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03-28-2018 HUCCPHUTCHINSON UTILITIES COMMISSION AGENDA REGULAR MEETING March 28, 2018 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. Legal d. General Manager 6. POLICIES a. Review Policies i. Sealing of Meters — Electric ii. Meter Testing - Electric iii. Right -of -Way Clearing iv. Promotions and Transfers v. Layoffs vi. Voluntary Leave of Absence b. Approve Changes i. Electric Meter Placement 7. UNFINISHED BUSINESS a. Update on Pack Gas Discussions 8. NEW BUSINESS a. BP to present on Prepay program b. Approval of `Incumbency Certificate' and `Board Resolution' C. Approval of Natural Gas Truck Requisition d. Approval of Pack Gas Settlement Agreement e. Discussion of COS Rate Track scenarios 9. ADJOURN MINUTES Regular Meeting — Hutchinson Utilities Commission Wednesday, February 28, 2018 Call to order — 3:00 p.m. President Monty Morrow called the meeting to order. Members present: President Monty Morrow; Vice President Anthony Hanson; Commissioner Mark Girard; Commissioner Don Martinez; General Manager Jeremy Carter; Attorney Marc Sebora Absent: Secretary Robert Wendorff Conflict of Interest 2. Approve Consent Agenda a. Approve Minutes b. Ratify Payment of Bills Motion by Commissioner Hanson, second by Commissioner Girard to approve the Consent Agenda. Motion carried unanimously. 3. Approve Financial Statements Jared Martig presented the financial statements. On the Gas Division, there was a net profit increase in January 2018 by $128K over January 2017. There was not a fuel cost adjustment for January 2018 due to depleting the rate stabilization fund in December. An additional $137K was added to the fund in January. On the Cash side, overall Cash increased due to an error in BP's December invoice leading to not receiving the invoice until February. GM Carter added on the Electric Division, Sales for Resale and purchase power increased due to the Transalta contract After discussion, a motion by Commissioner Girard, second by Commissioner Martinez to approve the financial statements. Motion carried unanimously. 4. Open Forum 5. Communication a. City Administrator— Matthew Jaunich- Absent b. Divisions Dan Lang, Engineering Services Manager —Nothing to report Dave Hunstad, Electric Transmission/Distribution Manager — 1. For the monthly outage report there was nothing to report for January, so included is the annual report for 2017. HUC is trending well. If there are no outages for the month, this type of report format will be reported quarterly. iii. Randy Blake, Production Manager - 1. Disassembly of Unit 2 is continuing. 2. Reiner Contracting is well underway of finalizing the contract just waiting on the performance & payment bonds. Communication from Jim Booty will take place when everything is finalized and the project will then proceed. 3. Had a Mechanic opening. Mike Gabrielson who was a plant operator has now been hired as a mechanic. 4. Currently now have an Internal posting up for a Plant Operator position which was vacated by Mike Gabrielson. If HUC does not fill internally, this will be posted externally. 5. CAT drawings are due this month. CAT engineers will be in Hutchinson next week. iv. John Webster, Natural Gas Division Manager- 1. Completing some NG work for new facilities at plant 1 v. Jared Martig, Financial Manager- Nothing to report c. Human Resources - Brenda Ewing — Absent d. Legal — Marc Sebora — Nothing to report e. General Manager — Jeremy Carter i. Working on 2018 objectives ii. Following up on COS Study 6. Policies a. Review Policies i. Electric Service Requirements & Charges ii. Temporary Service — Electric iii. Hiring iv. Probationary Period Upon Hiring v. Temporary Employees No changes recommended at this time. b. Approve Changes i. CIP Rebate Level of Authority - as noted, adding clarity ii. Service Beyond City Limits of Hutchinson - as noted, grammatical changes clarification iii. Purchasing Policy - Had Marc Sebora review and give more minimum requirements and flexibility. Motion by Commissioner Hanson, second by Commissioner Girard to approve the policy changes as recommended. Motion carried unanimously. 7. Unfinished Business a. Update on Pack Gas Discussions - GM Carter noted HUC received a draft settlement agreement today, will be reviewing this document with Marc Sebora this week and should bring something forth in March. 2 8. New Business a. Approval of Extension of Northern Natural Gas Transportation Contract #102733 John Webster presented the Extension of Northern Natural Gas Transportation Contract #102733. This provides a secondary supply of natural gas to the City of Hutchinson in the event of a catastrophic failure to the HUC natural gas transmission line. A small price to pay to keep two stations available here for an emergency. Motion by Commissioner Hanson, second by Commissioner Martinez to approve Extension of Northern Natural Gas Transportation Contract #102733. Motion carried unanimously. (Contract attached.) b. Approval of (2) 2018 GMC 1/2T Pickups Requisition #7461 At this time, GM Carter reviewed the Fleet program. Dave Hunstad has inventoried all HUC's equipment and has maintained the fleet management program of changes. Important for the Commission to know that HUC is managing and keeping within the guidelines. Dan Lang presented Requisition #7461 to purchase (2) 2018 GMC 1/2T Pickups in the amount of $52,158.44. One pickup is for the Engineering Services department and one pickup is for the Electric production department. Motion by Commissioner Girard, second by Commissioner Hanson to approve Requisition #7461 for (2) 2018 GMC 1/2T Pickups. Motion carried unanimously. c. Approval to Allow Purchase of Pipeline Repair Fittings for Inventory Requisition #7473 John Webster presented Requisition #7473 to Allow Purchase of Pipeline Repair Fittings for Inventory in the amount of $26,954.56. A few months ago, HUC had a suspected pipeline hit. If the line would have been hit HUC does not have anything on hand to repair it. This is something HUC has discussed since 2014. In light of what happened, HUC decided to look at what parts can be on hand in case a line is hit. Staff has priced three different manufactures. The recommendation is PLIDCO, HUC has more experience with this company and this includes a 5-year warranty. Motion by Commissioner Martinez, second by Commissioner Girard to approve Requisition #7473 to Allow Purchase of Pipeline Repair Fittings for Inventory. Motion carried unanimously. d. Approval of new Bucket Truck Requisition #7482 & Requisition #7487 Dave Hunstad presented Requisition #7482 & Requisition #7487 for Approval of new Bucket Truck in the amount of $143,414.85. This will be replacing a 2008 40' Bucket Truck. Commissioner Martinez inquired about the use of the bucket truck for HUC. Dave Hunstad explained this bucket truck is for maintaining the substations, street lights, as well as daily operations because it is fitted with a service body. So it doesn't just function as a bucket truck. Motion by Commissioner Martinez, 3 second by Commissioner Hanson to approve Requisition #7482 & Requisition #4787 for new Bucket Truck. Motion carried unanimously. e. Discussion on Cost of Service Study President Morrow recapped the special meeting from a couple of weeks prior. It was a good discussion and GM Carter needed to go back to Mr. Kasbohm and Staff for more conversations. GM Carter informed the Commission that he did talk with Mr. Kasbohm, the next step needed is to see where, and what direction the Commission wants to go. Mr. Kasbohm does not see a concern with a 3-year rate track, or if it would be a longer horizon path of 5-10 years. It also depends on how close the Commission wants to be between classes. These scenarios can be crafted to the comfort level of the Commission and Staff. Commissioner Martinez noted the approach to a longer horizon to make a better fit is ideal. Not talking major changes and can still achieve the end goal without any negative feedback Commissioner Hanson agreed. Having a 10-year horizon and then revisit in 3 years can show what might be happening in the community. GM Carter asked the Commission if they would like to have Mr. Kasbohm create a model for 5-7-10 years. Commissioner Martinez requested 7 and 10 year. This will give the Commission an idea but realizing it can change quickly -community changes, legislation changes, and industry changes. GM Carter inquired about 5-10% equitability between classes. The Commission would like to see 5%. There was not a rate class that needed more than 10% and 5% could be very incremental. The Commission would like to see the impact to each class. GM Carter noted that he has everything he needs for Mr. Kasbohm. f. Review 2017 Annual Distributed Generation i. Dave Hunstad presented the Distributed Generation 2017 report. Prior to 2017, HUC was required to file this report with the Department of Commerce and the Minnesota Public Utilities Commission. Attached the Commission will find the four solar customers in town and their annual usage. HUC already has policies in place and now annually every February the Commission will see this report. 9. Adjourn There being no further business, a motion by Commissioner Hanson, second by Commissioner Girard to adjourn the meeting at 3:49p.m. Motion carried unanimously. ATTEST: Monty Morrow, President 12 Robert Wendorff, Secretary MINUTES Special Meeting — Hutchinson Utilities Commission Tuesday, March 20, 2018 Call to order — 3:05 p.m. President Morrow called the meeting to order. Members present: President Monty Morrow; Vice President Anthony Hanson; Secretary Robert Wendorff; Commissioner Mark Girard Absent: Commissioner Don Martinez; General Manger Carter Others present: Randy Blake, John Webster and Angie Radke. The purpose of the special meeting is to Tour the Facility of Plant 1. Mr. Blake led the tour of Plant 1 and answered all general project questions that were asked by the Commission. There being no further business, a motion by Commissioner Hanson, second by Commissioner Girard to adjourn the meeting at 3:42p.m. Motion was unanimously carried. 