Eligibility for certified, Fast Track Eligibility' inverter -based DER on a Mainline3 Line Voltage Regardless of and:5 2.5 Electrical Circuit Miles from Location Substation' < 5 W <_ 500 kW <_ 500 kW >_5Wand <15W <_1MW <_2MW >_15Wand <30W <_2MW <_4MW >_30Wand<_69W <_4MW <_5MW In addition to the size threshold, the Interconnection Customer's proposed DER must meet the codes, standards and certification requirements found in Section 15 and Section 14. ' Additional information regarding certified equipment is found in Section 15 and Section 14. z Synchronous and induction machine eligibility is limited to no more than 2 MW even when line voltage is greater than 15 W. s For purposes of this table, a Mainline is the three-phase backbone of a circuit. It will typically constitute lines with wire sizes of 4/0 American wire gauge, 266 kcmil, 336.4 kcmil, 397.5 kcmil, 477 kcmil and 795 kcmil. 4 An Interconnection Customer can determine this information about its proposed interconnection location in advance by requesting a pre -application report described in Section 5. 3.5. Study Process An application to interconnect a DER that does not meet the Simplified Process or Fast Track Process eligibility requirements or does not pass the review as described in either process, shall be evaluated under the Study Process. 3.6. Process Assistance Prior to submitting an Interconnection Application, the Interconnection Customer may ask the Area EPS Operator's DER Interconnection Coordinator which process track a proposed interconnection is subject to and additional details on each process track. An Interconnection Customer can obtain, through an informal request, general information about the interconnection process and on Affected System(s) for a proposed interconnection at a specific location. Upon request, the existing electric system information provided to the Interconnection Customer should include relevant system study results, interconnection studies, and other materials useful to an understanding of an interconnection at a particular point on the Area EPS Operator's System. Information will be provided to the extent such provision does not violate the privacy policies of the Area EPS Operator, confidentiality provisions of prior agreements or critical infrastructure requirements. The Area EPS Operator shall comply with reasonable requests for such information. 4 Interconnection Application 4.1. Overview Each process track has different information that needs to be provided to the Area EPS Operator. Table 4.1 indicates which application is to be completed in its entirety and submitted to the Area EPS Operator to start the interconnection process for the proposed DER system. Table 4.1. Interconnection Application Process Track Application Simplified Simplified Interconnection Application Fast Track Standard Interconnection Application Study Standard Interconnection Application The Area EPS Operator will provide all necessary Interconnection Applications, Interconnection Process documents and sample interconnection agreements on its website if possible. The Area EPS Operator will also accept Interconnection Applications submitted electronically either through a web portal or to an email address specified by the Area EPS Operator. The Area EPS Operator may allow the Interconnection Application to be submitted with an electronic signature. 4.2. Availability of Information The Area EPS Operator will provide all necessary Interconnection Applications, Interconnection Process documents and sample interconnection agreements on its website if possible. If a website is not available, the applicable documents will be readily available at the Area EPS Operator's main office. The Area EPS Operator will establish a public queue of active interconnection applications on its website once the Area EPS Operator has received at least 40 completed Interconnection Applications in a year. The public queue will be updated, at minimum, on a monthly basis. 4.3. Interconnection Application Process Fees Each Interconnection Application submitted to the Area EPS Operator must include the appropriate interconnection application process fee prior to the Area EPS Operator reviewing the Interconnection Application. The required process fee for each process track is listed in Table 4.2. Table 4.2. Interconnection Application Process Fee Process Track Process Fee Simplified $100 Fast Track Certified' System $100 + $1/kW Non -Certified System $100 + $2/kW Study $1,000 + $2/kW down payment. Additional study fees may apply. 4.4. Application Review Timelines The Interconnection Application shall be date- and time -stamped upon initial, and if necessary, resubmission receipt. The Area EPS Operator shall notify the Interconnection Customer if the Interconnection Application is deemed incomplete within ten (10) Business Days. This notification shall include a written list detailing all information that must be provided to complete the Interconnection Application. Depending on the process track the Interconnection Customer has between five (5) and ten (10) Business Days to provide the missing information unless additional time is 5 Additional information regarding certified equipment is found in Section 15 and Section 14. requested with valid reasons. Failure to submit the requested information within the stated timeline will result in the Interconnection Application being withdrawn. An Interconnection Application will be deemed complete upon submission to the Area EPS Operator when all documents, fees and information required with the Interconnection Application adhering to Minnesota Technical Requirements is included. The time- and date- stamp of the completed Interconnection Application shall be accepted as the qualifying date for purposes of establishing a queue position as described in Section 4.7. Depending on the process track the Area EPS Operator has either a total of twenty (20) Business Days or twenty-five (25) Business Days to complete the Interconnection Application review and submit notice back to the Interconnection Customer stating the proposed DER system may proceed with the interconnection process or the proposed DER system requires additional engineering studies. The period of time when waiting for the Interconnection Customer to provide missing information is not included in the Area EPS Operator's twenty (20) Business Days or twenty-five (25) Business Days review timeline. 4.5. Comparability The Area EPS Operator shall receive, process and analyze all Interconnection Applications in a timely manner. The Area EPS Operator shall use the same Reasonable Efforts in processing and analyzing Interconnection Applications from all Interconnection Customers. 4.6. Changing Process Queues During the review of the initially submitted Interconnection Application for the proposed DER system, the Area EPS Operator may determine the proposed DER system should be in a different process track. For proposed DER systems that are moved into a different process track after submittal of the initial application, the difference between the originally submitted processing fee and the current process track's processing fee will be assessed. In addition, the Area EPS Operator may request the Interconnection Customer to provide additional information regarding the proposed DER system. 4.7. Queue Position The Area EPS Operator shall maintain a single, administrative queue and may manage the queue by geographical region. The queue position of each completed Interconnection Application is used to determine the engineering review. The queue position is also used to determine the cost responsibility for system upgrades necessary to accommodate the interconnection. An Interconnection Application will retain its queue number even when it is moved into a different process track. An Interconnection Application can lose its queue position if the Interconnection Customer misses timelines in the applicable process track. The Interconnection Customer and Area EPS Operator have the opportunity to request timeline extensions which are explained in detail in Section 10. 4.8. Site Control Documentation of site control must be submitted with the Interconnection Application. Site control may be demonstrated by any of the following: • Ownership of, a leasehold interest in, or a right to develop a site for the purpose of constructing the DER system. • An option to purchase or acquire a leasehold site for constructing the DER system. • An exclusivity or other business relationship between the Interconnection Customer and the entity having the right to sell, lease, or grant the Interconnection Customer the right to possess or occupy a site for constructing the DER system. For DER in the Simplified Process, proof of site control may be demonstrated by the site owner's signature on the Simplified Interconnection Application. 5 Pre -Application Report 5.1. Pre -Application Report Requests The Interconnection Customer may submit a Pre -Application Report Request, including a non-refundable fee of $300, for a Pre -Application Report on a proposed project at a specific site. The Interconnection Customer must fill out the Pre -Application Request form as completely as possible. The Area EPS Operator shall provide the readily available data listed in Section 5.3 within fifteen (15) Business Days of receipt of a completed request form and payment. The Pre -Application Report produced by the Area EPS Operator is non -binding, does not confer any rights, and does not preclude the Interconnection Customer from any interconnection process steps including submission of the Interconnection Application. 5.2. Information Provided Using the information provided in the Pre -Application Report Request form, the Area EPS Operator will identify the substation/area bus, bank or circuit likely to serve the proposed PCC. This selection by the Area EPS Operator does not necessarily indicate, after application of the screens and/or study, that this would be the circuit the project ultimately connects to. The Interconnection Customer must request additional Pre - Application Reports if information about multiple PCC is requested. The Pre -Application Report will only include existing data. A request for a Pre - Application Report does not obligate the Area EPS Operator to conduct a study or other analysis of the proposed DER in the event that data is not readily available. The Area EPS Operator will provide the Interconnection Customer with the data that is available. The confidentiality provisions in Section 12.1 Error! Reference source not found.apply to Pre -Application Reports. 5.3. Pre -Application Report Components The Pre -Application Report shall include following pieces of information provided the data currently exists and is readily available. • Total capacity (in megawatts (MW)) of substation/area bus, bank or circuit based on normal or operating ratings likely to serve the proposed Point of Common Coupling. • Existing aggregate generation capacity (in MW) interconnected to a substation/area bus, bank or circuit (i.e., amount of generation online) likely to serve the proposed Point of Common Coupling. • Aggregate queued generation capacity (in MW) for a substation/area bus, bank or circuit (i.e., amount of generation in the queue) likely to serve the proposed Point of Common Coupling. • Available capacity (in MW) of substation/area bus or bank and circuit likely to serve the proposed Point of Common Coupling (i.e., total capacity less the sum of existing aggregate generation capacity and aggregate queued generation capacity). • Substation nominal distribution voltage and/or transmission nominal voltage if applicable. • Nominal distribution circuit voltage at the proposed Point of Common Coupling. • Approximate circuit distance between the proposed Point of Common Coupling and the substation. • Relevant line section(s) actual or estimated peak load and minimum load data, including daytime minimum load and absolute minimum load, when available. • Whether the Point of Common Coupling is located behind a line voltage regulator. • Number and rating of protective devices and number and type (standard, bi- directional) of voltage regulating devices between the proposed Point of Common Coupling and the substation/area. Identify whether the substation has a load tap changer. • Number of phases available on the Area EPS medium voltage system at the proposed Point of Common Coupling. If a single phase, distance from the three- phase circuit. • Limiting conductor ratings from the proposed Point of Common Coupling to the distribution substation. • Whether the Point of Common Coupling is located on a spot network, grid network, or radial supply. • Based on the proposed Point of Common Coupling, existing or known constraints such as, but not limited to, electrical dependencies at that location, short circuit interrupting capacity issues, power quality or stability issues on the circuit, capacity constraints, or secondary networks 6 Capacity of the Distributed Energy Resources 6.1. Existing DER System Expansion If the Interconnection Application is for an increase in capacity to an existing DER system, the Interconnection Application shall be evaluated on the basis on the total new alternating current (AC) capacity of the DER. The maximum capacity for the DER shall be the aggregate maximum Nameplate Rating unless the conditions in Section 6.3 are met. 6.2. New DER Systems An Interconnection Application for a DER that includes a single or multiple energy production devices, (i.e. solar and storage), at a site for which the Interconnection Customer seeks a simple Point of Coupling, shall be evaluated on the basis of the aggregated maximum Nameplate Rating unless the conditions in Section 6.3 are met. 6.3. Limited Capacity A DER system may include devices, (i.e. control systems, power relays or other similar device settings), that can limit the maximum capacity at which the DER system can generate into the Area EPS Operator's distribution system. For DER system that include capacity limited devices, the Interconnection Customer must obtain the Area EPS Operator's agreement to consider the DER system with the Nameplate Rating as the limited capacity. The Area EPS Operator's agreement shall not be unreasonable withheld provided proper documentation is provided showing the effective limit active power output will not adversely affect the safety and reliability of the Area EPS Operator's distribution system. If the Area EPS Operator does not agree, the Interconnection Application must be withdrawn or revised to specify the maximum capacity that the DER system is capable of injecting into the Area EPS Operator's distribution system without such limitations. Nothing in this section shall prevent the Area EPS Operator from considering a higher output, (i.e. aggregate Nameplate Rating), if the limitations do not provide adequate assurance, when evaluating the system impacts. 7 Modification to Interconnection Applications 7.1. Procedures At any time after the Interconnection Application is deemed complete, the Interconnection Customer or the Area EPS Operator may identify modifications to the proposed DER system that may improve costs and benefits (including reliability) of the proposed DER system and the ability for the Area EPS Operator to accommodate the proposed DER system. The Interconnection Customer shall submit to the Area EPS Operator in writing all proposed modifications to any information provided in the Interconnection Application. The Area EPS Operator cannot unilaterally modify the Interconnection Application. Additional information regarding modifications to interconnection applications is found in each process track document. 8 Interconnection Agreements 8.1. Timelines After the Interconnection Application has been approved by the Area EPS Operator, the Area EPS Operator shall provide the Interconnection Customer with an executable Interconnection Agreement within five (5) Business Days. The Interconnection Customer shall have thirty (30) Business Days to sign and return the Interconnection Agreement to the Area EPS Operator. The Area EPS Operator shall sign the Interconnection Agreement within five (5) business days after receiving the signed Interconnection Agreement from the Interconnection Customer. If the Interconnection Customer fails to return a signed Interconnection Agreement to the Area EPS Operator within thirty (30) Business Days and fails to request an extension as explained in Section 10, the Interconnection Application will be deemed withdrawn. 8.2. Types of Agreements There are two main types of Interconnection Agreements that may be executed with an approved Interconnection Application. In general, Interconnection Customers with a proposed DER system that qualifies for the Simplified Process track will sign the Area EPS Operator's Uniform Contract for Cogeneration and Small Power Production Facilities (Uniform Contract). Proposed DER systems less than 100 kW that are under the Fast Track process may also sign the Uniform Contract. All other sized DER system will sign the Interconnection Agreement. Area EPS Operators who do not purchase the excess generation of the proposed DER system will also require the Interconnection Agreement executed for any size of DER system. Table 8.1. Interconnection Agreements Process Track Interconnection Agreement Simplified Uniform Contract Qualifies for Net Energy Billing Uniform Contract Fast Track Less than 100 kW & Area EPS Agrees to Purchase Excess Generation Uniform Contract All Other DER systems Interconnection Agreement Study Interconnection Agreement Interconnection Customers may choose to sign the Interconnection Agreement in lieu of the Uniform Contact. A separate power purchase agreement will also need to be executed if the Uniform Contract is not utilized. Interconnection of the proposed DER system will not occur until a signed Uniform Contract or the Interconnection Agreement is returned to the Area EPS Operator no later than five (5) days prior to schedule testing and inspection. 9 Interconnection 9.1. Metering Any metering requirements necessitated by the use of the DER system shall be installed at the Interconnection Customer's expense. The metering requirement costs will be included in the final invoice of interconnection costs to the Interconnection Customer. The Interconnection Customer is also responsible for metering replacement costs not covered in the Interconnection Customer's general customer charge. The Area EPS Operator may charge Interconnection Customers an ongoing metering -related charge for an estimate of ongoing metering -related costs specifically demonstrated. 