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Home My WebLink About10-28-2026 HUCCPHUTCHINSON UTILITIES COMMISSION AGENDA REGULAR MEETING October 28, 2026 3:00 p.m. 1. CONFLICT OF INTEREST 2. APPROVE CONSENT AGENDA a. Approve Minutes b. Ratify Payment of Bills 3. APPROVE FINANCIAL STATEMENTS 4. OPEN FORUM 5. COMMUNICATION a. City Administrator b. Divisions C. Human Resources d. Legal e. General Manager 6. POLICIES a. Review Policies i. Natural Gas Service Requirements & Charges ii. Temporary Service — Natural Gas iii. Natural Gas Meter Requirements & Placement iv. Meter Testing — Natural Gas v. Natural Gas Service Work vi. Locating Customer's Underground Utilities — Natural Gas b. Approve Changes i. Rate Schedule — Electric ii. Rate Schedule — Natural Gas iii. Security Light Rental — Rate to Furnish and Maintain Fixture 7. UNFINISHED BUSINESS 8. NEW BUSINESS a. Approve 2026 Audit Services with Conway Deuth & Schmiesing b. Approve setting a Special Budget Workshop meeting on November 25, 2026 C. Approve Level of Renewable Energy Credits for 2027 d. Discussion on LM6000 9. ADJOURN MINUTES Regular Meeting — Hutchinson Utilities Commission Wednesday, September 30, 2026 Call to order — 3:00 p.m. Vice President Tom Lambert called the meeting to order. Members present: Vice President Tom Lambert; Secretary Matt Cheney; Commissioner Kathy Silvernale; Commissioner Josh Wendland; GM Jeremy Carter; Attorney Marc Sebora IG1:l� iiii:%L�C Ca iii RZ•Ti11�1.FTiiliL� Josh Wendland was sworn in as commissioner by Attorney Marc Sebora 1. Conflict of Interest 2. Approve Consent Agenda a. Approve Minutes b. Ratify Payment of Bills Motion by Commissioner Cheney, second by Commissioner Silvernale to Approve the Consent Agenda. Motion carried unanimously 3. Approve Financial Statements Mr. Martig presented the Financial Statements. Electric Division customer revenue and usage was up with increased temperatures but was offset by lower sales for resales. Natural Gas Division usage and revenue increased. Large part of the revenue increase was due to a fuel cost adjustment in 2026 while there was a credit in 2025. GM Carter reviewed the fuel cost adjustment and rate stabilization fund along with the Power Cost Adjustment. GM Carter also compared the differences from 2025 to 2026. Balance sheet and Investments were also reviewed. Motion by Commissioner Silvernale, second by Commissioner Cheney to Approve the Financial Statements. Motion carried unanimously. 4. Open Forum 5. Communication a. City Administrator— Matthew Jaunich — i. Nothing to Report b. Divisions Dan Lang, Engineering Services Manager — 1. Hutch Sub Project Update Dave Hunstad, Electric Transmission/Distribution Manager — 1. Finishing up projects 2. Solar project update- Inverter is covered under warranty iii. Mike Gabrielson, Production Manager- 1. Plant 1 Cooling Tower Pipe update. Project is expected to take about 2 weeks. iv. Byron Bettenhausen, Natural Gas Manager — 1. River Project has been completed v. Jared Martig, Financial Manager 1. Nothing to Report c. Human Resources — Angie Radke - Absent d. Legal — Marc Sebora — i. Charter Commission did meet in Sept and voted on adding an additional classification of people who would be eligible to serve on the Commission. The classification would include rate payers that live within a 2-mile radius of Hutchinson. The hope is to increase the number of people eligible and willing to serve on the HUC Commission Board. Process going forward would be the recommendation from the Charter to be considered at the City Council meeting on Oct 13t". An ordinance would have to be considered making the charter change which will be at the next 2 Council meetings. If enacted, the statute has a procedure and does not take into effect until after 90 days which will be January. e. General Manager — Jeremy Carter i. Compensation Study Update ii. Customer Appreciation Open House for Public Power Week is Tuesday, October 6tn iii. Union Negotiations will be coming up this year. Tentative dates are in November. iv. Working on Budgets and CIP. Managers are working on Fleet. Looking at having a Budget workshop in November. 6. Policies a. Review Policies i. Electric Service Requirements and Charges ii. Temporary Service iii. Temporary Service in Case of Underground Failure iv. Electric Meter Placement v. Sealing of Meters vi. Meter Testing vii. Right -of -Way Clearing viii. Tree Removal or Trimming ix. Locating Customer's Underground Utilities No changes recommended at this time. 7. Unfinished Business 8. New Business a. Discussion about Extending the Term of the MRES Power Sale Agreement 2 GM Carter presented Extending the Term of the MRES Power Sale Agreement. GM Carter recapped conversations with MRES looking to extend S-1 member contracts out to January 1, 2067 (40 years). Current S-1 member contracts are extended out to January 1, 2057 (30 years). Currently MRES has 61 total members within the joint action agency. 58 members are S-1 members, meaning members receive all their supplemental power needs above their WAPA (Federal Hydro Power) allocation from MRES and 3 members who are non-S1 members just receive a block of power and capacity from MRES, which HUC is one of. MRES would like HUC to consider extending the current agreement which expires January 1, 2046 (-20years). Original MRES Power Sale Agreement, Annual Rate Changes and MRES Services are attached for review. Commissioners would like to table the conversation at a later date -Special Meeting to have Commissioner: President Don Marteniz present. b. Discussion on the 2-Year Rate Track Provided by UFS GM Carter presented Discussion on the 2-Year Rate Track Provided by UFS. Looking for feedback from the Commission on information that was received from the consultant on the Cost of Service Study which designed a 2-year rate track in the Electric Division and revenue neutral on the Natural Gas Division with balancing out the classes. Discussion was had about the start date of December 1st. By adjusting rates in the Spring and Fall it has the least impact on customers because consumption is down on both Electric and Natural Gas. Original conversations were for Nov 1st but by the time it goes to the City Council in October, customers will already be consuming electricity. GM Carter provided an update on the process of the date of December 1st GM Carter recapped the reasons behind the Cost of Service Study and the components of the Study compared to the classes and the historical background. Vice President Tom Lambert added new business item 8c. c. Set a Special Meeting for Tuesday, October 6, 2026, at 7:30am Motion by Commissioner Cheney, second by Commissioner Silvernale to Approve a Special Meeting for Tuesday, October 6, 2026, at 7:30am. Motion carried unanimously. 