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Depreciation Transfers (Elect./City) Operating Expense Debt Interest TOTAL EXPENSES NET PROFIT/(LOSS) 16.67% of Year Comp. Di %Chnq Full Yr Bud % of Bud 611,672 8.8% $ 35,763,605 21.2% 231,439 82.6% $ 2,519,200 20.3% (5,670) (3.8%) $ 739,440 19.3% 778 0.7% $ 656,366 16.7% (40,729) (31.0%) $ 492,808 18.4% 17,924 61.6% $ 100,000 47.0% 815,414 10.6% $ 40,271,419 21.0% $ 446,170 $ 447,230 $ (1,059) (0.24%) $ 996,380 $ 976,908 $ 19,472 2.0% $ 6,363,429 15.7% $ 1,858,632 $ 1,850,594 $ 8,038 0.4% $ 4,304,459 $ 4,117,569 $ 186,890 4.5% $ 19,600,000 22.0% $ 171,180 $ 190,719 $ (19,539) (10.2%) $ 360,521 $ 381,582 $ (21,061) (5.5%) $ 2,630,000 13.7% $ 31,481 $ 4,739 $ 26,742 564.4% $ 144,968 $ 71,399 $ 73,569 103.0% $ 992,082 14.6% $ 325,667 $ 317,333 $ 8,333 2.6% $ 651,333 $ 634,667 $ 16,667 2.6% $ 3,908,000 16.7% $ 158,986 $ 154,003 $ 4,984 3.2% $ 317,972 $ 308,005 $ 9,967 3.2% $ 1,907,835 16.7% $ 111,858 $ 196,413 $ (84,555) (43.0%) $ 305,165 $ 371,711 $ (66,546) (17.9%) $ 2,490,809 12.3% $ 103,551 $ 63,382 $ 40,169 63.4% $ 207,103 $ 126,765 $ 80,338 63.4% $ 1,280,863 16.2% $ 39,173,018 18.6% $ 3,207,525 $ 3,224,412 $ (16,887) (0.5%) $ 7,287,902 $ 6,988,605 $ 299,298 4.3% $ 734,182 $ 318,231 $ 415,951 130.7%1 1,186,741 $ 670,625 $ 516,116 77.0% $ 1,098,401 108.0% February February YTD YTD 2018 2017 Change 2018 2017 Change Gross Margin % 41.6% 33.4% 8.2% 37.3% 32.8% 4.5% Operating Income Per Revenue $ (%) 20.4% 9.1% 11.3% 15.5% 9.1% 6.4% Net Income Per Revenue $ (%): 18.6% 9.0% 9.6% 14.0% 8.8% 5.2% 2018 HUC Budget Target 32.2% IIIIIIIIIIIIIIIIIII 10NNNNNNNN�1 5.2% fN��IINIINIdI 2.7% HUTCHINSON UTILITIES COMMISSION ELECTRIC DIVISION FINANCIAL REPORT FOR FEBRUARY, 2018 10100 i� � ��ii�� iiii�fffttttftf�� iiii�� 16.67%of Year Comp. 2018 2017 2 . %Chna 2018 2017 2 . %Chna Full YrBud %of Bud Electric Division Customer Revenue $ 1,929,579 $ 1,950,027 $ (20,447) (1.0%) $ 4,060,673 $ 3,998,476 $ 62,198 1.6% $ 25,325,189 16.0% Sales for Resale $ 173,427 $ 100,987 $ 72,440 71.7% $ 511,758 $ 280,320 $ 231,439 82.6% $ 2,519,200 20.3% Other Revenues $ 14,751 $ 57,693 $ (42,941) (74.4%) $ 31,566 $ 88,893 $ (57,327) (64.5%) $ 208,800 15.1% Interest Income $ 11,251 $ 5,026 $ 6,225 123.8% $ 26,292 $ 14,541 $ 11,750 80.8% $ 50,000 52.6% TOTAL REVENUES $ 2,129,009 $ 2,113,733 $ 15,276 0.7% $ 4,630,290 $ 4,382,230 $ 248,060 5.7% $ 28,103,189 16.5% Salaries & Benefits $ 347,905 $ 351,542 $ (3,638) (1.0%) $ 777,981 $ 759,788 $ 18,193 2.4% $ 4,942,964 15.7% Purchased Power $ 1,122,166 $ 1,083,327 $ 38,839 3.6% $ 2,494,526 $ 2,331,042 $ 163,483 7.0% $ 14,000,000 17.8% Transmission $ 171,180 $ 190,719 $ (19,539) (10.2%) $ 360,521 $ 381,582 $ (21,061) (5.5%) $ 2,630,000 13.7% Generator Fuel/Chem. $ 31,481 $ 4,739 $ 26,742 564.4% $ 144,968 $ 71,399 $ 73,569 103.0% $ 992,082 14.6% Depreciation $ 241,667 $ 233,333 $ 8,333 3.6% $ 483,333 $ 466,667 $ 16,667 3.6% $ 2,900,000 16.7% Transfers (Elect./City) $ 128,224 $ 119,110 $ 9,115 7.7% $ 256,449 $ 238,219 $ 18,230 7.7% $ 1,538,693 16.7% Operating Expense $ 72,247 $ 152,091 $ (79,844) (52.5%) $ 197,668 $ 271,595 $ (73,926) (27.2%) $ 1,613,834 12.2% Debt Interest $ 47,376 $ 2,124 $ 45,252 2,130.6% $ 94,753 $ 4,248 $ 90,505 2,130.6% $ 606,763 15.6% TOTAL EXPENSES $ 2,162,245 $ 2,136,984 $ 25,261 1.2% $ 4,810,199 $ 4,524,540 $ 285,659 6.3% $ 29,224,336 16.5% P�RpO�FIIIT/((LLOSSSSSS))/) (33,236) $ (23,252))) (9,9(((8(5) 42.9% $ (179,909) $ (142,310) $ (337,,5(9((9) 26.4% $ (1,121,147) 16.0% 16.67%of Year Comp. y�NET� ((($ 2018 2017 2 . %Chna 2018 2017 2 . %Chna Full YrBud %of Bud Electric Division Residential 3,850,255 3,533,698 316,557 8.96% 8,109,219 7,760,820 348,399 4.49% 50,432,797 16.1% All Electric 324,900 257,557 67,343 26.15% 683,486 597,516 85,970 14.39% 2,611,705 26.2% Small General 1,509,417 1,368,387 141,030 10.31% 3,137,562 2,941,910 195,652 6.65% 17,085,853 18.4% Large General 5,462,980 5,388,598 74,382 1.38% 11,926,360 11,345,736 580,624 5.12% 79,262,499 15.0% Industrial 9,412,000 9,943,000 (531,000) (5.34%) 19,818,000 20,836,000 (1,018,000) (4.89%) 134,707,856 14.7% Total KWH Sold 20,559,552 20,491,240 68,312 0.33% 43,674,627 43,481,982 192,645 0.44% 284,100,710 15.4% February February YTD YTD 2018 HUC 2018 2017 Change 2018 2017 Change Budget Target Gross Margin % 27.9% 25.9% 1.9% 25.5% 24.5% 1.1% 24.0% Operating Income Per Revenue $ (%) 0.1°% -2 8°% 2 9°% -2.4% -4.3% 1.9% -2.0% 0%-5% Net Income Per Revenue $ (%): -1.6% -1.1% -0.5% -3.9% -3.2% -0.6% -4.0% 0%-5% Customer Revenue per KWH: $0.0939 $0.0952 -$0.0013 $0.0930 $0.0920 $0.0010 $0.0886 ��IIIIIIIIII'' Total Power Supply Exp. per KWH: $0.0743 $0.0751 -$0.0008 $0.0785 $0.0753 $0.0032 $0.0750 $0.0750 Electric division loss in February 2018 increased by $9,985. However, without the new bond interest there actually would have been an improvement of around $35,000. Sales for Resale of $173,427 consisted of $7,210 in market sales, $35,600 in the monthly tolling fee from Transalta, $34,617 in Transalta energy sales, and $96,000 in capacity sales to SMMPA. February 2017 Sales for Resale of $100,987 consisted of $87 in market sales, $34,400 in monthly tolling fees from Transalta, $0 in Transalta energy sales, and $66,500 in capacity sales to SMMPA. February 2016 Sales for Resale of $97,735 consisted of $2,831 market sales, $34,400 in Transalta tolling fees, $18,504 in Transalta energy sales, and capacity sales to SMMPA for $42,000. Overall Purchased Power increased by $38,839. MRES purchases decreased by $8,237 and market purchases/MISO costs increased by $47,076. The power cost adjustment for February 2018 was $.00899/kwhr bringing in an additional $184,255 of revenue for the month and and $378,190 YTD. Last year's power cost adjustment for February 2017 generated $218,659 in additional revenue for the month and $348,629 for the year. HUTCHINSON UTILITIES COMMISSION GAS DIVISION FINANCIAL REPORT FOR FEBRUARY, 2018 10#100 i� � ��ii�� iiii�� 16.67% of Year Comp. 2018 2017 2 . %Chna 2018 2017 2 . %Chna Full YrBud %of Bud Gas Division Customer Revenue $ 1,647,430 $ 1,274,675 $ 372,755 29.2% $ 3,512,652 $ 2,963,178 $ 549,474 18.5% $ 10,438,416 33.7% Transportation $ 71,670 $ 70,638 $ 1,032 1.5% $ 142,514 $ 148,184 $ (5,670) (3.8%) $ 739,440 19.3% Electric Div. Transfer $ 54,697 $ 54,308 $ 389 0.7% $ 109,394 $ 108,617 $ 778 0.7% $ 656,366 16.7% Other Revenues $ 30,437 $ 24,263 $ 6,174 25.4% $ 59,078 $ 42,480 $ 16,598 39.1% $ 284,008 20.8% Interest Income $ 8,463 $ 5,026 $ 3,437 68.4% $ 20,715 $ 14,541 $ 6,174 42.5% $ 50,000 41.4% TOTAL REVENUES $ 1,812,698 $ 1,428,910 $ 383,787 26.9% $ 3,844,354 $ 3,277,000 $ 567,354 17.3% $ 12,168,230 31.6% Salaries & Benefits $ 98,266 $ 95,687 $ 2,578 2.7% $ 218,399 $ 217,120 $ 1,280 0.6% $ 1,420,465 15.4% Purchased Gas $ 736,466 $ 767,267 $ (30,801) (4.0%) $ 1,809,934 $ 1,786,527 $ 23,407 1.3% $ 5,600,000 32.3% Operating Expense $ 39,611 $ 44,322 $ (4,711) (10.6%) $ 107,497 $ 100,116 $ 7,381 7.4% $ 876,975 12.3% Depreciation $ 84,000 $ 84,000 $ 0.0% $ 168,000 $ 168,000 $ - 0.0% $ 1,008,000 16.7% Transfers (City) $ 30,762 $ 34,893 $ (4,131) (11.8%) $ 61,524 $ 69,786 $ (8,262) (11.8%) $ 369,142 16.7% Debt Interest $ 56,175 $ 61,258 $ (5,083) 0.0% $ 112,350 $ 122,517 $ (10,167) JL12L $ 674,100 16.7% TOTAL EXPENSES $ 1,045,279 $ 1,087,428 $ (42,149) (3.9%) $ 2,477,703 $ 2,464,065 $ 13,638 0.6% $ 9,948,682 24.9% NET $((( 767,418 $ 341,482 $ 4(((25,936 124.7% $ 1,366,650 $ $ 5�55333,71(((6 68.1% $ 2,219,548 61.6% p�88122,93355 fOfiYih�rr�4illllllllllll lll 16.67% of Year Comp. ��yPROFIT/(LOSS)) ri �fir�l�f01lllllllllll lllhR?IIII 2018 2017 Di %Chnq 2018 2017 Di %Chnq Full YrBud %of Bud Gas Division Residential 73,863,472 53,256,741 20,606,731 38.69% 155,656,183 129,538,477 26,117,706 20.16% 449,582,000 34.6% Commercial 54,564,919 39,256,075 15,308,844 39.00% 115,850,239 93,960,117 21,890,122 23.30% 420,183,000 27.6% Industrial 96,635,237 83,144,903 13,490,334 16.23%1 205,250,519 186,391,625 18,858,894 10.12%1 786,836,000 26.1% Total CF Sold 225,063,628 175,657,719 49,405,909 28.13%1 476,756,941 409,890,219 66,866,722 16.31%1 1,656,601,000 28.8% February February YTD YTD 2018 HUC 2018 2017 Change 2018 2017 Change Budget Target Gross Margin % 57.9% 44.4% 13.5% 51.6% 44.0% 7.6% 51.4% IIIIIIIIIIIIIIIIIIIIIIII �� Operating Income Per Revenue $ (%) 44.4% 26.7% 17.7% 37.4% 27.3% 10.1% 22.1% Net Income Per Revenue $ (%): 43.3% 24.4% 18.9% 36.3% 25.2% 11.1% 18.8% �pyN�NNpNp�p�p�p�N� ��MflIII�IIIIIIIIIIIIIIIIIyy Contracted Customer Rev. per CF: $0.0042 $0.0042 $0.0000 $0.0042 $0.0044 -$0.0002 $0.0035pp�pp�pp��pp��pp��ryry�I Customer Revenue per CF: $0.0097 $0.0100 -$0.0003 $0.0098 $0.0096 $0.0001 $0.0088IIIIIIIIII��II�'' Total Power Supply Exp. per CF: $0.0033 $0.0044 ($0.0011) $0.0038 $0.0044 ($0.0006) $0.0035 $0.0035 Net Profit for February 2018 increased by $425,936 in the gas division over February 2017. Increased revenues can be attributed to colder weather as well as no fuel credits being issued. No fuel cost adjustment for February 2018 due to depleting the rate stabilization fund in December. An additional $185,195 was added to the fund in February. This brings the account to $522,541. Credits are issued once it surpasses $600,000. February 2017 credits to customers totalled $7,854 for the month and $65,723 YTD. Current Assets Unnestricted/Undesignated 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 HUTCHINSON UTILITIES COMMISSION BALANCE SHEET - CONSOLIDATED FEBRUARY 28, 2018 Electric Gas Total Total Net Change Division Division 2018 2017 Total (YTD) 17,082,809.69 7,101,285.96 24,184,095.65 11,262,468.30 12,921,627.35 680.00 170.00 850.00 850.00 - 2,750,000.00 700,000.00 3,450,000.00 2,699,000.00 751,000.00 882,327.00 369,142.00 1,251,469.00 1,196,331.00 55,138.00 314,539.41 - 314,539.41 314,539.41 - - 522,540.87 522,540.87 646,058.37 (123,517.50) 400,000.00 100,000.00 500,000.00 500,000.00 - 793,951.77 - 793,951.77 50,162.47 743,789.30 - 492,274.97 492,274.97 651,699.96 (159,424.99) 522,335.64 2,188,694.02 2,711,029.66 2,188,694.02 522,335.64 22,746,643.51 11,474,107.82 34,220,751.33 19,509,803.53 14,710,947.80 2,032,217.79 1,764,383.53 3,796,601.32 3,237,165.96 559,435.36 19,039.49 19,039.49 38,078.98 31,415.67 6,663.31 2,051,257.28 1,783,423.02 3,834,680.30 3,268,581.63 566,098.67 1,225,166.15 407,924.63 1,633,090.78 1,503,526.31 129,564.47 123,924.41 44,245.36 168,169.77 158,740.23 9,429.54 36,660.64 - 36,660.64 148,463.67 (111,803.03) 1,746,060.00 - 1,746,060.00 1,746,060.00 - - 582,020.00 582,020.00 582,020.00 - 3,131,811.20 1,034,189.99 4,166,001.19 4,138,810.21 27,190.98 27, 929, 711.99 14, 291, 720.83 690,368.40 89,040,746.99 (53,289,258.75) 4,519,556.27 40,961,412.91 3,901,323.35 41,260,565.70 (15, 501, 901.36) 311,229.94 29,971,217.63 42,221,432.82 26,917,195.37 15,304,237.45 4,591,691.75 4,590,287.00 1,404.75 130,301,312.69 130,306,747.03 (5,434.34) (68,791,160.11) (64,966,493.11) (3,824,667.00) 4,830,786.21 111,646.04 4,719,140.17 70,932,630.54 70,042,186.96 890,443.58 Total Assets 68,891,124.90 44,262,938.46 113,154,063.36 96,959,382.33 16,194,681.03 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- Nat Gas 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 FEBRUARY 28, 2018 Electric Gas Total Division Division 2018 2,164,519.06 185,305.50 67, 524.64 2,417,349.20 1,295,000.00 185,608.32 1,229,226.69 168,525.08 19,194.16 2,897,554.25 Total Net Change 2017 Total (YTD) 1,295,000.00 1,345,000.00 (50,000.00) 185,608.32 185,608.32 - 3,393,745.75 4,967,722.23 (1,573,976.48) 353, 830.58 190,146.90 163, 683.68 86,718.80 166,112.69 (79,393.89) 5,314,903.45 6,854,590.14 (1,539,686.69) 16,675,000.00 - 16,675,000.00 - 16,675,000.00 - 13,900,000.00 13,900,000.00 15,195,000.00 (1,295,000.00) - - - 465,000.00 (465,000.00) 660,774.96 1,438,464.11 2,099,239.07 1,624,072.43 475,166.64 4,226,202.00 - 4,226,202.00 4,226,202.00 - - 1,408,734.00 1,408,734.00 1,408,734.00 - 323,735.99 102,774.05 426,510.04 378,943.50 47,566.54 73,739.62 28,580.99 102,320.61 92,050.32 10,270.29 569,910.00 - 569,910.00 569,910.00 - - 189,970.00 189,970.00 189,970.00 - 22,529,362.57 17,068,523.15 39,597,885.72 24,149,882.25 15,448,003.47 43,944,413.13 24,296,861.06 68,241,274.19 65,954,909.94 2,286,364.25 43,944,413.13 24,296,861.06 68,241,274.19 65,954,909.94 2,286,364.25 Total Liabilities and Net Position 68,891,124.90 44,262,938.46 113,154,063.36 96,959,382.33 16,194,681.03 Hutchinson Utilities Commission Cash -Designations Report, Combined 2/28/2018 Change in Financial Balance, Balance, Cash/Reserve Institution Current Interest Rate Annual Interest February 2018 January 2018 Position Savings, Checking, Investments varies varies