9.2. Inspection, Testing and Commissioning The Interconnection Customer shall arrange for the inspection and testing of the DER system and the Customer's Interconnection Facilities prior to interconnection pursuant to Minnesota Interconnection Technical Requirements. Commissioning tests of the Interconnection Customer's installed equipment shall be performed pursuant to applicable codes and standards of Minnesota's Technical Requirements and Section 15. The Interconnection Customer shall notify the Area EPS Operator of testing and inspection no fewer than five (5) Business Days in advance, or as may be agreed to by the Parties. Depending on the process track, either a Certificate of Completion or a testing procedure shall be submitted to the Area EPS Operator prior to the testing and inspection date. The Area EPS Operator shall send qualified personnel to the DER site to inspect the interconnection and witness the testing. Testing and inspection shall occur on a Business Day at a mutually agreed upon time and date. The Area EPS Operator may waive the right to witness the testing. 9.3. Interconnection Costs The Interconnection Customer shall pay for the actual cost of the Interconnection Facilities and Distribution Upgrades along with the Area EPS Operator's cost to commission the proposed DER system. An estimate of the interconnection costs shall be stated in the Uniform Contract or Interconnection Agreement. 9.4. Non -Warrantee Area EPS Operator does not give any warranty, expressed or implied, as to the adequacy, safety, or other characteristics of any structures, equipment, wires, appliances or devices owned, operated, installed or maintained by the Interconnection Customer, including without limitation the DER and any structures, equipment, wires, appliances or devices not owned, operated or maintained by the Area EPS Operator. The Area EPS Operator does not guarantee uninterrupted power supply to the DER and will operate the distribution system with the same reliability standards for the entire customer base. 9.5. Technical Requirements The Area EPS Operator shall use Reasonable Efforts to provide the Interconnection Customer the Minnesota Technical Requirements by providing the document with the notice of approval of the interconnection application or by providing a website link to the document. Additionally, the Area EPS Operator shall notify the Interconnection Customer of any changes to these requirements as soon as they are known. Unless notified by the Area EPS Operator, the Interconnection Customer only needs to be in compliance of the current version of the Minnesota Technical Requirements at the time of interconnection. 9.6. Authorization for Parallel Operations The Interconnection Customer shall not operate its DER system in parallel with the Area EPS Operator's distribution system without prior written authorization from the Area EPS Operator. The Area EPS Operator shall provide such authorization within three (3) Business Days from when the Area EPS Operator receives notification that the Interconnection Customer has complied with all applicable parallel operations requirements; the completion of a successful testing and inspection of the DER system and all payments for issued bills related to the interconnection process that are past due have been paid in full. Such authorization shall not be unreasonably withheld, conditioned or delayed. 10 Extension of Timelines 10.1. Reasonable Efforts The Area EPS Operator shall make Reasonable Efforts to meet all time frames provided in these procedures. If the Area EPS Operator cannot meet a deadline provided herein, it must notify the Interconnection Customer in writing within three (3) Business Days after the deadline to explain the reason for the failure to meet the deadline and provide an estimated time by which it will complete the applicable interconnection procedure in the process. 10.2. Extensions For applicable time frames described in these procedures, the Interconnection Customer may request, in writing, one extension equivalent to half of the time originally allotted (e.g., ten (10) Business Days for a twenty (20) Business Days original time frame) which the Area EPS Operator may not unreasonably refuse. No further extensions for the applicable time frame shall be granted absent a Force Majeure Event or other similarly extraordinary circumstance. 11 Disputes 11.1. Procedures The Parties agree in a good faith effort to attempt to resolve all disputes arising out of the interconnection process and associated study and Interconnection Agreements. The Parties agree to follow the established dispute resolution policy adopted by the Area EPS Operator. 12 Clauses 12.1. Confidentiality Confidential Information shall mean any confidential and/or proprietary information provided by one Party to the other Party that is clearly marked or otherwise designated "Confidential." For purposes of these procedures, design, operating specifications, and metering data provided by the Interconnection Customer may be deemed Confidential Information regardless of whether it is clearly marked or otherwise designated as such. If requested by either Party, the other Party shall provide in writing the basis for asserting that the information warrants confidential treatment. Parties providing a Governmental Authority trade secret, privileged or otherwise not public or nonpublic data under Minnesota Government Data Practices Act, Minnesota Statute Chapter 13, shall identify such data consistent with the Commission's September 1, 1999 Revised Procedures for Handling Trade Secret and Privileged Data available online at: httns://mn. ov/�uc/s�uc-documents/#4. Confidential Information does not include information previously in the public domain with proper authorization, required to be publicly submitted or divulged by Governmental Authorities (after notice to the other Party and after exhausting any opportunity to oppose such publication or release), or necessary to be publicly divulged in an action to enforce these procedures. Each Party receiving Confidential Information shall hold such information in confidence and shall not disclose it to any third party nor to the public without the prior written authorization from the Party providing that information, except to fulfill obligations under these procedures, or to fulfill legal or regulatory requirements that could not otherwise be fulfilled by not making the information public. Each Party shall hold in confidence and shall not disclose Confidential Information, to any person (except employees, officers, representatives and agents, who agree to be bound by this section). Confidential Information shall be clearly marked as such on each page or otherwise affirmatively identified. If a court, government agency or entity with the right, power, and authority to do so, requests or requires either Party, by subpoena, oral disposition, interrogatories, requests for production of documents, administrative order, or otherwise, to disclose Confidential Information, that Party shall provide the other Party with prompt notice of such request(s) or requirements(s) so that the other Party may seek an appropriate protective order or waive compliance with the terms of this Agreement. In the absence of a protective order or waiver the Party shall disclose such confidential information which, in the opinion of its counsel, the party is legally compelled to disclose. Each Party will use reasonable efforts to obtain reliable assurance that confidential treatment will be accorded to any confidential information furnished. Critical infrastructure information or information that is deemed or otherwise designated by a Party as Critical Energy/Electric Infrastructure Information (CEII) pursuant to FERC regulation, 1S C,F.R. §388.133, as may be amended from time to time, may be subject to further protections for disclosure as required by FERC or FERC regulations or orders and the disclosing Party's CEII policies. Each Party shall employ at least the same standard of care to protect Confidential Information obtained from the other Party as it employs to protect its own Confidential Information. Confidential Information does not include information previously in the public domain with proper authorization, required to be publicly submitted or divulged by Governmental Authorities (after notice to the other Party and after exhausting any opportunity to oppose such publication or release), or necessary to be publicly divulged in an action to enforce these procedures. Each Party receiving Confidential Information shall hold such information in confidence and shall not disclose it to any third party nor to the public without the prior written authorization from the Party providing that information, except to fulfill obligations under these procedures, or to fulfill legal or regulatory requirements that could not otherwise be fulfilled by not making the information public. Each Party is entitled to equitable relief, by injunction or otherwise, to enforce its rights under this provision to prevent the release of Confidential Information without bond or proof of damages and may seek other remedies available at law or in equity for breach of this provision. 12.2. Non -Warranty The Area EPS Operator does not give any warranty, expressed or implied, as to the adequacy, safety, or other characteristics of any structures, equipment, wires, appliances or devices owned, operated, installed or maintained by the Interconnection Customer, including without limitation the DER and any structures, equipment, wires, appliances or devices not owned, operated or maintained by the Area EPS Operator. 12.3. Indemnification Each Party is protected from liability incurred to third parties as a result of carrying out the provisions of this interconnection process and subsequent interconnection agreements. The Parties shall at all times indemnify, defend, and save the other Party harmless from, any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the other Party's action or inactions of its obligations under this agreement on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnified Party. This indemnification obligation shall apply notwithstanding any negligent or intentional acts, errors or omissions of the indemnified Party, but the indemnifying Party's liability to indemnify the indemnified Party shall be reduced in proportion to the percentage by which the indemnified Party's negligent or intentional acts, errors or omissions caused the damages. Neither Party shall be indemnified for its damages resulting from its sole negligence, intentional acts or willful misconduct. These indemnity provisions shall not be construed to relieve any insurer of its obligation to pay claims consistent with the provisions of a valid insurance policy. If an indemnified person is entitled to indemnification under this article as a result of a claim by a third party, and the indemnifying Party fails, after notice and reasonable opportunity to proceed under this article, to assume the defense of such claim, such indemnified person may at the expense of the indemnifying Party contest, settle or consent to the entry of any judgment with respect to, or pay in full, such claim. If an indemnifying party is obligated to indemnify and hold any indemnified person harmless under this article, the amount owing to the indemnified person shall be the amount of such indemnified person's actual loss, net of any insurance or other recovery. Promptly after receipt by an indemnified person of any claim or notice of the commencement of any action or administrative or legal proceeding or investigation as to which the indemnity provided for in this article may apply, the indemnified person shall notify the indemnifying party of such fact. Any failure of or delay in such notification shall not affect a Party's indemnification obligation unless such failure or delay is materially prejudicial to the indemnifying party. 12.4. Limitation of Liability Each party's liability to the other party for any loss, cost, claim, injury, liability, or expense, including reasonable attorney's fees, relating to or arising from any act or omission in its performance of this Agreement, shall be limited to the amount of direct damage actually incurred. In no event shall either party be liable to the other party for an indirect, incidental, special, consequential, or punitive damages of any kind whatsoever, except as allowed under in Section 12.3. 13 Glossary Affected System — Another Area EPS Operator's System, Transmission Owner's Transmission System, or Transmission System connected generation which may be affected by the proposed interconnection. Applicant Agent — A person designated in writing by the Interconnection Customer to represent or provide information to the Area EPS on the Interconnection Customer's behalf throughout the interconnection process. Area EPS —The electric power distribution system connected at the Point of Common Coupling. Area EPS Operator — An entity that owns, controls, or operates the electric power distribution systems that are used for the provision of electric service in Minnesota. For this Interconnection Process the Area EPS Operator is Hutchinson Utilities Commission. Business Day — Monday through Friday, excluding Holidays as defined by Minn. Stat. §645.44, Subdivision 5. Any communication to have been sent or received after 4:30 p.m. Central Prevailing Time or on a Saturday, Sunday or holiday shall be considered to have been sent on the next Business Day. Certified Equipment — Certified equipment is equipment that has been tested by a national recognized lab meeting a specific standard. For DER systems, UL 1741 listing is a common form of DER inverter certification. Additional information is seen in Section 15 and Section 14. Confidential Information — Any confidential and/or proprietary information provided by one Party to the other Party and is clearly marked or otherwise designated "Confidential." All procedures, design, operating specifications, and metering data provided by the Interconnection Customer may be deemed Confidential Information. See Section 12.1 for further information. Distributed Energy Resource (DER) — A source of electric power that is not directly connected to a bulk power system or central station service. DER includes both generators and energy storage technologies capable of exporting active power to an EPS. An interconnection system or a supplemental DER device that is necessary for compliance with this standard is part of a DER. For the purpose of the Interconnection Process and interconnection agreements, the DER includes the Customer's Interconnection Facilities but shall not include the Area EPS Operator's Interconnection Facilities. Distribution System —The Area EPS facilities which are not part of the Local EPS, Transmission System or any generation system. Distribution Upgrades —The additions, modifications, and upgrades to the Distribution System at or beyond the Point of Common Coupling to facilitate interconnection of the DER and render the distribution service necessary to effect the Interconnection Customer's connection to the Distribution System. Distribution Upgrades do not include Interconnection Facilities. Electric Power System (EPS) —The facilities that deliver electric power to a load. Fast Track Process — The procedure as described in the Interconnection Process - Fast Track Process for evaluating an Interconnection Application for a DER that meets the eligibility requirements of Section 3.4. Force Majeure Event — An act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, an order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or another cause beyond a Party's control. A Force Majeure Event does not include an act of negligence or intentional wrongdoing. Good Utility Practice — Any of the practices, methods and acts engaged in or approved by a significant portion of the electric industry during the relevant time period, or any of the practices, methods and act which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region. Governmental Authority — Any federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the Parties, their respective facilities, or the respective services they provide, and exercising or entitled to exercise any administrative, executive, police, or taxing authority or power; provided, however, that such term does not include the Interconnection Customer, the Area EPS Operator, or any Affiliate thereof. The governing authority of the municipal utility is the authority governing interconnection requirements unless otherwise provided for in the Minnesota Technical Requirements. Interconnection Agreement —The terms and conditions between the Area EPS Operator and Interconnection Customer (Parties). See Section 8 for when the Uniform Contract or Interconnection Agreement applies. Interconnection Application —The Interconnection Customer's request to interconnect a new or modified, as described in Section 4, DER. See Simplified Application Form and Interconnection Application Form. Interconnection Customer —The person or entity, including the Area EPS Operator, whom will be the owner of the DER that proposes to interconnect a DER(s) with the Area EPS Operator's Distribution System. The Interconnection Customer is responsible for ensuring the DER(s) is designed, operated and maintained in compliance with the Minnesota Technical Requirements. Interconnection Facilities —The Area EPS Operator's Interconnection Facilities and the Interconnection Customer's Interconnection Facilities. Collectively, Interconnection Facilities include all facilities and equipment between the DER and the Point of Common Coupling, including any modification, additions or upgrades that are necessary to physically and electrically interconnect the DER to the Area EPS Operator's System. Some examples of Customer Interconnection Facilities include: supplemental DER devices, inverters, and associated wiring and cables up to the Point of DER Connection. Some examples of Area EPS Operator Interconnection Facilities include sole use facilities; such as, line extensions, controls, relays, switches, breakers, transformers and shall not include Distribution Upgrades or Network Upgrades. Interconnection Process —The Area EPS Operator's interconnection standards in this document. Material Modification — A modification to machine data, equipment configuration or to the interconnection site of the DER at any time after receiving notification by the Area EPS Operator of a complete Interconnection Application that has a material impact on the cost, timing, or design of any Interconnection Facilities or Upgrades, or a material impact on the cost, timing or design of any Interconnection Application with a later Queue Position or the safety or reliability of the Area EPS.6 MN Technical Requirements —The term including all of the DER technical interconnection requirement documents for the state of Minnesota; including Attachment 2 Distributed Generation Interconnection Requirements established in the Commission's September 28, 2004 Order in E-999/CI-01-1023) until superseded and upon Commission approval of updated Minnesota DER Technical Interconnection and Interoperability Requirements in E-999/CI-16- 521 (anticipated July 2019.) Nameplate Rating — nominal voltage (V), current (A), maximum active power (kWac), apparent power (WA), and reactive power (kVar) at which a DER is capable of sustained operation. For a Local EPS with multiple DER units, the aggregate nameplate rating is equal to the sum of all " A Material Modification shall include, but may not be limited