[PAGE 1]
BOARD OF PUBLIC WORKS
DEPARTMENT OF UTILITIES
January 4, 2017
4:15 P.M.
Fremont Municipal Building, 2nd Floor Conference Room,
400 East Military, Fremont Nebraska
__________________________________________________________________________
1. Roll call.
2. Approve minutes of December 21, 2016.
3. Consider Accounts Payable – 1st half of January 2017.
4. * Consider open season bid with Northern Natural Gas for additional Firm Deferred
Delivery Service Storage (staff report).
5. Consider Clawback Provisions and Indemnification Agreement with Costco Wholesale
Corp. (staff report).
6. Investments (staff report).
7. General Manager Update (no board action is requested).
a. Annual report – Keith Kontor
b. Public Power in Nebraska – Newton
8. Adjournment
The agenda was posted at the Municipal Building on December 28, 2016. The agenda and enclosures are distributed
to Board and posted on the City of Fremont’s website. The official current copy of the agenda is available at Municipal
Building, 400 East Military, office of the General Manager. A copy of the Open Meeting Law is posted in the 2nd floor
conference room for review by the public. The Board of Public Works reserves the right to adjust the order of items
on this agenda.
*items referred to City Council (if any)
Page 1

[PAGE 2]
CITY OF FREMONT BOARD OF PUBLIC WORKS
DECEMBER 21, 2016 - 4:15 P.M.
A meeting of the Board of Public Works was held on December 21, 2016 at 4:15 p.m. in the 2nd floor
meeting room at 400 East Military, Fremont, Nebraska. The meeting was preceded by publicized notice
in the Fremont Tribune and the agenda displayed in the Municipal Building. The meeting was open to
the public. A continually current copy of the agenda was available for public inspection at the office of
the General Manger, Department of Utilities, 400 East Military. The agenda was distributed to the
Board of Public Works on December 19, 2016, and posted, along with the supporting documents, on
the City’s website. A copy of the open meeting law is posted continually for public inspection.
ROLL CALL.
Roll call showed Board Members Sawtelle, Shelso, Vering, Behrens and Hoegemeyer present; 5
present, 0 absent. Others in attendance included City Councilman Steve Landholm, City Councilwoman
Susan Jacobus; Troy Schaben, Asst. GM; Jan Rise, Admin. Services Dir.; Jeff Shanahan, LDW Supt.;
Dan Goebel, Accountant; Larry Andreasen, Water Supt.; Al Kasper, Dir. of Engineering; John
Hemschemeyer, Dir. HR; Keith Kontor, WWTP Supt.; Mike Royuk, Electric Superintendent; and Dean
Kavan, Stores Supervisor.
APPROVE MINUTES.
Moved by Member Vering and seconded by Member Behrens to approve the minutes of the
December 7, 2016 meeting. Motion carried 5-0.
CONSIDER ACCOUNTS PAYABLE – 2nd HALF OF DECEMBER 2016.
Moved by Member Shelso and seconded by Member Hoegemeyer to approve the accounts payable in
the amount of $2,411,634.21. Motion carried 5-0.
REVIEW COLLECTION REPORT FOR NOVEMBER 2016.
Chairman Sawtelle noted the board reviewed and received the November 2016 collections report.
CONSIDER PURCHASE OF 2018 FREIGHTLINER/2017 VACTOR 2100 FROM NEBRASKA
ENVIRONMENTAL PRODUCTS.
Moved by Member Behrens and seconded by Member Shelso to approve the purchase of a 2018
Freightliner and 2017 Vactor 2100 jet pump for $453,256 from Nebraska Environmental Products
using the National Joint Powers Alliance (NJPA) contract; and recommend approval by the City
Council. Andreasen reviewed some of the reasons the Vactor jet pump was preferred and the
advantages of using the NJPA. Motion carried 5-0.
CONSIDER EXTENSION OF POWER MARKETING AGENT/METERING/COMMUNICATIONS
AGREEMENT WITH OPPD.
Moved by Member Vering and seconded by Member Hoegemeyer to renew the power marketing
agent/metering/communications agreement with OPPD for another year at the cost of $11,508.15 per
month (a 2% increase over the prior year). Shanahan explained the purpose of the agreement and
why staff recommended renewing the agreement. Motion carried 5-0.
INVESTMENTS.
Goebel reviewed the investments staff had made since the last board meeting. Member Vering moved
to accept and receive the report, seconded by Member Behrens. Motion carried 5-0.
GENERAL MANAGER UPDATE.
Kasper and Royuk presented the annual electric engineering and distribution system report and
reviewed the information with the board. Newton reviewed a draft letter from OPPD detailing what it
Page 2 1 Agenda Item #2

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would cost to reroute and bury a portion of the proposed Elkhorn River Valley Transmission line to avoid
the aesthetics of the line along Ritz Lake. The Board noted its acceptance to underground construction
as long as all additional costs are to be paid by the developer. Newton explained the Northern Natural
Gas (NNG) open season for additional Firm Deferred Delivery (FDD) storage. Currently FDU has
305,000 MMBtu of storage or approximately 13% of average annual gas sales. With the possibility of
the Costco load, Newton asked the Board to consider authorizing staff to bid for additional storage,
noting that if the bid was successful, the allocation could always be turned back into NNG without
penalty. The item will be placed on next month’s agenda. Kontor updated the board on the progress of
updating the wastewater treatment plant and Hormel’s commitment to install pretreatment.
ADJOURNMENT
Member Behrens moved and Member Shelso seconded the motion to adjourn the meeting at
5:30 p.m. Motion carried 5-0.
________________________________ ______________________________
Allen Sawtelle, Chairman Toni Vering, Secretary
Approved by:
______________________ ______________________ ___________________
Dennis Behrens David Shelso Erik Hoegemeyer
Page 3 2 Agenda Item #2

[PAGE 4]
PREPARED 12/28/2016 12:13:29 EXPENDITURE APPROVAL LIST
PROGRAM: GM339L REPORT PARAMETER SELECTIONS
EAL DESCRIPTION: EAL: 12282016 ANDERSEND
PAYMENT TYPES
Checks . . . . . . . . . . . . . . . . . . . . . Y
EFTs . . . . . . . . . . . . . . . . . . . . . . Y
ePayables . . . . . . . . . . . . . . . . . . . Y
VOUCHER SELECTION CRITERIA
Voucher/discount due date . . . . . . . . . . . 12/29/2016
All banks . . . . . . . . . . . . . . . . . . . A
REPORT SEQUENCE OPTIONS:
Vendor . . . . . . . . . . . . . . . . . . . . . X One vendor per page? (Y,N) . . . . . . . . . . N
Bank/Vendor . . . . . . . . . . . . . . . . . . One vendor per page? (Y,N) . . . . . . . . . . N
Fund/Dept/Div . . . . . . . . . . . . . . . . . Validate cash on hand? (Y,N) . . . . . . . . . N
Fund/Dept/Div/Element/Obj . . . . . . . . . . . Validate cash on hand? (Y,N) . . . . . . . . . N
Proj/Fund/Dept/Div/Elm/Obj . . . . . . . . . . .
This report is by: Vendor
Process by bank code? (Y,N) . . . . . . . . . . Y
Print reports in vendor name sequence? (Y,N) . . Y
Calendar year for 1099 withholding . . . . . . . 2016
Disbursement year/per . . . . . . . . . . . . . 2017/03
Payment date . . . . . . . . . . . . . . . . . . 12/28/2016
Page 4 Agenda Item #3

[PAGE 5]
PREPARED 12/28/2016,12:13:29 EXPENDITURE APPROVAL LIST PAGE 1
PROGRAM: GM339L AS OF: 12/29/2016 PAYMENT DATE: 12/28/2016
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
9999999 00 BOYER, JORDON G
000072221 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 107.75
VENDOR TOTAL * 107.75
0000584 00 CEI
20161229 PR1229 00 12/29/2016 051-0000-241.00-00 PAYROLL SUMMARY EFT: 4,144.44
VENDOR TOTAL * .00 4,144.44
9999999 00 FERGUSON, STEFANIE L
000072125 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 165.62
VENDOR TOTAL * 165.62
0001964 00 IBEW LOCAL UNION 1536
20161201 PR1201 00 12/29/2016 051-0000-241.00-00 PAYROLL SUMMARY 1,785.01
20161215 PR1215 00 12/29/2016 051-0000-241.00-00 PAYROLL SUMMARY 1,785.01
VENDOR TOTAL * 3,570.02
0002999 00 LAUGHLIN TRUSTEE, KATHLEEN A
20161229 PR1229 00 12/29/2016 051-0000-241.00-00 PAYROLL SUMMARY 162.00
VENDOR TOTAL * 162.00
0005002 00 NATIONAL ACCOUNT SYSTEMS OF OMAHA
20161229 PR1229 00 12/29/2016 051-0000-241.00-00 PAYROLL SUMMARY 239.29
VENDOR TOTAL * 239.29
0004192 00 PAYROLL EFT DEDUCTIONS
20161229 PR1229 00 12/29/2016 051-0000-241.00-00 PAYROLL SUMMARY 182,707.79
VENDOR TOTAL * 182,707.79
9999999 00 RAY, RUSSELL & ABBIE
000030097 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 125.67
VENDOR TOTAL * 125.67
9999999 00 SCHWARTZ, CODY L
000072893 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 20.76
VENDOR TOTAL * 20.76
9999999 00 SIBBALD, TOM
000071969 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 16.09
VENDOR TOTAL * 16.09
9999999 00 TOWN & COUNTRY PROPERTIES, LLC
000069021 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 96.82
VENDOR TOTAL * 96.82
9999999 00 VANEK, CARLIE A
000071017 UT 00 12/22/2016 051-0000-143.00-00 FINAL BILL REFUND 228.99
VENDOR TOTAL * 228.99
EFT/EPAY TOTAL *** 4,144.44
Page 5 Agenda Item #3

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PREPARED 12/28/2016,12:13:29 EXPENDITURE APPROVAL LIST PAGE 2
PROGRAM: GM339L AS OF: 12/29/2016 PAYMENT DATE: 12/28/2016
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
9999999 00
TOTAL EXPENDITURES **** 187,440.80 4,144.44
GRAND TOTAL ******************** 191,585.24
Page 6 Agenda Item #3

[PAGE 7]
Prepared 12/28/16, 10:57:33 CITY OF FREMONT Page 33
Pay Date 12/29/16 Direct Deposit Register
Primary FIRST NATIONAL BANK Program PR530L
------------------------------------------------------------------------------------------------------------------------------------
Account Social Deposit
Number Employee Name Security Amount
------------------------------------------------------------------------------------------------------------------------------------
Final Total 281,671.99 Count 172
Page 7 Agenda Item #3

[PAGE 8]
DEPARTMENT OF UTILITIES
ELECTRONIC WITHDRAWAL LIST
FOR BOARD OF PUBLIC WORKS MEETING: 1/4/17
AJ WITHDRAWAL WITHDRAWAL
GROUP NO VENDOR NAME DATE ACCOUNT NO ITEM DESCRIPTION AMOUNT
5606 VANTIV 12/20/16 051-5001-903-60-77 KIOSK CREDIT CARD FEES 13.20
TOTAL EXPENDITURES 13.20
Page 8 M:\Accounts Payable\DU\DU Electronic Withdrawals\12-20-16 Agenda Item #3

[PAGE 9]
PREPARED 12/29/2016 11:20:19 EXPENDITURE APPROVAL LIST
PROGRAM: GM339L REPORT PARAMETER SELECTIONS
EAL DESCRIPTION: EAL: 12292016 ANDERSEND
PAYMENT TYPES
Checks . . . . . . . . . . . . . . . . . . . . . Y
EFTs . . . . . . . . . . . . . . . . . . . . . . Y
ePayables . . . . . . . . . . . . . . . . . . . Y
VOUCHER SELECTION CRITERIA
Voucher/discount due date . . . . . . . . . . . 01/05/2017
All banks . . . . . . . . . . . . . . . . . . . A
REPORT SEQUENCE OPTIONS:
Vendor . . . . . . . . . . . . . . . . . . . . . X One vendor per page? (Y,N) . . . . . . . . . . N
Bank/Vendor . . . . . . . . . . . . . . . . . . One vendor per page? (Y,N) . . . . . . . . . . N
Fund/Dept/Div . . . . . . . . . . . . . . . . . Validate cash on hand? (Y,N) . . . . . . . . . N
Fund/Dept/Div/Element/Obj . . . . . . . . . . . Validate cash on hand? (Y,N) . . . . . . . . . N
Proj/Fund/Dept/Div/Elm/Obj . . . . . . . . . . .
This report is by: Vendor
Process by bank code? (Y,N) . . . . . . . . . . Y
Print reports in vendor name sequence? (Y,N) . . Y
Calendar year for 1099 withholding . . . . . . . 2017
Disbursement year/per . . . . . . . . . . . . . 2017/04
Payment date . . . . . . . . . . . . . . . . . . 01/05/2017
Page 9 Agenda Item #3

[PAGE 10]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 1
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0000957 00 AAA GARAGE DOOR INC
16-2960 PI1482 00 01/05/2017 051-5001-940.50-35 PO NUM 043515 9.64
16-2960 PI1483 00 01/05/2017 051-5001-940.60-61 PO NUM 043515 128.99
16-2972 PI1584 00 01/05/2017 051-5001-940.50-35 PO NUM 044728 65.28
16-2972 PI1585 00 01/05/2017 051-5001-940.60-61 PO NUM 044728 109.00
16-3023 PI1625 00 01/05/2017 051-5001-940.50-35 PO NUM 044783 10.05
16-3023 PI1626 00 01/05/2017 051-5001-940.60-61 PO NUM 044783 119.65
VENDOR TOTAL * 442.61
0000959 00 ACE HARDWARE
98669/3 PI1484 00 01/05/2017 051-5001-940.50-35 PO NUM 043953 101.61
98730/3 PI1485 00 01/05/2017 051-5001-940.50-35 PO NUM 043953 156.54
98737/3 PI1487 00 01/05/2017 051-5001-940.50-35 PO NUM 043953 28.86
98772/3 PI1598 00 01/05/2017 051-5001-940.50-35 PO NUM 043953 91.87
98731/3 PI1486 00 01/05/2017 051-5105-502.50-35 PO NUM 043953 2.45
98741/3 PI1523 00 01/05/2017 055-7105-512.50-35 PO NUM 044742 69.99
VENDOR TOTAL * 451.32
0004995 00 ACME CONTROLS
983143 PI1612 00 01/05/2017 055-7105-512.50-35 PO NUM 044650 275.00
VENDOR TOTAL * 275.00
0000960 00 ADAMS OIL INC
16594 PI1623 00 01/05/2017 055-7105-502.50-30 PO NUM 044768 EFT: 3,202.10
VENDOR TOTAL * .00 3,202.10
0004920 00 ADVANCED ELECTRICAL AND MOTOR
AEM-16-3262 PI1512 00 01/05/2017 051-5105-502.60-61 PO NUM 044673 EFT: 5,119.84
AEM-16-3262 PI1513 00 01/05/2017 051-5105-502.60-79 PO NUM 044673 EFT: 152.38
VENDOR TOTAL * .00 5,272.22
0004276 00 AIRGAS USA LLC
9058250553 PI1597 00 01/05/2017 051-5105-502.50-35 PO NUM 036774 EFT: 228.96
9058477045 PI1606 00 01/05/2017 051-5105-502.50-35 PO NUM 044169 EFT: 1,399.50
9058477045 PI1607 00 01/05/2017 051-5105-502.50-35 PO NUM 044169 EFT: 739.12
VENDOR TOTAL * .00 2,367.58
0000967 00 ALLIED APPLIANCE INC
57287 PI1515 00 01/05/2017 055-7105-512.50-35 PO NUM 044682 549.00
57287 PI1516 00 01/05/2017 055-7105-512.60-61 PO NUM 044682 80.00
VENDOR TOTAL * 629.00
0003124 00 ALLIED ELECTRONICS INC
9007055470 PI1596 00 01/05/2017 055-0000-154.00-00 PO NUM 044741 EFT: 468.92
VENDOR TOTAL * .00 468.92
0002612 00 ALTEC INDUSTRIES INC
10670882 PI1514 00 01/05/2017 051-5205-580.50-35 PO NUM 044675 1,424.13
VENDOR TOTAL * 1,424.13
0002228 00 AMERICAN WATER WORKS ASSOCIATION
Page 10 Agenda Item #3

[PAGE 11]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 2
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0002228 00 AMERICAN WATER WORKS ASSOCIATION
7001267194 PI1624 00 01/05/2017 053-6001-905.60-67 PO NUM 044769 3,361.00
VENDOR TOTAL * 3,361.00
0000583 00 ANCHOR SCIENTIFIC INC
225180 PI1479 00 01/05/2017 051-0000-155.00-00 PO NUM 044725 402.00
225180 PI1522 00 01/05/2017 051-5105-502.60-79 PO NUM 044725 19.49
VENDOR TOTAL * 421.49
0002531 00 BABCOCK & WILCOX
BA60333056 PI1595 00 01/05/2017 051-0000-153.00-00 PO NUM 044698 EFT: 8,078.50
VENDOR TOTAL * .00 8,078.50
0001662 00 BARR-THORP ELECTRIC CO INC
S1433694-001 PI1557 00 01/05/2017 051-5105-502.60-65 PO NUM 044428 2,949.99
VENDOR TOTAL * 2,949.99
0003660 00 BAUER BUILT INC
880049540 PI1613 00 01/05/2017 055-7105-502.50-48 PO NUM 044676 422.00
880049540 PI1614 00 01/05/2017 055-7105-502.60-61 PO NUM 044676 50.00
880048884 PI1615 00 01/05/2017 057-8205-870.50-48 PO NUM 044690 256.53
880048884 PI1616 00 01/05/2017 057-8205-870.60-61 PO NUM 044690 27.70
880049553 PI1618 00 01/05/2017 057-8205-870.50-48 PO NUM 044729 278.26
880049553 PI1619 00 01/05/2017 057-8205-870.60-61 PO NUM 044729 28.37
VENDOR TOTAL * 1,062.86
0005009 00 BDO USA LLP
000742633 00 01/05/2017 051-0000-173.00-00 Nov/Turbine Damage Claim 7,625.00
VENDOR TOTAL * 7,625.00
0004558 00 BLT PLUMBING HEATING & A/C INC
13206 PI1605 00 01/05/2017 055-7105-512.50-35 PO NUM 044004 62.07
VENDOR TOTAL * 62.07
0003545 00 BOMGAARS SUPPLY INC
16196652 PI1488 00 01/05/2017 051-5001-940.50-35 PO NUM 043954 37.44
16197382 PI1489 00 01/05/2017 051-5105-502.50-35 PO NUM 043954 114.46
16198557 PI1490 00 01/05/2017 055-7105-512.50-35 PO NUM 043954 44.95
VENDOR TOTAL * 196.85
0004996 00 BRIGGS AND MORGAN PA
591184 PI1617 00 01/05/2017 051-5001-919.60-61 PO NUM 044713 6,772.50
VENDOR TOTAL * 6,772.50
0004518 00 CAPPEL AUTO SUPPLY INC
204325 PI1602 00 01/05/2017 051-5001-940.50-35 PO NUM 043990 212.93
204414 PI1603 00 01/05/2017 051-5001-940.50-48 PO NUM 043990 161.51
203240 PI1611 00 01/05/2017 051-5001-940.50-48 PO NUM 044606 376.43
204201 PI1600 00 01/05/2017 051-5105-502.50-48 PO NUM 043990 230.62
204294 PI1601 00 01/05/2017 051-5205-580.50-48 PO NUM 043990 156.40
Page 11 Agenda Item #3

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PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 3
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0004518 00 CAPPEL AUTO SUPPLY INC
204488 PI1604 00 01/05/2017 055-7205-583.50-48 PO NUM 043990 131.88
VENDOR TOTAL * 1,269.77
0003817 00 CED AUTOMATION OMAHA
5411-492840 PI1477 00 01/05/2017 051-0000-155.00-00 PO NUM 044686 57.87
5411-492934 PI1594 00 01/05/2017 051-0000-155.00-00 PO NUM 044686 264.20
5411-492915 PI1478 00 01/05/2017 055-0000-154.00-00 PO NUM 044691 167.04
VENDOR TOTAL * 489.11
0002675 00 CENTURYLINK
4027272600 1216PI1549 00 01/05/2017 051-5001-922.50-53 PO NUM 043996 48.12
4027272606 1216PI1550 00 01/05/2017 051-5001-922.50-53 PO NUM 043996 408.72
4027272654 1216PI1551 00 01/05/2017 051-5001-922.50-53 PO NUM 043996 48.54
VENDOR TOTAL * 505.38
0002915 00 CREDIT BUREAU SERVICES INC
NOV 2016 PI1521 00 01/05/2017 055-7001-905.55-04 PO NUM 044721 125.00
VENDOR TOTAL * 125.00
0004646 00 DATABANK IMX LLC
MO41000652 PI1518 00 01/05/2017 051-5001-922.60-65 PO NUM 044695 9,719.20
VENDOR TOTAL * 9,719.20
0003586 00 DHHS LICENSURE UNIT
2017 N HRBEK PI1588 00 01/05/2017 053-6205-583.60-67 PO NUM 044740 115.00
VENDOR TOTAL * 115.00
0000313 00 DIAMOND POWER INTERNATIONAL INC
489894 PI1593 00 01/05/2017 051-0000-153.00-00 PO NUM 044660 1,730.20
VENDOR TOTAL * 1,730.20
0001313 00 DILLON CHEVROLET FREMONT INC, SID
1TCS121142 PI1664 00 01/05/2017 051-5205-580.60-61 PO NUM 043959 79.95
VENDOR TOTAL * 79.95
0001927 00 DOKTER TRUCKING CORP
2155 PI1608 00 01/05/2017 051-5105-502.60-61 PO NUM 044588 850.00
2302 PI1609 00 01/05/2017 051-5105-502.60-61 PO NUM 044588 1,000.00
2326 PI1610 00 01/05/2017 051-5105-502.60-61 PO NUM 044588 925.00
2177 PI1643 00 01/05/2017 051-5105-502.60-61 PO NUM 044588 650.00
VENDOR TOTAL * 3,425.00
0003321 00 DOUGLAS COUNTY TREASURER/LANDFILL
1171482 PI1586 00 01/05/2017 051-5001-940.60-61 PO NUM 044730 32.27
VENDOR TOTAL * 32.27
0004605 00 DXP ENTERPRISES INC
48331088 PI1524 00 01/05/2017 051-0000-154.00-00 PO NUM 044038 EFT: 409.15
VENDOR TOTAL * .00 409.15
0003087 00 EAKES OFFICE SOLUTIONS
Page 12 Agenda Item #3