varies 34,220,751.33 35,466,054.62 (1,245,303.29) Total Operating Funds 34,220,751.33 35,466,054.62 (1,245,303.29) Debt Reserve Requirements Debt Reserve Requirements Total Reserve Requirement Operating Reserve Rate Stabalization Funds PILOT Funds Catastrophic Funds Capital Reserves Total Earmarked Funds Bond Covenants - sinking fund Bond Covenants -1 year Max. P & I Min 60 days of 2018 Operating Bud. Charter (Formula Only) Risk Mitigation Amount 5 Year CIP ( 2018-2022 Fleet & Infrastructure Maintenance) 1,286,226.74 1,068,512.44 217,714.30 2,188,694.02 2,188,694.02 - 3,474,920.76 3,257,206.46 217,714.30 5,868,920.00 5,868,920.00 514,566.70 514,566.70 1,251,469.00 1,251,469.00 500,000.00 500,000.00 3,450,000.00 3,450,000.00 11, 584, 95 5.70 11, 584, 95 5.70 YE YE YE YE YTD HUC 2014 2015 2016 2017 2018 Target Debt to Asset 28.8% 32.0% 32.2% 40.8% 39.7% Current Ratio 2.26 2.52 3.06 5.73 6.75 �INigM� RONA 0.05% 1.31% 2.17% 1.80% 1.17% Change in Cash Balance (From 12131114 to 212812018) Month End Electric Elec. Change Natural Gas Gas Change Total Total Change 2/28/2018 22,746,644 11,474,108 34,220,751 12/31/2017 23,213,245 (466,601) 10,702,689 771,419 33,915,934 304,817 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. February Cash decreased due to our discussions last month on making two months of payments to BP. Hutchinson Utilities Commission Cash -Designations Report, Electric 2/28/2018 Change in Financial Balance, Balance, Cash/Reserve Institution Current Interest Rate Annual Interest February 2018 January 2018 Position Savings, Checking, Investments varies varies varies 34,220,751.33 35,466,054.62 (1,245,303.29) Total HUC Operating Funds 34,220,751.33 35,466,054.62 (1,245,303.29) Debt Restricted Requirements Bond Covenants - sinking fund Operating Reserve Min 60 days of 2018 Operating Bud. Rate Stabalization Funds $400K-$1.2K PILOT Funds Charter (Formula Only) Catastrophic Funds Risk Mitigation Amount Capital Reserves 5 Year CIP ( 2018-2022 Fleet & Infrastructure Maintenance) Total Designated Funds 793,951.77 740,329.14 53,622.63 4,387,223.00 4,387,223.00 314,539.41 314,539.41 882,327.00 882,327.00 400,000.00 400,000.00 2,750,000.00 2,750,000.00 8,734,089.41 8,734,089.41 Excess Reserves Less Restrictions & Designations, Electric 13,218fl6O2.33 13fl289fl925.65 (71fl323.32) YE YE YE YE YTD APPA Ratio HUC 2014 2015 2016 2017 2018 5K-10K Cust. Target Debt to Asset Ratio (* w/Gen.) 7.4% 13.2% 16.1% 36.1% 36.2% 50.1% Current Ratio 2.48 2.95 3.57 10.70 10.29 2.43 �I RONA -3.1% -1.2% -0.4% -0.1% -0.3% NA >0% Hutchinson Utilities Commission Cash -Designations Report, Gas 2/28/2018 Change in Financial Balance, Balance, Cash/Reserve Institution Current Interest Rate Annual Interest February 2018 January 2018 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 Requirements Operating Reserve Rate Stabalization Funds PILOT Funds Catastrophic Funds Capital Reserves Total Earmarked Funds varies 34,220,751.33 35,466,054.62 (1,245,303.29) 34,220,751.33 35,466,054.62 (1,245,303.29) Min 60 days of 2018 Operating Bud. $200K-$600K Charter (Formula Only) Risk Mitigation Amount 5 Year CIP ( 2018-2022 Fleet & Infrastructure Maintenance) 492,274.97 328,183.30 164,091.67 2,188,694.02 2,188,694.02 - 2,680,968.99 2,516,877.32 164,091.67 1, 481, 697.00 1, 481, 697.00 200,027.29 200,027.29 369,142.00 369,142.00 100, 000.00 100, 000.00 700,000.00 700,000.00 2,850,866.29 2,850,866.29 YE YE YE YE YTD HUC 2014 2015 2016 2017 2018 APGA Ratio Target Debt to Asset 55.6% 54.8% 51.5% 48.1% 45.1% TBD Current Ratio 2.07 2.17 2.59 2.72 3.81 TBD RONA 4.3% 4.7% 5.6% 5.0% 3.6% TBD C U� cococococo Q Q Q Q Q 0 0 0 0 0 N N N N N O N N N N 00000 0000 N O O O LO LO LO O LO LO N Co o r co M O V N I� Co m M Co N 0 0 V N I- W O O CO O oN 0) W co N Co Lo Lo V V o m Co Co o N V V V V V M o o O N N N N N N N N O N O O O O O O O O O N O O O O O O O O O Co O O o o o o o o o c000 0000000 c000 0000000 CO Ln Ln Ln Ln Ln Ln O Ln Ln N V V V V V V CO I� N N N N N N N N N O Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z d) W O- O O O O O O N O O O O I� co m N 0 0 0 0 O O m O co O r CO 0 V 0 0 0 N r O O V 0 N O O O M N V I� o M m COO M N N_ O Co Co (O V M M Lo OLD M N CO O m O M m O 0- O O W �N W Lo Ln M V O O O O O O O N O Ln O O M I� t I� O O Ln Ln Ln O d) O O Ln I` O O CO Ln d) d) M N CO CO O V d) r Ln Ln M O) O) I- O) Lo r Lo - O) Co co co co V co I- L2 o I` W o V O O N CO M co o Lo O V colcolcolN O N O N O O Ln O 0 OO OO d) OO co,O OO r 0 M V Lo Lo O Lo I` I` O (D V Lo I` O O O CO M CO M N V N O M M O co O I- O) Co Co co V co M Lo d) Lo M O d) O o 0 o co co o r O L(i V Co CO co m o m o o O M o o 0 0 0 r M 0 m 0 m N N 0 N N N M M- N Co co (O co N Lo I- O) V (O V 000000000 o O W Co Co M Co V Lo O O O O S O O O S Lo Ln I- co co O I-- r Lo O O o r W O) CO V NI I- O co co O) I� O) O) (O O) (O Co M M (O Co I� O) Co I- O) O) N O Lo V o V I� d) V E O I` O Co o o r N N co m N d) V m M Ln r N O O Ln Ln d) V V Ln d) d) d) Ln O O 0 0 0 0 N N V N N N N N N Co co I- co M o O O) O O O O O O O O O O O O O O O O CO O O O O O O O O O O O O O O O O Co O O O O O O O O O O O O O O 0 O M O o 0 0 0 0 00 0 0 0 0 0 0 0 0 co0v000000000000 v O Co N CO OOOOOOOOO Ln O V co V N o o O o o o O O O o o V O O O O N N o N N N M M N Co co I- co co n Co m m co N m N M co co co O O m m N O M O N N N N N N N N N N N N N c O O O O O O O O O c 00000000000000 c Q N N N N N N N N N O Q N N N N N N N N N N N N N N O O Z N CO r r r M r z V M .4 O N N N N O N N N N N N O O O O 0 0 0 0 0 O 0 O Co M Co m O 0 m O O Lo O Lo r W r V d) d) M O N 0000 000 O O O O O O O O- 0 0- 0 0 co co co O O r O r 0 r r r 0 0 0 0 0 0 r r r r 0 000000000 00000000000000 Q N N N N N N N N N Q N N N N N N N N N N N N N N N Z N Co I'- I` I` I` m I` Z I` I` I` I` I` co m m m r N N N N N V CO CO O M M M V V V N N N O 00 O 00000 0 0 0 0 0 0----- 0 0 0 o o o o o o 0 0 0 0 o o o o o o o o o o o 0 O O O O O O O Lo N (o O H O co O) (O O) O Co Ln O O O Lo O O O O o V O) o Lo V O I- W I` co N m m O V (O (O O- N O- O) - N - O Co I- co M- N N (o O- N N- N N- N N O--- N - N N N N- M 0 0 0 o o o o o o 0 0 0 0 o o o o o o o o o o o 0 0000000000 O Ln O O O O Ln Ln O O 0 0 0 O M (D 0 O) Lo O O O Ln V O O) Ln O co co Ln M Ln O O (O (O O N O N 0 0 N d) r co cor O co N O O N N N N N N O N N N N M M N N M Ln N F Z r m m m to to to to to to to to to to to r F In In In ~ wmmmmmmmmmmm ~ Y Z> C) [) C) N N N Q Q Q Q Q Q D- Q Q Q Q Y J -U -U � � � f/1 f/1 f/1 f/1 f/1 f/1 U U U U U U U 2 Q J J J m O _ _ = C C CC C CCC C CCC m F O (n (n (n 0 C) C) C) C) C) C) LL LL Il > > > F N N N N N N N N N N N N N N N U U U U U U U U U U U U U U U N N N N N N N N N N N N N N N C C C C C C C C C C C C C C C N N N N N N N N N N N N N N N m m m m m m m m m m > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > C C C C C C C C C C C C C C C LL LL LL LL LL LL LL LL LL LL R R R R R R R R R R R R R R R >N > N > N > N > N > N > N > N > N > N N N N N N N N N N N N N N N N a o o o o o o o N a Cl) N Ln O Cl) O c N O) M L() V o O I� O W...... v o o co co Lo Lo � v y v m R V M M I- r N 00 V Co Co O) M N cc W O co co I- Ln 00 o Ln O V o O N ti ,. N o I` o O co O 00 m N- m lb m i 69 N a J w d ^ f V w N M V n J N M V L) a � ti 0 0 0 0 O O O O 0 0 O O N 0 0 O O 0 O 0 0 0 0 O O O O 0 0 O O 0 0 O O 0 O 0 0 O O 0 O 0 0 O O 0 O 0 0 O N IT � L O) N n CO V O o M N O O o o oq m V O O w (O N O CO C r L6 CO N Co CO r 69 a+ U o n 3° V ri m O ry o c C 0 o 0 0 o O O m 3° C R N Co. M I- o II- v o 2. v o F 1 o _ c � N O N O 'T oo w o M m N N R d M N V O n r t N O Ul, N o V o M Efl V Ln r W aR+ O o R. D O I- I` V O 0 c r O ., Ln V Ln LO N O O V wI� L(i CO I� 10 N O M M w }= o R r O O N cc N dN r It d) N o N V n o Ln N Efl V o r W� � � I F C O -6 J 0] o V Y C O F V E R F O m O d Q N om a° > O C) O D C) (7 .5 E n E N o O ELECTRIC DIVISION Operating Revenue February 2018 CLASS AMOUNT KWH /KWH Street Lights $0.54 10 $0.05400 Electric Residential Service $409,578.48 3,850,255 $0.10638 All Electric Residential Service $32,950.98 324,900 $0.10142 Electric Small General Service $157,722.61 1,509,417 $0.10449 Electric Large General Service $541,920.92 5,462,980 $0.09920 Electric Large Industrial Service $787,405.88 9,412,000 $0.08366 Total $1,929,579.41 20,559,562 $0.09385 Power Adjustment $0.00899 Rate Without Power Adjustment $0.08486 Electric Division Year -to -Date 02018$A--t 02017$A-t ®2018 KWH110 02017KWH110 5,000,000 4,800,000 4,600,000 4,400,000 4,200,000 4,000,000 3,800,000 3,600,000 3,400,000 3,200,000 3,000,000 2,800,000 2,600,000 2,400,000 2,200,000 2,000,000 1,800,000 1,600,000 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 0 Street Lights Residential All Elec. Small Gen. Large Gen. Large For Resale Total Resid. Srv. Srv. Industrial NOTE: Sales for resale includes capacity sales, market sales and Transalta sales. NATURAL GAS DIVISION Operating Revenue FEBRUARY 2018 CLASS AMOUNT MCF /$ MCF Residential $703,816.89 73,863 $9.52868 Commercial $513,278.40 54,565 $9.40673 Large Industrial $430,334.87 96,635 $4.45320 Total $1,647,430.16 225,063 $7.31986 Fuel Adjustment $0.00000 Rate Without Fuel Adjustment $7.31986 Natural Gas Division Year -to -Date ® 2018 $ Amount 0 2017 $ Amount ® 2018 MCF 0 2017 MCF 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 Gas Residential Gas Commercial Large Industrial Total eReliability I Monthly Statistics Page I of 5 Monthly Report - Hutchinson Utilities Hutchinson Utilities Commission Commission Year Minimum duration Substation 2018 1�10 Month Maximum duration Circuit 02 -February I:V] Annual Report? Top-level Cause Remove Major Events? 0 Yes (�) No https://reliability.publicpower.org/reports/monthly/utility/9 I ?year=201 8&month=2&is—an... 3/19/2018 Page 2 of 5 IEEE 1366 Statistics Metric Feb 2018 Feb 2017 SAIDI 0.136 None SAIFI 0.00084 None CAIDI 163 None ASAI 99.9996% 100% Momentary Interruptions 0 0 Sustained Interruptions 1 0 Circuit Ranking - Worst Performing Ranked by Outage Count Circuit Substation Fdr#1 9 Plant 1 Ranked by Customer Interruptions Circuit Substation Fdr#1 9 Plant 1 Number of Outages 1 Customer Interruptions 6 Ranked by Customer Minutes of Duration Circuit Substation Customer Minutes of Duration Fdr#1 9 Plant 1 978 https:Hreliability.publicpower.org/reports/monthly/utility/9l?yeaT=2018&month=2&is—an... 3/19/2018 •. • Historical Monthly SAIDI Chart 2.0 O] 0.5 r OctMar Apr May Jun Jul Aug Sep 20172017 2017 2017 2017 2017 2017 2017 2017 2018 Historical Monthly SAIFI Chart 0.020 0.015 0.010 JIM 0.000 Mar Apr May Jun Jul Aug Se Dec p y p Oct Nov Dec 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 ly SAIDI values Jan Feb 2018 2018 ly SAIFI values s eReliability I Monthly Statistics Causes Ranked bvCount Equipment Damage Causes Ranked bvDuration Duration Equipment Damage 978 Page 5 of 5 Top 1 Outages for the Month Customers Customer Minutes of Address Interrupted Duration Interruption Arch 6 163 978 Street Total Customers Affected for the Month: Average Customers Affected per Outage: I Start Date 02/12/2018 0 0 https:llreliability.publicpower.org,�reportslmonthlylutilityl9l?year=2018&month,,,,,,.�2&is-an... 3/19/2018 ANNUAL 11:14% 0 r-7 I A wmmimmimmill D E N I I M / \ R K I N G IIIVVVVVVVVVVVpp eIABTVA(" ERE1 1It I ' T R, "IK F'�� REPORT AMERICAN �PUBLIIC PC R'. ASSOCIATION Powe6ng Strony Comrnurflbo,� Hutchinson Utilities Commission Funded by a grant from the Demonstration of Energy & Efficiency Developments (DEED) Program, the eReliability Tracker Annual Report was created by the American Public Power Association (the Association) to assist utilities in their efforts to understand and analyze their electric system. This report focuses on distribution system reliability across the country and is customized to each utility. The data used to generate this report reflect activity in the eReliability Tracker from January 1, 2017 to December 31, 2017. Note that if you currently do not have a full year of data in the system, this analysis may not properly reflect your utility's statistics since it only includes data recorded as of February 3, 2018; therefore, any changes made after that date are not represented herein. I. General Overview Reliability reflects both historic and ongoing engineering investment decisions within a utility. Proper use of reliability metrics ensures that a utility is not only performing its intended function, but also is providing service in a consistent and effective manner. Even though the primary use of reliability statistics is for self. evaluation, utilities can use these statistics to compare with data from similar utilities. However, differences such as electrical network configuration, ambient environment, weather conditions, and number of customers served typically limit most utility -to -utility comparisons. Due to the diverse range of utilities that use the eReliability Tracker, this report endeavors to group utilities by size and region to improve comparative analyses while reducing differences. Since this report contains overall data for all utilities that use the eReliability Tracker, it is important to consider the effect that a particularly large or small utility can have on the rest of the data. To ease the issues associated with comparability, reliability statistics are calculated for each utility with their respective customer weight taken into account prior to being aggregated with other utilities. This means that all utilities are equally weighted and all individual statistics are developed on a per customer basis. The aggregate statistics displayed in this report are calculated from utilities that experienced more than two outages in 2017. Also, utilities that experienced no outages this year, or did not upload any data, will have None/Null values in their report for their utility -specific data and were not included in the aggregate analysis. The aggregate statistics provided in the following sections of the report are based on data from 253 utilities. E This report separates utilities into groups of equal numbers of utilities according to their number of customers served. As seen in Table 1, the customer size distribution of utilities that use the eReliability Tracker is split into five distinct customer size class groups of approximately 85 utilities per group. Your utility belongs to customer size class 4,, and region Table 1 Customer size range per customer size class Class 1: 0 -1,497 Class 2: 1,498 - 3,126 Class 3: 3,127 - 6,797 Class 4: 6,798 - 12,695 Class 5: 12,696 - 650,000 Since the utilities considered in this report represent a wide variety of locations across the United States, each utility is also grouped with all others located in their corresponding American Public Power Association region. Figure 1 shows the number of utilities using the eReliability Tracker in each Association region and Figure 2 displays the Association's current United States map of regional divisions. Figure 1 Number of eReliability Tracker utilities per Association region 70 60 ID 50 40 ° 30 20 (3 10 0 1 2 3 4 5 6 7 8 9 10 Association Region Figure 2 Association map of regions 3 IEEE Statistics When using reliability metrics, a good place to start is with the industry standard metrics found in the IEEE 1366 guide. For each individual utility, the eReliability Tracker performs IEEE 1366 calculations for System Average Interruption Duration Index (SAIDI), System Average Interruption Frequency Index (SAIFI), Customer Average Interruption Duration Index (CAI DI), Momentary Average Interruption Frequency Index (MAIFI) and Average Service Availability Index (ASAI). When collecting the necessary data for reliability indices, utilities often take differing approaches. Some utilities prefer to include information as detailed as circuit type or phases impacted, while others include only the minimum required. In all cases, the more details a utility provides, the more practical their analysis will be. As a basis for calculating these statistics in the eReliability Tracker, the following are required: - Total number of customers served on the day of the outage - Start and end date/time of the outage - Number of customers that lost power Due to the differences in how some utilities analyze major events (MEs) relative to their base statistics, it is important to note how they are calculated and used in this report. An example of a major event could be severe weather, such as a tornado or thunderstorm, which can lead to unusually long outages in comparison to your distribution system's typical outage. In the eReliability Tracker and in this report, the Association's major event threshold is used, which is a calculation based directly on outage events, rather than event days. The major event threshold allows a utility to remove outages that exceed the IEEE 2.5 beta threshold for events, which takes into account the utility's past outage history up to 10 years. In the eReliability Tracker, if a utility does not have at least 36 outage events prior to the year being analyzed, no threshold is calculated; therefore, the field below showing your utility's threshold will be blank and the calculations without MEs in the SAIDI section of this report will be the same as the calculations with MEs for your utility. More outage history will provide a better threshold for your utility. Your utility's APPA major event threshold is 224549 (minutes)' The tables in this section can be used by utilities to better understand the performance of their electric system relative to other utilities nationally and to those within their region or size class. In the SAIDI section, indices are calculated for all outages with and without major events; furthermore, the data are broken down to show calculations for scheduled and unscheduled outages. For each of the reliability indices, the second table breaks down the national data into quartile ranges, a minimum value, and a maximum value. 1 If there is no major event threshold calculated for your utility, these fields are left blank and the calculations in this report including Major Events and excluding them will be the same. Your utility must have at least 36 outage events recorded in the eReliability Tracker in order to calculate a Major Event Threshold. S System Average Interruption Duration Index (SAIDI) SAIDI is defined as the average interruption duration (in minutes) for customers served by the utility system during a specific time period. Since SAIDI is a sustained interruption index, only outages lasting longer than five minutes are included in the calculations. SAIDI is calculated by dividing the sum of all customer interruption durations within the specified time frame by the average number of customers served during that period. For example, a utility with 100 customer minutes of outages and 100 customers would have a SAIDI of 1. Note that in the tables below, scheduled and unscheduled calculations include major events. Also note that wherever major events are excluded, the exclusion is based on the APPA major event threshold. Table 2 Average SAIDI for all utilities that use the eReliability Tracker (with and without MEs), belong to your region, and are grouped in your customer size class Your utility's SAIDI: All 6.0863 No MEs 6.0863 Unscheduled 6.0863 Scheduled 0 Average eReliability Tracker SAIDI 161.7605 62.1498 157.4675 4.4295 Average SAIDI for Utilities Within Your Region 100.7792 52.9737 99.1595 1.72 Average SAIDI for Utilities Within Your Customer Size Class 230.6849 70.9849 226.9916 3.7064 Table 3 Summary statistics of the SAIDI data compiled from the eReliability Tracker Minimum Value All 0.1282 No MEs 0.1282 Unscheduled 0.1282 Scheduled 0 First Quartile (25th percentile) 23.6535 10.6552 20.5479 0 Median Quartile (50th percentile) 54.863 27.2189 52.3865 0.097 Third Quartile (75th percentile) 120.8739 60.6194 114.7618 1.3001 Maximum Value 5208.0378 1412.0408 5199.7198 208 Figure 3 Average SAIDI for all utilities that use the eReliability Tracker per region 500 450 400 350 0 300 250 200 150 G 100 50 0 461.5984 1 2 3 4 5 6 7 8 9 10 Association Regions 5 System Average Interruption Frequency Index (SAIFI) SAIFI is defined as the average number of instances a customer on the utility system will experience an interruption during a specific time period. Since SAIFI is a sustained interruption index, only outages lasting longer than five minutes are included in the calculations. SAIFI is calculated by dividing the total number of customer interruptions by the average number of customers served during that time period. For example, a utility with 150 customer interruptions and 200 customers would have a SAIFI of 0.75 interruptions per customer. Table 4 Average SAIFI for all utilities that use the eReliability Tracker, belong to your region, and are grouped in your customer size class Your utility's SAIFI: 0.06 Average eReliability Tracker SAIFI 0.8515 Average SAIFI for Utilities Within Your Region 0.7275 Average SAIFI for Utilities Within Your Customer Size Class 0.8991 Table 5 Summary statistics of the SAIFI data compiled from the eReliability Tracker Minimum Value 0.0009 First Quartile (25th percentile) 0.2812 Median Quartile (50th percentile) 0.6357 Third Quartile (75th percentile) 1.0948 Maximum Value 8.0499 Figure 4 Average SAIFI for all utilities that use the eReliability Tracker per region 1.8 0 1.6 n 1.4 1.2 1 G 0.8 0 0.6 0.4 0.2 0 1 7043 1 2 3 4 5 6 7 8 9 10 Association Regions A Customer Average Interruption Duration Index (CAIDI) CAIDI is defined as the average duration (in minutes) of an interruption experienced by customers during a specific time frame. Since CAIDI is a sustained interruption index, only outages lasting longer than five minutes are included in the calculations. It is calculated by dividing the sum of all customer interruption durations during that time period by the number of customers that experienced one or more interruptions during that time period. This metric reflects the average customer experience (minutes of duration) during an outage. Table 6 Average CAIDI for all utilities that use the eReliability Tracker, belong to your region, and are grouped in your customer size class Your utility's CAIDI: 101.474 Average eReliability Tracker CAIDI 321.6103 Average CAIDI for Utilities Within Your Region 111.4538 Average CAIDI for Utilities Within Your Customer Size Class 227.8248 Table 7 Summary statistics of the CAIDI data compiled from the eReliability Tracker Minimum Value 11.7835 First Quartile (25th percentile) 60.0011 Median Quartile (50th percentile) 94.8976 Third Quartile (75th percentile) 151.0141 Maximum Value 22979.18 Figure 5 Average CAIDI for all utilities that use the eReliability Tracker per region 700 634.764 600 525.2002 500 0 400 340.985 U 300 m 200 151.7638 171.8783 134.1772 11 1.4538 89 589 95.6323 G 100 0 1 2 3 4 5 6 7 8 9 10 Association Regions 7 Momentary Average