to, a modification from the approved Interconnection Application that: (1) changes the physical location of the point of common coupling; such that it is likely to have an impact on technical review; (2) increases the nameplate rating or output characteristics of the Distributed Energy Resource; (3) changes or replaces generating equipment, such as generator(s), inverter(s), transformers, relaying, controls, etc., and substitutes equipment that is not like -kind substitution in certification, size, ratings, impedances, efficiencies or capabilities of the equipment; (4) changes transformer connection(s) or grounding; and/or (5) changes to a certified inverter with different specifications or different inverter control settings or configuration. A Material Modification shall not include a modification from the approved Interconnection Application that: (1) changes the ownership of a Distributed Energy Resource; (2) changes the address of the Distributed Energy Resource, so long as the physical point of common coupling remains the same; (3) changes or replaces generating equipment such as generator(s), inverter(s), solar panel(s), transformers, relaying, controls, etc. and substitutes equipment that is a like -kind substitution in certification, size, ratings, impedances, efficiencies or capabilities of the equipment; and/or (4) increases the DC/AC ratio but does not increase the maximum AC output capability of the Distributed Energy Resource in a way that is likely to have an impact on technical review. DERs nameplate rating in the Local EPS. For purposes of the Attachment V in the Interconnection Agreement, the DER system's capacity may, with the Area EPS's agreement, be limited thought use of control systems, power relays or similar device settings or adjustments as identified in IEEE 1547. The nameplate ratings referenced in the Interconnection Process are alternating current nameplate DER ratings at the Point of DER Coupling. Network Upgrades — Additions, modifications, and upgrades to the Transmission System required at or beyond the point at which the DER interconnects with the Area EPS Operator's System to accommodate the interconnection with the DER to the Area EPS Operator's System. Network Upgrades do not include Distribution Upgrades. Operating Requirements — Any operating and technical requirements that may be applicable due to the Transmission Provider's technical requirements or Minnesota Technical Requirements, including those set forth in the Interconnection Agreement. Party or Parties —The Area EPS Operator and the Interconnection Customer. Point of Common Coupling (PCC) —The point where the Interconnection Facilities connect with the Area EPS Operator's Distribution System. See figure 1. Equivalent, in most cases, to "service point" as specified by the Area EPS Operator and described in the National Electrical Code and the National Electrical Safety Code. Pal nt of IDLER. soonnaction J p0c) I. aIl EPS 2 .Area Electric Power System (Arco EPS) l;cacaEPS 4 ........... Figure 1: Point of Common Coupling and Point of DER Connection (Source: IEEE 1547) Point of DER Connection (PoC) — When identified as the Reference Point of Applicability, the point where an individual DER is electrically connected in a Local EPS and meets the requirements of this standard exclusive of any load present in the respective part of the Local EPS (e.g. terminals of the inverter when no supplemental DER device is required.) For DER unit(s) that are not self-sufficient to meet the requirements without a supplemental DER device(s), the Point of DER Connection is the point where the requirements of this standard are met by DER in conjunction with a supplemental DER device(s) exclusive of any load present in the respective part of the Local EPS. Queue Position —The order of a valid Interconnection Application, relative to all other pending valid Interconnection Applications, that is established based upon the date- and time- of receipt of the complete Interconnection Application as described in Section 4.7. Reasonable Efforts — With respect to an action required to be attempted or taken by a Party under these procedures, efforts that are timely and consistent with Good Utility Practice and are otherwise substantially equivalent to those a Party would use to protect its own interests. Reference Point of Applicability — The location, either the Point of Common Coupling or the Point of DER Connection, where the interconnection and interoperability performance requirements specified in IEEE 1547 apply. With mutual agreement, the Area EPS Operator and Customer may determine a point between the Point of Common Coupling and Point of DER Connection. See Minnesota Technical Requirements for more information. Simplified Process —The procedure for evaluating an Interconnection Application for a certified inverter -based DER no larger than 20 kW that uses the screens described in the Interconnection Process — Simplified Process document. The Simplified Process includes simplified procedures. Study Process —The procedure for evaluating an Interconnection Application that includes the scoping meeting, system impact study, and facilities study. Transmission Owner — The entity that owns, leases or otherwise possesses an interest in the portion of the Transmission System relevant to the Interconnection. Transmission Provider —The entity (or its designated agent) that owns, leases, controls, or operates transmission facilities used for the transmission of electricity. The term Transmission Provider includes the Transmission Owner when the Transmission Owner is separate from the Transmission Provider. The Transmission Provider may include the Independent System Operator or Regional Transmission Operator. Transmission System — The facilities owned, leased, controlled or operated by the Transmission Provider or the Transmission Owner that are used to provide transmission service. See the A&nicipal A4I .... Process Overview.....lan:. ary 2019 23 Commission's July 26, 2000 Order Adopting Boundary Guidelines for Distinguishing Transmission from Generation and Distribution Assets in Docket No. E-999/CI-99-1261. Uniform Contract — the Area EPS Operator's Agreement for Cogeneration and Small Power Production Facilities (Uniform Contract) that may be applied to all qualifying new and existing interconnections between the Area EPS Operator and an DER system having capacity less than 40 kilowatts. Upgrades — The required additions and modifications to the Area EPS Operator's Transmission or Distribution System at or beyond the Point of Interconnection. Upgrades may be Network Upgrades or Distribution Upgrades. Upgrades do not include Interconnection Facilities. 14 Certification of DER Equipment Distributed Energy Resource (DER) equipment proposed for use in an interconnection system shall be considered certified for interconnected operation if the following criteria is met: 1) It has been tested in accordance with industry standards for continuous utility interactive operation in compliance with the appropriate codes and standards referenced below by any Nationally Recognized Testing Laboratory (NRTL) recognized by the United States Occupational Safety and Health Administration to test and certify interconnection equipment pursuant to the relevant codes and standards listed in the Overview Process, 2) It has been labeled and is publicly listed by such NRTL at the time of the interconnection application and, 3) Such NRTL makes readily available for verification all test standards and procedures it utilized in performing such equipment certification, and, with consumer approval, the test data itself. The NRTL may make such information available on its website and by encouraging such information to be included in the manufacturer's literature accompanying the equipment. The Interconnection Customer must verify that the assembly and use of the equipment falls within the use or uses for which the equipment was tested, labeled, and listed by the NRTL. Certified equipment shall not require further type -test review, testing, or additional equipment to meet the requirements of this interconnection procedure; however, nothing herein shall preclude the need for a DER Design Evaluation or an on -site commissioning test by the parties to the interconnection as provided for in the Minnesota Technical Requirements. If the certified equipment package includes only interface components (switchgear, inverters, or other interface devices), then an Interconnection Customer must show that the generator or other electric source being utilized with the equipment package is compatible with the equipment package and is consistent with the testing and listing specified for this type of interconnection equipment. Provided the generator or electric source, when combined with the equipment package, is within the range of capabilities for which it was tested by the NRTL, and does not violate the interface components' labeling and listing performed by the NRTL, no further type -test review, testing or additional equipment on the customer side of the Point of Common Coupling shall be required to be considered certified for the purposes of this interconnection procedure; however, nothing herein shall preclude the need for a DER Design Evaluation or an on -site commissioning test by the parties to the interconnection as provided for in the Minnesota Technical Requirements. An equipment package does not include equipment provided by the Area EPS. 15 Certification Codes and Standards The existing Minnesota Technical Requirements and the following standards shall be used in conjunction with the Interconnection Process. The process has started to update the Technical Requirements to meet IEEE 1547-2018. Once that process is completed, the updated DER Technical Interconnection and Interoperability Requirements will supersede this section. When the stated version of the following standards is superseded by an approved revision then that revision shall apply: IEEE 1547-2003 IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems IEEE 1547a-2014 IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems — Amendment 1 IEEE 1547.1-2005 IEEE Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems IEEE 1547.1a-2015 (Amendment to IEEE Std 1547.1-2005) IEEE Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems — Amendment 1 UL 1741 Inverters, Converters, Controllers, and Interconnection System Equipment for Use in Distributed Energy Resources (2010) NFPA 70 (2017), National Electrical Code IEEE Std C37.90.1 (2012) (Revision of IEEE Std C37.90.1-2002), IEEE Standard for Surge Withstand Capability (SWC) Tests for Protective Relays and Relay Systems Associated with Electric Power Apparatus IEEE Std C37.90.2 (2004) (Revision of IEEE Std C37.90.2-1995), IEEE Standard for Withstand Capability of Relay Systems to Radiated Electromagnetic Interference from Transceivers IEEE Std C37.108-20021989 (Revision of C37.108-19892002), IEEE Guide for the Protection of Network Transformers IEEE Std C57.12.44-2014 (Revision of IEEE Std C57.12.44-2005), IEEE Standard Requirements for Secondary Network Protectors IEEE Std C62.41.2-2002, IEEE Recommended Practice on Characterization of Surges in Low -Voltage (1000 V and Less) AC Power Circuits IEEE Std C62.41.2-2002_Cor 1-2012 (Corrigendum to IEEE Std C62.41.2-2002) — IEEE Recommended Practice on Characterization of Surges in Low -Voltage (1000 V and Less) AC Power Circuits Corrigendum 1: Deletion of Table A.2 and Associated Text IEEE Std C62.45-2002 (Revision of IEEE Std C62.45-1992) — IEEE Recommended Practice on Surge Testing for Equipment Connected to Low -Voltage (1000 V and less) AC Power Circuits ANSI C84.1-(2016) Electric Power Systems and Equipment — Voltage Ratings (60 Hertz) IEEE Standards Dictionary Online, [Online] NEMA MG 1-2016, Motors and Generators IEEE Std 519-2014, IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems HUTCHINSON UTILITIES COMMISSION��` Board Action Form rMturit mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm Agenda Item: Approval of Asset Management Agreements Presenter: John Webster Agenda Item Type: Time Requested (Minutes): 3 New Business Attachments; Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: Hutchinson Utilities currently holds two natural gas transportation contracts with Northern Natural Gas company. Contract 21279 is for 100 dth's/day and contract 102733 is for 50 Dth's/day. Hutchinson Utilities maintains this capacity on the NNG pipeline system in the event of a catastrophic failure on the Hutchinson natural gas pipeline. The annual expense for maintaining both contracts in place is $16,688.14. Hutchinson Utilities is proposing to release this capacity to CenterPoint Energy Services from beginning May 1, 2019 for one year. Hutchinson Utilities will maintain immediate recall rights. In the event of an emergency on the Hutchinson Pipeline, CenterPoint Energy Services is under obligation to deliver quantities of gas to Hutchinson's delivery point on NNG up to the maximum daily quantity of the applicable capacity for the term of the delivery period. CenterPoint Energy Services will pay Hutchison Utilities $8,220.00 for the annual release of the NNG capacity. BOARD ACTION REQUESTED: Approval of Asset Management Agreements Fiscal Impact: $8,220.00 Included in current budget:' No Budget Change: No PROJECT SECTION:' Total Project Cost: Remaining Cost; Ah CenterPoint. W -Energy Natural Gas Asset ManagementAgreement April 9, 2019 Mr. John Webster Hutchinson Utilities Commission 225 Michigan Street SE Hutchinson, MN 55350 Thank you for allowing CenterPoint Energy Services (CES) the opportunity to provide an Asset Management Agreement (AMA) proposal for Hutchinson Utilities' consideration. CES has extensive experience supplying natural gas and related services to utilities and municipalities throughout our nearly 40-state footprint across 60-plus pipelines. With respect to Northern Natural Pipeline, CES manages 65,000 MMBtus per day of capacity during the winter and 40,000 MMBtus per day during the summer. CES is a market share leader in providing natural gas supply services to public gas systems throughout the U.S. and we hope Hutchinson Utilities will considerjoining us in partnership. The enclosed package is a brief outline of our services and capabilities including our pricing structure and proposal for asset management services. Please let me know if you have any questions or need clarifications. Best regards, zeadd4 f Fwawa The information in this document is privileged & confidential. It is intended solely for the use of authorized recipients. If you are not the intended recipient, or the intended recipient's agent, you are prohibited from reading, using, disseminating, distributing and/or copying this document. I I1'1ag Ah CerllerPoint. -Energy Proposed Services CenterPoint Energy Services (CES) would like to offer Hutchinson Utilities Commission an Asset Management Agreement for a one-year term beginning May 1, 2019. CES intends to take release of Hutchinson Utilities Commission's Northern Natural Gas (NNG) transportation capacity under a qualified AMA conforming to FERC's definition of an asset management arrangement, pursuant to FERC Order 712. In turn, CES will pay the NNG pipeline invoices and pass -through monthly reservation charges in addition to a capacity credit outlined below. Delivery Point: Zone E/F- Hutchinson Utilities (Hutchinson MN #1 & #2) Asset Optimization Payment: In consideration of Hutchinson Utilities Commission's release of the NNG TFX and TF contracts 102733 and 21279, CES will pay Hutchinson Utilities Commission an asset optimization credit of $685 per month. CES's right to utilize the released transportation capacity will be expressly subordinate to Hutchinson Utilities Commission's right to call upon CES to deliver quantities of gas to Hutchinson's delivery point on NNG up to the maximum daily quantity of the applicable capacity for the term of the delivery period. Valuation of these assets was made under the assumption that the NNG contracts stated above will not be utilized by Hutchinson Utilities Commission. If Hutchinson does recall the capacity a prorated calculation will determine any applicable reduction in asset optimization credit to be applied. Alternatively, deliveries can be made into the delivery points stated above. CES will have the right to deliver quantities to Hutchinson Utilities Commission utilizing transportation and/or storage service other than the managed capacity on the conditions that there will be no reduction in service, quantity or reliability to Hutchinson Utilities Commission. If such quantities are requested, pricing of such quantities will be based on current market conditions and will be agreed upon by both parties. CES also acknowledges that it will be responsible for any penalties or incremental costs (up to Hutchinson's NNG contracts MDQ) associated with non-compliance with any rule, regulation, tariff provision of any Federal, State or local governing entity. No adjustment will be made to the monthly asset optimization credit if deliveries are requested. Dedicated Account Management: Lindsay Brown — Manager of Origination Additional Account Management Staff: • Tom Sax — Director, Gas Supply & Transportation • Jimmy White — Gas Trader • Zac Littrell — Director of Origination • Dale Wateland — Manager, Volume Administration & Scheduling The information in this document is privileged & confidential. It is intended solely for the use of authorized recipients. If you are not the intended recipient, or the intended recipient's agent, you are prohibited from reading, using, disseminating, distributing and/or copying this document. 21Page Executive Summary Background of Operations CenterPoint Energy Services is the nation's 10th largest energy services company supplying over 1 trillion cubic feet of natural gas to customers in 40 states. CenterPoint Energy Services is a full -service natural gas marketing company providing supply and asset management services to utilities, industrial and commercial facilities, power plants, and gas producers. Ah CenterPoint. -Energy No K� INY M1M ,,... ,. V✓Y PA IA NJ NE off MID DE NV n V CO It / VA KS MQ KY CA NC TN oK P- SC � NM AGA LTX Il'l I - ii, uiII NI t as i aD t b t �� CenterPoint Energy Services is ElectricT�ns &Dl�bulti°° d NI Kral G D t bution committed to providing °°°1°P°°°rGeneration p g c°rnPar,yHa HQ exceptional customer service. We "Compat�e,E;,ergyBUSIna��'B0 e are consistently recognized as an industry leader in customer satisfaction. Meeting our customer's needs for reliability and flexibility is the most important priority of our organization. From our sales and customer service, accounting, scheduling, and trading teams, each department is dedicated to superior customer service. Services Provided CenterPoint Energy Services offers an array of natural gas supply and asset management services to all types of natural gas users — large and small. We have the resources and management systems necessary to deliver unparalleled reliability, flexibility and cost efficiency, with the goal of helping our customers gain competitive advantages. LIST OF SERVICES • Gas Supply Acquisition and Aggregation • Transportation and Storage Management o Nominations o Scheduling o Balancing • Pipeline Contract Negotiations and Strategies • Storage Optimization and Delivered Services • Invoice Review and Verification • 24-hour Operations Support • Pricing / Risk Management With Competitive Pricing Options • Online energy portal CenterPoint Energy Services takes the guesswork out of managing our customer's gas demand requirements. We offer load forecasting based on statistical analysis, historical consumption, and The information in this document is privileged & confidential. It is intended solely for the use of authorized recipients. If you are not the intended recipient, or the intended recipient's agent, you are prohibited from reading, using, disseminating, distributing and/or copying this document. 