3 9. Adjourn There being no Commissioner unanimously. ATTEST: further business, a motion by Commissioner Cheney, second by Silvernale to adjourn the meeting at 3:31 p.m. Motion carried Don Martinez, President 12 Matt Cheney, Secretary MINUTES Special Meeting — Hutchinson Utilities Commission Tuesday, October 6, 2026 Call to order — 7:30 a.m. President Don Martinez called the meeting to order. Members present: President Don Martinez; Vice President Tom Lambert; Secretary Matt Cheney; Commissioner Kathy Silvernale; Commissioner Josh Wendland; GM Jeremy Carter; Attorney Marc Sebora Others Present: Jared Martig, Mike Gabrielson, Byron Bettenhausen, Angie Radke The purpose of the special meeting is to have a Discussion and possibly Act on MRES Contract, Discussion and possibly Act on Cost of Service Resolution 26-03, and Discussion and possibly Act on Plant 1 Fagen Project. GM Carter recapped MRES conversations that were previously held regarding S-1 member and non S-1 member contracts. Anticipation from MRES is to have all member contracts be the same length and to extend out to 2067. HUC's current contract extends to 2046, which would then add 20 years to the current contract. Every 10 years, MRES continually looks to extend their contract out 40 years which allows long-term pledged revenue headroom to MRES's financing arm Western Minnesota Municipal Power Agency (WMMPA). The pledged revenues allow the most advantageous interest rate when issuing 30-year tax-exempt bonds to pay for generating facilities and capital purchases to fulfill MRES's energy and capacity obligations to the membership. Also 40 years is the longest length of term allowed under Iowa Law. Discussion was held on the services that MRES provides by being a full member vs a non-member and the block of energy HUC receives. Decision from the Board was to keep the current contract in place with no changes and to revisit it in 10 years. GM Carter provided a high-level overview of the Cost of Service Study and Resolution 26-03. If Commission is comfortable with the 2 years and adjustments for the gas side, the resolution will be presented to the City Council along with the Rate studies. Typically, what has been posted on social media sites does not include the Industrial charges because of the different Industrial contracts and the Security and Street Light charges. HUC highlights the majority of the classes which are residential and commercial. Commission's job is to look at the whole organization but also divisions as a separate division. Discussion was held on the Power Cost Adjustment, wholesale costs and communicating the Rate Comparison Study. All Commissioners agreed moving forward. Motion by Commissioner Lambert, second by Commissioner Silvernale to Approve Cost of Service Study — Resolution 26-03. Motion carried unanimously. GM Carter started the discussion on Plant 1 Fagen Project. Conversations have been held between HUC Staff, Fagen and HDR on the cooling tower pipe. 1 Mr. Gabrielson estimated 1-2 weeks to have project completed. Motion by Commissioner Lambert, second by Commissioner Cheney to Approve $100k and GM Carter has authority to go up to $174k. Motion carried unanimously. 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Q w a O H N z w N a � w w Q HUTCHINSON UTILITIES COMMISSION COMBINED DIVISIONS FINANCIAL REPORT FOR SEPTEMBER, 2026 Combined Division Customer Revenue Sales for Resale NG Transportation Electric Division Transfer Other Revenues Interest Income TOTAL REVENUES Salaries & Benefits Purchased Commodities Transmission Generator Fuel/Chem. Depreciation Transfers (Elect./City) Operating Expense Debt Interest TOTAL EXPENSES NET PROFIT/(LOSS) 75% of Year Comp. 2026 2025 Di . %Chna 2026 2025 Di %Chna Full Yr Bud %of Bud $ 3,170,399 $ 2,577,422 $ 592,977 23.0% $ 31,396,675 $ 26,432,360 $ 4,964,315 18.8% $ 40,209,447 78.1% $ 374,134 $ 684,339 $ (310,205) (45.3%) $ 3,039,208 $ 5,919,324 $ (2,880,116) (48.7%) $ 4,339,200 70.0% $ 176,952 $ 180,360 $ (3,408) (1.9%) $ 1,560,996 $ 1,558,721 $ 2,275 0.1% $ 2,037,588 76.6% $ 60,667 $ 60,639 $ 28 0.0% $ 546,000 $ 545,750 $ 250 0.0% $ 728,000 75.0% $ 210,185 $ 105,999 $ 104,186 98.3% $ 956,651 $ 534,336 $ 422,315 79.0% $ 573,955 166.7% $ 56,908 $ 77,832 $ (20,924) (26.9%) $ 387,936 $ 605,295 $ (217,358) (35.9%) $ 583,457 66.5% $ 4,049,245 $ 3,686,591 $ 362,654 9.8% $ 37,887,466 $ 35,595,785 $ 2,291,681 6.4% $ 48,471,647 78.2% $ 665,041 $ 635,056 $ 29,985 4.72% $ 6,052,963 $ 5,762,973 $ 289,991 5.0% $ 8,524,717 71.0% $ 1,528,399 $ 1,318,810 $ 209,589 15.9% $ 16,739,466 $ 14,868,666 $ 1,870,800 12.6% $ 20,816,157 80.4% $ 428,047 $ 304,106 $ 123,941 40.8% $ 3,384,143 $ 2,113,148 $ 1,270,995 60.1% $ 4,200,000 80.6% $ 120,624 $ 228,028 $ (107,404) (47.1%) $ 1,044,023 $ 1,992,515 $ (948,492) (47.6%) $ 2,008,656 52.0% $ 352,417 $ 351,864 $ 553 0.2% $ 3,179,465 $ 3,173,559 $ 5,906 0.2% $ 4,190,000 75.9% $ 222,552 $ 222,524 $ 28 0.0% $ 2,002,969 $ 2,002,719 $ 250 0.0% $ 2,670,626 75.0% $ 386,475 $ 202,371 $ 184,103 91.0% $ 2,931,358 $ 2,744,544 $ 186,815 6.8% $ 3,791,274 77.3% $ 54,699 $ 49,688 $ 5,011 10.1% $ 365,136 $ 447,192 $ (82,056) 18.3% $ 465,657 78.4% $ 3,758,253 $ 3,312,447 $ 445,806 13.5% $ 35,699,523 $ 33,105,315 $ 2,594,208 7.8% $ 46,667,087 76.5% $ 290,992 $ 374,144 $ (83,152) (22.2%) $ 2,187,943 $ 2,490,471 $ (302,528) (12.1%) $ 1,804,560 121.2% September September YTD YTD 2026 2025 Change 2026 2025 Change Gross Margin %: 34.2% 36.0% -1.8% 31.1% 34.0% -2.9% Operating Income Per Revenue $ (%): 2.7% 7.4% -4.7% 4.1% 5.7% -1.5% Net Income Per Revenue $ (%): 7.2% 10.1% -3.0% 5.8% 7.0% -1.2% 2026 HUC Budget Target 32.2% 2.8% 3.7% HUTCHINSON UTILITIES COMMISSION ELECTRIC DIVISION FINANCIAL REPORT FOR SEPTEMBER, 2026 2026 2025 Di . %Chna 2026 2025 Di %Chna FullYrBud %of Bud Electric Division Customer Revenue $ 2,555,903 $ 2,011,102 $ 544,802 27.1% $ 21,514,067 $ 18,116,920 $ 3,397,147 18.8% $ 27,471,918 78.3% Sales for Resale $ 374,134 $ 684,339 $ (310,205) (45.3%) $ 3,039,208 $ 5,919,324 $ (2,880,116) (48.7%) $ 4,339,200 70.0% Other Revenues $ 161,582 $ 43,964 $ 117,618 267.5% $ 616,266 $ 251,990 $ 364,275 144.6% $ 202,862 303.8% Interest Income $ 31,015 $ 40,310 $ (9,295) (23.1%) $ 207,682 $ 315,194 $ (107,512) (34.1%) $ 308,457 67.3% TOTAL REVENUES $ 3,122,635 $ 2,779,715 $ 342,920 12.3% $ 25,377,223 $ 24,603,428 $ 773,795 3.1% $ 32,322,437 78.5% Salaries & Benefits $ 491,609 $ 446,445 $ 45,165 Purchased Power $ 1,222,776 $ 1,006,736 $ 216,041 Transmission $ 428,047 $ 304,106 $ 123,941 Generator Fuel/Chem. $ 120,624 $ 228,028 $ (107,404) Depreciation $ 253,397 $ 254,029 $ (632) Transfers (Elect./City) $ 172,817 $ 172,789 $ 28 Operating Expense $ 296,331 $ 148,599 $ 147,732 Debt Interest $ 46,032 $ 32,771 $ 13,261 TOTAL EXPENSES $ 3,031,633 $ 2,593,502 $ 438,131 NET PROFIT/(LOSS) $ 91,002 $ 186,212 $ (95,210) 10.1% $ 4,420,537 $ 4,283,937 $ 136,600 3.2% $ 