Text

Nebraska Public Power District 2017 Financial Report
	ML18137A206
Person / Time
Site:	Cooper
Issue date:	05/08/2018
From:	Shaw J; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2018032
	Download: ML18137A206 (61)
	v • d • e

H Nebraska Public Power District NLS2018032 May 8 , 2018 U.S. Nuclear Regulatory Commission A TTN: Document Control Desk Washington, DC 20555-0001 Alwa1 s th e r e wh e n 1o u n ee d u s

Subject:

Nebraska Public Power District 2017 Financial Report Cooper Nuclear Station , Docket No. 50-298 , DPR-46

Dear Sir or Madam:

50.7l(b) The purpose of this letter is to transmit the Nebraska Public Power District (NPPD) Financial R e port for the calendar year 2017 in accordance with the requirements of 10 CFR 50. 71 (b ). Copies of this report are being distributed in accordance with 10 CFR 50.4. This letter does not contain any commitments. Should you have any questions or require additional information , please contact me at ( 402) 825-2788. Sincerely , Licensing Manager /jo Enclosure

-NPPD 2017 Financial Report cc: Regional Administrator w/enclosure USNRC -Region IV Cooper Project Manager w/enclosure USNRC -NRR Plant Licensing Branch IV Senior Resident Inspector w/enclosure U SNRC-CNS NPG Distribution w/o enclosure CNS Record s w/enclosure COOPER N UCL EAR S T A TION P.O. Box 98 / B r ownv i ll e, N E 6832 1-0098 Te l eph o n e: {402) 825-38 1 1 / F ax: {402) 825-5211 www.nppd.com NLS2018032 Enclosure Page 1 of 60 NPPD 2017 Financial Report 2 0 17 FINANCIAL REPORT OFTHE NEBRASKA PUBLIC POWER DISTRICT Statistical Review (Unaudited) 11 Management's Discussion and Analysis (Unaudited) 12 Report of Independent Auditors 28 Financial Statements 29 Notes to Financial Statements 32 Supplemental Schedules (Unaudited) 65 2017 YEAR AT A GLANCE KIIL J OWATT-HOUR SALES d 9 6 L IJ IO>N QPBRAm NG REWENUes $ .~01 6 MILl.LtON COS if OF D>~ER Pl!lRCHl~SEO l(ND S6N 1 ERA1'i EO $ K6.1 011:t,:IBR Q'AE:~1111

N'.G lE~P E flSB S $ re s ~e s m MEN tt ~\N[i) o m.it: SR UiO::GME 3 1 6 iM l llU J DBBT AiNCi> OllhlBR E iXJPtB NSBS $ 65.0 iMJUUIOlN INCRE~SE IN E U' asJ IOlN $ iT'!l .3 IMll.i l<DN DEBT SER~IQE OOJ~BRAGE 2.13 m lMBS 10 Fimanoial Report l 2017 STATISTICAL REVIEW (Unaudited)

Average Cents Per kWh Sold Average Average Less Government Cents Per Number of M\Nh OPERATING REVENUES Taxes/Transfers bl kWh Sold Customers Amount % Retail: Res i dential ....................... 10.72 ¢ 12.74 ¢ 72 , 021 809 , 095 4.1 Corrrnercial

...................

... 8.46 ¢ 9.86 ¢ 19, 533 1 , 12 5 , 3 11 5.8 Industrial

.......................... 5.22 ¢ 5.57 ¢ 60 1 , 314,989 6.7 Total Retail Sales ............ 7.71 ¢ 8.84 ¢ 91,614 3 , 249 , 395 16.6 W h olesale: Municipalities c, 1 ......................................... 6.33 ¢ 45 1 , 658 , 984 8.5 Municipalities (Partial Requirements)l 31 *.****** 5.n ¢ 1 1 86 , 956 0.9 Public Power Districts and Cooperatives w .. 5.93 ¢ 25 7 , 966 , 644 40.7 Total F irm Wholesale Sales...................... 5.99 ¢ 71 9 , 812 , 584 50.1 Total Firm Retail and Wholesale Sales.... 6.70 ¢ 91 , 685 13 , 061 , 979 66.7 P articipa tion Sales.......................................... 3.71 ¢ 5 1 , 973 , 441 10.1 Other sa1es c*J ................................................. 2.48 ¢ 2 4 , 533 , 128 23.2 Total Electr i c Energy Sales.................... 5.42 ¢ 9l692 19 1 568 1 548 100.0 Other Operating Revenues l s J ..........................................................................................

.................... . Unearned Revenues l&J .....................

.......................................

.........................................

.................. . Total Operating Revenues ................................................................................................................... . MVVh COST OF POVVER PURCHASED AND GENERATED Amount % Production C 7 l ..*..*......*..................................*......................*...

..................... 15 , 850 , 887 n.9 Power Purchased

....................................................................................... . 4 , 501 , 041 22.1 Total Production and Power Purchased

................................................... . 20.351.928 100.0 CONTRAClUAL AND TAX PAYMENTS (i n OOO's) 11 1 Payments to Retail Corrrn.mities

.................

..........................

............................................................ . Payments in lieu of Ta,es ........................................................

....................................................... . Total Contraclual and Tax Payments ............................................................................................. . OllER Mies of Transmission and Subtransrrission Li nes in Sen,ice ..............

................................................ . of Ful-lirne Efil>layees

....................................................................................................... . (1) Customer colections for taxes/lransl'ers to other governments are excluded from base rates. (2) Sales are total requirements , subject to certa in exceptions. Revenues (in OOO's) Amount % $ 103 , 101 9.4 110 , 906 10.1 73 , 244 6.6 287 , 25 1 26.1 104 , 985 9.5 10 , 78 5 0.9 472 , 291 42.9 588 , 061 53.3 875 , 312 79.4 73 , 199 6.6 11 2 , 209 10.2 1 , 060 , 720 96.2 76 , 182 6.9 {35 , 260} (3.1} $1.101.642 100.0 Costs (in OOO's) $ $ $ I Amount 424 , 190 161 , 963 586.153 Amount 27 , 102 10 , 060 37,162 Amount 5 , 294 1 , 875 % 72.4 27.6 100.0 (3) Sales are to a wstomer who li mited their requirements u nder th e 2002 Contract.

The average rate was lower" than total requirements wstomers due to th e exclusion of certain transmission costs from the wholesale rate as cost recovery was through the SPP transmission tariff. These revenues were included i n Other Sales. (4) I ncludes sales in the Southwest Power-Pool ("'SPP 1 and nonlirm sales to other" utiities.

(5) I ncludes revenues for transmission and other" miscelaneous revenues. (6) Includes unearned revenues from prior periods of $6.7 milion , recognized revenues of S23.0 milion for other' poslemploymen t benefit ("'OPEB 1 expenses related to past service and included in 20 17 rates , 20 17 surplus revenues deferred to future periods of s<<.9 million and coled i ons of $20.0 milion for the 2 018 Cooper-Nuclear Station ("'CNS~j refueling and maintenance outage. (7) I ncludes fuel , operation , and maintenance costs. Debt service and capilal-related costs are exduded. SOURCES OF THE DISTRICT'S ENERG Y SUPPLY (Y.OFIIWH)

Th i s chart shows th e sources of energy for sales , exd udin g participation sales to other utilities. Purchases were i nduded i n the appropriate source , except for th ose purchases for which the source was not known. F i nai lil'cial IR~p:<!rnt 45.3% Hydro 6.3% Purchases 4.1% 1.5%

L MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

The financial report for the Nebraska Public Power District ("District")

includes the Management's Discussion and Analysis , Financial Statements, Notes to Financial Statements, and Supplemental Schedules. The financial s t atements consist of the Balance Sheets , Statements of Revenues , Expenses , and Changes in Net Position , Statements of Cash Flows , and Supplemental Schedules. The following Management's Discussion and Analysis ("MD&A") provides unaudited information and analyses of a ct ivities and events related to the District's financial position or results of operations.

The MD&A should be read i n conjunction with the audited Financial Statements and Notes to Financial Statements. The Balance Sheets present assets , deferred outflows of resources , liabilities , deferred inflows of resources and net position as of December 31 , 2017 and 2016. The Statements of Revenues , Expenses , and Changes in Net Position present the operating results for the years 2017 and 2016. The Statements of Cash Flows present the s o urces and uses of cash and cash equivalents for the years 2017 and 2016. The Notes to Financial Statements a r e an i ntegral part of the basic financial statements and contain information for a more complete understanding o f the financial position as of December 31 , 2017 and 2016 , and the results of operations for the years 2017 and 2 01 6. The Supplemental Schedules include unaudited information required to accompany the Financial Statements. OVERVIEW OF BUSINESS The District is a public corporation and political subdivision of the State of Nebraska (the " State n). Control of the District and its operations are vested in a Board of Directors

(" Board n) cons i sting of 11 members popularty elected from districts comprising subd i v i sions of the District's chartered territory.

The District's chartered territory indudes all or parts of 86 of the State's 93 count i es and more than 400 municipalities i n the State. The right to vote for the Board i s generally limited to retail and wholesale customers receiving more than 50% of their annual energy from the District.

The District operates an i ntegrated electric utility system i nduding facilities for generation , transmission , and d i sbibution of electric power and energy for sales at retail and wholesale. Management and operation of the District i s accompl ish ed with a staff of approximately 1 , 875 full-time employees.

The District has the power , a mon g other things , to acqu ir e , construct , and operate generating plants , transmission lin es , substations , and d i stribution systems and to purchase , generate , distribute , transmit , and sell electric energy for all purposes.

There are no investor-owned utilities providing r eta i l electric service i n Nebraska.

The District has no power of taxation , and no governmental authority has the power to levy or collect taxes to pay , in whole or i n part, any i ndebtedness or obligation of or incurred by the District or upon which the Disbict may be liable. The Oisbict h as the ri ght of em in ent doma i n. The property of th e District, in the op i nion of its General Counsel , i s exempt under the State Constitution from taxation by the State and its subdivisions , but the District i s requ i red by th e State to make payments i n lieu of taxes which are distributed to the Sta t e and v a riou s governmental subdivisions. The District has the power a nd i s requ i red to fix, establish , and collect adequate rates and other charges for electrical energy a nd any and all commodities or services sold or furnished by it Such rates and charges must be fair , reasonable , and nondiscrimin a tory and adjusted in a fair a nd equitable manner to confer upon and distribute among th e users and consumers of such commodities and services the benefits of a successful and profitable operation and conduct of the business of the District.

THE SYSTEM To meet the anytime peak load in 20 17 of 2 , 891.5 megawatts rMW), the District had available 3 , 65 1.0 MW of capacity resomces that incl uded 3 ,046.2 MW of generation capacity from 12 owned and operated generating plants and 22 plants over which the District has operating control , 44 7.6 MW of firm capacity purdlases from the 12 We s tern Area Power Adm i nistration , and 157.2 MW of a c apacity purchase from Omaha Publ i c Power Distr i ct's (" OPPD") Nebraska City Stat i on Unit 2 (" NC2") coal-fired plant. Of the total capacity resources , 275.7 MW are being sold via participation sales or other capacity sales a greements , leav i ng 3 , 375.3 MW to serve firm retail and wholesale customers and t o meet capac i ty reserve requ i rements. The hi ghest summer anytime peak load of 3 , 030.3 MW was established i n July 2012 and the highes t winter anyt i me peak l oad of 2 , 252.0 MW was established in January 2014 for firm requirements customers. T h e fo ll owing t able shows the D i st ri ct's capac i ty resources from ge n eration a n d r espect i ve summer 2017 accred i ted capab ili ty. Steam -Conven ti onal C 3 J .*.*.******.***********.**********.********* Steam -Nuclear ....................................................... . Corrb in ed Cycle ...................................................... . Corrbustion Tu r bi ne w ............................................. . Hydro ...................................................................... . D i esel ......................................

....................

........... . Wi nd esJ ...........

................**................**.........*.......... Nurrber of Pla n ts<1> 3 1 1 3 6 12 8 34 (1) lndud es th ree hydro p la nt s a nd 12 di esel pl a nts und e r contrad to the Di s trict. (2) 2017 s umm e r a ccredit ed n e t ca pability based on SP P criteri a. Summe r 20 17 Accred i ted Capabili!i:

{MW} <2> 1 , 6 7 9.3 765.0 22 0.0 1 25.3 1 06.8 9 3.6 56.2 3 , 046.2 (3) lndud es Ge rald G e n tle m a n Station (" GG S 1 , Sh eldo n S tation (" S h el d o n 1 , a nd Can ada y Stati o n. (4) lndud es the H a U a m , H e bron a nd McC ook pe a kin g turbin es. (5) lndu des Ainsworth Wind En e rgy Facility ("Ain sworlh 1 and seven w i nd faciliti es und er contrad t o th e Di s trict. Percent of T otal 55.2 25.1 7.2 4.1 3.5 3.1 1.8 100.0 Th e followin g t a bl e s h ows th e genera ti o n facil iti es own ed b y th e D istrict a nd th ei r r espective fuel type s , s umm e r 2 017 accred it ed capab ility , a nd in-se rvi ce d a t es. Ty pe Gerald Gentleman Stati on ltits No. 1 and No. 2 ......... . Cooper fllJclear Station ...................................

......... . Beatri ce Power Station ............................................. . Sheldon Stati on ltits No. 1 and No. 2 ....................... . Cont>uslion Tlrllines (3 generating plants) ................. . Canaday Station ...................................................... . Hy<<t"o (3 g e neiating plants) ................

....................... . Ainsworth Wind Energy Faciity W ..........................

.. . (1) 2017 summer aa:redited net capabiity based on SPP aiteria. (2) Nominaly rated at 60 lM'. Fim.amoial R~p011t Fuel Ty pe Coal fllJclear Cormined Cycle Coal Oil or Natural Gas Nalural Gas WaeT Wind Su mner 2 017 Acc redi ted C apabi ity (MN) <1> 1 , 365.0 765.0 220.0 215.0 125.3 99.3 2 1.3 8.3 2 , 8 1 9.2 ln-Senii ce D ate 1979 , 1982 1974 2005 1961 , 1968 1973 1958 1 887 , 1927 , 1 939 2005 THE CUSTOMERS Retail and \/Vholesale Customers In 2017 , the District served an average of 91 , 614 retail customers.

Currently the District's reta i l service territory includes 79 municipal-owned distribution systems operated by the District for the municipality pursuant to a Professional Retail Operations

(" PRO") Agreement.

Details of the District's PRO Agreements are included in Note 12 in the Notes to Financial Statements. The District serves i ts wholesale customers under total requ i rements contracts that require them to purchase total p o wer and energy requirements from the District , subject to certain except i ons. In 2016 , the District entered into 2 0-year wholesale power sales contracts with a substantial number of i ts wholesale customers (the " 2016 Contracts"). The 2016 Contracts replaced wholesale contracts that were entered i nto in 2002 (the " 2002 Contracts"). \/Vholesale customers served under the 2016 Contracts indude 23 public power districts (20 of which a r e served under one contract with the Nebraska Generation and Transm i ssion Cooperative), one cooperative , and 37 mun i cipalit i es. VVholesale customers served under the 2002 Con tr acts i ndude one publ i c power district and nine municipalities.

The District's goal , with respect to the cost of wholesale service (production and tr a nsmiss i on), i s that such costs are among the lowest quartile (25 th percentile or less) for cost per kilowatt-hour

("k\/Vh") purchased , as published by the National R u ral Utilities Cooperative F i nance Corporation Key Ratio T r end Analys i s (Ratio 88) (the " CFC Data"). The District's wholesale power costs percentile was 28.2% for 2016 , based on the latest ava i lable data. Deta i ls of the District's \/Vholesale Power Contracts are i ncluded i n Note 12 i n the N o tes t o F i nancial Statements. The f ollowing charts s h ow th e D i s tri ct's average reta i l and wholesale cents per kVVh for the years ended December 3 1 , 2013 th r oug h 2017. The D i st ri ct also reported average cents per kVVh sold l ess customer collections for taxes and transfers to other governments , wh i ch are no t i ncluded i n the Dis tri ct's base rates for reta i l customers. AVERAGE CENTS PER kWh SOLD -RETAIL (Retail -All Classes) 9.80 ~-----------------------.s::. 9.00 3: 8.20 Q) C. .!!l 7.40 C: Q) u 6.60 5.80 9.04¢ 2013 9.06¢ 9.12¢ 9.05¢ 2014 2015 2016 2017 Average Cents per kWh Sold Average Cents per kWh Sold Less Government Taxes/Transfers 14 Fin a, n o ial R ep 0 11 t AVERAGE CENTS PER kWh SOLD -WHOLESALE 6.40 6.00 5.91¢ .s::. 5.60 Q) Q. .l!! 5.20 C: Q) (..) 4.80 4.40 2013 Participation Sales and Other Sales (Firm Wholesale Customers Only) 6.09¢ 2014 5.96¢ 5.93¢ I I I I I I l __ _____ l_~ __ I 2015 2016 5.99¢ 2017 There are participation sales agreements i n place with other util i ties for the sale of power and ene r gy at wholesale from specific generating plants. Such sales are to Lincoln Electric System (" LES.), Municipal Energy Agency of Nebraska ("MEAN"), OPPD , Grand Island Utilities

(" Grand Island*). and JEA. The District also sells energy on a nonfinn bas i s in SPP and through transactions executed with other utilities by The Energy Authority

(*TEA"). Transmission Customers The D i strict owns and operates 5 , 294 m i les of transmission and subtransm i ss i on lines , encompassing near1y the entire State. The District became a transmission owning member of SPP , a regional transmission organization , i n 2009. The District fi l es a rate with SPP annually that provides for the recovery of all transmission revenue requirements associated with transmission facilities equal to or greater than 115 kV. SPP collects and reimburses the District for the use of the District's transmission facilities by entities other than the District's firm requirements customers and all transm i ss i on customers still served d i rectly by the D i strict through grandfathered Transm i ss i on Agreements. Financ i al R~p@rt Customers and Energy Sales The following table shows customers , energy sales , and peak loads of the System , including participation sales , in each of the three years , 2015 through 2017. Megawatt-Hour Sales Anytime Peak Load {MW) Calendar A..erage Number of Wholesale Nati..e Load Percentage Total Percentage Busbar Nati..e Year Retail Customers Customers<1> Sa1es<2> Grov.fu Sa1es<3> Grov.fu(4) Load 2015 91 , 140 82 12 , 579 , 390 (2.7) 20 , 990 , 883 1.6 2 , 695.0 2016 91 , 457 78 12 , 901 , 989 2.6 18 , 902 , 173 (10.0) 2 , 963.7 2017 91 , 614 78 13 , 061 , 979 1.2 19 , 568 , 548 3.5 2,891.5 (1) At the end of 2017 , indu des sales to finn wholesale customers , participation customers (LE S , MEAN , JEA , OPPD , Grand Island), and a yearly average of 2 nonfinn customers. In 2016 , three of the District's municipal wholesale customers began purchasing power from three of the District's public power district wholesale customers , and one of the District's municipal wholesale customers allowed their contract to tenninate.

(2) Native load sales in dude wholesale sales to total firm requirements customers and the respons i b ility of replacement power being procured by the Di strict if the District's generating assets are not operating. Predominandy , native load wstomers are served under long-tenn total requirements contracts. (3) Total sales from the System in dude sales to LE S from GGS and Sheldon , which sales from Sheldon terminated on December 31 , 2017; to MEAN , JEA , OPPD , and Grand Island from Ainsworth

\llllnd Energy Facility , which sales commenced October 1 , 2005 , and terminates on September 30 , 2025; to OPPD , MEAN , LES and Grand Island from Elkhorn Ridge \llllnd Facility , which sales commenced March 1 , 2009 , and tenninates on Febru ary 28 , 2029; to MEAN from GGS and CNS , which sale commenced J anuary 1 , 2011 , and term i nates on December 31 , 2023; to MEAN , LES and Grand Island from Laredo Ridge \llllnd Facility , which sales commenced February 1 , 20 11 , and terminates on J anuary 3 1 , 2031; to OPPD , LE S and Grand Island from Broken Bow I \llllnd Facility , which sales commenced December 1. 20 12 , and terminates on November 30 , 2032; to OPPD , LES and MEAN from Crofton Bluffs \llllnd Facility , which sales commenced November 1 , 2012 , and tenninates on October 3 1 , 2032; and l o OPPO from Broken Bow II Wind Facility which sale commenced October 1 , 2014 , and terminates on September 30 , 2039. The District and LES exewted an agreement i n 2017 to terminate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing alter December 31 , 2017. (4) The in aease in percentage growth from 2016 to 2017 was due primariy to additional nonfinn energy sales from CNS as a result of 2017 being a non-outage year for the unit The deaease in percentage growth from 20 15 to 2016 was a rest.fi of lower nonfinn energy sales due prim arily to the planned refueling and maintenance ootage al CNS , lower n atural gas prices and additional wwtd generation in the SPP Integ rated M arke t 16 Financial Repmt FINANCIAL INFORMATION The following tables summa ri ze the Dis t r i ct's finan ci al posit i on and opera ti ng results. A s of December 3 1 , CONDENSED BALANCE SHEET S (in OOO's) 2017 Current Assets ..................

............................................. . Special Purpose Funds .................................................. . Util i ty Plan t, Ne t ..............................................

................ . Other Long-Term Assets ...............................

...........

....... . Deferred Outflows of Resources

...................................... . Total Assets and Defe rr ed Outflows .................

............ . Cur r ent Li ab ititi es ..................

......................................... . Long-Term Debt .....................................

........................ . Other Long-T er m Li abi fiti es ............................................. . Defe rr ed In flows of Reso u rces ........................................ . Ne t Posi ti on .............................

................

..............

........ . T otal Li abi li ti es , Def err ed I nflows , and Ne t P ositi on ....... . $ 858 , 872 746 , 448 2 , 569 , 898 383 , 70 1 295,402 $ 4 , 854 , 32 1 $ 370 , 50 1 1 , 6 17 , 269 1 , 028 , 467 3 51 , 65 1 1 , 486 , 433 $ 4 1 854 1 32 1 2016 $ 775 , 479 782 , 857 2 , 595 , 767 406 , 149 344 , 33 1 $ 4 1 904 1 583 $ 28 7 , 322 1 , 867 , 7 68 1, 063 , 11 8 27 1 , 258 1 , 4 1 5 , 11 7 $ 4 1 904 1 583 CONDENSED RESULTS OF OPERATIONS (i n OOO's) F or th e years ended Decerrber 3 1 , 2 017 2 01 6 Operati n g Rewn u es ...................

.................................... . $ 1 , 1 01 , 642 $ 1 , 1 53 , 997 Operati n g E>epenses

..................

..........................

........... . (988 , 93 1} {1 , 040,71 5} Operati ng Income ...................................................... . 11 2 , 711 1 1 3 , 2 8 2 l rNeSlrnent and Other Income .................

......................... . 2 3 , 591 31 , 77 2 Debt and Other E>epenses

...............

............

........... . {64 , 986} {62 , 1 2 1} Incr ease i n Net Position ....................

......................... . $ 7113 1 6 $ 82 1 9 33 SOURCES OF OPERATING REVENUES (i n OOO's) F or the y ears ended Oecermer 3 1 , 20 1 7 20 1 6 Rrm Retail and Wholesale Sales ..................

................... . $ 875 , 3 1 2 $ 865 , 66 1 Partic i pation Sales .....................................

................... . 73 , 1 99 77 , 900 Other Sales ...............

.............................

....................... . 11 2 , 209 89,492 Other Operating Re\iet1ues

.........

......................

...... . 76 , 1 82 66 , 060 Ulearned Re\iet1ues

............

........................................... . (35 , 260) 54 , 788 T otal Operating Re\iet1ues

...................

-******* *************** * $ 111 0\64 2 $ \1 53199 7 Financial R!ep c 1 rn t 2015 $ 764 , 278 738 , 967 2 , 508 , 97 1 353 , 639 40 , 775 $ 4 , 406 1 630 $ 218 , 858 1 , 838 , 672 72 7 , 070 289 , 846 1 , 332 , 1 84 $ 4z4 06 1 63 0 2 015 $ 1 , 09 7 , 2 1 6 (960 , 259} 1 36 , 9 57 22 , 355 (68 , 252} $ 91 060 2 0 1 5 $ 848 , 345 77 , 1 92 1 34 , 6 1 2 60 , 730 {23 , 663) $ 1 109 71 2 1 6 CONDENSED STATEMENTS OF CASH FLOWS (in OOO's) For the :tears ended December 31 , 2017 2016 2015 Ne t Cash Provided by Operating Activities

......................... $ 365 , 097 $ 253 , 711 $ 372 , 503 Net Cash Provided by (Used in) Investing Activities

............ (107 , 438) 2 , 374 10 , 961 Net Cash Used in Capital and Financing Activities

............. {332 , 584} {238 , 416} {388 , 483} Net Increase (Decrease) in Cash and Cash Equivalents

..... (74 , 925) 17 , 669 (5 , 019) Cash and Cash Equivalents, Beginning of Year ................. 102 , 729 85 , 060 90 , 079 Cash and Cash Equivalents , End of Year ..................... $ 271804 $ 1021729 $ 851060 Reven u es from Finn Retail and VVholesale Sales The District allocates costs between retail and wholesale service and establishes its rates to produce revenues s ufficient to meet its estimated respective retail and wholesale revenue requirements.

VVhol e sale revenue requirements include unbundled costs accounted for separately between generation and transmission. The rates for retail service indude an amount to recover the costs of wholesale power service in addition to distribution sy stem costs and government taxes and transfers. The District's wholesale power contracts provide for the e stablishment of cost-based rates. Such rates can be adjusted at such times as deemed necessary by the District.

The wholesale power contracts also provide for the creation of a rate stabilization account. Any surplus or d eficiency between revenues and revenue requirements , within certain limits set forth in the wholesale power contracts , may be retained in the rate stabilization account Any amounts in excess of the limits may be induded a s an adjustment to revenue requirements in the next rate review. The wholesale power contracts also indude a provision for establishing a new/replacement generation fund. This provision would pennit the District to collect an a dditional

0.5 mills

per kWh above the nonnal revenue requirements to be used for Mure capital expenditures a ssociated with generation. There was no change to the wholesale or retail rates on January 1 , 2018. The District i mplemented a 0.6% increase in the District's wholesale rates on January 1 , 2017 , for all customers.

N o i ncrease in retail rates was i mplemented in 2017. The D i strict implemented a 0.6% increase i n the District's wholesale rates on January 1 , 2016 , for those wholesale customers who signed the new 2016 20-year wholesale power contract, and a 3.8% increase i n the District's wholesale rates on January 1 , 2016 , for those wholesale customers who remained under the 2002 20-year wholesale power contract The rate i ncrease was higher for the 2002 Contracts as these customers will pay the i r share of a catch-up i n funding for OPEB costs related to prior service through rates prior to the expiration of the i r contracts i n 2021. The D i strict financed with taxable debt the 2016 Contracts customers' share of the OPEB catdHJp trust funding for 2016 and 2017 and plans to i ssue additional taxable debt i n 2018 for catdHJp trust funding. The rustomers under the 2016 Contracts will commence payment through rate collections of the related debt service for their share of the catch-up i n funding for OPEB costs beginning i n 2022 , the year after the expiration of the 2002 Contracts , and continue m aking payments through 2033. No i naease i n retail rates was im plemented i n 2016. Details of the D i strict's Wholesale Power Contracts are i nducled i n Note 12 i n the Notes to Fi nancial Statements. Revenues from firm sales i naeased $9.6 m il lion , or 1.1%, from $865.7 m il lion i n 20 1 6 to $875.3 m i llion i n 2017. Th e i naease i n revenue was due primarily t o a weather-related 1.2% i ncrease *n energy sales. Revenues from fi rm sales *naeasec:1

$17.4 m*t r JOO , or 2.1%, from $848.3 m ini on in 20 1 5 to $865.7 mi l i on i n 2016. The i ncrease i n revenues from 20 1 5 t o 20 1 6 was due prima rily t o a weather-related 2.6% i naease i n energy sales to fi rm requ i rements rustomers. Revenues from Participation Sales The District has participation sales agreements with othe,: uti ities that share operating expenses on a pro rata basis. Revenues from participation sales decreased from $7 8.0 mili on i n 20 1 6 to $7 3.2 m il lion i n 2 017 , a 18 Financial Repo 11 t reduction of $4.8 million. The reduction was due primarily to lower demand revenues for GGS and CNS , along with lower wind participation energy sales. Revenues from participation sales increased from $77 .2 million in 2015 to $78.0 million in 2016 , an increase of $0.8 million. The District and LES executed an agreement in 2017 to terminate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing after December 31 , 2017. Revenues from Other Sales Other sales consist of sales in SPP's Integrated Market and nonfirm sales to other utilities.

TEA, of which the District is a member , has energy marketing responsibilities for the District's other and nonfirm off-system sales and the related management of credit risks. Other sales increased from $89.5 million in 2016 to $112.2 million in 2017 , an increase of $22.7 million. The increase was a result of higher energy sales due to no refueling and maintenance outage at CNS and higher prices in the SPP Integrated Market due to higher natural gas prices. Other sales decreased from $134.6 million in 2015 to $89.5 million in 2016 , a decrease of $45.1 million. The decrease was a result of reduced nonfirm revenues due to lower energy sales due to the planned refueling and maintenance outage at CNS , lower natural gas prices , and additional wind generation in the SPP Integrated Market. Other Operating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues.

These revenues were $76.2 million , $66.1 million , and $60.7 million in 2017 , 2016 , and 2015 , respectively.

The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District. Unearned Revenues Under the provisions of the District's wholesale power contracts , any surplus or deficiency between net revenues and revenue requirements , within certain limits set forth in the wholesale power contracts , may be adjusted in the rate stabilization account. Any amounts i n excess of the rate stabilization limits may be induded as an adjustment to revenue requirements in the next rate review. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities , the balance of such surpluses or deficiencies are accounted for as *regulatory l i abilities or assets*. respectively. The District recognizes net r evenues i n excess of revenue requ i rements i n any year as a defenal or reduction of revenues. Such surplus revenues are exduded from the net revenues available under the General Revenue Bond Resolution f'General Resolution 1 to meet debt service requ i rements for such year. Surplus revenues are i nduded i n the determination of net revenues available under the General Resolution to meet debt service requirements i n the year that such surplus revenues are taken into account i n setting rates. The D i strict recognizes any deficiency i n revenues needed to meet revenue requirements in any year as an accrual or i naease in revenues , even though the revenue accrual will not be realized as ~cash* until some future rate period. Such r evenue deficiency i s i nduded , *n the year accrued , i n the net revenues available under the General Resolution to meet debt service requ i rements for such year. Revenue deficiencies are exduded i n the determ i nation of net revenues available under the General Resolution to meet debt service req ui rements in the year that such revenue deficit i s taken i nto account i n setting rates. The District deferred or decreased revenues a net amount of $35.2 m i ll i on i n 20 17. The District's revenues i n 20 17 from electric sales t o retai , wholesale , and other utilities resulted *n a surplus , or over collection of costs , of $44.9 mi l i on , which was deferred (deaease i n revenues). In addition , the wholesale rates that were *n place for 201 7 i ncluded a refund of $6. 7 m ili on of SlB"plus net revenues from past rate periods. Such surplus had previously been aa:ounted for as a reduction in revenues i n the year(s) the SlB"plus occurred. Accordingly , the 20 17 revenues from electric sales , which reflect the surplus being refunded , were offset by a revenue adjusbnent (increase i n revenues) for such amou n t The District also deferred or decreased revenues by $20.0 m ili on for the pre-colection of CNS refueling and mamenance outage costs.. This reg~ory l i abiity will be eliminated throlql revenue recognition dlM'i ng the 20 1 8 outage yea,-. I n ad<ition , the District r ecognized or increased revenues by Fina]l o ial Rep©11t

$23.0 million for OPES expenses related to past service for wholesale customers under the 2016 Contracts.

The OPES expenses were included in 2017 rates and financed with proceeds from General Revenue Bonds , 2016 Series E (Taxable). The District recognized or inc r eased revenues a net amount of $54.8 million in 2016. The District's revenues in 2016 from electric sales to retail , wholesale , and other utilities resulted in a surplus , or over collection of costs , of $10.0 million , which was deferred (decrease in revenues). In addition , the wholesale rates that were in place for 2016 included a refund of $17.4 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred.

Accordingly , the 2016 revenues from electric sales , which reflect the surplus being refunded , are offset by a revenue adjustment (increase in revenues) for such amount. The District also recognized or increased revenues by $24.7 million for CNS fall refueling and maintenance outage costs , which costs were pre-collected for in 2015. This regulatory liability was amortized through revenue during the 2016 outage year. In addition , the District recognized or increased revenues by $22. 7 million for OPES expenses related to past service for wholesale customers under the 2016 Contracts. The OPES expenses were included in 2016 rates and financed with proceeds from General Revenue Bonds , 2016 Series E (Taxable).

The District deferred or decreased revenues a net amount of $23.7 million in 2015. The District's revenues in 2 0 15 from electric sales to retail , wholesale , and other utilities resulted in a surplus , or over collection of costs , of $11.0 million , which was deferred (decrease in revenues). In addition , the wholesale rates that were in place for 2 0 15 i nduded a refund of $12.0 million of surplus net revenues from past rate periods. Such surplus had p r eviously been accounted for as a reduction i n revenues in the year(s) the surplus occurred. Accordingly , the 2 0 15 revenues from electric sales , which reflect the surplus be i ng refunded , were offset by a revenue adjustment (i n crease in revenues) for such amount. The District also deferred or decreased revenues by $24.7 million for the p r e-collection of CNS refueling and maintenance outage costs. This regulatory liability was eliminated through revenue recognition during the 2016 outage year. The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements i n future rate periods was $206.9 m i llion , $168.7 million , and $176.1 m i ll i on , as of December 31 , 2017 , 2016 , and 2015 , respectively. Operating Expenses The following chart illustrates operating expenses for the years ended December 3 1 , 2015 through 2017. $1,200 Power Purchased

& Fuel $1,041 $1,000 Production Operation

& Maintenance

(" O&M") U) $800 Transmission

& Distribution O&M s:: 0 ::E Customer Service & Information

$600 VI ... Administrative

& General .!!! 0 $400 0 Decommissioning

$200 Depreciation

& Amortization

$0 Other 2015 2016 2017 20 Financial Rep011t Total operating expenses in 2017 were $988.9 million , a decrease of $51.8 million from 2016. Total operating expenses in 2016 were $1 , 040.7 million, an increase of $80.4 million from 2015. The changes were due primarily to the following: Power purchased and fuel expenses were $342.8 million, $347.6 million , and $365.1 million in 2017 , 2016 , and 2015 , respectively. These expenses decreased

$4.8 million in 2017 as compared to 2016 due primarily to fewer energy purchases in the SPP Integrated Market as there was no refueling and maintenance outage at CNS. The favorable power purchased variance was partially offset by an unfavorable fuel variance from higher generation in 2017. These expenses decreased

$17.5 million in 2016 as compared to 2015 due primarily to additional energy purchases from NC2 and the wind facilities , and lower fuel costs as the result of decreased generation.

Production operation and maintenance expenses were $243.3 million , $287.7 million , and $242.8 million in 2017 , 2016 , and 2015 , respectively.

These costs decreased

$44.4 million in 2017 as compared to 2016 due primarily to the costs associated with a planned refueling and maintenance outage at CNS completed on November 8 , 2016. No such outage occurred in 2017. In 2016 these costs increased

$44.9 million due primarily to the costs associated with the planned refueling and maintenance outage at CNS. Transmission and distribution operation and maintenance expenses were $100.9 million , $102.0 million , and $87.3 million , in 2017 , 2016 , and 2015 , respectively.

These costs decreased

$1.1 million in 2017 as compared to 2016. These costs increased

$14.7 million in 2016 as compared to 2015 due primarily to higher fees charged by SPP for the District's share of qualifying transmission upgrade projects , induding an SPP resettlement for prior periods for the implementation of a tariff provision to compensate transmission upgrade sponsors for qualifying upgrades used by other transmission customers. Customer service and information expenses were $16.0 million , $17.7 million , and $17.2 million , in 2017 , 2016 , and 2015 , respectively.

Admin istr ative and general expenses were $106.2 million , $94.1 million , and $66.3 million , in 2017 , 2016 , and 2015 , respectively.

Administrative and general expenses i ncreased $12.1 million in 2017 as compared to 2016 due primarily to a reclassification in 2017 to indude all OPEB costs with adm i n i strative and general expense , a portion of these costs were in duded in operation and maintenance expense in prior years. These costs in creased $27.8 million in 2016 as compared to 2015 due primarily to OPEB expenses related to past service and indu ded in 20 1 6 rates. Details regarding OPEB , in dud in g the earty adoption of new accoun tin g gu i dance in 2016 , are indu ded in Note 11 in the Notes to F in ancial Statements. Decomm i ssion in g expenses were $19.9 million , $21.4 million , and $14.7 million , in 2017 , 20 16 , and 20 1 5 , respectively.

Prior to 20 17 , decommissioning expenses only represented the net a mount accrued each year for the future decommissioning of CNS. Commencing in 2017 , decommissioning expenses also indu ded amounts collected in rates for the future decommissioning of certa in non-nud ear utility plant assets. Decommissioning expenses are recorded in an amou nt equ iv alent to the incom e on investments in the nud ear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such y ear. Decommissioning expenses deaeased $1.5 million in 20 17 as compared to 2016. Thi s decrease was due to a $7.4 million decrease in investment incom e for the nud ear facility decommissioning fund , which was partially offset by $5.9 million in collections for decommissioning of certain nOl'Hlud ea r utility plant assets. Decommissioning expenses in creased by $6.7 million in 2016 as compared to 20 15 due to an *naease i n interest i ncome on investments. No add itional amounts for decomm i ssioning were collected through rates in 2016 and 2015. Depreciation a nd amortization expenses were $122.6 miUion , $133.7 million , and $1 30.2 m" lion , in 2017 , 2016 , and 2015 , respectively. The deaease in depreciation a nd amortization expenses was due primarily to a change in the estimate to longer asset liv es for certain transm i ssion assets. Increase in Net Position The i ncrease i n net position was $7 1.3 milion , $82.9 million , and $9 1.1 m* *on , i n 2017 , 2016 , and 2015 , respectively. The change in net position i n 2017 as compared to 2016 decreased

$11.6 million and was due Fi ili umcial R~p©rt pr i mar i ly to a decrease i n 2017 reve n ue r equirements from reduced collect i ons fo r pr i ncipal payments fo r debt s e rv i ce and utility plant add i tions , an i nc r ease in unrealized i nvestmen t losses and lower capital i zation of i nterest d u r i ng construction. These decreases i n net pos i tion were pa rti ally offset by a r educt i on in depreciation expense. The change in net position i n 2016 as compared to 2015 decreased

$8.2 million and was due primar i ly to a dec r ease i n 20 1 6 revenue r equirements fr om decreased collect i ons for pr in cipal payments for revenue bonds and c o nstruction from revenue , partially offset by increased collect i ons for p ri nc i pal payments on commercial paper n o tes The following chart i llustrates the Dist ri ct's operat i ng r evenues , other reve n ues , operating expe n ses , and other e x penses for th e years e n ded Decembe r 31 , 2015 t hrough 20 1 7. Revenues & Expenses $1,250

$1,200 -----------------------

en $1 , 150 L--------*,...L.2 $1,100 +---lii&iiil-----1 $1,050 -+-----i -f $1,000 +----I $950 ----$1,09 o $900 +--.....; $850 ____ _, $800 +--_Ji,_..,.....,,!

2015 2016 2017 F I NANC I AL MANAGEMENT PO LI C Y Other Expenses Operating Expenses Other Revenues Ope r at i ng Revenues Th e Di s trict h as a Fin a nci a l M a n ag em e nt Policy (th e *P olicy"), which i s s ubj ect to pe riodi c r e vi e w a nd r e vision s by th e Boa r d. Thi s P ol icy r e pr ese nts ge n era l fin a nci a l s trat eg i es a nd pr oced ur es th a t a r e i mplemented to demon s trat e fin a nci al int eg rity a nd fi scal r e sponsibility in th e m a n ag em e nt o f th e Di s trict's busin ess a nd it s assets. E mpl o y ees must a bi de by a ll appli cable Di s trict bylaws , Bo ard r e soluti o n s , bond resolution s , f ed eral and s tat e laws , other r e l e v a nt l egal r eq uir e m e nt s a nd th e Policy. DEBT SERVICE CO V ERAGE Under th e Policy , th e Di s trict h as established a m i nimum debt s ervice cov erage ratio on th e G en era l R e venue Bond s of 1.5 tim es th e debt servi ce on th e G eneral R e venu e Bond s. Th e District's d eb t servi ce cov erage ratio was 2.13 , 1.98 , and 1.84 , i n 2017 , 20 1 6 , and 2015 , respectively. Th e cov erage was provided primarily by the amounts collected i n operating revenu es for utility plant addition s , for principal and i nterest payments on outstand i ng commerci al paper not es and revolving credit agreem e nts , and for payments to those municipaliti es se,ved by th e District under long-term PRO Agreements. The i ncr ease i n the 2017 debt service coverag e ratio over 20 1 6 and the i ncrea se i n th e 2 016 debt service coverage ratio over 2015 were primarily due to a deaease i n the required debt servi ce deposits. A NA N C I NG AC TMTI ES Good credit ratings allow the District to borrow funds at more favorable i nterest rat es. Such rating s reflect only the view of such rating organization s , and an explanation of the significance of such rating may be obtained only from the respectiv e rating agency. There i s no assurance that such ratings will be maintained for any given period of ti me or that they wil not be revised downward or be withdrawn entirely by the respective rating agency if , i n its 22 FiJ;umcial Repo]t judgment , circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the market prices of bonds. The District's credit ratings on its revenue bonds were as follows: Moody's Investors Service ............................................................................ A 1 Standard & Poor's Ratings Services ............................................................. A+ Fitch Ratings ...................................................................................

...........

... A+ (stable outlook) (stable outlook) (stable outlook) The District plans , pursuant to the Policy , to issue separate series of indebtedness , including separate series of General Revenue Bonds , for production projects and for transmission projects.

No more than 20.0% of the amount of outstanding indebtedness issued for production projects , calculated at the time of issuance of each series of such indebtedness , or $200.0 million , whichever is less , will be permitted to mature after January 1 , 2036 , the end of the 2016 Contracts. Transmission indebtedness issued for transmission projects is expected to mature over the useful life of the asset that is being financed. New transmission indebtedness may mature after January 1, 2036. The District's transmission indebtedness is payable from the revenues received during the term of the 2016 Contracts and from retail sales and transmission revenues received under various SPP tariffs. After January 1 , 2036 , transmission indebtedness will be payable from revenues to be derived from wholesale and retail customers who use the District's transmission facilities , as well as revenues from various SPP tariffs. On January 1 , 2018 , the District called the remaining outstand i ng General Revenue Bonds , 2012 Series C , with a p ri ncipal amount that aggregated

$4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of OPEB costs for customers under the 2016 Contracts. I n June 2017 , the District executed a Tax-Exempt Revolving Credit Agreement

("TERCA") with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $150.0 million , which replaced its Commercial Paper Notes program. I n April 2017 , the District issued General Revenue Bonds , 2017 Series A and 2017 Series B , in the amount of $86.0 m i llion to refund the General Revenue Bonds , 2007 Series B. The refunding r educed total debt service payments over the life of the bonds by $11.8 million , which resulted in present value savings of $10.0 million. I n November 2016 , the District i ssued General Revenue Bonds , 2016 Series C and 2016 Series D , i n the amount o f $113.5 million to finance the costs of certain generation and transm i ssion capital projects and refund $61.7 m illion Tax-Exempt Commercial Paper ("TECP"). The District also issued i n November 2016 , General Revenue Bonds , 2016 Series E (Taxable), i n the amount of $56.1 million to fund a portion of OPEB costs for rustomers u n der 2016 Contracts. I n February 2016 , the D i strict i ssued General Revenue Bonds , 2016 Series A and 2016 Series B , i n the amount of $139.2 million to advance r efund $138.9 million of bonds and refund $16.5 m i llion of TECP. The refunding reduced total debt service payments over the life of the bonds by $29.8 m il lion , which resulted i n present value savings of $20.8 m i llion. I n January 2016 , the Dismct i ssued TECP i n the amount of $43.6 mi l li on to refund a portion of the General Revenue Bonds , 2005 Series C and General Revenue Bonds , 2006 Series A. I n February 20 1 6 , $1 6.5 m i llion of TE CP was refunded by General Revenue Bonds , 20 1 6 Series A and Series B. Details of the District's debt balances and activity are i nduded i n Note 7 in the Notes t o Financial Statements. CAPITAL REQUIREMENTS Th e Board-authorize capital projects totaled approximately

$85.0 mi l ion , $1 09.5 mill ion , and $50 1.0 m il ion , in 2 017 , 2016 , and 20 1 5 , respectively. The District's capital r equ irem ents are fu nded with m oni es generated from operations , debt proceeds , and other ava i lable reserve fu nds. Fi:nam:oial Rep01;t Capital projects for 2017 included: * $14.7 million for implementation of Advanced/Smart Metering and Interfaces

$11.2 million for construction of an evaporation pond at GGS * $6.4 million for refurbishment of a 115 kV substation in Beatrice , Nebraska Capital projects for 2016 included: * $22.0 million for const r uction of a high-voltage transmission line from the Muddy Creek substation to Ord , Nebraska * $16.4 million for construction of a high-voltage substation in Holt County , Nebraska and expansion of the GGS 345 kV substation

$12.6 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2 Capita l projects for 2015 included: * $346.8 million for construction of a high-voltage transmission line and related substations from a GGS substation north to Cherry County , Nebraska and east to a new substation in Holt County , Nebraska * $33.9 million for modifications to the hot flue gas ductwork at GGS Unit 2 * $33.1 million for construction of a high-voltage transmission line from a substation in Stegall , Nebraska to a substation in Scottsbluff , Nebraska T h ere were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $52.7 million , $59.0 million , and $87.2 million for 2017 , 2016 , and 2015 , respectively.

Th e Board-autho ri zed budget for cap i tal projects for 2018 i s $1 18.9 m i llion. Specific capital projects for 2018 i ndude: * $25.5 m illion for retrofit of the low pressure turb i ne for GGS Unit 2 * $4.5 million for refurbishment of the m a in generator exciter at CNS * $4.3 million for a tra i n i ng facility i n York , Nebraska The following chart i llustrates the Boa r d-authorized capital projects for the years ended December 3 1 , 20 1 5 th rough 2017 , i nduding the Board-authorized budget for the y ear ended Decembe r 3 1 , 2018. $600 $501 $500 -C/l C: $400 .2 = :E $300 -C/l ... $200 0 $110 0 $119 $100 --~ $------2015 2016 2017 2018 Budget RESOURCE PLANNING The Di s trict uses a div erse m i x of generation resou rces such as coal , n uclear , natu ral gas , hydro and wind to meet its firm requirement customer's needs. In 20 1 7 , the non-carbon energy resom:es as a percentage of nativ e load sales were 65%. 24 Fifa1ai:ncial ReJil(!llit The District's last comprehensive 20-year Integrated Resource Plan ("IRP") was completed and approved by the Board in 2013. Since that time there have been several changes in assumptions that have now been included in the limited scope, five-year IRP approved by the Board at their March 2018 meeting. The 2018 IRP shows the District does not require new resources for the next five years. The changes in assumptions in the 2018 IRP included:

2016 V\/holesale Power Contracts

-The negotiation of new contracts with the District's wholesale customers , which extended the term 20 years for all but ten of the current customers. The new contract allows a 10% renewable self-supply option , or 2 MW, whichever is greater.

Cooper Nuclear Station Power Uprate -The decision by the Board not to proceed with a power uprate at its nuclear facility , a low-cost resource option included in the 2013 IRP, due to a more detailed evaluation of costs and market risk.

Renewable Energy -The addition of two new wind facilities of which 74 MW will be used to serve the District's finn customers. This brings the total amount of wind in the portfolio of resources serving its firm customers to 281 MW.

Sheldon Station -The recapture of approximately 65 MW of capacity and energy from Sheldon after the Board approved ending the participation sale for 30% of Sheldon's output to LES.

Southwest Power Pool Integrated Market -In 2014 , SPP commenced a Day-Ahead , Ancillary Services , and Real-Time Balancing Market. The District , in tum , began participating as a member utility in the energy market place. The market coordinates next-day generation across its footprint to maximize cost effectiveness for its members. The District sells and purchases power in the SPP Integrated Market. A significant amount of renewables, primarily wind , continue to be added in the SPP Integrated Market.

Hydrogen Generation

-Monol i th Materials , Inc. ("Monolith

) has expressed an interest to construct and operate a carbon black facility adjacent to the District's Sheldon coal-fired generating facility in Nebraska. The construction of the carbon black facility is expected to be accomplished in two phases. The electric load to serve any Monolith facility will be served by Norris Public Power District , a finn wholesale customer of the District. At full buildout , Monolith may be the single-largest industrial customer served in the District's territory. The District entered into a 20-year contract with Monolith to purchase the carbon black plants' production of hydrogen rich tail gas , which will be produced by Monolith during production of carbon black. The District will have to convert its existing coal-fired boiler at Sheldon Unit No. 2 to bum the hydrogen rich tail gas. The boiler conversion is expected to result in a reduction of carbon dioxide (" C02 u). sulfur dioxide ("S02 u). mercury , and other air emissions. Groundbreaking for Phase 1 occurred in October 2016 and i s expected to be mechanically complete in 2018 and fully operational in 2019. Phase 2 construction is planned to begin in the second half of 2020. The oommercial operation date (defined jointly as the date on which Phase 2 is capable of sufficient , steady state hydrogen rich tail gas supply , and the Sheldon Unit No. 2 boiler has been converted and oomm i ss i oned) i s scheduled for the second quarter of 2021. ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of ri sks , i nduding exposure to volatility i n electric energy and fuel prices , uncertainty i n load and resource ava i lability , the aeditworth i ness of its counterparties , and the operational ri sks associated with transacting i n the wholesale energy markets. To help manage energy ri sks , i ndud i ng the ri sks related to the District's participation i n the SPP Integrated Market, the District rel i es upon TEA to both transact on its behalf i n the wholesale energy markets and to develop and recommend strateg i es to manage the Dis tri ct's exposure to ri sks i n the wholesale energy markets. TEA oombines a strong knowledge of the D i strict's system , an i n-depth understand i ng of the wholesale energy markets , experienced people , and state-Of-the-art tech n ology t o deliver a broad range of standardized and wstomized energy products and services t o the D i strict. TEA has assisted the District i n developing its Energy Risk Management C ERM") program. The program orig i nates with the Board-approved ERM Govern i ng Pol i cy and the ERM-Approved Products and Li mits Standard. These documents establ i sh the philosophy , objectives , delegation of authorities , approved producls and thei r li mits on the District's energy and fuel activities necessary t o govern its ERM program. The objective of the ERM program is to i ncrease fuel and energy price stabi flly b y hedging the ri sk of sign ifi cant adverse i mpacts to cash F i na in oial Rep0lit 25 flow. These adve r se impacts could be caused by events such as natural gas or powe r price vo l a ti lity , or extended unplanned ou t ages. The ERM program has been developed to provide assurance to the Board that the r isks inherent in the w h olesale ene r gy market a r e be i ng quantified and appropr i ately managed. ECONOMIC FACTORS Prelim i nary data i ndicated Nebraska's economy experienced a decline in 2017 , after three years of slow i ng growt h r ates. T h e State's i nflation ad j usted , estimated gross s t ate product (" GSP") decreased b y 0.8% from the th i rd quarter of 2016 to the t h i rd quarter of 20 17. The U.S. economy exper i enced a 2.2% increase in nat i onal gross domestic product ove r the same 1 2-month pe ri od. Prev i ous estimates of Nebraska's GSP were also revised downward. The t hird quarte r estimates for 20 1 6 , 2015 , a n d 2014 were decreased 1.3%, 0.9%, and 0.7%, respectively.

Nebraska's decline in GSP over t h e l atest 1 2 months was due t o declines in t he " Agr i culture , forestry , fishing , and hunt i ng", " Real estate and r e nt al and l eas i ng" , " Managemen t of compan i es and ente rpri ses", " Construction" and " Ut i lit i es" i ndust ri es. Nebraska and th e Midwest r egion continue to expe ri ence unemployment r a t es t h at a r e below the n a ti ona l average. Nebraska's ave r age annual unemploy m e nt r ate decreased from the rev i sed 2016 value o f 3.1 % t o 2.9% in 20 1 7. These r a t es were w ell be l ow th e nat i o n a l December seasona ll y adjusted unemployment r ates of 4.4% and 4.7% i n 20 17 a n d 2016 , r espective l y. After seve r a l years o f cons i ste ntly being o n e of the t hr ee states wi th t h e lowes t u nemp l o ym ent r ates , Nebraska's prel i m in a ry Decembe r 2017 and r ev i sed Decembe r 2 01 6 u nemp l oy m e nt rates w ere the f o u rth and nin th lowes t in the n a ti o n , respect i ve l y. The Dist ri ct co ntinu es t o mo nit o r changes i n n ational and globa l eco n o mi c cond iti o n s , as these cou l d i mpact th e cost o f debt a n d access to cap i ta l marke t s. CERTAIN FACTORS AFFEC TI NG THE ELECTRIC UTILITY INDUSTRY T he Be ctri c U tili ty In dustry In Gene r a l Th e e l e ctri c utility in d u s try h as bee n , a n d in th e futur e m a y b e , affected b y a num ber o f f actors which coul d im pa ct th e fin a nci al con d iti on a n d co m pe titiv e n ess o f el ectric utiliti es , s uch as th e D i s bict. S uch f a ctors indu de , a m o n g o th ers:

e ff e ct s of compli a n ce with ch a n g in g environm e ntal , sa f e ty , li ce n s ing , r eg ulat o ry , a nd l eg isl a tiv e r eq ui r em e n ts ,

ch a n ges r esu ltin g from energy e ffici e ncy a nd d e m a nd-sid e m a n a g e m e nt program s on th e timing and u se o f electri c e n e rgy ,

in creas ing dem a nd by cu s tom e rs for self-m a n ag ing ener g y u se to l o w e r their energy costs ,

oth e r f edera l a nd s tat e l eg islativ e a nd r eg ulatory ch a ng es ,

incr eased whol esa l e competition from ind e pend e nt pow er producers , m a rk e ters , and brok e rs ,

low m a rk e t pri ces for whol esale pow er , * ~se lf-generation

by certain i ndusbial a nd comm e rcial custom e rs ,

i ss u es relatin g to the ability to issu e tax-e xempt obligation s ,

se v e r e resbiction s on th e ability to sell to nongov e rnm e ntal entiti es electricity from generation projects financed with outstanding tax-e xempt obligation s ,

chang es from projected future load requirement s ,

in creases in co sts ,

shifts i n the availability and relative costs of different fuel s ,

in a dequate risk m a nagement procedures and practices with respect to , a mong other things , th e purdla se and sal e of energy , fuel , and transm i ssion capacity ,

effects of financial i nstability of va ri ou s participants in the power market,

d i mate chang e and th e potential contribution s made to d i mate chang e by coal-fired and other fueled generating units ,

in creased regulation of nuclear power plants in the United States resulting from the earthquake and tsunam i damage to certain nuclear power plants in Japan , and

i ssues relating to cyber a nd physical security. Any of these general factors (as well as other factors) could h a v e an effect on the financial condition of the District.

26 Eiililam: cfa l l :Re:p011.t Competitive Environment in Nebraska While wholesale competition is expected to increase in the future, there is a Nebraska statute that proh i bits competition for retail customers. Pursuant to state statutes , retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppliers and/or pursuant to an order of the Nebraska Power Review Board. While state statutes do not provide for wholesale suppliers of electricity to have exclusive rights to serve a particular area or customer at wholesale , wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements. Finan o ial R~piont REPORT OF INDEPENDENT AUDITORS To the Board of Directors of the Nebraska Public Powe r District:

We have aud i ted the accompany in g financial statements of Nebraska Publ i c Power District (th e " District"}, which comprise the balance sheets as of December 31 , 2017 and 2016 , and t he related statements of revenues , expenses , and changes in net position , of cash flows , and the related notes to the financial statements for the years then ended. Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; thi s includes the design , im plementation , and maintenance of int ernal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement , whether due to fraud or erro r. Auditors' Responsibility Our responsibility is to express a n opinion on the financial statements based on our aud its. We conducted our aud i ts in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit t o obtain reasonable assurance about whether the financial statements are free from material misstatement.

An aud it involv es perform in g procedures t o obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our ju dgmen t, includin g the assessment of the risks of material misstatement of the financial statements , whether due to fraud or error. In making those risk assessments , we consider int ernal control relevant to the District's preparation and fair presentation of the financial sta t ements in order to design aud it procedures that are approp ri ate in the circumstances , but not for the purpose of express ing an opinion on the effectiveness of the D i strict's int ernal control. Accordingly , we express no such opinion. An aud it also inclu des evaluating the appropriateness of accoun tin g policies used and the reasonableness of s i gnificant accounting estimates made by management , as well as eva lu a ting the overall presentation of the fin a nci al statements. We believe that the audit evidence we h ave obtained i s sufficient and approp ri ate to provide a basis for our a udit opinion. Opinion In our opinion , the financial statements referred to above present fair1y , i n all material respects , the fin ancia l position of the District as of Dece m ber 31 , 2017 and 2016 , a nd th e results of its operations and its cash flows for the years then ended i n accordance with accounting principles generally accepted in th e United Sta t es of America. Emphasis of Matter As discussed i n Note 1 and Note 9 to the financial statements , th e District changed the manner i n wh i ch it accounts for Asset Retirement Obligations i n 2017. Our opinion i s not modified with respect to th i s matter. Other Matters The accompanying management

's d i scussion and analysis and the supplemental schedules on pages 11 through 27 and 65 through 67 , respectively , are requ i red by accounting principles generally accepted i n th e United States of America to supplement the basic fin an cial statements. Such i nformation , although not a part of the basic financial statements , is requ i red by the Governmental Accounting Standards Board who considers it to be an essential part of fin a ncial reporting for placing the basic financial statements i n an appropriate operational , economic, or historical context We have applied certa i n l imited procedures t o the requ i red supplementary i nformation i n accordance with auditing standards generally accepted i n the United States of America , wh i ch consisted of i nqu i ries of management about the methods of preparing the i nformation and comparing the in formation fo r consistency with managemen t's responses to our i nqu *ries , the basic fin ancial statements , and other knowledge we obtained du ri ng our audits o f the basic financial statements. We do no express an op i n i on or provide any assurance on the in formation because the limited procedures do n ot provide us with sullicienl evidence to express an op" nion or provide any assurance. Our audits were conducted for the purpose o f tonn *ng opinions on the fi nancial statements that colledively comprise the District's basic fi nancial slatements. The statistical review is presented for purposes of additional analysis and is n ot a req " red part of the basic fi nancial stalements. SUch i n formation h as not been subjected to the auditing proced u res applied in the audi!s o f the basic fi nancial statements , and acmrdingly , we do n ot express an op-iion or provide a n y assurance on it ~LuJ St Louis,, Missou ri April 12, 20 1 8 28 Hi n mmia l Rl~p o r t FINANCIAL STATEMENTS Nebraska Public Power District Balance Sheets as of Decermer 31 , (in OOO's) ASSETS AND DEFERRED OUTFLOWS Current Assets: Cash and cash equivalents

....................................................................... . lnwstrnents

............................................................................................. . Receivables , less allowance for doubtful accounts of $541 and $530 , respectil.ely

........................................

..................... .. Foss il fuels , at awrage cost ....................................................

................ .. Mater i als and supplies , at aw rage cost .........................

............................ . Prepayments and other current assets ...................................................... . Special Purpose Funds: Construction funds ..............

.............

......................................

...........

...... . Debt resen.e funds ............................

.............................

...............

......... .. El11)1oyee benefit funds .....................

......................

............................... .. Decorrrnission ing funds ..................

.......................................

................. .. Utility Plant, at Cost Utility plant in ser"1ce ........................

......................................................

.. Less resen.e for depreciation

.........................................................

.......... . Construction work in progress ..........

........................................

................ . l'lk.lclear fuel , at amortized cost ........................

............

............................

.. Olher Long-Term Assets: Regulatory asset for other posfenl>loyment benefits ................................... . Long-term capacity contracts

............................................................

....... . lxlamortized financing costs .............................................................

....... . lm.estment in The Energy Autholity

...............................................

............ . Other ..............................................

.............

.................................

.......... . Total Assets .................................

.........................

......................

... . Deferred Outflows d Resources: Asset retirement obligation

.....................

........................

......................... .. lklamortized cost of refunded debt ............

.....................................

.......... . Other posler1')ioyment benefits .............

........................................

............ . IDTAL ASSElS ANJ DEFERRED OOTFLOIVS

.....................................

........ . 2017 $ 27 , 804 539 , 173 120 , 254 43 , 264 111 , 644 16 733 858 872 54 , 808 88 , 764 1 , 934 600,942 746448 4 , 928 , 370 2,658,206 2 , 270 , 164 133 , 515 166,21l;l 2,569,898 210 , 362 152 , 831 8 , 201 6 , 175 6132 383,701 4,558 , 919 222 , 369 38 , 430 34 , 603 295,402 I 4,854,321 LIABILITIES , DEFERRED 11\FLOIVS , ANJ flET POSITION Current Liabilities

Rel.enue bonds , current-******************************

- - - - -***

- - - - Noles and credit ag,eernenls , current*******-*************

.. ********************

- - - - Accounls payable and accrued labilities

- - - - ----

--*---*-*---**-*-***-*-

- - - - --*-* Accrued i n leu d 1aX payments *****************

- - - - -----*-***************-*******-*

Accrued payments ID retail cornn.mities

-----**********************************************

Accrued COl1l)el1S3led absences -*---***-**************-********--------*-**-*********-*-*-**

- Olher *-*-***---*-*-*-*********-*-*******

- - - - -********

- - - - -

-*-*****-*-Long-Term Debt Rel.enue bonds , net d a.-rent --*-----*----

-*---*--------*-------***-

-*-*****************-******

Noles and credit agieernenls,, net d a.-rent --***---*-------*-***-**-*--*-*--**

**-****

Olher Long-Term LiablDes: Asset retirement obligation

- - - - --********-****************

Net oiler poslerr'*1Jrnen benefit iabiity *-*-*---*-***--*****-*-************-*-*************

Olher ***********-***-******--*-*-**--*-*****-*-----**--

---*----**----------***-****-***-*-*-*-**-**-*--**-*

Total Liabiilies

--***------*-*---------

**--**--***-**---******-*******

-**********-*-******

Deferred lnllows d Rescuces: Lheamed rewenues ...............

.....................

....................

......................... . Olher derened i nflows*******************************************-************-*-*-****************

Net Position: Net i nwestnent in eapital assets ********-*********

- - - - ...........................

.................................................................... . Lhreslricled

- - - - -***********************************************-***

-*-*****-**** IDTAL LIABILITIES , DEFERIED 11\FLOIIIS , AN> flET POSITION**********-*-****-

The accompanying notes to financial statements are an i ntegral part of these statements. Financial Report s 98 , 205 165 , 212 64 , 981 10 , 000 6 , 074 1 6 , 97 1 9058 370 , 50 1 1 , 548 , 269 69000 1, 6 17, 269 823 , 794 182, 835 2 1 838 1,028.467 3 ,016., 237 206,927 1 44n4 35 1,651 1, 029 , 230 37 , 782 41~,421 1, 486 , 433 i 4,854321 2016 $ 102 , 729 373 , 331 123 , 905 43 , 620 114 , 640 17 254 775479 106 , 204 90 , 032 4 , 851 581 770 782 857 4 , 835 , 829 2 573 645 2 , 262 , 184 1 35 , 853 197 730 2,595,767 221 , 973 159 , 445 8 , 945 6 , 370 9416 406149 4,560,252 219 , 378 42,664 82 , 289 344331 I 4,904 583 s 81 , 250 74 , 000 87 , 061 10 , 008 6 , 037 17 , 594 113n 'ZP.7,322 1 , 678 , 844 188,924 1, 86 7, 768 801 , 147 258 , 609 3362 1,063,118 3,,218,208 1 68,,710 102..548 27 1, 258 928,,967 38,,776 447374 1, 415,117 i 4,904,583 Nebraska Public Power District Statements of Revenues , E><penses , and Changes i n Net Position For the years ended December 31, (in OOO's) Operating Revenues ..................................................................................... . Operating E><penses: Pov.,er purchased

.................................................................................... . Production

Fuel ................................................................................................... . Operation and maintenance

................................................................. . Transmission and distribution operation and ma i ntenance ........................

... . Customer service and information

............................................................. . Administrative and general ....................................................................... . Payments to retail comrrunities

................................................................ . Decommissioning

.................................................................................... . Depreciation and amortization

.................................................................. . Payments i n lieu of taxes ......................................................................... . Operating Income ......................................................................................

.. . I n vestment and Other Income: Investment i ncome ................................................................................... . Other i ncome .......................................................................................... . Increase i n Net Position Before Debt and Other Expenses ............................... . Debt and Other Expenses: Interest on long-term debt ...........................................

............................. . AbAance for finis used du ri ng construction

............................................ . Bond prenium amortization net of debt i ssuance expense .......................... . Other e>q:>enses

...........*..........*...*.*........**..***.*******..**

.*****.**.*.**********...****.** Increase i n Net Position ................................................................................ . Net Position: Beginning balance ................................................................................... . Encing balance ....................................................................................... . 2017 $ 1 , 101 , 642 161 , 963 180 , 858 243 , 332 100 , 945 15 , 988 106 , 190 27 , 102 19 , 934 122 , 559 10 , 060 988 , 931 112 , 711 20 , 091 3 , 500 23 , 591 136 , 302 76 , 186 (2 , 31 7) (1 2 , 598) 3 , 715 64 , 986 7 1 , 316 1 , 4 1 5 , 1 17 $ 1 , 486 , 433 The accompany i ng notes to financial statements are an integral part of these statements. 30 2016 $ 1 , 153 , 997 177 , 121 170 , 450 287 , 672 101 , 952 17 , 696 94 , 112 26 , 553 21 , 429 133 , 666 10 , 064 1 , 040 , 715 113 , 282 28 , 239 3 , 533 31 , 772 145 , 054 75,415 (4 , 1 20) (1 1,42 7) 2 , 253 62 , 1 2 1 82 , 933 1 , 332 , 184 $ 1 , 4 1 5 , 117 Fin a ncial Rep@Ii t Nebraska Public Povver Distr i ct Statements of Cash Fl o ws For the years ended December 31 , (in OOO's) Cash Flows from Op e rating Activities

Receipts from cu s tomers and others ......................................................... . Other receipts ......................................................................................... . Payments to suppl i ers and vendors ........................................................... . Payments to employees

........................................................................... . Net cash provided by operating activities

.............................................. . Cash Flows from Investing Activities

Proceeds from sales and maturities of investments

..................................... . Purchases of i nvestments

.........................................

.............

.................. . Income received on i nvestments

............................................................... . Net cash prO\,;ded by (used in) i nvesting activi ti es ................................. . Cash Flows f r om Capital and Related F i nancing Activities

Proceeds from issuance of bonds ...............................................

............. . Proceeds from notes and credit agreements

.............................................. . Capital expenditures for utitity plant ........................................................... . Contr i butions i n a i d of construction and other r e i rmursements

.................... . Pr i nc i pal payments on long-term debt ....................................................... . Interest payments on long-t erm debt .............................................

............ . Interest paid on defeasance deb t ...........................................

................... . P ri nc i pal payments on notes and cred it agreements

.....................

.............. . Interest payments on notes and c r ed i t agreements

..................................... . Olher non-operating r~ues ............

...................................................... . Net cash used i n capital and related fi nanc i ng ac ti\n ti es .............

............ . Net i ncrease (decrease) in cash and cash equivalents

................

.......... . Cash and cash equ i valents , beg in n i ng of y ear ................................................ . Cash and cash equ i valents , end of y ear ....................................

..................... . Reconc ili ation of Operating Income to Cash P r o\lided By Operati ng Ac ti\liti es: Operating i ncome ...................

..................................................

............... . Adjustments to r econc i le operating i nc ome to net cash pr o\lided by operating acti\lities

Deprec i ation and amortizati on .................

.........................................

... . Uldi sbibuted net r evenue -The Ener gy Authority

....................

............. . Decormissi oni ng , net of cuslomef" contributions

...................

...........

..... . Amortization of n uclear fuel ................................................................. . Changes i n assets and li abi iti es Wlich (used) pro\li ded cash: Receivables , net ..................................

......................

.................... . Fossi l fuels****************************************-**--*****************-**********-*-**-***

- - Nlalerials and Slff)li es ---****---**-****-***-*****

- - - - -*

-*******--*-*-*-*****-*--**-***

Prepay ments and olher c..-rent assets-*--*--**--**-*-*--*******--*--**-

Other long-term assets ***-*-*****-***-*---

- -****-*-**-****---*--*

- - - - -**-*---*****-**

Defened outflows---*-**-***-*------**-*--****-*-

-*--**-***--**--*-****--*

-**-------*-**--.Accomls pay able and accrued paymenls to r etail cormu,i ti es ---**--*--

ltlearned r ewenues **-**------*--***----*--*----**--**-*-**-*-*-*-*--------*-----------**--*

Other defened i nflows----**---*

-*--*----***---*----**---**

*-

Other liabiiti es ---*---*-**--*--*

*--------*--------

*----*-------*---*-*-------*---*** Net cash prOlided by operating ac lniti es **-------------*******-***-********--**-**-**** ~ella y l'bl-Cash CapitalAciNti es: Change in uti ity pall: addtions in accol.W1ls payable********************-**************

Th e acco mp a n yi ng n otes to fi nanc ial state m e n ts a re an i ntegra l p art of t he s e stat e me n ts. FinaiRcial Repo11t $ $ $ $ $ 2017 20 1 6 1 , 112 , 281 $ 1 , 067 , 143 679 209 (503 , 685) (565 , 252) (244 , 178) (248 , 389) 365,097 253 , 711 2 , 792 , 011 2 , 775 , 601 (2 , 920 , 4 1 1) (2 , 800 , 722) 20 , 962 27 , 495 (107 , 438) 2 , 374 96 , 957 354 , 776 98 , 737 163 , 807 (1 40 , 665) (26 1 , 900) 9 , 062 18 , 864 (191 , 160) (284 , 710) (76 , 920} (77 , 776} (1 , 1 0 7) (10 , 1 94) (1 2 7 , 449} (142 , 583) (3 , 554} (2 , 1 45) 3 , 515 3 , 445 {332 , 584) (238 , 4 1 6) (74 , 92 5} 1 7 , 669 1 02 , 729 85 , 060 2 7, 804 $ 1 02.729 1 1 2 , 711 $ 1 13 , 282 1 22 , 55 9 1 33 , 666 108 648 1 4 , 006 2 1 , 4 29 43 , 4 90 40 , 754 5 , 409 (10 , 9 11) 356 (4 , 285) 2 , 996 2 , 790 443 1 , 022 938 935 (45 , 654) (11 , 2 75) 1 9 , 1 22 38 , 2 17 (7 , 408) 33 , 404 (1 4 , 342) 1,7 35 2 , 663 365 , 097 $ 253 ,711 (1 0,768! $ 4 , 273 NOTES TO FINANCIAL STATEMENTS

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES: A. Organization

-Nebraska Public Power District ("Distr i ct"), a public corporat i on and a political subdivision of the State of Nebraska , operates an integrated elect ri c utility system which i ncludes facilities for the generation , transm i ss i on , a n d d i stribution of electric power and energy to i ts Reta i l and VVholesale c u stomers. T h e control of the Dist ri ct and its operations is vested in a Board of Directors

(" Board") cons i sting of 11 members popularly elected from d i stricts comp ri sing subd i v i sions of the District's chartered territory. The Board is aut h o ri zed to establis h ra t es. B. Basis of Accounting

-T h e fi n ancial statements are prepared i n accordance with Generally Accep t ed Accoun ti ng P ri nciples (" GAAP") for account i ng gu i dance prov i ded by the Governmental Account i ng Standa r ds Boa r d (" GASS") for prop ri etary funds o f governmental entities. In the abse n ce of es t abl i shed GASS pronouncements , other accoun ti ng l i terature i s followed i ndud i ng gu i dance prov i ded i n the Financial Accounting S t andards Boa r d (" FASS") Account i ng S t andards Cod ifi cat i on (" ASC"). The District appl i es t h e acco u nting polic i es establ i shed i n th e GASS codificat i o n Section Re10 , Reg u lated Opera ti ons. Th i s gu i dance perm i ts an en ti ty with cost-based r a t es and Boa r d autho ri za ti on to in d u de revenues or costs in a period other than t he pe ri od i n wh i ch the r evenues o r costs would be repo rt ed by an unregulated en ti ty. C. Re v enue-R e ta il and wholesale r even u es are r eco r ded in th e pe ri od in wh i ch serv i ces a r e r endered. Revenues and expenses related t o prov i d i ng energ y serv i ces in connection with the D i s tri ct's p ri ncipa l ongo i ng ope r ations are dass ifi ed as ope r a ti ng. Al l o th e r r eve n ues and expenses a r e dass i fied as non-opera tin g and r epo rt ed as i n v es tm ent and* o th e r in co m e or deb t a n d o th e r expe n ses on th e Statemen t s o f Reve nu es , Expe n ses a nd C h anges i n Net Pos iti on. D. Cash and Cash Equivalen t s -Th e operating fun d acco u n t s a r e ca ll ed Re v en u e F un ds. Th e r e i s a separa t e i n v es tm e nt acco unt for th e Re v e nu e F un ds. Th e Dis tri ct r eports hi g h l y l i q ui d in ves tm ents in th e Revenue F un ds with a n o ri g i nal m a turity of thr ee month s or l ess t o be cash a n d cash eq uiv alents o n th e bala n ce s h ee t, exce pt fo r th ese type o f i nv estments in th e Reve nu e F u nds i nv estmen t accou nt. Ca sh and cash equ iv ale nts in th e in ves tm e nt accou n ts for th e Re v e nu e Fun ds and the S peci al P u rpose Fun ds are r eported as inv es tmen ts o n th e bal ance sh ee t E. Fossil Fuel and Materials and Suppl i es -Th e Di s trict m a in ta in s inv e ntori es f o r fossi l fu els a n d m ate ri a l s a n d suppl i es which a r e v a lu ed a t a v erage cost Obsolete inv ent ory i s expensed an d rem o v ed from inv e ntory. F. Utility Plant , Depreciation , Amortization , and Ma i ntenance-Utility plant i s stat ed at cost. which i ndud es property ad dition s , repl acem ents of units of property and betterments. The Distri ct charg es mainten ance and repai rs , including the cos t of renewal s and replacem ents of minor item s of property , t o maintenan ce e xpen se accou nts when i ncurred. Upon retirement of property subject to depeciation , the cost of property i s removed from th e plant accounts and charged to th e reserv e for depreciation , net of salvage. Th e District records depreciation over the estimated u se ful l ife of the property primarily on a straight-line basi s. Depeciation on utility plant wa s approximately 2.3% and 2.6% for th e y ea rs ended December 3 1 , 2017 and 2 016. Th e District had fully depeci a ted utility plant, primarily related to Cooper Nuclear Station (" C N S"), which was still i n service of $978.1 m i lion and $927.5 m i lion as of December 31 , 2017 and 2016 , respectively. The District has long-term Professional Retail Operation s (" PRO'") Agreements with 79 mlMlicipaliti es for certm retail electric dislri>ution systems. These PR O Agreements obl i gat e the District to mak e payments based on gross revenues from the municipalities and pa y for normal property add iti on s during the term of the ag reements. The District recorded provisions , net of retirements , for amortization of these plant a<kition s of $7.5 million a1d 32 Fhiancial Repont

$5.9 million in 2017 and 2016, respectively , which was included in depreciation and amortization expense. These plant additions , which were fully depreciated , totaled $191.8 million and $185.6 million as of December 31 , 2017 and 2016 , respectively. G. Allowance for Funds Used During Construction

("AFUDC'J -This allowance , which represents the cost of funds used to finance construction, is capitalized as a component of the cost of the utility plant. The capitalization rate depends on the source of financing. The rate for construction fi n anced with revenue bonds is based upon the interest cost of each bond issue less interest income. Construction financed on a short-term basis with tax-exempt commercial paper (" TECP"), tax-exempt revolving c r edit agreement

("TERCA"), or taxable revolving credit agreement

(" TRCA") is charged a rate based upon the p r ojected average interest cost of the related debt outstanding.

The TECP program was terminated in 2017 and replaced with the TERCA. For the periods presented herein , the AFUDC rates for construction funded by revenue bonds varied from 2.2% to 4.9%. For construction financed on a short-term basis , the rate was 1.0% for 2017 and 2 01 6. H. Nuclear Fuel -Nuclear fuel inventories are included in utility plant. The nuclear fuel cycle requirements are satisfied through the procurement of raw material in the form of natural uranium , conversion services of such material to uranium hexafluoride , uranium hexafluoride that has already been converted from uranium , enrichment services , and fuel fabrication and related services.

The District purchases uranium and uranium hexafluoride on the spot market and canies inventory in advance of the refueling requirements and schedule.

Nuclear fuel in the reactor is being amortized on the basis of energy produced as a percentage of total energy expected to be produced. Fees for disposal of fuel in the reactor are being expensed as part of the fuel cost. I. Unamortized Financing Costs -These costs include issuance expenses for bonds which are be i ng amortized over the life of the respective bonds using the bonds outstanding method. Deferred unamortized financing costs associated with bonds refunded are amortized using the bonds outstanding method over the shorter of the orig i nal or refunded life of the respective bonds. Regulatory accounting , GASB codification section Re10 , Regulated Operations , i s used to amortize these costs over their respective periods. J. Asset Retirement Obligations

-Asset r etirement obligations

(" ARO*) r epresent the best estimate of the current value of cash outtays expected to be i ncurred for legally enforceable retirement obligations of tang i ble capital assets. Regulatory accounting , GASB codification section Re10 , Regulated Operations , i s used t o r ecognize these costs consistent with the rate treatment. K. Other Postemployment Benefits ("OPEB'J -F or purposes of measuring the net OPEB l i ability , deferred outflows of resources and deferred i nflows of r esources related to OPEB , and OPEB expense , i nforma ti on about the fiduciary net position of the D i strict's Postemployment Medical and Life Benefits Plan r Plan*) and add iti ons to/deductions from the Plan's fiduciary net position have been determ i ned on the same basis as they are reported by the Plan. For th i s purpose , the Pla n recognizes benefit payments when due and payable i n accordance with the benefit terms. I nv estments are r eported at fa i r value , except for certain i nvestments in real estate wh i ch are r eported at ne t asse t v alue. L. Auction Revenue Rights and Transmission Congestion Rights -The D i strict uses Auction Revenue Rights r ARR 1 and Transm i ssion Conges ti on Rights ("T CR 1 i n the Southwes t Power Pool r sPP 1 Integrated Marke t t o hedge against transm i ssion congestion charges. These financial i nstruments were primarily designed to allow fi rm transm i ssion customers the opportunity to offset price differences due t o transm i ssion congestion costs between resources and loads. Awarded ARR pro vi de a fi xed revenue stream t o offset congestion costs. TCR can be acqu i red th roug h the conversion o f ARR or pmchases from SPP auctions or secondary market trades. Financial Repo11t M. Deferred Outflows of Resources and Deferred Inflows of Resources

-Deferred o utflows of resources are con s umptions of assets that are applic a ble to future reporting. Regulatory accounting is used for ARO. The ARO deferred outflow is the d i ffer e nce between the related liability a mount and rate collecti o ns. The cost of refunded debt is the difference in the reacquisition price and the net carrying amount of the refunded debt in an ad v ance refunding. Deferred outflows related to OPES i nclude contrib u ti o ns m a de d uring the current year and actuarial experience losses. Deferred inflows of resources are acquired assets that are applicable to future reporting periods and consist of regulatory liabilities for unearned revenues and other deferred inflows. Other deferred inflows include Department of Energy ("DOE") settlements , nuclear fuel disposal collections , CNS outage collections , OPES actuarial experience gains , a settlement for termination of a participation power sales agreement , non-nuclear decommissioning collections and a sales tax refund from the State of Nebraska for the construction of a renewable energy facility. The District is required under the General Revenue Bond Resolution

(" Resolution

") to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses , aggregate debt service on the Gen e ral Revenue Bonds , amounts to be paid into the Debt reserve fund and all other charges or liens payable out of revenues. In the event the District's rates for wholesale service result in a surplus or deficit in revenues during a rate period , such surplus or deficit , within certain limits , may be retained in a rate stabilization account. Any amounts i n excess of the limits will be taken i nto account i n projecting revenue requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the D i strict's long-term wholesale power supply contracts. The District accounts for any surplus or deficit in revenues for retail service i n a s i milar manner. The following table summarizes the balance of Unearned revenues as of December 31 , 2017 and 2016 and activity for the years then ended (in OOO's): 2017 2016 Ulearned revenues , beginning of year .....................................

......................... . $ 1 68 , 710 $ 176 , 118 Surpluses*

- - - - 44 , 888 9 , 992 Use of prior period rate stabiization finis i n rates .........................

.................... . {6 , 671} {1 7 , 400) Ulearned revenues , end of year ................

...............................................

........ . ------$ 206 , 927 $ 168 , 710 The DOE setUement regulatory l i ability was establ i shed for the r eimbursement from the DOE for costs i ncurred by the D i sbict i n conjunction with the d i sposal of spent nudear fuel from CNS. Details of the Disbict's DOE setUement are i nduded i n Note 12 i n the Notes to F i nancial Statements. The D i sbict i ndudes i n rates the costs associated with nudear fuel disposal. Such collections were r emitted to the DOE under the Nudear Waste Pol i cy Act until the DOE adjusted the spent fuel d i sposal fee t o zero , effective May 1 6 , 20 1 4. The Board authorized the use of regulatory accounting for the continued collection of these costs. Th i s approach ensures costs are recognized i n the approp ri ate period with rustomers receiving the benefits from CNS pa yi ng the appropriate costs. The expense for spent nuclear fuel disposal i s recorded at the previous DOE rate based on net electricity generated and sold and th e regulatory l iability will be el i m in ated when payments are made for spent nu clear fuel d i sposal. Adartional deta i ls of th e Oisbict's DOE spent n uclear fuel collections are i nduded i n Note 1 2 i n the Notes t o F i nancial Statements. FiinaRcial Repont Beginning in 2017 , the District began collecting revenues for the costs of the 2018 CNS refueling and maintenance outage. This regulatory liabil i ty was included in Other deferred inflows on the Balance Sheets and will be amortized through revenue during 2018 , the year of the outage. The District and Lincoln Electric System (" LES") executed a termination and release agreement in May 2017 for the Sheldon Station Participation Power Agreement.

The Board author i zed the use of regulatory accounting for the settlement payment as the term of the Agreement was for the life of Sheldon Station (" Sheldon"). This regulatory liability was included in Other defer r ed inflows on the Balance Sheets and will be eliminated as revenues from the settlement payment are incorporated in future rates. T h e District began collecting in rates for non-nuclear decomm i ssioning costs in 20 17. The collections for assets which do not have a legally required retirement obligation are recorded as a regulatory liability , instead of an ARO , and are included in Other deferred infl ows on the Balance Sheets. The following t able summa ri zes the balance of Deferred outflows of resources as of Decembe r 31 , 2017 and 2016 (in OOO's): 2017 Asset retirement obligation

................................................................................. $ 222 , 369 Unamortized cost of refunded debt.....................................................

................ 38 , 430 OPEB contributions after the measurement date ... ..... ..... .... .......... ... ..... ...... .. .. ... .. 28 , 290 Unamortized OPEB losses for differences in actual and e,cpected earnings........... 3 , 283 l..klamortized OPEB losses for differences i n actual and e,cpected e>eperience

........ ____ 3~, 0_30_ $ 295,402 2016 $ 219 , 378 42 , 664 74 , 658 3 , 862 3 , 769 $ 344 , 331 The following table summarizes the balance of Other deferred inflows of resources as of December 31 , 2017 and 2016 (in OOO's): 2017 2016 DOE settlements . ............ ... ...... ........ ........................... ............ .... .. .... ... ............. $ 66 , 227 $ 82 , 664 Nuclear fuel disposal colections

......................................................................... 21 , 570 15 , 098 CNS outage colections

..................................................................................... 20 , 005 l..klamortized OPEB gains for differences i n actual and e,cpecled ellperience

......... 16 , 475 SeUlement for termination of partic i pation power sales agreement.

.............

........... 10 , 500 "°1-nuclear decormissioning colections

..................................................

......... 5 , 444 Renevleble energy facility sales tax refund .......................................................... ___ 4~, 50_3_ 4 , 786 $ 144 , 724 $ 102 , 548 N. Net Position -Net position i s made up of three components

Net inv estment in capital assets , Restricted , and Unrestricted. Net investment i n capital assets consisted of utility plant assets , net of accumulated depreciation and reduced by the outstanding balances of any bonds or notes that are attributable to the acquisition , construction , or improvement of these assets. This component also i ncluded long-term capacity contracts , net of the outstanding balances of any bonds or notes attributable to these assets. Resbicted net position consisted of the Primary account i n the Debt reserve funds that are requ i red deposits under the Resolution and the Decomm i ssion i ng funds , net of any related liabilities. Unrestricted net position consisted of any remaining net position that does not meet the definition of Net i nvestment i n capital assets or Restricted and i s u sed to provide for working capital to fund non-nuclear fuel and i nventory requirements , as well as other operating needs of the D i strict.

0. Use of Estimates

-The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. P. Recent Accounting Pronouncements

-GASS Statement No. 87 , Leases , was issued in June 2017. This Statement will bring substantially all leases for lessees on to the balance sheet. For operating leases , lessees will be required to recognize an asset for the right to use the leased item and a corresponding lease liability.

Lease liabilities will be considered long-term debt and lease payments will be capital financing outflows in the cash flow statement.

In the activity statement , lessees will no longer report rent expense for operating-type leases , but will instead report interest expense on the liability and amortization expense related to the asset. For lessors , the accounting will mirror lessee accounting. Lessors will recognize a lease receivable and a corresponding deferred inflow of resources (with certain exceptions), while continuing to report the asset underlying the lease. Interest income associated with the receivable will be recognized using the effect i ve interest method. Lease revenue will arise from amortizing the deferred inflow of resources in a systematic and rational manner over the lease term. The requirements of this Statement are effective for reporting periods beginning after December 15 , 2019 , with earl i er application encouraged. Management is currently evaluating the impact of this statement.

GASS Statement No. 85 , Omnibus 2017 , was issued in March 2017. This Statement addresses practice issues that were identified during implementation and application of certain GASS statements induding statements on OPES. This Statement prov i des darification for the presentation of payroll-related measures in required s u pplementary information for purposes of reporting by OPES plans and employers that provide OPES. This Statement requires the disdosure of covered-employee payroll by the employer if contributions to the OPEB plan are not based on a measure of pay. Covered-employee payroll i s defined as the payroll of employees that are provided with OPES through the OPEB plan. However , the financial statements for the OPEB plan should not present any measure of payroll if contributions to the plan are not based on a measure of pay. This Statement is e ff ective for fiscal years beginning after June 15 , 2017. The D i strict adopted this Statement in 2017 to coincide with its im plementation of related guidance in GASB Statement No. 75 , Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions.

The OPEB guidance was the only portion of this Statement with an im pact on the Disbict. GASB Statement No. 84 , Fiduciary Activities , was i ssued in January 2017. This Statement addresses accounting and financial reporting requirements for certa in fiduciary funds i n the basic financial statements. Governments with activities meeting the aiteria are required to present a statement of fiduciary net position and a statement of changes in fiduciary net position. The requirements of this Statement are effective for reporting periods beginn in g after December 15 , 2018. The impl ementation of this Statement will require the District to indud e fiduciary statements with the statements for its bus i ness-type activities. GASB Statement No. 83 , Certain Asset Retirement Obligations , was issued i n November 2016. This Statement addresses accounting and financial reporting requirements for certain AROs. Th i s Statement imposes requirements in regards to the ARO liability recognition , measurement and specifics on when re-measurement should occur. This Statement also requires disclosures regarding th e m ethods and assumptions u sed to estimate the ARO , the remaining useful life of capital assets associated with the liability , any governmental legal funding requirements , any assets restricted for payment and any minority share ARO liability. The requ i rements of th i s Statement are effective for reporting periods beginning after June 15 , 20 1 8. The District previously reported AROs under the FASB gu i dance , which differs from the GASB guidance. The FASB guidance required measurement of the liability based on the present value of the asse t's d i sposal costs whereas measurement under this GASB Statement i s based on the best estimate of the current value of cash ouffays expected to be i ncurred. The FASB guidance required the recognition of a corresponding capital asset whereas the GASB Statement requires the recognition of a corresponding deferred outflow of resources. The Disbict adopted thi s Statement in 2017 and uses regulatory accounting to align asset retirement costs with 1heir related recognition i n rates. 36 FiNa,nci a!l iR~JJOllt GASB Statement No. 75 , Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions , was issued in June 2015. The requirements of this Statement will improve accounting and financial reporting for OPEB. This Statement requires the liability for defined benefit OPEB (net OPEB liability) to be measured as the portion of the present value of projected benefit payments to be provided to current active and inactive employees that is attributed to those employees' past periods of service (total OPEB liability), less the amount of the OPEB plan's fiduciary net position.

Enhanced disclosures and additional required supplementary information are also required under the Statement.

This Statement is effective for fiscal years beginning after June 15 , 2017. The District adopted this Statement in 2016 and deferred costs through regulatory accounting , to be amortized during the period in which they are recovered in rates. Additional disclosures related to OPEB are in Note 11 . 2. CASH AND INVESTMENTS

Investments are recorded at fair value with the changes in the fair value of i nvestments reported as Investment income in the accompanying Statements of Revenues , Expenses , and Changes in Net Position. The District had unrealized net gains of $2.6 million and less than $0.1 m i llion in 2017 and 2016 , respectively. The fair value of all cash and i nvestments , regardless of classification on the Balance Sheets , we r e as follows as of December 31 (in OOO's): 2017 Weighted Average Maturity Fair Value (Years} U.S. Treasury and government agency secu riti es .. $ 998 , 148 Corporate bonds ................

................................. 169,051 Municipal bonds.............

....................

.................

11 , 900 Cash and cash equ i valents ............................

...... __ 134___,_, 3_2_6_ Total cash and i nvestments

.............

..............

... $1 , 313 , 425 Portfoio weighted average maturity .......................

.............. . 4.7 9.3 14.3 0.1 4.9 2016 Weighted Average Maturity Fair Value (Years) $ 936 , 317 181 , 438 11 , 901 129 , 261 $1 , 258 , 917 4.0 9.6 12.4 4.5 Interest Rate Risk-The in vestment strategy for all inv estments , except for the decomm i ss i on in g funds , i s to buy and hold securities until maturity , which minimizes int erest rate ri sk. The inv estment strategy for decomm i ssion in g funds i s to actively manage the diversification of multiple asset dasses to ach i eve a rate of return equal to or exceeding the rate used i n the decomm i ss ionin g funding plan model assumptions. Accordingly , securities are bought and sold prior to maturity to i ncrease opportunities for higher inv estment returns. Credit Risk -The D istrict follows a Board-approved Investment Pol i cy. Th i s policy compl i es with state and federal laws , and the Resolution

's provisions govern i ng the i nvestment of all funds. The majority of investments are d i rect obl i gations of , or obligations guaranteed by , the United States of America. Other i nvestments are limited to in vestment-grade fixed i ncome obligations. Custodial Credit Risk -Cash deposits , primarily i nterest bearing , are covered by federal depository i nsurance , pledged collateral consisting of U.S. Government Serurities held by various depositories , or an *rrevocable , nontransferable , unconditional lett er of credit i ssued by a Federal Home Loan Ba nk. Finanoial R~p@n t The fair values of the District's Revenue and Special Purpose Funds as of December 31 were as follows (in OOO's): The Revenue funds are used for operating activities for the District.

Cash and cash equivalents in the Revenue funds are reported as such on the balance sheet , except cash and cash equivalents in the Revenue Fund investment account are reported as investments. The investment account for the Revenue funds included cash equivalents of $99.5 million and $20.9 million as of December 31 , 2017 and 201 , respectively. 2017 2016 Re~nue funds -Cash and cash equivalents

.......................................

..............

$ 127,302 $ 123 , 678 Re~nue funds -ln~trnents

........................................................................

... ___ 4_3_9.,_, 6_7_5_ 352 , 382 $ 566 , 977 $ 476 , 060 The Construction funds are used for capital improvements , additions , and betterments to and extensions of the District's system. The sources of monies for deposits to the construction funds are from revenue bond proceeds and issuance of short-term debt. 2017 2016 Construction funds -Cash and cash equivalents . . . . .. . . . . .. . . . . . . . . . . .. . . . . . . . . . . . . . . . . .. .. . . . . $ $ 25 Construction funds -ln~ts ...................................................

...................

___ 54~, 8_08_ 106 , 179 $ 54 , 808 $ 106 , 204 The Debt reserve funds , as established under the Resolution , consist of a Primary account and a Secondary account. The D i strict is required by the Resolution to maintain an amount equal to 50% of the maximum amount of interest accrued i n the current or any Mure year i n the Primary account. Such amount totaled $37.8 million and $38.7 million as of December 31 , 2017 and 2016 , respectively. The Secondary account can be established at such amounts and can be utilized for any lawful purpose as determined by the District's Board. Such account totaled $51.0 m i llion and $51.3 million as of December 31 , 2017 and 2016 , respectively. 2017 2016 Debt reserve funds -lnwstrnents

.........................................................

............

$ 88 , 764 $ 90 , 032 The Employee Benefit funds cons i st of a self-funded hospital-medical benefit plan for active employees only as of December 31 , 2017 and 2016. The District pays 80% of the hospital-medical premiums with the employees paying the rema i n i ng 20% of the cost of such coverage. The self-funded hospital-medical benefit plan had funds of $1.9 m i llion and $4.9 million as of December 31 , 2017 and 2016 , r espectively. For additional i nformation on OPEB see Note 11. 2017 2016 Erq>loyee benefit fu nds-Cash and cash equivalents

..........................

...............

$ 935 $ 1 , 843 Erq>loyee benefit fu nds -ln\eStrnents

.......................................................

........ ____ 999__ _ ___ 3..,_, 008 __ $ 1 , 934 $ 4 , 85 1 The Decomm i ssion i ng funds are utilized t o account for th e i nvestments held t o fund the estimated cost of decomm i ssion i ng CNS when its operating l i cense expires. The Decomm i ssioning funds are held by outside trustees or custod i ans i n compliance with the decom mi ssioning fu nd*ng plans approved by the Board wh i ch are i nvested pri marily i n fi xed i ncome governmental serurities. 20 17 Decormissioning fu nds -Cash and cash eq u NBlerds .......................

...............

.. $ 6 , 089 Decormissioning fu nds-l rn estrne n ts ..............................................................

594 , 853 ---~--$ 600 , 942 38 $ $ 20 1 6 3 , 71 5 578 , 055 58 1770 Fi:nanoial Rep(!rnt

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value i s t he exchange p ri ce that would be rece i ved to sell an asset or paid to transfer a liab i l i ty (an ex i t price) i n the principal or most advantageous market for the asset or l i abil i ty i n an orderly transaction between market participants at the measurement date. GASS Statement No. 72 (" GASS 72"), Fa i r Value Measuremen t and Appl i cation , establ i shes a fa i r value hierarchy that p ri oritizes the i nputs used to measure fa i r value. The hierarchy gives the highest pr i ority to unadjusted quoted pr i ces i n an act i ve market for i dent i cal assets or l i ab i l i ties and t h e lowest pr i or i ty to unobservable i nputs. F i nancial assets and liab i lit i es are dass i fied in the i r ent i rety based on the lowest leve l of input that i s sign i ficant to the fa i r value measureme nt. The th r ee levels of fa i r value h i erarchy de fi ned i n GASS 72 are as follows: Le v el 1 -Quoted p ri ces are ava i lable i n act i ve markets for ident i ca l asse t s o r liab ili t i es as of the report i ng da t e. Act i ve markets are those i n wh i ch transact i ons for the asset o r l i abil i ty occu r i n suffic i ent frequency and volume to prov i de pricing i nformat i on on an ongo i ng basis. The D i strict's i nvestmen t s i n cash and cash equ i valents are included as Level 1 assets. Level 2 -P ri cing i nputs are other than quoted marke t prices i n the active m arkets i nduded i n Level 1 , which are e i ther d i rectly or i nd i rectly observable for th e asset or l i ab i lity as of the r epo rtin g date. Level 2 inpu t s i ndude t he following:

quoted p ri ces for s i m i lar assets or li ab i l iti es i n act i ve markets;

quoted p ri ces fo r i den ti cal assets o r l i abilities i n i nactive m a rk ets;

i nputs othe r th an quoted p ri ces th a t are observable for th e asset or li ab i l i ty; o r

i nputs tha t a r e de ri ved p ri ncipally from or co rr oborated b y observab l e m arke t d ata by co rr ela ti o n o r o th e r m ea n s. Level 2 assets p ri ma ri ly in dude U.S. T r eas u ry and government agency secu riti es h e l d in th e Reven u e funds and other Specia l Purpose F u nds and U.S. T r easu ry a n d gove rn men t age n cy secu riti es , corpora t e bonds , a n d mun i cipal bonds h eld in th e Decomm i ssio nin g fu nds. Level 3 -P ri cing i n put s indu de s i gn ifi can t in puts th a t a r e u nobse rv able a n d ca n no t be co rr oborated b y ma rk e t data. L evel 3 asse t s and li ab i l iti es are v a lu ed based o n int e rn all y de v eloped m odels a n d ass u mp ti o n s or m e th odolog i es u s ing sig nifi ca nt u nobse rv able in puts. Th e D i s trict currently d oes n o t h a v e a ny L e v el 3 asse t s or li ab i l iti es. Th e Distri ct pe rforms a n a n al ysi s a nnually t o d eterm in e th e app ropri a t e hi erar chy l evel d a ssifi cati on of th e asse ts and l i a biliti es th a t a r e in d u ded within th e scope of GASB 72. Fin an ci a l assets a n d li a bi l iti es are dass ifi ed in th ei r en tir e ty based on th e l owes t l e v el of input th a t i s si g nifi ca nt t o th e fa ir v al u e m easu r e m en t Th ere were no li a bi l iti es within th e scope of GASB 7 2 as o f December 3 1 , 2 017 a n d 2 01 6. Th e followin g tables se t forth th e District's fi na nci al asse ts th at a r e aa::ou nt ed for a nd r e port ed at fa i r v a lu e on a r ecu rring basi s by l e v el within the fair valu e h i erarch y as of Decembe r 31 , (i n OOO's): Rele1ue and special purpose finis,, erlJding dec.u111issioo i ng: U S. Treasury and gowemment agency sect.rilies

............ . $ Cash and cash equi"8lents

- - - - 1 28 , 23 7 Decormissi oni ng fmds: U S. Treasury and gowemment agency securiti es .........*... Corporate bonds .................

....................

...................... . PAricipal bonds *********************************************

- - - - Cash and cash equi\lllenls ............................................. . 6 , 089 s 1 34 , 326 Finanoia l iR e iJi>.@r t 20 17 l...e\lel 2 s 584 , 24'6 s 4 1 3 , 902 1 69 , 05 1 11 , 900 $1 , 179, 099 s l...e\lel 3 Total $ 584 , 24'6 1 28 , 23 7 4 1 3 , 902 1 69 , 05 1 11 , 900 6 , 089 $1 , 3 1 3 , 425 2016 Level 1 Level2 Level 3 Revenue and special purpose f unds , excluding decol'TYllissioning

U.S. Treasury and government agency secur i ties ............ . $ $ 551 , 602 $ Cash and cash equivalents

............................................. . 125 , 546 DecOl'TYllission i ng funds: U.S. Treasury and government agency secur i ties ............ . 384 , 7 1 5 Corporate bonds ........................................................... . 181 , 438 Munic i pal bonds ................................................

............ . 11 , 90 1 Cash and cash equ i valents .....................

........................ . 3 , 715 $ 1 29 , 261 $1 , 1 29 , 656 $ 4. UTILITY PLANT: Ut i lity plant activ i ty for the year ended December 31 , 2017 , was as follows (i n OOO's): Decermer 31 , 2016 Increases Decreases Nondepreciable utility plant Land and improwments

............................... $ 74 , 138 Construction in progress.............................. 135 , 853 ----'---T otal nondeprec i able uti li ty plant .............. __ 2_0_9_, 9_9_1_ f'l.l c lear fuel* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 97 , 730 ----'---Deprec i able utility plant Generation

-Fossi l ........................

..... : ...... . 1 , 62 1 , 9 1 9 Generation

-f'l.lclear

.................................. . 1 , 3 1 4 , 2 1 0 Tr ansmiss i on ............................................. . 1 , 254 , 42 1 Di stribution

................................................ . 226 , 563 General ...................

.................................. . 344 , 5 7 8 T ola! deprec i able utili ty plant 4 , 7 6 1 , 69 1 Less r esene f or deprec i ation ...................

........ . (2 , 5 7 3 , 645) Deprec i able utility plant, n et .................... . 2 , 1 88 , 046 Utility plant ac tiw:y. n et .........................

........... . $ 2 , 595 , 7 6 7 -----* Nuclear-tJel decreases represented amomzalioo cif: $43.5 m ion. $ $ 1 , 1 24 120 , 399 12 1 , 523 11 , 979 33 , 992 1 4 , 9 7 8 4 7 , 223 9 , 29 1 15 , 1 69 1 2 0 , 653 (11 3 , 729) 6 , 924 140 , 426 $ (68) (122 , 737) (1 22 , 805) (43 , 490) (5 , 754) (7 , 182) (5 , 0 11) (1 , 409) (9 , 8 1 2) (29 , 1 68) 29 , 1 68 $ (1 66 , 295) Total $ 55 1 , 602 1 25 , 546 384 , 7 1 5 18 1 , 438 1 1 , 90 1 3 7 15 $1 , 258 , 917 Oecermer 31 , 2017 $ 75 , 194 133 , 515 208 , 709 1 66 , 2 1 9 1 , 650 , 1 57 1 , 322 , 006 1 , 296 , 633 234 , 445 349 , 935 4 , 853 , 17 6 (2,658 , 206) 2,1 94 , 9 70 $ 2 , 569 , 898 Fiinmioiall Repemt Utility plant activity for the year ended December 31 , 2016 , was as follows (in OOO's): December 31 , December 31 , 2015 Increases Decreases 2016 Nondepreciable utility plant Land and improvements

............................... $ 64 , 370 $ 9 , 780 $ (12) $ 74 , 138 Construction in progress .............................. 209 , 626 180 , 237 (254 , 010) 135 , 853 Total nondepreciable utility plant .............. 273 , 996 190 , 017 (254,022) 209 , 991 Nuclear fuel* .................................................... 168 , 420 70 , 064 (40 , 754) 197 , 730 Depreciable utility plant Generation

-Fossil ...................................... 1 , 573 , 880 65 , 818 (17 , 779) 1,621 , 919 Generation

-Nuclear ................................

... 1 , 384 , 031 68 , 415 (138 , 236) 1 , 314 , 210 Transmission

...........................

................... 1 , 172 , 108 86 , 994 (4 , 681) 1,254 , 421 Distribution

................................................. 221 , 791 6 , 336 (1 , 564) 226 , 563 General ....................................

...........

....... 334 , 836 13 , 528 (3 , 786) 344 , 578 Total depreciable utitity plant 4 , 686 , 646 241 , 091 (166 , 046) 4 , 761 , 691 Less reserve for depreciation

....................

........ (2 , 620 , 091) (119 , 600) 166 , 046 (2 , 573 , 645) Depreciable utility plant, net ..................... 2 , 066 , 555 121 , 491 -2 , 188 , 046 Uliity plant acti\ftty , net ..................................... $ 2 , 508 , 971 $ 381 , 572_ $ (294 , 776} $ 2 , 595 , 767

Nuclear rue! decreases represented am orti zation of $40.8 m i llion. 5. L ONG-TERM CAPACITY CONTRACTS: Long-term capacity contracts indude the District's share of the construction costs of Omaha Public Power District's r oPPD.) 664 megawatt r MW) Nebraska City Station Un i t 2 r Nc2*) coal-fired power plant The D i strict has a participation power agreement with OPPD for a 23. 7% share of the power from this plant NC2 began commercial operation on May 1 , 2009 , at whidl time the District began amortizing the amount of the capacity contract associated with the plant on a straight-line basis over the 40-year estimated useful life of the plant Accumulated amortization was $39.9 million and $35.4 million as of December 31 , 2017 and 2016 , respectively. The unamortized amount of the plant capacity contract was $139.2 million and $143. 7 m i llion as of December 31 , 2017 and 2016 , respectively , of wh i dl $4.4 million was i nduded i n Prepayments and other current assets as of December 3 1, 2017 and 2016. The District's share of NC2 working capital was also induded in Prepayments and other current assets and was $6.5 million as of December 31 , 2017 and 2016. Long-t erm capacity contracts also i ndude the D i strict's purdlase of the capacity of a 50 MW hydroelectric generating facility owned and operated by The Central Nebraska Public Power and Irrigation District r eentrat'"). The D i strict i s amortizing the contract on a straight-l i ne basis over the 40-year estimated useful life of the facility. Accumulated amortization was $66.6 million and $64.3 million as of December 31 , 2017 and 2016 , respectively. The unamortized amount of the Central capacity contract was $20.1 million and $22.4 m i llion as of December 3 1, 2017 and 20 1 6 , respectively , of wh i dl $2.3 mill i on was i nduded i n Prepayments and other current assets as of December 3 1 , 20 17 and 20 1 6. The District has an agreement whereby Central makes available all the production of the facility and the District pays all costs of operating and maintain i ng the facility pl u s a charge based on the amount of energy delivered t o the D i strict Costs of $1.8 m i lion and $2.5 m i llion i n 20 17 and 2016 , respectively , are i nduded i n Power purdlased in the accompan yi ng Statements of Revenues , Expenses , and Changes i n Net Position. I Fililancial R~prnmt

6. INVESTMENT IN THE ENERGY AUTHORITY: The District has an investment in The Energy Authority

("T EA"), a nonprofit corporation headquartered in J a cksonville , Florida , and incorporated in Georgia. TEA prov i des public power util iti es access to dedicated re s ources and advanced technology systems. The District's interest in TEA was 16.67% as of December 31 , 2 01 7 and 2016 , respectively.

In addition to the District , the following utilit i es have interests of 16.67% each as of D e cember 31 , 2017 and 2016: Amer i can Municipal Power , Inc.; JEA (Florida); Municipal Energy Authority of G e org i a; and South Carolina Public Serv i ce Author ity (a.k.a. Santee Cooper). The following utilities have i nterests i n TEA of 5.56% each as of December 31 , 2017 and 2016: C i ty Utilities of Springfield , Missouri; Cowlitz County Public Utility Distr i ct (Washington) and Ga in esville Regional Utilities (Florida). Su ch inv estment was $6.2 million and $6.4 million as of December 31 , 2017 and 2016 , respectively. TEA's revenues and costs are allocated to members pursuant to Settlement Procedures under the Operating Agreement.

TEA provides the District gas contract management services and is the District's market participan t in SPP's Integrated Market. The District is obl i gated to guaranty , directly or indirectly , TEA's electric trading activities in an amount up to $78.9 million plus attorney's fees which any party claiming and prevailing under the guaranty might incur and be enti tl ed to recover under it s contract with TEA. Generally , the District's guaranty obligations for electric trading would arise if TEA did not make the contractually required payment for ene rgy , capac ity, or transmission which was delivered or made available or i f TEA failed to deliver or provide energy , capacity , or transmission as required under a contract. The District's exposure relating to TEA i s limit ed to the District's inv estment i n TEA , any accounts receivable from TEA , and trade guarantees provided to TEA by the District Upon the District making any payments under its electric guaranty , it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably , based upon each member's inter est i n TEA and the guarantees they have prov i ded. The District incr eased it s guarantee to TEA in March 2018 from $28_9 million to $78_9 million_ The additional

$50_0 million of guaranty i s to support add ition al trading for TEA on behalf of i ts continued business growth_ After such con tribution s h ave been effected , the District would only h ave recourse aga in st TEA to recover amounts paid under th e guaranty_

The term of this guaranty i s generally ind efinite , but th e District has the ab ility to term i nate its guaranty obl i gations by causing to be provided advance notice to th e beneficiaries thereof. Such termination of it s guaranty obligations only applies to TEA transactions not yet entered i nto a t the tim e the term i nation takes effect The D i s trict h as no liabiliti es for the se guarantees as of December 31 , 2017 and 20 1 6_ Financial statements for TEA may be obtained at The Energy Authority , 30 1 W_ Bay Stree t, Suite 2600 , Jacksonville , Florida , 32202_ 7_ DEBT: The following table summarizes the debt balances , net of current m aturities , as of December 3 1 , 2017 and 20 1 6 , and activity for 2017 (i n OOO's): Decermer 3 1 , 2016 Rewnue bonds --------------------------$ 1 , 678 , 844 Cmmercial paper no1es -------------7 4 , 000 Reldling aedit agreements c 11 ----1 88 , 924 -----"---T olal mg-term debt ac1ni1y ----___ $_1 .... , 94__.1 , ... 768_ Increases Oeaeases $ 96 , 957 $ (22 7 , 532) 11 , 320 (85 , 320) 87 , 4 17 {42.129} s 1 95 , 694 s {354 , 98 12 42 Princi pal ArooU1ls Due Decermer 31 , WllhinOle 2017 Y ew $ 1 , 548 , 269 $ 98 , 205 234 , 2 1 2 165 , 2 12 S 1 , 782,,481 $ 263 , 4 17 Einanoia l Rep.011t The following table summarizes the debt balances , net of current maturities , as of December 31 , 2016 and 2015 , and activity for 2016 (in OOO's): Principal Amounts Due December 31 , December 31 , Within One 2015 Increases Decreases 2016 Year Re\A:!nue bonds ......................... $ 1 , 596 , 972 $ 354 , 776 $ (272,905)

$ 1 , 678 , 844 $ 81 , 250 Commercial paper notes ............ 83 , 000 88 , 365 (97 , 365) 74 , 000 74 , 000 Rewl1Ang credit agreements

....... 158 , 700 75 , 443 (45 , 219) 188 , 924 Total long-term debt acti1Aty .. $ 1 , 838 , 672 $ 518 , 584 $ (415 , 489) $ 1 , 941 , 768 $ 155 , 250 Revenue Bonds On January 1 , 2018 , the District called the remaining outstanding General Revenue Bonds , 2012 Series C , with a principal amount that aggregated

$4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of OPES costs for customers under the 2016 Contracts.

Congress passed the Tax Cuts and Jobs Act ("Act") in December 2017 , which eliminated the use of tax-exempt advanced refunding transactions. In April 2017 , the District issued General Revenue Bonds , 2017 Series A and 2017 Series B , in the amount of $86.0 million to refund the General Revenue Bonds , 2007 Series 8. The refunding reduced total debt service payments over the life of the bonds by $11.8 million , which resulted in present value savings of $10.0 million. Also in April 2017 , the District entered into an escrow deposit agreement in conjunction with the refunding of certain of the General Revenue Bonds , 2007 Series 8 , having maturity dates ranging from January 1 , 2018 through January 1 , 2028. Congressional action reduced the 35% interest subsidy , pursuant to the requirements of the Balanced Budget and Eme r gency Deficit Control Act of 1985 , as amended , on the District's General Revenue Bonds , 2009 Series A {Taxable Build America Bonds) and 2010 Series A {Taxable Build America Bonds). Reductions were 6.9% and 6.8% for fiscal years ended September 30 , 2017 and 2016 , respectively. In November 2016 , the District i ssued General Revenue Bonds , 2016 Series C and 2016 Series D , in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and to refund a portion of Commercial Paper Notes , Series A. The D i strict also i ssued in November 2016 , General Revenue Bonds , 2016 Series E {Taxable), in the amount of $56.1 million to fund a portion of OPEB costs for customers under the 2016 Contracts. In February 2016 , the District i ssued General Revenue Bonds , 2016 Series A and 2016 Series B , in the amount of $139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of commercial paper notes. The refunding reduced total debt service payments over the life of the bonds by $29.8 million , which r esulted in present value savings of $20.8 million. Also in February 2016 , the District entered int o an esaow deposit agreement in conjunction with the advanced refunding of certain of the:

General Revenue Bonds , 2007 Series B , having maturity dates ranging from January 1 , 2026 through January 1 , 2037

General Revenue Bonds , 2008 Series B , having maturity dates ranging from January 1 , 2024 through January 1 , 2041

General Revenue Bonds , 2012 Series C , maturing on January 1 , 2025 through January 1 , 2026 In January 2016 , the District i ssued TECP i n the amount of $43.6 m i llion to refund a portion of the General Revenue Bonds , 2005 Series C and the General Revenue Bonds , 2006 Series A. Financial Rep@rt Certain of the General Revenue Bonds , from the following series , with outstanding principal amounts that a ggregate $324.1 million as of December 31 , 2017 , were legally def eased and a re no longer outstanding

2008 Series B and 2012 Series C. Debt service payments and principal payments of the General Revenue Bonds as of December 31 , 2017 , are as follows (in OOO's): Year 2018 ............................................ . 2019 ****************************

- - - - 2020 *********************************************

2021 .........................

................... . 2022 .......................

..................... . 2023-2027

.................................... . 2028-2032

..............................

...... . 2033-2037

..................

.................. . 2038-2042

.................................... . 2043-2045

..............................

...... . Total Payments ............................. . Debt Service Payments $ 170,403 146,856 146,760 143,968 136,550 637,780 469 , 091 270 , 720 103,408 15,962 $ 2 , 241,498 Principal Payments $ 98,205 79,320 82,915 84 , 085 80 , 825 417 ,4 75 341,640 218 , 700 88,685 14 , 895 $ 1,506 , 745 The fair value of outstanding revenue bonds was determ in ed using currently published rates. The fair value was estimated to be $1 , 737.9 million and $1 , 750.1 million as of December 31 , 2017 and 2016 , r espectively. Commercial Paper Notes and line of Credit Agreemen t The District terminated its Commercial Paper Notes ("Not es") program and the line of Cred it Agreement that supported the payment of the principal outstanding on the Notes after execution of the Tax-Exempt Revolving Cred i t Agreement

("T ERCA") i n 2017. Tax-Exempt Revolv i ng Credit Agreement The District entered int o a TERCA with two commercia l banks to provide for l oan commitments to th e D i strict up to an aggregate amount not to exceed $150.0 million on June 29 , 2017. The TERCA replaced the Commercial Paper Notes and line of Cred it Agreement The District had an outstanding balance under the TERCA of $69-0 million as of December 31 , 2017. The outstanding amount i s an ticipat ed to be r e tir ed by future collections through electric rates and the i ssuance of r evenue bonds. The canying value of the TERCA approximates market value due to the short-term natu re of the agreements. The TERCA term i nates on June 29 , 2020. Taxable Revolving Crecfll Agreement The District has entered i nto a Taxable Revolving Credit Agreement

('TRCA 1 with two commercial banks to provide for l oan commitments to th e District up to an aggregate amount not to exceed $200.0 million. The TRCA allows the District t o in crease the l oan commitments to $300.0 million. The D i strict had outstand i ng balances under the TRCA of $165.2 milion and $188.9 million , as of December 31 , 2017 and 2016 , respectively. The outstanding amount i s anticipated to be retired by future collections through electric rates. Th e carrying value of the taxable revolving aedit agreements approximates market value due to the short-term nature of the agreements. Th e TRCA was renewed on July 31 , 2015 , and terminates on July 30 , 2018. 44 iFinan:oia R~p 011t Revenue bonds consist of the followng (OOO's except interest rates): December 31 , Interest Rate 2017 General Revenue Bonds: 2007 Series B: Serial Bonds: 2016-2026

.............................

.. 4.375% -5.00% Term Bonds: 2027-2031

.............................. . 4.65% 2008 Ser i es B Serial Bonds 2017-2029

..........

........ .. 4.00% -5.00% 2009 Ser i es A Taxable Build America Bonds: Term Bonds: 2019-2025

.............................. . 6.606% 2026-2034

.............................. . 7.399% 2009 Ser i es C Serial Bonds 2017-2019

................... . 4.00% -4.2 5% 2010 Ser i es A Taxable Build Amer i ca Bonds: Ser i al Bonds: 2019-2024

...........

................... . 3.98% -4.73% Term Bonds: 2025-2029

.......................

...... .. 5.323% 2030-2042

.............................. . 5.423% 2010 Series B Taxable Ser i al Bonds 2016-2020

...... .. 3.358% -4.18% 201 O Series C: Serial Bonds: 2017-2025

.......................

...... .. 3.00% -5.00% Term Bonds: 2026-2030

.............................. . 4.00% 2026-2030

.............................. . 5.00% 20 1 2 Series A Serial Bonds 2017-2034

..................

.. 3.00% -5.00% 2012 Ser i es B: Serial Bonds: 2017-2032

.........................

.... .. 2.00% -5.00% Term Bonds: 2033-2036

.............................

.. 3.625% 2037-2042

.............................. . 3.625% 20 1 2 Series C Serial Bonds 2017-2028

................... . 3.00% -5.00% 20 13 Series A Serial Bonds 2017-2033

................... . 3.00% -5.00% 20 1 4 Series A:. Se ri al Bonds: 2017-2038

.............................

.. 2.00% -5.00% T e rm Bonds: 2039-2043

......................

........ . 4.00% 2039-2043

..................

............ . 4.125% 2014 Series C Serial Bonds 20 17-2 033 ................... . 4.00% -5.00% 2015 Series A-1 Serial Bonds 2022-2034

................ . 3.00% -5.00% 2015 Series A-2: Serial Bonds: 2017-2034

...................

........... . 3.00% -5.00% Term Bonds: 2035-2039

............................

.. . 5.00% 2016 Series A:. Serial Bonds: 2018-2035

...............................

3.125% -5.00% Term Bonds: 20~2040 ...............................

5.00% 2016 Series B: Serial Bonds: 2018-2036

..........................

..... 5.00% Term Bonds: 2037-2039

..........................

..... 5.00% 2016 Series C Serial Bonds 2017-2035

.................... 3.00% -5.00% 2016 Series D: $ 17 , 465 32 , 890 2 , 535 31 , 875 27 , 985 54 , 190 2 , 755 40 , 685 6 , 165 1 4 , 180 182 , 145 83 , 330 2 , 320 4 , 155 n , 480 151 , 015 31 , 650 1 , 945 138 , 130 119 , 400 56 , 045 46 , 205 65 , 210 5 , 595 67 , 255 1 , 1 65 67 , 025 Serial Bonds: 2017-2035

....................

........... 200% -5.00% 20 , 960 Term Bonds: 20~2040 ............................... 5.00% 9.505 2041-2045 ...............................

5.00% 12 , 140 2016 Series E T axable Serial Bonds 2022-2033

........ 2337% -3.567% 56 , 050 2017 Series A Serial Bonds 2017-2 027 .................... 200% -5.00% 18 , 125 2017 Series B Serial Bonds 2017-202 7 .................... 5.110% 59 , 170 Total par anorid rewenue bonds......................................................................

1 , 506 , 745 Uanortized prernilnl net d ciscotri ...........................

..................................

139 , 729 --~--1.646 , 474 Less -cwrent rnall.aities d rewenue bonds .....................................................

_ __..(98.::..=, 205.c;..;;...;.L..) Total rewenue bonds.........................................

........................................

$1 , 548 , 269 Fina:noial

Repolit 2016 $ 97 , 415 9 , 620 10 , 700 17 , 465 32 , 890 4 , 605 31 , 875 27 , 985 54 , 190 3 , 600 48 , 760 6 , 165 14 , 180 190 , 4 10 92 , 320 2 , 320 4 , 155 11 , 045 91 , 100 153 , 630 31 , 650 1 , 945 143 , 025 119 , 400 56 , 485 46 , 205 65 , 210 5 , 595 67 , 255 1 , 1 65 70 , 685 2 1 , 170 9 , 505 12,140 56 , 050 1 , 611 , 915 148 , 179 1 , 760 , 094 (81 , 250) $1 , 6 7 8 , 844

8. PAYMENTS IN LIEU OF TAXES: The Distri c t i s required to make payments in lieu of taxes , aggre g ating 5% of the gross revenue derived from electr i c retail sales within the city lim i ts of incorporated cit i es and towns served d i rectly by t he District.

Such payments totaled $10.1 million for each of the years ended December 31 , 20 1 7 and 20 1 6 , respect i vely. 9. ASSET RETIREMENT OBLIGATIONS

The District imp l emented GASS Statement No. 83 , Certa i n As s et Retire m ent Obliga ti ons , i n 20 1 7 , retroact i ve to 2016. Prior t o t h e i mpl e mentat i on of the GASS guidance , FASS gu i dance had been u sed for ARO report i ng. T h e FASS guidance required measuremen t of the liabil i ty based on d i scounted dolla r s o r the present value of the asse t's d i sp os al costs. Measurement under GASS guidance i s based on th e best es ti mate i n t oday's dolla r s , o r the current value , of cash outlays expected to be i ncu rr ed in the fut ur e. The F ASS guidance requ i red th e recogn i t i on of a correspond i ng capita l asset whereas t h e GASS gu i dance r equ i r es the r ecognit i on o f a corresponding de f e r red outflow of resou r ces. The District uses r egulatory accoun ti ng t o al i gn asset re ti re m e n t costs with their r elated recog niti on i n r ates. The d i ffe r ence i n t h e ARO amoun t s and th e r e l a t ed de f e rr ed ou tfl o w s represents the amounts collected i n rates. AROs as of December 3 1 , are as follows (i n OOO's): Descr i ption CNS li cense ter min atio n costs .................

....................

................... . GC3S and SS as h la n dfi ls ...........

.........................................

........... . Ainsv.orth

........................................

............................................. . Undergrou n d storage tanks ..........................................

.................. . 2 01 7 $ 8 11 , 80 1 9 , 040 1 , 95 3 1 0 00 $ 823 17 94 2 01 6 $ 7 95 , 026 3 , 2 0 8 1 , 91 3 1 000 $ 80 111 4 7 Th e Dis tri ct i s r eq uir ed b y th e Nu dea r R eg ul ato ry C ommi ss i o n (" N RC~) to d ecom mi ss ion CNS after cessa ti o n of plan t ope rati o n s , co n sis t e nt with r eg ul a ti o n s in th e U.S. Code o f F ede r a l Reg u la tion s. Th e C N S li ce n se t erm i na tion costs wer e b ased o n a n e xt e rn a l s tudy for costs f o r thr ee diff er ent scena ri os: 1) i mm ed i a t e com m e n ce m e nt of d ecom mi ssi on i n g a ft e r li cense termin a tion i n 2 0 34; 2) d ela y ed decommi ss ionin g for 46 y ea rs a ft e r li cense termin a tion; a n d 3) sa f e s t orage for 60 y ears a ft e r li cense termination. Th e cos ts wer e based on severa l k e y ass umption s i n a r eas o f r eg ulation , component ch ara cterization , hi g h-l e v el ra dioactiv e wa st e m a n agemen t, low-l e v el rad ioactiv e was t e di sposa l , perform a n ce un certa inti es (contingency) a nd sit e r es t o ration r equ ir e m en t s. An expe rt pan el , co nsi s tin g of D i strict m a n a g e m e nt r e presentativ es with con s i derabl e nu clea r expe ri ence , assig n ed probabiliti es to th ese diff e rent sce nario s. Th e co sts i n th e s tudy wer e i n 2 015 doll ars. Ra t es i n the co n su m er pri ce i n de x for all urban con s um e rs r c P I-U"') wer e u sed to a dju st th ese obl i g ations for i nfl a tion. The i nfl a tion rat es u sed wer e 2.1 1 % a nd 2.07% for the y ea rs 2017 a nd 2016 , r e spectively. Th e District h as fund s se t a si de for d ecom mi ssi on i ng of $600.9 m i llion a nd $581.8 m i llion as of Dece mber 31 , 20 17 a nd 2 0 1 6 , r espectively. Th ese fun ds e xceeded th e N RC's r equ i red fund i ng provision s f or n ud ea r decomm i ssion i ng. The D i strict i s requ i red by the En vi ronmental Protection A ge ncy f EP A 1 and th e Nebraska Department of Environment Q u al ity r ND E Q"') t o decomm i ssion th e ash l a ndfi U s at GGS and Sheldon , consistent with their r eg ulation s. As GA SB gu i dan ce i s undear related t o the accoun ti ng treabnent for a sh landfiU ARO s , GA SB Sta tement No. 83 wa s considered an al ogou s a uthoritativ e lit erature and applied in this situation. The ash l andfils hav e a n estim a ted dosure dat e in the years 2086 and 2036 for GGS and Sheldon , respectively. The AR Os were ba sed on e xternal stud ies t o estimat e costs using one scenario after an a ssessment of the physical sit e. The dosure and post-closure costs were based on th e Closure Plan in the stud ies and i ncluded fi nal cover placements and li ned surface water control slrudures. The costs i n the l atest studies wer e i n 2 01 7 dolars. The ARO i naeased from 20 1 6 because of a regulatory chang e which in aeasecl the post-closure period from fiv e y ears t o 30 years. The Oislrict provided guarant ees and financial assurance th roug h correspondence and supporting i nformation to ND E Q in 2 017. Commencing in 20 17 , the District incl uded in rates decom mi ssion i ng costs for certain assets at G GS and Sheldon. The costs induded in rates for the decomm i ssion i ng of the ash landfills were 46 Fiilil:arnoiaJl Rep@n t

$0.4 million for the year ended December 31 , 2017. These rate collections reduced the related deferred outflow for the ash landfills. The District is required by contracts with the landowners of the Ainsworth site to restore the property , as nearly as possible , to the condition it was in prior to the District's use of the easement.

Ainsworth has an estimated closure date of September 30 , 2025. The ARO was based on an external study for costs using one scenario.

The assumptions included: 1) no hazardous construction material abatement is required; 2) no environmental costs to address site clean-up; 3) floor drain and septic tanks will be decommissioned per state regulations

4) wind turbine nacelles , turbine towers , transformers and other electrical equipment are removed from the site by the demolition contractor

5) the O&M buildings and one onsite meteorological tower were included with the demolition costs; 6) all foundations will be removed to two feet below finished grade; and 7) all concrete and crushed rock surfacing will be removed. The costs in the study are in 2015 dollars. Rates in the consumer price index for all urban consumers

("CPI-U")

were used to adjust these obligations for inflation.

The inflation rates used we r e 2.11 % and 2.07% for the years 2017 and 2016 , respectively. There are no legally required funding and assurance provisions associated with this ARO. The costs included in rates for the decommissioning of Ainsworth were $0.1 million for the year ended December 31 , 2017. These rate collections reduced the related deferred outflow for Ainsworth. The District is requ i red by the NDEQ to decommission the underground storage tanks at various locations in the District's service area , consistent with its regulations.

The remaining lives of the storage tanks cannot be reasonably estimated. The AROs were based on the best estimate of District management representatives with expertise in environmental issues. The District provided guarantees and financial assurance through correspondence and supporting information to NDEQ in 2017. There have not been any decommissioning costs for the underground storage tanks included in rates. Financial Report The District cont i nues to use regulatory account i ng for AROs , so the amount i ncluded in rates is recorded as decommissioning expense. As a result , the impact on the Distr i ct's 2016 financial statements was limited to the Balance Sheet. The changes made to the 20 1 6 financial statements after the i mplementat i on of the GASB guidance were as follows (in OOO's): Balance Sheet Utility Plant, at Cos t: Util i ty plant in se r'Ace ................................................................... . Less reserve for depreciation

...........................

..................

.......... . Construction work i n progress ...................................................... . N u clear fuel , at amortized cost ..................................................... . Other Long-Term Assets: Regulatory asset f or ARO ....................................

...............

......... . Regulatory asset for other posterTl)loymen t benefits ..............

......... . Long-t erm capac i ty c ontracts ...............................

........................ . Unamortized fi nanc i ng costs ...............................

......................... . lmestmen t i n The En ergy A u thor ity .........................

..................... . Other ......................................................................................... . T otal Assets ..................

...................................

.....................

...... . Defe rr ed Outflows of Resour ces: A sset r e tir ement obi gati on ...................

...........

............................. . U1amorti zed cost of r e fu nded debt .....................................

.......... . Other ~rnent benefits ..........................

........................... . TOTA L A SS ETS AN) D EF ERRED OUTFLOWS Olher Long-Term Liabiiti es: Asset retirement obligation

.......................

.................................... . Net other ~rnent benefit iabiity ....................................

.. . Other ...........................................................

.............................. . Total Liabiiti es .....................................

................................

....... . IDTAL LIABILITIE S , DEFERRED IIIFLOWS , AN) f>ET POSITICJII

... 48 As reported 2016 $ 4 , 835 , 829 2 , 5 7 3 , 645 2 , 262.184 1 35 , 853 19 7 , 730 $ 2 , 595 , 767 $ 22 1 , 973 1 59 , 445 8 , 945 6 , 3 70 9 , 4 1 6 $ 406 , 1 49 $ 4 , 560 , 252 $ 2 19 , 378 42 , 664 8 2 , 28 9 $ 344 , 331 $ 4 , 904 , 583 $ 801 , 147 258 , 609 3 , 362 $ 1 , 063 , 118 $ 3 , 218 , 208 $ 4 , 904 , 583 As or i ginally reported 2016 $ 4 , 971 , 259 2 , 708 , 036 2 , 263 , 223 135 , 853 1 97 , 730 $ 2 , 596 , 806 $ 44 , 899 22 1, 97 3 1 59 , 44 5 8 , 945 6 , 3 70 9 , 4 1 6 $ 45 1 , 048 $ 4 , 606 , 190 $ 4 2 , 664 8 2 , 289 $ 1 24 , 953 $ 4 , 731 , 143 $ 627 , 707 258 , 609 3 , 362 $ 889 , 678 $ 3 , 044 , 768 $ 4 , 731 , 143 Change $ (135,4.30) (134 , 391) (1 , 039) $ (1 , 039) $ (44 , 899) $ (44 , 899) $ (45 , 938) $ 2 19 , 378 $2 19 , 378 $173 , 440 $173 , 440 $173 , 440 $ 173,440 $173 , 440 iFinanoia[

Rep©Iit

10. RETIREMENT PLAN: The District's Employees' Retirement Plan (the " Plan") is a defined cont ri bution 401 (k) pension plan established and admin i stered by the Distr i ct to prov i de bene fi ts at retirement to regular full-time and part-time employees. There were 1 , 848 and 1 , 931 active plan members as of December 3 1 , 2017 and 2016 , respectively. Plan prov i s i ons and contribut i on requ i rements are establ i shed and may be amended by the Board. Plan members are eligible to begin part i c i pation i n the Plan immediately upo n h i re. Co n tributions ranging from 2% to 5% of base pay are eligible for District matching dollars after six months of employment.

The D i strict cont ri butes two ti mes the Plan membe r's contr i but i on based o n covered salary up to $40 , 000. On covered salary greater than $40 , 000 , the District contr i butes one times the Plan member's cont ri bution. The Part i cipants' contribut i ons were $13.7 m i llion and $13.4 million for 2017 and 20 1 6 , r espectively. The Dist ri ct's match i ng cont ri bu ti ons were $1 2.0 million and $12.3 m i llion for 2017 and 2016 , respect i vely. Total contribut i ons of $1.3 and $1.4 m i llion were accrued in Accounts payable and accrued l i ab i l i t i es as of December 31 , 2017 and 2016 respec ti vely. Beg i nn i ng January 1 , 2018 , t he Boa r d approved a n i ncrease i n match i ng for cove r ed salary fro m $40 , 000 t o $75 , 000. Plan m embers are i mmediately vested i n t he i r own co ntri but i ons and ea rni ngs and become vested in th e Dist ri ct's con t ri bu ti ons and ea rni ngs based on the f ollowing ves tin g sched ul e: Years of Ves ti ng P art i c i pat i o n 5 years o r m o r e ................................... . 4 years ............................................... . 3 y ears ............................................... . 2 y ears ............................................... . L ess th a n 2 y ears ............................... . P e r ce nt 100% 7 5% 50% 25% 0% Nonves t ed D i s trict co ntri b uti o n s a r e fir s t u sed to cov e r P l a n adm in i s trativ e expe n ses a n d a ny r emai nin g f o rf ei tur es a r e alloca t ed b ack t o P l an pa rtici pants. E mpl o y ees m ay a l so con tri b ut e t o a de fin ed co ntribution 4 57 pension plan (" 4 57 P l a n*). Th e 45 7 P l a n i s a d e f e rr ed i nv estmen t op ti o n with n o D i s trict m at ch. Pa y pe ri od contributi o n s ca n be elected and ch a n ged a t a ny tim e. E a rty withd rawa l s ca n be m ade from th e 45 7 Pl a n followin g sep arati o n of serv i ce r egardless o f age with no I RS pe nalty. In co m e taxes a r e owed on a ny with d rawal s. Th e Partici pa nts' contri b ution s w e r e $2.5 m i lli o n a nd $2.1 m i lli o n f o r 2 017 a n d 2 01 6 , r es pectiv el y. 1 1. O TH ER P OS TEMPL O YM E NT BE N E FITS: Th e Disbict ea rty a dopt ed th e provision s of G A SS Statement No. 75 (" GA SB 75 m). Accounting and Financi a l Reporting for Postemployment Benefits Other than Pensions , in 2016. There was no im pact to beginn*ng net position as a r esult of the im p ementation in 20 16. A. General information regarding t he OPEB Plan -Plan Desaiption Th e Disb'ict's P ostemployment Med i cal and Life Benefits Plan (" Plan 1 provides postemployment hospital-med i cal a nd l if e i nsuran ce benefits to qualifyin g reti rees , surviving spouses , and employ ees on long-term d i sability and th eir dependents. Ben e fits and rel ated el i g ibility , fu nd i ng and other Pla n provi sion s , for th i s single-employer , de fi ned benefit Plan , are a uthorized by the Board. The Plan has been amended over th e years and provi des different benefits based on hi re dat e and/or the age of the employee. The District pays all or part of the cost (determ i ned b y age) of certain hospital-medical prem iu ms for employees hi red on or prior to December 3 1 , 1 992. Employees h ired on or after January 1 , 1 993 , are subject to a conbibulion cap that li mits the District's portion of the cost of such coverage t o the full prem i u m the year the employee reached age 65 , or the y ea r i n whi ch the emplo y ee retires if older than age 65. Employ ees hi red on or after January 1 , 1 999 , are not elig i ble for other postem ployment hospital-medical benefits once they reach age Fi:nm10ial Repolit

65. Employees hired on or after January 1 , 2004 , are not eligible for other postemployment hospital-medical benefits once they retire. The District amended the Plan effective July 1 , 2007 , to provide that any former employee who is rehired will receive credit for prior years of service. The District further amended the Plan effective September 1 , 2007 , to provide that employees hired or rehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for other postemployment hospital-medical benefits once they retire. In May 2015 , the Board approved a change for Medicare-eligible retirees for prescription drugs from the District's self-insured employee prescription plan to a group insured Medicare Part D supplement effective January 1 , 2016. The District also provides a postemployment death benefit of $5 , 000 for qualifying employees. Employees Covered by Benefit Terms The following table shows the employees covered by the hospital-medical benefit terms as of January 1 : 2017 2016 Actiw erll)loyees

......................... .... ... ......... ...... ................. .... 1,007 lnactiw elll)loyees in retirement status ....... ......................... ... .. 1 , 381 lnactiw elll)loyees in long-term disabitity status......................... 64 ------Total erll)loyees cowred by benefit terms...........................

... 2 , 452 -------1 , 175 1 , 260 67 2 , 502 The following table shows the employees covered by the life insurance benefit terms as of January 1: 2017 2016 Actiw erll)loyees

.................................................................... 1,851 lnactiw erll)loyees i n retirement status ..................................... 1 , 2 1 3 lnactiw erll)loyees in long-term disabiity status ..... ............ ........ 72 ------Total erll)loyees co'v'efed by benefit terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 , 136 -------Contributions 2 , 003 1 , 077 74 3 , 154 The Board annually approves the funding for the Plan , which has a minimum funding requirement of the actuarially-determined annual r equ ir ed contribution

(" ARC*) to achieve full funding status on or before December 31 , 2033. The District OPEB contributions were $28.4 million and $74.7 million in 2017 and 2016 , respectively.

Certa in wholesale customers under the 2002 Contracts have pursued legal action related to their objection of the in dusion in rates of additiona l collections of previously incurred OPEB costs. Since the arbitration filing i n May 2016 , collections from these customers have been held in separate accounts and have not been transferred to the Trust , pending the outcome of the legal action. Th e r evenue collections for the catdHJp OPEB funding from these customers , which have not yet been transferred to the P l a n , were $3.5 million and $1.6 million as of December 31 , 2017 and 2016 , respectively.

Contributions from i nactive Plan members for their share of the premium payments are reported as a reduction of benefit expenses. Contributions from Plan members were $0.6 million and $0.5 million for 2017 and 20 16 , respectively. 8. Net OPEB Liability-The District's net OPEB liability was m easured as of January 1 , 2017 , and January 1 , 2016 , and the total OPEB liability used to calculate th e net OPEB liability was determ i ned by an actuarial valuation as of th ese dates. 50 Financial

~~pont Actuarial Assumptions The actuarial assumptions used in the January 1 , 2017 , valuation were based on the results of an actuarial exper i ence study for the period January 1, 2016 through December 31 , 2016. The total OPEB liability in the January 1 , 2017 , actuarial valuation was determined using the following actuarial assumptions , applied to all periods included in the measurement , unless otherwise specified: Actuarial cost method ............. . Amortization method .............. . Amortization period ................ . Asset valuation method ........... . Discount rate .....................

.... . Healthcare cost trend rates ..... . Inflation

................................. . I nvestrnent rate of return ......... . M>rtality

..............................

.. . Retirement age ..............

........ . Entry Age Normal Le"1:ll amortization of the unfunded accrued liability 16-year closed period 5-year smoothed market 6.25% Pre-Medicare

7.3% initial , ultimate 4.5% Post-Medicare

9.1% initial, ultimate 4.5% 2.1% 6.25%, net of in"1:lstrnent e~nse , including inflation RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 with generational projection Varies by age The actuarial assumptions used in the January 1 , 2016 , valuation were based on the results of an actuarial experience study for the period January 1 , 2015 through December 31 , 2015. The total OPEB liability in the January 1 , 2016 , actuarial valuation was determined using the following actuarial assumptions , applied to all periods in ducted in the measurement , unless otherwise specified: Actuar i al cost method ...........

.. . Alrortization method .............. . Alrortization period ................ . Asset valuation method ........... . D i scount r ate .................

........ . Healhcare cost trend rates ..... . Inflation

................................. . In~ rated return ......... . Nlorlaity

.... --*. -* ...............

....... . Retirement age ...................... . Entry Age l'brmal Lei.el arrortization of the unfunded accrued tiability 17-year closed period 5-year srroolhed market 6.25% Pre-Med icar e: S°.k i nitial, ulimate 5% Post-Medicare

6. 75% i nitial , ulimate 5% 2.1% 6.25%, net din~ e>q:>enSe , i ncuding i nflation RP-20 14 Aggregate table projected back to 2006 using Scale Yl-2014 and projected forward using Scae Yl-2015 \Mlh generational projection Varies by age The long-term expected rate of return on OPEB plan *nvesbnents was determined using a building-block method i n which best-estimate ranges of expected future rates of return (expected returns , net of OPEB plan in vesbnent expense and i nflation) are developed for each major asset dass. These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by add ing expected i nflation.

Financia l R ep@rt The target allocation and best estimates of geometric real rates of return for each major asset class are summarized in the following table for the valuation measurement date of January 1 ,: Discount Rate Asset Class Equity (1) .............. . F i xed Income .......... . Asset Class Equity (1) .............. . F i xed Income .......... . Target Allocation 70% 30% 100% Target Allocation 68% 32% 100°/o 2017 Long-Term E><pected Real Rate of Return 6.8% 3.6% 6.1% 2016 Long-Term E><pected Real Rate of Return 6.8% 3.5% 6.1% (1) The actuary i ncluded the 10% real estate alocation YAth eq ui ty. The d i scount rate used to measu r e the total OPEB liab i l i ty was 6.25% for the actuarial valuations as of January 1 , 2017 and 2016. The projection of cash flows used to determine the discount rate assumed that contributions will be made at rates *equal to the actuarially-determined contribution rates. Based on those assump ti ons , the OPEB Plan's fiduciary net position was projected to be ava i lable to m ake all projected benefit payments for current active and inactive employees. Therefore , the long-term expected rate of r e tu rn on OPEB plan i nvestmen t s was applied to all periods of projected benefit payments to determine the tota l OPEB l iability. C. Changes in the Net OPEB Liability

-The following table shows the Total OPEB Liability , Plan F i duciary Net Position and Ne t OPEB Li ability as of January 1 , 2017 , and the changes during th i s period , based o n th e val u ation measuremen t date of January 1 , 2017 (i n OOO's): Li abi i ty Net Positi on Li abi i ty (a) (b) (a-b) Balances at 1/1/2016 ..........................

........................................ . $ 333 , 833 $ 7 5 , 224 $ 258 , 609 Changes f or the year: ............................................

...................... . Senice cost ..........................

.....................

............................. . 3 , 322 3 , 322 I nterest ................................................................................... . 20 , 658 20 , 658 Diff erences between elCpeC1ed and actual ellperience

................. . (203) (203) Changes of assuJ11]1ions

- .*.*.*.***.***.******.**..***..****..*..**...

- .*****..** (18,807) (1 8 , 807) Conbi bulions -efl'llloyer

....................................................

...... . 7 4 , 71 2 (7 4.71 2) Net i nvestnient i ncome ...........................................................

.. . 6 , 101 (6 , 101) Benefit payments .......................................

...............

............... . (13, 459) (13 , 459) Admni slralNe eicpense .**********...********.*****.******.****************.*********

(69) 69 Net changes ...........

...........................................*..........................

(8, 489) 67 , 285 (7 5 , 77 4) Balances at 1/1/2017 .....................................................

............. . $ 325 , 344 $ 1 42 , 509 $ 1 82,835 Net position as a % d Tolal CPEB Liabiity ..................................

.. . 43.8% 52 FinanciaJ1 R~p0rt There were changes made in certain assumptions for the valuation measurement date of January 1 , 2017. The mortality assumption was updated to the RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 with generational projection.

The health care trend dates were also updated. In December 2016 , the District initiated a voluntary early retirement incentive program ("Program") to all regular , fu ll-time employees, excluding senior management , who met certain retirement-eligible criteria. There were 121 employees who accepted the offer. The impact of the Program was included in the January 1 , 2017 actuarial valuation. Se n sitivity of the Net OPEB Liability to Changes in the Discount Rate The following table shows the net OPEB liability of the District , as well as what the net OPEB liability would be if it we r e calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1 , 2017 (in OOO's): 1% Decrease Discount Rate 1% Increase Net OPEB Liability

................ $224 , 980 $182 , 835 $147 , 850 Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPEB l i ability of the District , as well as what the net OPEB liability would be i f it were calculated using healthcare cost trend rates that are 1-percentage-point lower (Pre-Medicare ranging from 6.3% initial to 3.5% ultimate , Post-Medicare ranging from 8.1% initial to 3.5% ultimate) or 1-percentage-point higher (Pre-Medicare ranging from 8.3% initial to 5.5% ultimate , Post-Medicare ranging from 10.1 % initial to 5.5% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 7.3% initial to 4.5% ultimate , Med i care ranging from 9.1% initial to 4.5% ultimate) at the measurement date of January 1 , 2017 (i n OOO's): 1% Decrease Net OPEB liabifity

................

$148 , 629 Healthcare Cost Trend Rates $182 , 835 1% Increase $223 , 946 The following table shows the Total OPEB liability , Plan F i duciary Net Position and Net OPEB liability as of January 1 , 2016 , and the changes during th i s period , based on the valuation measurement date of January 1, 2016 (in OOO's): TotalOPEB Plan Fiduciary NetOPEB Liabiity Net Position Li ability (a) (b) (a-b) Balances at 1/1/2015 ..............

................................

.................... . $ 323 , 122 $ 64 , 487 $ 258 , 635 Changes f or the year: .................................................................. . Seniice cost .................

........................................................... . 3 , 228 3 , 228 l nlerest ...............................................

............

........................ . 19 , 877 1 9 , 877 Diffei euces between e>ipeeted and actual experience

...............

.. . 1 3 , 657 1 3 , 657 Changes of 3SSI.ST4Jlions

.......................................................... . (9 , 1 49) (9 , 1 49) Conlribulions

-ffl1)1oyer

.........................................

................. . 28 , 242 (28242) Net i m.esb1ell i ncome ........................

...........

......................

.... . (453) 453 Benefit payrnenls

...............................

...................................

... . (1 6 , 902) (1 6 , 902) Adrrinislralne eJll)el'lSe

..............*.***

........**..*........***.*.********.*......

(1 50) 1 50 Net changes ........................

.........................................

............... . 1 0 , 711 10 , 737 (26) Balances at 1/1/20 1 6 ..............................................

..............

...... . $ 333 , 833 $ 7 5 , 224 $ 258 , 609 Net position as a % of T olal OPE8 Liabi ily ............................

........ . 22.5% Financial Rep@rt Sensitivity of the Net OPEB Liability to Changes in the Discount Rate The following table shows the net OPEB liability of the District , as well as what the net OPEB liability would be if it were calculated using a discount rate that is 1-percentage-po i nt lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1 , 2016 (in OOO's): 1% Decrease Discount Rate 1% Increase Net OPEB Liability

............ ... . $306 , 681 $258 , 609 $219 , 295 Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPEB liability of the Distr i ct , as well as what the net OPEB liability would be i f it we r e calculated using healthcare cost trend rates that are 1-percentage-po i nt lower (Pre-Medicare ranging from 7% initial to 4% ultimate , Post-Medicare ranging from 5.75% i nitial to 4% ultimate) or 1-percentage-point h i gher (Pre-Medicare ranging from 9% initial to 6% ultimate , Post-Medicare ranging from 7.75% initial to 6% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 8% initial to 5% ultimate , Post-Medicare ranging from 6.75% initial to 5% ultimate) at the measurement date of January 1 , 2016 (in OOO's): 1% Decrease Net OPEB Liability................ $219 , 672 OPEB Plan Fiduciary Net Position Healthcare Cost Trend Rates $258 , 609 1% Increase $306 , 151 The following table shows i nformation on the OPEB Plan F i duciary Net Pos iti on as of December 31 , (i n OOO's): Assets: Cash and cash equ i valents .....................

.................................................. . Receivables

Contributions

.......................

.........................

...................................... . lnwslrnent i ncome ..........

.....................

.....................................

.......... . lnwslrnents

...........................

..................................

..................

............. . Total Assets ..........

................

.............................................

............ . Li abi liti es: Payables: Benefits -healh care ...................

...........................................

............ . Benefits -lif e i nsurance .............................................

..............

........... . lrNeStn ient ellpeflSe

.**.*****.**......*...........

....................................*.*******..

T olal li abi liti es .......................................

..................

....................... . Net Position -Restricted for Other Poslenl)loyment Benefits ................

............ . 54 20 1 7 2016 $ 3 , 02 7 1 49 45 1 17 3 , 4 1 9 177 , 046 1 48 33 5 1 232 $17 6 , 8 1 4 $ 9 , 609 53 261 1 32 , 875 142 , 798 1 28 29 85 289 $1 42 , 509 Fii:namcia l Rep>@r t The following tables show the OPEB assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , 2017 (in OOO's): Quoted Prices in Active Markets for Identical Assets (Level 1) U.S. Treasury and government agency secur i ties .. $ Corporate issues ................................................ . Foreign issues ........................................

........... . Municipal issues ...........................

...................... . Domestic common stocks ....................

............... . 45 , 678 Foreign stocks ......................................

............. . 4 , 002 Mutual funds ...........................................

........... . 64 , 183 $113,863 Significant Other Observable Inputs (Level 2) $ 15 , 956 28 , 056 6 , 629 779 $ 51 , 420 Significant Unobservable Inputs (Level 3) $ $ $ $ Total 15 , 956 28 , 056 6 , 629 779 45 , 678 4 , 002 64 , 183 165 , 283 Other investments measured at net asset value (A) . 8 , 136 $ 173 , 419 (A) The fair value of in vestments in a real estate fund has been estimated using the net asset value per share (or its equivalent) practical expedient and has not been dassified in the fair value hierarchy. The fund allows for quarter1y redemption with a 90-day notice. There are no unfunded commitments to the fund as of December 31 , 2017. The following tables show the OPEB assets that are accounted for and reported at fair value on a recurring basis by level within the fa i r value hierarchy as of December 31 , 2016 (i n OOO's): 2016 Le\EI 1 Lewl2 Lewl3 Total U.S. Tr easury and go\elllment agency secur iti es .. $ $ 2 , 678 $ 2 , 678 Corporate i ssues ................

................................ . 18 , 162 18 , 162 Foreign i ssues ..........................................

......... . 5 , 161 5 , 161 M.lnicipal i ssues ....................

............................. . 766 766 DonleSlic cornrnon stocks ................

................... . 39 , 002 39 , 002 Foreign stocks ................................................... . 3 , 569 3 , 569 Mrtual funds ...................................................... . 63 , 537 63 , 537 $106 , 108 $ 26 , 767 $ $ 132 , 875 D. OP EB Expense , Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB -The Board annually approves the OPEB expense i n rates and has authorized the use of regulatory accounting to equate OPEB expense with the amount i n rates. OPEB expense was $16.7 m i lion for 2017 , as cala.tlated under the GASB 75 guidance. \Mth regWltory accounting , OPEB expense and the amount i ncluded i n rates was $53.3 million for 2017. Th i s amount i ncluded a $25.0 million catch-up rate collection for the net OPEB liability for past production-level services. Fina:ncial Repl@l1t The following table summar i zes the reported deferred outflows and deferred i nflows of resources as of December 31 , 20 1 7 (in OOO's): D i fference betv.een actual and expected experience Difference betv.een expected and actual earnings on investments

........... . Contributions made during the year ended December 31 , 2017 .............. . Total Deferred Outflows .................................................................. . Deferred Outflow $ 3 , 030 3 , 283 28 , 290 $ 34 , 603 Deferred Inflow $ 1 6 , 475 $ 16 , 475 The deferred outflows of resources related to the contr i but i ons made during the year ended December 31 , 2017 will be recognized i n the actuarial valuat i on with a measurement date o f January 1 , 2018. The net of the other deferred outflows and deferred i nflows of resources will be recogn i zed as a reduction i n OPES expense as follows (in OOO's): Year Amount 2018 .......... $ (7 33) 2019 .......... (7 33) 2020 ..........

(7 34) 202 1 .......... (1 , 699) 2022 .......... (2 , 46 1) 2023 .......... (2 , 535) 2024 .......... (1 , 26 7} T otal $i10 , 1 62} OPES expense was $20.6 m i llion for 20 1 6 , as calcu l ated un de r the GASS 75 g ui dance. \Mth regula t o ry acco u n ti ng , OPES expense and th e amount i nduded in r a t es was $52.9 milli o n f o r 20 1 6. Thi s amo un t i nduded a $25 m i llion catch-u p r ate collect i on for th e n et OPEB li abil i ty f or pas t prod ucti on-le v el serv i ces. Th ere we r e n o deferred in flows of r esources r elated to OPES as o f Dece m ber 3 1 , 20 1 6. Th e f ol lowin g table su mm a riz es th e reported deferred o utfl ows of r eso u rces as o f Dece m be r 3 1 , 2 01 6 (in O O O's): Di fference be tween ac tu al and expec t ed expe rien ce .................

......... . Di fference betw een expec t ed a nd ac tu al earnin gs on im es tm e nt s ...... . Contributi o n s m ade du ring t he y ear en ded December 3 1 , 2 016 .......... . T o tal Deferred Outfl ows ............

......................

............................. . $ $ 2 016 3 , 7 69 3 , 86 2 7 4 , 658 82 , 2 8 9 Th e d e f erred outfl ows r ela t ed t o the con tri b uti o n s m ade durin g th e y ea r en ded December 31 , 2 016 wer e recog niz ed in the a ctu a ri al val uati o n with a m easu rement d a t e of January 1 , 2017. Th e oth e r de ferred outflows of resou rces will be r ecog niz ed i n OPEB expe n se as follows (in OOO's): Year 2 017 ****** 2018 ..... . 2019 ..... . 2 020 ..... . 202 1 ..... . 2022 ..... . Total Armunt $ 1 , 705 1 , 704 1 , 7 05 1 , 7 04 7 39 7 4 $ 7 , 631 Add iti onal i nformation i s available

n the unaudited Req ui red Supplementary Information section following the Notes to Financial Statements. 56 Financia[

R~port

12. COMMITMENTS AND CONTINGENCIES

A. Fuel Commitments

-T h e District has various coal supply contracts with minimum estimated future payments of $103.0 million at December 31 , 2017. These contracts expire at various times throu gh the end of 2020. The coal transportation co n tract in place i s sufficient to deliver coal to the generation facilities through and beyond the expiration date of th e aforementioned contracts and is subject to price escalation adjustments. Th e District has a contract for uranium purchases and deliver i es in 2018 , a contract for conversion services of ur a nium to uranium hexafluoride which is in effect through 2021 , a contract for enr i chment services through 2024 , if n eeded , and a contract for fabrication services through January 18 , 2034 if needed , the end of the current op er ating license of CNS. These commitments for nuclear fuel material and serv i ces have combined estimated future payments of $233.0 million. B. Power Purchase and Sales Agreements

-The District has entered into a participation power agreement (the " NC2 Agreemen t") with OPPD to purchase 23.7% of the power of NC2 , estimated to be 157 MW of the power from the 664 MW coal-fired power plant con s tructed by OPPD. The NC2 Agreement contains a step-up provision obl i gating the District to pay a share of the cost of any deficit in funds for operating expenses , debt service , other costs , and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursuant to such step-up prov i s i on i s limited to 160% of it s original participation share (23. 7%). No such default has occurred to date. The District has entered into a participation power sales agreement with Mun icip al Energy Agency of Nebraska (" MEAN") for the sale to MEAN of the power and energy from Gerald Gentleman Station (" GGS") and CNS of 50 MW which began January 1 , 20 11 and continues through December 31 , 2023. The D i strict has entered int o power sales agreements with LES for the sale to LES of 8% of the net power and energy of GGS. In return , LES agrees to pay 8% of all costs attributable to GGS. This agreement i s to terminate upon the later of the last maturity of the debt attributable to the station or the date on which the District retires such station from commercial operation.

The District had entered into a power sales agreement with LES for the sale t o LES of 30% of the net power and energy of Sheldon. In r eturn , LES agreed to pay 30% of all costs attributable to Sheldon. The District and LES executed a termination and release agreement in May 2017 for the Sheldon Station Participation Power Agreement with the termination effective December 31 , 2017. The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately

$36.3 million. These purchases are subject to rate changes. The District owns and operates the 60 MW Ainsworth Wind Energy Facility and h as 20-year participation power agreements to sell 28 MW to four other utiliti es. In addition , the District has power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities

n Nebraska over similar terms. The District has entered i nto a power purchase agreement with Central for the purdlase of the net power and energy produced by th e Kingsley Project during its operating rite. The Kingsley Project is a hydroelectric generating unit at the Kingsley Dam i n Keith County , Nebraska with an accredited net capacity of 37 MW. The District has entered i nto long-term PRO Agreements having i nitial terms of 15 , 20 , or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO Agreements expire on various years between 2023 and 2042. These PRO Agreements obligate the District to make payments based on gross revenues from the municipailies and pay for normal property adcfrtions during the term of the agreement Financia l Re p m 1 t C. Wholesale Po w er Contracts

-The District serves its wholesale customers under total requ i rements contracts that require them to purchase total demand and energy requirements from the Distr i ct , subject to certain exceptions. In 2016 , the Distr i ct entered i nto 20-year Vv'holesale Power Contracts

(" 2016 Contracts") w i th 23 public power distr i cts , one cooperat i ve , and 37 municipalities. One public power d i strict and 9 municipalit i es are served under 2002 Vv'holesale Power Contracts

(" 2002 Contracts"), which exp i re on December 31 , 202 1. The 2016 Contracts allow a wholesale customer to give not i ce to reduce i ts purchase of demand and energy requirements from the Distr i ct based on a comparison of the D i strict's average annual wholesale power costs i n a g i ven year compared to power costs of U.S. util i ties for such year listed in the National Rural Utilit i es Cooperat i ve F i nance Corporat i on Key Rat i o Trend Ana l ys i s (Ratio 88) (the " CFC Data"). The CFC Data places a ut i l i ty's power costs i n percentiles so that any g i ven ut il ity can compare i ts power cos t s on a percentile bas i s to the CFC published quart i le i nformation. The 2016 Contracts allow a wholesale customer to reduce i ts demand and energ y purchases from the District if the Dist ri ct's average annual wholesale powe r costs percent i le leve l for a g i ven y ea r is higher than the 45 111 percentile level (the " Performance Standard Percent i le") of the power costs of U.S. u tiliti es for such year as li sted i n the CFC Data. The 2016 Contracts would not allow any reductions i n demand and energy purchases by a wholesale customer as long as the Dis tri c t's ave r age annual wholesale powe r costs percent i le r ema i ned below the Performance Standard Percentile. The following table lists the Dist ri ct's wholesale power cos t s pe r cent il e fo r th e calenda r years 20 1 2 t o 20 1 6 se t f orth i n th e CFC Data: CFC Data Year Perce nti le 2012 29.1% 20 13 3 1.00A, 2014 2 7.6% 20 1 5 3 1.3% 2 01 6 28.2% Th e Di s tri ct h as t e n wholesale cu stomers r e m a inin g on th e 2 00 2 Con tracts. Th e 2 00 2 Co n tracts allow a wh olesale cu s t o m er t o r educe i ts purdlases o f dema nd an d e n er gy u pon g ivin g app r o pri ate n o ti ce. Red uction s could amo unt t o as mu ch as 90% of th e ir d emand a nd e n erg y r eq uir ements u nde r certa in ci r cum sta n ces. All wh olesale cu s t omers u nder th e 2 0 02 wholesa l e con tracts a r e req uired to purdl ase a t l ea st 10% o f their dem a nd a n d en ergy fro m th e D i s trict th r ou g h Decembe r 3 1 , 2 0 2 1. Th e D i s bi ct h as r ece iv ed n o ti ces fr o m all whol esa l e custom ers under the 2 00 2 C ontra cts as t o th e ir intent t o l e vel off , red u ce , or termin ate th e r eq uirem ents for v a riou s a mounts from 2 017 through 2 0 2 1. The ten cu st omers indud e one munici pal ity which h as a short-term whol esale contr a ct which termin at ed in M a y 2 016. Th ese wh olesale cu st om ers r epresented 4.8% an d 4.5% of operating reven ues for 2017 and 2 01 6 , respectiv el y. Th e Di s bict expects th at n o req uirem ents o f sai d whol esale custom ers will be serv ed by the District in 2 022 , and such wholesale custom ers will pur chase all o f their el ectri c requirements from other suppli ers. The D isbict e xpects to sel l the energy not sold t o such wholesale customers

nto th e S PP Integrated Mark e t and continues to e xplore additional firm requirement and/or fix ed pri ce ag reements. In 2016 , th ree of th e Disbicf s municipal whol esale customers began purdlasing power from thr ee of the District's public power district wh olesale custom ers. Th ese custom ers represented 0.1 % of th e Disbict's 2 016 operating revenues. One of the District's municipal whol esale customers allowed their contract to term*nat e. Th i s customer represented less than 0.1 % of the District's 2016 operating revenues. The 20 1 6 wholesale rat es resulted in a 0.6 % i ncrease for wholesale customers who signed the 2016 Contracts , and a 3.8% *ncrease for those wholesale customers who remained under the 2002 Contracts.

Customers under the 2002 Contracts will pay their share of previously i ncured OPEB costs (or the catch-up amount) through rates prior to the expiration of their contracts

n 2 021. Customers under the 2016 Contracts received a discount for the deferral of O PEB collections , extending those colections

nto the new contract period and redting in the lower Financial Re,po]t . . ' . ', ~; .. :~'-t*:~*~~::. !:* * * ***,f~,t~1\y.~J!.

net wholesale rate increase. The District financed with taxable debt the 2016 Contracts customers' share of the OPEB catch-up amount for 2016 and 2017 and plans to issue additional taxable debt for catch-up funding in 2018. The customers under the 2016 Contracts will commence payment of the related debt service beginning in 2022 , the year after the expiration of the 2002 Contracts. Eight of the ten wholesale customers who remained under the 2002 Contracts filed for binding arbitration in May 2016 claiming the 2016 wholesale rate violates the 2002 Contracts , is contrary to Nebraska's rate statute and reflects bad faith toward those not signing the 2016 Contracts. These customers have since added the OPEB component of the 2017 wholesale rate to their dispute. The arbitration panel ruled in favor of the District in April 20 1 7. This case was appealed and argued before the Nebraska State Supreme Court ("Court") in March 2018. The District is awaiting the Court decision. Since the arbitration filing in May 2016 , disputed amounts have been set aside in separate accounts.

The amount of disputed revenues in the separate accounts was $2.5 million and $0.9 million as of December 31 , 2017 and 2016 , respectively. The Northeast Nebraska Public Power District filed a lawsuit in the District Court of Wayne County , Nebraska regarding the demand and energy reduction provisions under the 2002 Contract. The court issued an order dated Feb ru ary 26 , 2016 , in favor of the Northeast Nebraska Public Power District which allows them to reduce their de m and and energy purchases from the District by 30% in 2018 , 60% in 2019 and 90% in 2020. The court decision will apply to certain other customers who have given notice for demand and energy reductions under the 200 2 Contract.

On March 23 , 2016 , the District filed a notice of appeal. The Nebraska Court of Appeals affirmed the District Court decision in June 2017. The Nebraska Supreme Court declined to review the matter in September 2017. D. SPP Membership and Transmission Agreements

-The District is a member of SPP , a regional transmission organization based in Little Rock , Arkansas. Membership in SPP provides the District reliability coordination service , generation reserve sharing , regional tariff admi n istration , induding generation interconnection service , network , and point-to-point transmission service , and regional transmission expansion planning.

The District was able to participate in SPP's energy imbalance market , a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marg i nal cost, through February 2014. On March 1 , 2014 , SPP commenced a Day-Ahead , Ancillary Services , and Real-Time Balancing Market Integrated Market The Integrated Market also provides a financial market to hedge unplanned transmiss i on congestion , or financial virtual products to hedge uncertainties , such as unplanned outages. The District entered i nto a Transmission Facilities Construction Agreement effective June 15 , 2009 , with Trans C anada Keystone Pipel i ne , LP f Keystone e). This agreement addresses the transmission facilities , construction , cost allocation , payment , and appl i cable cost recovery for the i nterconnection and del i very facilities required for the interconnection of Keystone to the District's transmission system. Cost of the project was $8.4 million and repayment by Keystone , over a 10-year period , began i n June 2010 with a rema i n i ng balance due the D i strict of $2.6 million and $3.5 mill i on as of December 31 , 2017 and 20 1 6 , respectively. The District entered i nto a second Transm i ssion Facilities Construction Agreement effective July 17 , 2009 with TransCanada Keystone XL Pipel i ne , LP r Keystone XL;. Th i s agreement addresses the transm i ssion facilities , construction , cost allocation , payment. and appl i cable cost r ecovery for the i nterconnection and del i very facilities requ i red for the i nterconnection of Keystone XL to the D i strict's transm i ssion system. TransCanada Corporation and TransCanada Pipel i ne USA Ltd. have j ointly and severally guaranteed the payment obl i gations of Keystone u nder its agreements with the D i strict The agreement was cancelled i n 20 1 6 alter the 20 1 2 application for a Presidential perm it for construction of the Keystone XL Pipel in e was denied. Al outstanding balances for Keystone XL were paid i n 2016. E. Cooper Nuclear Station -On November 29 , 20 10 , the NRC formally i ssued a certificate to the District:

to commemorate the renewal of the operating li cense for CNS for an additional 20 years unti l January 1 8 , 2034. CNS entered the 20-year period of extended operation on January 18 , 20 1 4. F i nancia l Rep©n t In October 2003 , the District entered into an agreement (the " Entergy Agreement")

for support services at CNS w i th Entergy Nuclear Nebraska , LLC ("Entergy"), a wholly owned indirect subsidiary of Entergy Corporation. In 2010 , the Entergy Agreement was amended and extended by the parties until January 18 , 2029 , subject to either party's right to terminate without cause by providing notice and paying a $20 million termination charge. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services , and to pay Entergy annual management fees. These annual management fees were $18.5 million for 2017 and $18.5 million for year 2016. These fees will increase by an additional

$1.0 million in 2019, and by an additional

$3.0 million in 2024. Entergy is eligible to earn additional incentive fees in an amount not to exceed $4.0 million annually if CNS ac h ieves identified safety and regulatory performance targets. Entergy has achieved certain safety and regulatory performance targets during the term of the Entergy Agreement and has been eligible for at least a portion of this annual incentive fee. Since the earthquake and tsunami of March 11 , 2011 , that impacted the Fukushima Da i-ichi Plants in Japan , the District , as well as the rest of the nuclear industry , has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the General Electric ("GE") boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities.

CNS utilizes th i s same containment system; however , significant enhancements to the design have been made over the life of the plant. An NRG Near Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12 , 2011 that included 12 recommendations for i mprovements for U.S. reactors. Subsequent to that report , on October 18 , 2011 , the NRG approved seven of the Task Force recommendations for im plementation.

On March 12 , 2012 , the NRG i ssued three orders to the U.S. nudear industry as a result of the Fukushima i chi event in Japan. The first order requires all domestic nudear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond des i gn basis external events. The second order requires nudear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened containment wetwell vents. The third order requires nudear plant operators to add reliable spent fuel pool water level instrumentation.

The NRC has also issued a request for i nformation pertaining to re-evaluation of seism i c and flooding hazards , and a commun i cations and staffing assessment for emergency preparedness. Phase one and phase three of said order have been completed.

Phase two of sa i d order , which requires a drywell vent or a bas i s and strategy for why venting the drywell would not be required , will be completed by the condusion of the fall 2018 r efuel in g and maintenance outage. Since the initi al site-specific se i smic reevaluation analysis for CNS that r esulted in no id entified se ismi c-related modifications to CNS , the District has performed an additional se ismi c analysis and has worked to answer additional questions from the NRG on this topic. The NRC has determined that CNS will have to perform the High Frequency Evaluation and a Spent Fuel Pool Evaluation , but will not have to complete a Seism i c Probabilistic Risk Assessment Unknown to the D i strict at this tim e i s the extent of modifications that may be required as a result of these additional seismic reevaluations.

The D i strict continues to work with the U.S. Anny Corps of Engineers and th e NRG to validate the data necessary to complete the CNS flood h azard reevaluation. The District submitted its updated flooding analysis to the NRC *n February 2015. The NRG subsequently submitted questions to which the Disbict has responded and submittal of the updated flood hazard reevaluation was completed

n September 2016. Based on rurrent interim , and term strategies for flooding mitigation , it i s not expected that any modifications will be required as a result of the flood hazard reevaluations. All equipment and materials required to mitigat e the identified im pacts associated with the flood hazard reevaluation have been flldlased and the equipment requ i red has been i nstalled. Additional equ i pment purchased , but not required to be " nstalled unless an i ssue occurs , i s stored on-site *n dedicated storage faci l ities. The District's cost estimate for plant mo<<ifications associated with the NRC's F u kushima Dai-ich i related orders i s rurrently estimated to cost $23.3 rmllion , which i s expected t o be funded primarily from the revenues of the Disbid and from the proceeds of General Revenue Bonds. As of December 3 1 , 20 17 , $17.3 milion has been spent on F i nancia l R e p ort * , , ' " '1k ...t ... , ' ~w * ..,"' . ,. '> / '

t ,9,',;t:J plant modifications with an additional

$6.0 million expected to be spent to establish compl i ance with the F u kushima Dai-ichi orders. CNS substantially completed the construction of a dry cask used fuel storage project in December 2009 to support plant operations unt il 2034 , which is the end of the Operat i ng License. The first loading campa i gn was completed in January 2011 and encompassed the l oading of 488 used fuel assemblies from the CNS used fuel pool int o eight dry used fuel storage casks for on-s it e storage. A second loading campaign , encompassing the loading of 610 used fuel assemblies into ten dry used fuel storage casks , began in April 2014 and was completed in June 2014. The third loading campaign , encompassing the loading of 732 used fuel assemblies into 12 dry used fuel storage casks , began in June 2017 and was completed in November 2017. As part of various disputed matters between GE and the Dist rict, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assembl i es from the first two full core loadings at CNS at no addit i onal cost to the Dis t rict until the expiration of the current NRC license in May 2022 for the Morris Facil ity. After that date , storage would cont in ue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Fac ility on essentially the existing design and ope r ating configuration. As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract , the District commenced legal action against the DOE on March 2 , 2001. The initi al settlement agreement addressed future claims through 2013. On January 13 , 2014 , the District and the DOE agreed to extend the settlemen t agreement through 2016. On March 2 , 2017 , the District and the DOE agreed to extend the settlement agreement through 2019. The District has received $118.2 million from the DOE for damages from 2009 through 20 16. The District also reserves the right to pursue future damages through the contract claims process. A corresponding r egulatory liabil i ty for these DOE receipts was establ i shed in Other deferred infl ows of resources. The District plans to use the funds to pay for costs related to CNS. The bala nce in the regul atory liability was $66.2 million and $82. 7 million as of December 31 , 201 7 and 2016 , respectively.

Under the t erms of th e DOE contracts , th e District was also sub j ect to a one mill per kilowatt-hour

(" k\1\/h") fee on all energy generated and sold by CNS which was paid on a quarter1y basis to DOE. The District includ es a component i n its wholesale and retail rates for the purpose of funding the costs associated with nucl ea r fuel disposal.

\1\/hile the District expects that the revenues developed therefrom will be sufficien t to cover the District's r esponsib ility for costs currently outlined in th e Nuclear Waste Policy Ad , th e District can give no assurance th a t such r evenues will be sufficient to cover all costs associated with th e disposal of used nucl ear fuel. On May 9 , 2014 , th e DOE provided notice th a t they would ad ju st the spen t fuel disposal fee to zero mills per k\1\/h effective May 16 , 2014. Correspondingly , no add ition a l payments h ave been m ade to the DOE for fuel disposal since th a t date. Th e Board authorized th e continued collection of this fee at the same ra t e. Thi s app roadl ensures costs are recognized i n th e appropriate pe ri od with current customers r eceiving the benefits from CNS paying the appropria te costs. The expense for spent nuclear fuel d i sposal i s recorded based on net electricity generated and sold and the regul a tory li ab i lity will be el i m in ated when payments are made for spent nuclear fuel d i sposal. Under the provisions of th e Federal P ri ce Anderson Act , the District and a ll other licensed nuclear power plant operators could each be assessed for claims i n amounts up to $1 27.3 million per unit owned in the event of any nudear inci dent involvin g any licensed facility i n the nation , with a maximum assessment of $19.0 million per year per inci dent per unit owned. The NRC evaluates nucl ear plant performance as part of its reactor oversight process r RO P"). The NRC h as five performance categories in cluded in the ROP Action Matrix S ummary that i s part of thi s process. As of December 3 1 , 20 17 , CNS was in the Licensee Response Col umn , which i s the first or best of the five NRC defined performance categories and has been i n this column since th e first quarter of 20 1 2. Refuel ing and maintenance outages are required to be performed at CNS approximately every two years. The m os t recent refuel ing and maintenance outage began on September 25 , 2 016 and was completed on November 8 , 20 1 6. During thi s outage , i n addition t o replacing 1 84 fuel assembl i es and conducting routine m aintenance , equipment replacements included one of the two reactor water recirrulalion punp im pelers and motor , the startup station transformer and the high pressure turbine. Financial R~JlO li t Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs , commencing in 2017. The regulatory liability for the pre-collection of outage costs was $20.0 million as of December 31 , 2017 and will be eliminated through revenue recognition during the 2018 outage year. F. Environmental-Water The Federal Clean Water Act contains requirements with respect to effluent limitations relating to the discharge of any pollutant and to the environmental impact of cooling water intake structures. The NDEQ establishes the requirements for the District's compliance with the Clean Water Act through issuance of National Pollutant Discharge Elimination System permits. NDEQ issued the District permits for the following facilities

GGS , Sheldon , CNS , Beatrice Power Station , Canaday Station , Kearney Hydro and the North Platte Office Building.

The District anticipates some level of fish protection equipment technology installation, both for impingement and entrainment , may be necessary for CNS and only for impingement at GGS. Until the final compliance options are determined , the District does not know the financial impact of this regulation. On January 2, 2016 , the final Steam Electric Power Plant Effluent Guidelines rule (the "Effluent Rule") became effective. The Effluent Rule revises the technology-based effluent limitation guidelines and standards that would strengthen the existing controls on discharges from steam electric power plants and sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants , based on technology improvements in the steam electric power industry over the last three decades. Generally , the Effluent Rule establishes new or additional requirements for wastewater streams from the following processes and byproducts associated with steam electric power generation

flue gas desulfurization , fly ash , bottom ash , flue gas mercury control , and gasification of fuels such as coal and petroleum coke. While the District facilities subject to the Effluent Rule are CNS , GGS , Sheldon and Canaday Station , the Effluent Rule only has an impact on Sheldon. Sheldon will be required to be a zero discharge facility for bottom ash transport water by December 31 , 2023. The District is currently analyzing the options for compliance , which is estimated to cost $2.4 million. EPA has listed this rule as one they will consider for regulatory reform and the requirements may be subject to change. Acid Rain Program The Clean Air Act Amendments Title IV established a regulatory program , known as the Acid Rain Program , to address the effects of acid rain and impose restrictions on sulfur dioxide fS02*) and nitrogen oxides r No x*) emissions. Acid Rain Permits have been issued for the following facilities

GGS , Sheldon , Canaday Station and Beatrice Power Station. The Acid Rain Permits allow for the discharge of S02 at each facility pursuant to an allowance system. The District expects to have sufficient allowances for its generating facilities through 2023 , but may be required to purchase additional allowances in the future. Mercury and Air Toxic Standards On February 16 , 2012 , the EPA i ssued a final rule intended to reduce emissions of toxic air pollutants from power plants. Specifically , the Mercury and Air Toxics Standards rMA TS 1 Rule will require reductions in em i ssions from new and existing coal-and oil-fired steam utility electric generating units of toxic air pollutants. The affected District facilities , which are GGS and Sheldon , are i n compliance with the MATS Rule. Cross-State Air Pollution Rule The EPA i ssued a rule i n 2012 wh i ch i s referred to as the Cross-State Air Pollution Rule r cSAPR m) that would require significant reductions i n S02 and NOx emissions i n a number of states , i nduding Nebraska CSAPR compliance periods went i nto effect on January 1 , 20 1 5. Based o n the current CSAPR allocation methodology and current generation projections through 2023 , the District expects to have sufficient CSAPR allowances to cover affected facil iti es em i ssion requ i rements over that ti meframe , but may be requ i red to purchase additional allowances i n the future. Regional Haze The EPA i ssued final regulations for a Regional Haze Program *n JlMle 1 999. The purpose of the regulations i s to i mprove visibility i n the form of reducing regional haze i n 1 56 national parks and wilderness areas across the country. Haze i s formed , *n part from emissions of SOiand NOx. 62 Financial R~p@rt For phase one o f t he Reg i o n a l Haze rul e the Bes t Av ailable Re tr ofi t T e c hn o l ogy (" BAR T') Repo rt was submitted to the NDEQ i n August 200 7 and a rev i sed report was submi tt ed i n Febr u ary 2008. The BART Report proposed that the Best Available Retrofi t Technology to meet reg i onal haze requirements at GGS would be low NO x burners on Un i ts No. 1 and No. 2 and no additional controls for S0 2. Low NO x burners have n ow been i nstalled on both un i ts a t GGS. The NDEQ State I mplementation Plan (" SIP") ag r eed w i th the BART Report. The NDEQ subm i tted the SIP to the EPA for approval on June 30 , 2011. On May 30 , 2012 , the EPA i ssued a r ule pertaining t o the Reg i o n al Haze P r ogram tha t wou l d app r ove the trad i ng program i n CSAPR as an alternat i ve t o determ ini ng BAR T for powe r plants. As a resu lt, states i n t he CSAPR region may subst i tute the trad i ng prog r am i n CSAPR for sou r ce-spec ifi c BART for S0 2 and/or NO x emissions as specified b y CSAPR. On Ju l y 6 , 2012 , t h e EPA i ssued the fin al rule on the Neb r aska Reg i ona l Haze SIP. Th e fi n a l r u l e approved t he GGS NO x portion of t he SIP but d i sapproved the S0 2 portion o f the SIP fo r GGS. Th e EPA i ssued a Fede r al I mplementat i on Plan (" FIP") f or GGS wh i ch stated tha t BART for S0 2 contro l a t GGS i s compl i a n ce wi th CSAPR. The D i strict i s currently i n compl i ance with all requ ir e m ents o f phase one of th e Reg i ona l Haze rule. On J anuary 10 , 20 1 7 , the EPA i ssued fin al changes t o the Reg i onal Haze regula ti o n s f or the second plann in g phase o f the Reg i onal Haze Ru l e. The Dis tri ct i s evalua ti ng t he p ro posed changes but will n ot know th e fu ll i mpact t o t h e Dist ri ct unt i l th e State a n d the EPA begin i mp l e m e nti ng th e second phase of th e Reg i onal H aze ru l e. Th e State i s r equ ir ed t o s u bm i t th e ir SIP for th e second p h ase of th e Reg i ona l H aze ru le b y July 3 1 , 2 0 2 1. Clean Ai r Act Comp li ance (New Source Rev i ew) As pa rt of EPA's na ti onwide inv es ti gat i on a n d enfo r ce m en t p rog r a m f o r coa l-fir ed po w e r p l a nt s' co m p li a n ce with th e Clean Air Act in d u d in g n ew source r e vi ew req uir ements , o n Dece m be r 4 , 2002 , th e Reg i o n 7 o ffi ce o f th e EPA bega n an i nvestiga ti on to d e t erm i ne th e Clea n Air Act co m p li a n ce s t a tu s of GGS a n d S h e l do n. Th e Dis trict ti me ly r esponded t o EPA's r equests for i n f orma ti o n. B y l e tt er d a t ed Dece m be r 8 , 2 008 , EPA Reg i o n 7 se nt a No ti ce o f Vi ola ti on ("N O V") t o th e D i s tri ct whi ch alleges th a t th e Di s tri ct viol a t e d th e C l ea n Ai r Act b y un derta kin g fiv e p ro j ects at GGS from 1 99 1 thr oug h 2 0 0 1 with o ut ob tai nin g th e n ecessa ry pe rmit s. In F e bru a ry a n d A u g u s t 2009 , Di s tri ct r e pr ese n ta tiv es m et with f ede r a l gov ernm e nt r ep r ese n t ativ es to d i scuss th e N O V a nd no add ition a l m ee tin gs h a v e bee n sdled u led. In ge n era l , en f orce ment a cti o n by E PA aga in s t th e D istrict for alleged n oncom pli a n ce with C l ea n Air A ct r equ ir e m e n ts , if uph el d a ft e r court r e view , ca n r es ult in th e r eq uir e m en t to in stall expe n s iv e a ir pol l uti o n co ntr o l equ ipm e nt th a t i s th e BAR T a nd th e impo s iti o n o f m o n eta ry penalti es r ang in g fr om $25 , 000 t o $32 , 500 per da y for ea ch vi o lation. Th e District ca nn o t d e t e rmin e at thi s tim e wh e th er it will h a v e a ny futur e fin a n cial obli g ati o n with r espect to th e NO V. O n July 22 , 2 016 , EPA Reg i o n 7 sen t a new 114(a) r eq u es t for documents a nd i nformation regardin g th e compl i a nce s tatu s of GGS. O n D ecem ber 27 , 2 016 , EP A Reg ion 7 sent a 114 (a) follow-up r eq uest for add ition a l informati o n on ce rtain project s th a t wer e i de ntifi ed in the July 22 , 2016 , 114 (a) request The EPA i s reviewing wheth er there h a v e been physi ca l or operation a l chan ges sin ce November 8 , 2007 wh i ch resulted i n , or could result i n , i n aeased em i ssion s i ncludin g proj ects underway or pl a nned for the next two y ea rs. Th e D i strict gath e red documents and i nformation a nd provided it to th e EPA. F a ilur e to comply with the Clean Air Act ca n result i n fines as desaibed abov e and/or requirements to i nstall additional em i ssion control equipment.

The Disbict beli e ve s GGS h as been operat ed and m a intained i n compliance with th e requirements of th e a ean Air Act.. aean Power Plan On October 23 , 2015 , the E PA published th e final a ea n Power Plan r cPP j rule addressing carbon dioxide reductions from existing fossil-fueled power plants. Th e final rule gav e states signifi ca nt responsibility for determ ini ng how to achiev e the reduction targets through the development of a Stat e Plan. Each stat e was given a reduction target to be achieved by 2030 , with i nterim reduction s reqt.ired between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 em i ssions. On February 9 , 20 1 6 , the U.S. S upreme Court issued a stay for the CPP until all legal challenges hav e been decided. The D.C. C i raJit Court of Appeals heard oral argtments on September 27 , 2016 and a decision was expected i n early 2017. Prior to the Court i ssu i ng a decision , the EPA asked the Court t o hold the legal process i n abeyance while the EPA worked to repeal and replace the CPP. Financia l R epo n t O n October 16 , 2017 , the EPA published a proposed rule to repeal the CPP on the basis that the CPP exceeded th e authority of the EPA. Comments are due on April 26 , 2018. On December 28 , 2017 , the EPA published an Ad v anced Notice of Proposed Rulemaking

(" ANPR") seeking input on what a CPP replacement rule should include. Comments on the ANPR were due on February 26 , 2018. Due to the stay and the EPA process to repeal and replace the CPP with a new rule , the NDEQ and the District have halted all work on implementing the CPP. It is u nknown at this time what the potent i al impact to the District will be until the EPA finalizes the CPP replacement rul e. Im p act from Changes to Environmental Regulatory Requi r ements An y changes in the environmental regulatory requirements imposed by federal or state law which are applicable to t h e District's generating stations could result in i ncreased capital and operating costs being in curred by the District. The District is unable to predict whether any changes will be made to current environmental regulatory requirements , i f such changes will be applicable to the District and the costs thereof to the District.

G. Sale of Spencer Hydro Facility-In September 2015 , a memorandum of understanding

(" MOU") was signed for the sale of the District's Spencer Hyd r o (" Spencer")

facility , including dam , structures , land , water appropriations , and perpetual easements for the reservoir , to the N i obrara River Basin Alliance ("Alliance

") (Five Natural Resource Districts) and the Nebraska Ga m e and Parks Commission

("NGPC") for $12.0 m illi on. The 2015 MOU that was signed expired on June 1 , 201 7. Following the expiration , both parties have negotiated an agreement for the sale and purchase of the Spencer facility. It was distributed to the Alliance and NGPC in December 2017 for s i gnatures. Currently , there is no agreement in place. 13. LITIGATION

On January 1 , 2016 , Tri-State Generation and Transm i ss i on Association , Inc. (" Tri-State") became a transmission mem b er of SPP and it s transmission facilities in western Nebraska , and the corresponding annual transmission revenue requirements were placed under the SPP tariff. SPP filed at FERC to place the Tri-State transmission facilities in the District's pricing zone rather than establ i sh a new pricing zone for Tri-State. The District protested the filing at FERC , because it results in approximately a $4.3 million per year , or 8%, cost sh ift incr ease to the transm i ss i on customers in the District's pricing zone. As a result of the District's protest , FERC set the matter for heari n g before an adm ini strative law ju dge and the District and other parties submitted briefs and testimony on the proper pricing zone and whether SPP's decision i s discriminatory and an unjust and unreasonable cost shift to the D i strict. On February 23 , 20 17 , the admin istr ative law ju dge i ssued an i nitial decision upholding the SPP pricing zone placement and made recommended condusions to FERC. This initi al decision has no legal effect until reviewed and acted upon by FERC which will be after the District submits briefs on it s exception to the factu al and l egal condusions in the initi al decision. FERC's future ruling on the i nitial decision can be appealed to a federal circuit court of appeals. When FERC will rule on the initial decision cannot be predicted. Information on liti gation with wholesale customers under th e 2002 Contracts i s i nduded in Note 12.C. A number of daims and suits are pending aga in s t the District for alleged damages to persons and property and for other alleged li abil iti es arising out of m atters usually incidental to the operation of a utility , such as the District.

In the opinion of management , based upon th e advice of its General Counsel , th e aggregate amounts recoverable from th e D i strict , taking i nto account estimated amounts provided in the financial statements and i nsuran ce coverage , are not material as of December 31 , 2017 and 2016. 1 4. SUBSEQUENT EVENTS: In 2017 , the Nebraska Department of Revenue r NDOR"') conducted a sales and use tax audit on the Districfs records for th e a udit period of June 1 , 20 1 4 through M a y 31 , 2017. NOOR i ssued a Notice of Deficiency Detenn" nation r 0etenn i nation"') to the District for approximately

$6.5 milion , i ncluding i nterest and penalties of over $1.0 milion , on January 30 , 20 1 8. Beyond the minor sales and use tax corrections contained i n a normal audit Determ ination , the NOOR assessed almost $5.5 mil i on of tax on the payments to municipaliti es ooder PRO Agreements. The District d i sagrees with the NDOR's assessment and filed a Petition for Redeterm i nation to formally challenge the Determ*nation on Mardi 29 , 2018. 64 Ffoanoia l Rr pomt SUPPLEMENTAL SCHEDULES (UNAUDITED)

Calculation of Debt Service Ratios in accordance wth the General Revenue Bond Resolution for the years ended December 31 , (in OOO's) Operating revenues .....................

................................................................... . Operating expenses .........................................................................

.............. . Operating income ..................

.................................................................... . Investment and other i ncome .......................................................................... . Debt and other expenses .............................

.......................

............................ . Increase i n net position ...................................

.......................................... . Add: Debt and related expenses c 11 .*..*......

..........*...............

.................................. D epreciation and amortization c 21 *....*...**.*.*..*...*...*...*.......*....

...**............*..**.* Payments to retail comrrunities C 3 J ............

................................................... . Amortization of current portion of financed nuclear fuef'1 ............................. . Amounts colected from th i rd party financing arrangements es 1 ....................... . Ded u c t In~ in come r etained in construction funds C*J ..................................... . U-.realized (loss) ga in on in~ sec uriti es ............................................ . Net position available for debt seNce for the General Re\el'lue Bond Resolution

.. Amounts deposited in the General System Debt Service Account P ri nc ipal ..................................................................

....................

............. . Interest ................................................................................

..................... . Ratio of net position available for debt seNce to debt seNce deposits ............... . $ $ $ $ 2017 1 , 101,642 (988 , 931) 11 2 , 711 23 , 591 (64 , 986) 71 , 316 64 , 986 1 22 , 559 27 , 102 42 , 198 938 257 , 783 645 (2 , 595) (1 , 950) 331 , 049 84 , 1 25 71 , 1 98 155 , 323 2.13 2016 $ 1 , 153 , 997 (1,040,715) 113 , 282 31 , 772 (62 , 121) 82 , 933 62 , 121 133 , 666 26 , 553 39 , 468 991 262 , 799 354 43 397 $ 345 , 335 $ 101 , 135 72 , 959 $ 174 , 094 1.98 (1) Debt and other expenses , exdusive of int erest on wstomer deposits , is not an operating expense as defined in the Resolution. (2) Depreciation and amortization a re not operating expenses as defined in the Resolution. (3) Under" the provisions of the Resolution , the payments required to be made by the District with respect to the Professional Retail Operating Agreements are to be made on the same basis as subordinated debL (4) General Revenue Bond financed nuclear fuel is not an operating expense as defined in the Resolution. As of July 31 , 2015 , the effective date of the T axab1e Revolving Credit Agreement, amortization of nudear fuel expense under" the TRCA is exchled from the debt service calculation as the Oislricfs obligation to make payments under" the TRCA is subordinate to the Oislricfs obligation to pay debt service on General Revenue Bonds. (5) The payments received by the District from Ihm party financing arrangements are i nchled as Revenues under" the Resolution , but are not recogrRed as revenue under" GAAP. (6) Interest income on i nvestments held in mnstrudion funds is not Revenue as defined in the Resolution. Financia[ Report Schedule of Changes in the Net OPEB Liability and Related Ratios using a January 1 Measurement Date (in OOO's) Tot a l OPEB Liability 2 017 2016 Service Cost ...................................................................................................................... . $ 3 , 322 $ 3 , 229 Interest .............................................................................................................................. . 20 , 658 19 , 876 Differences Between Expected and Actual Experiences

......................................................... . (203) 13 , 657 Changes of Assumptions

..................................................................................................... . (18 , 807) (9 , 149) Be n efit Payments ................................................................................................................ . (13 , 459} (16 , 902} Ne t Change in Total OPEB Liability

....................................................................................... . (8 , 489) 10 , 711 Total OPEB Liability (beginning)

........................................................................................... . 333 , 833 323 , 122 Total OPEB Liability (ending) (a) .......................................................................................... . $325 , 344 $333 , 833 Plan Fiduciary Net Position Contributions c 1 1 ........*..............*..........

...........................................................................*..... $ 74 , 7 11 $ 28 , 242 Net ln..estrnent Income ........................................................................................................ . 6 , 102 (453) Benefit Payments c 1 1 .....................................................*..*...............*.........................*.........* (13 , 459) (16 , 902) Administrati..e Expense ........................................................................................................ . (69} (150} Net C hange i n Plan F i duciary Net Position ............................................................................ . 67 , 285 10 , 73 7 Plan Fiduciary Net Position (Beginn i ng) ................................................................................ . 75 , 224 64 , 48 7 Plan Fiduciary Net Position (Ending) (b) ............................................................................... . $142 , 509 $ 75 , 224 Net OPEB Liability (Ending) (a) -(b) .................................................................................... . $182 , 835 $258 , 609 Net Posi ti on as a % of Total OPEB Li abi li ty ........................................................................... . 43.8% 22.5% (1) Con tri butions are ~y er-on ly contributions. lnacti..e meniJer contributions v.ere netted wlh bene fi t payments. GASB Statement No. 75 , Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans , was imp l emented by the District in 2016. The provisions of this Statement were not app l ied to prior periods , as it was not p r actical to do so as the information was not readily available. The OPEB schedules are intended to show information for ten years. Additional years will be displayed when available. 66 Fi,]la]loia1 Re,p o lit Schedule of OPES Contributions for Years Ended December 31 , (in OOO's) 2017 2016 Actuarially Determined Contr i bution ...........................

....................................... . $ 21 , 006 $ 28 , 283 Contributions Made in Relation to the Actuarially Determined Contribution

........... . 28 , 439 74 , 711 C o ntribution Deficiency (Excess) ...................................................................... . $ (7 , 433) $ (46 , 428) N o tes to Schedule: Valuation date -Actuarially determined contribution rates are calculated as of January 1 , one year prior to the end of the fiscal year in which contributions are reported. Me t hods and assumptions used for 2017 -Actuarial cost method . . . . . . . . . . . . . . Entry Age Normal Amortization method . . . . . . . ... .. .. . Le\tel amortization of the unfunded accrued liability Amortization period . . . . . . . . . . . . . . . . . 1 ~year closed period Asset valuation method . . . . . . . . . . . . 5-year smoothed market Discount rate . .... .. .. .. . . . ..... .. .. .. . 6.25% Healthcare cost trend rates ...... Pre-Medicare

7.3% initial , ultimate 4.5% Post-Medicare

9.1 % initial , ultimate 4.5% Inflation

.........................

......... 2.1% ln\teStment rate of return.......... 6.25%, net of in vestment e~nse , includin g inflation Mortaity ........ ..... .. ... . .. .. . . .. ...... RP-2014 Aggregate table projected back to 2006 using Scale M>-2014 and projected forward using Scale M>-2016 vlilh generational projection Retirement age .....................

.. Varies by age Methods and assumptions used for 2016-Actuarial cost method . . . . . . . . . . .... Entry Age Normal Amortization method . .. . . .. . . ...... Le\tel amortization of the unfunded accrued liabitity Amortization period................. 17-year closed period Asset valuation method .. .. . . .. .. .. 5-year smoothed market Discount rate ... .. .... ... .. . ....... .. .. 6.25% Healhcare cost trend rates ...... Pre-Medicare

8% initi al , ulimate 5% Post-Medicare

6. 75% i nitial, ulimate 5% Inflation........................

.......... 2.1% lme;tment rate of return .......... 6.25%, net of imestment e>cpense , i ncluding i nflation Mortaity ................................. RP-2014 Aggregate table projected back to 2006 using Scale M>-2014 and projected forward using Scale M>-2015 vlilh generational projection Retirement age .....................

.. Va-ies by age Schedule of lnvesbnent Returns for Years Ended December 31 , 20 17 2016 Annual Money-Weighted Rate of Return , Net of rrnestment Expense ............... . 14.2% 5.8% GASB Statement No. 75 , Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans , was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods , as it was not pra c tical to do so as the information was not readily available. The OPEB schedules are intended to show informa t ion for ten years. Additional years will be displayed when available. Financial}

RreFJ<!rnt Mission ---76 049

NLS2018032, Nebraska Public Power District 2017 Financial Report

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NLS2018032, Nebraska Public Power District 2017 Financial Report

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