3111a go Ah CenterPoint. -Energy operational changes. We monitor gas usage on an hourly, daily, or monthly basis while tracking imbalances with 24/7 information access. CenterPoint Energy, headquartered in Houston, is financially strong with more than $29 billion in assets and 14,000 employees. The current credit rating for CenterPoint Energy from Standard & Poor's is A - and Baal from Moody's. Why choose CenterPoint Energy Services? Centerpoint Energy Services recently received the top award from Mastio Quality in 2018. The achievement is awarded to the top natural gas suppliers based on reliability, customer services, account management, exceeding industry benchmarks, and overall customer CERTIFIED satisfaction. CES provides a rewarding relationship experience. Whether you're a customer or just have a question about our products and services, CES "''the Industry is an industry recognized leader in customer service and satisfaction. In addition to regional expertise, CES maintains strong working and MASTIO & COMPANY personal relationships with our municipal and LDC customers. We serve over 140 municipal systems and LDCs. Many of these Muni/LDC systems have been customers for over 30 years which serves as a strong confirmation of our expertise in providing AMA services. Additionally, CES employees are active in state and federal associations dedicated to serving the needs of municipal and utility systems, including the American Public Gas Association, American Gas Association and Southern Gas Association. Our financial desk offers various pricing options including monthly market variable or fixed index or NYMEX pricing, as well as structured products including call/put options or caps/collar options. In addition, our team provides asset management including storage management, firm and interruptible transportation administration and capacity release management. Other services provided by CES include mobile energy solutions, pipeline construction and infrastructure projects and green services. Exhibits The following are sample documents for your review: ✓ NAESB Base Agreement and Special Provisions ✓ AMA sample agreement The information in this document is privileged & confidential. It is intended solely for the use of authorized recipients. If you are not the intended recipient, or the intended recipient's agent, you are prohibited from reading, using, disseminating, distributing and/or copying this document. 411:1a g e ASSET MANAGEMENT ADDENDUM This Asset Management Addendum (the "Addendum") is attached to and made a part of that certain Transaction Confirmation ("Confirmation") entered into effective as of April 8, 2019 by and between CenterPoint Energy Services, Inc. ("Seller") and Hutchinson Utilities Commission (`Buyer"). Seller and Buyer are referred to hereinafter individually as a "party" and collectively as the "parties". The Confirmation and this Addendum are collectively referred to as the "AMA Transaction". ARTICLE I. DEFINITIONS AND INTERPRETATION 1.1 Definitions. The following terms when used herein shall have the meanings set forth below: "Commodity Charges" means all commodity charges, ACA surcharges, GRI surcharges and other tariff charges assessed by a Pipeline pursuant to the approved tariff or governing documents of such Pipeline as a result of the actual transportation of Gas. "Demand Charges" means any and all demand/reservation charges assessed by a Pipeline pursuant to the approved tariff of such Pipeline. "FERC" means the Federal Energy Regulatory Commission or any successor governmental agency. "Fuel" means the quantity of Gas consumed by a Pipeline in transporting Gas and includes any provision by such Pipeline for lost and unaccounted for Gas, as determined in accordance with the approved tariff or governing documents of such Pipeline. " Pi eline s " means any pipeline(s) on which Seller has acquired the Released Capacity from the Buyer under the terms of this Addendum. "Receipt Point(s)" means the primary receipt point(s) designated in the Transportation Agreements where Seller receives Gas for transport on the Released Capacity to the Delivery Point(s). "Released Capacity" means the capacity on the applicable Pipeline that has been released from the Buyer to Seller under the terms of this Addendum. "Transportation Agreement(s)" means those agreements for transportation services as listed on the chart set forth in Section 3.3 below with respect to the Released Capacity. 1.2 Unless otherwise defined, capitalized terms used herein shall have the meaning given in the Confirmation or Base Contract, as applicable. ARTICLE II. TERM The Addendum shall be effective for the Delivery Period (the "Term") unless (i) terminated as a result of an Event of Default under the Base Contract (inclusive of the additional Events of Default in Section 6.1 hereof), (ii) the parties otherwise mutually agree in writing to terminate, or (iii) terminated due to governmental requirements. To the extent that any of the foregoing in (i)-(iii) occur, the Term shall end on the date the event in (i)-(iii) occurs. Each party's obligations regarding payment and indemnification arising hereunder shall survive the termination hereof for a period of time equal to the time for which the applicable statute of limitations applies to this Addendum. ARTICLE III. CAPACITY RELEASE 3.1 Intent of Parties. It is the intention of the parties that this AMA Transaction, together with the applicable provisions, if any, of the Pipeline's FERC-approved tariff, as may be amended from time to time, contains all of the terms and conditions governing the Buyer's release of the Released Capacity to Seller. 3.2 Capacity Release. Buyer will release the Released Capacity for the Delivery Period in accordance with the terms and conditions hereof. Buyer will retain the benefits of any retroactive rate adjustments by the Pipeline(s) affecting the Released Capacity. The parties shall execute any further documents required to effect the release of the Released Capacity in accordance with this Addendum. 3.3 Release Terms. The following constitutes the Released Capacity to be released by Buyer to Seller: See Schedule 1 attached hereto and incorporated herein. The parties agree that the Buyer shall remain liable to the Pipeline for any and all Demand Charges related to the Released Capacity. 3.4 Contract with the Piueline(s). Seller shall execute a transportation agreement for the Released Capacity with the Pipeline(s) in order to satisfy the Pipeline(s)'s requirements, in addition to taking any and all other actions required by the Pipeline(s) as a condition to taking the Released Capacity. If Seller is unable to execute the transportation agreement with the Pipeline(s), the AMA Transaction shall terminate with no further performance obligation or damages (save and except for payments due and owing as a result of past performance) being owed by either party. 3.5 Receipt and Delivery Points. The Pipeline(s)'s tariff may permit Seller to change primary receipt and delivery points under the transportation agreements that Seller executes with the Pipeline. Notwithstanding any tariff provisions permitting such a change, Seller shall not change primary receipt or delivery points under such transportation agreements without the prior written consent of the Buyer. 3.6 Other Terms. Buyer shall release the Released Capacity to Seller in accordance with the capacity release regulations of FERC and the tariff requirements of the applicable Pipeline. Such releases shall be in the form of non -biddable, pre -arranged releases that conform to the FERC's capacity release regulations in all respects. The release will be posted by Buyer as a zero demand rate release or, if the Pipeline's electronic bulletin board will not accept a zero value, then the smallest value that will be accepted. If the release cannot be posted as a zero demand rate release, Buyer shall reimburse Seller for any Demand Charges that Seller pays to the relevant Pipeline with respect to the Released Capacity. The term of the releases shall be for the Delivery Period. Buyer and Seller acknowledge and agree that (i) the releases are being made pursuant to the asset management arrangements described herein and that such arrangements qualify as "asset management arrangements" pursuant to 18 CFR §284.8 and FERC Order 712 and (ii) both Buyer's and Seller's obligation to perform hereunder shall not commence until Seller has received the releases and all other documentation necessary to fulfill its obligations hereunder; provided that the Confirmation will be deemed effective upon execution by both parties, and Buyer and Seller acknowledge that each party may engage in financial hedging transactions associated with Gas to be supplied under such Confirmation following such effective date, prior to the receipt of such releases. All such capacity releases hereunder shall be subject to recall by Buyer. Buyer shall not terminate or materially modify or amend any of the transportation agreements without prior consultation with Seller. In the event any such modification or termination results in diminished rights to deliver or store Gas, the parties shall negotiate appropriate and comparable adjustments, if any, to the pricing and/or other terms hereof. With respect to the services to be performed by Seller hereunder and the amounts to be paid by Buyer to Seller for such services, Seller has the option, at its sole but reasonable discretion, to utilize alternate capacity to make deliveries to Buyer, but has no right to pass through to Buyer any resulting costs nor any obligation to pass through to Buyer any incremental savings except as referenced herein. Seller further agrees to hold Buyer harmless if any costs are incurred as a result of Seller's utilization of alternate capacity as referenced in this paragraph. ARTICLE IV. PERFORMANCE OBLIGATIONS 4.1 Sunnly of Information. Buyer shall timely provide information to Seller to facilitate Seller's nomination and scheduling of Gas for delivery at the Delivery Point(s), and to reasonably ensure that Imbalance Charges will not occur. If Buyer fails to provide such information to Seller, Buyer shall be responsible for any and all Imbalance Charges that are incurred by Seller as a result. 4.2 Seller Delivery Obligation. Subject to the terms of the AMA Transaction and the Base Contract, on any Day during the Term, Seller will deliver to the Buyer a volume of Gas equal to the Buyer's Gas requirements up to the MDQ of the Released Capacity. 4.3 Timely Instructions. The timeliness of the information provided by the Buyer for purposes of Section 4.1 shall be determined by ascertaining whether Seller was given a commercially reasonable amount of time from Seller's receipt of the relevant information prior to the nominating and scheduling deadlines established by the applicable Pipeline, unless express deadlines are otherwise set forth in the Confirmation or herein. ARTICLE V. CONSIDERATION The parties agree that good and adequate consideration has been included in the economic terms of the AMA Transaction and, accordingly, no other direct consideration is owed by the parties under the terms hereof. ARTICLE VI. DEFAULT AND REMEDIES 6.1 Events of Default. The following actions or inactions by a party hereunder shall constitute an Event of Default under the AMA Transaction, which shall be in addition to those Events of Default contained in the Base Contract: (a) breach of any material obligation under this Addendum, if such breach is not cured by the Defaulting party within five (5) Business Days after written notice of such breach from the Non -defaulting party; or (b) except with respect to actions taken as permitted by FERC's capacity release rules, 18 CFR § 284.8, either party takes or fails to take any action required by the Pipeline(s) or hereunder related to the Released Capacity which results in Seller's inability, in whole or in part, to utilize the Released Capacity on any Day or Buyer's inability, in whole or in part, to receive Gas at the Delivery Point(s) on any Day up to Seller's Delivery Obligation under Section 4.2. 6.2 Remedies. If an Event of Default has occurred and is continuing, the Non -Defaulting party may exercise any and all rights and remedies afforded to it under the Base Contract. Upon any termination hereof, the Released Capacity shall be automatically recalled. ARTICLE VIL MISCELLANEOUS 7.1 Further Assurances. The parties agree to execute and deliver such additional instruments or documents as may be necessary to carry out the purposes hereof. 7.2 Miscellaneous. This Addendum may be executed in multiple counterparts, each of which shall constitute an original and all of which together shall constitute one and the same instrument. The headings and subheadings contained herein are used solely for convenience and do not constitute a part hereof and shall not be used to construe or interpret the provisions hereof. 7.3 Authority to Execute. Each of the parties represents and warrants that (i) it has full and complete authority to enter into and perform this AMA Transaction, (ii) the person who executes this AMA Transaction on its behalf has full and complete authority to do so and is empowered to bind it thereby, and (iii) it is not insolvent and has not sought protection from creditors under the United States Bankruptcy Code or under any similar laws. 7.4 Entirety and Amendments. This AMA Transaction constitutes the entire agreement between the parties regarding the subject matter hereof, and supersedes and replaces any prior and contemporaneous communications, understandings and agreements between the parties related to such subject matter, whether written or verbal, express or implied. No modification, amendment, supplementation or alteration of the terms and provisions hereof shall be or become effective except by written amendment executed by the duly authorized representative of the parties. Except as set forth herein, the Base Contract shall remain unchanged. SELLER: Initials BUYER: Initials Schedule 1 Released Capacity Pipeline Contract # Rate Schedule MDQ Northern Natural 102733 TFX 50 Northern Natural 21279 TF 100 Base Contract for Sale and Purchase of Natural Gas This Base Contract is entered into as of the following date: MaV 1, 2019 The parties to this Base Contract are the following: PARTY A PARTY B PARTY NAME CENTERPOINT ENERGY SERVICES, INC. HUTCHINSON UTILITIES COMMISSION 1111 Louisiana Street, 111h Floor 225 Michigan St SE Houston, TX 77002 ADDRESS Hutchinson, MN 55350 www.centerpointenergy.com BUSINESS www.hutchinsonutilities.com WEBSITE CONTRACT NUMBER 83-8611739 D-U-N-S® 154-439-301 NUMBER 0 US FEDERAL: 72-1309319 0 US FEDERAL: 41-6005251 ❑ OTHER: TAX ID NUMBERS ❑ OTHER: JURISDICTION OF ORGANIZATION 0 Corporation ❑ LLC ❑ Corporation ❑ LLC ❑ Limited Partnership ❑ Partnership COMPANY TYPE ❑ Limited Partnership ❑ Partnership ❑ LLP ❑ Other: ❑ LLP 0 Other: Municipal Utility_ GUARANTOR IF APPLICABLE CONTACT INFORMATION 1111 Louisiana Street, 11th Floor, Houston, TX 77002 Same as above ATTN: Sales & Trading COMMERCIAL ATTN: John Webster TEL#: 713-428-4600 FAX#: 713-393-0263 TEL#: 320-234-0507 FAX#: 320-587-4721 EMAIL: Rob. Ellis center ointener .com Sales EMAIL: iwebster&ci.hutchinson.mn.us 1111 Louisiana Street, 11th Floor, Houston, TX 77002 Same as above ATTN: Gas Scheduling ATTN: John Webster SCHEDULING TEL#: 713-428-4600 FAX#: 713-393-0263 TEL#: 320-234-0507 FAX#: 320-587-4721 EMAIL: Derek. Husser(a7centerp2inte2ergy.com EMAIL: iwebster ci.hutchinson.mn.us 1111 Louisiana Street, 11th Floor, Houston, TX 77002 Same as above ATTN: John Webster ATTN: Contract Administration CONTRACT AND LEGAL NOTICES TEL#: 713-428-4600 FAX#: 713-393-0263 TEL#: 320-234-0507 FAX#: 320-587-4721 EMAIL: CESConfirm(a7centerpointenergLcom EMAIL: iwebster ci.hutchinson.mn.us 1111 Louisiana Street, 10th Floor, Houston, TX 77002 CREDIT Same as above ATTN: Credit Department ATTN: Jared Martiq TEL#: 713-207-3830 FAX#: 713-207-9233 TEL#: 320-234-0512 FAX#: 320-587-4721 EMAIL: CNPCorporateCredit(o7CenterpointEnergy. com EMAIL: imarti ci.hutchinson.mn.us 1111 Louisiana Street, 11th Floor, Houston, TX 77002 Same as above ATTN: John Webster ATTN: Contract Administration TRANSACTION TEL#: 713-428-4600 FAX#: 713-393-0263 CONFIRMATIONS TEL#: 320-234-0507 FAX#: 320-587-4721 EMAIL: CESConfirm(a7centerpointenergy.com EMAIL: iwebster ci.hutchinson.mn.us ACCOUNTING INFORMATION 1111 Louisiana Street, 10th Floor, Houston, TX 77002 Same as above ATTN: Gas Accounting •INVOICES ATTN: Jennifer Hoffman • PAYMENTS TEL#: 713-428-4600 TEL#: 320-234-0569 FAX#: 320-587-4721 'SETTLEMENTS EMAIL: CESAPInvoices(a)centerpointenergy.com EMAIL: ihoffman ci.hutchinson.mn.us BANK: JPMorgan Chase Bank, N.A BANK: Citizens Bank & Trust Co ABA: 021000021 ACCT: 00103275666 WIRE TRANSFER ABA: 091901862 ACCT: 000086 (IF APPLICABLE) BANK: JPMorgan Chase Bank, N. BANK: ACH ABA: ACCT: ABA: 111000614 ACCT: 00103275666 (IF APPLICABLE) ATTN: CenterPoint Energy Services, Inc. CHECK P. O. Box 733609, Dallas, TX 75373-3609 (IF APPLICABLE) Lockbox No. 733609 Copyright © 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved September 5, 2006 Base Contract for Sale and Purchase of Natural Gas (Continued) This Base Contract incorporates by reference for all purposes the General Terms and Conditions for Sale and Purchase of Natural Gas published by the North American Energy Standards Board. The parties hereby agree to the following provisions offered in said General Terms and Conditions. In the event the parties fail to check a box, the specified default provision shall apply. Select the appropriate box(es) from each section: Section 1.2 ® Oral (default) Section 10.2 ® No Additional Events of Default (default) Transaction OR Additional Procedure ❑ Written Events of Default ❑ Indebtedness Cross Default ❑ Party A: Section 2.7 ® 2 Business Days after receipt (default) Confirm Deadline OR ❑ Party B: ❑ Business Days after receipt ❑ Transactional Cross Default Specified Transactions: Section 2.8 ® Seller (default) Confirming Party OR ❑ [7 Buyer Section 3.2 ® Cover Standard (default) Section 10.3.1 ® Early Termination Damages Apply (default) Performance OR Early Obligation I I Spot Price Standard Termination OR Damages ❑ Early Termination Damages