6,178,442 21.5% $ 10,534,394 $ 9,663,529 $ 870,865 9.0% $ 13,035,315 40.8% $ 3,384,143 $ 2,113,148 $ 1,270,995 60.1% $ 4,200,000 (47.1%) $ 1,044,023 $ 1,992,515 $ (948,492) (47.6%) $ 2,008,656 (0.2%) $ 2,287,172 $ 2,292,528 $ (5,356) (0.2%) $ 3,060,000 0.0% $ 1,555,351 $ 1,555,101 $ 250 0.0% $ 2,073,802 99.4% $ 2,042,733 $ 1,878,482 $ 164,251 8.7% $ 2,553,967 40.5% $ 287,136 $ 294,942 $ (7,806) JL$ 361,657 16.9% $ 25,555,489 $ 24,074,182 $ 1,481,308 6.2% $ 33,471,839 (51.1%) $ (178,266) $ 529,246 $ (707,512) (133.7%) $ (1,149,402 71.5% 80.8% 80.6% 52.0% 74.7% 75.0% 80.0% 79.4% 76.3% 15.5% 75% of Year Comp. 2026 2025 Di . %Chna 2026 2025 Di %Chna FullYrBud %of Bud Electric Division Residential 4,379,106 4,533,699 (154,593) (3.41%) 42,527,832 41,980,430 547,402 1.30% 54,016,284 78.7% All Electric 126,237 121,380 4,857 4.00% 1,792,783 1,811,567 (18,784) (1.04%) 2,281,979 78.6% Small General 1,438,702 1,437,107 1,595 0.11% 13,543,885 13,701,847 (157,962) (1.15%) 17,753,235 76.3% Large General 8,707,510 8,738,560 (31,050) (0.36%) 76,849,710 70,192,990 6,656,720 9.48% 92,221,607 83.3% Industrial 8,267,000 8,332,000 (65,000) (0.78%) 74,419,000 75,075,000 (656,000) (0.87%) 97,880,814 76.0% Total KWH Sold 22,918,555 23,162,746 (244,191) (1.05%) 209,133,210 202,761,834 6,371,376 3.14%1 264,153,919 79.2% September September YTD YTD 2026 HUC 2026 2025 Change 2026 2025 Change Budget Target Gross Margin %: 26.4% 29.1% -2.7% 23.8% 28.1% -4.3% 24.7% 24%-28% Operating Income Per Revenue $ (%): -1.3% 5.5% -6.8% -1.8% 1.6% -3.4% -3.6% IIIIIIIIIIIIIIIII Net Income Per Revenue $ (%): 2.9% 6.7% -3.8% -0.7% 2.2% -2.9% -3.6% IIIIIIIIIIIIIIIII Customer Revenue per KWH: $0.1115 $0.0868 $0.0247 $0.1029 $0.0894 $0.0135 $0.1040 $0.1040 Total Power Supply Exp. per KWH: $0.0947 $0.0830 $0.0118 $0.0899 $0.0856 $0.0043 $0.0911 Net Income decreased by $95,210 over September 2025. Customer Revenue was up despite lower usage due to the difference in Power Cost Adjustment. Generator fuels were down with the decrease in sales for resale and transmission expenses continue to be much higher which was budgeted for. The increase in other revenues was due to data center cost reimbursements and the increase in operating expense was due to bond issuance costs. Sales for Resale of $374,134 consisted of $143,134 in market sales, $98,000 in capacity sales to Rice Lake, $70,000 in capacity sales to AEP, and $63,000 in capacity sales to Nextera. September 2025 Sales for Resale of $684,339 included $453,339 in market sales, $98,000 in capacity sales to Rice Lake, $70,000 in capacity sales to AEP, and $63,000 in capacity sales to Nextera. September 2024 Sales for Resale of $389,707 consisted of $145,457 in market sales, $98,000 in capacity sales to Rice Lake and $146,250 in capacity sales to AEP. Overall Purchased Power increased by $216,041. MRES purchases increased by $37,545 and market purchases/MISO costs increased by $178,796. The average cost of MISO power was $30.14/mwh (2,884 mwh's purchased) compared to $31.94/mwh (2,050 mwh's purchased) in September 2025. September 2026 PCA was $.01765/kwhr bringing in an additional $401,408 for the month and $2,243,422 YTD. The 9 month average PCA is $.0106. September 2025 PCA was a credit of $.00865/kwhr crediting customers $198,625 for the month and $384,054 YTD. Gas Division Customer Revenue Transportation Electric Div. Transfer Other Revenues Interest Income TOTAL REVENUES Salaries & Benefits Purchased Gas Operating Expense Depreciation Transfers (City) Debt Interest TOTAL EXPENSES NET PROFIT/(LOSS) HUTCHINSON UTILITIES COMMISSION GAS DIVISION FINANCIAL REPORT FOR SEPTEMBER, 2026 75% of Year Comp. 2026 2025 2 %Chna 2026 2025 2 . %Chna Full YrBud %of Bud $ 614,496 $ 566,321 $ 48,175 8.5% $ 9,882,608 $ 8,315,441 $ 1,567,168 18.8% $ 12,737,529 77.6% $ 176,952 $ 180,360 $ (3,408) (1.9%) $ 1,560,996 $ 1,558,721 $ 2,275 0.1% $ 2,037,588 76.6% $ 60,667 $ 60,639 $ 28 0.0% $ 546,000 $ 545,750 $ 250 0.0% $ 728,000 75.0% $ 48,603 $ 62,035 $ (13,432) (21.7%) $ 340,385 $ 282,346 $ 58,039 20.6% $ 371,093 91.7% $ 25,892 $ 37,522 $ (11,630) (31.0%) $ 180,254 $ 290,101 $ (109,847) (37.9%) $ 275,000 65.5% $ 926,610 $ 906,876 $ 19,733 2.2% $ 12,510,243 $ 10,992,357 $ 1,517,886 13.8% $ 16,149,210 77.5% $ 173,431 $ 188,611 $ (15,180) (8.0%) $ 1,632,426 $ 1,479,036 $ 153,390 10.4% $ 2,346,275 69.6% $ 305,623 $ 312,074 $ (6,451) (2.1%) $ 6,205,071 $ 5,205,137 $ 999,935 19.2% $ 7,780,842 79.7% $ 90,143 $ 53,772 $ 36,372 67.6% $ 888,625 $ 866,062 $ 22,563 2.6% $ 1,237,307 71.8% $ 99,020 $ 97,836 $ 1,185 1.2% $ 892,293 $ 881,031 $ 11,262 1.3% $ 1,130,000 79.0% $ 49,735 $ 49,735 $ - 0.0% $ 447,618 $ 447,618 $ 0 0.0% $ 596,824 75.0% $ 8,667 $ 16,917 $ (8,250) 0.0% $ 78,000 $ 152,250 $ (74,250) 48.8% $ 104,000 75.0% $ 726,620 $ 718,945 $ 7,675 1.1% $ 10,144,034 $ 9,031,133 $ 1,112,901 12.3% $ 13,195,248 76.9% $ 199,990 $ 187,931 $ 12,058 6.4% $ 2,366,209 $ 1,961,224 $ 404,985 20.6% $ 2,953,962 80.1% 75% of Year Comp. 2026 2025 2 %Chnq 2026 2025 p %Chnq Full YrBud %of Bud Gas Division Residential 8,814,968 Commercial 7,744,326 Industrial 45,185,771 7,054,374 8,866,591 49,268,819 1,760,594 (1,122,265) (4,083,048) 24.96% (12.66%) (8.29%) 270,232,463 211,819,733 583,215,761 279,539,470 217,104,261 596,381,130 (9,307,007) (5,284,528) (13,165,369) (3.33%) (2.43%) (2.21%) 410,283,000 317,957,000 820,578,000 65.9% 66.6% 71.1% Total CF Sold 61,745,065 65,189,784 (3,444,719) (5.28%) 1,065,267,957 1,093,024,861 (27,756,904) (2.54%) 1,548,818,000 68.8% September September YTD YTD 2026 HUC 2026 2025 Change 2026 2025 Change Budget Target Gross Margin %: 61.0% 59.0% 2.0% 46.1% 47.5% -1.4% 47.7% Operating Income Per Revenue $ (%): 16.3% 13.5% 2.8% 16.3% 15.1% 1.2% 15.9% Net Income Per Revenue $ (%): 21.6% 20.7% 0.9% 18.9% 17.8% 1.1% 18.3% Contracted Customer Rev. per CF: $0.0069 $0.0065 $0.0003 $0.0074 $0.0067 $0.0007 $0.0069 Customer Revenue per CF: $0.0170 $0.0136 $0.0034 $0.0113 $0.0086 $0.0027 $0.0095 Total N.G. Supply Exp. per CF: $0.0054 $0.0051 $0.0003 $0.0061 $0.0050 $0.0011 $0.0053 Notes/Graphs: September Net Income increased by $12,058. Just like the electric department a large part of the revenue increase was due to a fuel cost adjustment in 2026 while there was a credit in 2025. Fuel Cost Adjustment for September 2026 was $1.34/MCF bringing in an additional $25,111 for the month and $685,762 YTD. September 2025 Fuel Cost "Credit" Adjustment was $1.68441/MCF crediting customers $33,571 for the month and $660,334 YTD. HUTCHINSON UTILITIES COMMISSION BALANCE SHEET - CONSOLIDATED SEPTEMBER 30, 2026 Electric Gas Total Total Net Change Division Division 2026 2025 Total (YTD) Current Assets UnrestrictedlUndesignated Cash Cash (6,934,621.93) 16,257,882.14 9,323,260.21 11,731,816.76 (2,408,556.55) Petty Cash 680.00 170.00 850.00 850.00 - Designated Cash Capital Expenditures - Five Yr. CIP 