HomeMy WebLinkAbout9-30-2026 HUCCPHUTCHINSON UTILITIES COMMISSION
AGENDA
REGULAR MEETING
September 30, 2026
3:00 p.m.
Swearing in of Commissioner Josh Wendland
1. CONFLICT OF INTEREST
2. APPROVE CONSENT AGENDA
a. Approve Minutes
b. Ratify Payment of Bills
3. APPROVE FINANCIAL STATEMENTS
4. OPEN FORUM
5. COMMUNICATION
a. City Administrator
b. Divisions
C. Human Resources
d. Legal
e. General Manager
6. POLICIES
a. Review Policies
i. Electric Service Requirements and Charges
ii. Temporary Service
iii. Temporary Service in Case of Underground Failure
iv. Electric Meter Placement
v. Sealing of Meters
vi. Meter Testing
vii. Right -of -Way Clearing
viii.Tree Removal or Trimming
ix. Locating Customer's Underground Utilities
b. Approve Changes
7. UNFINISHED BUSINESS
8. NEW BUSINESS
a. Discussion about extending the term of the MRES Power Sale
Agreement.
b. Discussion on the 2-year rate track provided by UFS.
9. ADJOURN
MINUTES
Regular Meeting — Hutchinson Utilities Commission
Wednesday, August 26, 2026
Call to order — 3:00 p.m.
President Don Martinez called the meeting to order. Members present: President Don
Martinez; Secretary Matt Cheney; Vice President Tom Lambert; Commissioner Kathy
Silvernale; GM Jeremy Carter; Attorney Marc Sebora
Conflict of Interest
2. Approve Consent Agenda
a. Approve Minutes
b. Ratify Payment of Bills
Motion by Commissioner Cheney, second by Commissioner Lambert to Approve the
Consent Agenda. Motion carried unanimously.
3. Approve Financial Statements
Mr. Martig presented the Financial Statements. Transmission was overestimated
by $30K, making net profit $250K not $220K. The increase in misc. revenue was
due to reimbursement on the rooftop solar projects.
GM Carter reviewed the Electric Usage and the Power Cost Adjustment dollars
compared to previous years and the expectation of August PCA. GM Carter noted
the gas sales are behind from 2025; last year credits were given, this year building
back reserves from the January storm. Overall trending consistent. Balance sheet
was also reviewed.
Motion by Commissioner Silvernale, second by Commissioner Lambert to Approve
the Financial Statements. Motion carried unanimously.
4. Open Forum
5. Communication
a. City Administrator— Matthew Jaunich —
i. Wrapping up street projects
ii. Landing apartment project should be opening up in about 90 days.
iii. Budget season
'7=big0"017
Dan Lang, Engineering Services Manager —Absent
Dave Hunstad, Electric Transmission/Distribution Manager —
1. Solar project update
2. Hutch Sub update
iii. Mike Gabrielson, Production Manager-
1. Unit 1 update- GE will cover part of the repair that is under warranty.
Trying to get confirmation on warranty amount and timeline
2. Plant 1 finished up contracted summer gas for the year
3. Cooling tower repair to start in October
iv. Byron Bettenhausen, Natural Gas Manager - Absent
v. Jared Martig, Financial Manager
1. Wrapping up Bond material and Rate Study
c. Human Resources — Angie Radke -
i. Continuing to work on Compensation Study
ii. Working with Broker on Benefits
iii. Union Negotiations starting soon
d. Legal — Marc Sebora —
i. Charter Commission will be meeting next week to discuss HUC
Commission and ways to enlarge the pool of potential applicants for utilities
commissioners.
e. General Manager — Jeremy Carter
i. Cost of Service Update — looking to have special meeting in September
ii. Bond Proceeds Update did keep and A- rating
iii. Union Negotiations
iv. Cap X and Budget
6. Policies
a. Review
Policies
i.
Hutchinson Utilities Commission
ii.
Establishing a New Electric/Natural Gas Account
iii.
Deposit Requirement — Residential
iv.
Deposit Requirement — Commercial/Industrial
v.
Terminating Electric/Natural Gas Service by Customer
vi.
Definition of Your Bill
vii.
Errors in Billing
viii.
Payment of Your Bill
ix.
Automatic Bill Payment Plan
x.
Budget Payment Plan
xi.
Explanation of Billing Procedure
xii.
Disconnection of Residential Services by HUC
xiii.
Disconnection of Commercial Services by HUC
xiv.
After Hours Reconnection Policy
xv.
Landlord Acknowledgment
xvi.
Inserts with Utility Bills
xvii.
Identity Theft — "Red Flag Program"
xviii.
Minnesota Cold Weather Rule
xix.
Minnesota Government Data Practices Act and Public Records
Request
No changes recommended at this time.
7. Unfinished Business
8. New Business
2
a. Approve Req#010690 — Power Gate and Camera Install Electrical work at
Plant#2
Mr. Gabrielson presented Approval of Req#010690 — Power Gate and
Camera Install Electrical work at Plant#2. Requisition is for the installation of
electric wire to the power gate and two cameras at the plant that will be
pointed towards both entrances of the plant and is part of Req#010691.
GM Carter added cyber security is important along with physical security.
Motion by Commissioner Cheney, second by Commissioner Silvernale to
Approve Req#010690 — Power Gate and Camera Install Electrical work at
Plant#2. Motion carried unanimously.
b. Approve Req#010691 - Install Automated Pivot Gate
Mr. Gabrielson presented Approval of Req#010691 — Install Automated Pivot
Gate. HUC is looking to purchase an Automated Pivot gate at Plant 2 as part
of the continual efforts to secure HUC's critical infrastructure. Plant 2 has
critical natural gas infrastructure housed on site along with generation
equipment that should have greater security measures in place.
Motion by Commissioner Lambert, second by Commissioner Cheney to
Approve Req#010691 — Install Automated Pivot Gate. Motion carried
unanimously.
9. Adjourn
There being no further business, a motion by Commissioner Lambert, second by
Commissioner Cheney to adjourn the meeting at 3:21 p.m. Motion carried
unanimously.
ATTEST:
Don Martinez, President
3
Matt Cheney, Secretary
MINUTES
Special Meeting — Hutchinson Utilities Commission
Wednesday, September 9, 2026
Call to order — 7:00 a.m.
President Don Martinez called the meeting to order. Members present: President Don
Martinez; Vice President Tom Lambert; Secretary Matt Cheney; Commissioner Kathy
Silvernale; GM Jeremy Carter
Others Present: Jared Martig, Dave Hunstad, Mike Gabrielson, Angie Radke
Others Present Online: Dan Kasbohm from Utility Financial Solutions, LLC (UFS)
The purpose of the special meeting is to have a Cost -of -Service Study presentation by
Utility Financial Solutions.
Dan Kasbohm from UFS, thanked everyone for attending. Mr. Kasbohm reviewed the
Cost of Service (COS) process, projection assumptions, summaries, targets and results.
Discussion topics will be Financial Projection 1) Meet revenue requirements and 2)
Measure to key financial targets; Cost of Service 1) Monthly meter charge and 2)
Identify if one rate subsidizes another; and Guidance from Utility Commission 1) 2027
revenue adjustment and bandwidth and 2) Rate component adjustments towards cost of
service.
Project Assumption is based on 1) Using HUC 5-Year Budget Forecasted expenses for
operations and supply, 2) Using HUC 5-Year Budget Forecasted growth projections, 3)
Included bond 2026B issued in 2026 for $4.295M, 4) Includes data center load in 2027
and 5) PCA passes through purchase power changes.
First Projection Summary is without revenue adjustments with current rates. Years
2027-2031 shows HUC running at a loss and identifies need for rate adjustment. 2
Options with Rate adjustments were presented; A) 2027 rate adjustment of 6% and
2028 rate adjustment of 5%, 0% rate adjustment years 2029, 2030 and 2031, this
shows positive cash position in 2028; B) Rate adjustment of 4.1 % for years 2027, 2028
and 2029 which will take 3 years to have a positive cash position. Next Projection
Summary slide shows projection with current rates without Data Center, along with
Projection with proposed revenue adjustments without Data Center.
Three Projection Targets were reviewed along with the Cost -of -Service Summary. Cost
of Service Summary showed percent change required to move current rates to cost of
service for each customer rate class along with the Customer Charge per customer
class.
GM Carter noted past glide paths have done its job.
Mr. Kasbohm reviewed the Gas Financial projection and COS summary. Assumptions
are the same for inflation and growth. Projection Summary includes Projection with
current rates and Projection with optional rate track. Projection with optional rate track
shows a proposed revenue adjustment of 1 % for years 2030 and 2031. Cost of Service
Summary showed percent change required to move current rates to cost of service for
each customer rate class along with the Customer Charge per customer class.
Both rate designs will be developed using input from the Utility Commission.
Discussions were held on cash balances, transmission rate/costs, depreciation, cost of
projects, and the impacts to all classes for Electric and Gas divisions along with the
fundamental decisions that were made in the past with glide paths and the impact of how
those glide paths helped with decisions going forward.
Mr. Kasbohm left meeting at 7:40a.m
GM Carter is looking to have guidance from the Commission on rate track options to be
modeled by the UFS. Commissioners agree to look at 6%, 5% rate adjustment for years
2027 and 2028 for the Electric Division and rate adjustments based on UFS
recommendation while staying relatively neutral on revenues within the gas division. Mr.
Kasbohm would have a 2-week turnaround from the Commissions input. Looking to have
more discussion at the September Regular scheduled Commission meeting, take formal
action in September/ October which allows time to bring any changes to the City Council
in October. Implementation is expected November 1st but can change based on board
preference. GM Carter noted that the Council has the right to veto any rate changes.
There being no further business, a motion by Commissioner Cheney, second by
Commissioner Silvernale to adjourn the meeting at 7:59a.m. Motion carried unanimously.
ATTEST:
Don Martinez, President
2
Matt Cheney, Secretary
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HUTCHINSON UTILITIES COMMISSION
COMBINED DIVISIONS
FINANCIAL REPORT FOR AUGUST, 2026
Combined Division
Customer Revenue
Sales for Resale
NG Transportation
Electric Division Transfer
Other Revenues
Interest Income
TOTAL REVENUES
Salaries & Benefits
Purchased Commodities
Transmission
Generator Fuel/Chem.
Depreciation
Transfers (Elect./City)
Operating Expense
Debt Interest
TOTAL EXPENSES
NET PROFIT/(LOSS)
Ilrtrt��������������
Yfmmml��������l�lll�����������
66.7%of YearComp.
2026
2025
Di
%Chng
2026
2025
Di
%Chng
Full Yr Bud
%of Bud
$ 3,586,920
$ 2,470,875
$
1,116,045
45.2%
$ 28,226,276
$ 23,854,938
$ 4,371,338
18.3%
$ 40,209,447
70.2%
$ 331,568
$ 1,005,359
$
(673,791)
(67.0%)
$ 2,665,074
$ 5,234,985
$ (2,569,910)
(49.1%)
$ 4,339,200
61.4%
$ 176,970
$ 174,451
$
2,518
1.4%
$ 1,384,044
$ 1,378,361
$ 5,683
0.4%
$ 2,037,588
67.9%
$ 60,667
$ 60,639
$
28
0.0%
$ 485,333
$ 485,111
$ 223
0.0%
$ 728,000
66.7%
$ 139,210
$ 71,164
$
68,046
95.6%
$ 746,465
$ 428,337
$ 318,128
74.3%
$ 573,955
130.1%
$ 51,655
$ 74,900
$
(23,245)
(31.0%)
$ 331,029
$ 527,463
$ (196,434)
(37.2%)
$ 583,457
56.7%
$ 4,346,989
$ 3,857,388
$
489,601
12.7%
$ 33,838,221
$ 31,909,194
$ 1,929,027
6.0%
$ 48,471,647
69.8%
$ 625,404
$ 607,977
$ 17,427
2.87%
$ 5,387,923
$ 5,127,917
$
260,006
5.1%
$ 8,524,717
63.2%
$ 1,834,126
$ 1,574,185
$ 259,941
16.5%
$ 15,260,564
$ 13,549,856
$
1,710,708
12.6%
$ 20,816,157
73.3%
$ 443,884
$ 294,620
$ 149,264
50.7%
$ 2,956,096
$ 1,809,042
$
1,147,054
63.4%
$ 4,200,000
70.4%
$ 179,891
$ 387,714
$ (207,823)
(53.6%)
$ 923,398
$ 1,764,486
$
(841,088)
(47.7%)
$ 2,008,656
46.0%
$ 352,419
$ 351,932
$ 488
0.1%
$ 2,827,048
$ 2,821,694
$
5,353
0.2%
$ 4,190,000
67.5%
$ 222,552
$ 222,524
$ 28
0.0%
$ 1,780,417
$ 1,780,195
$
223
0.0%
$ 2,670,626
66.7%
$ 326,173
$ 308,309
$ 17,864
5.8%
$ 2,544,514
$ 2,542,172
$
2,341
0.1%
$ 3,791,274
67.1%
$ 38,805
$ 49,688
$ (10,883)
(21.9%)
$ 310,438
$ 397,504
$
(87,067)
21.9%
$ 465,657
66.7%
$ 4,023,253
$ 3,796,948
$ 226,305
6.0%
$ 31,990,397
$ 29,792,867
$
2,197,530
7.4%
$ 46,667,087
68.6%
$ 323,735
$ 60,440
$ 263,296
435.6%1
1,847,824
$ 2,116,327
$
(268,503)
(12.7%)
$ 1,804,560
102.4%
August
August
YTD
YTD
2026
2025
Change
2026
2025
Change
Gross Margin %:
29.9%
27.8%
2.1%
30.6%
33.8%
-3.2%
Operating Income Per Revenue $ (%):
4.6%
-0.5%
5.1%
3.7%
5.5%
-1.8%
Net Income Per Revenue $ (%):
7.4%
1.6%
5.9%
5.5%
6.6%
-1.2%
2026
HUC
Budget
Target
32.2%
2.8%
3.7%
HUTCHINSON UTILITIES COMMISSION
ELECTRIC DIVISION
FINANCIAL REPORT FOR AUGUST, 2026
i� ,��(��, f , ��� f�i,�� � 1111
Il �X#Wli(i�((((III(���rrrrrrrr�����IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII I ��((((r�I(flltttitf������IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
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,
66.7%gfYearComp.
2026
2025
Di .
%Chna
2026
2025
Di
%Chna
FullYrBud
%of Bud
Electric Division
Customer Revenue
$
2,950,855
$ 1,923,794
$
1,027,061
53.4%
$ 18,958,163
$ 16,105,818
$ 2,852,345
17.7%
$ 27,471,918
69.0%
Sales for Resale
$
331,568
$ 1,005,359
$
(673,791)
(67.0%)
$ 2,665,074
$ 5,234,985
$ (2,569,910)
(49.1%)
$ 4,339,200
61.4%
Other Revenues
$
106,957
$ 47,496
$
59,461
125.2%
$ 454,683
$ 208,026
$ 246,657
118.6%
$ 202,862
224.1%
Interest Income
$
27,221
$ 38,844
$
(11,623)
(29.9%)
$ 176,667
$ 274,884
$ (98,217)
(35.7%)
$ 308,457
57.3%
TOTAL REVENUES
$
3,416,601
$ 3,015,493
$
401,108
13.3%
$ 22,254,588
$ 21,823,713
$ 430,875
2.0%
$ 32,322,437
68.9%
Salaries & Benefits $ 449,043 $ 442,161 $ 6,882
Purchased Power $ 1,506,839 $ 1,253,097 $ 253,742
Transmission $ 443,884 $ 294,620 $ 149,264
Generator Fuel/Chem. $ 179,891 $ 387,714 $ (207,823)
Depreciation $ 253,399 $ 254,095 $ (696)
Transfers (Elect./City) $ 172,817 $ 172,789 $ 28
Operating Expense $ 213,215 $ 208,032 $ 5,183
Debt Interest $ 30,138 $ 32,771 $ (2,633)
TOTAL EXPENSES $ 3,249,225 $ 3,045,279 $ 203,946
NET PROFIT/(LOSS) $ 167,376 $ (29,786) $ 197,162
1.6% $ 3,928,928 $ 3,837,492 $ 91,436 2.4% $ 6,178,442
20.2% $ 9,311,618 $ 8,656,793 $ 654,825 7.6% $ 13,035,315
50.7% $ 2,956,096 $ 1,809,042 $ 1,147,054 63.4% $ 4,200,000
(53.6%) $ 923,398 $ 1,764,486 $ (841,088) (47.7%) $ 2,008,656
(0.3%) $ 2,033,775 $ 2,038,499 $ (4,724) (0.2%) $ 3,060,000
0.0% $ 1,382,534 $ 1,382,312 $ 222 0.0% $ 2,073,802
2.5% $ 1,746,161 $ 1,729,883 $ 16,278 0.9% $ 2,553,967
(8.0%) $ 241,104 $ 262,171 $ (21,067) jLgL $ 361,657
6.7% $ 22,523,615 $ 21,480,679 $ 1,042,936 4.9% $ 33,471,839
661.9%) $ (269,027) $ 343,034 $ (612,061) (178.4%) $ (1,149,402
63.6%
71.4%
70.4%
46.0%
66.5%
66.7%
68.4%
66.7%
67.3%
23.4%
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,
66.7�6ofYear Comp.
