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01-31-2018 HUCCP HUTCHINSON UTILITIES COMMISSION AGENDA REGULAR MEETING January 31, 2018 3:00 p.m. 1. CONFLICT OF INTEREST 2. COMMISSION REORGANIZATION a. President b. Vice President c. Appoint Secretary d. Appoint Legal Council e. Appoint Recording Secretary f. Designate Depositories for Utility Funds i. Citizens Bank & Trust ii. Wells Fargo Bank iii. Wells Fargo Advisors iv. Home State Bank v. Morgan Stanley vi. Cetera Investment Services 3. APPROVE CONSENT AGENDA a. Approve Minutes b. Ratify Payment of Bills 4. APPROVE FINANCIAL STATEMENTS 5. OPEN FORUM 6. COMMUNICATION a. City Administrator b. Divisions c. Legal d. General Manager 7. POLICIES a. Review Policies i. Administration of Personnel Policies & Procedures ii. Savings Clause iii. Equal Employment Opportunity iv. Identity Theft Red Flag Program v. Minnesota Government Data Practices Act & Public Records Request b. Approve Changes - None 8. UNFINISHED BUSINESS a. Update on Pack Gas Discussions 9. NEW BUSINESS a. Natural Gas Transportation Agreement b. Gas Transportation Agreement c. d. Approve 3M CIP Rebate e. Discussion of PILOT Resolution f. Discussion of Cost of Service Study 10. ADJOURN MINUTES Regular Meeting Hutchinson Utilities Commission Wednesday, December 20, 2017 Call to Order 3:00 p.m. In the absence of President Monty Morrow, Vice President Anthony Hanson called the meeting to order at 3:00 p.m. Members present: Vice President Anthony Hanson; Commissioner Robert Wendorff; and Commissioner Don Martinez. Secretary Mark Girard was absent. Others present: General Manager Jeremy Carter; Attorney Marc Sebora. 1. Conflict of Interest There were no conflicts of interest noted. 2. Approve Consent Agenda a. Approve Minutes b. Ratify Payment of Bills Motion by Commissioner Wendorff, second by Commissioner Martinez to approve the Consent Agenda. Motion carried unanimously. 3. Approve Financial Statements General Manager Carter and Jared Martig presented the financial statements. Jared Martig noted with the early meeting that there were a few estimates used. Everything is on track for the Electric Division. Gas Division shows a decrease from last year of $51k, however there was a $236k payment received on the Lafayette improvements in Other Revenues in November 2016. General Manager Carter noted the Electric Division cash increased due to receiving $17M in bond proceeds. Electric Division is fairly consistent. General Manager Carter also mentioned there was a 37% increase in heating days. Jared Martig mentioned that there was $13M invested in short-term bonds. Motion by Commissioner Martinez, second by Commissioner Wendorff to approve the financial statements. Motion carried unanimously. 4. Open Forum - none 5. Communication a. City Administrator Matt Jaunich- Absent b. Divisions i. Dan Lang, Engineering Services Manager Absent ii. Dave Hunstad, Electric Transmission/Distribution Manager Starting on hotel site and will be setting up temporary power this week 1 iii. Randy Blake, Production Manager Continuing to work on units 6 & 7. Have some building modifications coming up; concrete foundation has to be cut- down and recapped, remove walls at Plant 1, remove old Tower water pump bases, replace underground 16-inch pipes to 20-inch. These projects will all be coming forth. Will be going out to get local bids to remove walls. Also working hard at Unit 8 to get the exciter project done for year-end. iv. John Webster, Natural Gas Division Manager- End of year v. Jared Martig, Financial Manager End of year. c. Brenda Ewing, Human Resources Nothing to report d. Legal Marc Sebora Nothing to report e. General Manager Jeremy Carter i. Working on year-end. Auditors will be here January 29 ii. Will be having an on-site Cost of Service Study presentation January 17 at 3:30pm. Have extended an invitation to Matt Jaunich and City Council to attend. Location is yet to be determined. iii. Met with the PILOT committee this week. Made some minor wording changes to the amended draft resolution and the revisions were sent to the commission. iv. Next month need to look at reorganization and elect new officers v. Finished up benefits. 6. Policies a. Review Policies i. Purpose of this Handbook ii. Surplus Property Policy (every 3 years) b. Approve Changes i. Section 1 Introduction as noted, adding clarity ii. Definitions as noted, more current with terminology iii. Payments of HUC Payables as noted, amending dates every year. Motion by Commissioner Wendorff, second by Commissioner Martinez, to approve the policy changes as recommended. Motion carried unanimously. 7. Unfinished Business a. Update of Pack Gas Discussions Mr. Sebora noted there is nothing new from Heartland Corn. There has also been turnover at Nu-Ulm so there may be delays. Expecting to take longer. 8. New Business a. Approve 2018 Budget Mr. Carter spoke about the 2018 Budget. Mr. Carter pointed out in the Budget packet on page 71, 2016 is listed as a budget, these numbers are actual not budget 2 numbers. Last month Mr. Martinez mentioned to revisit the depreciation numbers, this was reviewed and has now been increased by $100k. Commissioner Hanson inquired about the 2018 pilot transfer. Mr. Carter noted the pilot would increase over the next 3 years phasing in a 4.5% increase. After further discussion, Mr. Carter looked at the commission for feedback on the presentation budget book. Last year there were more spreadsheets. This year it was designed to be more readable. Commissioner Hanson noted that he had talked with President Morrow and Secretary Girard and they are both pleased with the budget. Motion by Commissioner Martinez, second by Commissioner Wendorff, to approve the 2018 Budget. Motion carried unanimously. b. Approve Moving 2018 Pay Grid Mr. Carter spoke about moving the 2018 Pay Grid. Every year inflation is considered so it can be determined if the pay grid is accurate. Brenda looked at indexes and it is recommended moving the pay grid 2%. This move does not affect performance but keeps up with the industry, inflation, and proper organizational structure. Mrs. Ewing noted the pay study was completed a couple years ago and this needs to be reviewed every few years. Commissioner Hanson inquired the timing for this to take place. Mr. Carter replied st the 1 quarter in 2018. Motion by Commissioner Wendorff, second by Commissioner Martinez, to approve Moving the 2018 Pay Grid. Motion carried unanimously. c. Conduct the Performance Review of Hutchinson Utilities Commission General Manager. Vice President Hanson introduced the ag performance review. Hanson advised General Manager Jeremy Carter that he has the option to have the performance review conducted as either an open session or a closed session of the Utility Commission. Mr. Carter indicated his decision to have the review as part of a closed session. Commissioner Hanson entertained a motion to go into closed session to conduct the twelve-month (annual) performance review as permitted under Minnesota Statute 13D.05, Subdivision 3(a). Motion by Commissioner Martinez, second by performance review. The motion passed unanimously. The Commission then proceeded into a closed session at 3:32 p.m. 3 Hutchinson Utilities Commission Summary of Closed Meeting Proceedings General Manager Performance Appraisal Wednesday, December 20, 2017 On December 20, 2017, the Hutchinson Utilities Commission conducted a closed meeting for the annual performance appraisal for General Manager, Jeremy Carter. Individuals present included General Manager Jeremy Carter, Commission Members Anthony Hanson, Don Martinez and Bob Wendorff, City Attorney Marc Sebora, and City of Hutchinson Human Resources Director Brenda Ewing. Commissioners Monty Morrow and Mark Girard were absent. Mr. Carter exercised his right to close the proceedings to the public as permitted under Minnesota Statute 13D.05, Subdivision 3(a). Motion by Martinez, second by Wendorff to go into closed session to conduct the General proceeded into a closed session at 3:32 p.m. is required per the terms of the employment contract in place between