2,750,000.00 700,000.00 3,450,000.00 3,450,000.00 - Payment in Lieu of Taxes 1,345,802.00 596,824.00 1,942,626.00 1,942,626.00 - Rate Stabilization - Electric 1,301,838.58 - 1,301,838.58 1,443,969.35 (142,130.77) Rate Stabilization - Gas - 542,403.08 542,403.08 615,294.19 (72,891.11) Catastrophic Funds 800,000.00 200,000.00 1,000,000.00 1,000,000.00 - Restticted Cash Bond & Interest Payment 2017 932,713.60 - 932,713.60 789,818.75 142,894.85 Bond & Interest Payment 2012 - 1,638,000.00 1,638,000.00 1,717,666.66 (79,666.66) Debt Service Reserve Funds 1,175,000.00 2,072,000.00 3,247,000.00 3,255,256.00 (8,256.00) Total Current Assets 1,371,412.25 22,007,279.22 23,378,691.47 25,947,297.71 (2,568,606.24) Receivables Accounts (net of uncollectible allowances) 2,993,362.82 543,630.31 3,536,993.13 2,609,862.41 927,130.72 Interest 49,785.32 49,785.33 99,570.65 148,628.57 (49,057.92) Total Receivables 3,043,148.14 593,415.64 3,636,563.78 2,758,490.98 878,072.80 Other Assets Inventory 2,279,072.59 539,216.85 2,818,289.44 2,711,067.64 107,221.80 Prepaid Expenses 285,357.19 95,782.52 381,139.71 456,157.31 (75,017.60) Sales Tax Receivable 181,373.39 - 181,373.39 477,959.47 (296,586.08) Deferred Outflows- Electric 371,991.00 - 371,991.00 342,759.00 29,232.00 Deferred Outflows - Gas - 123,997.00 123,997.00 114,253.00 9,744.00 Total Other Assets 3,117,794.17 758,996.37 3,876,790.54 4,102,196.42 (225,405.88) Total Current Assets 7,532,354.56 23,359,691.23 30,892,045.79 32,807,985.11 (1,915,939.32) Capital Assets Land & Land Rights 690,368.40 3,899,918.60 4,590,287.00 4,590,287.00 - Depreciable Capital Assets 95,284,334.87 45,149,321.56 140,433,656.43 139,453,967.23 979,689.20 Accumulated Depreciation (53,343,421.57) (24,273,689.76) (77,617,111.33) (73,429,602.21) (4,187,509.12) Construction - Work in Progress 15,255,918.52 304,081.75 15,560,000.27 4,913,653.30 10,646,346.97 Total Net Capital Assets 57,887,200.22 25,079,632.15 82,966,832.37 75,528,305.32 7,438,527.05 Total Assets 65,419,554.78 48,439,323.38 113,858,878.16 108,336,290.43 5,522,587.73 Current Liabilities Current Portion of Long-term Debt Bonds Payable Bond Premium Lease Liability - Solar Array Accounts Payable Accrued Expenses Accrued Interest Accrued Payroll Total Current Liabilities Long -Term Liabilities Noncurrent Portion of Long-term Debt 2026B Bonds 2017B Bonds 2012 Bonds Bond Premium 2017 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 SEPTEMBER 30, 2026 Electric Gas Total Division Division 2026 Total Net Change 2025 Total (YTD) 820,000.00 2,080,000.00 2,900,000.00 2,770,000.00 130,000.00 - 185,608.32 185,608.32 185,608.32 - 19,546.00 - 19,546.00 - 19,546.00 4,567,798.32 584,395.09 5,152,193.41 3,727,348.26 1,424,845.15 136,445.80 34,667.00 171,112.80 198,752.12 (27,639.32) 98,040.98 40,423.25 138,464.23 117,148.68 21,315.55 5,641,831.10 2,925,093.66 8,566,924.76 6,998,857.38 1,568,067.38 4,025,000.00 - 4,025,000.00 - 4,025,000.00 10,930,000.00 - 10,930,000.00 11,750,000.00 (820,000.00) - - - 2,080,000.00 (2,080,000.00) 373,602.72 (154,673.97) 218,928.75 437,994.03 (219,065.28) 1,585,328.00 - 1,585,328.00 1,832,248.00 (246,920.00) 42,211.00 - 42,211.00 39,880.00 2,331.00 - 528,443.00 528,443.00 610,749.00 (82,306.00) - 14,071.00 14,071.00 13,293.00 778.00 635,863.89 224,492.28 860,356.17 739,330.02 121,026.15 224,153.38 44,404.41 268,557.79 245,721.73 22,836.06 1,087,158.00 - 1,087,158.00 1,294,449.00 (207,291.00) - 362,386.00 362,386.00 431,483.00 (69,097.00) 19,216,221.58 1,019,122.72 20,235,344.30 19,475,147.78 760,196.52 40,561,502.10 44,495,107.00 85,056,609.10 81,862,285.27 3,194,323.83 40,561,502.10 44,495,107.00 85,056,609.10 81,862,285.27 3,194,323.83 Total Liabilities and Net Position 65,419,554.78 48,439,323.38 113,858,878.16 108,336,290.43 5,522,587.73 Hutchinson Utilities Commission Cash -Designations Report, Combined 9/30/2026 Financial Institution Current Interest Rate Annual Interest Balance, September 2026 Balance, August 2026 Change in Cash/Reserve Position Savings, Checking, Investments varies varies varies 23,378,691.47 19,448,394.91 3,930,296.56 Total Operating Funds 23,378,691.47 19,448,394.91 3,930,296.56 Debt Reserve Requirements Bond Covenants - sinking fund Debt Reserve Requirements Bond Covenants -1 year Max. P & I Total Restricted Funds Operating Reserve Rate Stabalization Funds PILOT Funds Catastrophic Funds Capital Reserves Total Designated Funds Min 60 days of 2026 Operating Bud. Charter (Formula Only) Risk Mitigation Amount 5 Year CIP (2026-2030 Fleet & Infrastructure Maintenance) 2,570,713.60 2,290,242.24 280,471.36 3,247,000.00 3,247,000.00 - 5,817,713.60 5,537,242.24 280,471.36 7,079,514.50 7,079,514.50 - 1,844,241.66 1,819,130.33 25,111.33 1,942,626.00 1,942,626.00 - 1, 000, 000.00 1, 000, 000.00 3,450,000.00 3,450,000.00 - 15,316,382.16 15,291,270.83 25,111.33 YE YE YE YE YTD HUC 2022 2023 2024 2025 2026 Target Debt to Asset 31.4% 28.6% 26.0% 22.3% 25.3% Current Ratio 4.47 4.48 3.67 3.10 2.88 RONA -1.38% 1.96% 2.63% 3.23% 2.21% Historical Change in Cash Balance Month End Electric Elec. Change Natural Gas Gas Change Total Total Change 9/30/202 6 1,371,412 22, 007, 279 23, 378, 691 12/31/2025 (416,323) 1,787,735 18,975,091 3,032,188 18,558,768 4,819,923 12/31/2024 6,134,710 (6,551,033) 17,717,453 1,257,638 23,852,164 (5,293,396) 12/31/2023 12,158,338 (6,023,628) 15,622,242 2,095,211 27,780,580 (3,928,416) 12/31/2022 11,633,212 525,126 15,450,554 171,688 27,083,766 696,815 12/31/2021 12,870,253 (1,237,041) 15,086,000 364,554 27,956,253 (872,487) 12/31/2020 14,239,233 (1,368,981) 15,019,173 66,827 29,258,406 (1,302,153) 12/31/2019 12,124,142 2,115,092 13,837,040 1,182,133 25,961,181 3,297,225 12/31/2018 15,559,867 (3,435,725) 12,335,998 1,501,042 27,895,864 (1,934,683) 12/31/2017 23,213,245 (7,653,378) 10,702,689 1,633,309 33,915,934 (6,020,070) 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 Significant increase in cash balance is due to issuing bonds for the generator project. Hutchinson Utilities Commission Cash -Designations Report, Electric 9/30/2026 Change in Financial Annual Balance, Balance, Cash/Reserve Institution Current Interest Rate Interest September 2026 August 2026 Position �' Rr Savings, Checking, Investments varies varies varies 23,378,691.47 19,448,394.91 3,930,296.56 Total HUC Operating Funds 23,378,691.47 19,448,394.91 3,930,296.56 Debt Restricted Requirements Debt Restricted Requirements Total Restricted Funds Bond Covenants - sinking fund Bond Covenants -1 year Max. P & 1 932,713.60 1,175,000.00 2,107,713.60 834,242.24 1,175,000.00 2,009,242.24 98,471.36 - 98,471.36 Excess Reserves Less Restrictions, Electric (736,301.35) (4,313,720.57) 3,577,419.22 J11J! !!1 1 !1 J Operating Reserve Min 60 days of 2026 Operating Bud. 5,068,639.83 5,068,639.83 Rate Stabalization Funds $400K-$1.2K 1,301,838.58 1,301,838.58 PILOT Funds Charter (Formula Only) 1,345,802.00 1,345,802.00 Catastrophic Funds Risk Mitigation Amount 800,000.00 800,000.00 Capital Reserves 5 Year CIP (2026-2030 Fleet & Infrastructure Maintenance) 2,750,000.00 2,750,000.00 Total Designated Funds 11,266,280.41 11,266,280.41 Excess Reserves Less Restrictions & Designations, Electric 00 (15,580,000.98) YE YE YE YE YTD APPA Ratio HUC 2022 2023 2024 2025 2026 5K-10K Cust. Target Debt to Asset Ratio (* w/Gen.) 34.8% 34.0% 33.9% 31.6% 38.0% 39.8% pp ppppp ryry NNNNNNNNNNNN Current Ratio 4.96 4.35 2.38 0.80 0.90 3.75 >2.0 RONA -4.2% -0.9% -2.1% 0.4% -0.3% NA >0% Hutchinson Utilities Commission Cash -Designations Report, Gas 9/30/2026 Change in Financial Annual Balance, Balance, Cash/Reserve Institution Current Interest Rate Interest September 2026 August 2026 Position F�' Rr Savings, Checking, Investments varies varies varies 23,378,691.47 19,448,394.91 3,930,296.56 Total HUC Operating Funds 23,378,691.47 19,448,394.91 3,930,296.56 Debt Restricted Requirements Bond Covenants - sinking fund 1,638,000.00 1,456,000.00 182,000.00 Debt Restricted Requirements Bond Covenants -1 year Max. P & 1 2,072,000.00 2,072,000.00 - Total Restricted Funds 3,710,000.00 3,528,000.00 182,000.00 Excess Reserves Less Restrictions, Gas 18,297,279.22 18,224,873.24 72,405.98 1 1 JJJ1 111 1 11 J J Operating Reserve Min 60 days of 2026 Operating Bud. 2,010,874.67 2,010,874.67 - Rate Stabalization Funds $200K-$600K 542,403.08 517,291.75 25,111.33 PILOT Funds Charter (Formula Only) 596,824.00 596,824.00 - Catastrophic Funds Risk Mitigation Amount 200,000.00 200,000.00 Capital Reserves 5 Year CIP (2026-2030 Fleet & Infrastructure Maintenance) 700,000.00 700,000.00 - Total Designated Funds 4,050,101.75 4,024,990.42 25,111.33 YE YE YE YE YTD HUC 2022 2023 2024 2025 2026 AGA Ratio Target Debt to Asset 26.5% 21.0% 15.5% 10.6% 8.1% 35%-50% Current Ratio 4.06 4.61 5.08 5.18 6.68 1.0-3.0 RONA 3.0% 6.2% 9.1% 7% 5.7% 2%-5% Notes/Graphs: ELECTRIC DIVISION Operating Revenue September 2026 CLASS AMOUNT KWH /KWH Street Lights 28,464.02 404 $70.4555 Electric Residential Service $585,215.15 4,379,106 $0.1336 All Electric Residential Service $19,484.66 126,237 $0.1543 Electric Small General Service $185,765.63 1,438,702 $0.1291 Electric Large General Service $939,865.66 8,707,510 $0.1079 Electric Large Industrial Service $797,108.20 8,267,000 $0.0964 Total $2,555,903.32 22,918,959 $0.1115 Power Adjustment $0.01765 Rate Without Power Adjustment $0.09387 Electric Division Year -to -Date ® 2026 $ Amount ❑ 2025 $ Amount ® 2026 KWH110 ❑ 2025 KWH110 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 0 Residential All Elec. Resid. Small Gen. Srv. Large Gen. Srv. Large Industrial Sales For Resale Total NOTE: This graph includes sales for resale (capacity and energy sales) but excludes street lights and security lights NATURAL GAS DIVISION Operating Revenue September 2026 CLASS AMOUNT MCF /MCF Residential $171,729.59 8,815 $19.4816 Commercial $124,636.11 7,744 $16.0939 Large Industrial $22,699.99 2,182 $10.4044 Large Industrial Contracts $295,430.15 43,004 $6.8698 Total $614,495.84 61,745 $9.9521 Fuel Adjustment $1.34000 Rate Without Fuel Adjustment $8.61215 Natural Gas Division Year -to -Date ❑ 2026 $ Amount ❑ 2025 $ Amount m 2026 MCF ❑ 2025 MCF 12,000,000 10,000,000 8,000,000 6,000,000 4,000,000 2,000,000 0 Gas Residential Gas Commercial Large Industrial Large Industrial Total Contracts x Z E 7 E a` N_ (6 C R a w 0 ro ro a� Z N C Z Z Z Z Z Z Z Z Z �2 Z Z � Q o rnrnvorn- o (n ro O (n 'T O d' O) O ro o ao n vro f� 01 01 ro(O ro� N o646 O 4 m (n N v N Lo W ro N dT a) orl-W d' (n N (n ro (O � (n O) dt dt r-- (-4 (O M (n r-- ro O) (O 0W 61 NN N NMNO(0NON i f� 01 ro N N N N (O O M ; 0 0 0 0 0 0 0 ,. ro o dt .0000000 ro ro N 01 ro 0 0 0 0 0 0 0 0 0 0 N O O ro N 0 0 0 0 0 0 0 (n 0 (n M M ro N N N N N N N (n (n o 0 0 (n o (n o (n o 0 0 (n N' LQ (o(n(ooro(on rnrnvvv(n dT rl- (O ro rl- M M (n (n M r-(O r-M Oro dT dT dT Md' N (n O (n d' M rl- N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N O O O N O N N N O O N N (n � (n d' M ro N N N N N N N U n rl- ro ro ro n a ZZZZZZZZZZZZ?:ZZZZ'nZZZOZZOZZZZOZOZZO N 6) ro M o 61 d' ao OotrnoowaooiZvrn f� (nnoon(n 01 d'OM V f�(n d'(0000�OroN001 ro(n (O d'Nd'f� d'(O ao(ri(ri��aoriroaonn(000�(riri(ri�(ri��aon�(riaorooirn(riori f� N 01ro Nf� M ro01 (ON d'M roM �O (nN 000� V f� (00 d'01 d'� f� 01 f� V N MM (nN f�f� V ro d'M �001ro N(n d'ro O-01 MO oc 1 r� Mfg Oni MN Mr-- O) r--(O (nN MN d'rv7(n N� �� 0 r--rOr�� roN vd'd' N � � � � v M N W ON�N 0�1 d'�NMro W d'MMN(roO�ON�O W O0M (ro0 V V W M V �( M NN d'N(n 01 NO1 1(nM V O M(NO W rN ON1 N�NNM V ��(Oro roN! 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J W N (M V In C C moIEEE N ,r y 0 > � O o O o O o O o w f � J O O O o o o O o O N O o O o O o O Go O o o O O o o o o ui o O in ao m r- o o u, v O7 LO v LO v 00 O V (0 of N -° O M M 0 m C m O L N O V (0 (0 N kO M 0 0 U M vT y M O 6- ER N E N N � � O > O .2 M C O f6 00 M 00 7 O C7 7 o F N;: N M O l OM V V O O (G N E In 0) V N W N i 00 O N W M N LO M I- V V oc V N V 00 M N �O W O F M (O f0 c c 0 c o ,w � p N N N M N O © o o M- F N M O_ N LO O O h uuuuuuuuWMWOV VVVVVVVVVVVVV VVVVVVVVVO(V VVVVVV �'lu "i N 00 I- N �.,. N V Oo Oo N VVVV O N 2 (o V M o N i O O (0 00 O O 00 (0 O o WO P w T M (0 f0 0 F � VT 1 a, o 1 Fc N N rn J O -a Q O t; m 0 F 7 0 Y o 0co `m F '�'' III +• Y d _ N Q f6 A i U � N N N o O M U (7 0 Work Order Descri; Lion 12402 Plant 1 Combustible Gas Detection System 12502 Rubber Roof Repair West Portion of Plant 1 12503 Plant 1 Pump Room Ventilation 12504 Plant 1 Control Panel Upgrade 12505 Unit 1 CO2 System Update Code Compliance 12506 Cooling Tower Recirc and Chem Injection 12507 Plant 1 North Ground Fans 12601 Power Gates Plant 2 12602 Plant 1 and 2 Cooling Tower VFD's 12603 Unit 5 HUG Upgrade 12604 Plant 1 Web Master Upgrade 12605 Rooftop Solar 12606 Unit 1 LPT Stage 2 Blade Replacement Electric Production Total Total Materials Labor Budgeted Actual Difference 46,384.67 46,384.67 60,000.00 - 60,000.00 (60,000.00) 50,000.00 5,000.00 55,000.00 (55,000.00) 148,067.00 148,067.00 28,542.83 (119,524.17) 35,000.00 35,000.00 (35,000,00) 130,000.00 130,000.00 22,519.95 (107,480.05) 50,000.00 50,000.00 (50,000.00) 80,000.00 - 80,000.00 24,210.00 (55,790.00) 40,000.00 5,000.00 45,000.00 20,699.10 (24,300.90) 351,000.00 - 351,000.00 - (351,000.00) 7,870.00 7,870.00 - (7,870.00) - - - 310,619.80 310,619.80 951,937.00 $ 10,000.00 $ 961,937.00 $ 452,976.35 $ (508,960.65) Work Order Descriration 22301 Hutch Sub Transformer Upgrade Engineering 22401 Hutch Substation Transformer 22402 McLeod Sub Relay Replacement 22405 3M Sub SCADA Phase 2 22503 Plant 1 Sub Circuit Breakers 22504 Plant 1 Sub Rebuild Distribution 22522 Data Center 22601 Willmar Line Rebuild 22602 Plant 1 Sub Rebuild Transmission 22603 Pole Repair and Replacement 22604 