Do Not Apply Note: The following Spot Price Publication applies to both of the immediately preceding. Section 10.3.2 Other ® Other Agreement Setoffs Apply (default) Section 2.31 ® Gas Daily Midpoint (default) Agreement ® Bilateral (default) Spot Price OR Setoffs Publication ❑ Triangular OR ❑ Other Agreement Setoffs Do Not Apply Section 6 ® Buyer Pays At and After Delivery Point (default) Taxes OR Seller Pays Before and At Delivery Point Section 7.2 ® 25" Day of Month following Month of delivery Section 15.5 Texas Payment Date (default) Choice Of Law OR ❑ Day of Month following Month of deliver Section 7.2 ® Wire transfer (default) Section 15.10 ® Confidentiality applies (default) Method of Payment I Automated Clearinghouse Credit (ACH) Confidentiality OR ❑ Check ❑ Confidentiality does not apply Section 7.7 ® Netting applies (default) Netting OR ❑ Netting does not apply ® Special Provisions Number of sheets attached: 3 ❑ Addendum(s): IN WITNESS WHEREOF, the parties hereto have executed this Base Contract in duplicate. CENTERPOINT ENERGY SERVICES, INC. PARTY NAME HUTCHINSON UTILITIES COMMISSION B: SIGNATURE B: PRINTED NAME TITLE Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 2 of 13 September 5, 2006 General Terms and Conditions Base Contract for Sale and Purchase of Natural Gas SECTION 1. PURPOSE AND PROCEDURES 1.1. These General Terms and Conditions are intended to facilitate purchase and sale transactions of Gas on a Firm or Interruptible basis. "Buyer" refers to the party receiving Gas and "Seller" refers to the party delivering Gas. The entire agreement between the parties shall be the Contract as defined in Section 2.9. The parties have selected either the "Oral Transaction Procedure" or the "Written Transaction Procedure" as indicated on the Base Contract. Oral Transaction Procedure: 1.2. The parties will use the following Transaction Confirmation procedure. Any Gas purchase and sale transaction may be effectuated in an EDI transmission or telephone conversation with the offer and acceptance constituting the agreement of the parties. The parties shall be legally bound from the time they so agree to transaction terms and may each rely thereon. Any such transaction shall be considered a "writing" and to have been "signed". Notwithstanding the foregoing sentence, the parties agree that Confirming Party shall, and the other party may, confirm a telephonic transaction by sending the other party a Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means within three Business Days of a transaction covered by this Section 1.2 (Oral Transaction Procedure) provided that the failure to send a Transaction Confirmation shall not invalidate the oral agreement of the parties. Confirming Party adopts its confirming letterhead, or the like, as its signature on any Transaction Confirmation as the identification and authentication of Confirming Party. If the Transaction Confirmation contains any provisions other than those relating to the commercial terms of the transaction (i.e., price, quantity, performance obligation, delivery point, period of delivery and/or transportation conditions), which modify or supplement the Base Contract or General Terms and Conditions of this Contract (e.g., arbitration or additional representations and warranties), such provisions shall not be deemed to be accepted pursuant to Section 1.3 but must be expressly agreed to by both parties; provided that the foregoing shall not invalidate any transaction agreed to by the parties. Written Transaction Procedure: 1.2. The parties will use the following Transaction Confirmation procedure. Should the parties come to an agreement regarding a Gas purchase and sale transaction for a particular Delivery Period, the Confirming Party shall, and the other party may, record that agreement on a Transaction Confirmation and communicate such Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means, to the other party by the close of the Business Day following the date of agreement. The parties acknowledge that their agreement will not be binding until the exchange of nonconflicting Transaction Confirmations or the passage of the Confirm Deadline without objection from the receiving party, as provided in Section 1.3. 1.3. If a sending party's Transaction Confirmation is materially different from the receiving party's understanding of the agreement referred to in Section 1.2, such receiving party shall notify the sending party via facsimile, EDI or mutually agreeable electronic means by the Confirm Deadline, unless such receiving party has previously sent a Transaction Confirmation to the sending party. The failure of the receiving party to so notify the sending party in writing by the Confirm Deadline constitutes the receiving party's agreement to the terms of the transaction described in the sending party's Transaction Confirmation. If there are any material differences between timely sent Transaction Confirmations governing the same transaction, then neither Transaction Confirmation shall be binding until or unless such differences are resolved including the use of any evidence that clearly resolves the differences in the Transaction Confirmations. In the event of a conflict among the terms of (i) a binding Transaction Confirmation pursuant to Section 1.2, (ii) the oral agreement of the parties which may be evidenced by a recorded conversation, where the parties have selected the Oral Transaction Procedure of the Base Contract, (iii) the Base Contract, and (iv) these General Terms and Conditions, the terms of the documents shall govern in the priority listed in this sentence. 1.4. The parties agree that each party may electronically record all telephone conversations with respect to this Contract between their respective employees, without any special or further notice to the other party. Each party shall obtain any necessary consent of its agents and employees to such recording. Where the parties have selected the Oral Transaction Procedure in Section 1.2 of the Base Contract, the parties agree not to contest the validity or enforceability of telephonic recordings entered into in accordance with the requirements of this Base Contract. SECTION 2. DEFINITIONS The terms set forth below shall have the meaning ascribed to them below. Other terms are also defined elsewhere in the Contract and shall have the meanings ascribed to them herein. 2.1. "Additional Event of Default" shall mean Transactional Cross Default or Indebtedness Cross Default, each as and if selected by the parties pursuant to the Base Contract. 2.2. "Affiliate" shall mean, in relation to any person, any entity controlled, directly or indirectly, by the person, any entity that controls, directly or indirectly, the person or any entity directly or indirectly under common control with the person. For this purpose, "control" of any entity or person means ownership of at least 50 percent of the voting power of the entity or person. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 3 of 13 September 5, 2006 2.3. "Alternative Damages" shall mean such damages, expressed in dollars or dollars per MMBtu, as the parties shall agree upon in the Transaction Confirmation, in the event either Seller or Buyer fails to perform a Firm obligation to deliver Gas in the case of Seller or to receive Gas in the case of Buyer. 2.4. "Base Contract" shall mean a contract executed by the parties that incorporates these General Terms and Conditions by reference; that specifies the agreed selections of provisions contained herein; and that sets forth other information required herein and any Special Provisions and addendum(s) as identified on page one. 2.5. "British thermal unit" or "Btu" shall mean the International BTU, which is also called the Btu (IT). 2.6. "Business Day(s)" shall mean Monday through Friday, excluding Federal Banking Holidays for transactions in the U.S. 2.7. "Confirm Deadline" shall mean 5:00 p.m. in the receiving party's time zone on the second Business Day following the Day a Transaction Confirmation is received or, if applicable, on the Business Day agreed to by the parties in the Base Contract; provided, if the Transaction Confirmation is time stamped after 5:00 p.m. in the receiving party's time zone, it shall be deemed received at the opening of the next Business Day. 2.8. "Confirming Party" shall mean the party designated in the Base Contract to prepare and forward Transaction Confirmations to the other party. 2.9. "Contract" shall mean the legally -binding relationship established by (i) the Base Contract, (ii) any and all binding Transaction Confirmations and (iii) where the parties have selected the Oral Transaction Procedure in Section 1.2 of the Base Contract, any and all transactions that the parties have entered into through an EDI transmission or by telephone, but that have not been confirmed in a binding Transaction Confirmation, all of which shall form a single integrated agreement between the parties. 2.10. "Contract Price" shall mean the amount expressed in U.S. Dollars per MMBtu to be paid by Buyer to Seller for the purchase of Gas as agreed to by the parties in a transaction. 2.11. "Contract Quantity" shall mean the quantity of Gas to be delivered and taken as agreed to by the parties in a transaction. 2.12. "Cover Standard", as referred to in Section 3.2, shall mean that if there is an unexcused failure to take or deliver any quantity of Gas pursuant to this Contract, then the performing party shall use commercially reasonable efforts to (i) if Buyer is the performing party, obtain Gas, (or an alternate fuel if elected by Buyer and replacement Gas is not available), or (ii) if Seller is the performing party, sell Gas, in either case, at a price reasonable for the delivery or production area, as applicable, consistent with: the amount of notice provided by the nonperforming party; the immediacy of the Buyer's Gas consumption needs or Seller's Gas sales requirements, as applicable; the quantities involved; and the anticipated length of failure by the nonperforming party. 2.13. "Credit Support Obligation(s)" shall mean any obligation(s) to provide or establish credit support for, or on behalf of, a party to this Contract such as cash, an irrevocable standby letter of credit, a margin agreement, a prepayment, a security interest in an asset, guaranty, or other good and sufficient security of a continuing nature. 2.14. "Day" shall mean a period of 24 consecutive hours, coextensive with a "day" as defined by the Receiving Transporter in a particular transaction. 2.15. "Delivery Period" shall be the period during which deliveries are to be made as agreed to by the parties in a transaction. 2.16. "Delivery Point(s)" shall mean such point(s) as are agreed to by the parties in a transaction. 2.17. "EDI" shall mean an electronic data interchange pursuant to an agreement entered into by the parties, specifically relating to the communication of Transaction Confirmations under this Contract. 2.18. "EFP" shall mean the purchase, sale or exchange of natural Gas as the "physical" side of an exchange for physical transaction involving gas futures contracts. EFP shall incorporate the meaning and remedies of "Firm", provided that a party's excuse for nonperformance of its obligations to deliver or receive Gas will be governed by the rules of the relevant futures exchange regulated under the Commodity Exchange Act. 2.19. "Firm" shall mean that either party may interrupt its performance without liability only to the extent that such performance is prevented for reasons of Force Majeure; provided, however, that during Force Majeure interruptions, the party invoking Force Majeure may be responsible for any Imbalance Charges as set forth in Section 4.3 related to its interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by the Transporter. 2.20. "Gas" shall mean any mixture of hydrocarbons and noncombustible gases in a gaseous state consisting primarily of methane. 2.21. "Guarantor" shall mean any entity that has provided a guaranty of the obligations of a party hereunder. 2.22. "Imbalance Charges" shall mean any fees, penalties, costs or charges (in cash or in kind) assessed by a Transporter for failure to satisfy the Transporter's balance and/or nomination requirements. 2.23. "Indebtedness Cross Default" shall mean if selected on the Base Contract by the parties with respect to a party, that it or its Guarantor, if any, experiences a default, or similar condition or event however therein defined, under one or more agreements or instruments, individually or collectively, relating to indebtedness (such indebtedness to include any obligation whether present or future, contingent or otherwise, as principal or surety or otherwise) for the payment or repayment of borrowed money in an aggregate amount greater than the threshold specified in the Base Contract with respect to such party or its Guarantor, if any, which results in such indebtedness becoming immediately due and payable. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 4 of 13 September 5, 2006 2.24. "Interruptible" shall mean that either party may interrupt its performance at anytime for any reason, whether or not caused by an event of Force Majeure, with no liability, except such interrupting party may be responsible for any Imbalance Charges as set forth in Section 4.3 related to its interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by Transporter. 2.25. "MMBtu" shall mean one million British thermal units, which is equivalent to one dekatherm. 2.26. "Month" shall mean the period beginning on the first Day of the calendar month and ending immediately prior to the commencement of the first Day of the next calendar month. 2.27. "Payment Date" shall mean a date, as indicated on the Base Contract, on or before which payment is due Seller for Gas received by Buyer in the previous Month. 2.28. "Receiving Transporter" shall mean the Transporter receiving Gas at a Delivery Point, or absent such receiving Transporter, the Transporter delivering Gas at a Delivery Point. 2.29. "Scheduled Gas" shall mean the quantity of Gas confirmed by Transporter(s) for movement, transportation or management. 2.30. "Specified Transaction(s)" shall mean any other transaction or agreement between the parties for the purchase, sale or exchange of physical Gas, and any other transaction or agreement identified as a Specified Transaction under the Base Contract. 2.31. "Spot Price " as referred to in Section 3.2 shall mean the price listed in the publication indicated on the Base Contract, under the listing applicable to the geographic location closest in proximity to the Delivery Point(s) for the relevant Day; provided, if there is no single price published for such location for such Day, but there is published a range of prices, then the Spot Price shall be the average of such high and low prices. If no price or range of prices is published for such Day, then the Spot Price shall be the average of the following: (i) the price (determined as stated above) for the first Day for which a price or range of prices is published that next precedes the relevant Day; and (ii) the price (determined as stated above) for the first Day for which a price or range of prices is published that next follows the relevant Day. 2.32. "Transaction Confirmation" shall mean a document, similar to the form of Exhibit A, setting forth the terms of a transaction formed pursuant to Section 1 for a particular Delivery Period. 2.33. "Transactional Cross Default" shall mean if selected on the Base Contract by the parties with respect to a party, that it shall be in default, however therein defined, under any Specified Transaction. 2.34. "Termination Option" shall mean the option of either party to terminate a transaction in the event that the other party fails to perform a Firm obligation to deliver Gas in the case of Seller or to receive Gas in the case of Buyer for a designated number of days during a period as specified on the applicable Transaction Confirmation. 2.35. "Transporter(s)" shall mean all Gas gathering or pipeline companies, or local distribution companies, acting in the capacity of a transporter, transporting Gas for Seller or Buyer upstream or downstream, respectively, of the Delivery Point pursuant to a particular transaction. SECTION 3. PERFORMANCE OBLIGATION 3.1. Seller agrees to sell and deliver, and Buyer agrees to receive and purchase, the Contract Quantity for a particular transaction in accordance with the terms of the Contract. Sales and purchases will be on a Firm or Interruptible basis, as agreed to by the parties in a transaction. The parties have selected either the "Cover Standard" or the "Spot Price Standard" as indicated on the Base Contract. Cover Standard: 3.2. The sole and exclusive remedy of the parties in the event of a breach of a Firm obligation to deliver or receive Gas shall be recovery of the following: (i) in the event of a breach by Seller on any Day(s), payment by Seller to Buyer in an amount equal to the positive difference, if any, between the purchase price paid by Buyer utilizing the Cover Standard and the Contract Price, adjusted for commercially reasonable differences in transportation costs to or from the Delivery Point(s), multiplied by the difference between the Contract Quantity and the quantity actually delivered by Seller for such Day(s) excluding any quantity for which no replacement is available; or (ii) in the event of a breach by Buyer on any Day(s), payment by Buyer to Seller in the amount equal to the positive difference, if any, between the Contract Price and the price received by Seller utilizing the Cover Standard for the resale of such Gas, adjusted for commercially reasonable differences in transportation costs to or from the Delivery Point(s), multiplied by the difference between the Contract Quantity and the quantity actually taken by Buyer for such Day(s) excluding any quantity for which no sale is available; and (iii) in the event that Buyer has used commercially reasonable efforts to replace the Gas or Seller has used commercially reasonable efforts to sell the Gas to a third party, and no such replacement or sale is available for all or any portion of the Contract Quantity of Gas, then in addition to (i) or (ii) above, as applicable, the sole and exclusive remedy of the performing party with respect to the Gas not replaced or sold shall be an amount equal to any unfavorable difference between the Contract Price and the Spot Price, adjusted for such transportation to the applicable Delivery Point, multiplied by the quantity of such Gas not replaced or sold. Imbalance Charges shall not be recovered under this Section 3.2, but Seller and/or Buyer shall be responsible for Imbalance Charges, if any, as provided in Section 4.3. The amount of such unfavorable difference shall be payable five Business Days after presentation of the performing party's invoice, which shall set forth the basis upon which such amount was calculated. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 5 of 13 September 5, 2006 Snot Price Standard: 3.2. The sole and exclusive remedy of the parties in the event of a breach of a Firm obligation to deliver or receive Gas shall be recovery of the following: (i) in the event of a breach by Seller on any Day(s), payment by Seller to Buyer in an amount equal to the difference between the Contract Quantity and the actual quantity delivered by Seller and received by Buyer for such Day(s), multiplied by the positive difference, if any, obtained by subtracting the Contract Price from the Spot Price; or (ii) in the event of a breach by Buyer on any Day(s), payment by Buyer to Seller in an amount equal to the difference between the Contract Quantity and the actual quantity delivered by Seller and received by Buyer for such Day(s), multiplied by the positive difference, if any, obtained by subtracting the applicable Spot Price from the Contract Price. Imbalance Charges shall not be recovered under this Section 3.2, but Seller and/or Buyer shall be responsible for Imbalance Charges, if any, as provided in Section 4.3. The amount of such unfavorable difference shall be payable five Business Days after presentation of the performing party's invoice, which shall set forth the basis upon which such amount was calculated. 3.3. Notwithstanding Section 3.2, the parties may agree to Alternative Damages in a Transaction Confirmation executed in writing by both parties. 3.4. In addition to Sections 3.2 and 3.3, the parties may provide for a Termination Option in a Transaction Confirmation executed in writing by both parties. The Transaction Confirmation containing the Termination Option will designate the length of nonperformance triggering the Termination Option and the procedures for exercise thereof, how damages for nonperformance will be compensated, and how liquidation costs will be calculated. SECTION 4. TRANSPORTATION, NOMINATIONS, AND IMBALANCES 4.1. Seller shall have the sole responsibility for transporting the Gas to the Delivery Point(s). Buyer shall have the sole responsibility for transporting the Gas from the Delivery Point(s). 4.2. The parties shall coordinate their nomination activities, giving sufficient time to meet the deadlines of the affected Transporter(s). Each party shall give the other party timely prior Notice, sufficient to meet the requirements of all Transporter(s) involved in the transaction, of the quantities of Gas to be delivered and purchased each Day. Should either party become aware that actual deliveries at the Delivery Point(s) are greater or lesser than the Scheduled Gas, such party shall promptly notify the other party. 4.3. The parties shall use commercially reasonable efforts to avoid imposition of any Imbalance Charges. If Buyer or Seller receives an invoice from a Transporter that includes Imbalance Charges, the parties shall determine the validity as well as the cause of such Imbalance Charges. If the Imbalance Charges were incurred as a result of Buyer's receipt of quantities of Gas greater than or less than the Scheduled Gas, then Buyer shall pay for such Imbalance Charges or reimburse Seller for such Imbalance Charges paid by Seller. If the Imbalance Charges were incurred as a result of Seller's delivery of quantities of Gas greater than or less than the Scheduled Gas, then Seller shall pay for such Imbalance Charges or reimburse Buyer for such Imbalance Charges paid by Buyer. SECTION 5. QUALITY AND MEASUREMENT All Gas delivered by Seller shall meet the pressure, quality and heat content requirements of the Receiving Transporter. The unit of quantity measurement for purposes of this Contract shall be one MMBtu dry. Measurement of Gas quantities hereunder shall be in accordance with the established procedures of the Receiving Transporter. SECTION 6. TAXES The parties have selected either "Buyer Pays At and After Delivery Point" or "Seller Pays Before and At Delivery Point" as indicated on the Base Contract. Buyer Pas At and After Delivery Point: Seller shall pay or cause to be paid all taxes, fees, levies, penalties, licenses or charges imposed by any government authority ("Taxes") on or with respect to the Gas prior to the Delivery Point(s). Buyer shall pay or cause to be paid all Taxes on or with respect to the Gas at the Delivery Point(s) and all Taxes after the Delivery Point(s). If a party is required to remit or pay Taxes that are the other party's responsibility hereunder, the party responsible for such Taxes shall promptly reimburse the other party for such Taxes. Any party entitled to an exemption from any such Taxes or charges shall furnish the other party any necessary documentation thereof. Seller Pays Before and At Delivery Point: Seller shall pay or cause to be paid all taxes, fees, levies, penalties, licenses or charges imposed by any government authority ("Taxes") on or with respect to the Gas prior to the Delivery Point(s) and all Taxes at the Delivery Point(s). Buyer shall pay or cause to be paid all Taxes on or with respect to the Gas after the Delivery Point(s). If a party is required to remit or pay Taxes that are the other party's responsibility hereunder, the party responsible for such Taxes shall promptly reimburse the other party for such Taxes. Any party entitled to an exemption from any such Taxes or charges shall furnish the other party any necessary documentation thereof. SECTION 7. BILLING, PAYMENT, AND AUDIT 7.1. Seller shall invoice Buyer for Gas delivered and received in the preceding Month and for any other applicable charges, providing supporting documentation acceptable in industry practice to support the amount charged. If the actual quantity delivered is not known by the billing date, billing will be prepared based on the quantity of Scheduled Gas. The invoiced quantity will then be adjusted to the actual quantity on the following Month's billing or as soon thereafter as actual delivery information is available. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 6 of 13 September 5, 2006 7.2. Buyer shall remit the amount due under Section 7.1 in the manner specified in the Base Contract, in immediately available funds, on or before the later of the Payment Date or 10 Days after receipt of the invoice by Buyer; provided that if the Payment Date is not a Business Day, payment is due on the next Business Day following that date. In the event any payments are due Buyer hereunder, payment to Buyer shall be made in accordance with this Section 7.2. 7.3. In the event payments become due pursuant to Sections 3.2 or 3.3, the performing party may submit an invoice to the nonperforming party for an accelerated payment setting forth the basis upon which the invoiced amount was calculated. Payment from the nonperforming party will be due five Business Days after receipt of invoice. 7.4. If the invoiced party, in good faith, disputes the amount of any such invoice or any part thereof, such invoiced party will pay such amount as it concedes to be correct; provided, however, if the invoiced party disputes the amount due, it must provide supporting documentation acceptable in industry practice to support the amount paid or disputed without undue delay. In the event the parties are unable to resolve such dispute, either party may pursue any remedy available at law or in equity to enforce its rights pursuant to this Section. 7.5. If the invoiced party fails to remit the full amount payable when due, interest on the unpaid portion shall accrue from the date due until the date of payment at a rate equal to the lower of (i) the then -effective prime rate of interest published under "Money Rates" by The Wall Street Journal, plus two percent per annum; or (ii) the maximum applicable lawful interest rate. 7.6. A party shall have the right, at its own expense, upon reasonable Notice and at reasonable times, to examine and audit and to obtain copies of the relevant portion of the books, records, and telephone recordings of the other party only to the extent reasonably necessary to verify the accuracy of any statement, charge, payment, or computation made under the Contract. This right to examine, audit, and to obtain copies shall not be available with respect to proprietary information not directly relevant to transactions under this Contract. All invoices and billings shall be conclusively presumed final and accurate and all associated claims for under- or overpayments shall be deemed waived unless such invoices or billings are objected to in writing, with adequate explanation and/or documentation, within two years after the Month of Gas delivery. All retroactive adjustments under Section 7 shall be paid in full by the party owing payment within 30 Days of Notice and substantiation of such inaccuracy. 7.7. Unless the parties have elected on the Base Contract not to make this Section 7.7 applicable to this Contract, the parties shall net all undisputed amounts due and owing, and/or past due, arising under the Contract such that the party owing the greater amount shall make a single payment of the net amount to the other party in accordance with Section 7; provided that no payment required to be made pursuant to the terms of any Credit Support Obligation or pursuant to Section 7.3 shall be subject to netting under this Section. If the parties have executed a separate netting agreement, the terms and conditions therein shall prevail to the extent inconsistent herewith. SECTION 8. TITLE, WARRANTY, AND INDEMNITY 8.1. Unless otherwise specifically agreed, title to the Gas shall pass from Seller to Buyer at the Delivery Point(s). Seller shall have responsibility for and assume any liability with respect to the Gas prior to its delivery to Buyer at the specified Delivery Point(s). Buyer shall have responsibility for and assume any liability with respect to said Gas after its delivery to Buyer at the Delivery Point(s). 8.2. Seller warrants that it will have the right to convey and will transfer good and merchantable title to all Gas sold hereunder and delivered by it to Buyer, free and clear of all liens, encumbrances, and claims. EXCEPT AS PROVIDED IN THIS SECTION 8.2 AND IN SECTION 15.8, ALL OTHER WARRANTIES, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR OF FITNESS FOR ANY PARTICULAR PURPOSE, ARE DISCLAIMED. 8.3. Seller agrees to indemnify Buyer and save it harmless from all losses, liabilities or claims including reasonable attorneys' fees and costs of court ("Claims"), from any and all persons, arising from or out of claims of title, personal injury (including death) or property damage from said Gas or other charges thereon which attach before title passes to Buyer. Buyer agrees to indemnify Seller and save it harmless from all Claims, from any and all persons, arising from or out of claims regarding payment, personal injury (including death) or property damage from said Gas or other charges thereon which attach after title passes to Buyer. 8.4. The parties agree that the delivery of and the transfer of title to all Gas under this Contract shall take place within the Customs Territory of the United States (as defined in general note 2 of the Harmonized Tariff Schedule of the United States 19 U.S.C. §1202, General Notes, page 3); provided, however, that in the event Seller took title to the Gas outside the Customs Territory of the United States, Seller represents and warrants that it is the importer of record for all Gas entered and delivered into the United States, and shall be responsible for entry and entry summary filings as well as the payment of duties, taxes and fees, if any, and all applicable record keeping requirements. 8.5. Notwithstanding the other provisions of this Section 8, as between Seller and Buyer, Seller will be liable for all Claims to the extent that such arise from the failure of Gas delivered by Seller to meet the quality requirements of Section 5. SECTION 9. NOTICES 9.1. All Transaction Confirmations, invoices, payment instructions, and other communications made pursuant to the Base Contract ("Notices") shall be made to the addresses specified in writing by the respective parties from time to time. 9.2. All Notices required hereunder shall be in writing and may be sent by facsimile or mutually acceptable electronic means, a nationally recognized overnight courier service, first class mail or hand delivered. 9.3. Notice shall be given when received on a Business Day by the addressee. In the absence of proof of the actual receipt date, the following presumptions will apply. Notices sent by facsimile shall be deemed to have been received upon the sending party's receipt of its facsimile machine's confirmation of successful transmission. If the day on which such facsimile is received is not a Business Day or is after five p.m. on a Business Day, then such facsimile shall be deemed to have been received on the next Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 7 of 13 September 5, 2006 following Business Day. Notice by overnight mail or courier shall be deemed to have been received on the next Business Day after it was sent or such earlier time as is confirmed by the receiving party. Notice via first class mail shall be considered delivered five Business Days after mailing. 9.4. The party receiving a commercially acceptable Notice of change in payment instructions or other payment information shall not be obligated to implement such change until ten Business Days after receipt of such Notice. SECTION 10. FINANCIAL RESPONSIBILITY 10.1. If either party ("X") has reasonable grounds for insecurity regarding the performance of any obligation under this Contract (whether or not then due) by the other party ("Y") (including, without limitation, the occurrence of a material change in the creditworthiness of Y or its Guarantor, if applicable), X may demand Adequate Assurance of Performance. "Adequate Assurance of Performance" shall mean sufficient security in the form, amount, for a term, and from an issuer, all as reasonably acceptable to X, including, but not limited to cash, a standby irrevocable letter of credit, a prepayment, a security interest in an asset or guaranty. Y hereby grants to X a continuing first priority security interest in, lien on, and right of setoff against all Adequate Assurance of Performance in the form of cash transferred by Y to X pursuant to this Section 10.1. Upon the return by X to Y of such Adequate Assurance of Performance, the security interest and lien granted hereunder on that Adequate Assurance of Performance shall be released automatically and, to the extent possible, without any further action by either party. 10.2. In the event (each an "Event of Default") either party (the "Defaulting Party") or its Guarantor shall: (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or have such petition filed or proceeding commenced against it; (iii) otherwise become bankrupt or insolvent (however evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee or other similar official appointed with respect to it or substantially all of its assets; (vi) fail to perform any obligation to the other party with respect to any Credit Support Obligations relating to the Contract; (vii) fail to give Adequate Assurance of Performance under Section 10.1 within 48 hours but at least one Business Day of a written request by the other party; (viii) not have paid any amount due the other party hereunder on or before the second Business Day following written Notice that such payment is due; or ix) be the affected party with respect to any Additional Event of Default; then the other party (the "Non -Defaulting Party") shall have the right, at its sole election, to immediately withhold and/or suspend deliveries or payments upon Notice and/or to terminate and liquidate the transactions under the Contract, in the manner provided in Section 10.3, in addition to any and all other remedies available hereunder. 10.3. If an Event of Default has occurred and is continuing, the Non -Defaulting Party shall have the right, by Notice to the Defaulting Party, to designate a Day, no earlier than the Day such Notice is given and no later than 20 Days after such Notice is given, as an early termination date (the "Early Termination Date") for the liquidation and termination pursuant to Section 10.3.1 of all transactions under the Contract, each a "Terminated Transaction". On the Early Termination Date, all transactions will terminate, other than those transactions, if any, that may not be liquidated and terminated under applicable law ("Excluded Transactions"), which Excluded Transactions must be liquidated and terminated as soon thereafter as is legally permissible, and upon termination shall be a Terminated Transaction and be valued consistent with Section 10.3.1 below. With respect to each Excluded Transaction, tS actual termination aate Snail oe the Carly I ermination uate Tor purposes oT Section "I u.3."I . The parties have selected either "Early Termination Damages Apply" or "Early Termination Damages Do Not Apply" as indicated on the Base Contract. Termination 10.3.1. As of the Early Termination Date, the Non -Defaulting Party shall determine, in good faith and in a commercially reasonable manner, (i) the amount owed (whether or not then due) by each party with respect to all Gas delivered and received between the parties under Terminated Transactions and Excluded Transactions on and before the Early Termination Date and all other applicable charges relating to such deliveries and receipts (including without limitation any amounts owed under Section 3.2), for which payment has not yet been made by the party that owes such payment under this Contract and (ii) the Market Val ue, as defined below, of each Terminated Transaction. The Non -Defaulting Party shall (x) liquidate and accelerate each Terminated Transaction at its Market Value, so that each amount equal to the difference between such Market Value and the Contract Value, as defined below, of such Terminated Transaction(s) shall be due to the Buyer under the Terminated Transaction (s) if such Market Value exceeds the Contract Value and to the Seller if the opposite is the case; and (y) where appropriate, discount each amount then due under clause (x) above to present value in a commercially reasonable manner as of the Early Termination Date (to take account of the period between the date of liquidation and the date on which such amount would have otherwise been due pursuant to the relevant Terminated Transactions). For purposes of this Section 10.3.1, "Contract Value" means the amount of Gas remaining to be delivered or purchased under a transaction multiplied by the Contract Price, and "Market Value" means the amount of Gas remaining to be delivered or purchased under a transaction multiplied by the market price for a similar transaction at the Delivery Point determined by the Non -Defaulting Party in a commercially reasonable manner. To ascertain the Market Value, the Non -Defaulting Party may consider, among other valuations, any or all of the settlement prices of NYMEX Gas futures contracts, quotations from leading dealers in energy swap contracts or physical gas trading markets, similar sales or purchases and any other bona fide third -party offers, all adjusted for the length of the term and differences in transportation costs. A party shall not be required to enter into a replacement