the Hutchinson Utilities Commission and General Manager Carter. s performance was evaluated in the following areas: Organizational Management, Fiscal/Business Management, Program Development, Relationship & Communication with the Commission, Long-Range Planning, and Relationships with Public & Outside Organizations. The consensus of the Commission was found to be 4.31 on the rating scale of 0 5, and, per the Hutchinson Utilities Commission, is exceeding job requirements on the ratings scale. The employment contract between Hutchinson Utilities and Mr. Carter indicates that salary increases for the General Manager are subject to the provisions of the Compensation Plan section of the Hutchinson Utilities Commission Exempt Employee Handbook. Motion by Wendorff, second by Martinez to approve a 2018 salary of $158,921.98, or a 6% annual increase of $8,995.58 over the 2017 salary. Motion carried unanimously. Motion by Martinez, second by Wendorff to close the closed session. The motion passed unanimously. The Commission proceeded into open session at 4:30 p.m. Motion to adjourn by Wendorff, second by Martinez. The motion carried unanimously, and the meeting adjourned at 4:31 p.m. Mark Girard, Secretary 4 ATTEST: Monty Morrow, President 5 MINUTES Special Meeting Hutchinson Utilities Commission Wednesday, January 17, 2018 Call to order 3:00 p.m. President Morrow called the meeting to order. Members present: President Monty Morrow; Vice President Anthony Hanson; Secretary Mark Girard; Commissioner Robert Wendorff; Commissioner Don Martinez; General Manager Jeremy Carter. Others present: Randy Blake, John Webster, Jared Martig and Angie Radke. The purpose of the special meeting is to approve advertising for bids of concrete cutting and generator foundation work on units 6 & 7 and to approve the Engineering Agreement with HDR for the Cooling Tower Piping Project. GM Carter communicated with new units 6 & 7, there is much planning and prep work that needs to be done before the new units are installed. The old units 6 & 7 had certain foundation heights and widths, however with the upcoming installation of the new generating units foundation work needs to be completed to meet the new specifications and dimensions of the units. Staff is anticipating that work to be over $100k so a formal bidding process needs to occur. Staff is looking for commission approval to allow advertising for bids. Mr. Blake has contacted several contractors in advance to let them know of the project. With a bid closing date of February 12, this will be enough time to receive bids and allow staff and HDR about a week to review the proposals. After the review of bids, an additional meeting to approve the contractor will be requested. Mr. Blake added there is a lot of discussion and prep work that needs to be done to build the foundation back up to specs and make a smooth finished grade. Mr. Blake also added the engines will ship this summer. Commissioner Wendorff inquired how long will it take to prepare the foundations. Mr. Blake replied about 2 months. In the meantime, the piping needs to be worked on. Currently the piping is 16 inches and needs to be sized to 20 inches to accommodate the increased capacity needs of the new units. This has always been a project to work on and has been in the 5-year CIP plan in the past. Commissioner Hanson inquired if this was budgeted for in numbers. GM Carter replied piping has always been on the CIP list, these are all planned costs that were factored into the overall cost of the project. Concrete work was also planned work and part of the overall cost of the project. This project was going to be part of the original for mechanical and civil work but was broken out ahead of time to ensure the foundations are ready to go for engine installation. After more discussion, a motion was made by Commissioner Girard, seconded by Commissioner Hanson to approve Advertising for bids of concrete cutting and generator foundation work on units 6 & 7. GM Carter presented the need for approval of the Engineering Agreement with HDR for the Cooling Tower Piping Project. Cooling water system updates have been a part of management discussions and -going capital improvement projects for several years. This is a normal capital improvement that needs to me moved up now since we have 2 new units coming in. With HDR currently being the engineering firm charged with the overall generation project and has worked with HUC over the years, HDR is best positioned to provide these services. Commissioner Girard inquired about the cost. Mr. Blake communicated low end is $250k high end is $350k. After more discussion, a motion was made by Commissioner Martinez, seconded by Commissioner Wendorff to approve the Engineering Agreement with HDR for the Cooling Tower Piping Project. There being no further business, a motion was made by Commissioner Hanson, seconded by Commissioner Martinez to adjourn the meeting at 3:17 p.m. Motion was unanimously carried. __________________________ Mark Girard, Secretary ATTEST: _________________________ Monty Morrow, President MINUTES Special Meeting — Hutchinson Utilities Commission Wednesday, January 17, 2018 Call to order — 3:32 p.m. President Morrow called the meeting to order. Members present: President Monty Morrow; Vice President Anthony Hanson; Secretary Mark Girard; Commissioner Robert Wendorff; Commissioner Don Martinez; General Manager Jeremy Carter. Others present: Randy Blake, John Webster, Jared Martig, Matt Jaunich, Steve Cook, Mary Christensen, Dan Kasbohm from UFS and Angie Radke. GM Carter introduced Dan Kasbohm from Utility Financial Solutions, LLC (UFS). Mr. Kasbohm has helped gather, analyze, and summarize our Cost of Service (COS) study. There is a lot of information that has gone into this, with that Dan has offered to have an on -site presentation for us. Mr. Kasbohm thanked everyone for having him. Mr. Kashbohm reviewed the Cost of Service (COS) process and the results. The next phase will lead UFS in the direction of what the rated design will be. UFS uses three key points in the 5-year financial projection 1) Debt Coverage Ratio, 2) Minimum Cash Reserve and 3) Target Operating Income. From there, COS results are reviewed and lastly there is discussion recommendations on proposed rate track and recommendations on customer charges. Looking at the Electric projection assumptions, this is showing a growth of 6.1 % in 2019, power costs hold stable through 2020, and in 2021 and 2022 has an increase change of 3%. The new 2017 generation assets are included along with the bonding. There were adjustments for plant #2, removing units 1 & 9 from the historical investments and the utility's net book value (NBV). Along with that, the depreciation rate in plant #2 generating assets was doubled for COS from 30 years to 60 years. Mr. Kasbohm continued to review the electric projection summary without rate adjustment; here there is no rate adjustment in the 5 years. Now looking at the three targets, there is minimum cash policy-, which is the goal. Projected Cash Balances are $9M in 2018 to $15M in 2022. Capital plan is less than depreciation -cash is increasing. The Project Operating Income went from negative in 2018 to positive. Looking very good financially. Not always good to have too much cash. The recommendation is to have a Projected Rate Adjustment of 1 % increase in 2022. The reason for a 1 % increase is to maintain 2022 operating income. Mr. Cook inquired about the bond rating. Mr. Kasbohm communicated the minimum debt coverage ratio they use is 1.4 to maintain some buffer. Debt coverage ratio in 2018 is 4.03 this includes 20-year bond of $16.7 million acquired in 2017 for additional generating units. Mr. Kasbohm continued to speak about HUC's minimum cash reserve levels. There is $9M in O&M. There was discussion about Purchase Power and the Historical Rate base of 3%. Utilities have a life cycle; brand new, aging -depreciation, and old -that needs to be replaced. HUC has slightly older assets than typical utilities but they are maintained well so assets are living longer. Mr. Cook inquired about how many units there are in Plant 2. GM Carter informed him that there are 2 units, unit 9 is a back-up and unit 1 is the baseload, combined cycle unit. When energy markets came out in 2005, HUC could start to buy cheaper than to run, so unit 1 is not used as much. If HUC stays in generation, base load power production plants will not be used in the same fashion they were prior to the establishment of energy markets. HUC has lots of useful life in the baseload plant yet, but we have to consider what needs to happen down the road if it is too much to maintain or we cannot continue to leverage the plant with outside contracts. Mr. Kasbohm reviewed Target Operating Income. This is a great target to see if HUC should bond or pay from cash. Moving on to the summary results of the COS study, Mr. Kashbohm pointed out that HUC has 7 classes. Residential class has a change of 19.3% and goes down to Large Industrial of a change of 7.9%. Overall, for the utility to meet the cost of service analysis between all classes, a 9.6% increase is needed. The top 4 , bottom 2 classes are based on rate charge. The difference in rate classes are based on similar load profile. When a system is built, it is built to provide on the peak of what may be needed. Mr. Cook inquired about solar or any other renewables. A system sized for peak demand is what any city would have however there is a subsidy out there because most of the revenue collected is based on the energy charge not a fixed system charge. Mr. Kasbohm replied In Hutchinson, Large General and Large Industrial make up about 70% of the Cost of Service. Mr. Kasbohm, concluded the Electric Division with the COS Charges. The current customer charge for Residential is $6.50, this includes reading, billing, maintaining meters, and maintaining minimum system infrastructure; these are fixed costs no matter what. The recommendation is to have this charge at $14.35. Residential class does not have a demand meter so this is put mostly into the energy charge currently, the more they use the less fixed revenue is collected. . The recommendation for Small General Service class is to increase the fixed charge from $10 to $24.43 over time. Again, here there is no demand meter so that is included in the energy charge. For the two Large General Service and Large Industrial classes everyone is energized with power. The fixed costs are shared with customers it does not matter what supports a minimum system requirement. Larger customers also have an additional demand charge for the additional upsizing or unique infrastructure requirements specific to them. If the Demand charge goes up on large customers, this is usually a small component of their bill not like residential customers. Recommend increasing customer charges annually over next 3-5 years to meet COS. Consideration should be given to a +/- 2% bandwidth on customer classes. Best time to make adjustments is when there is a zero percent increase. Mr. Kasbohm reviewed the Gas Financial projection and COS summary. For Gas Projection Assumptions, 2018 projected sales are compared to actual 2016 sales, have the PILOT increasing over next 3 years from 2.75% to 4.5%, and bond issue of $4.5M in 2021 for $8.5M project. The projected 2018-22 inflation rate is 2.5%, the retail growth for 2018 is an increase projection of 12.5%. This also shows an increase to PILOT of $700k between both divisions. When looking at the Gas Projection Summary, Mr. Kasbohm pointed out the projected rate adjustments for 2020,21 and 22 has a rate increase of 2.1% with a potential new project included, however without the project only a 1% increase is projected in 2022. Mr. Cook questioned if the rate increase is coming, why not bump up sooner so future increases can be reduced. Mr. Kasbohm responded that it can, it comes down to how fixed the project is 4 years from now. This part of the study needs to be looked at every year. COS should be completed every 3-5 years. Overall gas utility is in very good shape like electric. Mr. Kasbohm discussed the three targets. The debt coverage ratio target shows a minimum debt coverage ratio of 1.4 for all 5 years. This includes a bond issue of $4.5M in 2021 to fund $8.5M capital project. The second target shows the minimum cash reserve level for 2018 of $3.6M and the 5-year capital improvements- net of bond proceeds allocated at 20%. Lastly, the target operating income over the 5 years shows a rate of return of 4.4%-4.6%. Mr. Kasbohm continued with the summary that is used in the analysis. Here the gas side is reversed from the electric side. Large Industrial has a larger adjustment. The COS results identify some customer classes are subsidized by others. It is recommended to have a revenue neutral adjustment on system revenue and have a bandwidth of +/- 2.0% to move rate classes towards COS, These changes can be done in the next 4 years to correct subsidizations. The COS results identify monthly customer charges need to be implemented or increased. The recommendation is to increase customer charges over 3-5 year timeframe towards COS and to increase max daily MCF (demand) charge. Currently the customer charge for residential is $6.50 and commercial is $31.50, the COS customer charge is $13.81 for residential and $72.87 for commercial. Long term, large customers need to be worked on to get to COS. Mr. Kasbohm summarized the recommendations. For electric department, PCA is a great thing to look at often. Both departments should have a revenue neutral rate adjustment in 2018 with a +/-2% bandwidth to move classes closer to cost of service and increase customer charges in 2018. Electric department should increase demand charges, while gas department should increase maximum daily MCF charges in 2018. Again electric department should discuss PCA, as gas department should discuss adjusting negative PGA. Mr. Kasbohm invited additional information to be given to Jeremy, Jeremy will pass on the information and from there the rate design can be built. Mr. Cook inquired about the depreciation of the assets as they get older, what other plans are in place. In addition, why more would not be done to keep depreciation in line. Commissioner Wendorff commented that by looking at the trend line, we are stable. Commissioner Hanson inquired about the percentage that goes to plant 1 and 2. GM rd Carter replied about a 3 or roughly $900k. Commissioner Hanson commented about maintaining reliability. GM Carter responded that the CAP X plans for that. Lots of assets are in generation. The staff maintains a good maintenance program and we monitor statistics to benchmark against locally and nationally. The way certain units are run today is vastly different from in years past. President Morrow asked if there was anything else for Mr. Kasbohm. President Morrow thanked Mr. Kasbohm for all the good information and his time. Commissioner Hanson inquired if this is something that will be discussed at the next meeting. GM Carter explained the next phase is a rate track discussion. The board needs to consider if any of the recommendations will be taken into consideration and if a 5-year rate track plan is desirable by the Commission. From there, that information will be communicated to the consultants to put together a rate track plan and rate design based on Commission feedback. President Morrow stated this is a good start and to add on the agenda. Mr. Cook expressed that rates have only been raised 1 time in 20 years which is pretty unheard of. Mr. Cook inquired about solar energy, how much is really out there, how is that shift made. GM Carter confirmed there is some solar in town. Mr. Cook expressed those that use more pay more. GM Carter explained one scenario is being revenue neutral, that the bill overall be kept neutral but change the fixed rate Mr. Kasbohm is talking about tweaking classes to keep everything neutral. Mr. Cook stated except if we do it every year or every 5 years. Mr. Martig pointed out on a list of municipals rd HUC is 3 from bottom when it comes to the fixed charge. GM Carter added HUC is below COS study numbers because HUC is maximizing its assets, if that were not the case, the rates would not be where they are. Ms. Christenson commented Hutchinson does have good rates and with the value of service it is a good rate. Mr. Cook commented that Hutchinson has been spoiled with low rates and very good reliability. President Morrow thanked everyone for joining. There being no further business, a motion was made by Commissioner Girard, seconded by Commissioner Martinez to adjourn the meeting at 5:23 p.m. Motion was unanimously carried. __________________________ Mark Girard, Secretary ATTEST: _________________________ Monty Morrow, President HUTCHINSON UTILITIES COMMISSION COMBINED DIVISIONS FINANCIAL REPORT FOR DECEMBER, 2017 December, 2017 MonthYear to Date 100% of Year Comp. 20172016Diff.% Chng20172016Diff.% Chng Full Yr Bud% of Bud Combined Division Customer Revenue$ 4,178,529$ 3,655,288 $ 523,24114.3%$ 36,117,108 $ 34,802,435 $ 1,314,6733.8%$ 36,743,052 98.3% Sales for Resale$ 183,078$ 164,299$ 18,780 11.4%$ 2,171,853$ 1,931,859$ 239,99412.4%$ 2,310,11094.0% NU Transportation$ 71,265 $ 64,030$ 7,23611.3%$ 902,042$ 831,969$ 70,073 8.4%$ 734,878122.7% Electric Division Transfer$ 54,308 $ 53,931$ 3780.7%$ 651,699$ 647,166$ 4,533 0.7%$ 651,700100.0% Other Revenues$ 75,691 $ 199,098$ (123,407)(62.0%)$ 758,002$ 991,870$ (233,868)(23.6%)$ 498,808152.0% Interest Income$ 53,976 $ 33,916$ 20,060 59.1%$ 182,120$ 8,372$ 173,7482,075.3%$ 100,000182.1% TOTAL REVENUES$ 4,616,847$ 4,170,560 $ 446,28710.7%$ 40,782,824 $ 39,213,671 $ 1,569,1534.0%$ 41,038,548 99.4% Salaries & Benefits$ 544,909$ 817,425$ (272,516)(33.34%)$ 5,589,865$ 5,988,510$ (398,645)(6.7%)$ 6,005,22793.1% Purchased Commodities$ 3,080,096$ 2,099,131 $ 980,96546.7%$ 21,135,057 $ 19,219,353 $ 1,915,70410.0%$ 20,990,267 100.7% Transmission$ 151,022$ 171,514$ (20,492)(11.9%)$ 2,462,733$ 2,215,298$ 247,43511.2%$ 2,550,00096.6% Generator Fuel/Chem.$ 43,013 $ 85,138$ (42,125)(49.5%)$ 888,669$ 1,191,997$ (303,328)(25.4%)$ 1,249,80171.1% Depreciation$ 317,333$ 379,655$ (62,322)(16.4%)$ 3,808,000$ 3,822,655$ (14,655)(0.4%)$ 3,808,000100.0% Transfers (Elect./City)$ 141,721$ 162,702$ (20,981)(12.9%)$ 1,700,646$ 1,807,887$ (107,241)(5.9%)$ 1,700,647100.0% Operating Expense$ 283,135$ 348,879$ (65,744)(18.8%)$ 2,620,239$ 2,320,686$ 299,55312.9%$ 2,583,006101.4% Debt Interest$ 56,175 $ 63,382$ (7,207) (11.4%)$ 750,265$ 807,818$ (57,553)(7.1%)$ 760,58898.6% TOTAL EXPENSES$ 4,617,405$ 4,127,827 $ 489,57811.9%$ 38,955,474 $ 37,374,204 $ 1,581,2704.2%$ 39,647,536 98.3% NET PROFIT/(LOSS)$ (557) $ 42,734$ (43,291)(101.3%)$ 1,827,349$ 1,839,467$ (12,118)(0.66%)$ 1,391,013131.4% Combined Divisions - Financial/Operating Ratios DecemberDecemberYTD YTD 2017HUC 20172016Change20172016ChangeBudgetTarget Gross Margin %21.6%34.2%-12.6%31.6%33.9%-2.3%30.0%26% - 28% Operating Income Per Revenue $ (%)-1.2%-2.4%1.2%5.0%5.0%0.0%4.5%1%-4% Net Income Per Revenue $ (%):0.0%1.0%-1.0%4.5%4.7%-0.2%3.4%0%-1% Notes/Graphs: These are the preliminary 2017 YTD Financial Statements. Year-end adjustments still will need to be made. HUTCHINSON UTILITIES COMMISSION ELECTRIC DIVISION FINANCIAL REPORT FOR DECEMBER, 2017 December, 2017 MonthYear to Date 100% of Year Comp. 20172016Diff.% Chng20172016Diff.% Chng Full Yr Bud% of Bud Electric Division Customer Revenue$ 2,077,809$ 1,964,423$ 113,387 5.8%$ 25,317,967$ 24,923,358$ 394,6091.6%$ 25,185,461100.5% Sales for Resale$ 183,078 $ 164,299$ 18,780 11.4%$ 2,171,853$ 1,931,859$ 239,99412.4%$ 2,310,11094.0% Other Revenues$ 58,352$ 128,143$ (69,791)(54.5%)$ 477,952$ 452,938$ 25,0145.5%$ 280,200170.6% Interest Income$ 29,776$ 16,958$ 12,818 75.6%$ 93,848 $ 4,186$ 89,6622,141.9%$ 50,000 187.7% TOTAL REVENUES$ 2,349,016$ 2,273,823$ 75,193 3.3%$ 28,061,620$ 27,312,341$ 749,2792.7%$ 27,825,771100.8% Salaries & Benefits$ 427,393 $ 623,522$ (196,129)(31.5%)$ 4,385,929$ 4,700,261$ (314,332) (6.7%)$ 4,727,13592.8% Purchased Power$ 1,194,166$ 1,169,852$ 24,314 2.1%$ 14,257,952$ 13,521,486$ 736,4665.4%$ 14,208,043100.4% Transmission$ 151,022 $ 171,514$ (20,492)(11.9%)$ 2,462,733$ 2,215,298$ 247,43511.2%$ 2,550,00096.6% Generator Fuel/Chem.$ 43,013$ 85,138$ (42,125)(49.5%)$ 888,669$ 1,191,997$ (303,328) (25.4%)$ 1,249,80171.1% Depreciation$ 233,333 $ 345,447$ (112,114)(32.5%)$ 2,800,000$ 2,820,447$ (20,447) (0.7%)$ 2,800,000100.0% Transfers (Elect./City)$ 111,126 $ 124,632$ (13,506)(10.8%)$ 1,333,515$ 1,401,635$ (68,120) (4.9%)$ 1,333,516100.0% Operating Expense$ 222,407 $ 261,531$ (39,125)(15.0%)$ 1,956,641$ 1,636,166$ 320,47519.6%$ 1,746,330112.0% Debt Interest$ -$ 2,124 $ (2,124) (100.0%)$ 20,248 $ 30,185$ (9,937)(32.9%)$ 25,488 79.4% TOTAL EXPENSES$ 2,382,461$ 2,783,760$ (401,299)(14.4%)$ 28,105,688$ 27,517,475$ 588,2132.1%$ 28,640,31398.1% NET PROFIT/(LOSS)$ (33,445)$ (509,937)$ 476,493 (93.4%)$ (44,068)$ (205,134)$ 161,066(78.5%)$ (814,542) 5.4% December, 2017 MonthYear to Date 100% of Year Comp. 20172016Diff.% Chng20172016Diff.% Chng Full Yr Bud% of Bud Electric Division Residential4,561,150 4,752,742 (191,592)(4.03%)49,389,40850,847,924 (1,458,516) (2.87%) 50,432,79797.9% All Electric368,595 378,269 (9,674)(2.56%)2,440,7852,449,790 (9,005) (0.37%) 2,611,70593.5% Small General1,585,661 1,664,477 (78,816) (4.74%)17,896,26417,933,482 (37,218) (0.21%) 17,085,853104.7% Large General6,225,320 6,063,397 161,9232.67%75,176,66373,932,676 1,243,987 1.68% 79,262,49994.8% Industrial8,811,000 9,750,000 (939,000)(9.63%)133,130,000138,496,000 (5,366,000) (3.87%) 134,707,85698.8% Total KWH Sold 21,551,726 22,608,885 (1,057,159)(4.68%) 278,033,120 283,659,872 (5,626,752)(1.98%) 284,100,71097.9% Financial/Operating Ratios DecemberDecemberYTD YTD 2017HUC 20172016Change20172016ChangeBudgetTarget Gross Margin %28.0%22.8%5.2%26.3%27.6%-1.3%22.5%24% - 28% Operating Income Per Revenue $ (%)-4.7%-28.9%24.1%-0.9%-1.2%0.3%-3.0%0%-5% Net Income Per Revenue $ (%):-1.4%-22.4%21.0%-0.2%-0.8%0.6%-2.9%0%-5% Customer Revenue per KWH:$0.0947$0.0853$0.0094$0.0905$0.0874$0.0032$0.0881$0.0881 Total Power Supply Exp. per KWH:$0.0760$0.0737$0.0023$0.0733$0.0693$0.0041$0.0758$0.0758 Notes/Graphs: Electric division loss in December 2017 decreased by $476,493. The primary reason at this point is due to reductions in monthly expenses. The only YTD operating expense category over budget is in the operating expenses section. This is due to new bond issuance costs. Accured interest expense and issuance cost expenses totalled $265,517. Sales for Resale of $183,078 consisted of $18,686 in market sales, $34,400 in the monthly tolling fee from Transalta, $33,992 in energy sales to Transalta, and $96,000 in capacity sales to SMMPA. December 2016 Sales for Resale of $164,299 consisted of $55,925 in market sales, $34,400 in monthly tolling fees from Transalta, $7,474 in Transalta energy sales, and $66,500 in capacity sales to SMMPA. December 2015 Sales for Resale of $93,247 consisted of $1,917 market sales, $34,400 in Transalta tolling fees, $14,930 in Transalta energy sales, and capacity sales to SMMPA for $42,000. Overall Purchased Power increased by $24,134. MRES purchases increased by $33,860 and market purchases/MISO costs decreased by $9726. The power cost adjustment for December 2017 was $.00904/kwhr bringing in an additional $192,540 of revenue for the month and $1,806,566 for the year. Last year's power cost adjustments through December 2016 generated $687,476 in additional revenue. Total PCA collections through December 2015 were $385,433 HUTCHINSON UTILITIES COMMISSION GAS DIVISION FINANCIAL REPORT FOR DECEMBER, 2017 December, 2017 MonthYear to Date 100% of Year Comp. 20172016Diff.% Chng20172016Diff.% Chng Full Yr Bud% of Bud Gas Division Customer Revenue$ 2,100,720$ 1,690,865$ 409,85424.2%$ 10,799,141$ 9,879,077 $ 920,0649.3%$ 11,557,59193.4% Transportation$ 71,265$ 64,030$ 7,23611.3%$ 902,042$ 831,969$ 70,0738.4%$ 734,878 122.7% Electric Div. Transfer$ 54,308$ 53,931$ 3780.7%$ 651,699$ 647,166$ 4,5330.7%$ 651,700 100.0% Other Revenues$ 17,338$ 70,954$ (53,616)(75.6%)$ 280,049$ 538,932$ (258,883)(48.0%)$ 218,608 128.1% Interest Income$ 24,200$ 16,958$ 7,24242.7%$ 88,272$ 4,186$ 84,0862,008.7%$ 50,000176.5% TOTAL REVENUES$ 2,267,831$ 1,896,738$ 371,09319.6%$ 12,721,204$ 11,901,330$ 819,8746.9%$ 13,212,77796.3% Salaries & Benefits$ 117,516$ 193,903$ (76,387)(39.4%)$ 1,203,936 $ 1,288,249 $ (84,313)(6.5%)$ 1,278,09294.2% Purchased Gas$ 1,885,930$ 929,279$ 956,651102.9%$ 6,877,106 $ 5,697,867 $ 1,179,23920.7%$ 6,782,224101.4% Operating Expense$ 60,728$ 87,348$ (26,620)(30.5%)$ 663,597$ 684,520$ (20,923)(3.1%)$ 836,676 79.3% Depreciation$ 84,000$ 34,208$ 49,792145.6%$ 1,008,000 $ 1,002,208 $ 5,7920.6%$ 1,008,000100.0% Transfers (City)$ 30,594$ 38,070$ (7,476)(19.6%)$ 367,131$ 406,252$ (39,121)(9.6%)$ 367,131 100.0% Debt Interest$ 56,175$ 61,258$ (5,084)0.0%$ 730,017$ 777,633$ (47,616)(6.1%)$ 735,100 99.3% TOTAL EXPENSES$ 2,234,944$ 1,344,067$ 890,87766.3%$ 10,849,787$ 9,856,729 $ 993,05810.1%$ 11,007,22398.6% NET PROFIT/(LOSS)$ 32,887$ 552,671$ (519,784) (94.0%)$ 1,871,417 $ 2,044,601 $ (173,184)(8.5%)$ 2,205,55484.9% December, 2017 MonthYear to Date 100% of Year Comp. 20172016Diff.% Chng20172016Diff.% Chng Full Yr Bud% of Bud Gas Division Residential74,446,01075,888,783 (1,442,773)(1.90%)396,761,756382,182,736 14,579,0203.81% 449,582,00088.3% Commercial54,605,36554,822,694 (217,329) (0.40%)325,983,624287,927,671 38,055,95313.22% 420,183,00077.6% Industrial94,863,74096,705,531 (1,841,791)(1.90%)859,892,970793,154,339 66,738,6318.41% 786,836,000109.3% Total CF Sold 223,915,115 227,417,008 (3,501,893)(1.54%) 1,582,638,350 1,463,264,746 119,373,604 8.16% 1,656,601,00095.5% Financial/Operating Ratios DecemberDecemberYTD YTD 2017HUC 20172016Change20172016ChangeBudgetTarget Gross Margin %15.0%47.7%-32.7%43.4%48.8%-5.4%46.2%37%-42% Operating Income Per Revenue $ (%)2.3%29.1%-26.7%18.2%20.1%-1.8%20.6%11%-16% Net Income Per Revenue $ (%):1.5%30.6%-29.1%15.1%18.0%-2.9%17.0%6%-11% Contracted Customer Rev. per CF:$0.0041$0.0040$0.0001$0.0038$0.0035$0.0004$0.0041$0.0041 Customer Revenue per CF:$0.0132$0.0100$0.0033$0.0104$0.0106-$0.0002$0.0096$0.0096 Total Power Supply Exp. per CF:$0.0085$0.0042$0.0043$0.0044$0.0040$0.0005$0.0042$0.0042 Notes/Graphs: Net Profit for December 2017 decreased by $519,784 in the gas division over December 2016. This can be explained by the additional gas costs over the final three days of December which would have caused a fuel cost adjustment of $879,466. However, HUC only charged customers 432,733. This difference was absorbed by HUC for December by lowering the rate stabilization fund. This will be collected in the form of less credits issued in 2018. The fuel cost adjustment for December 2017 was $3.23/MCF bringing in an additional $432,733 for the month but overall customers received an additional $225,769 in credits for 2017. Fuel credit adjustments totalled $44,625 through December of 2016. HUTCHINSON UTILITIES COMMISSION BALANCESHEET-CONSOLIDATED DECEMBER 31, 2017 ElectricGasTotalTotal Net Change DivisionDivision20172016Total (YTD) Current Assets Cash 18,156,655.95 6,980,564.23 25,137,220.18 10,185,055.58 14,952,164.60 Petty Cash 680.00 170.00 850.00 850.00 - Capital Expenditures - Current Yr. 2,750,000.00 700,000.00 3,450,000.00 2,699,000.00 751,000.00 Payment in Lieu of Taxes 882,327.00 369,142.00 1,251,469.00 1,196,331.00 55,138.00 Rate Stabilization - Electric 314,539.41 - 314,539.41 314,539.41 - Rate Stabiliation - Gas - 200,027.29 200,027.29 646,058.37 (446,031.08) Catastrophic Funds 400,000.00 100,000.00 500,000.00 500,000.00 - Bond Interest Payment 2017 186,706.51 - 186,706.51 25,081.21 161,625.30 Bond Interest Payment 2012 - 164,091.63 164,091.63 325,849.94 (161,758.31) Debt Service Reserve Funds 522,335.64 2,188,694.02 2,711,029.66 2,188,694.02 522,335.64 Total Current Assets 23,213,244.51 1 0,702,689.17 33,915,933.68 18,081,459.53 15,834,474.15 Receivables Accounts (net of uncollectible allowances) 2,044,379.79 2,060,973.43 4,105,353.22 3,486,027.08 619,326.14 Interest 19,039.49 19,039.49 38,078.98 31,415.67 6,663.31 Total Receivables 2,063,419.28 2 ,080,012.92 4,143,432.20 3,517,442.75 625,989.45 Other Assets 1,268,167.14 408,448.11 1,446,575.24 Inventory 1,676,615.25 230,040.01 6,658.64 133,386.22 169,743.92 Prepaid Expenses 140,044.86 (29,699.06) 180,328.56 - Sales Tax Receivable 180,328.56 145,585.89 34,742.67 Deferred Outflows - Electric 1,746,060.00 - 1,746,060.00 1,746,060.00 - Deferred Outflows - Gas - 582,020.00 582,020.00 582,020.00 - 3,201,214.34 1 ,123,854.33 4,325,068.67 4,089,985.05 235,083.62 Total Other Assets Total Current Assets 28,477,878.13 1 3,906,556.42 42,384,434.55 25,688,887.33 16,695,547.22 Capital Assets Land & Land Rights 690,368.40 3,901,323.35 4,591,691.75 4,590,287.00 1,404.75 Depreciable Capital Assets 89,042,263.52 41,260,565.70 130,302,829.22 130,306,747.03 (3,917.81) Accumulated Depreciation (52,805,925.45) (15,333,901.36) (68,139,826.81) (64,331,826.37) (3,808,000.44) Construction - Work in Progress 3,846,632.84 298,326.81 4,144,959.65 7,525.14 4,137,434.51 Total Net Capital Assets 40,773,339.31 3 0,126,314.50 70,899,653.81 70,572,732.80 326,921.01 Total Assets 6 9,251,217.44 4 4,032,870.92 1 13,284,088.36 9 6,261,620.13 17,022,468.23 HUTCHINSON UTILITIES COMMISSION BALANCESHEET-CONSOLIDATED DECEMBER 31, 2017 ElectricGasTotalTotal Net Change DivisionDivision20172016Total (YTD) Current Liabilities Current Portion of Long-term Debt Bonds Payable - 1,220,000.00 1,220,000.00 1,285,000.00 (65,000.00) Bond Premium - 185,608.32 185,608.32 185,608.32 - Accounts Payable 2,328,233.42 2,516,974.93 4,845,208.35 5,082,182.17 (236,973.82) Accrued Expenses Accrued Interest 90,552.74 56,175.00 146,727.74 63,382.30 83,345.44 Accrued Payroll 12,662.13 47,813.32 60,475.45 115,307.82 (54,832.37) Total Current Liabilities 2,431,448.29 4 ,026,571.57 6,458,019.86 6,731,480.61 (273,460.75) Long-Term Liabilities Noncurrent Portion of Long-term Debt 2017 Bonds - - - 465,000.00 (465,000.00) 2012 Bonds 16,675,000.00 13,975,000.00 30,650,000.00 15,255,000.00 15,395,000.00 Bond Premium 2012 666,351.12 1,469,398.83 2,135,749.95 1,655,007.15 480,742.80 Pension Liability - Electric 4,226,202.00 - 4,226,202.00 4,226,202.00 - Pension Liability - Nat Gas - 1,408,734.00 1,408,734.00 1,408,734.00 - Accrued Vacation Payable 323,735.99 102,774.05 426,510.04 378,943.50 47,566.54 Accrued Severance 73,739.62 28,580.99 102,320.61 92,050.32 10,270.29 Deferred Outflows - Electric 569,910.00 - 569,910.00 569,910.00 - Deferred Outflows - Nat Gas - 189,970.00 189,970.00 189,970.00 - Total Long-Term Liabilities 22,534,938.73 1 7,174,457.87 39,709,396.60 24,240,816.97 15,468,579.63 Net Position Retained Earnings 44,284,830.42 22,831,841.48 67,116,671.90 65,289,322.55 1,827,349.35 Total Net Position 44,284,830.42 2 2,831,841.48 67,116,671.90 65,289,322.55 1,827,349.35 Total Liabilities and Net Position 69,251,217.44 4 4,032,870.92 113,284,088.36 96,261,620.13 17,022,468.23 Hutchinson Utilities Commission Cash-Designations Report, Combined 12/31/2017 Change in Financial Balance, Balance, Cash/Reserve InstitutionAnnual InterestDecember 2017 November 2017 Position Current Interest Rate Operating Funds: Savings, Checking, Investmentsvariesvariesvaries 33,915,933.68 33,300,167.95 615,765.73 Total Operating Funds 33,915,933.68 33,300,167.95 615,765.73 Combined Division - Total Funds 33,915,933.68 33,300,167.95 615,765.73 Restricted Funds: Debt Reserve RequirementsBond Covenants - sinking fund 350,798.14 2,255,971.93 (1,905,173.79) Debt Reserve RequirementsBond Covenants -1 year Max. P & I 2,188,694.02 2,188,694.02 - Total Reserve Requirement 2,539,492.16 4,444,665.95 (1,905,173.79) Excess Reserves Less Restrictions, Combined 31,376,441.52 28,855,502.00 2,520,939.52 Designated Funds: Operating ReserveMin 60 days of 2018 Operating Bud. 5,868,920.00 5,973,256.00 (104,336.00) Rate Stabalization Funds 514,566.70 960,597.78 (446,031.08) PILOT FundsCharter (Formula Only) 1,251,469.00 1,048,947.00 202,522.00 Catastrophic FundsRisk Mitigation Amount 500,000.00 500,000.00 - Capital Reserves5 Year CIP ( 2018-2022 Fleet & Infrastructure Maintenance) 3,450,000.00 3,450,000.00 - Total Earmarked Funds 11,584,955.70 11,932,800.78 (347,845.08) Excess Reserves Less Restrictions & Designations, Combined 19,791,485.82 16,922,701.22 2,868,784.60 Financial/Operating Ratios YEYEYEYEYTDHUC 20132014201520162017Target Debt to Asset29.7%28.8%32.0%32.2%40.8%<50% Current Ratio2.082.262.523.065.73>2.0 RONA0.80%0.05%1.31%2.17%1.80%>0% Notes/Graphs: Change in Cash Balance (From 12/31/14 to 12/31/2017) Month End ElectricElec. ChangeNatural GasGas Change TotalTotal Change 12/31/2017 23,213,245 10,702,689 33,915,934 12/31/2016 8,612,801 14,600,444 9,500,074 1,202,615 18,112,875 15,803,059 12/31/2015 6,170,790 2,442,011 9,037,373 462,701 15,208,163 2,904,712 12/31/2014 3,598,821 2,571,969 6,765,165 2,272,208 10,363,986 4,844,177 * 2017's Signifcant increase in cash balance is due to issuing bonds for the generator project. Hutchinson Utilities Commission Cash-Designations Report, Electric 12/31/2017 Change in Financial Balance, Balance, Cash/Reserve InstitutionAnnual InterestDecember 2017 November 2017 Position Current Interest Rate Operating Funds: Savings, Checking, Investmentsvariesvariesvaries 33,915,933.68 33,300,167.95 615,765.73 Total HUC Operating Funds 33,915,933.68 33,300,167.95 615,765.73 Electric Division - Total Funds 23,213,244.51 23,363,208.84 (149,964.33) Restricted Funds: Debt Restricted RequirementsBond Covenants - sinking fund 186,706.51 137,946.88 48,759.63 Excess Reserves Less Restrictions, Electric 23,026,538.00 23,225,261.96 (198,723.96) Designated Funds: Operating ReserveMin 60 days of 2018 Operating Bud. 4,387,223.00 4,306,719.00 80,504.00 Rate Stabalization Funds$400K-$1.2K 314,539.41 314,539.41 - PILOT FundsCharter (Formula Only) 882,327.00 681,816.00 200,511.00 Catastrophic FundsRisk Mitigation Amount 400,000.00 400,000.00 - Capital Reserves5 Year CIP ( 2018-2022 Fleet & Infrastructure Maintenance) 2,750,000.00 2,750,000.00 - Total Designated Funds 8,734,089.41 8,453,074.41 281,015.00 Excess Reserves Less Restrictions & Designations, Electric 14,292,448.59 14,772,187.55 (479,738.96) Financial/Operating Ratios YEYEYEYEYTDAPPA RatioHUC 201320142015201620175K-10K Cust.Target Debt to Asset Ratio8.0%7.4%13.2%16.1%36.1%29.5%<50% Current Ratio2.772.482.953.5710.701.81>2.0 RONA-2.7%-3.1%-1.2%-0.4%-0.1%NA>0% Notes/Graphs: Hutchinson Utilities Commission Cash-Designations Report, Gas 12/31/2017 Change in Financial Balance, Balance, Cash/Reserve InstitutionAnnual InterestDecember 2017 November 2017 Position Current Interest Rate Operating Funds: Savings, Checking, Investmentsvariesvariesvaries 33,915,933.68 33,300,167.95 615,765.73 Total HUC Operating Funds 33,915,933.68 33,300,167.95 615,765.73 Gas Division - Total Funds 10,702,689.17 9,936,959.11 765,730.06 Restricted Funds: Debt Restricted RequirementsBond Covenants - sinking fund 164,091.63 2,118,025.05 (1,953,933.42) Debt Restricted RequirementsBond Covenants -1 year Max. P & I 2,188,694.02 2,188,694.02 - Total Restricted Requirements 2,352,785.65 4,306,719.07 (1,953,933.42) Excess Reserves Less Restrictions, Gas 8,349,903.52 5,630,240.04 2,719,663.48 Designated Funds: Operating ReserveMin 60 days of 2018 Operating Bud. 1,481,697.00 1,666,537.00 (184,840.00) Rate Stabalization Funds$200K-$600K 200,027.29 646,058.37 (446,031.08) PILOT FundsCharter (Formula Only) 369,142.00 367,131.00 2,011.00 Catastrophic FundsRisk Mitigation Amount 100,000.00 100,000.00 - Capital Reserves5 Year CIP ( 2018-2022 Fleet & Infrastructure Maintenance) 700,000.00 700,000.00 - Total Earmarked Funds 2,850,866.29 3,479,726.37 (628,860.08) Excess Reserves Less Restrictions & Designations, Gas 5,499,037.23 2,150,513.67 3,348,523.56 Financial/Operating Ratios YEYEYEYEYTDHUC 20132014201520162017APGA RatioTarget Debt to Asset58.6%55.6%54.8%51.5%48.1%TBD<50% Current Ratio1.312.072.172.592.72TBD>2.0 RONA5.8%4.3%4.7%5.6%5.0%TBD>0% Notes/Graphs: ELECTRIC DIVISION Operating Revenue December 2017 CLASSAMOUNTKWH$/KWH Street Lights$58.701,077$0.05450 Electric Residential Service$478,119.744,561,150$0.10482 All Electric Residential Service$37,199.82368,595$0.10092 Electric Small General Service$164,974.171,585,661$0.10404 Electric Large General Service$615,528.356,225,320$0.09887 Electric Large Industrial Service$745,082.448,811,000$0.08456 Total$2,040,963.22 21,552,803$0.09470 Power Adjustment$0.00904 Rate Without Power Adjustment$0.08566 Electric Division Year-to-Date 2017 $ Amount2016 $ Amount2017 KWH/102016 KWH/10 32,000,000 31,000,000 30,000,000 29,000,000 28,000,000 27,000,000 26,000,000 25,000,000 24,000,000 23,000,000 22,000,000 21,000,000 20,000,000 19,000,000 18,000,000 17,000,000 16,000,000 15,000,000 14,000,000 13,000,000 12,000,000 11,000,000 10,000,000 9,000,000 8,000,000 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 1,000,000 0 Street LightsResidentialAll Elec.Small Gen.Large Gen.LargeFor Resale Total Resid.Srv.Srv.Industrial NOTE: Sales for resale includes capacity sales, market sales and Transalta sales. NATURAL GAS DIVISION Operating Revenue DECEMBER 2017 CLASSAMOUNTMCF$/MCF Residential$948,276.8574,446$12.73778 Commercial$707,342.0654,605$12.95380 Large Industrial$445,100.6094,864$4.69199 Total$2,100,719.51223,915$9.38177 Fuel Adjustment$0.00323 Rate Without Fuel Adjustment$6.15177 Natural Gas Division Year-to-Date 2017 $ Amount2016 $ Amount2017 MCF2016 MCF 12,000,000 11,000,000 10,000,000 9,000,000 8,000,000 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 1,000,000 0 Gas ResidentialGas CommercialLarge Industrial Total Load Duration Curve: Analysis of 25MW Base Load Contract 20132014201520162017 290045296051302101295777290586Total system load (MWh) 219000219000219000219600219000Total base load energy purchased (MWh) 75.5%74.0%72.5%74.2%75.4%% of system load provided by base load contract 734340185322302Number of hours system load was less than 25 MW 8.4%3.9%2.1%3.7%3.4%Percentage of time system load was less than 25 MW 1819641317581560Base load energy resold into MISO because system load was less than 25 MW. (MWh) 0.8%0.3%0.1%0.3%0.3%% of base load energy resold because system load was less than 25 MW 2017 LOAD DURATION CURVE ЏЎ ЏЉ ЎЎ ЎЉ ЍЎ ЍЉ ЌЎ MW ЌЉ ЋЎ ЋЉ ЊЎ ЊЉ Ў Љ ЉЎЉЉЊЉЉЉЊЎЉЉЋЉЉЉЋЎЉЉЌЉЉЉЌЎЉЉЍЉЉЉЍЎЉЉЎЉЉЉЎЎЉЉЏЉЉЉЏЎЉЉАЉЉЉАЎЉЉБЉЉЉБЎЉЉ HOURS ЋЉЊАaw9{ 1/1/2018 10/1/2017 7/1/2017 4/1/2017 1/1/2017 10/1/2016 7/1/2016 4/1/2016 1/1/2016 10/1/2015 7/1/2015 4/1/2015 1/1/2015 10/1/2014 7/1/2014 4/1/2014 1/1/2014 10/1/2013 7/1/2013 4/1/2013 1/1/2013 10/1/2012 7/1/2012 4/1/2012 1/1/2012 10/1/2011 7/1/2011 4/1/2011 1/1/2011 10/1/2010 7/1/2010 4/1/2010 1/1/2010 10/1/2009 7/1/2009 4/1/2009 1/1/2009 10/1/2008 7/1/2008 4/1/2008 1/1/2008 10/1/2007 7/1/2007 4/1/2007 1/1/2007 10/1/2006 7/1/2006 4/1/2006 1/1/2006 10/1/2005 7/1/2005 4/1/2005 2014-16 Avg2017 DEC NOV OCT SEP AUG JUL JUN SYSTEM LOAD MAY APR MAR FEB JAN 3400032000300002800026000240002200020000 MWh HUTCHINSON UTILITIES COMMISSION Board Action Form Agenda Item: Review Policies Presenter: Agenda Item Type: Jeremy Carter Review Policies Time Requested (Minutes): 5 Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA 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. Administration of Personnel Policies & Procedures ii. Savings Clause iii. Equal Employment Opportunity iv. Identity Theft Red Flag Program v. Minnesota Government Data Practices Act & Public Records Request BOARD ACTION REQUESTED: None Fiscal Impact: Included in current budget: Budget Change: PROJECT SECTION: Total Project Cost: Remaining Cost: EXEMPT SECTION 2 ADMINISTRATION OF PERSONNEL POLICIES The Commission approves personnel policies intending uniform administration of personnel matters of the Utilities. The Commission may supplement, amend and/or rescind the policies to assure that they will remain practical, useful and current. In approving personnel policies, the Commission has made every effort to be as reasonable and practical as possible. Final responsibility for the enforcement of the policies shall rest with the Commission. The Commission however, has delegated to the General Manager the responsibility and authority for the enforcement of all personnel policies. The General Manager, in turn, delegates certain responsibilities and authority to the Staff as deemed advisable in order to carry out the personnel policies. The General Manager, however, remains accountable to the Commission. If the Commission has not clearly delegated its authority in a certain manner, the Commission retains authority to determine the appropriate action. These personnel policies govern all Utilities employees and apply to all cases except where a policy contained herein conflicts with a Union Contract, or other employment contract, or past practice, in which case the Union Contract, or other employment contract, or past practice shall govern. NON-EXEMPT SECTION 2 ADMINISTRATION OF PERSONNEL POLICIES The Commission approves personnel policies intending uniform administration of personnel matters of the Utilities. The Commission may supplement, amend and/or rescind the policies to assure that they will remain practical, useful and current. In approving personnel policies, the Commission has made every effort to be as reasonable and practical as possible. Final responsibility for the enforcement of the policies shall rest with the Commission. The Commission however, has delegated to the General Manager the responsibility and authority for the enforcement of all personnel policies. The General Manager, in turn, delegates certain responsibilities and authority to the Staff as deemed advisable in order to carry out the personnel policies. The General Manager, however, remains accountable to the Commission. If the Commission has not clearly delegated its authority in a certain manner, the Commission retains authority to determine the appropriate action. These personnel policies govern all Utilities employees and apply to all cases except where a policy contained herein conflicts with a Union Contract, or other employment contract, or past practice, in which case the Union Contract, or other employment contract, or past practice, shall govern. EXEMPT S AVINGS C LAUSE If any provision of this Handbook is declared by proper legislative, administrative or judicial authority to be unlawful, unenforceable or not in accordance with applicable Civil Service rules, or law, all other provisions of this Handbook shall remain in full force and effect for the duration of this Handbook. NON-EXEMPT S AVINGS C LAUSE If any provision of this Handbook is declared by proper legislative, administrative or judicial authority to be unlawful, unenforceable or not in accordance with applicable Civil Service rules, or law, all other provisions of this Handbook shall remain in full force and effect for the duration of this Handbook. EXEMPT E QUAL E MPLOYMENT O PPORTUNITY HUC is committed to providing equal opportunity in all areas of employment, including, but not limited to recruitment, hiring, demotion, promotion, transfer, recruitment, selection, lay-off, disciplinary action, termination, compensation and selection for training. In accordance with Minnesota State Statute 363A, HUC will not discriminate against any employee or job applicant on the basis of race, color, creed, religion, national origin, ancestry, sex, sexual orientation, disability, age, marital status, genetic information, status with regard to public assistance, veteran status, familial status, or membership on a local human rights commission. NON-EXEMPT E QUAL E MPLOYMENT O PPORTUNITY HUC is committed to providing equal opportunity in all areas of employment, including, but not limited to recruitment, hiring, demotion, promotion, transfer, recruitment, selection, lay-off, disciplinary action, termination, compensation and selection for training. In accordance with Minnesota State Statute 363A, HUC will not discriminate against any employee or job applicant on the basis of race, color, creed, religion, national origin, ancestry, sex, sexual orientation, disability, age, marital status, genetic information, status with regard to public assistance, veteran status, familial status, or membership on a local human rights commission. Identity Theft It shall be the policy of HUC to establish an identity theft prevention program, also known as the HUC has an identity theft program in place called , pursuant ed Flags Rule, which implements Section 114 of the Fair and Accurate Credit Transactions Act of 2003. Internal procedures have been established whereby employees of HUC have been trained on how to recognize and what procedures to follow if the employee suspects an identity theft is taking place. Implementation of the Red Flag Program is the responsibility of the Account Supervisor. Administration and maintenance of the Red Flag Program is the responsibility of the Financial Manager. Minnesota Government Data Practices Act and Public Records Request HUC is in compliance with Minnesota Government Data Practices Act and Public Records Request. Forms are available at the office of HUC. Forms are available at the office of HUC. HUTCHINSON UTILITIES COMMISSION Board Action Form Agenda Item: ApprovalofHTI'sNaturalGasTransportationAgreement Presenter:Agenda Item Type: JohnWebster NewBusiness Time Requested (Minutes): 1 Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA ITEM: HTIhastransportednaturalgasonHutchinsonUtilities'transmissionanddistribution systemsbeginninginMay2010.HTI'scurrentagreementexpiresonMay1,2018at9 A.M..ThisagreementprovidestransportationrightstoHTIonHutchinson'sfacilities fromMay1,2018,at9:00A.M.,throughMay1,2020at9:00A.M..HutchinsonUtilities hasnotchangedthetransportationrateordailybalancingfeesfromtheexisting agreement. BOARD ACTION REQUESTED: ApprovaloftheHTITransportationAgreement Fiscal Impact: Approx.$60,000peryear Included in current budget: Budget Change: Yes No PROJECT SECTION: Total Project Cost: Remaining Cost: HUTCHINSON UTILITIES COMMISSION Board Action Form Agenda Item: Approvalof3M'sNaturalGasTransportationandDailySwingSupplyAgreement Presenter:Agenda Item Type: JohnWebster NewBusiness Time Requested (Minutes): 1 Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA ITEM: 3McurrentlytransportsbaseloadanddailyswingsuppliesofnaturalgasonHutchinson Utilities'transmissionanddistributionsystems.3M'scurrentagreementexpiredon January1,2018at9A.M..Thisagreementprovidestransportationrightsto3Mon Hutchinson'sfacilitiesfromJanuary1,2018,at9:00A.M.,throughJanuary1,2020at 9:00A.M..HutchinsonUtilitieshasnotchangedthetransportationrateordaily balancingfeesfromthepreviousagreement. BOARD ACTION REQUESTED: Approvalofthe3M'sNaturalGasTransportationandDailySwingSupplyAgreement Fiscal Impact: Approx.$520,000peryear Included in current budget: Budget Change: Yes No PROJECT SECTION: Total Project Cost: Remaining Cost: HUTCHINSON UTILITIES COMMISSION Board Action Form Agenda Item: Approvalof3M'sFirmNaturalGasCommodityPurchaseAgreement Presenter:Agenda Item Type: JohnWebster NewBusiness Time Requested (Minutes): 1 Attachments: Yes BACKGROUND/EXPLANATION OF AGENDA ITEM: ThisAgreementallows3Mtocontinuetopurchasebaseloadnaturalgascommodity throughHutchinsonUtilities.Inaddition,thisAgreementallows3Mtoplacesegmentsof theirbaseloadcommoditycontractsintotheCommodityPrePayPurchaseProgramthat iscurrentlybeingputinplacebetweenHutchinsonUtilitiesanditsnaturalgassupplier. BOARD ACTION REQUESTED: Approvalofthe3M'sFirmNaturalGasCommodityPurchaseAgreement Fiscal Impact: Included in current budget: Budget Change: Yes No PROJECT SECTION: Total Project Cost: Remaining Cost: HUTCHINSON UTILITIES COMMISSION Board Action Form Agenda Item: 3MCIPrebate Presenter:Agenda Item Type: JaredMartig NewBusiness Time Requested (Minutes): Attachments: BACKGROUND/EXPLANATION OF AGENDA ITEM: 3Mhasturnedintheir201rebateapplicationforenergysavingprojects.Theysaved KWandKWHontheelectricside.Theyalsohad,MCFin naturalgassavings. BOARD ACTION REQUESTED: ApprovePaymentof$,to3MforCIPsavings. Fiscal Impact: Included in current budget: Budget Change: Yes PROJECT SECTION: Total Project Cost: Remaining Cost: wĻĬğƷĻ ƚƷğƌ ЍЊͲЋЎА͵ЌЎ υ 000000000000 63 3.3 Y 0.98 76.86 БЊ͵ЊЍ ЋЍͲЌЍЋ͵ЉЉ υ 659837 YI 3,5892,2537,8207,705 31,15173,90327,92931,55135,41813,97438,08411,019 197,047607,476 ЊͲЉВЉͲЍЊЏ ЊЉͲВЉЍ͵ЊЏ υ 000000000 432217 382264104 a/C 2,603 ЌͲЍЌЎ ЏͲЉЊЊ͵ЊВ υ 5ĻƭĭƩźƦƷźƚƓ Replaced 14 fixtures at 350W each with 12 fixtures at 112W each.Reduce the Water Pump VFD Speeds for Dryer 1 (VCA) & Dryer 3 (VCB) from 100% to 50% after steady state reached (20 minute checks). Tests were completed by Maintenance that determined lowering them to 50% was sufficient to maintain necessary temperatures. Currently running all 24 (VCA = 7 top / 7 bottom, VCB = 5 top / 5 bottom) pumps at 100%. Reducing them 50% takes the current draw from 1.41 Amps to 0.91 Amps each. Assumptions: 90% run time (includes 20 minute check, 151.2 hrs/wk). 1hp, 480V Programming change to implement. Reducing the amount of time the vacuum pull roll pump is running on H26 / H27. Currently runs when oven fans are on. Project shut off pumps when tension is off. Estimate using process data is 20% of time. H26 has a 20 hp motor and H27 has a 10 hp motor. Reduced the amount of air exhausted by 50% (280 cfm); therefore reducing the amount of conditioning needed for outside air. Installed better recirculation ducting. Heat exchange coils were being replaced due to steam leaks in finned tubes; some had been patched and covered with Lexan to prevent air bypassing coils. The coils had a large amount of dirt and debris in the fins and between the coils. Approximate increase in pressure drop of 0.5" water column above original design across the coils.Automated the process to turn steam off at a specified temperature instead of over-heating and then cooling afterward.Automated the process to turn steam off at a specified temperature instead of over-heating and then cooling afterward.Currently, the H1 cure chamber lights exhaust fan operates at either 100% or 10% (during downtimes). This 25HP fan operating at 10% is approximately 4000 cfm. The fan can be shut off during non-UV cured products and on weekend shutdowns during low-humidity months (3680hrs/year). The setpoint was changed and the process standards updated.Use new curing technology on existing coating adhesives to increase line speed. The project increased line speeds for a specified ST6 product improving productivity and reducing overall energy usage per lb product.Use new curing technology on existing coating adhesives to increase line speed. The project increased line speeds for a specified ST6 product improving productivity and reducing overall energy usage per lb product.There is a panel purge fan that is always on even when the department is not running. It is a 3HP motor that is constantly running. The area is 2 crew, so from Thursday afternoon to Monday morning it could be shut off. Modified work practices to turn fan off when area is going down.Reduce fresh air intake in to all oven zones by improving dampers to get better operational control. The gas usage and air flow was measured before and after the damper improvements were made. Gas usage accounts for the energy needed to heat room temp air up to oven operating temp. The conditioned air energy savings is what was saved by not having to condition outside air to room temperature.PCD area needs to use plastic bulbs. Moved from CFL to LED. 140- 25 watt bulbs were replaced with 18 watt bulbs. Replaced two hydraulic molding presses with new electric presses. Replaced 2 less efficient hydraulic presses.In 2017, 10,980 4 ft LED 18 watt light bulbs replaced CFL 25 watt bulbs. These lights run on average 90% of annual hours. In addition, two outdoor 459 watt pole lights were replaced with 85 watt LEDs. These lights run 12 hrs/day.Turned of unused transformers feeding trainer outlets that are not used any more in Sandalwood conference room. Transformers used a percentage of energy just being powered up.Measure values for the two transformers= 1.5 amps at 240 volts. The two transformers are 7.5 kva each.240volt x1.5 amp x 1.752 (3 phase) = 623.52 watts operating 24/7. Ќa /Lt wĻĬğƷĻ tƩƚƆĻĭƷ North Compounding LightingVoyager Water Pump ReductionVacuum Pull Roll ReductionNorth Optical Exhaust Air Reduction Steam Coil Replacement for Coater 27Mogul 1 Wash and Air OutMogul 2 Wash and Air OutH1/ST5 Cure Chamber Lamp Exhaust Air ReductionIncrease linespeed using new ST6 curing technologyIncrease linespeed using new ST7 curing technology19J Panel Purge Air FanPhase 1 7L Oven Opt- Fresh Air Dampener PCD Lighting upgrade/reductionMolding Renewal Phase 1LED Lighting 2017- phase 2Turned off unused transformers A RESOLUTION ANNUAL CONTRIBUTION TO THE CITY OF HUTCHINSON IN LIEU OF TAXES WHEREAS, the Hutchinson City Charter and the Hutchinson Utilities Commission By-laws contain provisions for the transfer of surplus utility funds of the Hutchinson Utilities Commission to the City in lieu of the payment of taxes; and WHEREAS, in December of 2006 both the Hutchinson City Council (City) and the Hutchinson Utilities Commission (HUC) passed resolutions (13100) which set the annual contribution by HUC at 2.75% of the total operating revenue as determined by the second preceding year financial audit of the Hutchinson Utilities Commission in lieu of the payment of taxes; and WHEREAS, HUC also makes additional annual payments to the City for Street Lighting and the Energy Tree Program bringing the combined total transfer to approximately 3.22%; and WHEREAS, such transfers are common between municipal utilities and their cities and typically average around 4.5% in the West North Center United State region according to ; and WHEREAS, the PILOT formula has not been adjusted since the 2006 resolutions were adopted; and WHEREAS, the City and the HUC have determined that it is in the best interest of both entities to update the PILOT payment and formula used. NOW, THEREFORE, BE IT RESOLVED by and between the City Council of the City of Hutchinson and the Hutchinson Utilities Commission, that the contribution from the HUC to the City in lieu of taxes shall be an amount equal to 4.50% of the total operating revenue of the HUC as determined by the most recent completed financial audit of the HUC. The arrangement between the City and the HUC shall be as follows: The contribution of 4.50% shall be phased in over three (3) years and will include a floor and cap. collectively at 3.25% of total operating revenue of the HUC as determined by the 2016 financial audit of the HUC. collectively at 4.00 total operating revenue of the HUC as determined by the 2017 financial audit of the HUC total operating revenue of the HUC as determined by the 2018 financial audit of the HUC For years 2021 and beyond, the payment shall be collectively a total operating revenue of the HUC as dete completed financial audit of the HUC. Future PILOT payments shall include a floor and a ceiling. The floor will be no less than payment of each division and a ceiling that does not extend beyond a 2% increase of each divisions operating revenue from the payment. The contribution in lieu of taxes shall be paid to the City each year in four quarterly installments. The City and HUC will review the formula every three years, or sooner, if conditions warrant. FURTHERMORE, BE IT RESOLVED that the City and HUC recognize that a Cost of Service Study, along with APPA and Minnesota City Surveys may affect rates in future years and will be taken into consideration when looking at future PILOT payments. FURTHERMORE, BE IT RESOLVED that in keeping in harmony with the Hutchinson City Charter the City and HUC agree to look at additional one-time transfers in the future, as conditions and opportunities warrant. FURTHERMORE, BE IT RESOLVED that the Street Lighting and Energy Tree Program payments from the HUC to the City be phased out as well. The phasing will include 100% payment in 2018, 50% payment in 2019, and 0% payment in 2020 and beyond. FURTHERMORE, BE IT RESOLVED that this arrangement shall stay in place until a new resolution is negotiated between the City and the HUC. FURTHERMORE, BE IT RESOLVED that the Hutchinson Utilities Commission unanimously approved the above detailed resolution and arrangement on ___________, 2018. ADOPTED BY THE HUTCHINSON CITY COUNCIL THIS _____ DAY OF _________, 2018 _________________________________________ GARY T. FORCIER, MAYOR ATTEST: ______________________________________________ MATTHEW JAUNICH, CITY ADMINISTRATOR