2026
2025
Di .
%Chna
2026
2025
Di
%Chna
FullYrBud
%of Bud
Electric Division
Residential
5,735,211
5,644,396
90,815
1.61%
38,148,726
37,446,731
701,995
1.87%
54,016,284
70.6%
All Electric
161,527
157,829
3,698
2.34%
1,666,546
1,690,187
(23,641)
(1.40%)
2,281,979
73.0%
Small General
1,712,093
1,706,734
5,359
0.31%
12,105,183
12,264,740
(159,557)
(1.30%)
17,753,235
68.2%
Large General
9,794,450
9,152,550
641,900
7.01%
68,142,200
61,454,430
6,687,770
10.88%
92,221,607
73.9%
Industrial
9,231,000
8,748,000
483,000
5.52%
66,152,000
66,743,000
(591,000)
(0.89%)
97,880,814
67.6%
Total KWH Sold
26,634,281
25,409,509
1,224,772
4.82%
186,214,655
179,599,088
6,615,567
3.68%1
264,153,919
70.5%
August
August
YTD
YTD
2026
HUC
2026
2025
Change
2026
2025
Change
Budget
Target
Gross Margin %:
22.2%
20.6%
1.6%
23.5%
28.0%
-4.6%
24.7%
24%-28%
Operating Income Per Revenue $ (%):
2.4%
-2.4%
4.8%
-2.5%
1.1%
-3.6%
-3.6% IIIIIIIIIIIIIIIII
Net Income Per Revenue $ (%):
4.9%
-1.0%
5.9%
-1.2%
1.6%
-2.8%
-3.6% IIIIIIIIIIIIIIIII
Customer Revenue per KWH:
$0.1108
$0.0757
$0.0351
$0.1018
$0.0897
$0.0121
$0.1040
$0.1040
Total Power Supply Exp. per KWH: $0.0964 $0.0920 $0.0044 $0.0893 $0.0860 $0.0033 $0.0911
Net Income increased by $197,162 over August 2025. Customer revenue and usage was up with increased temperatures but offset by lower sales for resale.
Generator fuels were down with the decrease in sales for resale and transmission expenses continue to be much higher which was budgeted for.
Sales for Resale of $331,568 consisted of $100,568 in market sales, $98,000 in capacity sales to Rice Lake, $70,000 in capacity sales to AEP, and $63,000 in
capacity sales to Nextera. August 2025 Sales for Resale of $1,005,359 included $774,359 in market sales, $98,000 in capacity sales to Rice Lake, $70,000 in
capacity sales to AEP, and $63,000 in capacity sales to Nextera. August 2024 Sales for Resale of $278,802 consisted of $72,577 in market sales, $98,000 in
capacity sales to Rice Lake and $108,225 in capacity sales to AEP.
Overall Purchased Power increased by $253,742. MRES purchases increased by $53,384 and market purchases/MISO costs increased by $200,358.
The average cost of MISO power was $41.46/mwh (4,180 mwh's purchased), compared to $29.05/mwh (2,160 mwh's purchased) in August 2025.
2026 PCA was $.02146/kwhr bringing in an additional $566,526 for the month and $1,842,014 YTD. The 8 month average PCA is $.00972.
2025 PCA was a credit of $.01339 crediting customers $337,226 for the month and $185,428 YTD.
Gas Division
Customer Revenue
Transportation
Electric Div. Transfer
Other Revenues
Interest Income
TOTAL REVENUES
Salaries & Benefits
Purchased Gas
Operating Expense
Depreciation
Transfers (City)
Debt Interest
TOTAL EXPENSES
NET PROFIT/(LOSS)
HUTCHINSON UTILITIES COMMISSION
GAS DIVISION
FINANCIAL REPORT FOR AUGUST, 2026
66.7% of Year Comp.
2026
2025
2
%Chna
2026
2025
2 .
%Chna
Full YrBud
%of Bud
$ 636,065
$ 547,081
$
88,984
16.3%
$ 9,268,112
$
7,749,120
$
1,518,992
19.6%
$ 12,737,529
72.8%
$ 176,970
$ 174,451
$
2,518
1.4%
$ 1,384,044
$
1,378,361
$
5,683
0.4%
$ 2,037,588
67.9%
$ 60,667
$ 60,639
$
28
0.0%
$ 485,333
$
485,111
$
223
0.0%
$ 728,000
66.7%
$ 32,253
$ 23,668
$
8,586
36.3%
$ 291,782
$
220,311
$
71,471
32.4%
$ 371,093
78.6%
$ 24,433
$ 36,056
$
(11,623)
(32.2%)
$ 154,362
$
252,579
$
(98,217)
(38.9%)
$ 275,000
56.1%
$ 930,388
$ 841,895
$
88,493
10.5%
$ 11,583,633
$
10,085,481
$
1,498,153
14.9%
$ 16,149,210
71.7%
$ 176,361
$ 165,816
$
10,545
6.4%
$ 1,458,995
$
1,290,424
$
168,570
13.1%
$ 2,346,275
62.2%
$ 327,287
$ 321,087
$
6,199
1.9%
$ 5,948,946
$
4,893,063
$
1,055,883
21.6%
$ 7,780,842
76.5%
$ 112,958
$ 100,277
$
12,681
12.6%
$ 798,353
$
812,290
$
(13,937)
(1.7%)
$ 1,237,307
64.5%
$ 99,020
$ 97,837
$
1,184
1.2%
$ 793,273
$
783,195
$
10,077
1.3%
$ 1,130,000
70.2%
$ 49,735
$ 49,735
$
-
0.0%
$ 397,883
$
397,883
$
0
0.0%
$ 596,824
66.7%
$ 8,667
$ 16,917
$
(8,250)
0.0%
$ 69,334
$
135,333
$
(66,000)
48.8%
$ 104,000
66.7%
$ 774,028
$ 751,670
$
22,359
3.0%
$ 9,466,782
$
8,312,188
$
1,154,594
13.9%
$ 13,195,248
71.7%
$ 156,359
$ 90,226
$
66,134
73.3%1
2,116,851
$
1,773,293
$
343,558
19.4%
$ 2,953,962
71.7%
1
66.7% of Year Comp.
2026
2025
2
%Chnq
2026
2025
p
%Chnq
Full YrBud
%of Bud
Gas Division
Residential
6,046,345
6,215,838
(169,493)
(2.73%)
261,417,495
272,485,096
(11,067,601)
(4.06%)
410,283,000
63.7%
Commercial
8,913,470
8,834,599
78,871
0.89%
204,075,407
208,237,670
(4,162,263)
(2.00%)
317,957,000
64.2%
Industrial
48,884,097
46,928,547
1,955,550
4.17%
538,029,990
547,112,311
(9,082,321)
(1.66%)
820,578,000
65.6%
Total CF Sold
63,843,912
61,978,984
1,864,928
3.01%1
1,003,522,892
1,027,835,077
(24,312,185)
(2.37%)l
1,548,818,000
64.8%
August
August
YTD
YTD
2026 HUC
2026
2025
Change
2026
2025
Change
Budget Target
Gross Margin %:
59.1%
55.1%
4.0%
44.5%
46.6%
-2.0%
47.7%
Operating Income Per Revenue $ (%):
12.9%
6.6%
6.4%
15.9%
15.3%
0.6%
15.9%
Net Income Per Revenue $ (%):
16.8%
10.7%
6.1%
18.3%
17.6%
0.7%
18.3%
Contracted Customer Rev. per CF:
$0.0070
$0.0068
$0.0002
$0.0075
$0.0067
$0.0008
$0.0069
Customer Revenue per CF:
$0.0167
$0.0142
$0.0025
$0.0111
$0.0084
$0.0026
$0.0095
Total N.G. Supply Exp. per CF:
$0.0056
$0.0057
($0.0001)
$0.0062
$0.0050
$0.0012
$0.0053
Notes/Graphs:
August Net Income increased by $66,134. Usage and revenue were up. A large part of the revenue increase was due to a fuel cost adjustment in 2026 while
there was a credit in 2025.
Fuel Cost Adjustment for August 2026 was $1.30/MCF bringing in an additional $25,356 for the month and $660,651 YTD.
August 2025 Fuel Cost "Credit" Adjustment was $1.78998/MCF crediting customers $30,712 for the month and $626,763 YTD.
HUTCHINSON UTILITIES COMMISSION
BALANCE SHEET - CONSOLIDATED
AUGUST 31, 2026
Electric
Gas
Total
Total
Net Change
Division
Division
2026
2025
Total (YTD)
Current Assets
UnrestrictedlUndesignated Cash
Cash
(10,512,041.15)
16,210,587.49
5,698,546.34
11,568,910.42
(5,870,364.08)
Petty Cash
680.00
170.00
850.00
850.00
-
Designated Cash
Capital Expenditures - Five Yr. CIP
2,750,000.00
700,000.00
3,450,000.00
3,450,000.00
-
Payment in Lieu of Taxes
1,345,802.00
596,824.00
1,942,626.00
1,942,626.00
-
Rate Stabilization - Electric
1,301,838.58
-
1,301,838.58
1,443,969.35
(142,130.77)
Rate Stabilization - Gas
-
517,291.75
517,291.75
615,294.19
(98,002.44)
Catastrophic Funds
800,000.00
200,000.00
1,000,000.00
1,000,000.00
-
Restticted Cash
Bond & Interest Payment 2017
834,242.24
-
834,242.24
691,214.06
143,028.18
Bond & Interest Payment 2012
-
1,456,000.00
1,456,000.00
1,535,749.99
(79,749.99)
Debt Service Reserve Funds
1,175,000.00
2,072,000.00
3,247,000.00
3,255,256.00
(8,256.00)
Total Current Assets
(2,304,478.33)
21,752,873.24
19,448,394.91
25,503,870.01
(6,055,475.10)
Receivables
Accounts (net of uncollectible allowances)
3,277,172.88
564,211.62
3,841,384.50
2,438,441.74
1,402,942.76
Interest
49,785.32
49,785.33
99,570.65
148,628.57
(49,057.92)
Total Receivables
3,326,958.20
613,996.95
3,940,955.15
2,587,070.31
1,353,884.84
Other Assets
Inventory
2,292,385.43
505,802.07
2,798,187.50
2,634,114.93
164,072.57
Prepaid Expenses
265,394.29
109,066.71
374,461.00
679,494.46
(305,033.46)
Sales Tax Receivable
153,684.06
-
153,684.06
454,261.70
(300,577.64)
Deferred Outflows- Electric
371,991.00
-
371,991.00
342,759.00
29,232.00
Deferred Outflows - Gas
-
123,997.00
123,997.00
114,253.00
9,744.00
Total Other Assets
3,083,454.78
738,865.78
3,822,320.56
4,224,883.09
(402,562.53)
Total Current Assets
4,105,934.65
23,105,735.97
27,211,670.62
32,315,823.41
(5,104,152.79)
Capital Assets
Land & Land Rights
690,368.40
3,899,918.60
4,590,287.00
4,590,287.00
-
Depreciable Capital Assets
95,284,258.02
45,149,321.56
140,433,579.58
139,438,732.65
994,846.93
Accumulated Depreciation
(53,090,024.87)
(24,174,669.39)
(77,264,694.26)
(73,077,737.85)
(4,186,956.41)
Construction - Work in Progress
13,464,944.23
264,336.73
13,729,280.96
4,331,052.87
9,398,228.09
Total Net Capital Assets
56,349,545.78
25,138,907.50
81,488,453.28
75,282,334.67
6,206,118.61
Total Assets 60,455,480.43 48,244,643.47 108,700,123.90 107,598,158.08 1,101,965.82
Current Liabilities
Current Portion of Long-term Debt
Bonds Payable
Bond Premium
Lease Liability - Solar Array
Accounts Payable
Accrued Expenses
Accrued Interest
Accrued Payroll
Total Current Liabilities
Long -Term Liabilities
Noncurrent Portion of Long-term Debt
2017 Bonds
2012 Bonds
Bond Premium 2012
Pension Liability- Electric
Pension Liability - Electric OPEB
Pension Liability - Nat Gas
Pension Liability - Nat Gas OPEB
Accrued Vacation Payable
Accrued Severance
Deferred Outflows - Electric
Deferred Outflows - Nat Gas
Total Long -Term Liabilities
Net Position
Retained Earnings
Total Net Position
HUTCHINSON UTILITIES COMMISSION
BALANCE SHEET - CONSOLIDATED
AUGUST 31, 2026
Electric Gas Total
Division Division 2026
820,000.00
19, 546.00
4,099,377.70
90,413.94
74,296.36
5,103,634.00
10,930,000.00
376,390.80
1, 585, 328.00
42,211.00
635,863.89
224,153.38
1,087,158.00
14,881,105.07
2,080,000.00
185,608.32
641,426.74
26,000.25
31,269.20
2,964,304.51
(139,206.61)
528,443.00
14,071.00
224,492.28
44,404.41
362,386.00
1,034,590.08
2,900,000.00
185,608.32
19, 546.00
4,740,804.44
116,414.19
105, 565.56
8,067,938.51
10,930,000.00
237,184.19
1, 585, 328.00
42,211.00
528,443.00
14,071.00
860,356.17
268,557.79
1,087,158.00
362,386.00
15,915,695.15
Total Net Change
2025 Total (YTD)
2, 770, 000.00 130, 000.00
185,608.32 -
- 19,546.00
3,426,057.61 1,314,746.83
149,064.09 (32,649.90)
85,883.21 19,682.35
6, 616, 613.23 1, 451, 325.28
11,750,000.00
(820,000.00)
2,080,000.00
(2,080,000.00)
456,249.47
(219,065.28)
1,832,248.00
(246,920.00)
39,880.00
2,331.00
610,749.00
(82,306.00)
13,293.00
778.00
739,330.02
121,026.15
245,721.73
22,836.06
1,294,449.00
(207,291.00)
431,483.00
(69,097.00)
19,493,403.22 (3,577,708.07)
40,470,741.36 44,245,748.88 84,716,490.24 81,488,141.63 3,228,348.61
40,470,741.36 44,245,748.88 84,716,490.24 81,488,141.63 3,228,348.61
Total Liabilities and Net Position 60,455,480.43 48,244,643.47 108,700,123.90 107,598,158.08 1,101,965.82
Hutchinson Utilities Commission
Cash -Designations Report, Combined
8/31/2026
Financial
Institution
Current Interest Rate
Annual
Interest
Balance,
August 2026
Balance,
July 2026
Change in
Cash/Reserve
Position
Savings, Checking, Investments varies varies varies 19,448,394.91 19,300,329.76 148,065.15
Total Operating Funds 19,448,394.91 19,300,329.76 148,065.15
Debt Reserve Requirements Bond Covenants - sinking fund
Debt Reserve Requirements Bond Covenants -1 year Max. P & I
Total Restricted Funds
Operating Reserve
Rate Stabalization Funds
PILOT Funds
Catastrophic Funds
Capital Reserves
Total Designated Funds
Min 60 days of 2026 Operating Bud.