Interruption Frequency Index (MAIFI) MAIFI is defined as the average number of times a customer on the utility system will experience a momentary interruption. In this report, an outage with a duration of less than five minutes is classfied as momentary. The index is calculated by dividing the total number of momentary customer interruptions by the total number of customers served by the utility. Momentary outages can be more difficult to track and many smaller utilities may not have the technology to do so; therefore, some utilities may have a MAIFI of zero. Table 8 Average MAIFI for all utilities that use the eReliability Tracker, belong to your region, and are grouped in your customer size class Your utility's MAIFI: 0 Average eReliability Tracker MAIFI 0.3515 Average MAIFI for Utilities Within Your Region 0.686 Average MAIFI for Utilities Within Your Customer Size Class 0.309 Table 9 Summary statistics of the MAIFI data compiled from the eReliability Tracker Minimum Value 0 First Quartile (25th percentile) 0 Median Quartile (50th percentile) 0 Third Quartile (75th percentile) 0.1166 Maximum Value 25.0421 Figure 6 Average MAIFI for all utilities that use the eReliability Tracker per region 0.8 S 0.686 0.6716 `0 0.7 0 0.6 0.5 LL 0.4 0.3432 0.3 0.2673 0.28990.2283 a� 0.2 0.1806 2 0.0935 G 0.1 0.0197 0 0 1 2 3 4 5 6 7 8 9 10 Association Regions A Average Service Availability Index (ASAI) ASAI is defined as a measure of the average availability of the sub -transmission and distribution systems that serve customers. This load -based index represents the percentage availability of electric service to customers within the time period analyzed. It is caclulated by dividing the total hours service is available to customers by the total hours that service is demanded by the customers. For example, an ASAI of 99.99% means that electric service was available for 99.99% of the time during the given time period. Table 10 Average ASAI for all utilities that use the eReliability Tracker, belong to your region, and are grouped in your customer size class Your utility's ASAI (%): 99.9988 Average eReliability Tracker ASAI 99.9693 Average ASAI for Utilities Within Your Region 99.9808 Average ASAI for Utilities Within Your Customer Size Class 99.9561 Table 11 Summary statistics of the ASAI data compiled from the eReliability Tracker Minimum Value 99.0091 First Quartile (25th percentile) 99.9779 Median Quartile (50th percentile) 99.9896 Third Quartile (75th percentile) 99.9954 Maximum Value 99.9999 Figure 7 Average ASAI for all utilities that use the eReliability Tracker per region i� li 80.00 U) 60.00 0 N 40.00 Q 20.00 0.00 147 99.9761 99.9808 99.9894 99.9566 99.9121 99.9818 99.9849 99.9677 1 2 3 4 5 6 7 8 9 10 Association Regions 9 2016 Energy Information Administration (EIA) Form 861 Data Form EIA-861 collects information on the status of electric power industry participants involved in the generation, transmission, distribution, and sale of electric energy in the United States, its territories, and Puerto Rico. EIA surveys electric power utilities annually through EIA Form 861 to collect electric industry data and subsequently make that data available to the public. In 2014, EIA began publishing reliability statistics in their survey from utility participants; therefore, the Association included EIA reliability statistics in this report for informational purposes. Please note that the following data includes investor -owned, rural cooperative, and public power utilities that were large enough to be required to fill out the full EIA 861, not the EIA 861-S form (for smaller entities). In addition, since the collection and release of EIA form data lags by more than a year, the data provided here is based on 2016 data only. Therefore, it is suggested that the aggregate statistics contained herein be used only as an informational tool for further comparison of reliability statistics. In the table, if an entity calculates SAIDI, SAIFI, and determines major event days in accordance with the IEEE 1366-2003 or IEEE 1366-2012 standard, they are included under the "IEEE Method" columns. If the entity calculates these values via another method, they are included under the "Other Method" columns. Additionally, it looks as though a number of utilities submitted incorrect data, which shows itself most in the average SAIFI numbers. For more general information on reliability metrics you can see the Association's website at http://publicpower.org/reliability. Although EIA collected other reliability -related data, the tables below only include SAIDI and SAIFI data. The full set of data can be downloaded at this link: http://www.eia.gov/electricity/data/eia861/ Table 12 Summary statistics of the SAIDI data compiled from 2016 data collected by EIA verage linimum Value irst Quartile (25th percentile) ledian Quartile (50th percentile) hird Quartile (75th percentile) laximum Value IEEE Method All No MEDs 314.2593 128.6160 0.2840 0.0000 81.7025 54.3800 154.8600 101.9000 292.7500 164.5150 6957.4700 1099.0700 Other Method All No MEDs 210.6055 111.4045 0.1740 0.1740 31.4225 23.5100 97.0000 80.9000 205.1620 153.3400 3163.4000 648.0000 Table 13 Summary statistics of the SAIFI data compiled from 2016 data collected by EIA verage linimum Value irst Quartile (25th percentile) ledian Quartile (50th percentile) hird Quartile (75th percentile) laximum Value IEEE Method All No MEDs 1.6569 1.2989 0.0040 0.0000 0.8800 0.6700 1.3400 1.0700 2.0600 1.5600 29.0000 28.0200 Other Method All No MEDs 1.3222 1.0575 0.0000 0.0000 0.4740 0.3900 1.0540 0.9300 1.7920 1.4400 13.0000 5.8800 10 Analysis of Miles of Line and Interruptions Benchmarking metrics were created to help utilities explore the relationship between outages, overhead line exposure, and customer density. More specifically, by using interruptions per overhead mile of line and customers per mile utilities can benchmark reliability against system characteristics along with the customer normalized metrics included in the rest of the report. These system topography -related metrics can be helpful in understanding, for example, utility reliability against weather and animal -related outages relative to similarly dense and exposed utilities. Your utility's overhead miles of line as reported by Ventyx: 155 Table 14 Analysis of overhead miles of line and interruptions Interruptions per Mile Customers per Mile Your Utility: 0.0581 46.0774 Average for eReliability Tracker Utilities 0.9053 104.7849 Average for Utilities Within Your Region 0.8384 122.3345 11 III. Outage Causes Equipment failure, extreme weather events, wildlife and vegetation are some of the most common causes of electric system outages. However, certain factors, such as regional weather and animal/vegetation patterns, can make a different set of causes more prevalent to a specific group of utilities. The following sections of this report include graphs depicting common causes of outages for your individual utility, all utilities in your region, and all utilities using the eReliability Tracker. The charts containing aggregate information are customer -weighted to account for differences in utility size for a better analytical comparison. For example, a particularly large utility may have a large number of outages compared to a small utility; in order to avoid skewing the data towards large utilities, the number of cause occurrences is divided by customer size to account for the differences. In the figures below, the data represent the number of occurrences for each group of 1000 customers. For instance, a customer -weighted occurrence rate of "1" means 1 outage of that outage cause per 1000 customers on average in 2017. Note that the sustained outage cause analysis is more comprehensive than the momentary outage cause analysis due to a bigger and more robust sample size for sustained outages. Regardless, tracking both sustained and momentary outages helps utilities understand and reduce outages. To successfully use the outage information tracked by your utility, it is imperative to classify and record outages in detail. The more information provided per outage, the more conclusive and practical your analyses will be. Sustained Outage Causes In general, sustained outages are the most commonly tracked outage type. In many analyses of sustained outages, utilities tend to exclude scheduled outages, partial power, customer -related problems, and qualifying major events from their reliability indices calculations. While this is a valid method for reporting, these outages should be included for internal review to make utility -level decisions. In this section, we evaluate common causes of sustained outages for your utility, corresponding region, and for all utilities that use the eReliability Tracker. It is important to note that in this report, sustained outages are classified as outages that last longer than five minutes, as defined by IEEE 1366. 12 Figure 8 Top five customer -weighted occurrence rates for common causes of sustained outages for all utilities that use the eReliability Tracker Service 2 1.4 1.2187 1.2 1.0485 1.0099 1 0.8259 of 0.8 0.579 0.6 u 0.4 U O 0.2 0 Trees Human Weather Squirrel Unknown Outage Causes Types Tree Unknown Squirrel Equipment Figure 9 Top five customer -weighted causes of sustained outages for your utility2 1 0.8401 0.8 m 0.6 U 0.4 0 0.2 0.14 0.14 0.14 0 0 SIM Outage Cause Types Electrical Failure Storm Tree Equipment Damage Electrical Failure None Figure 10 2 Top five customer -weighted occurrence rates for sustained outage causes in your region 1.4 1.2111 1.2041 ,1.2 1.1204 m 1 0.8252 0.8229 0.8 0.6 0.4 O 0.2 1 E E M M M 0 Outage Cause Types Squirrel Weather Tree Wildlife Utility Maintenance and Repairs 2 For each utility, the number of occurrences for each cause is divided by that utility's customer size (in 1000s) to create an occurence rate that can be compared across different utility sizes. 13 Momentary Outage Causes The ability to track momentary outages can be difficult or unavailable on some systems, but due to the hazard they pose for electronic equipment, it is important to track and analyze momentary causes. In this section, we evaluate common causes of momentary outages for your utility, region and customer size class as well as common causes for all utilities that use the eReliability Tracker. Please note that only outages lasting less than five minutes are classified as momentary, as defined by IEEE 1366. Figure 11 Top five customer -weighted occurrence rates for common causes of momentary outages for all utilities that use the eReliability Tracker Service 2 0.25 - 0.2 - 0.1914 m 0.15 - U 0.1 - 0.0578 0.0522 0.0383 0.038 O 0.05 - 0- Trees Human Weather Squirrel Unknown Outage Cause Types Unknown Utility Maintenance and Customer Service Equipment Replacement Repairs Figure 12 Top five customer -weighted causes of momentary outages for your utilityz, 3 1 a0.8 m � 0.6 U N t 0.4 U U 0 0.2 0 0 0 0 0 0 Outage Cause Types None None None None 3 If your utility has less than eight momentary outages recorded in the eReliability Tracker, this graph will be blank. Equipment None 14 Figure 13 Z Top five customer -weighted occurrence rates for momentary outage causes in your region 0.2 0.15 0.1 0.05 01883 Outage Cause Types Utility Human Error Utility Maintenance Unknown Unknown/Other Weather and Repairs Thank you for using the eReliability Tracker, and we hope this report is useful to your utility in analyzing your system. If you have any questions regarding the material provided in this report, please contact: APPA's Reliability Team Michael J. Hyland Alex Hofmann Tanzina Islam Christina Ospina Ethan Epstein American Public Power Association 2451 Crystal Drive, Suite 1000 Arlington, VA 22202 reliability@publicpower.org Copyright 2018 by the American Public Power Association. All rights reserved. 15 2451 Crystal Drive Suite l000 ArIlington, VA 22202-4PO4 vvww.R,d,)hcPo,,Y,/or,oig EM dlectiiirII ° iii iii' IiO Hutchinson Utilities Comi-nissio-11 225 Michiga�i Street SE HLJtchirnsoii"i, NAN 553501905 320 587-4746 1 Fax 320-587-4721 wwwhutchirisoi-UHffies cuin Putting All of Our Energy into Serving You Q 11 Tobias Sellier, American Public Power Association, 202-467-2927, MediaRelations@PublicPower.om "Iftrom-WRI11010 •PRKTOMMMEM FOR RELIABLE SERVICE TO THE COMMUNITY Hutchinson, MN 3/20/18 Hutchinson Utilities Commission has received national recognition for achieving exceptional electric reliability in 2017. The recognition comes from the American Public Power Association (www.PublicPower.org), a trade group that represents more than 2,000 not -for -profit, community -owned electric utilities. The Association helps members track outage and restoration data through its subscription -based eReliability Tracker service and then compares the data to national statistics tracked by the U.S. Energy Information Administration for all types of electric utilities. "This recognition helps demonstrate public power's conumitment to reliable electric service," said the Association's Senior Vice President of Engineering Services, Michael Hyland. M �1 `ITT=proua to receive tfus recognition. it is a testament to the hard work of all our staff to ensure thal the lights stay on for all our customers," said Jeremy Carter, General Manager at Hutchinson Utilities, The American Public Power Association has offered the RP3 designation for 13 years now. The Association is the voice of not -for -profit, community -owned utilities that power 49 million people in 2,000 towns and cities nationwide. The Association advocates and advises on electricity policy, technology, trends, training, and operations, Work Order Description 11708 units 6&7 omnz Unit oBuilding spancret Joint Replacement zzmna Unit zControl Building Air Conditioning 11803 Plant zCooling Tower Piping Replacement 11804 Soft Start Motor Controllers for Air Supply Fan zzmns Replace Stage a-sxpcBlades 11806 Unit zceMsData Logger 11807 Plant zPipe Replacement Engineering Electric Production Total Total Percentage Materials Labor Budgeted Actual Difference Completed $»4,ae9,rnz.on $ $»4,aa9,7oz.00 $ 678,837.30 $ (13'691'064.70) 10,000.00 $ 10,000.00 ' $ (10,000.00) zs'Onoon $ zs'000.00 - $ (zs'ooO.on) asO'Onn.no $ asn'onnoO - $ (aso'ooOun) 0'000.00 z'nonon $ zn'onnoO amgJz $ (e'710.20) zsn'onn.no $ zsn'onn.00 - $ (zso'oon.on) 30,000o0 $ an'nonoO - $ (so'noO.On) 7nonoO ----�� -_ $7,000.00 -_ $ 570,000o0 $ a'non.nn $ 572'000.00 $ 289J2 $ (571,713.28) Electric Distribution Work Total Total Percentage Order Description Materials Labor Budgeted Actual Difference Completed 21801 Pole Repair or Replacement 15,000.00 - 15,000.00 - $ (15,000.00) 21802 Hutch Substation Roof Replacement 10,000.00 10,000.00 - $ (10,000.00) 21803 Station Equipment 10,000.00 10,000.00 $ (10,000.00) 21804 Duct for Reconductor 15,000.00 65,000.00 80,000.00 $ (80,000.00) 21805 Uponer New Feed 85,000.00 50,000.00 135,000.00 $ (135,000.00) 21806 Feeder 16 and 17 Reconductor 30,000.00 70,000.00 100,000.00 $ (100,000.00) 21807 MITGI New Feed 80,000.00 35,000.00 115,000.00 $ (115,000.00) 21808 New Developments 50,000.00 50,000.00 292.26 $ (49,707.74) 21809 Century Court Apartments 20,000.00 15,000.00 35,000.00 $ (35,000.00) 21810 Century Avenue Trail Work Feeder 22 10,000.00 10,000.00 20,000.00 $ (20,000.00) 21811 New Developments Transformers 50,000.00 50,000.00 $ (50,000.00) 21812 Plant 14160 Generator Transformer Repl 70,000.00 5,000.00 75,000.00 $ (75,000.00) 21813 Transformer Replacements 40,000.00 14,000.00 54,000.00 $ (54,000.00) 21814 Century Court Apartments 10,000.00 3,000.00 13,000.00 $ (13,000.00) 21815 Meters 30,000.00 - 30,000.00 - $ (30,000.00) $ 525,000.00 $ 267,000.00 $ 792,000.00 $ 292.26 $ (791,707.74) Administrative Total Work Order Description Budeeted 51801 Replace 2008 Super Duty Bucket Truck 140,000.00 51802 Replace 2007 Metering Van 25,750.00 51803 Replace 2006 Production Dodge Dakota 25,000.00 51804 Replace 2006 Ford F150 25,750.00 51805 Replace Vehicle #433 37,080.00 Total Actual Difference 140,000.00 25,750.00 25,000.00 25,750.00 $ (37,080.00) $ 253,580.00 $ - $ (253,580.00) Percentage Completed Work Order Description 61801 Transmission Lateral u`*cp-ROW Easements 61802 Transmission Lateral u,*cp-Materials and Permits 61803 Lafayette Interconnect Metering Upgrade 61804 Locator 61805 M\scDevelopments and Improvements 61806 Regulator Station Improvements 61807 Service Lines 61808 Meters, *m|'and all Fittings 61809 Industrial Metering and Regulation Natural Gas Total Materials Labor Budgeted $ 500,000.00 g 4,200.00 $ 504,200.00 g z'000'000uo 4,200.00 1,004,200.00 go'000uo zm'00000 108'000.00 6,000.00 - $ 6'000.00 zas'000un am'00000 $ zsa'onouo zs'000.no 4,e00.00 $ zg'goo.00 ss'oon.no az's0000 $ 86,sono0 e0,000.00 4,e00.00 $ e4'900o0 80,000.00 7'000.00 $ 87'000.00 Total Percentage Actual Difference Completed $ (sm\aoo.00) $ (1,00*200o0 $ (108,000.00) $ (6,000.00) 1,204.27 $ (151,795.73) $ <ze'euo.mo> 6,657.35 $ (7e,84265) 3'767.45 $ (91,132s5) 11,62947 $ <2,052,07093> OS HUTCHINSON UTILITIES COMMISSION 9T, Board Action Form iiiiiiiiiiiiiiiiiiiiiillillillillillillilliillillillillillillilliilliillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliilllI Agenda Item: Review Policies Presenter: Jeremy Carter 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. Sealing of Meters — Electric ii. Meter Testing - Electric iii. Right -of -Way Clearing iv. Promotions and Transfers v. Layoffs vi. Voluntary Leave of Absence BOARD ACTION REQUESTED: None Fiscal Impact: Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: RemainingCost: Sealing of Meters Electric meters and current transformer housings, which have been sealed by HUC, shall not be broken or tampered with without the consent of HUC except in emergency cases. HUC shall be notified immediately after a seal has been broken. If HUC is not notified and HUC personnel discover a broken seal, a $10 broken seal charge may be assessed to the customer. Seals will be assigned to each meter/account by color according to the following: Gray Seal Regular Account Red Seal Meter Disconnected for Non -Payment Blue Seal Meter Disconnected by Customer Request Yellow Seal Life Support Equipment Meter Testing HUC will test all meters periodically for accuracy and mechanical condition. All electric meters must be accurate to within 2%, plus or minus, at full and light load. Upon request of the customer, HUC will test the accuracy of an electric meter. If the meter is found to be registering more than 2% fast, there will be no testing charge to the customer. If the meter is found to be accurate within the 2% limit, a $40 trip charge will be billed to the customer. HUC has the right to place special meters on the premises of a customer for the purpose of testing all or part of the customer's load at no expense to the customer. Right -of -Way Clearing HUC shall maintain right-of-way clearance on all overhead and underground facilities. EXEMPT PROMOTIONS AND TRANSFERS HUC encourages individual advancement by providing opportunities for promotion and transfer as positions become available. Job vacancies shall be posted ten (10) working days. Employees desiring to be considered for the position must provide a letter of interest to the appropriate staff person by the deadline stated on the posting. All promoted employees shall serve a six (6) month probationary period during which time the promoted employee may be placed back in the employee's previous job classification if a position is available and at the sole discretion of the Staff Personnel, without loss of seniority. We encourage employees to discuss their career plans and goals with their Director or Manager. NON-EXEMPT PROMOTIONS AND TRANSFERS HUC encourages individual advancement by providing opportunities for promotion and transfer as positions become available. Job vacancies shall be posted ten (10) working days. Employees desiring to be considered for the position must provide a letter of interest to the appropriate staff person by the deadline stated on the posting. All promoted employees shall serve a six (6) month probationary period during which time the promoted employee may be placed back in the employee's previous job classification if a position is available and at the sole discretion of the Staff Personnel, without loss of seniority. We encourage employees to discuss their career plans and goals with their Director or Manager. EXEMPT LAYOFFS HUC retains its right toe I iminate positions within the organization if the Commission deems it appropriate to do so. If a layoff occurs, HUC will provide four weeks' notice to affected employees. Layoffs will be based on skill, knowledge, utility needs and also employee's seniority. NON-EXEMPT LAYOFFS HUC retains its right to eliminate positions within the organization if the Commission deems it appropriate to do so. If a layoff occurs, HUC will provide four weeks' notice to affected employees. Layoffs will be based on the Utility's skill and knowledge needs and also employee's seniority. EXEMPT VOLUNTARY LEAVE OF ABSENCE HUC may request employees to voluntarily take a leave of absence without pay for a specified period of time. NON-EXEMPT VOLUNTARY LEAVE OF ABSENCE HUC may request employees to voluntarily take a leave of absence without pay for a specified period of time. OS HUTCHINSON UTILITIES COMMISSION 9T, Board Action Form iiiiiiiiiiiiiiiiiiiiiillillillillillillilliillillillillillillilliilliillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliillillillillillillillillillillilliillillillillillillilliillillillillillillilliilllI Agenda Item: Approve Policy Changes Presenter: Jeremy Carter Agenda Item Type: Time Requested (Minutes): 5 App 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. Electric Meter Placement BOARD ACTION REQUESTED: Approve Policy Changes Fiscal Impact: Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: RemainingCost: Electric Meter Placement HUC reserves the right to specify the electric meter location on all installations. Electric service lines and meter housing are the property of the home/business owner. Meters may be relocated to a location agreed upon by HUC and the CLISt met (of location approvedappioved by HUC). The customer will be responsible for all costs involved in relocating these facilities. All meters must be located on an external wall. New construction electric meters must be located within 10 feet of the natural gas meter if HUC is providing both services. Electric meters shall be accessible at all times for disconnection, examination, reading, replacement or necessary maintenance. Electric meters not accessible are subject to disconnection and will need to be moved to a location approved by HUC, at the home/business owner's expense. HUC requires a minimum of a 3-foot clear zone in front of the electric meter. Reasonable care must be taken to protect all metering facilities when remodeling, test i g,roofing, painting, etc. In the event of damage to the electric facilities, the customer shall be responsible for the cost of repairing or replacing the electric facilities. Conditions may exist which may require other restrictions or distances (e.g. multiple meters or commercial/industrial). Any exceptions require the approval of HUC prior to the start of construction. If violations or deviations are determined, the customer will be responsible for the cost of the correction. Single Family Dwellings All residential electric metering facilities shall be located on the side of the home within 6 feet of the front building wall and 60 inches from finished grade. Front building wall is defined as the wall nearest the street of the resident's living space. Multi -Family Dwellings/Multiple Business Establishments All HUC electric meters must be located on the exterior wall of the building. Individual metering is required for each single-family private residence contained in a multi -family dwelling and each separately owned and/or operated business. In addition, if required, a "house meter" shall also be installed in these establishments. Commercial or Industrial All commercial and industrial electric meters must be located outside. If remodeling is done on the premises, which would cause the meter to be located inside, the owner, at owner's expense, must relocate the meter to the outside to a location agreed upon (of appio ved by) by HUC. 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M CD C L] U A. - +- O O c C S L L] C L M Co O U I O L I o M E O_ C a C3 C Z O C Cn Co O C 3 CD Co C/] CD L C/] C L- E m E C/] ED Ll 0 C cn C o] L co E ED L ED E co ED . i 0 L a O ED L co C O C O U C O +� Co C C a E U L O] L Co Co O_ C L S Co M O CO +- O CD Co C C CD M c A.— Co C L] C3 cm U C .LE CD O L c ro E CD m ro �C L O CO A. - CD C C ro Co O L-I.- A. -i C CD L c =3 C/3 m -" -' =3 s C/] A. — CD O Cv MM HUTCHINSON UTILITIES COMMISSION�� Board Action Form �'Ylkll'M1'k� Agenda Item: Approval of "Incumbency Certificate" and "Board Resolution" Presenter: John Webster Agenda Item Type: Time Requested (Minutes): 3 New Business Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA ITEM: Incumbency Certificate In order to participate in the natural gas prepay program Hutchinson Utilities must comply with certain Dodd Frank protocols. The first being an Incumbency Certificate which states that certain individuals can enter into derivative agreements, such as an ISDA, on behalf of Hutchinson Utilities Commission and provides sample signatures for them and: Board Resolution This is an action that authorizes Hutchinson Utilities Commission to enter into any agreement for the purchase and sale of financial derivatives or physical commodities and then authorizes the Hutchinson Utilities Commission President to execute any and all agreements such person deems advisable in connection with such authorization BOARD ACTION REQUESTED: Approval of "Incumbency Certificate" and "Board Resolution" Fiscal Impact: Reduction in base load costs Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: Remaining Cost: HUTCHINSON UTILITIES COMMISSION HUTCHINSON MINNESOTA INCUMBENCY CERTIFICATE THE UNDERSIGNED, BEING THE DULY QUALIFIED AND ACTING CSECRETARY1 OF HUTCHINSON UTILITIES COMMISSION, A MINNESOTA MUNICIPAL UTILITY (THE "COMPANY") DOES HEREBY CERTIFY THAT: 1. THE FOLLOWING PERSON IS A DULY ELECTED OFFICER OF THE COMPANY; 2. THE FOLLOWING PERSON IS AUTHORIZED TO EXECUTE MASTER AND AMENDMENT AGREEMENTS; AND 3. THE SIGNATURE SET FORTH OPPOSITE HIS NAME AND OFFICE IS HIS GENUINE SIGNATURE: NAME OFFICE SPECIMEN SIGNATURE MONTY PRESIDENT MORROW IN WITNESS WHEREOF, I HAVE HEREUNTO SET MY HAND THIS 28TH DAY OF MARCH, 2018. ROBERT WENDORFF SECRETARY HUTCHINSON UTILITIES COMMISSION RESOLUTION AUTHORIZING HUTCHINSON UTILITIES COMMISSION TO ENTER INTO ANYAGREEMENT FOR THE PURCHASE AND SALE OF FINANCIAL DERIVATIVES OR PHYSICAL COMMODITIES WHEREAS, HUTCHINSON UTILITIES COMMISSION HAS THE UNIQUE OPPORTUNITY TO PARTICIPATE IN A NATURAL GAS COMMODITY PREPAY DEAL TO PROVIDE ITS CUSTOMERS WITH REDUCED PRICE BASE LOAD NATURAL GAS BE IT RESOLVED BY THE HUTCHINSON UTILITIES COMMISSION AS FOLLOWS: TO ENTER INTO ANY AGREEMENT, INCLUDING AN ISDA AGREEMENT, FOR THE PURCHASE AND SALE OF FINANCIAL DERIVATIVES OR PHYSICAL COMMODITY. 2. TO AUTHORIZE THE HUTCHINSON UTILITIES COMMISSION PRESIDENT TO EXECUTE ANY AND ALL AGREEMENTS THE COMMISSION PRESIDENT DEEMS ADVISABLE IN CONNECTION WITH SUCH AUTHORIZATION. 2018. ADOPTED BY THE HUTCHINSON UTILITIES COMMISSION THIS 28TH DAY OF MARCH, ATTEST: ROBERT WENDORFF, SECRETARY MONTY MORROW, PRESIDENT HUTCHINSON UTILITIES COMMISSION�� Board Action Form 'Ylkll'M1'k Agenda Item: Approve Requisition No. 007499 for Chevrolet Silverado Presenter: John Webster Agenda Item Type: Time Requested (Minutes): 2 New Business Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA ITEM: In compliance with the 2018 Fleet Management Program the Natural Gas Division is to replace vehicle #433, 2006 Chevrolet 1500 4WD w/utility body. The replacement vehicle that is being recommended by Hutchinson Utilities is a 2018 Chevrolet Silverado 350OHD 4WD Crew Cab w/167.7" wheelbase. The existing utility box in use on vehicle #433 will be installed on the vehicle to be purchased. The pickup bed/box for the 2006 vehicle will be reinstalled prior to the sale. The new pickup bed/box will be sold in the near future. State Bid Contract No. 135740 Contract Release T-642(5) State I D 87 Hutchinson Utilities will offer the 2006 Chevrolet 1500 up for sale in 2018. BOARD ACTION REQUESTED: Approval of Requisition No. 007499. Fiscal Impact: $32,913.95 Included in current budget: Yes Budget Change: No PROJECT SECTION: Total Project Cost: Remaining Cost: %rom z HUTCHINSON UT'IIILIIT'IIIE'S RANGER GM 1502 E HOWARD STREET HIBBING, MN 55746 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. 03/02/2018 007499 Required by: Requested by: JWebster Item Part No. Description Qty Unit Due Date Unit Price Ext. Amount No. 2018 CHEVROLET SILVERADO 3500 - 4WD, - SINGLE REAR WHEEL, CREW CAB, CK35943, 1 000-00000 167.7" WB, MN STATE BID ID 87 1.00 EA 03/02/2018 $30,122.700 $30,122.70 MFG. PART: OPTION: ZY1 - PAINT, SOLID - MFG. PART: 2 000-00000 1.00 EA 03/02/2018 $0.000 $0.00 OPTION: GAZ - SUMMIT WHITE PAINT - MFG. PART: 3 000-00000 1.00 EA 03/02/2018 $0.000 $0.00 OPTION:H2R - DARK ASH W/JET BLACK - INTERIOR ACCENTS, CLOTH SEAT TRIM 4 000-00000 MFG. PART: 1.00 EA 03/02/2018 $0.000 $0.00 OPTION: AE7 - CLOTH SEATS - MFG. PART: 5 000-00000 1.00 EA 03/02/2018 $0.000 $0.00 OPTION: VYU - SNOW PLOW PREP PACKAGE MFG. PART: 6 000-00000 1.00 EA 03/02/2018 $338.800 $338.80 OPTION: K05 - ENGINE BLOCK HEATER - MFG. PART: 7 000-00000 1.00 EA 03/02/2018 $88.000 $88.00 OPTION: 91-7 - UPFITTER SWITCHES - MFG. PART: 8 000-00000 1.00 EA 03/02/2018 $110.000 $110.00 Date Printed: 03/23/2018 Requisitioned By: JWebster Page: 1/2 %rom z HUTCHINSON UT'IIILIIT'IIIE'S RANGER GM 1502 E HOWARD STREET HIBBING, MN 55746 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. 03/02/2018 007499 Required by: Requested by: JWebster Item No. Part No. Description Qty Unit Due Date Unit Price Ext. Amount OPTION: 8S3 - BACKUP ALARM - MFG. PART: 9 000-00000 1.00 EA 03/02/2018 $121.440 $121.44 TAX - MFG. PART: 10 000-00000 1.00 EA 03/02/2018 $2,000.760 $2,000.76 TITLE & LICENSE PLATE - MFG. PART: 11 000-00000 1.00 EA 03/02/2018 $132.250 $132.25 Total: 32,913.95 Date Printed: 03/23/2018 Requisitioned By: JWebster Page: 2/2 HUTCHINSON UTILITIES COMMISSION�� Board Action Form �'Ylkll'M1'k� Agenda Item: Approve Proposed Pipeline Imbalance Settlement Agreement Presenter: Jeremy Carter Agenda Item Type: Time Requested (Minutes): 5 New Business Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA ITEM: Hutchinson Utilities staff has been working towards a resolution on the Natural Gas (NG) pipeline imbalance that occurred between the time periods of January 1st, 2013 - July 31st, 2015 with the remaining stakeholder. Based on the amount of time put in by all stakeholders involved in resolving the pipeline imbalance and the comfort level of the calculations, numbers, and resolution discussed, HCP has provided HUC with a proposed settlement agreement that states the volume and liability owed by HUC, which was based off original calculations and analysis performed by HUC. The proposed settlement agreement for approval represents the remaining portion of the liability owed by HUC in resolving this item. HUC staff is very appreciative of the cooperation and time spent by all parties involved in resolving the imbalance. This final settlement agreement being presented will bring the NG pipeline imbalance to conclusion. BOARD ACTION REQUESTED: Approve Settlement Agreement Fiscal Impact: Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: Remaining Cost: SETTLEMENT AGREEMENT AND MUTUAL RELEASE This Settlement Agreement and Mutual Release ("Settlement Agreement"), entered into this day of March, 2018, by and between the Hutchinson Utilities Commission of the City of Hutchinson, Minnesota ("Hutchinson") and Heartland Corn Products ("Heartland") of Winthrop, Minnesota, for and in consideration of the recitals, mutual agreements and covenants described below. RECITALS A. Hutchinson and Heartland are parties to various agreements relating to an intrastate natural gas pipeline from a point on the Northern Border Pipeline near Trimont, Minnesota, to a point of terminus near Hutchinson, Minnesota ("Pipeline"). B. The use of the Pipeline pursuant to the various agreements provides natural gas to Heartland, natural gas which is nominated, received and used by Heartland, and for which Heartland pays a fee for the natural gas received by Heartland. C. For a period of time between January 1, 2013 and July 31, 2015, a problem arose whereby inaccurate and overstated meter readings resulted in Heartland being excessively charged for the amount of natural gas Heartland received and used. D. As a result of the foregoing, Hutchinson and Heartland desire to voluntarily address and mutually resolve in good faith claims relating to Heartland's overpayment of the natural gas transported through the Pipeline to Heartland's facility during the period of time noted above, pursuant to these Recitals and the terms and conditions set forth below. AGREEMENTS 1. Consideration by the Parties. In consideration for all of the terms and conditions of this Settlement Agreement, including the above Recitals which are expressly incorporated herein by reference, Hutchinson shall pay Heartland the sum of $458,954.80 within sixty (60) days from the date the last party signs this Settlement Agreement. The sum of $458,954.80 represents an overcharge of about 90,468 dekatherms of natural gas paid for but not received or used by Heartland during the period of time noted above. 