Station Equipment 22605 Plant 1 Batteries 22606 Install Duct 22607 Reconductor Feeder 19 22608 New Developments 22609 Then Landing Apartments 22610 Burns Manor Apartments 22611 The Farmhouse Memory Care 22612 Scooters Coffee 22613 Plant 1 Sub Rebuild XFMR 22614 Transformer Replacements 22615 Transformer New Developments 22616 The Landing Apartments 22617 Burns Manor Apartments 22618 The Farmhouse Memory Care 22619 Scooters Coffee 22620 Meters 22621 LED Street Light Conversion Electric Distribution Total Total Materials Labor Budgeted Actual Difference 10,417,571.05 10,417,571.05 2,694,564.65 2,694,564.65 400,000.00 400,000.00 22,993.00 (377,007.00) 90,068.66 90,068.66 112,497.00 112,497,00 84,231.10 84,231.10 20,000.00 5,000.00 25,000.00 338,902.95 313,902.95 15,000.00 15,000.00 (15,000.00) 10,000.00 - 10,000.00 (10,000.00) 15,000.00 2,500.00 17,500.00 - (17,500.00) 18,000.00 65,000.00 83,000.00 27,809.44 (55,190.56) 80,000.00 20,000.00 100,000.00 152,049.49 52,049.49 60,000.00 15,000.00 75,000.00 50,746.14 (24,253.86) 15,000.00 5,000.00 20,000.00 27.17 (19,972.83) 15,000.00 5,000.00 20,000.00 347.08 (19,652.92) 7,000.00 2,000.00 9,000.00 126.29 (8,873.71) 7,000.00 2,000.00 9,000.00 - (9,000.00) - - - 252,675.74 252,675.74 50,000.00 15,000.00 65,000.00 2,119.26 (62,880.74) 60,000.00 15,000.00 75,000.00 923.78 (74,076.22) 20,000.00 2,000.00 22,000.00 2,523.53 (19,476.47) 20,000.00 2,000.00 22,000.00 - (22,000.00) 20,000.00 2,000.00 22,000.00 (22,000.00) 15,000.00 2,000.00 17,000.00 - (17,000.00) 36,000.00 36,000.00 39,741.54 3,741.54 175,000.00 175,OOOA0 ��.�... - 175,000.00 $ 1,058,000.00 $ 159,500.00 $ 1,217,500.00 ....a.-- ...- $ 14,289,917.87 13,072,417.87 Natural Gas Work Order Description Materials 62511 DRS #5 Upgrades 23,500.00 62601 Misc Developments & System Improvements 25,000.00 62602 City Projects 10,000.00 62603 Install 6" Line from Plant 1 to School Road 370,000.00 62604 Improvements to Regulator Stations 10,000.00 62605 Make DRS#11 at Plant 1 14,000.00 62606 Service Lines, The Landing, Burns Manor 65,000.00 62607 Service lines to Hjerpe - 62608 Meters, AMI, and All Fittings 250,000.00 62609 Residential Regulators - 62610 Industrial Metering and Regulation 25,000.00 62611 3m Boiler Bypass Rund 3,000.00 62612 Fairfax Micro Motion Elite Coriolis Meter - $ 79 5,500.00 Total Total Labor Budgeted Actual Difference 2,000.00 25,500.00 3,746.24 (21,753.76) 5,000.00 30,000.00 9,152.75 (20,847.25) 4,000.00 14,000.00 2,357.87 (11,642.13) 12,000.00 382,000.00 150,320.46 (231,679.54) 3,500.00 13,500.00 8,495.78 (5,004.22) 2,000.00 16,000.00 6,304.48 (9,695.52) 15,000.00 80,000.00 38,562.67 (41,437.33) - - 20,557.01 20,557.01 10,000.00 260,000.00 33,428.56 (226,571.44) - - 1,066.70 1,066.70 3,500.00 28,500.00 292.74 (28,207.26) 3,000.00 6,000.00 4,684.56 (1,315.44) 25,085.68 25,085.68 $60,000.00 $ 855,500.00 $ 304,055.50 $ (551,444.50) HUTCHINSON UTILITIES COMMISSION 9 Board Action Form iiiiiiiiiiiiiiiiiiiiiillillillillillillilliillillillillillillilliilliillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliilllI Agenda Item: Review Policies Presenter: Angie Radke Agenda Item Type: Time Requested (Minutes): 5 Review Policies Attachments: Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: 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: i. Natural Gas Service Requirements & Charges ii. Temporary Service — Natural Gas iii. Natural Gas Meter Requirements & Placement iv. Meter Testing — Natural Gas v. Natural Gas Service Work vi. Locating Customer's Underground Utilities — Natural Gas BOARD ACTION REQUESTED: None Fiscal Impact: Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: Remaining Cost: SERVICE POLICIES — NATURAL GAS Natural Gas Service Requirements and Charges HUC shall not install any facilities until all affected properties are within 6 inches of final grade. HUC shall furnish and install the underground natural gas service line. The service line to the meter shall remain the property of HUC. Type/Size Fee Single-family residential — W I PS $600 — up to 150 ft. plus $4.00/ft. in excess of 150 ft. Multi-family/Commercial/Industrial — %" IPS $950 — up to 100 ft. plus $7.50/ft. in excess of 100 ft. Multi-family/Commercial/Industrial — 2" IPS $1900 — up to 100 ft. plus $9.00/ft. in excess of 100 ft. Industrial — 4" IPS and larger Time and Material Expense Service line length is defined as "distance from customer's property line to metering facilities", or in the instance the distribution main is located in rear easement, "distribution main to metering facilities". No structure or building may be located over natural gas lines or metering facilities. In the event that a structure or building is determined to be located over natural gas facilities, the natural gas facility must be relocated to a mutually agreed upon location. The customer shall be responsible for all costs associated with the relocation. No service line valve or any portion of the natural gas metering facilities may be buried. The customer shall be responsible for all costs incurred in raising all facilities. In the event owner requires relocation of the installed natural gas service line, Owner agrees to pay Hutchinson Utilities Commission the entire cost of relocating the service line as billed. Hutchinson Utilities Commission agrees to use its best efforts in repairing the premises in a workman -like manner and returning the premises to the same or similar condition as existed prior to establishing or repairing the underground service line. Hutchinson Utilities Commission shall begin installing excess flow valves, as of April 14, 2017, on all newly installed and replacement service lines serving the following types of services before the line is activated: A single service line to one single-family residence; A branched service line to a single-family residence installed concurrently with the primary single-family residence service line (i.e., a single EFV may be installed to protect both service lines); A branched service line to a single-family residence installed off a previously installed single-family residence service line that does not contain an EFV; Multifamily residences with known customer loads not exceeding 1,000 SCFH per service, at time of service installation based on installed meter capacity, and • A single, small commercial customer served by a single service line with a known customer load not exceeding 1,000 SCFH, at the time of meter installation, based on installed meter capacity. Hutchinson Utilities shall install either a manual service line shut-off valve or, if possible, based on sound engineering analysis and availability, an excess flow valve for any new or replaced service line with installed meter capacity exceeding 1,000 SCFH. All new natural gas consumer -owned fuel lines, downstream of the metering facilities, must be pressure tested, prior to the gas meter being set. The test must be verified by an approved inspector. Installation of Natural Gas Service Lines — November 1 through March 31 Final determination on installation of natural gas service lines during this time shall be made by HUC. K Temporary Service HUC does not offer temporary natural gas service. Natural Gas Meter Requirements and Placement HUC shall furnish and install the natural gas meter at no charge to the customer. HUC reserves the right to specify the natural gas meter location on all installations. All meters must be located on an external wall of the building, at a horizontal distance of no less than 3 feet from fresh air intakes, windows or door openings. New construction natural gas meters must be located within 10 feet of the electric meter if HUC is providing both services. Access to all natural gas meters shall not be obstructed. Natural gas meters shall be located in ventilated spaces readily accessible for examination, reading, replacement or necessary maintenance. Decks, porches, etc. shall not be constructed over a natural gas meter. Natural gas meters shall not be located where they will be subject to damage, such as adjacent to a driveway or other locations subject to vehicular traffic, in public passages, where they will be subject to excessive corrosion or vibration or in areas subject to ice and snow damage. Natural gas meters shall not be installed directly beneath external stairways. Natural gas meters shall not be located where they will be subjected to extreme temperatures or sudden extreme temperature changes (e.g., air ducts, dryer vents). Manufacturer's installation specifications shall be adhered to when installing fresh air intake and exhaust terminations near natural gas metering facilities. Natural gas regulators shall be located - no less than 3 feet from any source of ignition or any source of heat that may damage the facilities. HUC requires a minimum of a 3-foot clear zone in front of the natural gas meter. Reasonable care must be taken to protect all metering facilities when remodeling, roofing, painting, etc. In the event of damage to the natural gas facilities, the customer shall be responsible for the cost of repairing or replacing the natural gas facilities. Conditions may exist which may require additional restrictions or distances (e.g. multiple meters, etc.). Please contact HUC if you should have any questions regarding your natural gas metering facilities. Modifications made to the customer's metering facilities, necessitated by customer changes, shall be performed by HUC, at the customer's expense. C! All natural gas service lines retired due to building demolition, overbuilding, etc. shall be retired at the customer's expense. HUC Natural Gas Division performs all retirement work on natural gas facilities. Estimate is provided by HUC Natural Gas Division when requested. All exceptions require the approval of HUC prior to the start of construction. if violations or deviations are determined, the customer shall be responsible for the cost of the correction. Single Family Dwellings HUC shall provide natural gas to residential customers at the standard delivery pressure of 7 inches of water column, measured at the inlet to the natural gas meter. All residential natural gas metering facilities shall be located on the side of the home within 6 feet of the front building wall. Front building wall is defined as the wall nearest the street of the resident's living space. Multi -Family Dwellings/Multiple Business Establishments Delivery pressures greater than 7 inches of water column, for multi -family and multiple business establishments, shall only be allowed by the prior approval of HUC. The customer must provide adequate over -pressure protection for all fuel lines subject to increased delivery pressure. The single metering of multiple -family dwellings, apartment buildings or multiple business establishments within a single building is permitted to the extent that each building is centrally heated. Individual metering is required for all individually heated, single-family private residences and each separately heated, owned and/or operated business. Please contact HUC for specifications regarding meter facilities. Commercial/Industrial Facilities Delivery pressures greater than 7 inches of water column, for commercial and industrial applications, shall only be allowed by the prior approval of HUC. The customer must provide adequate over -pressure protection for all fuel lines subject to increased delivery pressure. Please contact HUC for specifications regarding meter facilities. Meter Testing HUC shall periodically test all natural gas meters for accuracy and sound mechanical condition. Meters that have an average incest accuracy of 100, ± 2%, shall be considered accurate. Average accuracy is defined as the average of the open and check flow accuracies. Accounts for which the natural gas meter tests in excess of 102% are subject to a refund. This refund shall be based on the "as found average meter accuracy" and the customer's consumption for the previous six month period. Upon request of the customer, HUC shall test the average accuracy of the natural gas meter. A $40 trip charge may be assessed to all accounts in which the "as found average meter accuracy" is determined to be 102% or less. Natural Gas Service Work HUC personnel shall perform leak investigation and carbon monoxide testing at no charge to the customer. HUC does not perform service work on customer owned facilities. rA Locating Customer's Underground Utilities HUC shall locate all natural gas underground distribution and transmission facilities up to the meter at no charge to the customer or landowner. �;a HUTCHINSON UTILITIES COMMISSION Board Action Form �rre tit' Agenda Item: Approve Policy Changes Presenter: Angie Radke Agenda Item Type: Time Requested (Minutes): 5 Changes to Policies Attachments: Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: As part of HUC's standard operating procedures, a continual policy review is practiced. The following revisions to the policies below are recommended. i. Rate Schedule — Electric ii. Rate Schedule — Natural Gas iii. Security Light Rental — Rate to Furnish and Maintain Fixture BOARD ACTION REQUESTED: Approve Policy Changes Fiscal Impact: Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: Remaining Cost: ELECTRIC Rate Schedule Electric Residential Service Code 10 -Available for domestic purposes only, in a single or multiple residence. All newly connected multiple dwelling units shall have one meter per unit, and a house meter. Energy charge: 9,040773.. cents per KWH Monthly Customer charge: $17.2030 Electric Small General Service Code 30 - Applicable to any customer for single or three phase electric service with less than 50 