Charter (Formula Only)
Risk Mitigation Amount
5 Year CIP (2026-2030 Fleet & Infrastructure Maintenance)
2,290,242.24 2,009,770.88 280,471.36
3,247,000.00 3,247,000.00 -
5,537,242.24 5,256,770.88 280,471.36
7,079,514.50
7,079,514.50 -
1,819,130.33
1,793,774.36 25,355.97
1,942,626.00
1,942,626.00 -
1, 000, 000.00
1, 000, 000.00
3,450,000.00
3,450,000.00 -
15,291,270.83
15,265,914.86 25,355.97
YE
YE
YE
YE
YTD
HUC
2022
2023
2024
2025
2026
Target
Debt to Asset 31.4%
28.6%
26.0%
22.3%
22.1%
Current Ratio 4.47
4.48
3.67
3.10
2.63
RONA -1.38%
1.96%
2.63%
3.23%
1.95%
Historical Change
in Cash Balance
Month End
Electric
Elec. Change
Natural Gas
Gas Change
Total
Total Change
8/31/2026
(2,304,478)
21,752,873
19,448,395
12/31/2025
(416,323)
(1,888,155)
18,975,091
2,777,782
18,558,768
889,627
12/31/2024
6,134,710
(6,551,033)
17,717,453
1,257,638
23,852,164
(5,293,396)
12/31/2023
12,158,338
(6,023,628)
15,622,242
2,095,211
27,780,580
(3,928,416)
12/31/2022
11,633,212
525,126
15,450,554
171,688
27,083,766
696,815
12/31/2021
12,870,253
(1,237,041)
15,086,000
364,554
27,956,253
(872,487)
12/31/2020
14,239,233
(1,368,981)
15,019,173
66,827
29,258,406
(1,302,153)
12/31/2019
12,124,142
2,115,092
13,837,040
1,182,133
25,961,181
3,297,225
12/31/2018
15,559,867
(3,435,725)
12,335,998
1,501,042
27,895,864
(1,934,683)
12/31/2017
23,213,245
(7,653,378)
10,702,689
1,633,309
33,915,934
(6,020,070)
12/31/2016
8,612,801
14,600,444
9,500,074
1,202,615
18,112,875
15,803,059
12/31/2015
6,170,790
2,442,011
9,037,373
462,701
15,208,163
2,904,712
12/31/2014
3,598,821
2,571,969
6,765,165
2,272,208
10,363,986
4,844,177
* 2017's Significant increase in cash balance is due to issuing bonds for the generator project.
Hutchinson Utilities Commission
Cash -Designations Report, Electric
8/31/2026
Change in
Financial
Annual
Balance,
Balance,
Cash/Reserve
Institution
Current Interest Rate
Interest
August 2026
July 2026
Position
�' Rr
Savings, Checking, Investments varies varies varies 19,448,394.91 19,300,329.76 148,065.15
Total HUC Operating Funds 19,448,394.91 19,300,329.76 148,065.15
Debt Restricted Requirements
Debt Restricted Requirements
Total Restricted Funds
Bond Covenants - sinking fund
Bond Covenants -1 year Max. P & 1
834,242.24
1,175,000.00
2,009,242.24
735,770.88
1,175,000.00
1,910,770.88
98,471.36
-
98,471.36
Excess Reserves Less Restrictions,
Electric
(4,313,720.57)
0.
i 11J! !!1 1 !1
J J
Operating Reserve
Min 60 days of 2026 Operating Bud.
5,068,639.83
5,068,639.83
Rate Stabalization Funds
$400K-$1.2K
1,301,838.58
1,301,838.58
PILOT Funds
Charter (Formula Only)
1,345,802.00
1,345,802.00
Catastrophic Funds
Risk Mitigation Amount
800,000.00
800,000.00
Capital Reserves
5 Year CIP (2026-2030 Fleet & Infrastructure Maintenance)
2,750,000.00
2,750,000.00
Total Designated Funds
11,266,280.41
11,266,280.41
Excess Reserves Less Restrictions
& Designations, Electric
(15,580,000.98)
YE YE YE YE
YTD
APPA Ratio
HUC
2022 2023 2024 2025
2026
5K-10K Cust.
Target
Debt to Asset Ratio (* w/Gen.)
34.8% 34.0% 33.9% 31.6%
33.1%
39.8%
pp ppppp
ryry NNNNNNNNNNNN
Current Ratio
4.96 4.35 2.38 0.80
0.34
3.75
>2.0
RONA
-4.2% -0.9% -2.1% 0.4%
-0.5%
NA
>0%
Hutchinson Utilities Commission
Cash -Designations Report, Gas
8/31/2026
Change in
Financial
Annual
Balance,
Balance,
Cash/Reserve
Institution
Current Interest Rate
Interest
August 2026
July 2026
Position
51' Rr
Savings, Checking, Investments varies varies varies 19,448,394.91 19,300,329.76 148,065.15
Total HUC Operating Funds 19,448,394.91 19,300,329.76 148,065.15
Debt Restricted Requirements
Bond Covenants - sinking fund
1,456,000.00
1,274,000.00
182,000.00
Debt Restricted Requirements
Bond Covenants -1 year Max. P & 1
2,072,000.00
2,072,000.00
-
Total Restricted Funds
3,528,000.00
3,346,000.00
182,000.00
Excess Reserves Less Restrictions,
Gas
18,224,873.24
18,105,797.32
119,075.92
1 1 JJJ1 111 1 11
J J
Operating Reserve
Min 60 days of 2026 Operating Bud.
2,010,874.67
2,010,874.67
-
Rate Stabalization Funds
$200K-$600K
517,291.75
491,935.78
25,355.97
PILOT Funds
Charter (Formula Only)
596,824.00
596,824.00
-
Catastrophic Funds
Risk Mitigation Amount
200,000.00
200,000.00
Capital Reserves
5 Year CIP (2026-2030 Fleet & Infrastructure Maintenance)
700,000.00
700,000.00
-
Total Designated Funds
4,024,990.42
3,999,634.45
25,355.97
YE
YE
YE
YE
YTD
HUC
2022
2023
2024
2025
2026
AGA Ratio
Target
Debt to Asset 26.5%
21.0%
15.5%
10.6%
8.3%
35%-50%
Current Ratio 4.06
4.61
5.08
5.18
6.56
1.0-3.0
RONA 3.0%
6.2%
9.1%
7%
5.1%
2%-5%
Notes/Graphs:
ELECTRIC DIVISION
Operating Revenue
August 2026
CLASS
AMOUNT
KWH
/KWH
Street Lights
21.42
393
$0.0545
Electric Residential Service
$752,950.02
5,735,211
$0.1313
All Electric Residential Service
$23,816.82
161,527
$0.1474
Electric Small General Service
$221,536.70
1,712,093
$0.1294
Electric Large General Service
$1,054,497.62
9,794,450
$0.1077
Electric Large Industrial Service
$898,032.71
9,231,000
$0.0973
Total
$2,950,855.29
26,634,674
$0.1108
Power Adjustment
$0.02146
Rate Without Power Adjustment
$0.08933
Electric Division Year -to -Date
® 2026 $ Amount ❑ 2025 $ Amount ® 2026 KWH110 ❑ 2025 KWH110
25,000,000
20,000,000
15,000,000
10,000,000
5,000,000
0
Residential All Elec. Resid. Small Gen. Srv. Large Gen. Srv. Large Industrial Sales For Resale Total
NOTE: This graph includes sales for resale (capacity and energy sales) but excludes street lights and security lights
NATURAL GAS DIVISION
Operating Revenue
August 2026
CLASS
AMOUNT
MCF
/MCF
Residential
$150,280.95
6,046
$24.8548
Commercial
$132,099.03
8,913
$14.8202
Large Industrial
$43,490.42
4,544
$9.5708
Large Industrial Contracts
$310,194.53
44,340
$6.9958
Total
$636,064.93
63,844
$9.9628
Fuel Adjustment $1.30000
Rate Without Fuel Adjustment $8.66281
Natural Gas Division Year -to -Date
❑ 2026 $ Amount ❑ 2025 $ Amount m 2026 MCF ❑ 2025 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 Large Industrial Total
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Monthly Statistics Report
Search Criteria Used
Year: 2026; Starting Month: August;
Organization: Hutchinson Utilities Commission;
Is an Annual Report: Unchecked;
IEEE 1366 STATISTICS
2025 ( 08/01/2025 - 08/31/2025) 2026 ( 08/01/2026 - 08/31/2026 )
SAIDI 0 0.8434058
SAIFI 0 0.005372012
CAIDI 0 157
ASAI 0 99.99811
Momentary Interruptions 0 0
Sustained Interruptions 0 1
MONTHLY SAIDI CHART
A-I.Se SAI®1 °°. Mrnnthly SAIDI
MONTHLY SAIFI CHART
Aveirage SAIFI °°- Monthly SAIFI
� P!ufi-0
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Month
Month
PRIMARY OUTAGE CAUSES (COUNT)
INon Utillity Exeavatirsm M%' (�
Primary Outage Causes (Count)
Non -Utility Excavation
PRIMARY OUTAGE CAUSES (DURATION)
Non-UtiVity Excvatic r:: HtlG'.-'�
Primary Outage Causes (Duration)
Non -Utility Excavation 6280
CIRCUIT RANKING - WORST PERFORMING
Ranked by Outage Count
Circuit
Substation
Fdr#14 Plant 1 1
Number of
Outages
Ranked by Customer Interruptions
Customer
Circuit Substation Interruptions
Fdr#14 Plant 1 40
Ranked by Customer Minutes of Duration
Circuit Substation
Fdr#14
Plant 1
Customer Minutes
of Duration
6,280
TOP 10 OUTAGES FOR THE MONTH +/-
Customer
Customers Minutes of
Address Interrupted Duration Interruption Start Date
Ivy Lane (/n/esams/reliability- 40 157 6280 8/31/2026
tracker/d ash board/outages/1 087349/details) 9:38:00 AM
Total Customers Affected for the Month: 40
Average Customers Affected per Outage: 40
Work
Order Descrigtion
12402 Plant 1 Combustible Gas Detection System
1.2502 Rubber Roof Repair West Portion of Plant 1
12503 Plant 1 Pump Room Ventilation
12504 Plant 1 Control Panel Upgrade
12505 Unit 1 CO2 System Update Code Compliance
12506 Cooling Tower Recirc and Chem Injection
12507 Plant 1 North Ground Fans
12601 Power Gates Plant 2
12602 Plant 1 and 2 Cooling Tower VFD's
12603 Unit 5 HUG Upgrade
12604 Plant 1 Web Master Upgrade
12605 Rooftop Solar
12606 Unit 1 LPT Stage 2 Blade Replacement
Electric Production
Total
Materials
Labor Budgeted
60,000.00
60,000.00
50,000.00
5,000.00 55,000.00
148,067.00
148,067.00
35,000.00
35,000.00
130,000.00
130,000,00
50,000.00
50,000.00
80,000.00
- 80,000.00
40,000.00
5,000.00 45,000.00
351,000.00
- 351,000.00
7,870.00
7,870.00
$ 951,937.00 $ 10,000.00 $ 961,937.00 $
Total
Actual
46,384.67
24,391.67
22,519.95
20,699.10
310,619.80
424,615.19 $
Different
46,394.67
(60,000.00)
(55,000.00)
(123,675.33)
(35,000.00)
(107,480.05)
(50,000.00)
(80,000.00)
(24,300.90)
(351,000.00)
(7,870.00)
310,619.80
(537,321.81)
Work
order Descriotion
22301 Hutch Sub Transformer Upgrade Engineering
22401 Hutch Substation Transformer
22402 McLeod Sub Relay Replacement
22405 3M Sub SCADA Phase
22503 Plant 1 Sub Circuit Breakers
22504 Plant 1 Sub Rebuild Distribution
22522 Data Center
22601 Willmar Line Rebuild
22602 Plant 1 Sub Rebuild Transmission
22603 Pole Repair and Replacement
22604 Station Equipment
22605 Plant 1 Batteries
22606 Install Duct
22607 Reconductor Feeder 19
22608 New Developments
22609 Then Landing Apartments
22610 Burns Manor Apartments
22611 The Farmhouse Memory Care
22612 Scooters Coffee
22613 Plant 1 Sub Rebuild XFMR
22614 Transformer Replacements
22615 Transformer New Developments
22616 The Landing Apartments
22617 Burns Manor Apartments
22618 The Farmhouse Memory Care
22619 Scooters Coffee
22620 Meters
22621 LED Street Light Conversion
Electric Distribution
Total
Total
Materials
Labor
Budgmete,d,
Actual
Difference
9,103,969.59
9,103,969.59
2,677,239.93
2,677,239.93
400,000.00
400,000.00
22,993.00
(377,007.00)
-
90,068.66
90,068.66
112,497.00
112,497.00
-
-
84,231.10
84,231.10
20,000.00
5,000.00
25,000.00
201,798.02
176,798.02
15,000.00
-
15,000.00
-
(15,000.00)
10,000.00
-
10,000.00
-
(10,000.00)
15,000.00
2,500.00
17,500.00
-
(17,500.00)
18,000.00
65,000.00
83,000.00
24,627.07
(58,372.93)
80,000.00
20,000.00
100,000.00
131,897.50
31,897.50
60,000.00
15,000.00
75,000.00
37,155.63
(37,844.37)
15,000.00
5,000.00
20,000.00
27.17
(19,972.83)
15,000.00
5,000.00
20,000.00
-
(20,000.00)
7,000.00
2,000.00
9,000.00
-
(9,000.00)
7,000.00
2,000.00
9,000.00
-
(9,000.00)
-
-
-
165.74
165.74
50,000.00
15,000.00
65,000.00
2,119.26
(62,880.74)
60,000.00
15,000.00
75,000.00
923.78
(74,076.22)
20,000.00
2,000.00
22,000.00
2,523.53
(19,476.47)
20,000.00
2,000.00
22,000.00
-
(22,000.00)
20,000.00
2,000.00
22,000.00
-
(22,000.00)
15,000.00
2,000.00
17,000.00
-
(17,000.00)
36,000.00
-
36,000.00
35,421.54
(578.46)
175,000.00
-
175,000.00
-
175,000.00
$ 1,058,000.00 $ 159,500.00 $ 1,217,500.00 $ 12,527,658.52 11,310,158.52
Natural Gas
Work
Total
Total
Order
Description
Materials
Labor
Bu,de,ted
Actual
Difference
62511
DRS #5 Upgrades
23,500.00
2,000.00
25,500.00
3,746.24
(21,753.76)
62601
Misc Developments & System Improvements
25,000.00
5,000.00
30,000.00
9,152.75
(20,847.25)
62602
City Projects
10,000.00
4,000.00
14,000.00
2,297.25
(11,702.75)
62603
Install 6" Line from Plant 1 to School Road
370,000.00
12,000.00
382,000.00
131,489.93
(250,510.07)
62604
Improvements to Regulator Stations
10,000.00
3,500.00
13,500.00
7,997.52
(5,502.48)
62605
Make DRS#11 at Plant 1
14,000.00
2,000.00
16,000.00
6,051.93
(9,948.07)
62606
Service Lines, The Landing, Burns Manor
65,000.00
15,000.00
80,000.00
21,890.35
(58,109.65)
62607
Service lines to Hjerpe
-
-
-
19,265.76
19,265.76
62608
Meters, AMI, and All Fittings
250,000.00
10,000.00
260,000.00
31,587.84
(228,412.16)
62609
Residential Regulators
-
-
-
1,066.70
1,066.70
62610
Industrial Metering and Regulation
25,000.00
3,500.00
28,500.00
144.72
(28,355.28)
62611
3m Boiler Bypass Rund
3,000.00
3,000.00
6,000.00
4,684.56
(1,315.44)
62612
Fairfax Micro Motion Elite Coriolis Meter
-
-
-
24,961.18
24,961.18
$ 795,500.00 $ 60,000.00 $ 855,500.00 $ 264,336.73 $ (591,163.27)
HUTCHINSON UTILITIES COMMISSION
Board Action Form
�rre tit'
Agenda Item: Review Policies
Presenter: Angie Radke
Agenda Item Type:
Time Requested (Minutes): 5
Review Policies
Attachments: Yes
BACKGROUND/EXPLANATION OFAGENDA ITEM:
As part of HUC's standard operating procedures, a continual policy review is practiced.
This month, the following policies were reviewed and no changes are recommended on
these policies at this time:
i. Electric Service Requirements & Charges
ii. Temporary Service- Electric
iii. Temporary Service in Case of Underground Failure
iv. Electric Meter Placement
v. Sealing of Meters — Electric
vi. Meter Testing - Electric
vii. Right -of -Way Clearing
viii. Tree Removal of Trimming
ix. Locating Customer's Underground Utilities — Electric
BOARD ACTION REQUESTED:
None
Fiscal Impact:
Included in current budget: Budget Change:
PROJECT SECTION:
Total Project Cost: Remaining Cost:
SERVICE POLICIES - ELECTRIC
Electric Service Requirements and Charges
HUC will require a 24-hour notice, a copy of the State Board of Electricity Certificate of
Inspection, and an established account prior to installing a meter and making the final
connection.
HUC shall not install any facilities until all affected properties are within 6 inches of final
grade.
Installation of Any Electric Services — November 1 Through March 31
The final determination on installation of electric services shall be made by HUC.
New Single -Family Dwelling — Service Size: 200 Amperes or less
Single-family dwelling customers will be 240/120 volt single-phase service.
HUC shall furnish and install the underground conductors to serve the single-family home
with a one-year warranty after installation date. The underground service is the property
of the homeowner at date of installation.
(4/0-2/0-4/0 URD): Minimum $300.00 Installation Charge up to 100 ft.; additional
$2.00/ft. in excess of 100 ft.
The customer or their contractor shall provide and install a 200A, ringless meter socket
with lever bypass (See meter requirement/placement section).
New Single -Family Dwelling — Service Size: Greater than 200 Amperes
Single-family dwelling customers will be 240/120 volt single-phase service.
Current transformer metering is required. HUC shall furnish the current transformers,
meter socket and meter (See meter requirement/placement section). The customer or
their contractor shall provide the current transformer housing and facilities, install the
current transformers, mount the meter socket and provide an empty 1-'/4 inch conduit to
the meter socket. HUC shall install the meter wiring and meter. No current transformer
metering will be allowed in the power transformer secondary compartment.
Bar type current transformers will be used. Provisions for voltage connections for the
meter must also be provided.
The customer will be responsible for installing the service to the utility transformer or
pedestal location. HUC will be responsible to make all secondary connections in the
transformer. Transformer secondary connections will be limited to a maximum of four
conductors per phase with a maximum size of 750 MCM per conductor. If additional
conductors are required per phase, the owner or contractor must provide an approved
secondary transition cabinet. HUC's Electric Division may be contacted for further details.
New Multi-Familv Dwellina. Commercial. or Industrial
The customer will be responsible for installing the service to the utility transformer or
pedestal location. For any services that require current transformer metering, the
customer will be responsible to install the conductor from the metering cabinet to the
transformer. For any three-phase services, the customer shall furnish the transformer pad
and ground grid. The transformer location shall be determined by HUC.
HUC will provide the following voltages:
120/208 volts three phase, not to exceed 3,000 amperes without prior approval.
277/480 volts three phase, not to exceed 3,000 amperes without prior approval.
7,970/13,800 volts three phase, with prior arrangements with HUC.
HUC will be responsible to make all secondary connections in the transformer.
Transformer secondary connections will be limited to a maximum of four conductors per
phase with a maximum size of 750 MCM per conductor. If additional conductors are
required per phase, the owner or contractor must provide an approved secondary
transition cabinet. HUC's Electric Division may be contacted for further details.
On services greater than 200 amperes at 240/120volts, current transformer metering is
required. HUC shall furnish the current transformers, meter socket and meter. The
customer or their contractor shall provide the current transformer housing and facilities,
install the current transformers, mount the meter socket and provide an empty 1-'/4 inch
conduit to the meter socket. HUC shall install the meter wiring and meter. No current
transformer metering will be allowed in the power transformer secondary compartment.
Any service greater than 240 volts, shall require current transformer metering.
Bar type current transformers will be used. Provisions for voltage connections for the
meter must also be provided. Approved multi -family dwelling meter stacks will be provided
by the customer or their contractor.
Primary metering at 7,970/13,800 volts will be by special arrangement and approval of
HUC.
Temporary Service
For temporary service, please contact HUC's Customer Service Department.
HUC shall bill the customer or their contractor for all related expenses.
Temporary Service in Case of Underground Failure
When an underground service fails, HUC will furnish a temporary service to the customer
at no charge. The customer will have ten working days to repair or replace the service.
In the event the work can't be completed within ten working days the customer may
contact HUC to perform the required maintenance at HUC's current time and material
rates. If after ten working days, the required maintenance has not been completed or
the customer has not contacted HUC to make arrangements to have the service repaired,
HUC will remove the temporary service.
In the event of frost, the customer will need to contact HUC to make arrangements to
have the repair done at a later date.
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.
No customer owned device or equipment is allowed to be connected to the meter socket.
Meters may be relocated to a location agreed upon by HUC and the customer (or location
approved 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,
residing, 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 (or
approved by) by HUC.
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.
Tree Removal or Trimming
Tree removal or trimming for other than right-of-way clearance is the responsibility of the
property owner. Please notify HUC with any questions concerning tree removal or
trimming.
Any repair of damage to the HUC electrical distribution system caused by tree removal or
trimming, by the property owner or their representatives will be billed to the property
owner.
Locating Customer's Underground Utilities
HUC will locate all underground electric distribution and transmission facilities up to the
meter at no charge to the customer or landowner.
3724 West Avera Drive
PO Box 88920
Sioux Falls, SD 57109-8920
Telephone: 605.338.4042
Fax: 605.978.9360
www.mrenergy.com
November 21, 2025
Jeremy Carter
Hutchinson Utilities Commission
225 Michigan St SE
Hutchinson, MN 55350
RE: Official Notice of January 1, 2026 S-1 Rates
Dear Jeremy Carter:
Rate Schedules B and C to the S-1 Power Sale Agreement (S-1 Agreement) between Missouri River Energy
Services (MRES), Western Minnesota Municipal Power Agency, and your utility are enclosed. Schedule B
includes power supply rates for all members, and Schedule C reflects transmission rates for the various
transmission groups.
The changes to the 2026 Supplemental Power Demand and Energy rates in Schedule B compared to the 2025
rates are as follows:
• Summer demand rates will increase to $20.00/kW from $19.50/kW.
• Winter demand rates will increase to $16.00/kW from $15.50/kW.
• Spring/Fall demand rates will increase to $10.25/kW from $10.00/kW.
• Time -Of -Use (TOU) energy rates will increase as follows:
2025
2026
n Peak `cents per kWh'
$0.049
$0.053
Mid Peak ',cents firermkWh"i
$0 035
$0.037
Off Peak
$0 025
$0.027
The average power supply rate for all members is projected to be approximately 6.2 cents per kWh in 2026, an
increase from the budgeted 2025 average power supply rate of 6.0 cents per kWh. The average MRES power
supply rate for your utility will depend on the seasonal and annual load factor of your utility.
The Supplemental Power Demand and Energy rates will be effective January 1, 2026, and the current rates are:
.........
Power Su 1,, Rates:
Suivlemental Power Demand durin r June, July, and Au a1!st (>er kW)
Supplemental Power Demand during January, February, and December (per kW)
Rates
Effective
01/01/2026
$20.00
$16.00
Current
Rates
$19.50
$15.50
Sup:elemental Power Demand durin ., all other months !Per kW'
$10.25
$10.00
Energy for Supplemental Power (per kWh) (TOU implemented in 2023)
On Peak
$0.053
$0.049
Mid Peak
$0.037
$0.035
Off Peak
$0.027
$0.025
Production Cost Adjustment Base (per kWh)
$0.030
$0.030
Green Energy Rate adders, i.e., in addition to the energy for supplemental power
noted above:
Renewable Energy Certificate REC) not specifically associated with an MRES-
(Standard
$0.001
$0.001
contracted renewable resource REC) ,per kWh
REC specifically associated with an MRES-contracted renewable resource (MRES
$0.002
$0.002
Resource REC) (per kWh)
REC specifically associated with WAPA hydroelectric renewable resources (WA -PA
$0.001
N/A
Resource REC)
Since Hutchinson Utilities Commission (HUC) does not take transmission service from MRES, the
transmission rates in the enclosed Schedule C are not applicable to HUC. We have enclosed Schedule C since
the rates are included in a rate schedule to the S-1 Agreement.
The attached Schedules B and C fulfill the requirements of Section 7 of the S-1 Agreement and supersede any
previously issued rate schedules.
If you have any questions regarding the enclosed information, please call Chris Olson at 800-678-4042.
Sincerely,
0 / 0
Matthew E. Schull
President and Chief Executive Officer
Enclosures
MISSOURI BASIN MUNICIPAL POWER AGENCY
d/b/a MISSOURI RIVER ENERGY SERVICES
POWER SALE AGREEMENT (S-1)
SCHEDULE B
S-1 SUPPLEMENTAL POWER RATES
L APPLICABILITY
This Schedule B is applicable to the purchase of Supplemental Power by any Municipality pursuant to the terms
of the Power Sale Agreement (S-1 Agreement) with Missouri River Energy Services (MRES). This Schedule B is
also applicable to the purchase of the Power Requirements pursuant to the terms of the Pella Power Sale
Agreement, the purchase of the Supplemental Power pursuant to the terms of the Atlantic Municipal Utilities
Power Sale Agreement, and the purchase of the Contract Quantity pursuant to the terms of the HUC Power Sale
Agreement (collectively, the Other Power Sale Agreements). The term Power Supply in this Schedule B includes
all power and energy subject to this rate schedule, pursuant to the various power sale agreements identified in this
Section. All capitalized terms shall have the meaning defined in the S-1 Agreement, unless otherwise provided in
this Schedule B.
2. CHARACTER OF SERVICE
Electric power and energy furnished under this Schedule B shall be alternating current, 60 hertz, 3-phase.
3. MONTHLY RATES FOR POWER SUPPLY
For electric power and energy furnished under the S-1 Agreement and Other Power Sale Agreements subject to
this rate schedule, the monthly charges shall be determined as follows:
Demand Rate:
a. Summer Season (June, July, and August): $20.00 per kilowatt (kW) of Demand as determined in
Section 11 below.
b. Winter Season (January, February, and December): $16.00 per kW of Demand as determined in
Section 11 below.
C. All Other Months (March, April, May, September, October, and November): $10.25 per kW of
Demand as determined in Section 11 below.
Energy Rate:
Time Of Use (TOU) rate per Kilowatt-hour (kWh) (see table below) as determined in Section 11 below.
........ _ TOU Ener....
gy Blocks
Summer: _ Winter: Sprin/Fall:
— _ .— _ March-Maylye. bb ...
June —Au rest December-Februaa° � Se stember-November
Weekday
Mid Peak — 6AM —12PM AM 1 OAM _ .... 6�8 _.....
— 1 OAM — 4PM PM
On Pea � 12PM — 8PM 6 — 4PM 8PM None
Off Peak 8PM — 6AM
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 1 B
id PedlHohdaM
Mee en .... .....
k _ 6AM - 8PM w�
Off Peak 8PM — 6AM
are the 6 standard No rth American Electric Reliability Corporation holidays: New Years Day, Memorial , DayIndepen deuce
*Holidays
Day, Labor Day, Thanksgiving Day and Christmas Day.
Green Energy Rate Adder.
If Municipality is purchasing Green Energy pursuant to Section 3(a)(ii) of the S-1 Agreement or pursuant to the
terms of any Other Power Sale Agreement with a Green Energy option, MRES shall charge for Green Energy at
the applicable TOU rate per kWh plus:
$0.001 per kWh for Renewable Energy Certificates (REC) not specifically associated with an MRES-
contracted renewable resource (Standard REC); or
$0.002 per kWh for RECs specifically associated with an MRES-contracted renewable resource (MRES
Resource REC).
The applicable Demand Rate identified in this Section 3, above, also applies to the Green Energy Rate Adder.
WAPA REC Rate:
If Muni.....................1.......ww..v
cipality elects to sell to MRES any RECs allocated to Municipality by Western Area Power
Administration (WAPA) associated with power purchased from WAPA in 2026 (WAPA RECs), MRES shall
purchase and pay Municipality for such WAPA RECs at the following rate:
$0.001 per kWh for RECs specifically associated with WAPA hydroelectric renewable resources (WAPA
Resource REC).
4. POWER COST ADJUSTMENT
The base variable production and purchased power cost (VC) included in the Energy Rate is $0.030 per kWh.
Six -Month VC (SMVC), for the purposes of this Section, is defined as the actual average VC of energy produced
and purchased by MRES for the preceding 6-month period. If the SMVC is greater than $0.032, MRES shall
charge Municipality an amount equal to the product of the SMVC less $0.032, multiplied by the number of kWh
for the most recent month.
The VC, for purposes of this adjustment, shall include, as determined by MRES:
a. The variable production costs of the generating plants owned by Western Minnesota Municipal
Power Agency (WMMPA) to meet MRES Power Supply obligations to Members under the S-1
Agreement and Other Power Sale Agreements; and
b. The cost of power and energy purchased by MRES or WMMPA from other power suppliers or
markets to meet Member Power Supply needs.
5. MEMBER -OWNED RENEWABLE RESOURCE GENERATION
If MRES has executed a Member Renewable Resource Agreement with Municipality requiring MRES to
purchase the output from Municipality's renewable resource generator(s) and to resell the output to Municipality
under the S-1 Agreement or Other Power Sale Agreement as part of Municipality's Power Supply, the charges for
that generation shall be based on the rates established in the Member Renewable Resource Agreement.
6. RETAIL CUSTOMER -OWNED GENERATION
Standb,^�Rates:
a. Applicability: This rate is available and applicable to each Municipality which has a retail
customer with internal generation from a generating unit exceeding five megawatts (MW). If a
Municipality has a retail customer with internal generation from a unit exceeding five MW, such
generation shall be separately metered. Municipality is responsible for installing and maintaining
all such metering equipment.
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 2B
b. Standby Demand: If a Municipality so chooses, it may nominate, in writing to MRES, all or a
portion of the qualifying retail generation for the Nominated Standby Demand Rate (as defined
farther in this Section, below). In such event, MRES shall charge Municipality the product of the
amount of generation nominated multiplied by the Nominated Standby Demand Rate, on a
monthly basis. Municipality may make such nomination at or before the time the generation of
the retail customer goes online. Subsequently, Municipality is allowed to nominate or change its
nomination one time each year by providing written notice of any such action no later than
November 30 for the following year. If notice is properly given, any changes to the nomination
will be effective on December 31, hour ending 24:00; provided however that if a nomination
change is made during an Excess Standby Demand Rate period as described in this Section 6
below, the revised nomination shall not take effect until the expiration of the Excess Standby
Demand Rate period.
If the generation of a retail customer's internal generating unit exceeding five MW is not in
service, whether planned or unplanned (Out -of -Service Event), MRES shall charge Municipality
the following demand charge to replace such customer's generation measured as of the time of
Municipality's peak supplemental demand:
(i) If Municipality nominated internal customer generation as described above, and such
nomination level exceeds the demand required as a result of the Out -of -Service Event,
MRES shall not charge Municipality for any amount in addition to the Nominated Standby
Demand Rate.
(ii) If Municipality elected not to nominate internal customer generation, or nominated an
amount less than the demand required due to the Out -of -Service Event, MRES shall charge
Municipality the Excess Standby Demand Rate (as defined further below in this Section 6)
on demand exceeding the nominated generation or, if Municipality made no nomination of
generation, on all demand for the month of the Out -of -Service Event and each of the
succeeding 11 months (the Excess Standby Demand Rate period).
Nominated Standby Demand Rate: $5.00 per kW -month. This rate shall be multiplied by the
amount of retail customer qualifying generation nominated by Municipality.
Excess Stand_ by Demand Rate: The rate shall be the Power Supply demand rate in effect under
Section 3 for the month of the Out -of -Service Event. MRES will assess a charge based on the
product of the Power Supply Demand Rate multiplied by the retail customer monthly 30-minute
coincident peak to the member monthly system 30-minute peak. If there is another Out -of -
Service Event during the Excess Standby Demand Rate period, MRES shall charge Municipality
the higher of the Excess Standby Demand Rate applicable to the initial Out -of -Service Event and
the Excess Standby Demand Rate applicable to the subsequent Out -of -Service Event.
Each retail generation Out -of -Service Event begins a new 12-month Excess Standby Demand
Rate period, commencing the month of the Out -of -Service Event.
C. Standby Energy: The Standby Energy Rate shall be the higher of the energy rate under Sections
3 and 4 of this rate schedule or 125 percent of the day -ahead Locational Marginal Price on the
dates of such purchases. MRES shall charge for energy purchased by Municipality during an
Out -of -Service Event to replace retail customer generation meeting the applicability requirements
of this Section 6 times the Standby Energy Rate,
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 3B
Other Retail Customer Generation Rates:
If MRES .. � ..�w..._w�w.............-.......ww.. � ..
incurs a transmission charge from Midcontinent Independent System Operator, Inc. (MISO) or
Southwest Power Pool, Inc. (SPP) for generation of any retail customer (irrespective of size) of a Municipality
and Municipality has not been charged the Excess Standby Demand Rate, MRES shall charge Municipality the
cost incurred by MRES from MISO or SPP for that retail customer generation.
7. LARGE CUSTOMER RETENTION INCENTIVE
a. Eligibility: MRES shall make available the Large Customer Retention Incentive (Retention
Incentive) described in this section to any Municipality that:
(i) MRES has the obligation to provide Supplemental Power or all Power Requirements,
(ii) has a retail customer with a coincident peak demand (the customer's peak coincident to the
Municipality's peak) of at least 30 MW and a load factor of at least 80 percent, each as
determined on a 12-month rolling monthly average (Eligible Customer),
(iii) enters into a Large Customer Retention Incentive Agreement with MRES and the Eligible
Customer as described in subsection e below (Customer Agreement), and
(iv) provides a corollary rate Retention Incentive to the Eligible Customer as described in
subsection c below.
A customer will not be considered an Eligible Customer under this Section 7 if that customer is a
beneficiary, through the Municipality, of the Economic Development Incentive described in
Section 8 below.
In the event a Municipality has more than one Eligible Customer as described in this Section 7,
the Retention Incentive shall be available to the Municipality with respect to each such Eligible
Customer, subject to the terms and conditions of this section and the Customer Agreement
entered into with each Eligible Customer. The terms of this Section 7 shall apply independently
with respect to each Eligible Customer.
b. Retention Incentive: Subject to the terms and conditions of this Section 7 and the Customer
Agreement, MRES shall provide a Retention Incentive to the Municipality in the amounts
described below, which Retention Incentive shall be applied to all kWh purchased from the
Municipality by the Eligible Customer during the term of the Retention Incentive, as set forth in
the Customer Agreement. The Retention Incentive shall be a rate discount of $0.0057 per kWh
for the first two years of the Retention Incentive, $0.0053 per kWh for the next five years of the
Retention Incentive, and $0.0020 per kWh for the remaining term of the Retention Incentive. The
Retention Incentive must be passed on to the Eligible Customer by the Municipality, be a separate
line item on the bill, and identify MRES as the provider of the credit.
C. Municipality Participation: The Municipality shall provide a corollary Retention Incentive to the
Eligible Customer of at least $0.0005 per kWh during the first seven years that the Retention
Incentive described in subsection b is provided by MRES and at least $0.0002 per kWh for any
additional years that the Retention Incentive described in subsection b is provided by MRES.
This corollary Retention Incentive shall be applied to all kWh purchased from the Municipality
by the Eligible Customer during the term of the Retention Incentive, as set forth in the Customer
Agreement.
d. Duration: The Retention Incentive shall be provided for a term of up to ten years. The Retention
Incentive shall terminate immediately in the event:
(i) the Municipality or the Eligible Customer ceases to satisfy the eligibility requirements
described in subsection a above,
(h) the Eligible Customer, either directly or indirectly, engages in any activity to secure or
develop any resource other than the Municipality to serve any of the Eligible Customer's
power or energy requirements, or
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 4B
(iii) the Customer Agreement is terminated pursuant to the terms thereof.
Customer Agreement: The Municipality, the Eligible Customer, and MRES shall enter into an
agreement in a form and substance acceptable to MRES to further memorialize all terms and
conditions associated with the Retention Incentive, including without limitation the duration of
the Retention Incentive, the obligations of the Municipality and the Eligible Customer to receive
the Retention Incentive, and other terms as agreed by the parties. In the event a Municipality,
Eligible Customer, and MRES enter into a Customer Agreement, such Customer Agreement and
associated Retention Incentive shall remain in effect for the term set forth in the Customer
Agreement, subject to the terms and conditions of the Customer Agreement.
ECONOMIC DEVELOPMENT INCENTIVE
a. Eligibility: MRES shall make available the Economic Development Incentive described in this
section to any Municipality that:
(i) Is a party to an S-1 Agreement or an Other Power Sale Agreement that is dated prior to
January 1, 2018, and pursuant to which the Municipality purchases from MRES all
Supplemental Power or Power Requirements;
(ii) (A) Has a new retail commercial or industrial customer that:
(1) commenced operation of a new commercial or industrial facility on or after January 1,
2026 (for purposes of this subsection, the term "new commercial or industrial facility"
shall mean a newly constructed facility or an existing facility that had not been in active
commercial operation for at least 12 months prior to its commencement of operation on
or after January 1, 2026),
(2) has electric requirements meeting the criteria set forth in subsection b of this Section
8, and
(3) has not installed internal generation to self -supply any of its electric requirements; or
(B) Has an existing retail commercial or industrial customer that:
(1) expanded its commercial or industrial facility and such expansion will enter
commercial operation on or after January 1, 2026,
(2) has electric requirements meeting the criteria set forth in subsection b of this Section
8, and
(3) has not installed internal generation to self -supply any of its electric requirements
(a retail commercial or industrial customer that satisfies the requirements of subsection (A)
or (B) above constitutes a "Qualifying Customer" for purposes of this section, except as
otherwise provided below).
(iii) Requests the incentive from MRES and supplies adequate information to support the
requirements of this Section 8 as determined by MRES;
(iv) Provides at least 50 percent of this incentive to the Qualifying Customer; and
(v) Supports economic development locally and has provided to MRES documentation of the
local development efforts.
A customer will not be considered a Qualifying Customer under this Section 8 if such customer is
a beneficiary, through the Municipality, of the Large Customer Retention Incentive described in
Section 7 above.
In the event a Municipality has more than one Qualifying Customer as described in this Section 8,
the Economic Development Incentive shall be available to the Municipality with respect to each
such Qualifying Customer, subject to the terms and conditions of this section. The terms of this
Section 8 shall apply independently with respect to each Qualifying Customer.
b. Rate Discount: The incentive provided pursuant to this Section 8 is in the form of a rate discount
provided by MRES to the Municipality. The amount of the rate discount shall be based on the
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 5B
application of the following table to the eligible customer of the Municipality. To be eligible for
this incentive, a customer must satisfy at least two of the three criteria noted in columns 1 through
3 of the table, and the applicable rate discount will be based on the level of qualification under
columns 1 through 3.
For a new customer as described in subsection (a)(ii)(A) above, columns 1 through 3 will be
applied to the new load.
For an existing customer with an added load as described in subsection (a)(ii)(B), columns 1 and
2 will apply to the added load and column 3 will apply to the total load at the customer's facility.
1
2
3
4 E5
6
_I
7
. ... ..........
Load must meet at
least 2 of the followin
criteria
Rate Discount
` )er kWh
Minimum
Minimum
Monthl kWh,
Monthlsr Peak
Monthl
Years 1
Usage
Demand
Load Factor
and 2 Year 3
Year 4
Year 5
1,000,000 and higher
2 MW
60%
$0.0150 $0.0125
$0.0100
$0.0000
500,000 and higher
1 MW
60%
$0.0100 $0.0075
$0.0050
$0.0000
250,000 and higher
500 kW
60%
$0.0075 $0.0050
$0.0025
$0.0000
125,000 and higher
250 kW
50%
$0.0050 $0.0025
$0.0025
$0.0000
9. TAX ADJUSTMENT CLAUSE
In the event that any lawful authority imposes on MRES any tax, or charge for payment in lieu of tax, on the
production, transmission, or sale of electric power and energy sold by MIRES, MRES may charge the
Municipality the cost incurred for its share of such tax or payment in lieu thereof.
10. LATE PAYMENT CHARGE
A charge of 5 percent may be imposed on the unpaid balance of any amount due and owing after the date when
such amount is due.
11. BILLING MEASUREMENT
The metered demand in kW shall be the highest 30-minute integrated demand (or corrected to a 30-minute basis
in the event 15-minute demand registers are installed) measured during the billing period (with meter reading
adjustments, if any, as provided for in Schedule A of the S-1 Agreement or any Other Power Sale Agreement
subject to this rate schedule). The billing measurements for Power Supply shall be determined as follows:
a. S-1 Agreement:
Demand = TD-WD
Energy = TE-WE
TD — The total demand for the current billing period determined on a basis in accordance with the
contract in effect between Municipality and WAPA pursuant to which WAPA sells the
Municipality electric power and energy (WAPA Power).
TE — The total energy delivered during the billing period determined on a basis in accordance
with the WAPA Power.
S-1 Agreement, Schedule C, effective January 1, 2026 Page 66
WD — The amount of demand delivered to Municipality by WAPA for the current billing period.
WE — The amount of energy delivered to Municipality by WAPA for the current billing period.
b. Other Power Sale Agreements:
Pella Power Sale Agreement: The maximum amount of all power, energy, and related products
and services required by Municipality to meet the needs of all of its consumers.
Atlantic Municipal Utilities Power Sale Agreement: The Supplemental Power as established in
such agreement.
HUC Power Sales Agreement: The Contract Quantity as established in such agreement.
C. Losses: Losses charged by a third party transmission provider, if any, will be added to the
respective Municipality's demand and energy purchases from MRES and WAPA.
12. BILLING PERIOD
The MRES billing period shall be established to coincide with the meter reading schedules of WAPA for all
services provided pursuant to the S-1 Agreement and shall be established by MRES, Municipality, and third party
transmission provider, if necessary, for Other Power Sale Agreements.
Effective: The first day of the January 2026 billing period
Approved September 11, 2025: Board of Directors
Missouri Basin Municipal Power Agency
d/b/a Missouri River Energy Services
Issued by: Matthew E. Schull, President and Chief Executive Officer
Missouri Basin Municipal Power Agency
d/b/a Missouri River Energy Service
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 7B
MISSOURI BASIN MUNICIPAL POWER AGENCY
d/b/a MISSOURI RIVER ENERGY SERVICES
POWER SALE AGREEMENT (S-1)
SCHEDULE C
S-1 TRANSMISSION RATES
I , APPLICABILITY
This Schedule C is applicable to Transmission Service provided by Missouri River Energy Services (MRES)
pursuant to the terms of the Power Sale Agreement (S-1 Agreement). This Schedule C is also applicable to
Transmission Service provided by MRES pursuant to the terms of the Pella Power Sale Agreement and the
Atlantic Municipal Utilities Power Sale Agreement (collectively, the Other Power Sale Agreements). MRES
shall charge for Transmission Service based on the costs incurred by MRES from Midcontinent Independent
System Operator, Inc. (MISO) or Southwest Power Pool, Inc. (SPP), or others, for providing Transmission
Service to the Point of Delivery (POD) at or over those transmission facilities to which Municipality is
interconnected. The transmission facilities to which the various Municipalities are interconnected shall be
referred to as Transmission Service Groups, as follows:
a. Great River Energy (GRE) Group, includes the Municipality listed on page 3c of this Schedule C;
b. L&O Power Cooperative (L&O) Group, includes the three Municipalities listed on page 3c of this
Schedule C;
c. MidAmerican Group, includes the two Municipalities listed on page 3c of this Schedule C;
d. Northern Cities Group (NCG), includes the 12 Municipalities listed on page 3c of this Schedule C;
e. Split Rock Group (SRG), includes the five Municipalities listed on page 3c of this Schedule C;
f. Upper Missouri Zone (UMZ) Group, includes the 32 Municipalities listed on page 3c of this Schedule C;
and
g. Xcel Group, includes the five Municipalities listed on page 3c of this Schedule C.
All capitalized terms shall have the meaning defined in the S-1 Agreement or Other Power Sale Agreements,
unless otherwise provided in this Schedule C.
2. CHARACTER OF SERVICE
Transmission Service furnished or made available under this Schedule C shall be that service at POD shown on
Schedule A for 3-phase, 60-hertz alternating current at the voltages shown.
3. MONTHLY RATE
For Transmission Service funnished or made available pursuant to Section 6 of the S-1 Agreement, or the Other
Power Sale Agreements, MRES shall charge each Municipality for all costs incurred by MRES which may be
required to effect Transmission Service, including those costs and charges included in Section 6 and Section 7 of
the S-1 Agreement, or the Other Power Sale Agreements, and all costs and charges under provisions of any Tariff
of MISO or SPP (as such Tariffs may be supplemented or amended by MISO or SPP or their respective
successor), pursuant to which MRES has acquired transmission capacity or service for the purpose of supplying
Transmission Service to Municipality. The rates for each Transmission Service Group shall be as follows:
a. GRE Group: The monthly demand rate shall be $10.00 per kilowatt ^). This rate will be multiplied by
Municipality's Monthly Peak Demand as determined in Section 7 below.
b. L&O Group: The monthly demand rate shall be: (i) the UMZ Group rate as set forth below ($7.46 per
kW), plus (ii) $2.12 per kW. Each component of this rate will be multiplied by Municipality's applicable
Monthly Peak Demand as determined in Section 7 below.
c. MidAmerican Group: The monthly transmission charges assessed to Municipality by MidAmerican
Energy Company and MISO.
d. NCG: The monthly demand rate shall be $4.85 per kW. This rate will be multiplied by Municipality's
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 1C
Monthly Peak Demand as determined in Section 7 below.
e. SRG: The monthly demand rate shall be $16.22 per kW. This rate will be multiplied by Municipality's
Monthly Peak Demand as determined in Section 7 below.
f. UMZ Group: The monthly demand rate shall be $7.46 per kW. This rate will be multiplied by
Municipality's Billing Demand as determined in Section 7 below.
g. Xcel Group: The monthly demand rate shall be $9.05 per kW. This rate will be multiplied by
Municipality's Monthly Peak Demand as determined in Section 7 below.
4. TRANSMISSION COST ADJUSTMENT
MRES shall adjust the charges to Municipality monthly based on the difference between the total charges based
on the Monthly Rates in Section 3, above, and the actual costs incurred by MRES for Transmission Service
provided to Municipality. This adjustment shall not be made to Municipalities in the NCG. Reserves
accumulated by the NCG will absorb the variances between costs incurred and the rate charged until such time as
these reserves are exhausted, which is not expected to occur in 2026.
5. TAX ADJUSTMENT CLAUSE
In the event any lawful authority imposes on MRES any tax, or charge for payment in lieu of tax, on the
production, transmission, or sale of electric power and energy sold by MRES, MRES may charge the
Municipality the costs incurred for its share of such tax or payment in lieu thereof.
6. LATE PAYMENT CHARGE
A charge of 5 percent may be imposed on the unpaid balance of any amount due and owing after the date when
such amount is due.
7. BILLING MEASUREMENT
For the GRE Group, MidAmerican Group, SRG, and Xcel Group, the Monthly Peak Demand in kW shall be the
highest 30-minute integrated demand for Municipality's total electric requirements measured during the billing
period. When electricity is measured at more than one POD, the total demand shall be the sum of the maximum
recorded integrated demand at each Point of Measurement during the same 30-minute interval.
For the L&O Group, the Billing Demand for each month shall be:
(a) for the portion of the L&O Group rate described in subsection (i) of Section 3(b) above, the average
monthly peak of the demand purchases by Municipality from MRES for the preceding calendar year,
calculated by taking the total demand purchases of Municipality for the preceding year (in kW) and
dividing this sum by 12 months; and
(b) for the portion of the L&O Group rate described in subsection (ii) of Section 3(b) above, the average
monthly peak of the demand purchases by Municipality from MRES and Western Area Power
Administration (WAPA) for the preceding calendar year, calculated by taking the total demand purchases
of Municipality for the preceding year (in kW) and dividing this sum by 12 months.
For the NCG, the Monthly Billing Demand for each month sliall be the greater of the highest 30-minute integrated
demand for the Municipality's total electric requirements measured during the billing period or 90 percent of the
Municipality's Monthly Peak Demand during the preceding 11 months. When electricity is measured at more
than one POD, the total demand shall be the sum of the maximum recorded integrated demand at each Point of
Measurement during the same 30-minute interval.
For the UMZ Group, the Billing Demand for each month shall be the average monthly peak of the demand
purchases by Municipality from MRES for the preceding calendar year, calculated by taking the total demand
purchases of Municipality for the preceding year (in kW) and dividing this sum by 12 months.
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 2B
8. BILLING PERIOD
The MRES billing period shall be established to coincide with the meter reading schedules of WAPA for all
services provided pursuant to the S - 1 Agreement, and shall be established by MRES, Municipality, and third party
transmission provider, if necessary, for the Other Power Sale Agreements.
Effective: The first day of the January 2026 billing period
Approved September 11, 2025: Board of Directors
Missouri Basin Municipal Power Agency
d/b/a Missouri River Energy Services
Issued by: Matthew E. Schull, President and Chief Executive Officer
Missouri Basin Municipal Power Agency
d/b/a Missouri River Energy Services
S-9 Agreement, Schedule C, effective January 9, 2026 1 Page 3B
Munici �alities taldn � service under Schedule C are:
Upper Missouri Zone Group:
Alton, Iowa
Denison, Iowa
Hartley, Iowa
Hawarden, Iowa
Kimballton, Iowa
Manilla, Iowa
Orange City, Iowa
Paullina, Iowa
Primghar, Iowa
Remsen, Iowa
Sanborn, Iowa
Shelby, Iowa
Sioux Center, Iowa
Woodbine, Iowa
Madison, Minnesota
Moorhead, Minnesota
Cavalier, North Dakota
Lakota, North Dakota
Northwood, North Dakota
Riverdale, North Dakota
Valley City, North Dakota
Beresford, South Dakota
Brookings, South Dakota
Burke, South Dakota
Faith, South Dakota
Fort Pierre, South Dakota
Flandreau, South Dakota
Pickstown, South Dakota
Pierre, South Dakota
Vermillion, South Dakota
Watertown, South Dakota
Winner, South Dakota
L&O Group:
Lake Park, Iowa
Rock Rapids, Iowa
Luverne, Minnesota
Northern Cities Group:
Alexandria, Minnesota
Barnesville, Minnesota
Benson, Minnesota
Breckenridge, Minnesota
Detroit Lakes, Minnesota
Elbow Lake, Minnesota
Henning, Minnesota
Lake Park, Minnesota
Ortonville, Minnesota
Staples, Minnesota
Wadena, Minnesota
Big Stone City, South Dakota
Split Rock Group:
Adrian, Minnesota
Jackson, Minnesota
Lakefield, Minnesota
Westbrook, Minnesota
Worthington, Minnesota
Xcel Group:
Marshall, Minnesota
Melrose, Minnesota
Saint James, Minnesota
Sauk Centre, Minnesota
Hillsboro, North Dakota
MidAmerican Group:
Atlantic, Iowa
Pella, Iowa
GRE Group:
Willmar, Minnesota
S-1 Agreement, Schedule C, effective January 1, 2026 1 Page 4C
HUC POWER SALE AGREEMENT
This Power Sale Agreement ("Agreement") is entered into on _ m 3 2010, by and
between Missouri Basin Municipal Power Agency, a body corpora nd politic organized
under Chapter 28E of the Code of Iowa, doing business as Missouri River Energy Services
("MRES"), the Hutchinson Utilities Commission, a municipal corporation and political
subdivision of the State of Minnesota ("HUC"), and Western Minnesota Municipal Power
Agency, a municipal corporation and political subdivision of the State of Minnesota
("Western Minnesota"). MRES, HUC and Western Minnesota are individually referred to
as "Party" and collectively as "Parties."
Article 1. ESSENTIAL TERMS OF THE TRANSACTION
1.1 Seller: The Seller is MRES.
1.2 Buyer: The Buyer is HUC.
1.3 Contract Term: The Contract Term is from hour beginning 00:01, September 1,
2010 through hour ending 24:00 January 1, 2046. Upon expiration of the Contract
Term, the Agreement shall remain in effect as permitted by law unless and until
terminated by a Party upon not less than one year's written notice.
1.4 Commodity: The Commodity is must -take energy of the Contract Quantity specified
below. MRES will provide HUC the same ancillary services associated with the
Contract Quantity that it provides to members ("Members") under the Power Sale
Agreement (S-1) ("S-1 Agreement") for delivery of power and energy to the Western
Area Power Administration Integrated System outlet.
1.5 Contract Quantity: The Contract Quantity is 15 megawatts (MW) on a 100% load
factor basis (15 megawatt -hours (MWh) per hour) from hour beginning 00:01 on
September 1, 2010 through hour ending 24:00 on December 31, 2012 ("Period I")
and increasing on hour beginning 00:01 on January 1, 2013 to 25 MW on a 100%
load factor basis (25 MWh per hour) continuing through the end of the Contract
Term ("Period II"). The Contract Quantity includes both demand and energy
components.
1.6 Financial Firmness: MRES will provide the Contract Quantity from electric energy
available in the Midwest Independent Transmission System Operator ("MISO")
energy market or from any of its generation resources.
1.7 Delivery Point: The Delivery Point shall be GRE.HUC, a node for delivery of energy
by MISO that is designated under the MISO Transmission, Energy and Operating
Reserve Markets Tariff ("TEMT"), as currently in effect and as may be modified
during the term of this Agreement, or any successor point of delivery if the MISO
node concept ceases to exist during the Contract Term.
1
1.8 Energy Scheduling: All schedules for energy under this Agreement shall be
governed by the TEMT. All schedules shall be made in the MISO energy market. A
financial bilateral transaction will be submitted by MRES in the MISO Financial
Scheduling System ("fmSched"). HUC will approve the finSched. HUC will
continue its energy scheduling in the ordinary course.
1.9 Planning Resource Credits (PRC): MRES will each month make available to HUC
Planning Resource Credits ("PRCs") (as defined in the TEMT) to meet HUC's
Resource Adequacy Requirements ("RAR") in MISO to cover the Contract Quantity.
MRES will also provide such additional PRC amounts as are required to cover losses
and MISO Resource Planning Reserve Margin on the Contract Quantity as required
to meet the RAR. HUC will apply the PRCs provided to meet the foregoing
purposes. The PRCs shall either be locally deliverable or aggregately deliverable.
The cost of the PRCs is included in the Charges.
1.10 Transmission: HUC will be responsible for all costs and making all arrangements
required to deliver energy from the Delivery Point to its distribution system. During
the Contract Term, HUC will pay the same Supplemental Power Delivery charge as
other MRES Members under the S-1 Agreement.
1.10.1 HUC currently acquires and pays for transmission service for energy
deliveries to the GRE.HUC node over the MISO system via a MISO transmission
tariff. If the transmission tariff arrangements allowing HUC to receive energy via
the MISO energy market cease to exist without a substitute with substantially
similar or comparable terms and conditions for both the purchase and delivery of
electric energy, MRES, Western Minnesota and HUC will develop and agree upon
alternative arrangements for the delivery from sources determined by MRES to the
Delivery Point of the Contract Quantity at no additional transmission service expense
to MRES or Western Minnesota.
1.11 Renewable Energy Credits (REC): Each year, MRES will provide HUC with the
same proportion of RECs to energy delivered as MRES provides to its Members
located in Minnesota who are served under the S-1 Agreement in order to satisfy
applicable state and/or federal renewable energy standards. The cost of RECs is
included in the Charges -with no additional cost to HUC. As an example, in 2010, if
MRES retired RECs to meet renewable energy standards equivalent to seven percent
of Minnesota S-1 Members' energy purchases from MRES, HUC will receive RECs
equal to seven percent of HUC's energy purchases from MRES under this
Agreement.
1.12 The charges for the Commodity ("Charges") shall be as follows:
2
1.12.1 For calendar year 2010, the Charges for the Commodity shall be comprised
of the following monthly charges:
a. Demand charge: $12.45/kW-month
b. Supplemental Power Delivery charge: $ 2.85/kW-month
C. Energy charge: $.0265 per kWh
d. Rate Adder: $.003 per kWh
e. Supplemental Power Cost Adjustment $/kWh which is defined
in the 2010 S-1 Agreement Schedule C.
1.12.2 Subsequent to 2010, the Charges for the Commodity shall be the applicable
rates in Schedule C to the S-1 Agreement that are in effect from time to time or that
are in any successor rate schedule to Schedule C plus the Rate Adder as defined
below. The Charges for the Commodity shall be adjusted each time that the rates in
Schedule C are adjusted. MRES shall, in the fall of 2010, provide to HUC a copy of
the Schedule C that will be effective January 1, 2011, and MRES shall provide
updated versions of Schedule C to HUC as soon as practicable after each rate
adjustment.
The Charges for the Commodity for each calendar year from 2011 through the
end of the Contract Term, including any adjustments during a calendar year,
shall be the following components of the charges included on Schedule C to the
S-1 Agreement for each applicable calendar year plus the Rate Adder, to wit:
a. Demand charge: $/kW -month charge which is the S-1 Agreement Schedule
C Supplemental Power Demand charge, whether on an annual or seasonal
basis.
b. Supplemental Power Delivery charge: $/kW -month charge which is the S-
1 Agreement Schedule C Supplemental Power Delivery charge as adjusted
for the IS factor, as defined in the S-1 Agreement Schedule C.
c. Energy charge: $/kWh charge which is the S-1 Agreement Schedule C
energy charge.
d. Supplemental Power Cost Adjustment: $/kWh charge which is the S-1
Agreement Schedule C Supplemental Power Cost Adjustment charge.
e. Rate Adder: The rate adder ("Rate Adder") is $.003 per kWh for all energy
delivered through 8/31/2020. The Rate Adder shall automatically expire on
8/31 /2020.
1.12.3 The energy charge encompasses the energy portion of the locational
marginal price ("LMP") at the GRE.HUC node but does not include the congestion
and loss components of the LMP.
1.12.4 To the extent that Schedule C to the S-1 Agreement is restructured so that
the rate elements in the Schedule C effective on January 1, 2011 cease to exist or are
changed, the Parties will discuss whether and how to revise the Charges under this
Agreement to accord with the restructuring of Schedule C so that, except for the Rate
Adder, HUC is treated comparably under this Agreement to MRES Members under
the S-1 Agreement.
3
1.12.5 MRES will calculate the MISO charges for regulation, spinning and
supplemental services associated with the Contract Quantity under this Agreement
and provide a credit to HUC on the monthly bill.
1.13 MISO Charges: MRES shall pay to MISO the MISO congestion and losses on the
Contract Quantity and in exchange HUC shall pay the MISO MIA rate and losses as
defined below. The MIA rate and losses shall be the same as the charges that all
MRES Members serviced under the S-1 Agreement in the MISO footprint are
assessed according to the MISO Market Implementation Agreement ("MIA"):
1.13.1 For calendar year 2010, HUC shall pay MRES a rate to recover congestion
costs associated with the Contract Quantity at the Delivery Point. The rate for 2010
is identified in Exhibit A.
1.13.2 For calendar year 2010, HUC Contract Quantity shall be adjusted according
to the MISO Market Loss percentage as defined in Exhibit A. The loss rate for 2010
is identified in Exhibit A. HUC shall pay MRES for such losses according to the
Charges for the Commodity identified above in this Agreement.
1.13.3 For each calendar year from 2011 through the end of the Contract Term,
HUC rate and losses shall be the same as the MIA rate and losses. The MIA rate and
losses are subject to change from time to time as determined by the Board of
Directors of MRES and any changes to the MIA Exhibit B ("Rate for Market Service
Charge Types") and MIA Exhibit C ("Loss Percentages") will be provided to HUC
as soon as practicable after each rate adjustment.
Article 2. GENERAL TERMS AND CONDITIONS
2.1 Additional Rate Provisions:
2.1.1 Payments made under this Agreement shall be made as an operating
expense from the revenues of the HUC electric utility system and from other funds
thereof legally available therefore and shall be in addition to and not in substitution
for any other payments whether on account of dues or otherwise owed by HUC to
MRES. The obligation of HUC to make such payments for electric power and
energy and furnished pursuant to this Agreement shall not be subject to any rights of
setoff, recoupment or counterclaim which HUC shall otherwise have against MRES;
provided, however, that nothing contained herein shall be construed to prevent or
restrict HUC from asserting any rights which it may have against MRES under this
Agreement or under any provision of law, including the institution of legal
proceedings for specific performance or recovery of damages.
2.1.2 As soon as practicable after any revision of any of the charges or rates in
Article 1, MRES shall cause written notice to be provided to HUC with the effective
date thereof not less than thirty days after the date of the notice.
4
2.2 HUC Covenants:
2.2.1 HUC agrees to maintain rates for electric power and energy to its
consumers which shall provide to HUC revenues sufficient to meet its obligations to
MRES under this Agreement and to pay all other obligations payable from, or
constituting a charge or lien on, such revenues.
2.2.2 HUC shall not contract to sell at wholesale any of the electric power and
energy delivered to it hereunder to any of its customers for resale by those
customers, unless such resale is specifically approved in writing by MRES and
Western Minnesota which approval shall not unreasonably be withheld; provided,
however, that if HUC's native load is less than the Contract Quantity, then HUC may
sell that difference between its native load and the Contract Quantity into the MISO
real-time or day -ahead market or their equivalent.
2.2.3 HUC shall not take any action to transfer either its distribution facilities or
control over its electric distribution functions or take any other action having the
same effect without (a) notifying MRES at least 90 days before formally committing
to the action, and (b) taking such action strictly in conformance with the provisions
of the Assignments section below.
2.2.4 HUC shall remain a Market Participant member, or its equivalent, of MISO
throughout the duration of this Agreement.
2.3 Billing and Payment:
2.3.1 MRES shall bill HUC by the fifth working day of each month for electric
power and energy, and MISO Charges furnished hereunder. Such bill shall be paid
for at the office of MRES in Sioux Falls, South Dakota, or at such other location that
MRES may designate, monthly, within fifteen days after the postmark of the bill,
such bill to be provided to HUC monthly on a prompt and timely basis. If said
fifteenth day is a Sunday or a legal holiday in the state in which HUC is located, the
next following business day shall be the last day on which payment may be made
without the addition of the delayed payment charge. A delayed payment charge of
five percent may be imposed on the unpaid balance of any amount due and owing
after the date when such amount is due. All payments shall be made by Automated
Clearing House (ACH) as initiated by MRES. MRES may, whenever any amount
due remains unpaid after the due date and after giving 15 days advance notice in
writing of its intention to do so, discontinue service hereunder or take all steps
available to it under applicable law to collect such amount and all subsequent
payments which shall have become due or both. MRES may, whenever any amount
due remains unpaid for 120 or more days after the due date and after giving 30 days'
advance notice in writing of its intention to do so, terminate this Agreement. No
such discontinuance or termination shall relieve HUC from liability for payment for
the commodity or services furnished.
2.3.2 Upon request from HUC, MRES shall provide reasonable back-up
information to support the monthly bill. In the event HUC desires to dispute all or
any part of a bill, it shall nevertheless pay the full amount of the bill when due and,
within 60 days from the date of the bill, notify MRES in writing of the grounds on
which any charges in the bill are disputed and the amount in dispute. HUC will not
10
be entitled to any adjustment on account of any disputed charges which are not
brought to the attention of MRES within the time and in the manner herein specified.
2.4 Uncontrollable Forces: Neither MRES nor HUC shall be considered to be in default
in respect to any obligation (other than the obligation of HUC to pay for Contract
Quantity) if prevented from fulfilling such obligations by reason of uncontrollable
forces, the term uncontrollable forces being deemed for the purposes of this
Agreement to mean any cause beyond the control of the Party affected, including but
not limited to, failure of facilities, flood, earthquake, storm, lightning, fire, epidemic,
pestilence, war, riot, civil disturbance, labor disturbance sabotage, and restraint by
court or public authority, which by due diligence and foresight such Party could not
reasonably have been expected to avoid. Either Party rendered unable to fulfill any
obligation by reason of uncontrollable forces shall exercise due diligence to remove
such inability with all reasonable dispatch
2.5 Assignments: All covenants and agreements contained in this Agreement shall
inure to the benefit of the Parties and their respective successors and assigns;
provided, however, that, except as provided below, no Party may transfer or assign
its interests or rights under this Agreement except that:
2.5.1 A Party may transfer or assign its interests or rights or the assignment of the
security interest therein to any trustee or secured party, as security for bonds or other
indebtedness, present or future, and such trustee or secured party may, if so
empowered, sell or otherwise realize upon such security in foreclosure or other
suitable proceedings, possess or take control thereof or cause a receiver to be
appointed with respect thereto and otherwise succeed to all interests and rights of the
Party making the assignment; and
2.5.2 In the case of a proposed transfer either to any entity acquiring all or
substantially all of the property of the Party making the transfer, or to any entity into
which or with which the Party making the transfer may be merged or consolidated,
the Party proposing the transfer shall give all other Parties written notice at least
ninety (90) days prior to the date such transfer or assignment is scheduled to occur
and must obtain the prior written consent of the other Parties hereto, which consent
shall not be unreasonably withheld, it being understood that it would be reasonable
for a Party to withhold such consent if such transfer or assignment would (a) reduce
the total amount of electric power or energy being sold hereunder; (b) be to a party
with senior debt, if any, not rated in one of three highest whole rating categories by
at least one nationally recognized bond rating agency; (c) adversely affect the value
of this Agreement as security for the payment of bonds and interest thereon; or (d)
affect (either alone or in conjunction with any other actions by any other
municipality to which MRES sells power and energy under a long term arrangement
such as the S-1 Agreement) the eligibility of interest on bonds of MRES or Western
Minnesota (whether then outstanding or thereafter to be issued) for Federal tax-
exempt status. In making the determination required by clause (d) above, MRES and
Western Minnesota may rely upon an opinion of a nationally recognized bond
counsel as to the effect of any such transfer or assignment on the Federal tax-exempt
status of any bonds (whether then outstanding or thereafter to be issued), as that
0
status is governed by the Federal income tax laws, as amended from time to time,
including but not limited to, Section 141 of the Internal Revenue Code of 1986, as
amended, and the Treasury Regulations or any rulings promulgated there under or as
affected by a decision of any court of competent jurisdiction (collectively, the "Tax
Laws"). Within sixty (60) days after receipt of a notice from HUC requesting a
transfer or assignment, MRES and Western Minnesota shall advise HUC as to
whether, in the opinion of a nationally recognized bond counsel, the transfer or
assignment would affect the eligibility of interest on bonds for Federal tax-exempt
status as described in clause (d) above. In the event that allocations (including, but
not limited to allocations relating to private use issues) are necessary under the Tax
Laws to determine whether entering into any such transfer or assignment affects the
eligibility of interest on bonds for Federal tax-exempt status as described in clause
(d) above, MRES and Western Minnesota shall make such allocations, in their sole
discretion, after receipt of an opinion of a nationally recognized bond counsel.
2.5.3 Notwithstanding anything in this Section to the contrary, HUC may transfer
or assign this Agreement if it affects the eligibility of interest on bonds for Federal
tax-exempt status as described in clause (d) if, but only if, the transferee enters into
an agreement in form and substance satisfactory to MRES and Western Minnesota
providing that the transferee will bear and pay any and all increased costs allocated
to it resulting from the use by MRES or Western Minnesota of borrowed or other
funds that are not derived from the proceeds of tax-exempt debt ("Non -Tax Exempt
Funds"). MRES and Western Minnesota, in their sole discretion, after receipt of an
opinion of a nationally recognized bond counsel, shall allocate on a reasonable basis
the increased costs associated with the use of such Non -Tax Exempt Funds to any
such transferee and shall determine the terms and conditions upon which the
transferee shall pay such increased costs. Any such agreement shall contain such
other terms and provisions as MRES and Western Minnesota reasonably deem
necessary in order to preserve the Federal tax-exempt status of any borrowed funds
not intended by MRES or Western Minnesota to be issued as debt which is not
excludable from gross income for Federal income tax purposes.
2.5.4 In connection with any such proposed transfer or assignment under this
Section, various opinions are required to be delivered by a nationally recognized
bond counsel. Such counsel or counsels shall be chosen by MRES and Western
Minnesota and the cost of such counsel or counsels shall be borne by the Parry
requesting the transfer or assignment. Any of the opinions required under this
Section may be delivered in one or more opinions.
2.5.5 No assignment or transfer of this Agreement shall relieve the Parties of any
obligation hereunder, unless specifically agreed to in writing by the Parties.
2.6 Amendment: Except as provided for expressly herein, neither this Agreement nor
any terms hereof may be terminated, amended, supplemented, waived or modified
except by an instrument in writing executed by all Parties.
2.7 Representations and Warranties: Each Party represents and warrants, as of the date
of this Agreement, the following:
2.7.1 It is, as applicable, an agency, municipal corporation and political
subdivision, duly organized validly existing and in good standing under the laws of
7
the State of its formation and authorized to conduct business in its state of
organization and the States in which it does business;
2.7.2 It has the power and authority to enter into, execute and perform this
Agreement;
2.7.3 There are no bankruptcy, insolvency, reorganization, or receiverships
pending or being contemplated by it or, to its knowledge, threatened against it; and
2.7.4 To its knowledge, there are no actions, proceedings, judgments, or rulings,
issued by or pending before any court or other governmental body, with applicable
jurisdiction, that would materially adversely affect its ability to perform its
obligations under this Agreement.
2.8 Opinion: Upon the execution and delivery of this Agreement, HUC shall furnish
MRES with an opinion by an attorney or firm of attorneys qualified to practice in the
State of Minnesota to the effect that:
2.8.1 HUC is a municipal corporation duly created and validly existing pursuant
to the Constitution and statutes of the State of Minnesota;
2.8.2 HUC has full legal right and authority to enter into this Agreement and to
carry out its obligations hereunder; and
2.8.3 HUC has approved this Agreement and its execution and delivery, and this
Agreement has been duly executed by the appropriate officer of HUC and constitutes
the legal, valid, and binding obligation of HUC enforceable in accordance with its
terms.
2.9 Notices: Any notice, demand or request required or authorized by this Agreement
shall be deemed properly given if mailed, postage prepaid, to MRES at its principal
place of business at P.O. Box 88920, Sioux Falls, SD 57109-8920, to HUC at 225
Michigan Street, SE, Hutchinson, Minnesota 55350-1940 and to Western Minnesota
at 25 NW 2nd Street, Suite 102, Ortonville, Minnesota 56278-0357. The foregoing
addresses may be changed at any time by similar notice.
2.10 Waivers: Any waiver at any time by any Party hereto of its rights with respect to a
default or any other matter arising in connection with this Agreement shall not be
deemed to be a waiver with respect to any subsequent default or matter.
2.11 Severability: In the event that any of the terms, covenants or conditions of this
Agreement, or the application of any such term, covenant or condition, shall be held
invalid as to any person or circumstance by any court having jurisdiction under the
circumstances, the remainder of this Agreement, and the application of its terms,
covenants or conditions to such persons or circumstances shall not be affected
thereby.
2.12 Dispute Resolution:
2.12.1 The Parties shall attempt in good faith to resolve any dispute arising out of
or relating to this Agreement through negotiation between representatives who have
authority to resolve the matter.
2.12.2 Any Party may give written notice to the other Parties of any dispute not
resolved in the normal course of business. Within fourteen (14) days following
8
delivery of the notice (or a date mutually agreed by the Parties), representatives of
each Parry with settlement authority shall meet in person at a mutually acceptable
time and place and confer in good faith to resolve the dispute, and thereafter as often
as they reasonably deem necessary to attempt to resolve the dispute. All reasonable
requests for information made by a Party to another Party will be honored.
2.12.3 If a dispute has not been resolved within thirty (30) days of the original
dispute notice, then the Parties shall submit their dispute to mediation. If the dispute
is not resolved by mediation within 60 days after the submission to mediation, the
Parties may invoke their legal remedies available at law. The mediation may be
continued beyond the original 60 days by agreement of the Parties.
2.13 Governing law: This Agreement shall be governed by the laws of the state of
Minnesota.
The Parties have caused this Agreement to be executed as of the day, month and
year first written above.
MISSOURI BASIN MUNICIPAL POWER AGENCY
d/b/a MISSOURI RIVER ENERGY SERVICES
B . Date:
� '12 r�>
Y
Harold Schiebout
Chairman of the Board
HUTCHINSON UTILITIES COMMISSION
By:_
Name:
Title: 1�ti£ 5i
Date:
WESTERN MINNESOTA MUNICIPAL POWER AGENCY
By:m �........._C� cal _ Date:
Curt Punt
President
M
HUC POWER SALE AGREEMENT
EXHIBIT A
HUC 2010 MISO CHARGES: CONGESTION AND LOSSES
Section I. DEFINITIONS
1.1 "MIA" shall mean the MISO Market Implementation Agreement.
1.2 "Power Sale Agreement" shall mean the HUC Power Sale Agreement (PSA) entered
into among MRES, HUC and WMMPA.
Section 2. SERVICES PROVIDED BY MRES
In exchange for MRES paying for the MISO Market congestion and losses on the Contract
Quantity at the GRE.HUC Node, MRES shall bill HUC for Congestion -Charges and MISO
Market Losses under the PSA according to the following method:
2.1 Congestion Charges: HUC shall pay MRES for congestion costs on the MRES energy
portion of the Contract Quantity. The 2010 Congestion Charge is $0.0001 per kWh.
In future years, this rate shall be equivalent to the rate for MISO market services as
paid by any MRES Member under an S-1 Agreement that has executed an MIA and is
located in the MISO footprint.
2.2 MISO Market Losses: HUC shall pay MRES for MISO Market Losses on MRES
Contract Quantity by multiplying the MISO Market Loss percentage times the
appropriate demand and energy quantities. For calendar year 2010, the MISO Market
Losses are 3.3%. The MISO Market Loss percent in subsequent years will be that
charged pursuant to the MIA and will be the same percentage as paid by any MRES
Member under an S-1 Agreement that has executed an MIA and is located in the
MISO footprint.
Section 3. BILLING AND PAYMENT
The MISO Charges for HUC are subject to the terms and conditions specified in the PSA.
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Hutchinson Utilities Commission
Electric
Rate Design
UFS
9/14/2026
UTILITY FINANCIAL
SOLUTIONS, LLC
Corporate location:
Utility Financial SOILItions, LLC
185 Sian Meadow Court
Holland, MI USA 49424
(616) 393-9722
Fax (888) 566-4430
Hutchinson Utilities Commission
Table of Contents
Page
Rate Design Summary
Projected Residential Rates 4
Projected Small General Service Rates 5
Projected Street Lighting Rates 6
Projected Security Lighting Rates 7
Projected Large General Service Rates 8
Projected Large Industrial Rates 9
'J A
ti N C1LU'I'IS'aM:��. L(C.
Rate Design for 2027 & 2028
Rate Design Summary
Projected
Projected
Projected
Projected
Projected
Revenues Under
Revenues Under
Percentage
Percentage
Revenues Under
Proposed Rates
Proposed Rates
Change
Change
Customer Class
Current Rates
2027
2028
2027
2028
COS
Residential
$ 7,092,942
$ 7,527,707
$ 7,915,324
6.1%
5.1%
18.0%
Small General Service
2,145,586
2,270,030
2,378,992
5.8%
4.8%
13.3%
Street Lighting
119,191
126,343
132,660
6.0%
5.0%
15.4%
Security Lighting
10,229
10,894
11,493
6.5%
5.5%
17.9%
Large General Service
9,285,410
9,828,283
10,301,357
5.8%
4.8%
14.2%
Large Industrial
8,527,022
9,046,740
9,509,401
6.1%
5.1%
18.8%
Totals
$ 27,180,381
$ 28,809,997
$ 30,249,228
6.00%
5.00%
16.6%
3 !us�S
Electric Rate Design
Rates
Current
Year 1
Year 2
Monthly Facilities Charge:
All Customers
$
17.20
17.30
17.40
Energy Charge:
All Energy
$
0.09040
$
0.09773
$ 0.10425
Power Cost Adjustment:
All Energy
$
0.00752
$
0.00752
$ 0.00752
Revenue from Rate $
7,092,942
$
7,527,707
$ 7,915,324
Change from Previous
6.1%
5.1%
Change by Monthly kWh Usage (%)
10.0%
9.0%
8.0%
v 7.0%
ao
c
fa 6.0%
t IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
v
5.0% IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII IIIIIInnIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIIIInnIIIIIIIIIInnIIIIIIIIIInnIIIIIIIIIInnIIIIIIIIIInnIIIIIIIIIInn
m 4.0%
IIIIIIIIIIInnIInnllnnlllllllllllllnnllnnllnnlllllllllllllnnllnnllnnlllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllll
Y
v 3.0%
V
v 2.0%
d
1.0% Year 1 IIIIIIIIIIIIIIIIIII Year 2
0.0%
300 400 500 600 700 800 900 1000 1100
Energy (kWh)
Monthlv $ Change by Energy Usage
All Energy
Year 1
Year 2
300
$
2.30
$
2.06
400
$
3.03
$
2.71
500
$
3.77
$
3.36
600
$
4.50
$
4.01
700
$
5.23
$
4.66
800
$
5.96
$
5.32
900
$
6.70
$
5.97
1000
$
7.43
$
6.62
1100
$
8.16
$
7.27
Electric Rate Design 4 of 9
UIILOIY f"NAh AL
ti O[U'llo"S L(C.
Hutchinson Utilities Commission
Electric Rate Design
Small General Service
Rates
Current
Year 1
Year 2
Monthly Facilities Charge:
All Customers
$
28.50
28.50
28.50
Energy Charge:
Block 1 (0 - 2,000 kWh)
$
0.09780
$
0.10497
$ 0.11124
Block 2 (Excess)
$
0.08784
$
0.09428
$ 0.09991
Power Cost Adjustment:
All Energy
$
0.00752
$
0.00752
$ 0.00752
Revenue from Rate $
2,145,586
$
2,270,030
$ 2,378,992
Change from Previous
5.8%
4.8%
Change by Monthly kWh Usage (%)
10.0%
9.0%
8.0%
ao 7.0%
c
fa 6.0 ° °
IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
t �
v
5.0°° III
� IIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
00 4.0% IInnIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIInnIIIIIIIIIIIIIIIIIIInnIIIInnIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIInnIIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIInnI
Y
v 3.0%
V
v 2.0%
1.0% Year 1 Year 2
0.0%
700 950 1200 1450 1700 1950 2200 2450 2700
Energy (kWh)
Monthly $ Change by Energy Usage
Energy
Year 1
Year 2
700 $
5.02
$
4.39
950 $
6.81
$
5.96
1200 $
8.60
$
7.53
1450 $
10.39
$
9.10
1700 $
12.18
$
10.67
1950 $
13.98
$
12.24
2200 $
15.62
$
13.68
2450 $
17.23
$
15.09
2700 $
18.84
$
16.50
Electric Rate Design 5 of 9 us�Is
LOIV f"YNAN AL
tiUIIO[U'I'ICaMS L(C.
Hutchinson Utilities Commission
Electric Rate Design
Street Lights
Rates Current Year 1 Year 2
Monthly Facilities Charge:
StrL 100 Rate
StrL 150 Rate
StrL 175 Rate
StrL 200 Rate
StrL 250 Rate
StrL 400 Rate
New LED 70W Rate
Energy Charge:
All Energy
Power Cost Adjustment:
All Energy
Revenue from Rate $
Change from Previous
3.99
6.18 $
6.67 $
8.83 $
8.17 $
11.33 $
4.81 $
119,191 $
4.23 $
6.56 $
7.07 $
9.36 $
8.66 $
12.01 $
5.09 $
126,343 $
6.0%
132,660
5.0%
Electric Rate Design 6 of 9 pJo3
501.UiICMS., I..I.C'
Hutchinson Utilities Commission
Electric Rate Design
Security Lights
Rates
Current
Year 1
Year 2
Monthly Facilities Charge:
SecL 70 LED Rate
$ 3.42
3.64
3.84
SecL 250 Rate
$ - $
$
SecL 400 Rate
$ - $
$
SecL 70 LED Unmetered Rate Rate
$ 7.99 $
8.51
$ 8.98
SecL 250 Unmetered Rate Rate
$ - $
$
SecL 400 Unmetered Rate Rate
$ - $
$
Revenue from Rate
$ 10,229 $
10,894
$ 11,493
Change from Previous
6.5%
5.5%
Electric Rate Design 7 of 9 pJo3
501.UiICMS., I..I.C'
Hutchinson Utilities Commission
Electric Rate Design
Large General Service
Rates Current Year 1 Year 2
Monthly Facilities Charge:
All Customers
$ 152.30
152.30
152.30
Energy Charge:
All Energy
$ 0.05832
$
0.06276
$ 0.06645
Demand Charge
All Demand (w/ 75% ratchet)
$ 11.50
$
12.00
$ 12.50
Power Cost Adjustment:
All Energy
$ 0.00752
$
0.00752
$ 0.00752
Revenue from Rate
$ 9,285,410
$
9,828,283
$ 10,301,357
Change from Previous
5.8%
4.8%
Change by Percent Load Factor with average load 185kW (%)
10.0%
9.0%
8.0%
v 7.0%
ao
c
fa
6.0 o IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
t /IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
v
5.0% / IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII - IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInnIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInn IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInn IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIInn
00 4.0%
Y
a) 3.0%
a 2.0%
1.0% Year 1 IIIIIIIIIIIIIIIIIII Year 2
0.0%
30% 35% 40% 45% 50% 55% 60% 65% 70%
Load Factor (%)
Monthly $ Change by Customer Load Factor
Load Factor
Year 1
Year 2
30%
$
265.58
$
236.33
35%
$
294.80
$
260.67
40%
$
324.03
$
285.02
45%
$
353.25
$
309.37
50%
$
382.47
$
333.71
55%
$
411.69
$
358.06
60%
$
440.91
$
382.40
65%
$
470.13
$
406.75
70%
$
499.35
$
431.09
Electric Rate Design 8 of 9 us�Is
LOIY f"YNAN AL
tiUIIO[U'I'ICaMS L(C.
Hutchinson Utilities Commission
Electric Rate Design
Large Industrial
Rates Current Year 1 Year 2
Monthly Facilities Charge:
All Customers
$
432.50
475.00
525.00
Energy Charge:
All Energy
$
0.05445
$
0.05925
$ 0.06347
Demand Charge
All Demand
$
12.50
$
12.75
$ 13.00
Power Cost Adjustment:
All Energy
$
0.00752
$
0.00752
$ 0.00752
Revenue from Rate $
8,527,022
$
9,046,740
$ 9,509,401
Change from Previous
6.1%
5.1%
Change by Percent Load Factor with average load 185kW(%)
10.0%
78- 8.0%
v
bJO
L 6,0% II
— IIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII�IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII�
00 4.0%
Y
V
v 2.0%
d
Year 1 IIIIIIIIIIIIIIIIIII Year 2
0.0 %
50% 55% 60% 65% 70% 75% 80% 85% 90%
Load Factor (%)
Monthly $ Change by Customer Load Factor
Load Factor
Year 1
Year 2
50% $
16,413.02
$
14,674.51
55% $
17,845.65
$
15,932.53
60% $
19,278.27
$
17,190.56
65% $
20,710.90
$
18,448.58
70% $
22,143.52
$
19,706.60
75% $
23,576.15
$
20,964.63
80% $
25,008.77
$
22,222.65
85% $
26,441.40
$
23,480.68
90% $
27,874.02
$
24,738.70
Electric Rate Design 9 of 9 us�Is
LOIV f"YNAN AL
tiUIIO[U'I'ICaMS L(C.
Hutchinson Utilities Commission
Gas Cost of Service for CY2027
Rate Design for 2027
FJFS
9/21/2026
UTILITY FINANCIAL
SOLUTIONS, LLC
Corporate location:
Utility Financial SOILItions, LLC
185 Sian Meadow Court
Holland, MI USA 49424
(616) 393-9722
Fax (888) 566-4430
Hutchinson Utilities Commission
Rate Design
Rate Design Summary
Projected Residential (60) Rates
Projected Commercial (65) Rates
Projected Large Industrial Rates
Projected Large Industrial 2 Rates
Projected Large Industrial 3 Rates
Page
3
4
5
6
7
8
Rate Design
Hutchinson Utilities Commission
ate Design Summary
Projected
Projected
Projected
Projected
Projected
Revenues Under
Revenues Under
Percentage
Percentage
Revenues Under
Proposed Rates
Proposed Rates
Change
Change
Customer Class
Current Rates
2027
2028
2027
2028
COS
Residential (60)
$ 3,872,500
$ 3,864,491
$ 3,856,694
-0.2%
-0.2%
-3.8%
Commercial (65)
2,757,862
2,749,589
2,740,274
-0.3%
-0.3%
-5.7%
Large Industrial
5,495,340
5,511,826
5,528,362
0.3%
0.3%
-29.6%
Totals $ 12,125,702
$ 12,125,906
$ 12,125,329
0.00%
0.00%
-1.9%
3
Rates
Current
Year 1 Year 2
Monthly Facilities Charge:
All Customers
$
17.90
18.15 18.4
Commodity Charge:
All Gas (MCF)
$
7.1000
7.0425 6.9855
Gas Cost Adjustment:
All Gas (MCF)
$
(0.77252)
$
(0.77252) $ (0.77252)
Revenue from Rate $ 3,872,500 $ 3,864,491 $ 3,856,694
Change tram Previous ®uacia ®uacia
Change by Monthly MCF Usage (%)
3.0%
2.0%
1.0%
0.0%
3 4 5 6 7IIIIIIIIIIIIIIIIIIIIII11
-1.0%
-2.0%
Year 1IIIIIIIIIIIIIIIIIII Year 2
-3.0%
Gas (MCF)
Monthly $ Change by Gas Usage
All Gas (MCF) Year 1 Year 2
2
$
0.14
$ 0.14
3
$
0.08
$ 0.08
4
$
0.02
$ 0.02
5
$
(0.04)
$ (0.04)
6
$
(0.09)
$ (0.09)
7
$
(0.15)
$ (0.15)
8
$
(0.21)
$ (0.21)
9
$
(0.27)
$ (0.26)
10
$
(0.32)
$ (0.32)
11
$
(0.38)
$ (0.38)
Electric Rate Design 4 of 8 us�Is
LOIV NNAN—L
tiUIIO[U'I'ICaMS L(C.
Hutchinson Utilities - Gas
Natural Gas Rate Design
Commercial (65)
Rates
Current
Year 1
Year 2
Monthly Facilities Charge:
All Customers
$
100.70
101.00
101.50
Commodity Charge:
All Gas (MCF)
$
7.1447
7.1127
7.0733
Gas Cost Adjustment:
All Gas (MCF)
$
(0.77252)
$
(0.77252)
$ (0.77252)
Revenue from Rate $
2,757,862
$
2,749,589
$ 2,740,274
Monthly $ Change by Gas Usage
All Gas (MCF) Year 1 Year 2
25
$
(0.50)
$ (0.49)
30
$
(0.66)
$ (0.68)
35
$
(0.82)
$ (0.88)
40
$
(0.98)
$ (1.08)
45
$
(1.14)
$ (1.28)
50
$
(1.30)
$ (1.47)
55
$
(1.46)
$ (1.67)
60
$
(1.62)
$ (1.87)
65
$
(1.78)
$ (2.07)
70
$
(1.94)
$ (2.26)
Electric Rate Design
5of8
'Js�s
U'I'IL9'I'Y NNAN—L
ti O[U'I'ICaMS L(C.
Hutchinson Utilities - Gas
Gas Rate Design
Industrial 1
Rates Current Year 1 Year 2
Monthly Facilities Charge:
Monthly Charge
$
363.00
368.50 374.00
Commodity Charge:
All Gas (MCF)
$
7.54000
7.56363 7.58733
Demand Charge
Peak Day Demand (max daily MCF/mth)
$
8.00
8.00 8.00
Gas Cost Adjustment:
All Gas (MCF)
$
- $
- $ -
Revenue from Rate $ 333,813 $ 334,814 $ 335,819
Change from Previous 0.3% 0.3%
Monthly $ Change by Gas Usage
All Gas (MCF) Year 1 Year 2
2200
$
57.48
$
57.65
2700
$
69.29
$
69.50
3200
$
81.11
$
81.35
3700
$
92.92
$
93.20
4200
$
104.74
$
105.06
4700
$
116.55
$
116.91
5200
$
128.36
$
128.76
5700
$
140.18
$
140.61
6200
$
151.99
$
152.46
Electric Rate Design 6 of 8 L
I U ,1
1k;
o
YF11kANLoJ>„ LA.c L
Hutchinson Utilities - Gas
Gas Rate Design
Industrial 2
Rates Current Year 1 Year 2
Monthly Facilities Charge:
Monthly Charge
$ 536.00
555,00
575,00
Commodity Charge:
All MCF -Summer Gas
$ 2.96380
$
2.96380
$ 2.96380
All MCF -Winter Gas
$ 4.61180
$
4.61180
$ 4.61180
HUC Transportation (MCF)
$ 1.00000
$
1.00701
$ 1.01229
Demand Charge
Peak Day Demand (max daily MCF/mth)
$ 10.33
$
10,40
$ 10,50
Gas Cost Adjustment:
All Gas (MCF)
$ -
$
-
$ -
Revenue from Rate
$ 208,569
$
209,195
$ 209,823
Change from Previous
0,3%
0,3%
Change by Monthly Gas (MCF) Usage (%)
3.0%
2.0%
1.0%
IIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII
0.0% uuuuuumo
1,E 00 2,300 2,800 3,300 3,800 4,300 4,800 5,300 5,800
-1.0%
-2.0%
Year 1 IIIIIIIIIIIIIIIIIII Year 2
-3.0%
Gas (MCF)
Monthly $ Change by Gas Usage
All Gas (MCF)
Year 1
Year 2
1800 $
42.57
$
45.14
2300 $
46.07
$
47.77
2800 $
49.58
$
50.41
3300 $
53.09
$
53.05
3800 $
56.59
$
55.68
4300 $
60.10
$
58.32
4800 $
63.60
$
60.96
5300 $
67.11
$
63.60
5800 $
70.61
$
66.23
Electric Rate Design 7 of 8 �J3
501.UiICMS., I..I.C'
Hutchinson Utilities - Gas
Gas Rate Design
Industrial 3
Rates Current Year 1 Year 2
Monthly Facilities Charge:
Monthly Charge
$ 1,034.00
1,060.00
1,085.00
Commodity Charge:
All MCF -Summer Gas
$ 5.73000
$
5.73000
$ 5.73000
All MCF -Winter Gas
$ 5.89000
$
5.89000
$ 5.89000
HUC Transportation (MCF)
$ 0.47000
$
0.47862
$ 0.48738
Demand Charge
Peak Day Demand (max daily MCF/mth)
$ 9.00
$
9,20
$ 9,40
Gas Cost Adjustment:
All Gas (MCF)
$ -
$
-
$ -
Revenue from Rate
$ 4,952,958
$
4,967,817
$ 4,982,720
Change from Previous
0,3%
0,3%
Change by Monthly Gas (MCF) Usage (%)
3.0%
2.0%
1.0%
IIIIIIIIIIIIIIIIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII,
0.0
7,(00 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000
-1.0%
-2.0%
Year 1 IIIIIIIIIIIIIIIIIII Year 2
-3.0%
Gas (MCF)
Monthly $
Change by Gas Usage
All Gas (MCF)
Year 1
Year 2
7000
$
172.47
$
172.50
8000
$
181.09
$
181.27
9000
$
189.71
$
190.03
10000
$
198.32
$
198.79
11000
$
206.94
$
207.56
12000
$
215.56
$
216.32
13000
$
224.18
$
225.09
14000
$
232.79
$
233.85
15000
$
241.41
$
242.62
Electric Rate Design 8 of 8 �J3
501.UiICMS., I..I.C'
HUTCHINSON UTILITIES COMMISSIONCONSIDERATION
f APR
a
ELECTRIC RATES
Current
Rates
Residential
Monthly Charge
$
17.20
Energy Charge (per Kwh)
$
0.09040
Small General
Monthly Charge
$
28.50
Energy Charge (per Kwh) "Block 1"
$
0.09780
Energy Charge (per Kwh) "Block 2"
$
0.08784
Large General
Monthly Charge
$
152.30
Energy Charge (per Kwh)
$
0.05832
Demand Charge (per KW)
$
11.50
Industrial
Monthly Charge
$
432.50
Energy Charge (per Kwh)
$
0.05445
Demand Charge (per KW)
$
12.50
NATURAL GAS RATES
Current
Rates
Residential
Monthly Charge
$
17.90
Gas Commodity Charge (per MCF)
$
7.1000
Commercial
Monthly Charge
$
100.70
Gas Commodity Charge (per MCF)
$
7.1447
Large Industrial
Monthly Charge
$
363.00
Gas Commodity Charge (per MCF)
$
7.5400
Demand Charge (Max Daily MCF per/month)
$
8.00
Contract Industrial Customers
Customer #1
Monthly Charge
$
536.00
Transportation Charge
$
1.00
Demand Charge (Max Daily MCF per/month)
$
10.33
Customer #2
Monthly Charge
$
1,034.00
Transportation Charge
$
0.4700
Demand Charge (Max Daily MCF per/month)
$
9.00
PROPOSED RATE SCHEDULE
2027
Annual % Inc.
2028
Annual % Inc.
12/1/2026 12/1/2027
$
17.30
$
17.40
6.10%
5.10%
$
0.09773
$
0.10425
$
28.50
$
28.50
5.80%
4.80%
$
0.10497
$
0.11124
$
0.09428
$
0.09991
$
152.30
$
152.30
5.80%
4.80%
$
0.06276
$
0.06645
$
12.00
$
12.50
$
475.00
$
525.00
6.10%
5.10%
$
0.05925
$
0.06347
$
12.75
$
13.00
PROPOSED RATE SCHEDULE
2027
Annual % Inc.
2028
Annual % Inc.
12/1/2026 12/1/2027
$
18.15
$
18.40
-0.20%
-0.20%
$
7.0425
$
6.9855
$
101.00
$
101.50
-0.30%
-0.30%
$
7.1127
$
7.0733
$
368.50
$
374.00
0.30%
0.30%
$
7.56363
$
7.58733
$
8.00
$
8.00
$
555.00
$
575.00
0.30%
0.30%
$
1.00701
$
1.01229
$
10.40
$
10.50
$
1,060.00
$
1,085.00
0.30%
0.30%
$
0.47862
$
0.48738
$
9.20
$
9.40
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