[PAGE 13]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 4
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0003087 00 EAKES OFFICE SOLUTIONS
S 136574 PI1558 00 01/05/2017 051-5001-932.60-65 PO NUM 044456 1,250.99
VENDOR TOTAL * 1,250.99
0004551 00 ELEMETAL FABRICATION LLC
21516 PI1599 00 01/05/2017 051-5001-940.50-35 PO NUM 043975 245.04
21495 PI1494 00 01/05/2017 051-5105-502.50-35 PO NUM 043975 244.92
VENDOR TOTAL * 489.96
0001091 00 EMANUEL PRINTING INC
8142 PI1511 00 01/05/2017 051-5001-903.50-40 PO NUM 044640 144.99
VENDOR TOTAL * 144.99
0004993 00 FIKES COMMERCIAL HYGIENE LLC
573 PI1495 00 01/05/2017 051-5001-932.60-61 PO NUM 044106 EFT: 164.78
VENDOR TOTAL * .00 164.78
0002168 00 FORNEY CORPORATION
403987 PI1591 00 01/05/2017 051-0000-155.00-00 PO NUM 044446 1,595.47
VENDOR TOTAL * 1,595.47
0004833 00 FREMONT AREA UNITED WAY
NOV'16 CARESHAR 00 01/05/2017 055-0000-242.02-00 Nov 2016 Care & Share EFT: 281.51
VENDOR TOTAL * .00 281.51
0001124 00 FREMONT PRINTING CO
15037 PI1499 00 01/05/2017 051-5001-903.50-31 PO NUM 044256 77.15
15037 PI1500 00 01/05/2017 051-5001-917.50-31 PO# 044256 213.98
15037 PI1501 00 01/05/2017 051-5001-919.50-31 PO# 044256 25.66
15037 PI1502 00 01/05/2017 051-5001-920.50-31 PO# 044256 34.23
15037 PI1503 00 01/05/2017 051-5001-922.50-31 PO# 044256 25.66
15037 PI1504 00 01/05/2017 051-5001-926.50-31 PO# 044256 25.66
15037 PI1505 00 01/05/2017 051-5001-940.50-31 PO# 044256 34.23
15037 PI1506 00 01/05/2017 051-5205-580.50-31 PO# 044256 34.23
VENDOR TOTAL * 470.80
0003377 00 GEA MECHANICAL EQUIPMENT US INC
7586519608 PI1576 00 01/05/2017 055-7105-512.50-35 PO NUM 044696 7,273.74
VENDOR TOTAL * 7,273.74
0003102 00 GEORG FISCHER CENTRAL PLASTICS LLC
1790200 PI1592 00 01/05/2017 057-0000-154.00-00 PO NUM 044482 3,477.00
VENDOR TOTAL * 3,477.00
0002804 00 GOVERNMENT FINANCE OFFICERS ASSN
0166596 PI1507 00 01/05/2017 051-5001-920.60-67 PO NUM 044333 150.00
VENDOR TOTAL * 150.00
0004932 00 GRACE CONSULTING INC
6187 PI1481 00 01/05/2017 051-5105-502.60-61 PO NUM 043258 13,000.00
Page 13 Agenda Item #3

[PAGE 14]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 5
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0004932 00 GRACE CONSULTING INC
VENDOR TOTAL * 13,000.00
0001445 00 GRAYBAR
988880380 PI1474 00 01/05/2017 051-0000-154.00-00 PO NUM 044296 601.70
988047958 PI1525 00 01/05/2017 051-0000-154.00-00 PO NUM 044274 1,547.00
988451322 PI1589 00 01/05/2017 051-0000-154.00-00 PO NUM 044314 1,120.70
988985403 PI1590 00 01/05/2017 051-0000-154.00-00 PO NUM 044314 439.20-
VENDOR TOTAL * 2,830.20
0004707 00 GREAT PLAINS COMMUNICATIONS INC
4020010078 1216PI1496 00 01/05/2017 051-5001-922.50-53 PO NUM 044192 149.00
4020010078 1216PI1497 00 01/05/2017 051-5001-922.60-65 PO NUM 044192 500.00
4020010078 1216PI1498 00 01/05/2017 055-7105-502.60-76 PO NUM 044192 229.00
VENDOR TOTAL * 878.00
0003155 00 HACH COMPANY
10241141 PI1620 00 01/05/2017 055-7105-502.50-52 PO NUM 044743 825.73
10241141 PI1621 00 01/05/2017 055-7105-512.50-35 PO NUM 044743 50.12
VENDOR TOTAL * 875.85
0004419 00 HANSEN TIRE LLC
17392 PI1629 00 01/05/2017 051-5105-502.50-48 PO NUM 043963 106.24
17392 PI1630 00 01/05/2017 051-5105-502.60-61 PO NUM 043963 10.00
17403 PI1631 00 01/05/2017 051-5205-580.50-48 PO NUM 043963 219.75
VENDOR TOTAL * 335.99
0002794 00 HDR ENGINEERING INC
1200025586 PI1533 00 01/05/2017 053-6205-583.60-61 PO NUM 043936 9,468.48
1200025586 PI1534 00 01/05/2017 055-7205-583.60-61 PO NUM 043936 9,468.48
VENDOR TOTAL * 18,936.96
0004599 00 IBT INC
6926434 PI1627 00 01/05/2017 051-0000-154.00-00 PO NUM 044441 EFT: 571.85
6926433 PI1652 00 01/05/2017 055-7105-512.50-35 PO NUM 044716 EFT: 23.00
6926433 PI1653 00 01/05/2017 055-7105-512.50-35 PO NUM 044716 EFT: 775.56
VENDOR TOTAL * .00 1,370.41
0004264 00 INDUSTRIAL PIPE & SUPPLY LLC
60175-00 PI1509 00 01/05/2017 051-5105-502.50-35 PO NUM 044564 EFT: 563.09
60175-00 PI1510 00 01/05/2017 051-5105-502.60-79 PO NUM 044564 EFT: 107.00
VENDOR TOTAL * .00 670.09
0001833 00 INDUSTRIAL SALES CO INC
D 965795-003 PI1475 00 01/05/2017 057-0000-154.00-00 PO NUM 044383 1,233.64
969275-000 PI1645 00 01/05/2017 057-8205-870.50-35 PO NUM 044647 439.08
969275-000 PI1646 00 01/05/2017 057-8205-870.60-61 PO NUM 044647 94.95
969275-000 PI1647 00 01/05/2017 057-8205-870.60-79 PO NUM 044647 22.94
VENDOR TOTAL * 1,790.61
0001687 00 INLAND TRUCK PARTS & SERVICE
Page 14 Agenda Item #3

[PAGE 15]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 6
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0001687 00 INLAND TRUCK PARTS & SERVICE
6-26834 PI1519 00 01/05/2017 055-7105-512.50-35 PO NUM 044717 270.62
VENDOR TOTAL * 270.62
0003483 00 INTERSTATE CHEMCIAL CO INC
260362 PI1480 00 01/05/2017 051-5105-502.50-52 PO NUM 042699 3,206.15
VENDOR TOTAL * 3,206.15
0003085 00 KELLY SUPPLY CO
11117134-0 PI1648 00 01/05/2017 051-5105-502.50-35 PO NUM 044662 391.95
11117134-0 PI1649 00 01/05/2017 051-5105-502.60-79 PO NUM 044662 30.25
VENDOR TOTAL * 422.20
0004676 00 KIEWIT ENGINEERING & DESIGN CO
9000071425 PI1508 00 01/05/2017 051-5105-502.60-61 PO NUM 044516 6,650.93
VENDOR TOTAL * 6,650.93
9999999 00 KING, JEFF
120816 KING 00 01/05/2017 055-7205-583.50-01 Jeff King Crop Damage 661.50
VENDOR TOTAL * 661.50
0002902 00 KRIZ-DAVIS CO
S101461592-006 PI1476 00 01/05/2017 051-0000-154.00-00 PO NUM 044612 EFT: 133.75
S101446595-001 PI1527 00 01/05/2017 051-0000-154.00-00 PO NUM 044558 EFT: 9,373.67
S101461806-001 PI1644 00 01/05/2017 051-5105-502.50-35 PO NUM 044627 EFT: 144.45
S101468658-001 PI1517 00 01/05/2017 051-5205-580.60-62 PO NUM 044688 EFT: 400.00
S101469710-001 PI1520 00 01/05/2017 051-5205-580.50-64 PO NUM 044718 EFT: 474.01
S101469728-001 PI1491 00 01/05/2017 053-6205-583.50-35 PO NUM 043965 EFT: 258.48
S101469905-001 PI1492 00 01/05/2017 055-7105-512.50-35 PO NUM 043965 EFT: 128.37
S101470229-001 PI1493 00 01/05/2017 055-7205-583.50-35 PO NUM 043965 EFT: 49.46
VENDOR TOTAL * .00 10,962.19
0002654 00 LEAGUE ASSN OF RISK MANAGEMENT
10539 PI1690 00 01/05/2017 051-5001-919.60-63 PO NUM 044808 3,194.02
10541 PI1691 00 01/05/2017 051-5001-919.60-63 PO NUM 044808 507.58-
VENDOR TOTAL * 2,686.44
0004976 00 MARCO TECHNOLOGIES LLC
INV3878140 PI1555 00 01/05/2017 051-5001-920.60-65 PO NUM 044364 119.28
VENDOR TOTAL * 119.28
0002052 00 MATHESON LINWELD
14583016 PI1642 00 01/05/2017 051-5001-950.80-50 PO NUM 044514 EFT: 9,405.30
VENDOR TOTAL * .00 9,405.30
0003289 00 MATT FRIEND TRUCK EQUIPMENT INC
0082383-IN PI1564 00 01/05/2017 051-5001-940.50-48 PO NUM 044643 550.67
0082383-IN PI1565 00 01/05/2017 051-5001-940.60-79 PO NUM 044643 24.28
VENDOR TOTAL * 574.95
0002963 00 MCGILL ASBESTOS ABATEMENT CO INC
Page 15 Agenda Item #3

[PAGE 16]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 7
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0002963 00 MCGILL ASBESTOS ABATEMENT CO INC
114653 PI1692 00 01/05/2017 051-5001-932.60-61 PO NUM 044817 550.00
VENDOR TOTAL * 550.00
0001469 00 MCGRATH NORTH MULLIN & KRATZ PC LLO
450749 PI1628 00 01/05/2017 051-5105-502.60-61 PO NUM 041300 9,413.06
VENDOR TOTAL * 9,413.06
0000667 00 MCMASTER-CARR SUPPLY CO
93777563 PI1654 00 01/05/2017 051-5001-940.50-35 PO NUM 044745 423.26
93777563 PI1655 00 01/05/2017 051-5001-940.60-79 PO NUM 044745 33.25
92712110 PI1573 00 01/05/2017 051-5105-502.50-35 PO NUM 044685 152.31
92712110 PI1574 00 01/05/2017 051-5105-502.50-35 PO NUM 044685 29.90
92712110 PI1575 00 01/05/2017 051-5105-502.60-79 PO NUM 044685 8.10
VENDOR TOTAL * 646.82
0001229 00 MENARDS - FREMONT
21398 PI1535 00 01/05/2017 051-5001-940.50-35 PO NUM 043970 23.55
21482 PI1537 00 01/05/2017 051-5001-922.50-42 PO NUM 043970 154.08
21663 PI1540 00 01/05/2017 051-5001-922.50-42 PO NUM 043970 12.66
21706 PI1542 00 01/05/2017 051-5001-922.50-42 PO NUM 043970 .95-
21708 PI1543 00 01/05/2017 051-5001-922.50-42 PO NUM 043970 3.79
21776 PI1635 00 01/05/2017 051-5001-940.50-35 PO NUM 043970 141.05
21539 PI1538 00 01/05/2017 051-5105-502.50-35 PO NUM 043970 93.25
21637 PI1633 00 01/05/2017 051-5105-502.50-35 PO NUM 043970 85.56
21709 PI1634 00 01/05/2017 051-5105-502.50-35 PO NUM 043970 156.35
21481 PI1536 00 01/05/2017 051-5205-580.50-35 PO NUM 043970 38.39
21558 PI1539 00 01/05/2017 053-6105-502.50-35 PO NUM 043970 106.84
21683 PI1541 00 01/05/2017 053-6105-502.50-35 PO NUM 043970 23.40
VENDOR TOTAL * 837.97
0002069 00 MIDWEST OUTDOOR POWER LLC
31704 PI1580 00 01/05/2017 051-5205-580.50-35 PO NUM 044719 79.66
31704 PI1581 00 01/05/2017 051-5205-580.60-61 PO NUM 044719 96.30
VENDOR TOTAL * 175.96
0004883 00 MISSISSIPPI LIME COMPANY
1294399 00 01/05/2017 051-0000-158.02-00 12/16/16 25.37 TN EFT: 4,336.12
1295404 00 01/05/2017 051-0000-158.02-00 12/22/16 24.64 TN EFT: 4,211.47
VENDOR TOTAL * .00 8,547.59
0002646 00 MONITORING SOLUTIONS INC
23945 PI1529 00 01/05/2017 051-0000-153.00-00 PO NUM 044723 300.21
VENDOR TOTAL * 300.21
0001486 00 MOTION INDUSTRIES INC
NE01-457662 PI1660 00 01/05/2017 051-0000-153.00-00 PO NUM 044754 18.51
NE01-457994 PI1661 00 01/05/2017 051-0000-153.00-00 PO NUM 044754 39.07
NE01-457286 PI1577 00 01/05/2017 051-5105-502.50-35 PO NUM 044701 289.96
NE01-457286 PI1578 00 01/05/2017 051-5105-502.60-79 PO NUM 044701 23.01
Page 16 Agenda Item #3

[PAGE 17]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 8
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0001486 00 MOTION INDUSTRIES INC
NE01-457662 PI1687 00 01/05/2017 051-5105-502.60-79 PO NUM 044754 9.42
NE01-457354 PI1556 00 01/05/2017 055-7105-512.50-35 PO NUM 044413 1,237.96
VENDOR TOTAL * 1,617.93
0002985 00 MSC INDUSTRIAL SUPPLY CO INC
47806196 PI1528 00 01/05/2017 051-0000-154.00-00 PO NUM 044704 EFT: 343.28
50924100 PI1662 00 01/05/2017 051-0000-154.00-00 PO NUM 044779 EFT: 338.03
VENDOR TOTAL * .00 681.31
0001958 00 NEBR PUBLIC HEALTH ENVIRONMENTAL
483488 PI1559 00 01/05/2017 053-6105-502.60-61 PO NUM 044530 EFT: 15.00
483489 PI1560 00 01/05/2017 053-6105-502.60-61 PO NUM 044530 EFT: 601.00
VENDOR TOTAL * .00 616.00
0003428 00 NEW PIG CORPORATION
22093434-00 PI1656 00 01/05/2017 051-5001-940.50-35 PO NUM 044749 295.00
22093434-00 PI1657 00 01/05/2017 051-5001-940.60-79 PO NUM 044749 14.99
VENDOR TOTAL * 309.99
0001020 00 O'REILLY AUTOMOTIVE INC
0397-423531 PI1638 00 01/05/2017 051-5001-940.50-35 PO NUM 043973 66.05
0397-423801 PI1639 00 01/05/2017 051-5001-940.50-48 PO NUM 043973 12.81
0397-417612 PI1636 00 01/05/2017 051-5105-502.50-48 PO NUM 043973 76.65-
0397-424252 PI1640 00 01/05/2017 051-5105-502.50-35 PO NUM 043973 74.47
0397-423803 PI1658 00 01/05/2017 051-5105-502.50-48 PO NUM 044760 465.16
0397-417614 PI1637 00 01/05/2017 055-7105-502.50-48 PO NUM 043973 71.64
VENDOR TOTAL * 613.48
0002888 00 OFFICENET
856347-0 PI1566 00 01/05/2017 051-5001-940.50-40 PO NUM 044669 215.54
857575-0 PI1650 00 01/05/2017 051-5205-580.50-40 PO NUM 044689 96.82
857193-0 PI1651 00 01/05/2017 051-5205-580.50-40 PO NUM 044702 190.88
VENDOR TOTAL * 503.24
0002971 00 OMAHA DOOR & WINDOW CO INC
ORD0037274 PI1561 00 01/05/2017 051-5001-940.50-35 PO NUM 044573 320.57
ORD0037274 PI1562 00 01/05/2017 051-5001-940.60-79 PO NUM 044573 26.78
VENDOR TOTAL * 347.35
0001912 00 OMAHA PUBLIC POWER DISTRICT
CSB000537 PI1530 00 01/05/2017 051-5305-560.60-61 PO NUM 040993 EFT: 83,583.13
CSB000540 PI1531 00 01/05/2017 051-5305-560.60-61 PO NUM 040993 EFT: 3,620,348.50
VENDOR TOTAL * .00 3,703,931.63
0002946 00 OMAHA PUBLIC POWER DISTRICT
1115740525 1216 00 01/05/2017 051-5305-560.60-76 Dec 2016 Interconnection EFT: 4,285.88
VENDOR TOTAL * .00 4,285.88
0001268 00 P & H ELECTRIC INC
Page 17 Agenda Item #3

[PAGE 18]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 9
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0001268 00 P & H ELECTRIC INC
116149 PI1641 00 01/05/2017 055-7105-512.50-35 PO NUM 043974 29.75
VENDOR TOTAL * 29.75
0004948 00 PCM SALES INC
S99833900101 PI1568 00 01/05/2017 051-5105-502.50-42 PO NUM 044674 30.09
S99833900101 PI1569 00 01/05/2017 051-5105-502.60-79 PO NUM 044674 16.05
VENDOR TOTAL * 46.14
0003827 00 PEST PRO'S INC
MNCP BLD 122016PI1673 00 01/05/2017 051-5001-932.60-61 PO NUM 044194 42.80
ASH PD 122016 PI1674 00 01/05/2017 051-5105-502.60-61 PO NUM 044208 48.15
CMBT TUR 122016PI1675 00 01/05/2017 051-5105-502.60-61 PO NUM 044208 53.50
PWR PLT 122216 PI1676 00 01/05/2017 051-5105-502.60-61 PO NUM 044208 85.60
SUB STA 122016 PI1677 00 01/05/2017 051-5205-580.60-61 PO NUM 044218 190.35
WTR PLT 122016 PI1671 00 01/05/2017 053-6105-502.60-61 PO NUM 044137 69.55
WWTP 122216 PI1672 00 01/05/2017 055-7105-502.60-61 PO NUM 044189 110.00
VENDOR TOTAL * 599.95
0004800 00 PINNACLE BANK - VISA
AQ0FE0915570 PI1689 00 01/05/2017 051-5105-502.60-67 PO NUM 044793 150.00
VENDOR TOTAL * 150.00
0002622 00 PITNEY BOWES INC
1002711980 PI1670 00 01/05/2017 051-5001-903.60-65 PO NUM 044127 150.00
VENDOR TOTAL * 150.00
0002793 00 PLIBRICO COMPANY LLC
96365 PI1579 00 01/05/2017 051-5001-932.60-61 PO NUM 044711 4,463.75
VENDOR TOTAL * 4,463.75
0004968 00 POWER SCREENING LLC
H612018432 PI1663 00 01/05/2017 055-7001-950.80-50 PO NUM 043773 402,750.00
VENDOR TOTAL * 402,750.00
0003762 00 PR DIAMOND PRODUCTS INC
0043678-IN PI1582 00 01/05/2017 053-6205-583.50-35 PO NUM 044726 474.00
0043678-IN PI1583 00 01/05/2017 053-6205-583.60-79 PO NUM 044726 18.00
VENDOR TOTAL * 492.00
0004740 00 PREMIER STAFFING INC
8917 PI1546 00 01/05/2017 051-5001-940.60-61 PO NUM 043988 30.00
VENDOR TOTAL * 30.00
0004696 00 PRIME COMMUNICATIONS INC
40447 PI1554 00 01/05/2017 051-5001-922.50-42 PO NUM 044348 5,236.23
VENDOR TOTAL * 5,236.23
0004413 00 RADWELL INTERNATIONAL INC
INV2678693 PI1680 00 01/05/2017 055-7105-512.50-35 PO NUM 044490 1,852.00
Page 18 Agenda Item #3

[PAGE 19]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 10
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0004413 00 RADWELL INTERNATIONAL INC
INV2680265 PI1681 00 01/05/2017 055-7105-512.60-61 PO NUM 044490 1,733.00
VENDOR TOTAL * 3,585.00
0002876 00 RAWHIDE CHEMOIL INC
57775 PI1570 00 01/05/2017 051-5001-940.50-35 PO NUM 044680 41.73
16441 PI1587 00 01/05/2017 051-5001-917.50-30 PO NUM 044737 16,763.64
57793 PI1683 00 01/05/2017 051-5001-940.50-35 PO NUM 044680 13.91
56376 PI1688 00 01/05/2017 055-7105-502.50-30 PO NUM 044767 633.15
VENDOR TOTAL * 17,452.43
0001514 00 SAFWAY SERVICES LLC
D058567/CO58655PI1682 00 01/05/2017 055-7105-512.60-61 PO NUM 044653 EFT: 748.00
VENDOR TOTAL * .00 748.00
0001308 00 SHERWIN-WILLIAMS CO
1392-4 PI1544 00 01/05/2017 053-6105-502.50-35 PO NUM 043978 58.09
VENDOR TOTAL * 58.09
0000429 00 SKARSHAUG TESTING LABORATORY INC
214099 PI1547 00 01/05/2017 051-5205-580.60-61 PO NUM 043994 432.95
214099 PI1548 00 01/05/2017 051-5205-580.60-79 PO NUM 043994 146.22
VENDOR TOTAL * 579.17
0003415 00 SNAP-ON INDUSTRIAL
ARV/31101631 PI1686 00 01/05/2017 051-5001-940.50-35 PO NUM 044748 220.21
VENDOR TOTAL * 220.21
0002023 00 SOLUTIONONE
462621 PI1553 00 01/05/2017 051-5001-903.60-65 PO NUM 044126 158.98
462979 PI1669 00 01/05/2017 051-5001-903.60-65 PO NUM 044126 49.22
VENDOR TOTAL * 208.20
0003960 00 SPX TRANSFORMER SOLUTIONS INC
041656 PI1567 00 01/05/2017 051-5205-580.50-35 PO NUM 044671 608.21
VENDOR TOTAL * 608.21
0003923 00 STATE OF NEBRASKA - CELLULAR
1042367 00 01/05/2017 051-5001-903.50-53 Cellular EFT: 104.58
1042367 00 01/05/2017 051-5001-926.50-53 Safety Mgr Cellular EFT: 57.59
1042367 00 01/05/2017 051-5105-502.50-53 Cellular EFT: 137.64
1042367 00 01/05/2017 051-5205-580.50-53 Engineers Cellular EFT: 230.36
1042367 00 01/05/2017 051-5205-580.50-53 Elect Distr Cellular EFT: 359.51
1042367 00 01/05/2017 053-6105-502.50-53 Cellular EFT: 57.59
1042367 00 01/05/2017 053-6205-583.50-53 Cellular EFT: 164.57
1042367 00 01/05/2017 055-7105-502.50-53 Cellular EFT: 23.22
1042367 00 01/05/2017 057-8205-870.50-53 Cellular EFT: 188.82
VENDOR TOTAL * .00 1,323.88
0001137 00 STEFFY CHRYSLER CENTER INC, GENE
Page 19 Agenda Item #3

[PAGE 20]
PREPARED 12/29/2016,11:20:19 EXPENDITURE APPROVAL LIST PAGE 11
PROGRAM: GM339L AS OF: 01/05/2017 PAYMENT DATE: 01/05/2017
DEPARTMENT OF UTILITIES
------------------------------------------------------------------------------------------------------------------------------------
VEND NO SEQ# VENDOR NAME EFT, EPAY OR
INVOICE VOUCHER P.O. BNK CHECK/DUE ACCOUNT ITEM CHECK HAND-ISSUED
NO NO NO DATE NO DESCRIPTION AMOUNT AMOUNT
------------------------------------------------------------------------------------------------------------------------------------
0001137 00 STEFFY CHRYSLER CENTER INC, GENE
5053740 PI1622 00 01/05/2017 051-5105-502.50-48 PO NUM 044759 358.45
VENDOR TOTAL * 358.45
0003891 00 SUNGARD PUBLIC SECTOR INC
128242 PI1678 00 01/05/2017 051-5001-903.60-77 PO NUM 044387 EFT: 233.13
128242 PI1679 00 01/05/2017 051-5001-917.60-77 PO# 044387 EFT: 12.27
VENDOR TOTAL * .00 245.40
0004647 00 T SQUARE SUPPLY LLC
15215 PI1665 00 01/05/2017 051-5001-940.50-35 PO NUM 043980 183.87
15283 PI1667 00 01/05/2017 051-5001-940.50-35 PO NUM 043980 114.07
15269 PI1666 00 01/05/2017 055-7105-512.50-35 PO NUM 043980 22.00
VENDOR TOTAL * 319.94
0001339 00 TIMME WELDING & SUPPLY LLC
32720 PI1668 00 01/05/2017 053-6205-583.50-35 PO NUM 043981 62.60
VENDOR TOTAL * 62.60
0004754 00 TOTAL TOOL SUPPLY INC
08556166 PI1532 00 01/05/2017 051-5105-502.60-61 PO NUM 043508 222.42
VENDOR TOTAL * 222.42
0004515 00 TRACTOR SUPPLY CREDIT PLAN
191520 PI1545 00 01/05/2017 051-5105-502.50-35 PO NUM 043982 56.67
191347 PI1685 00 01/05/2017 057-8205-870.50-48 PO NUM 044693 353.09
VENDOR TOTAL * 409.76
0002413 00 USI EDUCATION & GOVERNMENT SALES
0381746901010 PI1684 00 01/05/2017 051-5205-580.50-40 PO NUM 044683 EFT: 70.10
VENDOR TOTAL * .00 70.10
0002568 00 WATER ENVIRONMENT FEDERATION
9000414616 PI1571 00 01/05/2017 055-7105-502.60-67 PO NUM 044681 79.00
2017 S SEELHOFFPI1572 00 01/05/2017 055-7105-502.60-67 PO NUM 044681 79.00
VENDOR TOTAL * 158.00
0000482 00 WESCO RECEIVABLES CORP
784895 PI1526 00 01/05/2017 051-0000-154.00-00 PO NUM 044503 EFT: 353.10
796697 PI1659 00 01/05/2017 051-0000-154.00-00 PO NUM 044747 EFT: 192.60
VENDOR TOTAL * .00 545.70
0004135 00 WINDOW PRO INC
30469 PI1552 00 01/05/2017 051-5001-932.60-61 PO NUM 044095 EFT: 10.70
VENDOR TOTAL * .00 10.70
EFT/EPAY TOTAL *** 3,763,658.94
TOTAL EXPENDITURES **** 564,763.64 3,763,658.94
GRAND TOTAL ******************** 4,328,422.58
Page 20 Agenda Item #3

[PAGE 21]
STAFF REPORT
TO: Board of Public Works
FROM: Brian Newton, General Manager
DATE: January 4, 2017
SUBJECT: Open Season Bid for Northern Natural Gas Storage
R ecommendation: Authorize the General Manager to submit an open season bid with
N orthern Natural Gas (NNG) for 72,000 MMBtu of additional storage at the NNG tariff
r ate.
Background: Northern Natural Gas (NNG) is soliciting binding bids for 6.1 Bcf of Firm
Deferred Delivery (FDD) service (storage). The last time NNG held an open season for
FDD storage was 2004, when FDU acquired 100,000 MMBtu. Currently FDU has
302,510 MMBtu of FDD storage with NNG, which represents approximately 13% of
annual sales. With the possibly of the Costco poultry plant coming on line in 2018,
submitting a bid for additional FDD storage would be a practical business decision. Also,
should the additional FDD storage not be needed in the future, it can be returned to NNG
without penalty.
Fiscal Impact: Approximately $53,000 per year.
Page 21 Agenda Item #4

[PAGE 22]
From: Rosman, Stacy
Subject: Northern Natural Gas - Firm Deferred Delivery Service Open Season for Service Beginning June 1, 2017
Date: Tuesday, December 06, 2016 4:51:46 PM
Attachments: image002.png
NNG_Email_Logo.bmp
Hello!
I wanted to make sure you all saw the Firm Deferred Delivery Service (FDD Storage) open season
that was posted earlier today, so I’ve forwarded along a copy of the posting below…
Please feel free to contact me if you have any interest in purchasing additional storage and we can
talk through the bid process.
Have a good evening!
Stacy
Stacy L Rosman
Account Director - Marketing
Email: stacy.rosman@nngco.com | O: 402-398-7377 | C: 402-578-2525 | AIM: stacylrosman
From: notices@nngco.com [mailto:notices@nngco.com]
Sent: Tuesday, December 06, 2016 10:44 AM
Subject: Non-Critical, TSP Capacity Offering, 20161206, Northern, 784158214
TSP Name: Northern Natural Gas Company Post Date/Time: 12/06/2016 10:44 AM
TSP: 784158214 Notice Effective Date/Time: 12/06/2016 10:44
Notice ID: 034607 AM
Notice Type: TSP Capacity Offering Notice End Date/Time: 01/13/2017 5:00 PM
Subject: FIRM DEFERRED DELIVERY SERVICE For Gas Day(s): 12/6/2016 - 1/13/2017
OPEN SEASON FOR SERVICE BEGINNING JUNE 1, Notice Status: Initiate
2017 Required Response Indicator Description: 5-
Critical: N No response required
Notice Text:
Northern Natural Gas Company is hereby soliciting binding bids for a total of 6.1 Bcf of Firm
Deferred Delivery (FDD) service. This includes 5.8 Bcf of newly available capacity plus 0.3 Bcf
of generally available capacity. Northern has identified that it can convert 5.8 Bcf of existing
interruptible capacity to FDD. An increase in peak deliverability has been determined to be
available at both the Redfield, Iowa and Cunningham, Kansas storage fields that will provide
the maximum withdrawal rate to accommodate this conversion of service without significant
facility requirements. Firm service made available pursuant to this Open Season is anticipated
to be available for injections commencing on June 1, 2017, subject to FERC approval[1] FERC
approval is anticipated prior to June 1, 2017, however, if FERC approval is received after June
Page 22 Agenda Item #4

[PAGE 23]
1, 2017, but prior to August 1, 2017, service will begin upon receipt of FERC approval and
shippers will pay all reservation and capacity fees as if the FDD service began June 1, 2017.[2]
If FERC approval is received after August 1, 2017, the service will begin June 1 of the following
year. Parameters for the firm service will be as described in Northern’s FERC Gas Tariff (Tariff)
under the FDD Rate Schedule.
Up to 0.3 Bcf of generally available capacity will be awarded without regard to the FERC
approval of the proposed 5.8 Bcf of converted interruptible capacity to firm capacity.
Open Season
The open season commences Tuesday, December 6, 2016, and ends Friday, January 13, 2017,
at 5:00 p.m. CCT. For a bid to be considered, it must be received by 5:00 p.m. CCT January
13, 2017. If you have any questions, please contact your account manager or Dave Stockdale
at (402) 398-7643.
Bid Procedures
1. Submit your binding bid to Northern either via facsimile to (402) 398-7413 or e-mail to
NNGOpenSea@nngco.com. The bid must contain a completed Open Season Bid Form or
all the information required by such form. After submission, upon a determination by
Northern that the bid is a best bid, the bid becomes a binding contract. If bidder is
awarded capacity, bidder shall execute a service agreement upon tender by Northern.
All bids must include the firm storage quantity (FSQ) bid, the minimum acceptable FSQ
the bidder will accept and the term in years.
2. Bid quantities will only be accepted for service terms commencing on June 1, 2017, that
are in full annual increments (June 1 through May 31).
3. Alternative Bid Methodology - The capacity will be awarded to the highest bidder(s)
based on a determination of the best bid, or combination of bids that result in the
highest net present value (NPV) of reservation revenue, on a per unit of capacity basis.
Northern shall have the right to aggregate bids, or portions of bids, that generate the
highest NPV to Northern. The NPV per unit will be determined by discounting the cash
flow (using the FERC interest rate) generated from an annualized unit rate, based on
the firm deferred delivery reservation fee and capacity fee, over the term bid and
dividing by the FSQ requested. The annualized unit reservation rate equates to $0.7134
per Dth.
4. Northern will only be accepting maximum tariff rate bids. For purposes of bid
evaluation, any bids exceeding twenty years will be economically evaluated as a bid for
twenty years.
5. Northern agrees to a rollover charge per Dth equal to $0.00 for any quantity less than
or equal to 5% of the contract FSQ on May 31 of each year for the term of the bid.
6. Northern and bidder(s) may agree to amend the service agreement, as allowed by
Northern’s FERC Gas Tariff, at any time after award of the capacity.
7. Northern will evaluate bids and award the capacity based on the terms of this open
season.
8. Customer(s) must meet the creditworthiness provisions of Northern’s Tariff. Upon
request by Northern, customer shall provide appropriate credit assurance within ten
(10) calendar days of Northern’s request. If a non-creditworthy customer fails to
provide the appropriate security, Northern may award the capacity to the next best
bid(s) or proceed to remarket the capacity, and customer will be liable for any
difference in value of the bids, in addition to any other remedies available by law.
9. The results will be posted on Northern’s website and notification will be made to the
winning bidder(s).
10. Northern may consider contingent bids.
[1] Changes to Northern’s FERC Gas Tariff that increase the amount of FDD service that can be sold must be
approved by the FERC.
[2] In the event the effective date of the FDD service is after June 1, 2017 but before August 1, 2017, the
transportation service agreement will be filed as a non-conforming, negotiated rate service agreement.
Non-Critical notices are located on Northern's website at the following address -
http://www.northernnaturalgas.com/InfoPostings/Notices/Pages/NonCritical.aspx
Page 23 Agenda Item #4

[PAGE 24]
City of Fremont - Firm Storage Contract Information
10/11/16
ROFR Min Bal Max Bal Max Bal FDD Rate Rate Rate
Contract Initial Current Max Bal on Rate
Contract# End Date or FSQ on on on O ption Reservation Reservation Reservation POI Point Description
Type Start DateStart Date Aug 31st Commodity
Rollover Jan 31st Mar 1st May 31st Type Average Winter Summer
98 OGDEN DEF. DELIVERY Max WD FDQ
Max INJ FDQ
INJ Period Max Bal - 8/31
FDD 22309 06/01/93 06/01/11 05/31/19 Rollover 202,510 134,669 81,004 50,628 10,126 4 Step Max Max Max Max
WD Period Min Bal - 1/31
WD Period Max Bal - 3/1
Max Rollover Bal - 5/31
98 OGDEN DEF. DELIVERY Max WD FDQ
Max INJ FDQ
INJ Period Max Bal - 8/31
FDD 111012 06/01/04 06/01/11 05/31/21 ROFR 100,000 66,500 40,000 25,000 5,000 4 Step Max Max Max Max
WD Period Min Bal - 1/31
WD Period Max Bal - 3/1
Max Rollover Bal - 5/31
Page 24 Agenda Item #4

[PAGE 25]
Natural Gas Actual Usage - Monthly
City of Fremont Dept. of Utilities
Date Range : 12/01/2011 - 11/30/2016
(All Volumes in MMBtu)
Month Actual MIN MAX AVG CO2e
(MMBtu) (MMBtu) (MMBtu) Usage (Metric tons)
Dec - 11 285,246 6,771 12,804 9,201 15,532
Jan - 12 297,376 6,437 14,539 9,593 16,193
Feb - 12 271,886 7,059 13,503 9,375 14,805
Mar - 12 163,728 3,132 8,718 5,282 8,915
Apr - 12 135,602 3,180 5,957 4,520 7,384
May - 12 124,726 2,677 4,890 4,023 6,792
Jun - 12 124,333 2,576 8,289 4,144 6,770
Jul - 12 140,712 3,027 8,238 4,539 7,662
Aug - 12 121,327 2,599 4,529 3,914 6,606
Sep - 12 116,862 2,624 4,909 3,895 6,363
Oct - 12 172,862 3,372 8,590 5,576 9,413
Nov - 12 217,735 4,632 11,122 7,258 11,856
Dec - 12 306,320 5,492 13,835 9,881 16,680
Jan - 13 341,719 7,597 15,583 11,023 18,607
Feb - 13 284,656 7,064 13,533 10,166 15,500
Mar - 13 265,836 3,235 11,763 8,575 14,475
Apr - 13 187,618 2,489 9,718 6,254 10,216
May - 13 133,403 1,746 8,514 4,303 7,264
Jun - 13 100,387 1,859 4,235 3,346 5,466
Jul - 13 105,706 1,985 4,172 3,410 5,756
Aug - 13 102,045 1,810 4,244 3,292 5,557
Sep - 13 91,562 1,479 3,973 3,052 4,986
Oct - 13 162,554 3,178 7,711 5,244 8,851
Nov - 13 245,514 4,860 11,982 8,184 13,369
Dec - 13 366,153 6,905 15,501 11,811 19,938
Jan - 14 372,054 6,998 15,887 12,002 20,259
Feb - 14 326,040 8,154 15,674 11,644 17,754
kgarst Page 25 Agenda Item #4Page 1 of 2
12/5/2016 2:44:54 PM

[PAGE 26]
Natural Gas Actual Usage - Monthly
City of Fremont Dept. of Utilities
Date Range : 12/01/2011 - 11/30/2016
(All Volumes in MMBtu)
Month Actual MIN MAX AVG CO2e
(MMBtu) (MMBtu) (MMBtu) Usage (Metric tons)
Mar - 14 255,399 3,787 13,065 8,239 13,907
Apr - 14 164,496 2,697 9,232 5,483 8,957
May - 14 111,919 1,761 6,366 3,610 6,094
Jun - 14 95,166 1,852 4,070 3,172 5,182
Jul - 14 99,806 2,231 3,960 3,220 5,435
Aug - 14 101,680 2,244 4,154 3,280 5,537
Sep - 14 88,539 1,644 3,981 2,951 4,821
Oct - 14 138,320 2,248 7,321 4,462 7,532
Nov - 14 265,968 4,118 13,598 8,866 14,482
Dec - 14 300,639 4,892 16,453 9,698 16,370
Jan - 15 328,808 7,156 16,147 10,607 17,904
Feb - 15 326,230 6,227 15,482 11,651 17,764
Mar - 15 217,956 3,882 12,934 7,031 11,868
Apr - 15 149,211 3,054 8,168 4,974 8,125
May - 15 124,205 2,632 5,928 4,007 6,763
Jun - 15 103,997 2,831 4,279 3,467 5,663
Jul - 15 121,026 2,388 7,452 3,904 6,590
Aug - 15 118,904 1,917 12,225 3,836 6,475
Sep - 15 173,796 2,920 13,327 5,793 9,464
Oct - 15 146,578 2,849 8,548 4,728 7,981
Nov - 15 213,292 3,755 11,462 7,110 11,614
Dec - 15 286,129 6,250 13,247 9,230 15,580
Jan - 16 348,347 7,096 15,256 11,237 18,968
Feb - 16 270,935 4,540 12,517 9,343 14,753
Mar - 16 203,618 3,827 11,572 6,568 11,087
Apr - 16 157,475 2,984 7,818 5,249 8,575
May - 16 125,573 2,404 5,330 4,051 6,838
Jun - 16 212,898 2,734 12,361 7,097 11,593
Jul - 16 152,977 2,643 14,676 4,935 8,330
Aug - 16 118,097 1,525 5,062 3,810 6,431
Sep - 16 118,868 2,898 4,740 3,962 6,473
Oct - 16 152,236 2,731 12,657 4,911 8,290
Nov - 16 202,373 4,022 10,069 6,746 11,020
Totals: 11,559,423 1,479 16,453 6,345 629,435
kgarst Page 26 Agenda Item #4Page 2 of 2
12/5/2016 2:44:54 PM

[PAGE 27]
Input # FDD BILLING EXAMPLE
72,000 MMBTU
Cycle Quantity Ref Tariff Sheet Nos. 54 & 55
FDD Season
Jun-Oct Nov-May
The storage rates shown in the table are the tariff rates starting Reservation Rate 1.714 1.7140
November 1, 2006. Capacity Rate 0.3567 0.3567
Injection/Withdrawal Rate 0.0149 0.0149
Overrun 0.0887 0.0887
Jun-Oct Nov-Apr
COMPONENTS RATE RATE BILLING QUANTITY INJECTION PERIOD WITHDRAWAL PERIOD
MAXIMUM DAILY MONTHS MONTHS OVERRUN ONLY
W/D QUANTITY JUNE JULY AUG. SEPT. OCT. NOV. DEC. JAN. FEB. MARCH APRIL MAY TOTAL
RESERVATION FEE * 1 $1.7140 $1.7140 1,249 MMBTU $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $2,140 $25,685
ANNUAL
CYCLE QUANTITY
CAPACITY FEE * 2 $0.3567 $0.3567 72,000 MMBTU $5,136 $5,136 $5,136 $5,136 $5,136 $25,682
INJECTION * 3 SEE ACTUAL Inject. w/in Firm Reqrmts: $0.0149 per MMBTU W/D w/in Firm Reqrmts: $0.0149 per MMBTU $2,146
and INFORMATION QUANTITIES Inject. Overrun $0.0149 plus $0.0887 per MMBTU W/D Overrun $0.0149 plus $0.0887 per MMBTU Increm. Cost (if an
WITHDRAWAL FEES AT RIGHT W/D w/in Firm Reqrmts: $0.0887 per MMBTU Inject. w/in Firm Reqrmts: $0.0887 per MMBTU Increm. Cost (if an
W/D Overrun $0.0887 per MMBTU Inject. Overrun $0.0887 per MMBTU Increm. Cost (if an
FDD STORAGE FUEL ACTUAL
see Tariff Sheet No. 54 SUMMER
for most current rate INJECTIONS
Note * 1: Rate x maximum daily w/d volume, billed monthly over 12 months TOTAL FDD BILLING $53,513
(w/o any increm. cost)
Note * 2: Rate x annual cycle volume, billed equally over the injection period, only
FDD UNIT COST $0.7432
Note * 3: Rate x actual monthly injection or withdrawal volume equals each monthly bill (w/o any increm. VOL.) PER MMBTU
FDU Gas Sales
2014 2015 2016 Costco
Jan 3 72,054 328,808 348,347 45,000
Feb 3 26,040 326,230 270,935 45,000
Mar 2 55,399 217,956 203,618 45,000
Apr 1 64,496 149,211 157,475 45,000
May 1 11,919 124,205 125,573 45,000
Jun 9 5,166 103,997 212,898 45,000
Jul 9 9,806 121,026 152,977 45,000
Aug 1 01,680 118,904 118,097 45,000
Sept 8 8,539 173,796 118,868 45,000
Oct 1 38,320 146,578 152,236 45,000
Nov 2 65,968 213,292 202,373 45,000
Dec 3 00,639 286,129 300,000 45,000
Total Year 2,320,026 2,310,132 2,363,397 540,000
Avg sales 2,331,185
Current storage 302510 New sales 2,871,185
2014 2015 2016 New storage needs
% of storage to sales 13.04% 13.09% 12.80% 70744
Page 27 Agenda Item #4

[PAGE 28]
STAFF REPORT
TO: Board of Public Works
FROM: Brian Newton, General Manager
DATE: January 4, 2017
SUBJECT: Clawback Agreement with Costco
R ecommendation: Authorize the General Manager to execute the clawback agreement
w ith Costco and recommend approval by the City Council.
Background: As part of the Amended and Restated Redevelopment Agreement with
Costco the City agreed to provide Costco a $2,000,000 Economic Incentive for the
installation and construction of utility infrastructure; subject to certain clawback
provisions. Clawback provisions include a 15-year commitment by Costco to not
discontinue use of its agricultural and industrial processing facilities and to meet yearly
minimum utility consumption requirements. Failure to meet the provisions will require
Costco to repay all or a portion of the Economic Incentive.
Fiscal Impact: None
Page 28 Agenda Item #5

[PAGE 29]
CLAWBACK PROVISIONS AND INDEMNIFICATION AGREEMENT
This Clawback Provisions and Indemnification Agreement (the “Agreement”) is made
and entered into on this ___ day of _______, ________, between the City of Fremont, a
municipal political subdivision of the State of Nebraska (“City”), whose address for the purposes
of this Agreement is 400 E Military Ave, Fremont NE 68025, and Costco Wholesale Corporation,
a Washington corporation (“Costco”), whose address for the purposes of this Agreement is 999
Lake Drive, Issaquah, WA 98027.
PRELIMINARY STATEMENT
The City has agreed to provide Costco a $2,000,000 incentive (“Economic Development
Incentive”) in the Amended and Restated Redevelopment Agreement dated __________,
_______ (“Redevelopment Agreement”) in connection with the installation and construction of
utility infrastructure (electric, natural gas, water, and wastewater) the general locations as legally
described on the attached Exhibit “A” (the “Costco Property”) to be owned by Costco and
operated by Lincoln Premium Poultry as an agricultural and industrial processing facility so long
as Costco or its lessee and/or operator consumes minimum volumes of utility services depicted
in attached Exhibit “B” (the “Minimum Utility Requirements”) during the term of this agreement.
Should Costco fail to meet the Minimum Utility Requirements during the term of this agreement,
Costco has agreed to reimburse the City’s incentive, subject to the terms and conditions set
forth herein.
TERMS AND CONDITIONS
Now, therefore, in consideration of the foregoing Preliminary Statement which is included
herein by this reference and the mutual covenants of the parties hereto, it is agreed as follows:
1. Term: The term of this agreement shall be fifteen (15) years commencing
(“Term”) one (1) year following the date of commercial operation.
2. Utility Consumption Reporting: Within ninety (90) days after receipt, Costco shall
pay all utility consumption bills, and with such payment, Costco shall provide a summary of its
utility consumption, which shall include a reasonable level of detail describing the utility service
provided, the actual amount of utility services consumed by Costco, and the disparity between
the actual utility services consumed on the Costco Property and the Minimum Utility
Requirements.
3. Reimbursement: Costco shall reimburse the City the Economic Development
Incentive upon the occurrence of the following events:
a. If Costco elects to discontinue its use of the facilities at the Costco Property
as contemplated in the Redevelopment Agreement during the Term of this
Agreement, within thirty (30) days of such election Costco must: (1) notify the
City in writing of such election, and (2) reimburse the Department of Utilities
for the Economic Development Incentive in full; or
b. If, at the end of the Term, Costco has not met the yearly Minimum Utility
Requirements set forth on Exhibit “B”, within thirty (30) days following the
expiration of the Term of this Agreement, Costco shall reimburse the
Department of Utilities a portion of the two million dollar ($2,000,000.00)
Page 29 Agenda Item #5

[PAGE 30]
Economic Development Incentive which corresponds to Costco’s average
overall deficiency percentage calculated as follows:
i. Every year during the Term of the Agreement for each of the four
utilities listed on Exhibit “B”, it shall be determined whether Costco
met the Minimum Consumption Requirements for that utility outlined in
Exhibit “B.” If Costco did not meet the Minimum Consumption
Requirements for some or all of the four utilities, the difference
between the actual consumption and Minimum Consumption
Requirements for each utility that did not meet the Minimum
Consumption Requirements shall be used to calculate the percent
Costco was deficient in meeting the Minimum Consumption
Requirements for that utility as follows:
Minimum Consumption
Requirement (-) Actual Consumption
(X) X = Deficiency %
Minimum Consumption Requirement 100
ii. After the deficiency percentage is calculated for each utility as
applicable, the deficiency percentage for each such utility shall be
averaged by totaling said individual percentages and dividing the total
by four (4) to produce an aggregate deficiency percentage for the
year. No credit shall be given for consuming more than the Minimum
Utility Requirements for any utility.
iii. After the aggregate yearly deficiency percentage is calculated for
each year during the Term of the Agreement, the yearly deficiency
percentage for each year shall be totaled, and the total shall be
divided by the number of years in the Term to produce the average
aggregate deficiency percentage for the Term, which aggregate
percentage shall be multiplied by the amount of the Two Million Dollar
Economic Development Incentive, the product of which is the amount
which Costco must repay to the City pursuant to this Agreement.
4. Costco hereby agrees to indemnify and hold City harmless from and against any
and all liabilities, expenses including reasonable attorneys’ and engineers’ fees, orders,
lawsuits, causes of actions, claims, damages, costs, penalties, fines, interest and demands
whatsoever suffered, threatened against, or paid, or incurred by City in connection with, or
arising from, Costco’s failure to reimburse the City.
5. This Agreement shall be binding upon and inure to the benefit of the successors
and assigns of the parties.
6. All notices or other communications required or permitted by this Agreement shall
be in writing and in all cases addressed to the party at the location or address indicated above.
Such notice shall be considered to be properly given by and received by a party (i) whenever
delivered in person, or (ii) on the date a return receipt is signed by a party when sent by certified
mail, regardless of when received or delivered. A party shall have the right to change its
address for notice or other communication to any other person or location within the continental
United States by giving prior written notice to the other party.
2
Page 30 Agenda Item #5

[PAGE 31]
7. This Agreement may be executed in counterparts, each of which will be deemed
an original and all of which together will constitute one agreement. Each counterpart may be
delivered by facsimile or computer-scanned image transmission. The signature page of any
counterpart may be detached therefrom without impairing the legal effect of the signature(s)
thereon provided such signature page is attached to any other counterpart identical thereto.
8. No amendment of this Agreement shall be valid unless it is in writing and is
signed by the parties or by their duly authorized representatives, and unless it specifies the
nature and extent of the amendment.
9. The City and Costco each agree to abide by all federal, state, and local laws,
statutes, ordinances and regulations governing the activities discussed herein. Costco shall
comply with, and indemnify the City against any violations of applicable regulations promulgated
by the Environmental Protection Agency or other government agencies regulating any activities
engaged in by Costco.
10. This Agreement, and the rights and duties of the parties arising from or relating in
any way to the terms, covenants, or conditions of this Agreement shall be governed by,
construed and enforced in accordance with the laws of the State of Nebraska.
[Signature Page Follows]
3
Page 31 Agenda Item #5

[PAGE 32]
IN WITNESS WHEREOF, this Agreement was executed on the date as first written
hereinabove.
COSTCO WHOLESALE CORPORATION CITY OF FREMONT, NEBRASKA,
a Washington corporation, a municipal political subdivision of the State
of Nebraska,
By:___________________________ By:___________________________
Scott Getzschman, Mayor
Name:________________________
Title:_________________________
ATTEST APPROVED AS TO FORM
____________________________
Tyler Ficken, City Clerk Paul Payne, City Attorney
4
Page 32 Agenda Item #5

[PAGE 33]
[Signature Page to Clawback Provisions and Indemnification Agreement]
Exhibit “A”
(“Costco Property”)
A TRACT OF LAND TO BE ANNEXED INTO THE CITY OF FREMONT, LOCATED IN PART OF NORTHEAST
AND NORTHWEST QUARTERS OF SECTION 26, TOWNSHIP 17 NORTH, RANGE 8 EAST OF THE 6TH
P.M., DODGE COUNTY, NEBRASKA, MORE PARTICULARLY DESCRIBED AS FOLLOWS:
BEGINNING AT THE NORTHWEST CORNER OF THE SOUTHEAST QUARTER OF SECTION 26,
TOWNSHIP 17 NORTH, RANGE 8 EAST, DODGE COUNTY, NEBRASKA, THENCE EASTERLY ON AN
ASSUMED BEARING OF N87°43’50”E ON THE NORTH LINE OF THE SOUTHWEST QUARTER OF
SECTION 26, 1130.95 FEET TO A POINT ON THE APROXIMATE WESTERLY RAILROAD RIGHT-OF-WAY
LINE; THENCE S05°07’33”E ON SAID WESTERLY RAILROAD RIGHT-OF-WAY LINE, 1178.00 FEET TO A
POINT INTERSECTING THE NORTHERLY RIGHT-OF-WAY LINE OF HILLS FARM ROAD; THENCE
N59°05’58”W ON SAID NORTHERLY RIGHT-OF-WAY LINE; 697.41 FEET; THENCE CONTINUNING
N86°26’21”W, ON SAID NORTHERLY RIGHT-OF-WAY LINE, 1931.80 FEET; THENCE N02°10’38”W,
1162.85 FEET TO THE NORTHWEST CORNER OF LOT 6, EAST INGLEWOOD SUBDIVISION, A PLATTED
AND RECORDED SUBDIVISION IN DODGE COUNTY; THENCE N87°42’03”E ON THE NORTH LINE OF
SAID LOT 6, 545.50 FEET TO THE NORTHEAST CORNER OF SAID LOT 6; THENCE N02°06’54”W ON THE
EAST LINE OF LOT 5, SAID EAST INGLEWOOD SUBDIVISION, 283.94 FEET TO A POINT ON THE EAST
LINE OF LOT 4, SAID EAST INGLEWOOD SUBDIVISION; THENCE N88°10’00”E, 772.03 FEET TO A POINT
ON THE WEST LINE OF THE SOUTHWEST QUARTER OF THE NORTHEAST QUARTER; THENCE
S01°58’55”E ON SAID WEST LINE OF THE NORTHEAST QUARTER, 842.47 FEET TO THE POINT OF
BEGINNING.
SAID TRACT OF LAND CONTAINS A CALCULATED AREA OF 2,839,313.53 SQ. FT. OR 65.18 ACRES
MORE OR LESS.
AND
A TRACT OF LAND TO BE ANNEXED INTO THE CITY OF FREMONT, LOCATED IN PART OF SOUTHEAST
QUARTER OF THE NORTHEAST QUARTER, AND PART OF THE EAST HALF OF THE SOUTHWEST
QUARTER OF SECTION 26, AND PART OF THE SOUTH HALF OF THE NORTHWEST QUARTER AND
PART OF THE SOUTHWEST QUARTER AND PART OF THE WEST HALF OF THE SOUTHEAST QUARTER
OF SECTION 25, AND PART OF THE NORTHWEST QUARTER OF THE NORTHEAST QUARTER OF
SECTION 36, TOWNSHIP 17 NORTH, RANGE 8 EAST OF THE 6TH P.M., DODGE COUNTY, NEBRASKA,
MORE PARTICULARLY DESCRIBED AS FOLLOWS:
COMMENCING AT THE SOUTHWEST CORNER OF THE NORTHEAST QUARTER OF THE NORTHEAST
QUARTER OF SAID SECTION 26; THENCE NORTHEASTERLY ON THE NORTH LINE OF THE
NORTHEAST QUARTER OF THE NORTHEAST QUARTER ON AN ASSUMED BEARING OF N87°52’30”E,
33.00 FEET TO THE POINT OF BEGINNING; THENCE S58°58’04”E, 191.84 FEET TO A POINT ON THE
SOUTHERLY RIGHT-OF-WAY LINE OF EAST CLOVERLY ROAD; THENCE N88°05’46”E ON SAID
SOUTHERLY RIGHT-OF-WAY LINE OF EAST CLOVERLY ROAD, 1425.78 FEET TO A POINT OF
CURVATURE; THENCE ON A 1308.22 FOOT RADIUS CURVE TO THE RIGHT ON SAID SOUTHERLY
RIGHT-OF-WAY LINE OF EAST CLOVERLY ROAD, AN ARC LENGTH OF 1030.78 FEET (LONG CHORD
BEARS S69°21’38”E, 1004.32 FEET); THENCE S46°47’16”E ON SAID SOUTHERLY RIGHT-OF-WAY LINE
OF EAST CLOVERLY ROAD, 1238.40 FEET TO A POINT OF CURVATURE; THENCE ON A 260.00 FOOT
RADIUS CURVE TO THE LEFT ON SAID SOUTHERLY RIGHT-OF WAY LINE OF EAST CLOVERLY ROAD,
AN ARC LENGTH OF 145.89 FEET (LONG CHORD BEARS S62°49’54”E, 143.98 FEET); THENCE
5
Page 33 Agenda Item #5

[PAGE 34]
S43°15’’11”W, 507.62 FEET; THENCE S02°10’141”E, 149.93 FEET; THENCE S87°49’55”E, 729.97 FEET;
THENCE N02°07’45”W, 189.94 FEET; THENCE N02°07’45”W, 256.01 FEET TO A POINT ON THE
APPROXIMATE SOUTHWESTERLY RAILROAD RIGHT-OF-WAY LINE; THENCE S46°46’20”E ON SAID
SOUTHWESTERLY RAILROAD RIGHT-OF-WAY LINE, 1911.83 FEET TO A POINT ON THE EAST LINE OF
SAID WEST HALF OF THE SOUTHEAST QUARTER; THENCE S02°14’28”E ON SAID EAST LINE OF THE
WEST HALF, 1107.05 FEET TO THE SOUTHEAST CORNER OF THE SOUTHWEST QUARTER OF THE
SOUTHEAST QUARTER; THENCE S02°12’31”E ON THE EAST LINE OF SAID NORTHWEST QUARTER OF
THE NORTHEAST QUARTER OF SECTION 36, 1356.15 FEET TO A POINT ON THE NORTHERLY RIGHT-
OF-WAY LINE OF HILLS FARM ROAD; THENCE N70°35’17”W ON SAID NORTHERLY RIGHT-OF-WAY
LINE OF HILLS FARM ROAD, 1410.04 FEET; THENCE N02°14’36”W, 711.27 FEET; THENCE N71°00’17”W,
375.56 FEET TO A POINT ON THE SOUTH LINE OF SAID SOUTHWEST QUARTER OF SECTION 25;
THENCE CONTINUING N71°00’17”W, 825.89 FEET; THENCE N70°58’58”W, 290.07 FEET; THENCE
N62°51’54”W, 488.40 FEET; THENCE S01°12’50”E, 631.29 FEET TO A POINT ON SAID SOUTH LINE OF
THE SOUTHWEST QUARTER; THENCE N58°57’36”W ON THE NORTHERLY RIGHT-OF-WAY LINE OF
HILLS FARM ROAD, 984.75 FEET TO A POINT INTERSECTING THE NORTHERLY RIGHT-OF-WAY LINE
OF HILLS FARM ROAD AND THE WEST RIGHT-OF WAY LINE OF YAGER ROAD; THENCE N02°09’03”W
ON SAID WEST RIGHT-OF-WAY LINE OF YAGER ROAD, 306.92 FEET TO THE NORTHEAST CORNER OF
LOT 1R, REPLAT OF BLOCK 1 SOUTH FREMONT; THENCE S87°49’05”W ON THE NORTH LINE OF SAID
LOT 1R, 226.99 FEET TO THE NORTHWEST CORNER OF SAID LOT 1R; THENCE S02°11’37”E ON THE
WEST LINE OF SAID LOT 1R, 161.11 FEET TO A POINT ON SAID NORTHERLY RIGHT-OF-WAY LINE OF
HILLS FARM ROAD; THENCE N59°08’09”W ON SAID NORTHERLY RIGHT-OF-WAY LINE OF HILLS FARM
ROAD, 1231.92 FEET TO A POINT INTERSECTING SAID NORTHERLY RIGHT-OF-WAY LINE OF HILLS
FARM ROAD AND THE EAST RIGHT-OF-WAY LINE OF SOUTH PLATTE AVENUE; THENCE N02°07’30”W
ON SAID EAST RIGHT-OF-WAY LINE OF SOUTH PLATTE AVENUE, 2604.69 FEET TO THE POINT OF
BEGINNING.
SAID TRACT OF LAND CONTAINS A CALCULATED AREA OF 15,119,539.82 SQ. FT. OR 347.10 ACRES
MORE OR LESS.
6
Page 34 Agenda Item #5

[PAGE 35]
Exhibit “B”
(“Minimum Utility Requirements”)
Minimum Yearly Requirements:
Utility:
Electric 10.15 MW
62,380,800 kWh
Water
597,600,000 Gal
Wastewater
584,400,000 Gal
Natural gas
897,600 Dkt
Exhibit “B”
Page 35 Agenda Item #5

[PAGE 36]
WWTP ANNUAL REPORT
2015/2016
Agenda Item #7a

[PAGE 37]
 WWTP 10 Employees
 Superintendent
 Lab Technician
 5 Operators
 3 Mechanics
Agenda Item #7a

[PAGE 38]
Annual Budget 2015/2016
Account Budget Actual %
Wages 562000 531066 94.5
Benefits 290955 284031 97.6
Commodities 404000 425291 105.3
Contractual Services 438070 435184 99.4
Depreciation 819400 805774 98
Capital Projects 435000 338536 77.8
Total 2,560,900 2,502,819.04 97.70
Agenda Item #7a

[PAGE 39]
CAPITAL EXPENDITURES
 Budget Actual
 Roof Replacement 75,000.00 88,895.00
 Headwork's Heating System 110,000.00 98,450.00
 Dissolved Oxygen TSS meters 50,000.00 24,900.00
 Tractor 50,000.00 43,459.00
 Compost Screen 175,000.00 82,832.00 145,168.00 Grant (228,000)
 Total 460,000.00 338,536.00
Agenda Item #7a

[PAGE 40]
WASTEWATER TREATED
 1,661,112,000 Gallons/yr.
 137,630,000 Gallons/month
 4,614,200 Gallons/day
 1.507 Cost/1000 gallons (1.021/1000 gallons)
Agenda Item #7a

[PAGE 41]
BIOSOLIDS PROGRAM
 Biosolids Hauled/spread – 4730 tons
 Spread on 450 acres
 Hauling $31,984.00
 Spreading $22,920.00
 Scale $1348.00
 Total Expenses $56,252.00
 Biosolids Income $48,735.00
 Net cost $7517.00
Agenda Item #7a

[PAGE 42]
WWTP UPGRADE
 HDR – Design and Specifications
 30-35 Million estimated cost
 25% complete
 Plans and Specs to DEQ (May 31, 2017)
 June/August 2017 bid????
 Completion by November 2019
Agenda Item #7a

[PAGE 43]
Nebraska Public Power’s
Competitiveness in the
Regional Energy Market
Produced for Wind is Water Foundation
December 12, 2016
Goss & Associates Economic Solutions
www.gossandassociates.com
The Goss Institute
Ernest Goss, Principal Investigator
600 17th Street, Suite 2800 South
Denver, Colorado 80202-5428
303.226.5882
Ernest Goss, Ph.D.
ernieg@creighton.edu
Jeffrey Milewski, M.S.
jmilewski@gossandassociates.com
Page 43 Agenda Item #7b

[PAGE 44]
Table of Contents
Nebraska Public Power’s Competitiveness
In the Regional Energy Market
Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .i
Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Section 1: The Southwest Power Pool’s Integrated Marketplace Challenges Nebraska’s Public
.......... Power Model . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Section 2: Threats facing Nebraska’s Public Power Generation. . . . . . . . . . . . . . . . . . . . . . . . . . 10
Section 3: A Case for Retail Choice in Nebraska - The effect on electric rates, reducing ratepayer
..........risk, and the need for greater transparency using unbundled billing . . . . . . . . . . . . . . 15
Appendix A: SPP Market Participants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Appendix B: Illustration of Southwest Power Pool Integrated Market. . . . . . . . . . . . . . . . . . . . . . . 24
Appendix C: Example of an Unbundled Bill. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Appendix D: Screenshot of powertochoose.org Showing Suppliers’ Rate Options. . . . . . . . . . . . 26
Appendix E: 2015 Utility Bundled Retail Sales - Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Appendix F: 2015 Utility Bundled Retail Sales - Industrial. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Appendix G: Researchers’ Biographies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
NEBRASKA PUPBLICa POgWERe’S C O4MP4ETITIVENESS IN THE REGIONAL ENERGY MARKET Agenda Item #7b

[PAGE 45]
Preface
Nebraska Public Power’s Competitiveness
In the Regional Energy Market
The subsequent analysis was prepared Goals of the study
for Wind is Water by Ernest Goss, Ph.D., Principal
The goal of this study was to examine how
Investigator, and Jeff Milewski of Goss &
Nebraska’s power industry operates within the
Associates Economic Solutions. Findings remain
Southwest Power Pool, particularly the integrated
the sole property of Wind is Water Foundation
marketplace, and to determine whether Nebraska’s
and may not be used without prior approval of
Public Power Model is adequately serving the
this organization. Any errors or misstatements
ratepayer.
contained in this study are solely the responsibility
of the authors.1 The authors’ biographies are Specific goals of the study are to:
provided in Appendix G. Please address all
• Determine whether increased competition and
correspondence to:
choice in Nebraska’s power industry leads to
cheaper sources of electricity and better rates
for consumers.
o If so, explore how increasing competition and
choice affect Nebraska’s generating utilities,
consumer-utilities, and ratepayers.
• Examine how federal tax credits for renewables
and environmental regulations, particularly the
new Clean Power Plan, would affect Nebraska’s
public power utilities.
• Investigate how Nebraska’s public power
structure restricts choice. What disincentivizes
private capital from investing in Nebraska’s
electricity sector?
• Determine whether legislative changes would
help increase transparency and promote greater
choice in the electric industry in Nebraska.
Goss & Associates thanks Wind is Water
Foundation for their assistance in providing data
for this study. However, any errors, omissions, or
misstatements are solely the responsibility of Goss &
Associates and the principal investigator.
1This study was completed independent of Creighton
University. As such, Creighton University bears no
responsibility for findings or statements by Ernie Goss, or
Goss & Associates, Economic Solutions.
Page 45 Agenda Item #7b
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET Page i

[PAGE 46]
Executive Summary
Nebraska Public Power’s Competitiveness
In the Regional Energy Market
• Since the implementation of the SPP Integrated Market (IM) in March 2014, electricity prices have trended
downward due to the addition of wind generation and low natural gas prices. Because of the high cost
of production at some plants in Nebraska, ratepayers have not fully benefited from the more than $1
billion saved by lower electricity prices from the SPP IM. Until Nebraska’s generation costs are reduced,
ratepayers will not benefit from the lower prices in the SPP IM.
• The cost effectiveness of Nebraska’s public power generation is currently at risk in the SPP IM. There
are two main reasons for this: (1) low natural gas prices; and (2) additional wind generation in the SPP
footprint.
• The financial risk to ratepayers in owning generation is increasing, as seen with the decommissioning
of the Fort Calhoun nuclear plant. Divesting from generating assets and embracing retail choice could
reduce ratepayers’ risk by eliminating the potential future costs of stranded assets.
• A more competitive energy landscape would allow consumers to choose among public and private power
providers in the state. This arrangement is commonly referred to as “retail choice.” In a competitive, retail
choice environment, Nebraska public power could pursue a strategy to divest from owning generating
assets, and instead, focus solely on the management and operation of transmission and distribution
systems. This would incentivize competition to produce from the cheapest sources of generation and
substantially reduce the ratepayer risk and uncertainly of owning generation in a changing energy market.
Page 46 Agenda Item #7b
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET
Page 1

[PAGE 47]
Section 1 - The Southwest Power Pool’s
Integrated Marketplace Challenges
Nebraska’s Public Power Model
Introduction
The SPP footprint recently expanded in
The Southwest Power Pool (SPP) is a October 2015 to include much of North Dakota
regional transmission organization (RTO) based and South Dakota, and parts of Montana.2 This
in Little Rock, Arkansas with approximately 600 expansion added 5,000 megawatts of demand and
employees. It covers all or parts of fourteen states: 9,500 miles of transmission lines. The expansion
Arkansas, Iowa, Kansas, Louisiana, Minnesota, added more wind production to the SPP footprint
Missouri, Montana, Nebraska, New Mexico, North and integrated market.
Dakota, Oklahoma, South Dakota, Texas and
In 2014, the SPP established a pooled
Wyoming.
marketplace, referred to as the Integrated Market
Figure 1.1 shows the SPP footprint. As
(IM), for buying and selling electricity to its Market
of June 2016, the SPP had 94 members and 175
Participants (MP). Market Participants in the IM are
market participants (See Appendix A). Several
members of the SPP, which consists of private and
Nebraska Public Power utilities own transmission,
public utilities, independent power generators, and
including the Nebraska Public Power District (NPPD)
retail providers. The purpose of the IM is to optimize
and the Omaha Public Power District (OPPD). NPPD
generation to meet the demand for the SPP footprint
and OPPD joined the SPP in 2009.
by determining which generation is dispatched for
maximum cost-effectiveness.
Figure 1.1: SPP Footprint, 2016
Source: SPP
2http://www.spp.org/about-us/newsroom/southwest-power-
pool-expands-electric-grid-management-to-14-states/.
Page 47 Agenda Item #7b
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET Page 2

[PAGE 48]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
When the IM became operational in 2014,
Since the start of the SPP
the SPP consolidated 16 balancing authority areas
into a single balancing authority. This meant that
integrated marketplace,
the SPP, instead of the individual SPP members,
became responsible for balancing the supply and estimated electricity cost
demand to ensure reliability over the entire SPP
savings to MPs have totaled
footprint. SPP does not own the transmission grid
but independently operates it to ensure reliability,
more than $1 billion.
and manages long-term planning for future
needs. The SPP members continue to own their
transmission systems within the SPP footprint.
How is the SPP market price
Essentially, electricity is a commodity that is determined?
traded like any other commodity. In the Integrated
In the integrated market, each market
Marketplace, the SPP acts as the market operator,
participant bids in generation to supply their
responsible for clearing transactions. As a market
forecasted load for the following day as required
operator, the SPP determines which power is bought
by the SPP. The MP does not have to submit 100%
and sold based on current demand (load) and supply
of its forecasted load into the day-ahead market; a
from electricity generators located throughout the
portion of the forecasted load can be submitted into
power pool footprint.
the day-ahead market and the remaining portion
The IM has a day-ahead market, where the
of the load can be purchased from the real-time
market price changes hourly, and a real-time market,
market.
where the market price changes every 5 minutes.
Market participants bid generation into
MPs can either submit load and generation into
the IM based on their marginal cost of production,
either the day-ahead or real-time market.
as allowed by SPP requirements. The generation
A total of 83,465 megawatts (MW) of
bid amount does not include any fixed costs. The
generation capacity is available from 756 generating
following terms used for the SPP IM are defined for
plants participating in the SPP integrated market.
the purposes of this report:
This currently provides a reserve capacity of 28% to
Generation. Generation is the ability of
ensure that the SPP can reliably meet demand for
power plants to generate electricity that is bid into
electricity during extreme peak times when loads
the SPP IM. Generation is also known as capacity,
are high.
which is the amount of generation that a power
To put this in perspective, all the current
plant is capable of producing at a given moment
generation in Nebraska could be eliminated and
in time. For instance, if a 1,000 MW power plant is
the excess reserve capacity in the SPP integrated
sitting idle and is capable of producing 1,000 MW of
market would be enough to supply all customer
electricity if called upon (dispatched), then it would
demand in Nebraska.
have 1,000 MW of capacity that could be bid into the
The SPP IM does not select generation SPP IM. If the same 1,000 MW power plant could
based on fuel type but on bid price and reliability. only produce 800 MW of electricity, if called upon,
The market determines the winners and losers of due to being derated, then it would only have 800
generation based on the marginal production cost, MW of capacity available to bid into the SPP IM, not
which does not include any fixed costs. 1,000 MW.
Since the start of the SPP integrated There are three types of generation:
marketplace, estimated electricity cost savings to baseload, intermediate, and renewable. Baseload
MPs have totaled more than $1 billion.3 generation is either fossil fuel or nuclear that are
designed to operate at a constant output.
3https://www.spp.org/about-us/newsroom/total-savings-from-
spp-s-markets-cross-the-1-billion-mark/.
Page 48 Agenda Item #7b
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET Page 3

[PAGE 49]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
Intermediate generation is designed Generation or Capacity Cost. This is the
to change output more quickly than baseload difference between the cost of production and
generation and is used when the demand for the SPP market price at the generator’s pricing
electricity changes. node (Annual Cost of Production - Annual Revenue
from the SPP IM). This is the cost to the Market
Renewable generation output is based on the
Participant for owning the generation. If the cost of
conditions (wind and sun) at any given time. Due to
production is more than the SPP market price, the
variable weather conditions, renewable generation
cost must be passed through to the ratepayers in
cannot always generate at 100% of its rated output,
the rates.
SPP credits 10% of its rated output for capacity in
the SPP IM. If a power plant that produces 6.8 million
megawatt-hour (MWh) of electricity annually
Marginal Cost of Production (or Incremental
with a cost of production of $306 million, and the
Energy Cost). This is the incremental cost of a
average annual SPP market price is $20/MWh, the
generator to produce electricity. This includes fuel
generation cost for that year that must be passed on
and variable operations and maintenance (O&M)
to the ratepayers is $170 million ($306 million - (6.8
costs. Variable O&M costs are costs for items that
million x $20)).
are needed to produce electricity, but not needed
when the plant is sitting idle. The marginal cost of The SPP combines the forecasted load
production changes due to the plant’s efficiency (demand) of all market participants to determine
at different outputs. The plant does not incur the how much generation is needed to provide the
marginal cost of production when the plant is not most cost-effective and reliable combination of
producing electricity. generation to be dispatched the following day.
Fixed Cost. This is the generator’s cost For example, Figure 1.2 shows the
that does not change based on the output of the forecasted load (demand line) and generation
generation. This cost would be the same if the plant (supply curve) intersecting at the CCGT2 generator.
was sitting idle or operating at 100% of its capacity. The SPP will dispatch CCGT2 and all the generation
Fixed costs include items like labor, debt service, units left of CCGT2 (i.e. the generators with the
routine maintenance, facilities, and corporate lowest marginal cost of production: CCGT1, Coal,
charges. Lignite, Nuclear, Hydro, and Wind). In the day-ahead
market, the forecast load and generation are bid
Cost of Production. This is the total cost
(offered) in hourly so the dispatch of generation
of generation, which is sometimes referred to as
and IM price changes hourly. If an MP’s generation
busbar cost. Cost of production includes both the
isn’t selected to be dispatched for any hour in the
marginal cost of production and fixed cost.
day-ahead market, the MP can bid their generation
SPP IM Market Price. This is the price into the real-time market using the same bid criteria
established by SPP based on the generation and as the day-ahead market. The MP is not required to
load submitted by the SPP Market Participants submit their total forecasted load in the day-ahead
into the SPP IM. The Market Participants purchase market; load can be purchased from the real-time
electricity from the SPP IM at their purchase node. market at the real-time market price.
For Nebraska public power, the SPP North Hub is
The market price in the integrated market
used for pricing the electricity that is purchased.
is determined by the price of the next available
Generation that is dispatched by SPP receives the
generator that could be dispatched at the forecasted
market price for their electricity at the SPP pricing
demand (see Figure 1.2). The graph shows the
node for the generation’s location. Each generation
forecasted load (demand) and generation (supply)
source in the SPP footprint has an SPP pricing node.
curve intersect at CCGT 2’s marginal cost of
Since cost data isn’t available for Nebraska public
production. At this intersection point, the market
power generation, the SPP North Hub market pricing
price is established at the bid price (i.e. marginal
will be used in this report.
cost of production) of CCGT 2. If the market
bid price for CCGT 2 was $23.74/MWh, then all
Page 49 Agenda Item #7b
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET Page 4

[PAGE 50]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
Figure 1.2: How the supply and demand of electricity signals price based on the dispatch order of
different generation assets
Source: Goss & Associates
generation bids in the day-ahead market with lower as the marginal fuel supply, lower natural gas prices
marginal cost of production than CCGT 2 (left of the put downward pressure on the wholesale market
Demand line) would receive the same market price price in the SPP’s IM.
of $23.74/MWh for that hour.
As explained above, it becomes increasingly
Since the IM bid (offer) price for generation important to own generation (capacity) with the
is based on fuel price, the dispatch order can lowest cost of production, not the lowest marginal
change depending on fluctuations of fuel prices for cost of production, when participating in the SPP
different forms of generation. Due to the current integrated market. The MP’s customers must make
generation mix and low gas prices in the SPP up the difference between the cost of production
footprint, gas-fired generation is on the margin, and the market price.
meaning that gas generators are typically the last
Figure 1.3 profiles the relationship between
generation units dispatched during high demand
the price of natural gas and SPP wholesale
(on-peak) periods.
market prices. The data supports a strong positive
During periods of very low demand (off- association between the price of natural gas
peak), it is possible that the SPP IM price can and SPP market prices. In fact, the correlation
go negative because there is more supply than coefficient between natural gas prices and SPP
demand. Excess supply is created when large market prices from January 2012 to December 2014
baseload plants (e.g. coal and nuclear) are unable was 0.87 indicating that the two move in almost
to change output levels fast enough to react to lockstep.4
changes in demand. Gas and renewable generators
have the ability to rapidly adjust output, making
them better able to capitalize on changing market
conditions.
4The linear correlation coefficient, measures the strength and
the direction of a linear relationship between two variables, in
Natural gas prices have trended downward
this case natural gas prices and SPP prices. The value ranges
since the second half of 2008. Since electricity
between -1.0 and +1.0. A larger the value, the greater the
produced from gas-fired generators are dispatched association (e.g. +1.0 indicates two variables move in perfect
lock step such as farenheit and centigrade temperature).
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET Page 5
noitcudorP
fo
tsoC
lanigraM
Generation Fuel types
Page 50 Agenda Item #7b

[PAGE 51]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
Figure 1.3: Natural gas prices and SPP day ahead locational market price, Jan. 2012- Nov. 2014
Source: Goss & Associates, SPP and Federal Reserve of St. Louis
Table 1.1 lists the electricity capacity It also supports the hypothesis that
and consumption by fuel type. As indicated, the electricity producers have reduced utilization
consumption and capacity of coal generation has (capacity factor) of electricity plants fueled by
steadily declined, although coal consumption has coal.5 Likewise, the consumption of natural gas has
declined more significantly than the capacity. This risen more dramatically than capacity. On the other
indicates that utilities in the region have not altered hand, wind generation has expanded steadily and
their generation mix capability as fast as market significantly over that time period.
conditions dictate.
Table 1.1: SPP capacity (2013-2015) and consumption (2013-2016) by fuel type
Type 2013 2014 2015 2016 (rolling 365)
Coal Capacity 34.1% 35.4% 33.3%
Coal Consumption 61.2% 58.8% 55.1% 47.9%
Natural gas Capacity 42.0% 46.5% 42.6%
Natural gas Consumption 21.2% 18.9% 21.6% 23.4%
Nuclear Capacity 3.3% 3.4% 3.2%
Nuclear Consumption 6.0% 7.9% 8.1% 8.0%
Wind Capacity 10.0% 11.5% 14.9%
Wind Consumption 10.8% 11.8% 13.5% 16.7%
Hydro Capacity 4.6% 1.1% 4.1%
Hydro Consumption 0.6% 2.5% 1.5% 3.7%
Other Capacity 26.8% 20.8% 23.1%
Other Consumption 0.6% 2.5% 1.5% 0.3%
Source: SPP
5For example, a 1,000 MW coal plant operating at an 80%
capacity factor would produce 7.0 million MWH of electricity
in a year (1000*.80*8760). For a 70% capacity factor it
would generate 6.1 million MWH of electricity in a year
(1000*.70*8760).
Page 51 Agenda Item #7b
NEBRASKA PUBLIC POWER’S COMPETITIVENESS IN THE REGIONAL ENERGY MARKET Page 6

[PAGE 52]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
There are currently more than 12,000 MW of fuel cost on the margin, then it will have no effect on
wind generation in the SPP footprint. The addition market prices, but if it is below, one can expect the
of renewable generation and the retirement of coal market price to increase.
and nuclear generation has impacted the market
Effect of SPP Integrated Market on
price. Since the fuel cost of wind energy is zero, and
is dispatched first in the day-ahead market, wind Nebraska’s Public Power
generation lowers the market price by displacing
Prior to the SPP Integrated Market becoming
generation with higher fuel cost. The retirement of
operational in March 2014, Nebraska public
nuclear generation, however, will increase market
power was responsible for dispatching their own
prices because nuclear has lower fuel costs than
generation to match their load. They also acted as
generation currently on the margin (gas-fired). The
the balancing authority for Nebraska.
effect on market prices from the retirement of coal
plants depends on whether the fuel cost is above or This meant that nearly all generation
below the fuel cost on the margin. If it is above the from power plants in Nebraska was used to
serve the native load in Nebraska. Therefore, the
Since the fuel cost of wind cost of production (fuel, variable operations and
maintenance, and fixed) for generation was passed
energy is zero, and is dispatched
along to customers through rates.
first in the day-ahead market, For an illustration of generation costs,
see table 1.2. Note: the following information are
wind generation lowers the
approximations based on the best information
available for various plant types. Nebraska public
market price by displacing higher
power has denied a request for information
fuel-cost generation. concerning generation costs so actual cost data is
not being used.
Table 1.2: Breakdown of generation costs for specific types of power plants
Marginal Cost of Cost of Production
Plant Type Size (MW) Fixed Cost ($/MWh)
Production ($/MWh)* ($/MWh)
Large Coal 1,350 13.15 13.20 26.35
Small Coal 225 21.00 33.85 54.85
Nuclear 800 8.90 36.10 45.00
Combined Cycle 250 42.75 117.80 160.55
Wind 300 0.00 20.00** 20.00**
* This would be the generation bid price in the SPP Integrated Market
**This would be the Power Purchase Agreement (PPA) price
The cost for each type of generation ratepayers were paying prior to 2014, when the SPP IM went
operational, is as follows:
Table 1.2a: Cost for each type of generation ratepayers were paying prior to 2014, when the SPP IM went operational
Annual Output Cost of Annual Energy and
Plant Type
(MWh) Production ($/MWh) Demand Cost ($)
Large Coal 9,650,000 26.35 254,277,500
Small Coal 1,120,000 54.85 61,432,000
Nuclear 6,800,000 45.00 306,000,000
Combined Cycle 137,000 160.55 21,995,350
Wind 1,314,000 20.00 26,280,000
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[PAGE 53]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
Prior to the SPP IM, and based on the costs in table 1.2a above, ratepayers would be charged
$669,984,850 for their public power utility to provide them with electricity. If a utility sold 19,021,000 MWh, the
generation cost (energy and demand) would have been $35.22/MWh.
After the SPP went operational in 2014, energy and demand costs are separate, as illustrated in Table
1.2b. Note: for simplicity and illustration purposes, the 2015 SPP North Hub average market price is being
used; in reality, every generation in SPP has a market price node for their location.
Table 1.2b: Energy and demand costs
Large Coal Small Coal Nuclear Combined Cycle Wind
Cost of Production
$26.35 $54.85 $45.00 $160.55 $20.00
($/MWh)
2015 Average Market
$20.28 $20.28 $20.28 $20.28 $20.28
Price1 ($/MWh)
Annual Output (MWh) 9,650,000 1,120,000 6,800,000 137,000 1,314,000
Demand Cost ($/MWh) $6.07 $34.57 $24.72 $140.27 -$.08
Annual Demand Cost2 $58,575,500 $38,718,400 $168,096,000 $19,216,990 -$105,120
Annual Demand Cost3 $44,389/MW $172,082/MW $210,120/MW $76,867/MW -$350.40/MW
1 Energy Cost
2 Annual Cost to for generation that must be paid by the ratepayers as a demand cost
3 Annual Demand Cost ($) divided by Generation Size
The Demand Cost ($/MWh) does not provide much value, the Annual Demand Cost is what is
important since this amount must be included in the rates that the ratepayers must pay. The Annual Demand
Cost expressed in $/MW is also important for determining the capacity cost relative to other types of
generation . As shown in Table 1.2b, nuclear generation is the most expensive generation capacity.
Using the information from the Table 1.2b above, the SPP market price is the energy cost. The capacity
or demand cost for the utility’s total generation is $284,501,770/year or $14.94/MWh. The total energy
and demand cost remains, as before the SPP IM went operational, at $35.22/MWh. As the energy price
(SPP market price) decreases the demand cost for generation increases because the difference between
the marginal cost of production and the market price isn’t high enough to further offset fixed costs. If the
generation’s cost of production was lower than the market price, the generation would have negative demand
cost and would have a positive cash flow.
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[PAGE 54]
SECTION 1 - THE SOUTHWEST POWER POOL’S INTEGRATED MARKETPLACE CHALLENGES NEBRASKA’S PUBLIC POWER MODEL
Since the SPP IM went operational in March 2014, Nebraska public power no longer dispatches their
own generation to supply electricity to their customers. Instead, they purchase power from the market, either
day-ahead or real-time, which is supplied from generators within the SPP footprint with the lowest marginal
cost of production (fuel and variable O&M). See Appendix B for an illustration on how the SPP Integrated
Market works for generation and supplying electricity to market participants.
When the SPP market price is lower than Nebraska public power generation’s marginal cost of
production, the generation assets remain idle and Nebraska’s public power utilities purchase electricity from
the IM at a cost lower than their generation can produce it because they will not be incurring the marginal
cost of production. Purchasing electricity from the SPP IM when the market price is lower than the MP’s
generators marginal cost of production saves the MP money and should ultimately save the ratepayer money
because the MP is purchasing electricity cheaper than the cost of self-dispatching their generation to provide
electricity to their customers, which they did prior to the SPP IM.
Table 1.3 shows the average SPP market prices since the IM went operational in March of 2014. As
shown, the market price has been lower every year since becoming operational. This is due mostly to the
increase of wind generation in the SPP footprint and low natural gas prices.
Table 1.3: Average SPP market price
Average SPP market price (North hub)
2014 (As of March 1) $28.06
2015 $20.28
2016 (thru June) $17.34
Source: SPP
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[PAGE 55]
Section 2: Threats facing Nebraska’s Public
Power Generation
Introduction
footprint.7 The SPP will have nearly 17,000 MW of
The cost effectiveness of Nebraska’s public
installed wind by the end of 2016, up from 12,397
power generation is currently at risk in the SPP IM.
MW in 2015. An additional 2,000 MW is expected
There are two main reasons for this: (1) low natural
to be installed in 2017. As more wind energy is
gas prices; and (2) additional wind generation in the
produced, there is risk that Nebraska’s coal plants
SPP footprint.
will sit idle more often, less able to recover fixed
Low natural gas prices keep the SPP IM
costs, as electricity is dispatched from wind
market price low. Gas-fired generators are the
generation first, and mainly from other states within
marginal supply, so bids from those generators
the SPP footprint.
typically sets the market price. Lower fuel costs
for natural gas generators lead to lower bids in Excess Coal and Nuclear Generation
the market since fuel is a major contributor to the when Natural Gas is Cheap
generator’s bid price.
Nebraska’s generation portfolio has a higher
Low market prices threaten the
coal and nuclear mix relative to the SPP generation
competitiveness and ultimately the value of coal and
mix. Table 2.1 shows the breakdown of NPPD’s
nuclear assets owned by Nebraska public power.
and OPPD’s generation mix compared to the SPP
The second threat comes from additional generation mix. NPPD and OPPD combined have
wind generation in the SPP footprint.6 Wind half the wind percentage and nearly 20 percent
displaces higher cost fossil fuel generation when more coal capacity than the SPP generation mix.
SPP dispatches generation. Significant increases in
wind generation are expected in the SPP
Nebraska’s generation portfolio has a higher coal and
nuclear mix relative to the SPP generation mix.
Table 2.1: Generation Mix comparison between NPPD and OPPD and the total SPP mix, 2015
NPPD and OPPD Generation Mix SPP Generation Mix
Coal 52.2% 33.3%
Natural gas & oil 18.8% 42.6%
Nuclear 19.0% 3.2%
Wind 7.0% 14.9%
Other 3.1% 6.2%
Total 100.0% 100.0%
Source: SPP, NPPD, and OPPD Annual Reports
6Wind generation as a percentage of supply in the SPP contin-
ues to set records, with penetration now exceeding 40 percent 7The SPP estimates that it can reliably handle up to 60
on certain days: http://www.platts.com/latest-news/electric- percent wind penetration: https://www.spp.org/docu-
power/houston/us-southwest-power-pool-sets-new-wind-peak- ments/34200/2016%20wind%20integra¬tion%20study%20
record-21139345. (wis)%20final.pdf.
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[PAGE 56]
SECTION 2: THREATS FACING NEBRASKA’S PUBLIC POWER GENERATION
Baseload capacity, like coal and nuclear, NPPD generates more than four million MWh
is expected to continue to decrease in value as of excess generation (more electricity is sold to the
wind generation capacity increases in the SPP.8 SPP market than purchased from the SPP market to
For example, in September 2016, NPPD’s Sheldon serve their customers). In 2015, NPPD’s generation
Station went offline because the SPP’s wholesale capability (capacity) was 3,660 MW and system
market price was lower than its marginal cost of peak load was 2,695 MW.10 Since SPP requires
production. It doesn’t make economic sense to burn Market Participants have generation capacity for
the fuel to produce electricity which would have 112% of their peak load, NPPD had 642 MW of
been sold below the fuel cost. Fixed costs, however, excess capacity. This excess generation would be at
are still incurred while the plant sits idle. produced from NPPD’s Cooper Nuclear Station since
this is NPPD’s generation with the highest annual
cost of production.
Baseload capacity like coal and
Even when market prices are above the
nuclear is expected to continue
generation’s marginal cost of production, low
market prices result in less revenue to help offset
to decrease in value as wind
the fixed cost of generation. OPPD’s decision
generating capacity increases in to shut down the Fort Calhoun station can be
seen as an indication of low forecasted market
the SPP.
prices in the SPP. OPPD determined that incurring
decommissioning costs of over $1 billion today was
more cost effective than shortfalls in covering fixed
OPPD recently took action to shut down costs while keeping the station operating.11
Fort Calhoun Nuclear Station (FCS) because of its
The price of natural gas has reached
high cost of production and low SPP wholesale
near record lows in 2016. This has driven SPP
market prices. In 2015, OPPD’s generation capability
IM wholesale market prices below $20/MWh for
(capacity) was 3,080 MW and system peak load
several months this year. Figure 2.1 shows this
was 2,315 MW.9 With SPP requirements to have
year’s monthly gas price (right axis) compared to the
generation capacity for 112% of peak load, OPPD
average monthly wholesale market prices (left axis)
had 487 MW of excess capacity with FCS. Shutting
in the SPP IM.
down FCS will decrease excess generation and
reduce generation costs to OPPD ratepayers.
If additional generation is needed due to
FCS being shutdown, OPPD can either replace The price of natural gas has
the generation, by building new generation or
reached near record lows in
contracting generation from another supplier, with a
lower annual cost of production.
2016. This has driven SPP IM
wholesale market prices below
$20/MWh for several months
8Energy Information Administration (EIA), ‘Higher wind 10NPPD Financial and Sustainability Report, 2015 (http://www.
nppd.com/assets/publications/2015FinancialSustainabilityRep
generation in the Southwest Power Pool is reducing use of
ort/files/assets/basic-html/page-1.html#).
baseload capacity’, http://www.eia.gov/today-inenergy/detail.
php?id=12831. 11http://www.oppd.com/news-resources/news-releases/2016/
9OPPD quick facts: http://www.oppd.com/media/216550/quick- june/oppd-board-votes-to-decommission-fort-calhoun-
facts.pdf. station/.
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[PAGE 57]
SECTION 2: THREATS FACING NEBRASKA’S PUBLIC POWER GENERATION
Figure 2.1: SPP IM wholesale market prices versus the cost of natural gas
Source: SPP State of the Market Report, Summer 2016
The future price of natural gas is uncertain, In October 2015, the SPP expanded its
but projections of supply growth versus demand footprint to cover most of North Dakota and
growth in the United States indicate that excess South Dakota, and parts of Montana. This added a
supply from shale will remain. Projections by substantial amount of wind generation to the SPP,
the U.S. Energy Information Administration raising wind generation as a percentage of total
(EIA) indicate that by 2020 domestic supply will generation resources. As a result, more wind is
substantially outpace domestic consumption, now available to dispatch prior to other sources of
making the U.S. a net exporter.12 Expect excess generation.
domestic supply to put downward pressure on the
In addition, wind generation in the SPP
price of natural gas.
footprint is currently growing and is expected to
Although U.S. energy policy is uncertain continue to grow because of the recently renewed
going forward, the potential implementations federal renewable electricity production tax credits
of regulations from the Clean Power Plan could (PTC). The PTC is an inflation-adjusted per-kilowatt-
continue to increase the cost of production of fossil hour (kWh) tax credit for electricity generated by
fuel generation. With Nebraska’s heavy reliance on qualified energy resources. The electricity must
coal, there is a presence of regulatory risk. be sold by the producer to an unrelated person or
organization. Originally the duration of the credit
Renewables Displace Baseload
was 10 years for all facilities placed into service
Generation after August 8, 2005.
The growth in low-cost wind generation in In December 2015, Congress passed
the SPP footprint is putting downward pressure on the Consolidated Appropriations Act, which
the SPP IM wholesale market prices. As the amount extended the expiration date for this tax credit to
of wind generation increases throughout the SPP December 31, 2019, for wind facilities commencing
footprint, expect this low-cost source of generation construction. For 2016, the inflation adjustment
to drive down average wholesale market prices in factor used by the IRS is 1.556, resulting in a 2016
the SPP IM as it displaces fossil-fueled baseload calendar year tax credit amount of $0.023/kWh. The
generation. tax credits do, however, phase down with projects
commencing construction after December 31, 2016.
12http://www.eia.gov/pressroom/presentations/siemin-
ski_06282016.pdf..
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[PAGE 58]
SECTION 2: THREATS FACING NEBRASKA’S PUBLIC POWER GENERATION
The tax credit phase-down for wind facilities
Since the private wind developer
is a percentage reduction in the tax credit amount
listed above: (a) for wind facilities commencing
can receive tax credits, the price
construction in 2017, the PTC amount is reduced
by 20 percent, (b) for wind facilities commencing of PPAs incorporate those cost
construction in 2018, the PTC amount is reduced by
savings, allowing Nebraska
40 percent, and (c) for wind facilities commencing
construction in 2019, the PTC amount is reduced
Public Power to indirectly benefit
by 60 percent. The duration of the credit is 10 years
after the date the facility is placed in service.13 from overall cheaper wholesale
These recently renewed tax credits are
prices of electricity.
incentivizing wind generation investment throughout
the SPP, putting downward pressure on the IM
wholesale price. Nebraska’s public utilities do
PPAs to purchase wind energy are currently
not pay taxes and therefore are unable to directly
averaging $20/MWh in the interior states, according
benefit from tax credits. However, in most cases,
to recent analysis by the Berkeley Lab and the U.S.
wind generation is purchased from a private wind
Department of Energy.14 PPAs at this price are
developer through a Power Purchase Agreement
significantly less than NPPD’s and OPPD’s average
(PPA).
generation cost of production, and below the average
2015 SPP IM wholesale market price.
These recently renewed
The growth of wind generation throughout
tax credits are incentivizing the SPP will displace baseload generation in the
dispatch order, raising the risk that baseload plants
wind generation investment
sit idle more often. This will raise the overall costs to
own those types of plants, since revenue will not be
throughout the SPP, putting
generated to help offset fixed costs. This increases
downward pressure on the IM the risk that costlier generating assets will be forced
to close as demand for baseload will not keep pace
wholesale price. with this additional generation capacity.
The growth of wind generation
Nebraska’s public power benefit from federal
tax credits indirectly because they are factored
throughout the SPP will displace
into the PPA price along with any other capital or
fixed costs incurred by wind generators. The PPA baseload generation in the
price for electricity can be thought of as the cost
dispatch order, raising the risk
of production when comparing to other types of
generation.
that baseload plants sit idle
more often.
13Renewable energy facilities placed in service after 2008 14PPAs for wind in the interior states have a significant cost
and commencing construction prior to 2015 (or 2020 for wind advantage to the rest of the nation. In 2013, wind PPAs signed
facilities) may elect to make an irrevocable election to claim the in the interior states averaged between $20-$25, whereas the
Investment Tax Credit (ITC) in lieu of the PTC. Wind facilities Great Lakes region averaged above $40 and the West and
making such an election with have the ITC amount reduced by Northeast region averaged above $50: http://energy.gov/sites/
the same phase-down specified above for facilities commenc- prod/files/2016/08/f33/2015-Wind-Technologies-Market-Report-
ing construction in 2017. Presentation.pdf.
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[PAGE 59]
SECTION 2: THREATS FACING NEBRASKA’S PUBLIC POWER GENERATION
Since wind generation is intermittent, it only It is true that Federal Tax Credits are a key
receives capacity in the SPP integrated market for driver of the expected growth in wind generation
only 10 percent of its nameplate capacity (i.e. 10 throughout the SPP footprint. After the tax credits
MW for a 100 MW wind farm). This is unlike other expire, expect investment in wind to lessen.
types of generation, which receive credit for the full However, cost of wind generation is falling rapidly
amount of nameplate capacity. Wind generation is and is expected to become competitive, even
bid into the SPP IM the same as other generation, without tax credits, relative to new builds of other
but the credit counted toward market capacity forms of energy.16
requirements is different.
If new generation (capacity) is needed to
This is done to ensure that there is enough supply demand growth in the future, expect wind
generation available when the wind does blow. and solar to compete with new builds of coal,
Expect the SPP to consider larger capacity credit for natural gas, and nuclear.17 The cost of solar has
wind in the future as energy storage technologies fallen rapidly in recent years due to increases in
advance to alleviate intermittency concerns.15 investment worldwide.18
This will further decrease the value of baseload
generation.
16Lazard estimated that the unsubsidized levelized cost of en-
ergy for wind has decreased 61 percent from 2009 to 2015. The
unsubsidized levelized cost of energy for solar has decreased
82 percent during that same period. New wind builds, unsubsi-
dized, now average between $32-$52/MWh, compared to new
coal at $61-$150/MWh and new natural gas at $52-$78/MWh.
17The EIA projects that in 2022 the LCOE for wind and solar will
be $64.50/MWh and $84.70/MWh, respectively, compared new
builds of coal to be $139.50/MWh and nuclear to be $102.80/
MWh. New builds of natural gas LCOE is expected to range from
$57-$84/MWh: https://www.eia.gov/forecasts/aeo/pdf/electric-
ity_generation.pdf .
15Although unproven in the market, industrial-sized batter- 18The learning curve (i.e. production cost decrease) for solar
follows a trend called Swanson’s Law. Swanson’s Law is the
ies have seen some traction at the utility level. Tesla recently
observation that the cost of solar decreases 20 percent every
signed a deal to supply a California utility with industrial
time the cumulative shipped volume of photovoltaics doubles.
capacity lithium batteries to reduce intermittency concerns
Worldwide shipments of photovoltaics are growing fast, led by
from renewables: http://www.bloomberg.com/news/ar-
investment in Asia, with a compounded annual growth rate of
ticles/2016-09-15/tesla-wins-utility-contract-to-supply-grid-
42 percent from 2000-2015: https://www.ise.fraunhofer.de/de/
scale-battery-storage-after-porter-ranch-gas-leak.
downloads/pdf-files/aktuelles/photovoltaics-report-in-englisch-
er-sprache.pdf.
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[PAGE 60]
Section 3: A Case for Retail Choice in
Nebraska: The effect on electric rates,
reducing ratepayer risk, and the need for
greater transparency using unbundled billing
A Case for Unbundling and Retail Choice in These functions were all turned over and are now
the responsibility of the SPP.
Nebraska
As part of being members of the SPP,
Nebraska public power has changed
Nebraska public power no longer maintains the
significantly since 1936 when public power was
reliability of the transmission system in the state.
established to provide power to rural customers
Transmission owned by Nebraska public power
in Nebraska. More changes came when Nebraska
is regulated by the Federal Energy Regulatory
public power joined the Southwest Power Pool in
Commission (FERC). In 1996, FERC issued Order
2009 and began participating in the SPP Integrated
888 to provide “open access” to transmission at
Market in 2014, where they now buy and sell
non-discriminatory rates to third-party electricity
wholesale electricity.
providers to allow for a competitive wholesale
Today with competitive wholesale energy electricity market.
markets, electricity is no longer a natural monopoly.
What this means is that private electricity
Transmission and distribution systems, however,
generators (e.g. wind farms) or power marketers
do remain for the most part natural monopolies
are able to use transmission infrastructure owned
because it is typically not economical to duplicate
by Nebraska public power for a regulated, set rate,
transmission and distributions systems in a given
which is non-discriminatory. This open-access
area. Providing electricity and being a transmission
infrastructure makes retail choice possible, where
owner are two completely different business
private power marketers with access to competitive
models, and as such it makes no sense for them to
generation and/or lower overhead costs can
be bundled together.
participate in the electricity market and potentially
Participating in a competitive wholesale provide more competitive options to ratepayers in
market involves much risk and uncertainty, whereas the state.
being a transmission owner involves little risk
Furthermore, according to Nebraska
(mainly weather events) since the same amount of
legislative research, three conditions must be met
electricity is transported through the transmission
for customer (retail) choice to be effective and
system regardless of who is providing the electricity.
beneficial to the citizens of Nebraska.19 They are:
This is also holds true for the distribution system.
The transmission and distribution system owner has • A viable regional transmission organization and
the responsibility for maintaining their system to adequate transmission must exist in Nebraska
deliver electricity from the wholesale market to the or a region that includes Nebraska;
end-use (retail) customer.
• A viable wholesale electricity market must exist
In 2009, when Nebraska public power joined in a region that includes Nebraska;
the SPP, Nebraska was no longer an electricity
• Wholesale electricity prices in the region must
island, but part of a much larger market-based RTO.
be comparable or competitive to Nebraska
The landscape changed even more dramatically
prices.
in 2014 when the SPP IM became operational. In
this environment, Nebraska public power no longer
dispatches power plants or supplies electricity 19Annual report – Monitoring of “Conditions Certain” Issues
2010 Report in Neb. Rev. Stat. 70-
to their customers with their own generation.
1002 (6) to (8), dated 2010.
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[PAGE 61]
SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
The report at the time stated that the first two conditions were satisfied and the last condition was not
satisfied. However, since the report was last issued in 2010, Nebraska public power has significantly raised
rates across the board and wholesale market prices have dropped significantly.
Figure 3.1 shows industrial rates in Nebraska compared to the United States from 2005 to 2014.
Compared to US averages, the industrial rate in Nebraska became more expensive in 2012. Comparing
Nebraska’s rates to the U.S. understates how uncompetitive the state is to the surrounding region, as
electricity rates on the East and West coast are usually significantly higher than the Midwest. Having
uncompetitive industrial rates is a deterrent for bringing and keeping companies in Nebraska.
Figure 3.1: Nebraska’s average industrial rate (cents per kWh) per year compared to the U.S.
2005-2014
Source: EIA
Wholesale market prices in the SPP IM are currently more competitive as well. Based on figures
reported in NPPD’s and OPPD’s annual report, SPP IM wholesale market prices are substantially below the
cost of production for NPPD’s and OPPD’s generation. As shown in Table 3.1, in 2015, NPPD had an average
generation cost of production of $28.21/MWh and OPPD had an average generation cost of $32.11/MWh.20
The 2015 average SPP IM day-ahead market price was $22.84/MWh and the real-time market price was
$21.68/MWh.21 The 2015 SPP average IM prices include both the North and South Hub. NPPD and OPPD
had generation cost of production that were 23.5 percent and 40.6 percent, respectively, higher than the SPP
IM day-ahead market price. Both the recent rise in rates for consumers and the decreasing market price of
wholesale electricity satisfy the third criteria listed above. Retail choice in Nebraska would be effective and
beneficial according to the guidelines of the legislative report discussed above.
As outlined in Section 2, lower wholesale market prices are the result of low natural gas prices and
more renewable sources of generation in the SPP footprint. Natural gas prices in 2017 are expected to remain
lower than the average price of the last five years.22 Renewable generation is expected to expand significantly
within the SPP footprint over the next few years due to the five-year extension of production tax credits.
Expect wholesale market prices to remain low as the renewable market matures and natural gas extraction
continues to provide plentiful supply.
This environment has resulted in wholesale market prices in the SPP IM dropping below the cost of
production of coal and nuclear generation, creating additional losses for those types of plants.
20Reported average NPPD and OPPD generation costs presented here due not include capital costs or debt servicing costs, therefore
these figures underestimate the true cost of generation, but still provide a conservative comparison for competitiveness to market
prices.
21These prices were averaged from the SPP North and South Hubs. Source: SPP State of the Market Report, Winter 2016; https://www.
spp.org/documents/37619/qsom_2016winter.pdf.
22https://www.eia.gov/forecasts/steo/report/natgas.cfm.
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[PAGE 62]
SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
Table 3.1: Comparison of NPPD and OPPD average generation costs versus the SPP 2015 integrated market
average prices
NPPD average generation cost $28.21
OPPD average generation cost $32.11
SPP IM day-ahead average price $22.84
SPP IM real-time average price $21.68
Source: SPP, OPPD and NPPD annual reports
The decision to decommission OPPD’s Fort This arrangement is commonly referred to
Calhoun nuclear plant depended partially on the as “retail choice.” In a competitive, retail choice
expectation that wholesale market prices in the SPP environment, Nebraska public power could pursue
IM would remain low, making the plant expensive a strategy of competing in the energy market or
to operate relative to other generation resources. divest from owning generating assets, and instead,
This controversial decision is a signal that OPPD’s focus solely on the management and operation of
leadership does not expect wholesale market prices transmission and distribution systems.
to return to levels where this nuclear station would
Retail choice would incentivize competition
be cost effective.
by owning generation with the lowest production
The financial risk to ratepayers in owning costs and maintaining low corporate overhead
generation is increasing, as seen with the shutdown costs. This would substantially reduce the risk and
and decommissioning of the Fort Calhoun plant. uncertainly to the ratepayer in a changing energy
Divesting from generating assets and embracing market.
retail choice could reduce ratepayers’ risk by
NPPD Wholesale Power Contact
eliminating the potential future costs of stranded
assets. In this case, stranded assets are generating Renewal
assets such as coal or nuclear plants that decrease
In 2015, many rural public power districts
in production value due to a change in the
and municipalities approved a new 20-year
economics of the industry.
NPPD 2016 Wholesale Power Agreement.23 This
agreement requires that those who approved the
Stranded assets are generating
contract to purchase the majority of their wholesale
assets such as coal or power requirement from NPPD who buys the power
from the SPP IM. The agreement does not specify
nuclear plants that decrease any price for the electricity but only a performance
criteria that allows the customer to decrease the
in production value due to a
required amount of electricity that is purchased
from NPPD if NPPD’s rates go up drastically.
change in the economics of the
Several of NPPD’s current wholesale
industry.
customers did not sign the NPPD 2016 Wholesale
Power Agreement, and decided instead to contract
Currently, inexpensive renewable generation, with other wholesale power providers.24 This is
greater environmental regulations, and an excess possible due to the competitive wholesale markets
supply of natural gas threaten the competitiveness and open access to transmission.
of Nebraska’s coal and nuclear plants, raising
the risk that more plants will become more
uneconomical in the future.
23NPPD 2016 wholesale power contract (http://info.cityoflex.
A more competitive energy landscape would
com/ccdocs/meeting/2015/October27/5C102715.pdf).
allow consumers to choose among public and
24http://www.omaha.com/news/nebraska/rising-rate-hikes-
private power providers in the state.
prompt-some-nppd-customers-to-look-to/article_d99e15f9-
e41d-58dc-8c3d-ac03c7cc36ec.html.
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[PAGE 63]
SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
The Cost Composition of Electricity Transmission Cost: This is the cost
the wholesale power provider pays to get the
Rates
electricity from the energy market to the wholesale
To understand how divesting from customer. Wholesale power is transported through
generation and embracing retail choice in Nebraska transmission lines. The wholesale power provider
would affect ratepayers, it is important to know the may or may not own the transmission lines. The
composition of electric rates and how each cost cost to use the transmission system is the same
component would be affected. for all wholesale power providers that uses the
transmission system.
Electric rates are made up of various
components that recover the electricity provider’s Distribution Cost: This is the cost the local
costs to deliver their product to the customer. The energy provider, usually a rural power district or
two major types of electric rates are wholesale and city, pays to get the wholesale electricity from the
retail. transmission system to the retail customer.
Wholesale Rate: Wholesale power is the Overhead: This is the cost that determines if
bulk electricity that is delivered by a wholesale the wholesale power provider’s rate is competitive,
power provider to the retail electricity providers for because the costs for electricity and transmission
resale to its customers. Bulk electricity is bought are essentially the same for all wholesale power
and sold into an energy market similar to other providers. Overhead costs include demand, debt
commodity markets. The major cost components service, administration, employee healthcare and
that go into a wholesale rate are: energy cost, pension plans.
demand cost, transmission cost and the wholesale
One other major component of overhead
power provider’s overhead. For NPPD in 2014, the
is demand (capacity) costs. As mentioned above,
breakdown for wholesale energy costs is; 47%
capacity is the ability to generate electricity that
Energy, 39% Demand, 10% Transmission, and 4%
can be supplied to the energy market at any given
other.
time when called upon to meet the market demand
Retail Rate: The retail rate is what the for electricity. The wholesale power provider must
end-use customer pays for electricity. There are either own or purchase capacity to meet the energy
typically three categories of retail rates that are market requirements for capacity (i.e. if a wholesale
based on electricity usage: industrial, commercial, power provider is going to purchase 100 MW of
and residential. Wholesale power is delivered to the electricity, then it must have at least 100 MW plus
retail customer by the local distribution entity after required SPP margin of capacity available).
adding on the distribution charge. Local entities are
It should be noted that just because a MP
often rural electric associations (REAs) or cities.
has 100 MW of capacity available, generation
The end rate paid by the retail customer is the retail
from another market participant might be used to
rate. The retail rate includes the wholesale power
produce the electricity needed to supply the MP’s
cost and distribution cost to the customer. The
100 MW load.
breakdown of the cost components of the retail rate
is generally: 60% wholesale electricity cost, 10% Generation or capacity cost is comprised of
transmission, and 30% distribution. the total expenses (fuel, operation & maintenance,
facilities, capital improvement, etc.) minus the
Electricity Cost: This is the cost the
revenue from selling the electricity generated to the
wholesale power provider pays to purchase the
energy market, such as an SPP integrated market.
electricity from the energy market. The energy
Capacity costs vary significantly depending on the
market updates the electricity price every hour in
type of generation (i.e. coal, nuclear, gas, renewable,
the day-ahead market and every five minutes in the
hydro).
real-time market. The average 2015 market price for
Nebraska public power was $20.28.
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SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
The Importance of Cost-Based Rates Unbundled billing improves transparency and
accountability by separating the cost components of
The electricity rates on a ratepayer’s most
the rate that the electric utilities charge. An example
recent bill might not represent the true cost of
of an unbundled bill is illustrated in Appendix C,
power. It is possible that a utility could defer costs
Example of an Unbundled Bill.
(i.e. pensions, retirement, decommissioning, debt,
etc.) into the future in order to avoid raising rates For example, an unbundled bill would show
in the present. These deferred costs, also known separate charges for energy, demand, transmission,
as unfunded liabilities, could expose customers to and distribution, supplemental charges, which all
unexpected higher rates in the future. contribute to the overall rate. Additional charges
such as decommissioning costs and metering
An unfunded liability exists when a utility
charges should also be included in a properly
incurs an expense but defers payment. If current
unbundled bill. This line-by-line billing information
rates are based on deferred expense, the rate
allows the ratepayer to scrutinize each component.
doesn’t represent the true cost of electricity today.
When rates increase, an unbundled bill would
Therefore, once those unfunded liabilities come
indicate the factors that caused it.
due, future customers will face higher rates, while
customers today obtain the benefit. Unbundled bills should be a staple in
public power districts and cities in Nebraska. As
An unfunded liability exists when a public power state, Nebraska’s ratepayers vote
for the board of directors of the public utilities
a utility incurs an expense but
that represent and serve them. A voter should
be informed by seeing which costs drive any
defers payment. If current rates
rate changes. Without this level of transparency,
are based on deferred expense, ratepayers lack the knowledge to make informed
decisions when electing the board of directors
the rate doesn’t represent the who have the fiduciary responsibility to hold
management accountable for decisions it has made.
true cost of electricity today.
The National Energy Marketers Association
(NEM) says that “proper rate unbundling is a
When the ratepayer is locked into a
prerequisite to sending proper price signals, to
monopolistic power provider and cannot choose
assist in making educated consumption decisions,
from whom they purchase electricity, the rate
and to permit suppliers to invest risk capital to make
should be cost-based to avoid receiving benefit
competitive product and service offerings available
from services they are not paying for. As described
to consumers.”25
above, deferred costs by an electricity provider
(public or private) are unacceptable for cost-based Increased transparency from unbundled
rates. If an electricity provider (public or private) billing is also important in today’s changing
makes bad business decisions, future ratepayers energy landscape because of competition from
suffer the outcome because there is no other option renewable sources of generation. The preference
for the customer to choose. The utility suffers no for renewables is often overshadowed by the
consequences in the form of lost customers as the assumed higher costs rather than recent objective
result of its decisions. data. Unbundled bills would give Nebraska
ratepayers insight into whether renewable sources
Providing Cost Transparency through
of generation are cost effective compared to current
Unbundled Billing sources such as coal and nuclear. Alternative
sources of generation, such as wind or solar, could
With several cost components making up
be offered by companies competing in a retail
an electric rate, it is important that consumers
choice environment.
understand what is driving any changes in their
rates. Consumers can gain insight into costs of 25https://www.energymarketers.com/Documents/nem_me_un-
electricity production through unbundled billing. bundling_ nal_cmts.pdf.
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[PAGE 65]
SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
Having the costs separated, particularly distribution and transmission, would allow consumers to
clearly compare prices of different energy providers. There is nothing physically (transmission or distribution)
to prevent retail choice from being implemented in Nebraska. With retail choice, the only thing that would
need to change would be a line item on the bill to show who the customer is purchasing electricity from. The
transmission and distribution cost would remain the same as it is currently, with local entities delivering the
electricity to the consumer. SPP is responsible for the planning and reliability of the transmission system.
All repairs would still be handled the same as they are today, by the local distribution or transmission system
owners.
Electricity is the competitive component of a customer’s bill, whereas other charges are non-
competitive; all retailers rely on the same transmission and distribution systems and incur the same charges.
In a retail choice environment, electricity providers compete on how efficiently they can supply a commodity:
electricity. Unbundled bills give clear information on who supplies electricity in the most cost-effective
manner.
Retail Choice in Practice
Seventeen states have adopted retail choice. The level of adoption differs, with some states allowing
full retail choice for all customers, and others providing it only to commercial and industrial customers. Retail
choice becomes more important as competing sources of electricity production enter the market. Without
retail choice, consumers are left with no other option than one with expensive rates if the monopoly utility
makes poor business decisions such as choosing the wrong portfolio of generating assets. Figure 3.2 shows
states that have implemented some form of retail choice.
Figure 3.2: States that have implemented retail choice
Source: EIA
Retail choice in Texas is administered by the Public Utility Commission through the website
powertochoose.org (see Appendix D). This site provides a good example of how retail choice could work
for residential, commercial, and industrial ratepayers in Nebraska. After entering a zip code, the ratepayer
is shown multiple competitive offers from different electricity retail providers available in their area. Offers
mainly differ in terms of price and contract length.
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[PAGE 66]
SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
Some contracts last only three months while
others last an entire year. This gives the ratepayer A retail choice environment
the option to lock in a current rate for an extended
promotes competition among
time, if that rate predictability is well-suited to their
budget. Some retail providers offer rates based on
suppliers and matches
the source of generation. This gives the ratepayer
the option to buy electricity from a retailer that preferences to consumers.
sources electricity entirely from renewables, if that’s
preferred.
If consumers prefer renewable sources
Some retail providers offer
of generation, a retail choice environment would
rates based on the source be able to match that preference effectively. A
competitive environment increases both productive
of generation. This gives the
and allocative efficiencies.26
ratepayer the option to buy Potential Cost Savings from Retail
Choice
electricity from a retailer that
The price of a retail rate is comprised
sources electricity entirely from of approximately 60 percent generation cost,
30 percent distribution cost, and 10 percent
renewables, if that’s preferred.
transmission cost. The ability of retail choice to
offer competitive rates is dependent on the costs of
each retailer’s owned generation mix and/or costs
of wholesale purchases. The conditions that can
Electric retailers offer different rates
affect wholesale energy costs can change rapidly,
because each company has its own strategy
and are variable throughout the state. For example,
when it comes to sourcing the most cost effective
the current market price for wholesale energy
sources of generation. Generation costs are based
supplied through wind PPAs has recently dropped
on many variables, most prominently fuel costs
to levels that are very competitive to other sources
and technological advances. Since those variables
of generation. Compared to the costs of owning
are unknown in the future, strategic decisions
and operating coal and nuclear plants, a retailer
should be made in an environment where market
that is able to quickly adapt and execute wholesale
forces dictate the allocation of capital, which is not
purchases in favorable market conditions would be
possible in a monopoly environment. The invested
in a more competitive position. The combination of
capital financed by ratepayers is at risk with
low-priced wholesale electric purchases and less
publicly-owned generation, whereas, in retail choice,
overhead expense, should allow providers to put
private investors bear the investment risk.
competitive downward pressure on rates in a retail
A retail choice environment promotes
choice environment.
competition among suppliers and matches
To illustrate the variability in retail rates
preferences to consumers. This ensures that the
throughout the state, see Appendices E and F.
most cost-effective strategy to procure generation is
available, which is passed on to consumers through
lower rates. Ineffective generation investment
strategies will be uncompetitive, ceasing to exist.
On the demand side, consumer choice is especially
important in being able to match production to
consumer preferences, especially in regards to
26Productive efficiency is the ability to produce at the lowest
environmental concerns.
cost. Allocative efficiency is the ability to match production with
consumer preferences. Market failures occur when the econo-
my fails to allocate resources efficiently.
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[PAGE 67]
SECTION 3: A CASE FOR RETAIL CHOICE IN NEBRASKA
In the competitive wholesale environment, According to the EIA, in 2015 Nebraska
power districts, cities, and regional utilities are able ratepayers paid more than $2.5 billion for
to seek out the lowest cost wholesale supply, as electricity.28 The ratepayer could save between
did twelve cities and a regional utility in Nebraska.27 $250-$400 million annually if retail choice was
For example, instead of NPPD, South Sioux City has permitted in Nebraska as demonstrated by the
signed a wholesale provider contract with a utility in public power districts and cities that chose to
Ohio and Northeast Nebraska Public Power District purchase their power from utilities outside of the
has signed with a provider in Kentucky. Nebraska Public Power System. Since the SPP
IM went operational, the competitive market price
This is because approximately 60 percent
for electricity has dropped 38% but Nebraska
of the retail rate a city or regional utility offers to
public power electric rates have not decreased. In
consumers is made up of the wholesale cost of
fact, many ratepayers are having to pay more for
electricity, so the cheaper they can procure this
electricity because NPPD and OPPD are increasing
electricity supply, the more cost savings they can
the customer charges due to sustained revenue
pass on to consumers.
shortfall from external market factors and lower
In contracting with cheaper wholesale customer usage.
providers, entities like Northeast Nebraska Public
The Nebraska Public Power Model currently
Power and South Sioux City have less costs incurred
is not effective in the SPP wholesale power market
with this wholesale supply component of the rate,
due to past and current decisions to build and
which can then get passed on to end users in the
maintain generation resources. With a wholesale
form of cheaper rates.
power market in place, the Nebraska Public Power
This explains some of the rate variability Model should be changed to allow free market
possible throughout the state. Similar competitive principles to work to lower electricity prices for
forces, as seen in the wholesale competitive market, the ratepayer. This would be consistent with the
could lead to additional downward pressure on rates findings of the legislative study for retail choice in
if applied to the retail environment. Nebraska.
27http://www.omaha.com/news/nebraska/cities-regional-utility-
turn-down-new-nppd-contracts/article_205502e9-d68b-5cf5- 28http://www.eia.gov/electricity/sales_revenue_price/
8c5c-23eecf9aa5ec.html.
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[PAGE 68]
Appendix A: SPP market participants
(source: https://www.spp.org/about-us/footprint/)
Alliant Energy Corporate Services, Inc. Flat Ridge 2 Wind Energy NSP Energy Trading
American Electric Power West Franklin Power Occidental Power Services
Appian Way Energy Partners Southwest, LLC Freepoint Commodities, LLC Oklahoma Gas & Electric Company
APX Galt Power Oklahoma Municipal Power Authority
Arkansas Electric Cooperative Golden Spread Electric Cooperative Omaha Public Power District
Associated Electric Cooperative, Inc. – Power Market Goodwell Wind Project Oneta Power
ATNV Energy, LP Google Energy Otter Tail Power Company
Automated Algorithums Grand River Dam Authority Peninsula Power, LLC
Basin Electric Power Cooperative GRG Energy Pharetram Energy Services, Ltd.
BioUrja Power, LLC Guzman Energy Powerex Corp.
BJ Energy H.Q. Energy Services US Public Service Co. of Colorado
Black Hills Power Harlan Municipal Utilities Public Service Co. of Colorado MISO MP
Black Oak Energy LLC Hastings Utilities Pure Energy
Blackout Power Trading Heartland Consumers Power District Rainbow Energy Marketing
Blue Canyon Windpower Hexis Energy Trading Resale Power Group of IOWA
Boston Energy Trading & Marketing High Majestic Wind II RPM Access LLC
BP Energy Company Iberdola Renewables Saracen Energy Midwest
Brookfield Energy Marketing LP Inertia Power III Seiling Wind LLC
Brookfield Renewable Energy Group Intergrid Midwest Group Sempra Generation
BTG Pactual Commodities (US) Invenergy Energy Management SESCO SPP Trading LLC
Buffalo Dunes Wind Project J. Aron and Company Shell Energy North America
Calicot Energy Kansas City Board of Public Utilities Smoky Hills Wind Project II
Calpine Energy Services Kansas City Power and Light Solea Energy, LLC
Canadian Woods Products Kansas Municipal Energy Agency Southern Company Services
Caney River Kansas Power Pool Southwestern Public Service
Canopus Power Trading, LLC Kentucky Municipal Power Agency Sunflower Electric Power
Cargill Power Markets Lincoln Electric System Sustaining Power Solutions
Carpe Diem Trading II Little Elk Wind Project SW Power Trading, LLC
Castleton Power Trading, LLC LM Power TEC Energy, Inc.
Chisholm View Wind Project Macquarie Energy Tenaska Power Services
Cimarron Wind Energy MAG Energy Solutions Tennessee Valley Authority
Citigroup Energy Marshall Wind Energy The Energy Authority
City of Chanute Mercuria Energy America Tios Capital, LLC
City of Fremont Merrill Lynch Commodities TPS1
City of Grand Island MET Southwest Trading TPS2
City of Independence, Mo. MidAmerican Energy Company TPS3
Conoco Phillips Midwest Energy TPS4
CP Bloom Wind Midwest Energy Trading East TPS5
Cumulus Master Fund Minco Wind TPS6
Darby Energy Minnesota Muncipal Power Agency TPS7
DC Energy Midwest Minnkota Power Cooperative, Inc. TPS8
DC Transco, LLC Missouri Joint Municipal Trailstone Power
Dempsey Ridge Wind Farm Missouri River Energy Services TransAlta Energy Marketing (U.S.) Inc.
Denver Energy Montana-Dakota Utilities Trumpet Trading LLC
Dogwood Power Management Monterey SW Tungsten Power LP
DTE Energy Trading Monterey SWF Twin Eagle Resource Management
Dufossat Capital VI Morgan Stanley Capital Group Uncia Energy LP - Series D
Dynasty Power Morningstar Commodity Data, Inc Utilities Plus
East Texas Electric Coop Municipal Energy Agency of Nebraska Velocity American
Ecesis NextEra Energy Power Marketing Vitol
EDF Trading North America NJ Resources Westar Energy
EDP Renewable North America Noble Americas Gas & Power Western Area Power Admininstration - Rocky Mountain Region
eKapital Investments Noble Great Plains Windpark Western Area Power Administration - Upper Great Plains Marketing
Emera Energy Services Northern States Power Western Area Power Administration
Empire District Electric Northpoint Energy Solutions Western Farmers Electric Cooperative
Endurance Energy Midwest LLC Northstar Trading LTD XO Energy SW
ETC Endure Energy NorthWestern Corporation dba NorthWestern Energy XO Energy SW2
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[PAGE 69]
Appendix B: Illustration of Southwest Power
Pool Integrated Market
Market Participants submit bids for both their load and generation for each hour in the day-ahead
market. Suppose an SPP Market Participant (MP) forecasts that their load (demand) for the following day
at hour-12 will be 2,300 MWh. The MP submits a bid for their load into the day-ahead market for hour-12 the
following day for 2,000 MWh (SPP does not require that 100% of the forecasted load be bid into the day-ahead
market). The SPP will purchase the remaining 300 MWh forecasted load in the real-time market.
SPP requires the MP to submit generation bids into the day-ahead market with at least enough
generation (capacity) to meet 112% of the load that was bid into the day-ahead market (2,240 MWh) for hour-
12. The 112% requirement is to ensure that there is enough margin for reliability in case the demand is higher
than expected. In the illustrative example below, the MP bids in the following generation into the day-ahead
market for hour-12:
Table B1: Illustrative example of MP bids for generation into the day-ahead market for hour-12
Marginal Cost of
Amount Cost of Production
Production2
Wind 200 MWh1 $0/MWh $20.003/MWh
Nuclear4 800 MWh $8.90/MWh $45.00/MWh
Large Coal 1,350 MWh $13.15/MWh $26.35/MWh
Small Coal 225 MWh $21.00/MWh $54.85/MWh
Combined Cycle 250 MWh $42.75/MWh $160.55/MWh
1 Wind generation is only credited 10% of rated nameplate or 20 MW toward the 2,240 MWh bid requirement
2 SPP generation bid price only includes fuel and variable operation & maintenance costs
3 This is recent Power Purchase Agreement cost for wind generation
4 Nuclear is considered “must-run” or a “price-taker” so it will dispatch regardless of market price
Based on the above table, the MP bid 2,645 MWh of generation into the day-ahead market. This is
more than 2,240 MWh the SPP day-ahead required for supplying the MP load.
For example, if the day-ahead market price for hour-12 is determined to be $18.00/MWh based on the
generation bids received from all the SPP Market Participants. SPP will dispatch the generation with marginal
cost of production at or below $18.00/MWh. Based upon the information above, SPP will dispatch the MP
wind, nuclear, and large coal. The MP will still purchase 2,000 MWh from the day-ahead market to serve the
load they bid into the SPP day-ahead market. All the generation that is dispatched by SPP will receive $18.00/
MWh for the output from their generation. Note that the cost of production for generation that was dispatched
by SPP is, in this illustration, more than the market price of $18.00/MWh, except for wind generation. This
means that the market price did not cover the cost of the MP to own the generation for other sources.
If the marginal cost of production for generation is greater than the day-ahead market price, the MP
purchases electricity cheaper from the day-ahead market than it would cost them to produce the electricity
themselves (for Small Coal, $21.00/MWh to produce vs. $18.00/MWh to purchase). The MP generation that
SPP did not dispatch, Small Coal and Combined Cycle, did not receive any revenue from the day-ahead market
and incurred fixed costs during this period.
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[PAGE 70]
Appendix C: Example of an Unbundled Bill
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[PAGE 71]
Appendix D: Screenshot of powertochoose.org
showing suppliers’ rate options
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[PAGE 72]
Appendix E: 2015 utility bundled
retail sales - residential
2015 Utility Bundled Retail Sales- Residential
(Data from forms EIA-861- schedules 4A & 4D and EIA-861S)
Entity State Ownership Customers (Count)Sales Revenues (Thousands Average Price
(Megawatthours) Dollars) (cents/kWh)
Auburn Board of Public Works NE Municipal 1,904 24,543 2,229.0 9.08
Burt County Public Power Dist NE Political Subdivision 3,341 57,379 7,485.0 13.04
Butler Public Power District - (NE) NE Political Subdivision 4,603 60,903 6,778.0 11.13
Cedar-Knox Public Power Dist NE Political Subdivision 5,422 95,184 8,137.0 8.55
Cherry-Todd Electric Coop, Inc NE Cooperative 827 8,605 1,028.9 11.96
Chimney Rock Public Power Dist NE Political Subdivision 1,981 22,178 3,496.0 15.76
City of Alliance- (NE) NE Municipal 4,185 38,856 4,811.8 12.38
City of Beatrice - (NE) NE Municipal 5,782 67,896 6,458.0 9.51
City of Broken Bow - (NE) NE Municipal 1,896 22,092 2,182.6 9.88
City of Cambridge - (NE) NE Municipal 481 5,621 608.0 10.82
City of Central City NE Municipal 1,370 16,660 1,700.4 10.21
City of Crete NE Municipal 2,444 25,264 2,313.0 9.16
City of David City NE Municipal 1,207 14,264 1,658.0 11.62
City of Fairbury NE Municipal 2,672 30,922 3,235.0 10.46
City of Falls City - (NE) NE Municipal 2,135 24,033 1,959.0 8.15
City of Fremont - (NE) NE Municipal 12,345 136,546 12,646.0 9.26
City of Gering - (NE) NE Municipal 3,439 32,648 4,975.0 15.24
City of Gothenburg - (NE) NE Municipal 1,486 19,973 1,644.0 8.23
City of Grand Island - (NE) NE Municipal 21,467 213,241 20,960.0 9.83
City of Hastings - (NE) NE Municipal 10,882 108,725 10,058.1 9.25
City of Hebron - (NE) NE Municipal 743 8,756 805.0 9.19
City of Holdrege NE Municipal 2,564 28,541 2,675.4 9.37
City of Imperial NE Municipal 1,040 11,630 1,205.0 10.36
City of Kimball - (NE) NE Municipal 1,445 9,938 1,548.0 15.58
City of Lexington - (NE) NE Municipal 3,436 48,412 4,914.7 10.15
City of Madison - (NE) NE Municipal 793 9,420 897.0 9.52
City of Minden - (NE) NE Municipal 1,321 14,261 1,877.7 13.17
City of Nebraska City NE Municipal 4,759 52,445 5,692.5 10.85
City of Neligh - (NE) NE Municipal 869 9,207 961.0 10.44
City of North Platte NE Municipal 11,269 117,841 11,768.0 9.99
City of Ord - (NE) NE Municipal 1,126 15,973 1,371.0 8.58
City of Pierce - (NE) NE Municipal 999 12,057 1,050.0 8.71
City of Schuyler - (NE) NE Municipal 2,112 27,919 2,633.0 9.43
City of Seward - (NE) NE Municipal 2,788 28,494 3,312.0 11.62
City of Sidney - (NE) NE Municipal 4,065 29,988 3,692.0 12.31
City of South Sioux City NE Municipal 4,686 68,516 6,931.0 10.12
City of St Paul - (NE) NE Municipal 954 11,112 1,152.0 10.37
City of Superior - (NE) NE Municipal 1,023 9,608 1,047.0 10.90
City of Syracuse - (NE) NE Municipal 1,071 8,802 983.0 11.17
City of Tecumseh NE Municipal 809 7,920 954.3 12.05
City of Valentine - (NE) NE Municipal 1,422 22,017 1,939.7 8.81
City of Wahoo - (NE) NE Municipal 1,878 21,928 1,897.0 8.65
City of Wakefield - (NE) NE Municipal 566 4,676 507.4 10.85
City of Wayne NE Municipal 2,019 17,951 1,989.0 11.08
City of West Point - (NE) NE Municipal 1,490 14,430 1,677.0 11.62
Cornhusker Public Power Dist NE Political Subdivision 7,054 122,722 13,558.0 11.05
Cozad Board of Public Works NE Municipal 1,708 20,404 2,140.1 10.49
Cuming County Public Pwr Dist NE Political Subdivision 2,791 48,443 4,817.8 9.95
Custer Public Power District NE Political Subdivision 4,598 72,438 8,320.0 11.49
Dawson Power District NE Political Subdivision 15,642 237,391 24,392.0 10.28
Elkhorn Rural Public Pwr Dist NE Political Subdivision 5,917 103,210 10,150.0 9.83
High West Energy, Inc NE Cooperative 1,778 17,815 2,274.0 12.76
Highline Electric Assn NE Cooperative 751 8,162 1,009.3 12.37
Howard Greeley Rural P P D NE Political Subdivision 3,218 52,850 5,685.0 10.76
KBR Rural Public Power District NE Political Subdivision 3,345 35,811 4,765.0 13.31
LaCreek Electric Assn, Inc NE Cooperative 168 2,263 242.0 10.69
Lincoln Electric System NE Municipal 117,859 1,168,564 110,421.3 9.45
Loup River Public Power Dist NE Political Subdivision 14,993 227,342 22,541.0 9.92
Loup Valleys Rural P P D NE Political Subdivision 2,854 39,334 4,442.0 11.29
McCook Public Power District NE Political Subdivision 3,734 37,445 4,839.6 12.92
Midwest Electric Member Corp NE Cooperative 3,195 33,805 3,865.3 11.43
Nebraska Public Power District NE Political Subdivision 70,318 793,831 84,858.0 10.69
Niobrara Valley El Member Corp NE Cooperative 4,786 49,709 5,804.0 11.68
Norris Public Power District NE Political Subdivision 12,920 240,805 22,917.1 9.52
North Central Public Pwr Dist NE Political Subdivision 3,504 40,981 4,830.5 11.79
Northeast Nebraska P P D NE Political Subdivision 6,713 114,287 11,554.0 10.11
Northwest Rural Pub Pwr Dist NE Political Subdivision 1,439 20,529 3,038.6 14.80
Omaha Public Power District NE Political Subdivision 319,501 3,452,484 382,260.0 11.07
Panhandle Rural El Member Assn NE Cooperative 1,766 29,749 3,788.0 12.73
Perennial Public Power Dist NE Political Subdivision 3,587 64,402 6,303.0 9.79
Polk County Rural Pub Pwr Dist NE Political Subdivision 2,859 41,046 4,694.5 11.44
Roosevelt Public Power Dist NE Political Subdivision 2,081 29,726 3,509.0 11.80
Seward County Rrl Pub Pwr Dist NE Political Subdivision 3,152 56,679 5,988.0 10.56
South Central Public Pwr Dist NE Political Subdivision 3,802 62,198 5,793.5 9.31
Southern Public Power District NE Political Subdivision 15,045 233,136 23,455.9 10.06
Southwest Public Power Dist NE Political Subdivision 2,247 34,644 3,492.0 10.08
Stanton County Public Pwr Dist NE Political Subdivision 1,788 28,177 3,174.0 11.26
Twin Valleys Public Power Dist NE Political Subdivision 4,106 36,693 4,338.0 11.82
Wheat Belt Public Power Dist NE Political Subdivision 3,235 33,907 4,307.8 12.70
Wyrulec Company NE Cooperative 269 2,722 407.0 14.95
Adjustment 2015 NE Other 28,101 301,053 34,709.1
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[PAGE 73]
Appendix F: 2015 utility bundled
retail sales - Industrial
2015 Utility Bundled Retail Sales- Industrial
(Data from forms EIA-861- schedules 4A & 4D and EIA-861S)
Sales Revenues (Thousands Average Price
Entity State Ownership Customers (Count)
(Megawatthours) Dollars) (cents/kWh)
Auburn Board of Public Works NE Municipal 1 2,904 262.8 9.05
Burt County Public Power Dist NE Political Subdivision 685 22,750 3,413.0 15.00
Butler Public Power District - (NE) NE Political Subdivision 666 8,921 2,553.0 28.62
Cedar-Knox Public Power Dist NE Political Subdivision 1,198 24,805 3,774.0 15.21
Cherry-Todd Electric Coop, Inc NE Cooperative 226 16,566 2,032.1 12.27
Chimney Rock Public Power Dist NE Political Subdivision 928 18,039 2,361.0 13.09
City of Alliance- (NE) NE Municipal 12 29,093 2,868.4 9.86
City of Beatrice - (NE) NE Municipal 119 69,163 5,325.0 7.70
City of Broken Bow - (NE) NE Municipal 8 52,275 3,738.8 7.15
City of Cambridge - (NE) NE Municipal 1 33,788 2,059.0 6.09
City of Central City NE Municipal 11 5,851 609.0 10.41
City of Crete NE Municipal 3 63,323 4,062.0 6.41
City of David City NE Municipal 30 18,179 1,871.0 10.29
City of Fairbury NE Municipal 18 31,762 2,465.0 7.76
City of Falls City - (NE) NE Municipal 7 4,278 298.0 6.97
City of Fremont - (NE) NE Municipal 530 230,816 16,910.0 7.33
City of Gering - (NE) NE Municipal 40 18,185 2,085.0 11.47
City of Gothenburg - (NE) NE Municipal 15 22,654 1,889.0 8.34
City of Grand Island - (NE) NE Municipal 99 317,928 23,554.0 7.41
City of Hastings - (NE) NE Municipal 128 180,698 11,145.5 6.17
City of Holdrege NE Municipal 2 54,208 2,625.2 4.84
City of Imperial NE Municipal 45 4,321 357.0 8.26
City of Lexington - (NE) NE Municipal 5 115,517 7,792.3 6.75
City of Madison - (NE) NE Municipal 1 45,108 3,010.0 6.67
City of Nebraska City NE Municipal 34 69,297 5,922.0 8.55
City of North Platte NE Municipal 4 38,521 2,664.0 6.92
City of Pierce - (NE) NE Municipal 28 609 36.0 5.91
City of Schuyler - (NE) NE Municipal 127 97,418 7,295.0 7.49
City of Seward - (NE) NE Municipal 5 29,559 2,460.0 8.32
City of Sidney - (NE) NE Municipal 67 36,138 2,793.0 7.73
City of St Paul - (NE) NE Municipal 32 8,908 802.0 9.00
City of Superior - (NE) NE Municipal 15 6,017 560.0 9.31
City of Syracuse - (NE) NE Municipal 19 5,798 454.0 7.83
City of Tecumseh NE Municipal 5 7,485 643.8 8.60
City of Wahoo - (NE) NE Municipal 4 12,533 935.0 7.46
City of Wakefield - (NE) NE Municipal 1 36,630 2,556.0 6.98
City of West Point - (NE) NE Municipal 80 31,330 2,947.0 9.41
Cornhusker Public Power Dist NE Political Subdivision 2,287 152,835 14,106.0 9.23
Cozad Board of Public Works NE Municipal 1 4,301 371.8 8.64
Cuming County Public Pwr Dist NE Political Subdivision 326 14,653 1,688.4 11.52
Custer Public Power District NE Political Subdivision 4,911 98,225 13,236.0 13.48
Dawson Power District NE Political Subdivision 5,795 241,846 27,821.0 11.50
Elkhorn Rural Public Pwr Dist NE Political Subdivision 2,807 109,716 12,773.0 11.64
High West Energy, Inc NE Cooperative 1,196 71,167 8,048.0 11.31
Highline Electric Assn NE Cooperative 1,084 63,788 8,138.7 12.76
Howard Greeley Rural P P D NE Political Subdivision 1,445 39,213 4,140.0 10.56
KBR Rural Public Power District NE Political Subdivision 779 34,562 5,631.0 16.29
LaCreek Electric Assn, Inc NE Cooperative 46 2,432 277.0 11.39
Lincoln Electric System NE Municipal 184 487,115 32,121.3 6.59
Loup River Public Power Dist NE Political Subdivision 53 662,298 42,513.0 6.42
Loup Valleys Rural P P D NE Political Subdivision 2,245 72,081 7,113.0 9.87
McCook Public Power District NE Political Subdivision 910 101,832 8,620.5 8.47
Midwest Electric Member Corp NE Cooperative 2,058 141,936 17,330.1 12.21
Nebraska Public Power District NE Political Subdivision 56 1,170,406 66,056.0 5.64
Niobrara Valley El Member Corp NE Cooperative 1,203 64,229 7,544.0 11.75
Norris Public Power District NE Political Subdivision 1,869 460,966 33,847.5 7.34
North Central Public Pwr Dist NE Political Subdivision 1,109 38,128 5,903.1 15.48
Northeast Nebraska P P D NE Political Subdivision 673 12,689 2,341.0 18.45
Northwest Rural Pub Pwr Dist NE Political Subdivision 652 45,414 5,843.0 12.87
Omaha Public Power District NE Political Subdivision 174 3,299,315 201,969.0 6.12
Panhandle Rural El Member Assn NE Cooperative 847 36,869 6,048.0 16.40
Perennial Public Power Dist NE Political Subdivision 2,709 194,047 16,590.0 8.55
Polk County Rural Pub Pwr Dist NE Political Subdivision 1,289 21,702 4,335.4 19.98
Roosevelt Public Power Dist NE Political Subdivision 684 18,498 2,246.0 12.14
Seward County Rrl Pub Pwr Dist NE Political Subdivision 757 9,933 1,863.0 18.76
South Central Public Pwr Dist NE Political Subdivision 3,129 74,072 8,547.8 11.54
Southern Public Power District NE Political Subdivision 9,359 767,508 64,605.8 8.42
Southwest Public Power Dist NE Political Subdivision 1,280 116,678 12,314.0 10.55
Stanton County Public Pwr Dist NE Political Subdivision 594 93,517 7,461.0 7.98
Twin Valleys Public Power Dist NE Political Subdivision 1,246 27,471 4,768.0 17.36
WAPA-- Western Area Power Administration NE Federal 1 3,982 32.0 0.80
Wheat Belt Public Power Dist NE Political Subdivision 1,014 87,579 10,170.7 11.61
Wyrulec Company NE Cooperative 164 4,070 616.4 15.14
Y-W Electric Assn Inc NE Cooperative 72 6,131 774.0 12.62
Adjustment 2015 NE Other 349 32,528 3,888.0
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[PAGE 74]
Appendix G: Researchers’ Biographies
Ernie Goss is the Jack MacAllister Chair in Regional Jeffrey Milewski is a senior research economist
Economics at Creighton University and is the initial at Goss & Associates. He received his master’s
director for Creighton’s Institute for Economic degree in political economy from the London
Inquiry. He is also principal of the Goss Institute in School of Economics and Political Science in
Denver, Colo. Goss received his Ph.D. in economics 2013. He completed his bachelor’s degree at
from The University of Tennessee in 1983 and is a Creighton University in 2007, having studied
former faculty research fellow at NASA’s Marshall economics and finance. Milewski also has
Space Flight Center. He was a visiting scholar with experience working in finance and as an
the Congressional Budget Office for 2003-2004, and entrepreneur. Recently, he has co-authored impact
has testified before the U.S. Congress, the Kansas studies on a range of topics such as property-
Legislature, and the Nebraska Legislature. In the fall casualty insurance, highway expansion, cost/
of 2005, the Nebraska Attorney General appointed benefit analysis, and national sporting events.
Goss to head a task force examining gasoline
pricing in the state.
He has published more than 100 research studies
focusing primarily on economic forecasting
and on the statistical analysis of business and
economic data. His book Changing Attitudes
Toward Economic Reform During the Yeltsin Era was
published by Praeger Press in 2003, and his book
Governing Fortune: Casino Gambling in America
was published by the University of Michigan Press
in March 2007.
He is editor of Economic Trends, an economics
newsletter published monthly with more than
11,000 subscribers, produces a monthly business
conditions index for the nine-state Mid-American
region, and conducts a survey of bank CEOs in 10
U.S. states. Survey and index results are cited each
month in approximately 100 newspapers; citations
have included the New York Times, Wall Street
Journal, Investors Business Daily, The Christian
Science Monitor, Chicago Sun Times, and other
national and regional newspapers and magazines.
Each month 75-100 radio stations carry his Regional
Economic Report.
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[PAGE 75]
Energy Rate, Residential Only (cents/kWh)
State 2004 2015 % Change Retail Choice Avg 15.27
Washington 6 .37 9 .09 43% % to Retail -31%
Louisiana 8 .05 9 .33 16% % to US Average -16%
Lincoln Electric System 6 .18 9 .39 52% Nebraska Rank 10
North Dakota 6 .79 9 .62 42%
Arkansas 7 .36 9 .82 33% LES % to Retail* -39%
Idaho 6 .10 9 .93 63% LES % to US Average* -26%
West Virginia 6 .23 10.08 62%
Oklahoma 7 .72 10.14 31%
Kentucky 6 .11 10.24 68%
Tennessee 6 .90 10.30 49%
Nebraska 6 .96 10.60 52%
Oregon 7 .18 10.66 48%
Montana 7 .86 10.88 38%
Utah 7 .21 10.88 51%
Wyoming 7 .21 10.97 52%
South Dakota 7 .65 11.08 45%
Missouri 6 .97 11.21 61%
Mississippi 8 .21 11.27 37%
North Carolina 8 .45 11.28 33%
Virginia 7 .99 11.37 42%
Georgia 7 .86 11.54 47%
Texas 9 .73 11.56 19%
Indiana 7 .30 11.57 58%
Florida 8 .99 11.58 29%
Iowa 8 .96 11.63 30%
Alabama 7 .62 11.70 54%
Colorado 8 .42 12.12 44%
Minnesota 7 .92 12.12 53%
Arizona 8 .46 12.13 43%
Kansas 7 .74 12.34 59%
New Mexico 8 .67 12.47 44%
Illinois 8 .37 12.50 49%
South Carolina 8 .12 12.57 55%
US Average 8 .95 12.65 41%
Nevada 9 .69 12.76 32%
Ohio 8 .45 12.80 51%
District of Columbia 8 .00 12.99 62%
Delaware 8 .78 13.42 53%
Pennsylvania 9 .58 13.64 42%
Maryland 7 .80 13.82 77%
Wisconsin 9 .07 14.11 56%
Michigan 8 .33 14.42 73%
Maine 12.16 15.61 28%
New Jersey 11.23 15.81 41%
California 12.20 16.99 39%
Vermont 12.94 17.09 32%
New Hampshire 12.49 18.50 48%
New York 14.54 18.54 28%
Rhode Island 12.19 19.29 58%
Alaska 12.44 19.83 59%
Massachusetts 11.75 19.83 69%
Connecticut 11.63 20.94 80%
Hawaii 18.06 29.60 64%
Source: U.S. Department of Energy - Energy Information Administration; Average Retail Price of Electricity
*LES rate is calculated as the total revenue divided by total energy sold, averaged over 12 months from EIA 826 data for 2004 and 2015
Page 75 Agenda Item #7b

[PAGE 76]
Energy Rate, All Customer Classes (cents/kWh)
State 2004 2015 % Change Retail Choice Avg 12.67
Washington 5 .80 7 .40 28% % to Retail -30%
Louisiana 7 .13 7 .65 7% % to US Average -14.41%
Oklahoma 6 .50 7 .90 22% Nebraska Rank 15
Wyoming 4 .98 7 .97 60%
Lincoln Electric System 5 .16 8 .02 55% LES % to Retail* -37%
Idaho 4 .97 8 .09 63% LES % to US Average* -23%
West Virginia 5 .13 8 .11 58%
Kentucky 4 .63 8 .14 76%
Arkansas 5 .67 8 .19 44%
Iowa 6 .40 8 .35 30%
Utah 5 .69 8 .54 50%
Texas 7 .95 8 .70 9%
North Dakota 5 .69 8 .75 54%
Oregon 6 .21 8 .75 41%
Montana 6 .40 8 .90 39%
Nebraska 5 .70 8 .91 56%
Indiana 5 .58 8 .99 61%
Tennessee 6 .14 9 .30 51%
Virginia 6 .43 9 .31 45%
Alabama 6 .08 9 .33 53%
North Carolina 6 .97 9 .37 34%
Illinois 6 .80 9 .40 38%
Missouri 6 .07 9 .44 56%
South Dakota 6 .44 9 .47 47%
Nevada 8 .56 9 .48 11%
Minnesota 6 .24 9 .53 53%
Mississippi 7 .00 9 .53 36%
South Carolina 6 .22 9 .58 54%
Georgia 6 .58 9 .62 46%
New Mexico 7 .10 9 .62 35%
Colorado 6 .95 9 .94 43%
Ohio 6 .89 9 .98 45%
Kansas 6 .37 10.14 59%
Pennsylvania 8 .00 10.31 29%
Arizona 7 .45 10.34 39%
US Average 7 .61 10.41 37%
Florida 8 .16 10.49 29%
Wisconsin 6 .88 10.73 56%
Michigan 6 .94 10.76 55%
Delaware 7 .53 11.17 48%
District Of Columbia 7 .47 12.07 62%
Maryland 7 .15 12.07 69%
Maine 9 .69 12.78 32%
New Jersey 10.29 13.74 34%
Vermont 11.02 14.41 31%
New York 12.55 15.28 22%
California 11.35 15.42 36%
New Hampshire 11.37 16.02 41%
Massachusetts 10.77 16.90 57%
Rhode Island 10.96 17.01 55%
Alaska 10.99 17.59 60%
Connecticut 10.26 17.77 73%
Hawaii 15.70 26.17 67%
Source: U.S. Department of Energy - Energy Information Administration; Average Retail Price of Electricity
*LES rate is calculated as the total revenue divided by total energy sold, averaged over 12 months from EIA 826 data for 2004 and 2015
Page 76 Agenda Item #7b