KW demand supplied through one meter at the secondary voltage at that location. At any time the customer demand reaches 50 kilowatts for three consecutive months, the customer will be removed from the Electric Small General Service rate and billed under Electric Large General Service rate. Energy charge: First 2000 KWH per month --- .2..:: �-901 .49 7 cents per KWH Over 2000 KWH per month --- &;K949,423 cents per KWH Monthly Customer Charge: $28.50 Electric Large General Service Code 40 Code 41 - Applicable to any customer for combined power and lighting with a minimum demand of 50 kilowatts for single or three phase electric service supplied through one meter at the secondary voltage at that location. If demand drops below 50 kilowatts for 12 consecutive months, the customer will be removed from Electric Large General Service rate and billed under Electric Small General Service. Demand charge: $44-5-912,00 per KW Energy charge: &932 6,276 cents per KWH Monthly Customer Charge $152.30 Minimum monthly charge: 75% of the maximum demand charge -the maximum demand is the customer's peak usage over the previous 12 months. SERVICE AT PRIMARY VOLTAGE: Customer owns/maintains facilities, and service provided at primary voltage - a 5% discount will be applied to the energy charge. This adjustment includes a discount for primary metering. HUC owns/maintains facilities, and service provided at primary voltage - a 2% discount will be applied to the energy charge. POWER FACTOR PENALTY: A power factor penalty will apply if the customers measured power factor drops below .94. Large Industrial Service Code 50 and 51 — Applicable to any customer for combined power and lighting with a minimum demand over 4000 KW during any one month in a 12 month period. Service will be delivered at the primary voltage available at the customer's property line. The customer will own and maintain all electrical facilities on the customer's side of the metering transformer. Demand Charge: Energy Charge: Monthly Customer Charge $12.5075 per KVA 5.44,54925 cents per KWH $4 2....... 75.00 Power Cost Adjustment - Power cost adjustment is based on the combined costs of purchased power from outside suppliers, fuel (natural gas and fuel oil), and unrecovered or excess revenues from previous month. Computations of power adjustments shall be made monthly. The resultant adjustment, if any, shall be applicable for the month. NATURAL GAS Rate Schedule Residential Code 60 — Available to any customer who uses less than 70 MCF of gas per day. Gas Commodity Charge: $7.10000425 per MCF, or $.0071000425 per CF Monthly Customer Charge:$ ... 1 3. 1 Commercial Gas Code 65 — Available to any customer who uses less than 200 MCF of gas per day. Gas Commodity Charge: $7.14441127per MCF, $.00 "14441127per CF Monthly Customer charge: $1 70-1.00 1. Large Industrial Gas Code 89 Code 91 — Available to all customers who use in excess of 200 MCF of gas per day. The demand level shall be based on the maximum daily volume (MCF per day) of natural gas delivered to the customer per month. Demand Charge Gas Commodity Charge $8.00 per MCF $7.54005636 per MCF, or $.00754005636 per CF Monthly Customer Charge: $34370068,50 Minimum Monthly Charge: The demand charge for month. Fuel Cost Adjustment — Fuel cost adjustment is based on the combined cost of purchased gas and unrecovered or excess revenues from previous month. Computations of fuel adjustment shall be made monthly. The resulting adjustment, if any, shall be applicable for the month. All rates are subject to fuel cost adjustment. Security Light Rental — Rate to Furnish and Maintain Fixture HIGH PRESSURE SODIUM: Monthly Monthly Lamp Size Charge Lamp Size Charge 70 watt LED metered $3....4264 70 watt LED unmetered $ :;K.99...3. 1 Lights will be dusk to dawn type with photo control and will be installed on existing pole in the area. If a new pole is needed, customer will pay for the pole and installation. All new installations will be High Pressure Sodium. All rates subject to power cost adjustment. HUTCHINSON UTILITIES COMMISSION ^I'xP61Tti'°" Board Action Form Agenda Item: Approve Audit Services Presenter: Jared Martig Agenda Item Type: Time Requested (Minutes): 2 New Business Attachments: No BACKGROUND/EXPLANATION OFAGENDA ITEM: Audit services for fiscal year 2026 was quoted by Conway Deuth & Schmiesing at $32,750. Below is a history of audit fees. 2025: $31,250 2024: $30,000 2023: $28,500 2022: $26,000 2021: $24,850 2020: $24,750 2019: $24,750 2018: $24,750 2017: $23,200 2016: $22,750 2015: $22,525 2014: $21,950 2013: $21,950 2012: $21,500 2011: $21,250 BOARD ACTION REQUESTED: Approve fiscal year 2026 audit services with Conway Deuth & Schmiesing Fiscal Impact: $32,750 Included in current budget: Yes Budget Change: No PROJECT SECTION: Total Project Cost: Remaining Cost: t bD o C O •U � fC m cu IIYa" O Qj �u o� Y 41 QJ a.r C n� � � m O � � N �116 O C) a •y O co � �` N L IL^ V m min w louu � C lui�up V IW � o� O O d -0 O O E &i %A Ip— ;A +Z Q Ln n N cn O G1 fl) � ➢wd fC bo QJ O U E f� N m O — 0 N � *—'u La M 1A CD , {A CO to O N N C O E a1� C O O -0 M �O o a� Q >Z) c 4-7 a c 'o. O C +C O C ?� N +�+ O O. C vOi p �. O 4J ? U v Q y L M +_ O is N to 'a .O C ul O V O L Cl) u O n L atw `^ .M N � 'L E V) O O ? O 41 U1 O O U ci E :3 CC C X 'L E L u ow 41 Q) O in m OD 0 M O O Ln Q E s a 0 , o V L L 0 — 1ii no U O C O S- > UJ L toL Z Q- f° 'i S .� O � a� 41 ai J f4 y 041 �- C O O A CL 41 W 'aO�.r E f 6 -M C � O c ru E w E v Z LO 0 E O `o E HUTCHINSON UTILITIES COMMISSION ^I'�xP61Tti'°" Board Action Form Agenda Item: Approve Level of Renewable Energy Credits for 2027 Presenter: Jeremy Carter Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments: Yes BACKGROUND/EXPLANATION OFAGENDA ITEM: Each Year HUC is required to notify Missouri River Energy Services (MIRES), HUC's wholesale supplier on the participation level for carbon free/renewable energy for the upcoming year. The requirement deadline is Nov 9, 2026 of this year. MIRES through the Bright Energy Choices program sets aside current carbon free & renewable attributes from either currently owned assets, market purchases or bilateral contracts for carbon free/renewable energy from other companies. MIRES maintains an inventory of Renewable Energy Credits (REC's) that are used to meet State regulatory compliance or local municipal utility carbon free/renewable energy goals. For the coming year of 2027, HUC is starting off with 22% Carbon Free Energy from the MISO market before purchasing additional REC's. This is a decrease of 3% from 2026 where HUC started with 25% Carbon Free energy. The 3% reduction is from a reduction in Market purchases that can be claimed as renewable. Attached is a summary table of various options to consider that will impact the 2027 budget. 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