2. Release of Claims by Heartland. In consideration of, and only upon Hutchinson's full compliance with the terms and conditions of this Settlement Agreement, the receipt and sufficiency of which is hereby acknowledged, Heartland, for itself and for each of its parent corporations, affiliated corporations, subsidiaries, divisions, insurers, indemnitors, attorneys, successors, representatives, agents, heirs, assigns, directors, partners, owners, members, shareholders, officers, and employees does hereby release and forever discharge Hutchinson and each of its parent corporations, affiliated corporations, subsidiaries, divisions, insurers, indemnitors, attorneys, successors, representatives, agents, heirs, assigns, directors, partners, owners, members, shareholders, officers, and employees, of and from any and all actions, suits, proceedings, claims (including, but not limited to, claims for attorney's fees), complaints, judgments, executions, whether liquidated or unliquidated, known or unknown, asserted or unasserted, absolute or contingent, accrued or not accrued, arising out of and related to the Pipeline overcharge for the time period noted in Recital C., above. Notwithstanding anything herein to the contrary, this Settlement Agreement does not release Hutchinson from its obligations provided for in this Settlement Agreement. Moreover, Hutchinson and Heartland expressly reserve their rights to bring, assert, pursue, prosecute and file any and all known or unknown action, suit, proceeding, claim, complaint, cause of action, demand, damages, losses, costs, expenses, defenses, set-off, recoupment, in law or in equity, in contract, in tort or otherwise, against any other individual, party or entity not a party to this Settlement Agreement, and Hutchinson and Heartland expressly reserve any and all rights they may have against any such individual, party or entity. 3. Release of Claims by Hutchinson. Inconsideration of the other terms and conditions of this Settlement Agreement, the receipt and sufficiency of which is hereby acknowledged, Hutchinson, for itself and for each of its parent corporations, affiliated corporations, subsidiaries, divisions, insurers, indemnitors, attorneys, successors, representatives, agents, heirs, assigns, directors, partners, owners, members, shareholders, officers, and employees does hereby release and forever discharge Heartland and each of its parent corporations, affiliated corporations, subsidiaries, divisions, insurers, indemnitors, attorneys, successors, representatives, agents, heirs, assigns, directors, partners, owners, members, shareholders, officers, and employees, of and from any and all actions, suits, proceedings, claims (including, but not limited to, claims for attorney's fees), complaints, judgments, executions, whether liquidated or unliquidated, known or unknown, asserted or unasserted, absolute or contingent, accrued or not accrued, arising out of and related to the Pipeline overcharge for the time period noted in Recital C., above. Notwithstanding anything herein to the contrary, this Settlement Agreement does not release Heartland from its obligations provided for in this Settlement Agreement. Moreover, Hutchinson and Heartland expressly reserve their rights to bring, assert, pursue, prosecute and file any and all known or unknown action, suit, proceeding, claim, complaint, cause of action, demand, damages, losses, costs, expenses, defenses, set-off, recoupment, in law or in equity, in contract, in tort or otherwise, against any other individual, party or entity not a party to this Settlement Agreement, and Hutchinson and Heartland expressly reserve any and all rights they may have against any such individual, party or entity. 4. Mutual Indemnification. Except as otherwise provided in this Settlement Agreement, any party to this Settlement Agreement that breaches the terms of or fails to perform fully any of its obligations under this Settlement Agreement ("Breaching Party") shall indemnify, defend and hold the non -breaching party and their respective parents, subsidiaries, divisions, affiliates, principals, employees, associates, agents, representatives, consultants, officers and directors, predecessors and successors (collectively "Non - Breaching Indemnified Parties") harmless from and against any and all liabilities, claims, demands, damages, losses, costs, expenses, penalties and assessments including, without limitation, reasonable attorneys' fees and costs, technical and consultant fees and costs, and expert witness fees and costs, incurred by the Non -Breaching Indemnified Parties as a W result of the Breaching Party's breach of or failure to perform fully any of its obligations under this Settlement Agreement. The indemnification obligations of Hutchinson and Heartland under this paragraph shall survive indefinitely and shall be unlimited as to amount. 5. Non -Disparagement. Hutchinson and Heartland acknowledge and agree that, as part of the consideration for this Settlement Agreement, and as an expression of their mutual desire to obtain a good faith and amicable resolution of this Pipeline overcharge matter, neither party will make any disparaging or derogatory statements, whether oral or written, about the other, or the other's business activities. 6. Non -Admission of Liability. By executing this Settlement Agreement, Hutchinson and Heartland understand and agree that this Settlement Agreement does not constitute, nor should it be construed as an admission of liability, fault or wrongdoing by any of the parties to this Settlement Agreement. 7. Voluntary Nature of Agreement. Hutchinson and Heartland acknowledge and agree that they have entered into this Settlement Agreement voluntarily and without any coercion. They further represent that they have had the opportunity to consult with legal counsel of their own choice, that they have read the terms of this Settlement Agreement, and that they fully understand and voluntarily accept the terms. 8. Authority. Each party signing this Settlement Agreement represents and warrants that the person signing this Settlement Agreement on its behalf has the full authority to bind that party to the terms and conditions of this Settlement Agreement. 9. Construction of Agreement. Each party signing this agreement has been able to review, comment on and revise this Settlement Agreement, and it shall be construed as if each party jointly prepared it, and any uncertainty or ambiguity shall not be interpreted against any one party and in favor of the other party. In the event any one or more of the terms, conditions or provisions of this Settlement Agreement is deemed invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions will not in any way be affected or impaired. 10. Governing Law and Choice of Forum. This Settlement Agreement shall be construed and interpreted in accordance with the laws of the State of Minnesota without regard to conflict of law principles. Any action to interpret or enforce this Settlement Agreement shall be filed in the courts of Minnesota, which shall have exclusive jurisdiction of such claims. Hutchinson and Heartland hereby consent to personal jurisdiction in Minnesota and waive any argument that Minnesota is an improper venue or a less convenient venue. 11. Arbitration. Except as otherwise agreed to by both parties in writing, Hutchinson and Heartland shall submit any disputes concerning this Settlement Agreement and the overcharge matter to non -binding arbitration; provided, however, that such disputes shall first be the subject of informal, good faith negotiation between the Parties. If such negotiation fails to resolve the Parties' dispute(s), then either party may send written notice 3 to the other party of such party's intent to submit the issue to non -binding arbitration, with the non -binding arbitration proceeding to be governed solely and entirely by an agreed upon non -binding arbitration process in Minnesota. A party who is dissatisfied with the result of the non -binding arbitration proceeding has fourteen (14) days within an arbitrator's decision to initiate a legal action in a court of competent jurisdiction and venue. 12. Entire Agreement. The terms of this Settlement Agreement supersede and terminate all prior oral and written agreements and communications between the parties relating to the Pipeline overcharge matter, and this Settlement Agreement contains all of the agreements between Hutchinson and Heartland relating to the same. 13. Execution in Counterparts. Hutchinson and Heartland agree that this Settlement Agreement may be executed simultaneously in two or more counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument. The parties further contemplate that they may execute this Settlement Agreement facsimile or email, and that certain actions may be taken in reliance on facsimile or emailed signatures on this Settlement Agreement, and shall be equally valid and binding as an original signature, and will have the same legal effect as physical delivery of an original signature. Heartland Corn Products By: Its: Date Hutchinson Utilities Commission City of Hutchinson, Minnesota By: Its: Date: By: Its: Date: 4 -i e __! |a==! j- -`\ ,,,, \ \\\) /\\\\) � 2 -i 11-61 j�2 j�2 \ � m -i j��\ E� \\ �t O \ 0 \ / / 0 _ _ ƒ >1 2 | O \ 0 \ / / 0 _ _ ƒ >1 2 A B CO )--\ 0000 '00-m \ \\\\ � D Cl) D F-i-5.5-7 V, E n 2 r Hutchinson Utilities Commission Gas Rate Design Residential Service with 2% Revenue increase Current Rate Monthly Proposed Rate Summer Winter Customer Gas Commodity Purchased Gas Charge Charge $/MCF Adjustment $ 6.50 $ 9.0800 $ (1.1993) $ 6.50 $ 9.0800 $ (1.1993) Customer Gas Commodity Purchased Gas Charge Charge $/MCF Adjustment Monthly Summer $ 8.50 $ 8.9677 $ (1.1993) Winter $ 8.50 $ 8.9677 $ (1.1993) Cost of Service Charges $ 21.34 $ 0.6748 Estimated Change in Revenues Current Revenues $ 3,703,085 Proposed Revenues 3,777,147 5 $ 45.90 $ 47.34 $ 1.44 3.1% 7 61.66 62.88 1.21 2.0% 9 77.43 78.42 0.99 1.3% 11 93.19 93.95 0.76 0.8% 13 108.95 109.49 0.54 0.5% 15 124.71 125.03 0.32 0.3% IMMMI' 4 fiNk,y, Ifinmmlwl :AJx k.aa. ns, L,LC Hutchinson Utilities Gas Department Rate Design for 2018 Options OPTION A with +/- 2.0% Estimated Revenue Change with implementation of Retail rate adjustments without contract adjustments Rate Class Cos Projected 2018 2019 Residential $ 3,096,455 $ 3,703,084 -0.4% 3,688,272 3,673,519 Commercial 2,280,977 2,865,103 -0.9% 2,839,317 2,813,763 Large Industrial 279,562 426,227 -2.0% 417,703 409,349 Test Customer 1 - HTI 354,737 273,670 0.0% 273,670 273,670 Test Customer 2 - 3M 2,918,717 2,595,730 0.0% 2,595,730 2,595,730 Total $ 8,930,448 $ 9,863,814 9,814,692 9,766,031 -0.5% -0.5% Estimated Annual Revenue Adjustment ® Option A $ (49,123) $ (48,661) OPTION B with +/- 4.0% Rate Class Cos Projected 2018 2019 Residential $ 3,096,455 $ 3,703,084 -0.8% 3,673,274 3,643,705 Commercial 2,280,977 2,865,103 -1.3% 2,826,711 2,788,833 Large Industrial 279,562 426,227 -3.4% 411,608 397,490 Test Customer 1 - HTI 354,737 273,670 0.0% 273,670 273,670 Test Customer 2 - 3M 2,918,717 2,595,730 0.0% 2,595,730 2,595,730 Total $ 8,930,448 $ 9,863,814 9,780,993 9,699,427 -0.8% -0.8% Estimated Annual Revenue Adjustment ® Option B $ (82,822) $ (81, 66) OPTION C with +/- 6.0% Rate Class Cos Projected 2018 2019 Residential $ 3,096,455 $ 3,703,084 -1.5% 3,649,019 3,595,744 Commercial 2,280,977 2,865,103 -2.3% 2,800,352 2,737,064 Large Industrial 279,562 426,227 -5.4% 403,339 381,680 Test Customer 1 - HTI 354,737 273,670 0.0% 273,670 273,670 Test Customer 2 - 3M 2,918,717 2,595,730 0.0% 2,595,730 2,595,730 Total $ 8,930,448 $ 9,863,814 9,722,110 9,583,887 -1.4% -1.4% Estimated Annual Revenue Adjustment ® Option C $ (141,705) $ (138,223) 1 Utility Financial Solutions, LLC