transaction(s) in order to determine the Market Value. Any extension(s) of the term of a transaction to which parties are not bound as of the Early Termination Date (including but not limited to "evergreen provisions") shall not be considered in determining Contract Values and Market Values. For the avoidance of doubt any option pursuant to which one party has the right to extend Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 8 of 13 September 5, 2006 the term of a transaction shall be considered in determining Contract Values and Market Values. The rate of interest used in calculating net present value shall be determined by the Non -Defaulting Party in a commercially reasonable manner. Early Termination Damages Do Not Apply: 10.3.1. As of the Early Termination Date, the Non -Defaulting Party shall determine, in good faith and in a commercially reasonable manner, the amount owed (whether or not then due) by each party with respect to all Gas delivered and received between the parties under Terminated Transactions and Excluded Transactions on and before the Early Termination Date and all other applicable charges relating to such deliveries and receipts (including without limitation any amounts owed under Section 3.2), for which payment has not yet been made by the party that owes such payment under this Contract. The parties have selected either "Other Agreement Setoffs Apply" or "Other Agreement Setoffs Do Not Apply" as indicated on the Base Contract. Other Agreement Setoffs Apply: Bilateral Setoff Option: 10.3.2. The Non -Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1, so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option and without prior Notice to the Defaulting Party, the Non -Defaulting Party is hereby authorized to setoff any Net Settlement Amount against (i) any margin or other collateral held by a party in connection with any Credit Support Obligation relating to the Contract; and (ii) any amount(s) (including any excess cash margin or excess cash collateral) owed or held by the party that is entitled to the Net Settlement Amount under any other agreement or arrangement between the parties. Triangular Setoff Option: 10.3.2. The Non -Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1, so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option, and without prior Notice to the Defaulting Party, the Non -Defaulting Party is hereby authorized to setoff (i) any Net Settlement Amount against any margin or other collateral held by a party in connection with any Credit Support Obligation relating to the Contract; (ii) any Net Settlement Amount against any amount(s) (including any excess cash margin or excess cash collateral) owed by or to a party under any other agreement or arrangement between the parties; (iii) any Net Settlement Amount owed to the Non -Defaulting Party against any amount(s) (including any excess cash margin or excess cash collateral) owed by the Non -Defaulting Party or its Affiliates to the Defaulting Party under any other agreement or arrangement; (iv) any Net Settlement Amount owed to the Defaulting Party against any amount(s) (including any excess cash margin or excess cash collateral) owed by the Defaulting Party to the Non -Defaulting Party or its Affiliates under any other agreement or arrangement; and/or (v) any Net Settlement Amount owed to the Defaulting Party against any amount(s) (including any excess cash margin or excess cash collateral) owed by the Defaulting Party or its Affiliates to the Non -Defaulting Party under any other agreement or arrangement. Other Agreement Setoffs Do Not Apply: 10.3.2. The Non -Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1, so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option and without prior Notice to the Defaulting Party, the Non -Defaulting Party may setoff any Net Settlement Amount against any margin or other collateral held by a party in connection with any Credit Support Obligation relating to the Contract. 10.3.3. If any obligation that is to be included in any netting, aggregation or setoff pursuant to Section 10.3.2 is unascertained, the Non -Defaulting Party may in good faith estimate that obligation and net, aggregate or setoff, as applicable, in respect of the estimate, subject to the Non -Defaulting Party accounting to the Defaulting Party when the obligation is ascertained. Any amount not then due which is included in any netting, aggregation or setoff pursuant to Section 10.3.2 shall be discounted to net present value in a commercially reasonable manner determined by the Non -Defaulting Party. 10.4. As soon as practicable after a liquidation, Notice shall be given by the Non -Defaulting Party to the Defaulting Party of the Net Settlement Amount, and whether the Net Settlement Amount is due to or due from the Non -Defaulting Party. The Notice shall include a written statement explaining in reasonable detail the calculation of the Net Settlement Amount, provided that failure to give such Notice shall not affect the validity or enforceability of the liquidation or give rise to any claim by the Defaulting Party against the Non -Defaulting Party. The Net Settlement Amount as well as any setoffs applied against such amount pursuant to Section 10.3.2, shall be paid by the close of business on the second Business Day following such Notice, which date shall not be earlier than the Early Termination Date. Interest on any unpaid portion of the Net Settlement Amount as adjusted by setoffs, shall accrue from the date due until the date of payment at a rate equal to the lower of (i) the then -effective prime rate of interest published under "Money Rates" by The Wall Street Journal, plus two percent per annum; or (ii) the maximum applicable lawful interest rate. 10.5. The parties agree that the transactions hereunder constitute a "forward contract" within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each "forward contract merchants" within the meaning of the United States Bankruptcy Code. 10.6. The Non -Defaulting Party's remedies under this Section 10 are the sole and exclusive remedies of the Non -Defaulting Party with respect to the occurrence of any Early Termination Date. Each party reserves to itself all other rights, setoffs, counterclaims and other defenses that it is or may be entitled to arising from the Contract. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 9 of 13 September 5, 2006 10.7. With respect to this Section 10, if the parties have executed a separate netting agreement with close-out netting provisions, the terms and conditions therein shall prevail to the extent inconsistent herewith. SECTION 11. FORCE MAJEURE 11.1. Except with regard to a party's obligation to make payment(s) due under Section 7, Section 10.4, and Imbalance Charges under Section 4, neither party shall be liable to the other for failure to perform a Firm obligation, to the extent such failure was caused by Force Majeure. The term "Force Majeure" as employed herein means any cause not reasonably within the control of the party claiming suspension, as further defined in Section 11.2. 11.2. Force Majeure shall include, but not be limited to, the following: (i) physical events such as acts of God, landslides, lightning, earthquakes, fires, storms or storm warnings, such as hurricanes, which result in evacuation of the affected area, floods, washouts, explosions, breakage or accident or necessity of repairs to machinery or equipment or lines of pipe; (ii) weather related events affecting an entire geographic region, such as low temperatures which cause freezing or failure of wells or lines of pipe; (iii) interruption and/or curtailment of Firm transportation and/or storage by Transporters; (iv) acts of others such as strikes, lockouts or other industrial disturbances, riots, sabotage, insurrections or wars, or acts of terror; and (v) governmental actions such as necessity for compliance with any court order, law, statute, ordinance, regulation, or policy having the effect of law promulgated by a governmental authority having jurisdiction. Seller and Buyer shall make reasonable efforts to avoid the adverse impacts of a Force Majeure and to resolve the event or occurrence once it has occurred in order to resume performance. 11.3. Neither party shall be entitled to the benefit of the provisions of Force Majeure to the extent performance is affected by any or all of the following circumstances: (i) the curtailment of interruptible or secondary Firm transportation unless primary, in -path, Firm transportation is also curtailed; (ii) the party claiming excuse failed to remedy the condition and to resume the performance of such covenants or obligations with reasonable dispatch; or (iii) economic hardship, to include, without limitation, Seller's ability to sell Gas at a higher or more advantageous price than the Contract Price, Buyer's ability to purchase Gas at a lower or more advantageous price than the Contract Price, or a regulatory agency disallowing, in whole or in part, the pass through of costs resulting from this Contract; (iv) the loss of Buyer's market(s) or Buyer's inability to use or resell Gas purchased hereunder, except, in either case, as provided in Section 11.2; or (v) the loss or failure of Seller's gas supply or depletion of reserves, except, in either case, as provided in Section 11.2. The party claiming Force Majeure shall not be excused from its responsibility for Imbalance Charges. 11.4. Notwithstanding anything to the contrary herein, the parties agree that the settlement of strikes, lockouts or other industrial disturbances shall be within the sole discretion of the party experiencing such disturbance. 11.5. The party whose performance is prevented by Force Majeure must provide Notice to the other party. Initial Notice may be given orally; however, written Notice with reasonably full particulars of the event or occurrence is required as soon as reasonably possible. Upon providing written Notice of Force Majeure to the other party, the affected party will be relieved of its obligation, from the onset of the Force Majeure event, to make or accept delivery of Gas, as applicable, to the extent and for the duration of Force Majeure, and neither party shall be deemed to have failed in such obligations to the other during such occurrence or event. 11.6. Notwithstanding Sections 11.2 and 11.3, the parties may agree to alternative Force Majeure provisions in a Transaction Confirmation executed in writing by both parties. SECTION 12. TERM This Contract may be terminated on 30 Day's written Notice, but shall remain in effect until the expiration of the latest Delivery Period of any transaction(s). The rights of either party pursuant to Section 7.6, Section 10, Section 13, the obligations to make payment hereunder, and the obligation of either party to indemnify the other, pursuant hereto shall survive the termination of the Base Contract or any transaction. SECTION 13. LIMITATIONS FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY. A PARTY'S LIABILITY HEREUNDER SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN OR IN A TRANSACTION, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 10 of 13 September 5, 2006 SECTION 14. MARKET DISRUPTION If a Market Disruption Event has occurred then the parties shall negotiate in good faith to agree on a replacement price for the Floating Price (or on a method for determining a replacement price for the Floating Price) for the affected Day, and if the parties have not so agreed on or before the second Business Day following the affected Day then the replacement price for the Floating Price shall be determined within the next two following Business Days with each party obtaining, in good faith and from non-affiliated market participants in the relevant market, two quotes for prices of Gas for the affected Day of a similar quality and quantity in the geographical location closest in proximity to the Delivery Point and averaging the four quotes. If either party fails to provide two quotes then the average of the other party's two quotes shall determine the replacement price for the Floating Price. "Floating Price" means the price or a factor of the price agreed to in the transaction as being based upon a specified index. "Market Disruption Event" means, with respect to an index specified for a transaction, any of the following events: (a) the failure of the index to announce or publish information necessary for determining the Floating Price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading on the exchange or market acting as the index; (c) the temporary or permanent discontinuance or unavailability of the index; (d) the temporary or permanent closing of any exchange acting as the index; or (e) both parties agree that a material change in the formula for or the method of determining the Floating Price has occurred. For the purposes of the calculation of a replacement price for the Floating Price, all numbers shall be rounded to three decimal places. If the fourth decimal number is five or greater, then the third decimal number shall be increased by one and if the fourth decimal number is less than five, then the third decimal number shall remain unchanged. SECTION 15. MISCELLANEOUS 15.1. This Contract shall be binding upon and inure to the benefit of the successors, assigns, personal representatives, and heirs of the respective parties hereto, and the covenants, conditions, rights and obligations of this Contract shall run for the full term of this Contract. No assignment of this Contract, in whole or in part, will be made without the prior written consent of the non -assigning party (and shall not relieve the assigning party from liability hereunder), which consent will not be unreasonably withheld or delayed; provided, either party may (i) transfer, sell, pledge, encumber, or assign this Contract or the accounts, revenues, or proceeds hereof in connection with any financing or other financial arrangements, or (ii) transfer its interest to any parent or Affiliate by assignment, merger or otherwise without the prior approval of the other party. Upon any such assignment, transfer and assumption, the transferor shall remain principally liable for and shall not be relieved of or discharged from any obligations hereunder. 15.2. If any provision in this Contract is determined to be invalid, void or unenforceable by any court having jurisdiction, such determination shall not invalidate, void, or make unenforceable any other provision, agreement or covenant of this Contract. 15.3. No waiver of any breach of this Contract shall be held to be a waiver of any other or subsequent breach. 15.4. This Contract sets forth all understandings between the parties respecting each transaction subject hereto, and any prior contracts, understandings and representations, whether oral or written, relating to such transactions are merged into and superseded by this Contract and any effective transaction(s). This Contract may be amended only by a writing executed by both parties. 15.5. The interpretation and performance of this Contract shall be governed by the laws of the jurisdiction as indicated on the Base Contract, excluding, however, any conflict of laws rule which would apply the law of another jurisdiction. 15.6. This Contract and all provisions herein will be subject to all applicable and valid statutes, rules, orders and regulations of any governmental authority having jurisdiction over the parties, their facilities, or Gas supply, this Contract or transaction or any provisions thereof. 15.7. There is no third party beneficiary to this Contract. 15.8. Each party to this Contract represents and warrants that it has full and complete authority to enter into and perform this Contract. Each person who executes this Contract on behalf of either party represents and warrants that it has full and complete authority to do so and that such party will be bound thereby. 15.9. The headings and subheadings contained in this Contract are used solely for convenience and do not constitute a part of this Contract between the parties and shall not be used to construe or interpret the provisions of this Contract. 15.10. Unless the parties have elected on the Base Contract not to make this Section 15.10 applicable to this Contract, neither party shall disclose directly or indirectly without the prior written consent of the other party the terms of any transaction to a third party (other than the employees, lenders, royalty owners, counsel, accountants and other agents of the party, or prospective purchasers of all or substantially all of a party's assets or of any rights under this Contract, provided such persons shall have agreed to keep such terms confidential) except (i) in order to comply with any applicable law, order, regulation, or exchange rule, (ii) to the extent necessary for the enforcement of this Contract , (iii) to the extent necessary to implement any transaction, (iv) to the extent necessary to comply with a regulatory agency's reporting requirements including but not limited to gas cost recovery proceedings; or (v) to the extent such information is delivered to such third party for the sole purpose of calculating a published index. Each party shall notify the other party of any proceeding of which it is aware which may result in disclosure of the terms of any transaction (other than as permitted hereunder) and use reasonable efforts to prevent or limit the disclosure. The existence of this Contract is not subject to this confidentiality obligation. Subject to Section 13, the parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with this confidentiality obligation. The terms of any transaction hereunder shall be kept confidential by the parties hereto for one year from the expiration of the transaction. In the event that disclosure is required by a governmental body or applicable law, the party subject to such requirement may disclose the material terms of this Contract to the extent so required, but shall promptly notify the other party, prior to disclosure, and shall cooperate (consistent with the disclosing party's legal obligations) with the other party's efforts to obtain protective orders or similar restraints with respect to such disclosure at the expense of the other party. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 11 of 13 September 5, 2006 15.11. The parties may agree to dispute resolution procedures in Special Provisions attached to the Base Contract or in a Transaction Confirmation executed in writing by both parties 15.12. Any original executed Base Contract, Transaction Confirmation or other related document may be digitally copied, photocopied, or stored on computer tapes and disks (the "Imaged Agreement'). The Imaged Agreement, if introduced as evidence on paper, the Transaction Confirmation, if introduced as evidence in automated facsimile form, the recording, if introduced as evidence in its original form, and all computer records of the foregoing, if introduced as evidence in printed format, in any judicial, arbitration, mediation or administrative proceedings will be admissible as between the parties to the same extent and under the same conditions as other business records originated and maintained in documentary form. Neither Party shall object to the admissibility of the recording, the Transaction Confirmation, or the Imaged Agreement on the basis that such were not originated or maintained in documentary form. However, nothing herein shall be construed as a waiver of any other objection to the admissibility of such evidence. DISCLAIMER: The purposes of this Contract are to facilitate trade, avoid misunderstandings and make more definite the terms of contracts of purchase and sale of natural gas. Further, NAESB does not mandate the use of this Contract by any party. NAESB DISCLAIMS AND EXCLUDES, AND ANY USER OF THIS CONTRACT ACKNOWLEDGES AND AGREES TO NAESB-S DISCLAIMER OF, ANY AND ALL WARRANTIES, CONDITIONS OR REPRESENTATIONS, EXPRESS OR IMPLIED, ORAL OR WRITTEN, WITH RESPECT TO THIS CONTRACT OR ANY PART THEREOF, INCLUDING ANY AND ALL IMPLIED WARRANTIES OR CONDITIONS OF TITLE, NONaNFRINGEMENT, MERCHANTABILITY, OR FITNESS OR SUITABILITY FOR ANY PARTICULAR PURPOSE (WHETHER OR NOT NAESB KNOWS, HAS REASON TO KNOW, HAS BEEN ADVISED, OR IS OTHERWISE IN FACT AWARE OF ANY SUCH PURPOSE), WHETHER ALLEGED TO ARISE BY LAW, BY REASON OF CUSTOM OR USAGE IN THE TRADE, OR BY COURSE OF DEALING. EACH USER OF THIS CONTRACT ALSO AGREES THAT UNDER NO CIRCUMSTANCES WILL NAESB BE LIABLE FOR ANY DIRECT, SPECIAL, INCIDENTAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES ARISING OUT OF ANY USE OF THIS CONTRACT. Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 12 of 13 September 5, 2006 TRANSACTION CONFIRMATION EXHIBIT A FOR IMMEDIATE DELIVERY Letterhead/Logo Date: Transaction Confirmation #: This Transaction Confirmation is subject to the Base Contract between Seller and Buyer dated The terms of this Transaction Confirmation are binding unless disputed in writing within 2 Business Days of receipt unless otherwise specified in the Base Contract. SELLER: BUYER: Attn: Attn: Phone: Phone: Fax: Fax: Base Contract No. Transporter: Transporter Contract Number: Base Contract No. Transporter: Transporter Contract Number: Contract Price: $ /MMBtu or Delivery Period: Begin: End: Performance Obligation and Contract Quantity: (Select One) Firm (Fixed Quantity): Firm (Variable Quantity): Interruptible: MMBtus/day MMBtus/day Minimum Up to MMBtus/day 1 J EFP MMBtus/day Maximum subject to Section 4.2. at election of Buyer or I I Seller Delivery Point(s): (If a pooling point is used, list a specific geographic and pipeline location): Special Conditions: Seller: Buyer: By: By: Title: Title: Date: Date: Copyright C 2006 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 13 of 13 September 5, 2006 SPECIAL PROVISIONS TO THE NAESB BASE CONTRACT FOR SALE AND PURCHASE OF NATURAL GAS These Special Provisions to the NAESB Base Contract for Sale and Purchase of Natural Gas (these "Special Provisions") are attached to and made a part of that certain Base Contract for Sale and Purchase of Natural Gas between CenterPoint Energy Services, Inc. and Hutchinson Utilities Commission, dated April 1, 2019 (the "Base Contract"). The parties hereto agree that (i) references to Sections in these Special Provisions refer to a Section of the General Terms and Conditions of the Base Contract; and (ii) these Special Provisions amend the Base Contract as of the date of the Base Contract. 1. Section 1.2 "Oral Transaction Procedure" is amended by adding the phrase "or other electronic means of communication" immediately after the phrase "EDI transmission" in the second sentence, and by deleting the last sentence in the section. 2. Section 2.15 "Delivery Period" is amended by adding the following new sentence at the end of the section: "If a transaction does not specify that a renewal period applies, but Party A continues to deliver and Party B continues to receive Gas after the expiration of the initial Delivery Period specified therein, then the Delivery Period will be deemed to automatically extend month -to -month under the terms of the transaction until terminated by either party on not less than 30 days' notice; provided, however, if the Contract Price in such transaction is a fixed price, then the applicable Contract Price during any monthly extension of the Delivery Period will be the then -current monthly spot price for Gas in the geographic area where the Delivery Point is located, as determined by Party A in a commercially reasonable manner If a transaction specifies that a renewal period applies and the parties agree to a fixed price with respect to all or part of the Contract Quantity for any Month(s) occurring after the initial Delivery Period or renewal thereof, as applicable and then in effect, then the Delivery Period of the transaction will be deemed to have been extended through and including the last calendar month of the last renewal period in which all or part of the Contract Quantity for any Month occurring during such renewal period is subject to a fixed price ." 3. The following sentence is added at the end of Section 2.19: "Unless otherwise specified in a transaction, "Firm" means the utilization of a firm service agreement with a Transporter under which the transaction's Delivery Point is not a specified primary point for the delivery of Gas." 4. The following new Section 2.36 is hereby added, as follows: ""CFTC Regulations" shall mean any applicable rules, regulations, orders, supplementary information, interpretation and guidance issued by the Commodity Futures Trading Commission or any division of office thereof, as amended, modified, superseded, or otherwise supplemented from time to time." 5. The following new Section 3.5 is added: "3.5 The parties acknowledge that an operational flow order declared by a Transporter may occur with little to no advance notification. Accordingly, if either party receives notice or becomes aware of an operational flow order requiring action to be taken in connection with the operational flow order or the delivery or consumption of Gas under an affected transaction, such party will use commercially reasonably efforts to notify the other party by telephone or electronic mail of such event in a timely manner. Each party will take all actions required to comply with and within the time prescribed by the operational flow order, and any penalties assessed by a Transporter will be borne by the party who failed to comply. Both parties agree that an operational flow order may require one or both parties to buy or sell quantities of Gas in the then current market conditions, which may be appreciably higher or lower than the pricing set forth in an affected transaction, and any such quantities will be priced according to the then current market conditions and delivered or received on a reasonable best efforts basis, subject to available transportation." 6. Section 7.5 is amended by deleting in clause (i) thereof the words "the then -effective prime rate of interest published under "Money Rates" by The Wall Street Journal, plus two percent per annum" and replacing them with the following: "one and one- half percent (1'/2%) of the outstanding balance per month". 7. Section 10.2 is amended by deleting the word "or" preceding clause (ix) therein and inserting the following immediately after the semicolon at the end of clause (ix): "or (x) consolidate or amalgamate with, or merge with or into, or transfer all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all of the obligations of such party under the Contract or the resulting, surviving or transferee entity's credit is materially weaker as determined by the other party acting in good faith and in a commercially reasonable manner;". 8. The following new Section 10.8 is added: "10.8 The Non -Defaulting Party may recover, and include in its calculation of the Net Settlement Amount, all reasonable costs it incurred as a result of the Terminated Transactions, including but not limited to the following: (i) losses incurred by the Non -Defaulting Party as a result of the Terminated Transactions associated with Transporter costs which cannot be avoided through the Non -Defaulting Party's reasonable efforts; (ii) brokerage fees and commissions and transaction losses, costs and expenses reasonably incurred by the Non - Defaulting Party either in terminating any arrangement pursuant to which it has hedged its obligations or entering into new arrangements which replace a Terminated Transaction; and (iii) commercially reasonable attorneys' fees and court costs, if any, incurred in connection with enforcing its rights in respect of the Fonn-2006 NAESB Special Provisions Version 1.2 Page 1 Terminated Transaction(s) (including collection costs incurred for past due invoices)." 9. Section 11.3(i) is deleted and replaced with "(i) the curtailment of interruptible transportation unless Firm transportation is also curtailed." 10. Section 11.6 is deleted and replaced with the following: "Notwithstanding the provisions of the preceding paragraphs, in the event a transaction: (i) has a performance obligation that is Firm; (ii) as a result of a Force Majeure Event, Party A is unable to sell and deliver, or Party B is unable to purchase and receive, the Contract Quantity; (iii) the Delivery Period is at least one month; and (iv) the Contract Price is a fixed price, then a. If the FOM Price (as hereinafter defined) is above the fixed price, Seller will pay Buyer an amount equal to the product of (1) the portion of the Contract Quantity that could not be delivered or received and (2) the difference between the FOM Price and the fixed price; or b. If the FOM Price is below the fixed price, Buyer will pay Seller an amount equal to the product of (1) the portion of the Contract Quantity that could not be delivered or received and the difference between the fixed price and the FOM Price. The "FOM Price" means the last day settle price of the New York Mercantile Exchange natural gas futures contract for the month in which the Force Majeure Event occurs. The process described in the last two sentences of Section 10.4 of this Agreement shall govern the payment of any obligations incurred under this Section 11.6." 11. Section 14 is deleted and replaced with the following: "If a Market Disruption Event has occurred then either party may give notice thereof to the other party specifying in reasonable detail the event that has occurred constituting a Market Disruption Event. Upon the giving of such notice, the parties shall negotiate in good faith to agree on a replacement price for the Floating Price (or on a method for determining a replacement price for the Floating Price) for the Affected Period. An "Affected Period" is any part of the Delivery Period under a transaction affected by the Market Disruption Event. If the parties have not agreed on or before the tenth Business Day following the date of the notice of the occurrence of the Market Disruption Event, then the replacement price for the Floating Price shall be determined within the next two following Business Days with each party obtaining, in good faith and from non-affiliated market participants in the relevant market, two quotes for prices of Gas for the Affected Period of a similar quality and quantity in the geographical location closest in proximity to the Delivery Point and averaging the four quotes, rounded to the third decimal place. If either party fails to provide two quotes, then the average of the other party's two quotes shall determine the replacement price. "Floating Price" means the price or a factor of the price, based on a specified index, agreed to in a transaction as the Contract Price. "Market Disruption Event" means, relating to an index specified in a transaction, any of the following events: (a) the failure of the index to announce or publish information necessary for determining the Floating Price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading on the exchange or market acting as the index; (c) the temporary or permanent discontinuance or unavailability of the index; (d) the temporary or permanent closing of any exchange acting as the index; or (e) a market abnormality, anomaly or other occurrence, other than an event of Force Majeure, which causes the Floating Price to no longer be reflective of the market price of Gas for the relevant market in the geographic area in which the Delivery Point is located." 12. The following new Sections 15.13, 15.14 and 15.15 are added: "15.13 If requested, a party shall deliver, within one hundred twenty (120) days after the end of each fiscal year and within sixty (60) days after the end of each of its first three fiscal quarters of each fiscal year, a copy of its or its credit support provider's audited financial statements (or certified consolidated unaudited financial statements) prepared in accordance with generally accepted accounting principles." 15.14. Each party shall promptly provide the other party any information reasonably requested by such other party to enable such other party to comply with Title VII of the Dodd -Frank Wall Street Reform and Consumer Protection Act and CFTC Regulations in connection with any transaction between the parties under this Base Contract. Notwithstanding anything to the contrary in this Base Contract or in any non -disclosure, confidentiality or similar agreement between the parties, each party hereby consents to the disclosure of information by the other party to the extent required under CFTC Regulations. 15.15 In addition to any provisions for early termination set forth herein, the parties agree that either party may terminate a relevant transaction if: (i) a Transporter files a tariff change or a court or governmental agency with jurisdiction (including, without limitation, the Federal Energy Regulatory Commission) causes a Transporter to initiate a tariff change in a manner that causes a party to incur additional, uncontemplated material capital or operating costs (including, but not limited to, Transporter fixed and/or variable charges or fuel, or in connection with transporter system operational limitations or restrictions) relating to its performance under the transaction; and (ii) the Parties are unable, after good faith negotiations, to renegotiate the transaction." Fonn-2006 NAESB Special Provisions Version 1.2 Page 2 IN WITNESS WHEREOF, the parties have executed these Special Provisions, which may be executed in multiple counterparts, but which shall constitute one and the same instrument, effective as of the date first written above. CENTERPOINT ENERGY SERVICES, INC. HUTCHINSON UTILITIES COMMISSION By Name: Title: By: Name: Title: Fonn-2006 NAESB Special Provisions Version 1.2 Page 3 TRANSACTION CONFIRMATION FOR IMMEDIATE DELIVERY Date: April 8, 2019 CenterPo nt Transaction Confirmation #: 1 Energy This Transaction Confirmation is subject to the Base Contract between Seller and Buyer dated April 8, 2019. The terms of this Transaction Confirmation are binding unless disputed in writing within 2 Business Days of receipt unless otherwise specified in the Base Contract. SELLER: BUYER: CENTERPOINT ENERGY SERVICES, INC. HUTCHINSON UTILITIES COMMISSION 1111 Louisiana Street 225 Michigan Street SE Houston, TX 77002 Hutchinson, MN 55350-1905 Attn: Contracts Administration Attn: John Webster Phone: Phone: (320) 234-0507 Email: Email: Iwebster&ci.hutchinson.mn.us Transporter: Northern Natural Gas ("NNG") Contract Price: A delivered market price mutually agreed upon prior to Gas flow. Delivery Period: Begin: May 1, 2019 End: April 30, 2020 Performance Obligation and Contract Quantity: Firm up to the maximum daily quantity ("MDQ") of the Released Capacity (as hereinafter defined) Delivery Point(s): Buyer's NNG city gate(s) (Hutchinson #1 and #2), or such other point(s) as may be mutually agreed upon. Special Conditions: 1. Buyer has Firm transportation on NNG, and to the extent that the pipeline capacity under a Firm transportation contract is releasable under the applicable Transporters' FERC tariff, Buyer hereby appoints CES as its asset manager for purposes of FERC's applicable pipeline capacity release regulations and the Transaction, insofar as such releasable capacity is concerned (the "Released Capacity"), shall constitute a qualified asset management arrangement as defined in 18 CFR Sec. 284.8. In connection herewith, the terms and conditions of the AMA Addendum ("AMA Addendum") attached hereto are incorporated herein. To the extent any capacity is not released or releasable, Seller will serve as Buyer's agent with respect thereto for purposes of nominations, scheduling and other services. 2. On any Day during the Delivery Period, Buyer may call upon Seller to deliver, via a timely written nomination, quantities of Gas to Buyer at the Delivery Point up to the MDQ at the Contract Price, or any quantity in excess thereof as may be mutually agreed to by the Parties. Any nominations for Gas hereunder must be made by Buyer to Seller no later than 8:00 A.M. (Central Time) of the Day of flow and must specify the quantity. Quantities in excess of the MDQ will be delivered on a best efforts basis, subject to available transportation. Nominations for delivery over weekends and holidays will be ratable per the "next -day" definition of the Intercontinental Exchange. 3. During the Delivery Period, Seller will pay Buyer the monthly sum of $685.00 as an asset optimization payment (the "Asset Fee"). On any Day(s) Buyer (i) calls upon Seller to deliver Gas to Buyer hereunder or (ii) recalls the Released Capacity, then Seller will be entitled to a refund of a prorated amount of the Asset Fee calculated upon the quantity called upon or recalled by Buyer, the number of Days of such call or recall and the applicable number of Day(s) in the Month(s) of such call or recall. 4. Seller, as Buyer's agent, will pay Buyer's monthly demand/reservation fees due to the Transporters under Buyer's firm transportation and storage contracts and pass such costs through to Buyer on Seller's monthly state ment/invoice. 5. If any service provided by Seller under this Transaction to Buyer is at any time construed or found to be in contravention of any applicable rule, order or regulation of FERC, Seller shall immediately terminate the provision of such service to Buyer and the Parties agree to work together to implement an alternative service by Seller that is consistent with applicable Federal Energy Regulatory Commission (FERC) rules, orders or regulations. 6. With respect to the services to be performed by Seller hereunder, Seller has the option, at its sole discretion, to utilize alternate capacity to make deliveries to Buyer, but has no right or obligation to pass through to Buyer any resulting incremental costs or savings. 7. At the expiration of the Delivery Period, this Transaction Confirmation and the Delivery Period shall automatically extend for successive one-year year periods unless terminated by either party upon written notice to the other party not less than one hundred twenty (120) Days prior to the end of the initial Delivery Period or anyone -year extension thereof. Seller: CENTERPOINT ENERGY SERVICES, INC. Buyer: HUTCHINSON UTILITIES COMMISSION By: By: Title: Title: Date: Date: