Text

Nebraska Public Power District 2016 Financial Report
	ML17165A304
Person / Time
Site:	Cooper
Issue date:	06/08/2017
From:	Shaw J; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2017058
	Download: ML17165A304 (56)
	v • d • e

L H Nebraska Public Power District NLS2017058 June 8 , 2017 U.S. Nuclear Regulatory Commission A TIN: Document Control Desk Washington , DC 20555-0001 Always t h e r e whe n you ne e d us

Subject:

Nebraska Public Power District 2016 Financial Report Cooper Nuclear Station , Docket No. 50-298 , DPR-46

Dear Sir or Madam:

50.71(b) The purpose of this letter is to transmit the Nebraska Public Power District (NPPD) Financial Report for the calendar year 2016 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 , /jo Enclosure

-NPPD 2016 Financial Report cc: Regional Administrator w/enclosure USNRC -Region IV Cooper Project Manager w/enclosure USNRC -NRR P l ant Licensing Branch IV Senior Resident Inspector w/enclosure USNRC-CNS NPG Distribution w/o enclosure CNS Records w/enclosure COOPER NUCLEAR STATION P.O. Box 98 /Brownvi ll e, NE 68321*0098 Telephone: (402) 825*3811 /Fax: (402) 825*5211 www.nppd.com NLS2017058 Enclosure Page 1of55 NPPD 2016 Financial Report

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

FINANCIAL REPORT of the 2016 Nebraska Public Power District Statistical Review (Unaudited) 13 Management's Discussion and Ana l ysis (Unaudited) 14 Report of Independent Auditors 29 Financial Statements 30 Notes to Financial Statements 33 Supplemental Schedules (Unaudited) 62 2016 YEAR AT A GLANCE KILOWATT -HOUR SALES 18.9 BILLION OPERATING REVENUES $ 1, 154.0 MILLION COST OF POWER PURCHASED AND GENERATED

$ 635.2 MILLION OTHER OPERATING EXPENSES $ 405.5 MILLION INVESTMENT AND OTHER INCOME $ DEBT AND OTHER EXPENSES $ INCREASE IN NET POSITION $ DEBT SERVICE COVERAGE 31.7 MILLION 62.1 MILLION 82.9 MILLION 1.98 TIMES Financial Report 12 2016 S T A T ISTICAL REVIEW (Unaudited)

Awrage Cents Per kWh Sold Awrage Awrage Less Go'-1'lmmen t Cents Per Number of MWh OPERAT I NG REVENUES Taxes/Transfers

<1) kW h Sold Cus tomers Amount % Retail: Resident i al ..................... . 10.77 ¢ 12.79 ¢ 7 1,868 818 , 305 4.3 Commercia l .................... . 8.50 ¢ 9.88 ¢ 19 , 530 1 , 13 1 , 223 6.0 Industria l ........................ . 5.57 ¢ 5.93 ¢ 59 1 , 277 , 557 6.8 Total Reta i l Sales ......... . 7.91 ¢ 9.05 ¢ 91,457 3 , 227 , 085 17.1 ------Wholesale: Munic i pa l ities<ii ........................................ 6.26 ¢ 46 1 , 868 , 510 9.9 Public Power Districts and Cooperati'.1'ls 1 2) .. 5.85 ¢ 25 7 , 806 , 394 41.3 Total F i rm Wholesale Sales.................... 5.93 ¢ 71 9 , 674 , 904 51.2 Tota l Firm Retail and Wholesale Sales .. 6.71 ¢ 91 , 528 12 , 901 , 989 68.3 Part i cipation Sa l es........................................ 4.05 ¢ 5 1 , 926 , 845 10.2 Other Sa l es<3 l ....................................... ........ 2.20 ¢ 2 4 , 073 , 339 2 1.5 Tota l Electric Energy Sa l es.................. 5.47 ¢ 91 , 535 18 , 902 , 173 100.0 Other Operating Re\1'lnues c*J .......................

.................................................................................. . Unearned Rewnues csJ .................................................................................................................. . Total Operat in g Rewnues .............................................................

................................................ . MWh COST OF POWER PURCHASED AND GENERATED Amount % Production c 6 J ...........................*.....*****....****.**.*...*....****...*..***....****.**.****.*.** 14 , 787 , 399 75.2 Power Purchased

..................................................................................... . 4 , 864 , 394 24.8 Total Production and Power Purchased

.................................................. . 19 , 651,793 100.0 CON1RACTUAL AND TAX PAYMENTS (in OOO's) C 1> Payments to Retail Communities

................................................................................................ . Payments in Lieu of Taxes ......................................................................................................... . Total Contractual and Tax Pa yments ....................................................................................... . OTHER Miles of Transm i ssion and Subt r ansmission Lines i n Ser.;ce ..........................

............................... . Number of Fu ll-lime Employees

.................................................................................................. . (1) Customer coll ections fo r taxes/transfers to other governments are excluded from base rate s. (2) Sales are total r equirements , subject to certa in e x ceptions.

(3) Includes sales in th e Southwest Power Pool (" SPP") and nonfirm sa le s to othe r utilities. (4) Includes revenues for transmission and other m i scellaneous revenues. Re'.1'lnues (in OOO's) Amount % $ 104 , 642 9.1 111 , 722 9.7 75 , 777 6.5 292 , 141 25.3 1 1 6 , 906 10.1 456 , 614 39.6 573 , 520 49.7 865 , 661 75.0 77 , 996 6.8 89,492 7.7 1 , 033 , 149 89.5 66 , 060 5.7 54 , 788 4.8 $1 , 153 , 997 100.0 Costs (in OOO's) Amount % $ 458 , 122 72.1 177 , 12 1 27.9 $ 635 , 243 100.0 Amoun t $ 26 , 553 10 , 064 $ 36 , 617 Amo unt 5 , 267 1, 966 (5) Includes unearned reven ues from prior periods of $17.4 million , 2016 s u r plus reven u es deferred to future period s of $10.0 m i llion , recogn i zed reve nues of $24.7 million fo r the 2016 Cooper Nuc lear Station (" CNS") r efuel in g and maintenance outage , and rec ogni zed revenues of $22.7 million for OPEB expenses related to past service and i nc l uded i n 2016 r ates. (6) I ncludes fuel , operation , and maintenance cos ts. Debt service and capital-related costs are excluded. SOURCES OF THE DISTRICT'S ENERGY SUPPLY (%OF MWH) This chart shows the sources o f energy for sales , ex clu ding participation sales to other utilit i es. Purchases were incl uded i n the appropriate source , except for those pu rchases for which the source was not known. 13 Financ i al Report 48.0% Wind Hydro 6.8%

Purchases 4.5% 1.5%

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

The financial report for the Nebraska Public Power District ("Distr i ct") includes this Management's Discussion and Analys i s , Financial Statements , Notes to Financial Statements and Supplemental Schedules. The financ i al statements consist of the Ba l ance Sheets , Statements of Revenues , Expenses , and Changes in Ne t Position , Statements of Cash Flows , and Supplemental Schedules. The following Management's Discussion and Analysis (" MD&A") provides unaudited information and analyses of activities and events related to the Distr ict's financial position or results of operations. The MD&A should be read in conjunction w i th the audited Financial S tatements and Notes to Financial Statements. The Balance Sheets present assets, deferred outflows of resources , liabilities , deferred infl ows of resources and net position as of December 31 , 2016 and 2015. T he Statements of Revenues , Expenses, and Changes in Net Position present the operating results for the years 2016 and 2015. The Statements of Cash Flows present the sources and uses of cash and cash equ i valents for the years 2016 and 2015. The Notes to F inancial Statemen ts are an integ ral part of the basic financia l statements and contain informa t ion for a more complete understand i ng of the financial position as of December 31 , 2016 and 2015 , and the results of operations for the years 2016 and 2015. The Supplemental Schedules include unaudited information re quired to accompany the Financial Statements. OVERVIEW OF BUSINESS The District is a public corporat i on and political subdivision of the Sta t e of Nebraska (the " State"). Control of the Distr i ct and it s operations are vested i n a Board of Directors

(" Board") consisting of 11 members popularly elected from districts comprising subdivisions of the D istrict's chartered territory. The D i strict's chartered territory inc ludes all or parts of 86 of the State's 93 counties and more than 400 munic i palities in the State. The right to vote for the Board i s generally limited to reta i l and wholesale customers receivi n g more than 50% of the i r annual energy from t he District.

The District operates an integrated electric utility system i ncluding facilit i es for generation , transmission , and distribution of electric power and energy for sales at retail and wholesale. Management and operation of the District is accomplished w i th a staff of approximately 1 , 960 full-time employees. The District has the power, among other things , to acquire , construct , and operate generating plants , transmi ss ion lines , substat i ons , and distribution systems and to purchase , generate , distribute , transmit , and sell electric energy for all purposes. There are no i nvestor-owned utilit i es provid ing retail electric service in Nebraska. The District has no power o f taxation , and no governmental authority has the power to levy or collect taxes to pay, in who l e or i n part , any indebtedness or obligation of or incurred by the Distric t or upon which the D i strict may be liabl e. The District has the right of eminent domain. The property of the District, in the opinion of its Gene ral Counsel , is exempt und er the State Constitut i on from taxation by the Sta te and its subdiv is ions, but the District is required by the State to make payments in lieu of taxes which are distributed to the State and various governmental subdivisions. The District has the power and is required to fix , establish , and collect adequate rates and other charges for electrical energy and any and all commodities or services sold or furnished by it. Such rates and charges mus t be fair , reasonable , and nondiscriminatory and adjusted in a fair and equitable manner to confer upon and distribute among the users and consumers of such commod i ties 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 2016 of 2 , 963.7 megawatts

(" MW"), the District had available 3 , 638.2 MW of capacity resources that included 3 , 033.3 MW of generation capacity from 12 owned and operated genera ting plants and 22 plants over which the District has operating control , 447.7 MW of firm capacity purchases from the Western Area Power Administration , and 157.2 MW of a capacity purchase from Omaha Public Power D istrict's Financial Report 14

(" OPPD") Nebraska City Station Unit 2 (" NC2") coal-fired plant. Of the total capacity resources , 223.7 MW are being sold via partic ipa t i on sales or other capacity sales agreements , leaving 3,414.5 MW to serve fir m retail and wholesale customers and to me et capacity reserve requirements.

The h i ghest summer anytime peak load of 3,030.3 MW was established in July 2012 and the highest winter anyt ime peak load of 2 , 252.0 MW was es t ablished in January 2014 for firm requirements customers. The following tab l e shows the D i strict's capacity resources from generation and respective summer 2016 accred i t ed capability. Type Steam -Con-..entional C 3 l ...................

....................... . Steam -Nuclear ..................................................... . Comb in ed Cycle ...................

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

................... . Combus ti on Turbine c 4 i ...................

........................ . Hydro .................................................................... . Diesel ....................

............................................... . Wind csi .......................................

.......................... . Number of Plan t s (1 l 3 3 6 12 8 34 (1) Inc lu des three hydro plan t s and 12 diesel plants under contract to the D istrict. (2) 2016 summer accredited net capability based on SPP criteria. Summer 2016 Accre d ited Capability (MW) (2 l 1 , 674.0 765.0 220.0 1 25.3 110.7 91.5 46.8 3 , 033.3 (3) Includes Gerald Gentleman Sta t io n (" GGS"), She ldo n Station (" S h eldon"), and Canaday Station (" Canaday"). (4) In clu des the Hallam , Hebron and McCook peak i ng turbines. (5) Includes A inswo rth Wind Energ y F acility (" A insworth") and seven wind fac i lities under contract to the D i stric t. Percent of Total 55.2 25.2 7.3 4.1 3.7 3.0 1.5 100.0 The following table shows the generation facilities owned by the District and their respective f u el types , summe r 2016 accred i ted capability , and i n-service dates. Type Gerald Gentleman Stat i on Units No. 1 and No. 2 ....... . Cooper Nuclear Stat ion .............

.............................. . Beatri ce Power Station ........................................... . She l don Stat i on Units No. 1 and No. 2 .................

.... . Combust i on Turbines (3 generat in g plants) ............... . Canaday Stat i on ...............................

..................... . Hydro (3 generating plants) ...................

.................. . A i nswort h Wind Energy Facility c 2 i ........................... . (1) 20 16 summ er accredited net capability based on SPP c riter i a. (2) Nominally rated at 60 MW. Fue l Type Coal Nuclear Combined Cycle Coal Oi l or N atural Gas Natural Gas Wate r W i nd TH E CUSTOM E RS Reta il and Wholesa l e Cust om ers Summer 2016 Accredited Capab i lity (MW) (1) 1 , 365.0 765.0 220.0 215.0 125.3 94.0 25.2 10.1 2 , 819.6 In-Service Date 1979 , 1982 1974 2005 1961 , 1968 1973 1958 1887 , 1927 , 193 9 2005 In 2016 , the District served an average of 91,457 reta il customers. Currently the District's retail service terr i tory includes 80 munic i palit i es , of which 79 are municipal-owned distribution systems o perated by t he D i strict for the mun i cipality pursuant to a Professional Retail Operations

(" PRO") Agreement.

Details of the District's PRO Agreeme n ts are included in N ote 12 in t he Notes to Financia l Statements. 15 F in a ncial R eport The D i strict serves its wholesa l e customers under total requirements contracts that require them to purchase total power and energy requirements from the District , subject to certain exceptions. In 2016 , the D istrict entered i nto 20-year wholesale power sales contracts with a substantial number of its wholesale customers (t h e '2016 Contracts"). The 2016 Contracts replaced wholesale contracts that were entered into in 2002 (the " 2002 Contracts"). Wholesale customers served under the 2016 Contracts include 23 public power di s tricts (20 of wh i ch are served under one contract with the Nebraska Generation and T r a nsmission C o o perative), one coo perative , and 37 municipalities. Who l esale customers served under the 2002 Contracts i n clude one publ i c power district and n i ne municipalities. The District's goal , with respect to the cost of wholesale service (production and transmission), is that such costs are among the lowest quartile (25 th percentile or less) for cost per kilowatt-hour

(" kWh") purchased , as published by the N ational Rural Utilities Coopera t ive Finance Corporation Key R atio Trend Analysis (Ratio 88) (the " CFC Data"). The District's wholesale power costs percentile was 31.3% for 2015 , based on the latest ava i lable data. Deta i ls of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financia l Statements. The following charts show the District's average reta i l and whole sa le cents per kWh for the years ended D ecember 31, 2012 t h rough 2016. The District also reported av e rage ce n ts p e r kWh sold l e s s customer co ll ect i ons for taxes and transfers to other governments , which are n o t i ncluded i n the D istrict's base rates for retail custome r s. 9.80 .r:. 9.00 8.20 Q) c. .!!? 7.40 c Q) <..> 6.60 5.80 AVERAGE CEN T S PER kWh SOLD -RETAIL (Retail -A ll C l asses) 9.04¢ 9.06¢ 9.12¢ 7.65¢ 2012 2013 2014 2015 9.05¢ 2016 Average Cents per kWh Sold Average Cents per kWh Sold L ess Government TaxesfTran s fers 6.40 6.00 .r:. 5.60 Q) Q. 5.20 Q) <..> 4.80 4.40 AVERAGE CENTS PER kWh SOLD -WHOLESALE (Firm Wholesale Customers Only) 5.91¢ 6.09¢ .. , . , 2012 2013 I I I I I I 2014 2015 2016 Financ i al Report 1 6 Part i c i pa ti o n Sales a n d Othe r Sa l es I n addition, t here are five participation sales agreements in place w i th other util i ties for t he sale of p o wer and energy a t wholesale from specific genera ti ng p l ants. Such sales a r e to Lincoln Electric S ystem (" LES"), Mun i c i pal Energy Age n cy of Nebras k a (" MEA N"), OPPD , Grand Island U ti l i t i es (" G r and I s l and"), and J E A. The Distr i ct a l so se ll s energ y on a n onfirm bas i s in S P P a n d throug h transactions executed with other ut i lities by The Energy Author i ty (" TEA"). T r ans m iss i on Customers The Dis t r i ct ow n s and operates 5 , 267 m i les of t ransm i ss i on and sub t ransmission lines , encompassing near l y the entire Sta t e o f Neb r aska. The Dis t rict became a transm i ssion owning m ember o f S PP , a r eg i onal transmiss i on o r gan i zat i on , i n 2009. The Distr i ct fi les a ra t e with SPP annually that prov i des for t h e recovery o f all transmiss i on revenue requirements associated w i th transm i ss i on fac i l i t i es equa l to or grea t er than 1 1 5 kV. SP P collects and r eimburses the D i s t rict for the u se of the D i st ri c t's transmiss i on f acil i ties by entities other tha n the D i st r ict's firm req u irements customers and all t r ansm i ssion cus t omers st ill served directly by the D i str i ct t hro u gh gran d fathered Transmiss i on Agree m ents. Customers , E n ergy Sa l es , and Revenues The follow i ng table shows cus t omers , energy sa l es , and peak loads of the System , i n clud i n g part i cipati o n sa l es , i n each of the th r ee years , 20 1 4 t hroug h 2016. Megawatt-Hour Sa l es A n yt i me Pe ak Load {MW) Ca l en d ar Average Nu m ber o f Wholesa l e Native Load Percentage Total Percentage Busbar Native Year Reta i l C u stomers Customers<1 l Sa l es (2 l Growth Sales (J) Growth L oad 2014 90 , 293 86 12 , 932 , 5 1 8 (1.6) 20 , 658,755 (0.8) 2 , 811.0 2015 91 , 140 82 1 2 , 579 , 390 (2.7) 20 , 990 , 883 1.6 2 , 695.0 20 1 6 91 , 457 78 1 2 , 90 1 , 989 2.6 18 , 902 , 1 73 (1 0.0) 2 , 963.7 (1) A t t h e end of 2016 , includ e s sales to firm wh o les a le cu s tomers , partici p a t ion cus to mers (L E S , M EA N , J EA , OPPD , G rand I s l a n d), and a y ea rly average o f 2 nonfirm customers. B i l a t e r al s a les to u t iliti es decreased in 2014 due to SPP" s tr ans iti on to a n in te g rated mark et. In 20 1 6 , three of t he D i s trict's mun i cip al w hole s a le cus t o m ers began p urchasi ng p o w er f r om thr e e of the D i s tri c t's public p o w er d istrict wh ol e sa l e cu stome rs , and one of t he D i stri ct's mun ic ipa l who les a le c ustom ers a llowed th ei r co ntract to term i nate. (2) Na t i ve load sales inclu de whol es a l e s ales t o to ta l firm re qu i re men ts c us t o mers an d i n cl ude the r espons i b i l ity o f r e p l a cem e n t powe r b eing procured by t h e District if t he D istr i ct's g ene ra ting assets ar e not operating. P re d o m i n a nt ly , n a ti v e load c u sto me rs a r e served under long-term total re q uirements contracts. (3) Total sales from the S ystem i n clude sales to L ES from G GS a nd Sh el d on; to H e a rt l a n d from C NS , which sale com m enced Ja nuary 1 , 2004 , and term i nated December 31 , 2013; t o KC P L from C NS , whic h sale comme n ce d Ja nuary 1 , 2 0 0 5 , an d t ermina t ed o n Janu ary 18 , 2014; to ME AN , J E A , OPPD , and Gra nd Island from A i n sworth Wind E n e rgy F aci l ity , which sa l e s comme n c ed O cto be r 1, 20 05 , and t e r minates on S ep t em b er 30 , 2025; to OPPD , MEAN , LES an d Grand Isl an d f rom E l kh orn R i d g e Wind Fa ci l i t y , w hic h s al es co mm enced M arc h 1 , 2009 , a nd t e r m i n ates on F e bruary 2 8 , 202 9; to MEAN from GGS a nd CNS , w hic h s a l e c o m m e nced J anuary 1 , 2 01 1 , and t e r minates on Decembe r 3 1 , 2023; to MEA N , LE S and G r an d I s l and fr o m L a r ed o R idge W i n d Fa cility , wh ich sales c omm enced Fe bruary 1 , 2011 , and termi n ates on Ja nu a ry 31 , 203 1; t o O PPD , Linc o ln a nd G ran d Isl a nd from B rok e n B ow I W i nd Facility , w h ich sales commenced D ecemb e r 1, 2012, and te rminat es on N o ve mb er 30 , 2032; t o O PPD , LES and M EAN from C roft on B luffs W i n d Fac i l i ty , which sa l es comme n ced November 1 , 2012 , a n d termin a t es o n Octo be r 31 , 2032; and to OP P D fro m Bro k e n B ow II Wind Fac i li ty which sale commenced Octob e r 1 , 2014 , and terminates on S ep t ember 30 , 2039. (4) The decrease in p erce n ta g e growth fro m 20 1 5 to 2016 wa s a resu lt of r ed u ced n on fi rm r e ve n ues due to l owe r ener gy s a l e s d ue to the p l anned refueling and m ai ntenance ou t a g e at CN S , lo wer nat ur al gas pr ices a nd addi t i ona l wind g e n era t io n i n th e SPP I n t egr ated M a r ket. 17 Fina n cial R eport FINANCIAL INFORMA TI ON The following tables summarize the Dis t rict's financial pos i tion and operating results. CONDENS E D BALA N CE SHEETS (i n OOO's) As of December 31 , 2016 2015 2014 Current Assets ............

.................................................. $ 775,479 $ 764 , 278 $ 719 , 987 Spec i a l Purpose Funds .................................

................. 7 82 , 857 738 , 967 808 , 552 Ut ili ty Plant , Net ..........

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

............................... 2 , 596 , 806 2 , 508 , 971 2,495 , 206 Other Long-Term Assets ............................................... 451 , 048 353 , 639 800,406 Deferred Outflows of Resources

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

.......... 124 , 953 40 , 775 26 , 794 Total Assets and Deferred Outflows ............................ $ 4 , 731 , 143 $ 4 , 406 , 630 $ 4 , 850 , 945 Cu r rent Liabilit i es ........................

.................................. $ 2 8 7 , 322 $ 218 , 858 $ 395 , 676 Long-Term Debt .................

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

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

.... 1 , 867 , 768 1 , 838 , 672 1 , 802 , 850 Other Long-Term Liabilities

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

................................ 889 , 678 727 , 070 1 , 159 , 647 Deferred Inflows of Resources

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

....................... 271 , 258 289 , 846 251 , 648 Net Position .................................................................. 1 , 415 , 117 1 , 332 , 184 1 , 241 , 124 Total Liabilities , D eferred Inflows , and Net Pos i tion ....... $ 4 , 7 31 , 143 $ 4 , 406 , 630 $ 4 , 850,945 CONDENSED RESULTS OF OPERATIONS (i n OOO's) For the years ended December 31 , 2016 2015 20 1 4 O perat i ng Rel.*nues

...................................................... $ 1 , 153 , 997 $ 1 , 097 , 216 $ 1 , 1 22 , 454 Operat i ng Expenses .............

......................................... (1,04 0 , 715) (960 , 259) (1 , 010 , 693) Operat i ng I ncome ..................................................... 113 , 282 136 , 957 111 , 761 lnl.*s t ment and Other Income ......................................... 31 , 772 22 , 355 26 , 039 Deb t and Other Expenses .............................................. (62 , 121) (68 , 252) (75,438) Increase in Net Posit i on ............................................ $ 82,933 $ 91 , 060 $ 62 , 362 SOURCES OF OPERATING REVENUES (in OOO's) For the years ended December 31 , 2016 2015 2014 Firm Retail and Wholesale Sales ...............

..................... $ 865 , 661 $ 848 , 345 $ 887 , 619 Part i c i pation Sales ******************************************************* 77 , 996 77 , 192 81 , 063 O ther Sales ............

...................................................... 89,492 134 , 612 1 72 , 521 Other Operating Rel.*nues

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

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

66 , 060 60 , 730 58 , 352 Unearned Rel.*nues

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

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

................ 54 , 788 (23 , 663) (77 , 101) Total Operating Rel.*nues

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

...................... $ 1 , 153 , 997 $ 1 , 097 , 2 1 6 $ 1 , 122,454 Financial Report 18 CONDENSED STATEMENTS OF CASH FLOWS (in OOO's) For the years ended December 31 , Net Cash Pro'v1ded by Operating Acti'v1ties

...................... . Net Cash Pro'v1ded by (Used in) ln\*sting Acti'v1ties

.......... . Net Cash Used in Capital and Financing Acti'v1t i es ........... . Net Increase (Decrease) i n Cash and Cash Equi1.0 l ents ... . Cash and Cash Equiva l ents , Beginning o f Year ............... . Cash and Cash Equiva l ents , End of Year ................... . Revenues from Firm Retail and Wholesale Sales 2016 $ 253 , 711 $ 2 , 374 (238 , 416) 17 , 669 85 , 060 2015 372 , 503 10 , 961 (388 , 483) (5 , 019) 90 , 079 85 , 060 $ 102 , 729 $ ===========

2014 $ 362 , 365 (199 , 101) (241 , 874) (78 , 610) 168,689 $ 90 , 079 The District allocates costs between retai l and wholesale service and establ i shes its rates to produce revenues sufficient to meet i ts estimated respective retail and wholesale revenue requirements. Wholesa le revenue requirements inc l ude unbundled costs accounted for separately be tween generatio n and transmission. Transm i ss i on costs not recovered from the Distr i ct's wholesale power contracts are expected to be r eco vered through rates charged by SPP. The rates for retail service include an amount to recover the costs of wholesa l e power service in addition to distribution system costs and government taxes and transfers. The D i str i ct's wholesale power contracts provide for the establishment of cost-based rates. Such rates ca n be adjusted at such times as deemed necessary by the D istrict. The wholesale power contracts also provide for the creation of a rate stabilization account. Any surp l us or deficiency between revenues and revenue requirements , within certain limits set forth i n the wholesale power contracts , may be retained in the rate stabilization account. A ny amounts in excess of the lim i ts may be i ncluded as an adjustment to revenue requirements i n the next rate review. The wholesale power contracts also include a prov i sion for establishing a new/replacement generation fund. This provis i on would permit the D i strict to collect an additiona l 0.5 mills per kWh above the normal revenue requirements to be used for future capital expenditures associated w i th generation.

The Dist r ict implemented a 0.6% increase in the District's wholesale rates on January 1, 2017, for all customers.

No increase in retail rates has been im ple mented in 2017. The D i str i ct implemented a 0.6% increase in the D istrict'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 in the Distric t's wholesale rates on January 1 , 2016 , for those wholesale customers who remain under the 2002 20-year wholesale power contract.

The rate increase was h igher for the 2002 Contra cts as these customers will pay the ir share of a catch-up i n fund i ng for other post-employment benefits ("O PEB") costs in 2016 and 2017. The D istrict financed with taxable debt the 2016 Contracts customers' share of the OPEB catch-up trust funding and the 2016 Contracts customers w i ll pay the debt service associated w i th such debt beginning in 2022 and continuing through 2033. No increase i n retai l rates was i mplemented in 2016. Details of the Distr ict's Wholesale Po wer Contracts are included in Note 12 i n the Notes to Financia l Statemen ts. The District implemented a 0.5% i ncrease i n the D istrict's wholesale rates commencing on Janua ry 1 , 2015. No inc rease i n retail rates was implemented in 2015. The District had no wholesale or retail rate inc rease i n 2014. Revenues from firm sales increased

$17.4 mil lion , or 2.1%, from $848.3 million in 2015 to $865.7 million in 2016. The increase i n revenues from 2015 to 2016 was due primarily to a weather-related 2.6% increase in energy sales to firm requirements customers. Revenues from firm sales decreased

$39.3 m illion , or 4.4%, from $887 .6 million in 2014 to $848.3 million in 2015. The decrease was due primarily to lowe r unbilled retail energy with a revenue impact of $14.4 million and a 1.4% decrease in sales volume which was the result of m ilder temperatures. Revenues from Participation Sales The District has participation sales agreements with other utilities that share operating expenses on a pro rata basis. Revenues from participation sales increased from $77 .2 million in 2015 to $78.0 mill i on in 2016 , an 19 Financial Report i ncrease of $0.8 m illio n. Revenues from participation sales decreased from $81.1 million i n 2014 to $77.2 m illi on i n 2015 , a decrease of $3.9 million. This decline was due primarily to participation sales to LES which decreased by $4.4 m illi on due to a 23.0% reduction i n the dispatch of generat i on from Sheldon due to lower prices in the SPP Inte grated Market. The decrease was partially offset by increased wind participation sales Revenues from Other Sales Other sales consist of sales i n SPP's Integrated Market and nonfirm sa l es to other utilities. TEA , of wh ic h the Distric t is a member , has energy marketing responsibilities for the D i strict's other and nonfirm off-system sales and the related management of cred it r i sks. Other sa l es 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 p l anned refueling and ma i ntenance outage at CNS , lower natural gas prices and add i tional w i nd generation in the SPP Integrated Market. Revenue from participat i on sales decreased from $172.5 million in 2014 to $134.6 million in 2015, a decrease of $37.9 million. This decrease was a result of lower prices in the SPP Integrated Market which was due to lower natural gas prices and additional wind generation.

Other Operating Revenues Other operat i ng revenues consist primarily of revenues for transm i ssion and other miscellaneous revenues. These revenues were $66.1 million , $60. 7 million, and $58.4 million in 2016, 2015 , and 2014 , respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the Distr i ct. Unearned Revenues Under the prov i sions of the District's wholesale power contracts , any surplus or deficiency between net revenues and revenue requirements , within certain lim i ts set forth in the wholesale power contracts , may be adjusted in the rate stabilization account. Any amounts in excess of the rate stabil i zation limits may be included as an adjustment to revenue requirements in the next rate review. A sim i lar process is fo ll owed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retai l electric service. Under generally accepted accounting principles for regulated electric utilities , the balance of such surpluses or deficiencies are accounted for as " regulatory liabilities or assets", respect i vely. The District recognizes net revenues in excess o f revenue requirements in any year as a deferral or reduction of revenues. Such surplus revenues are excluded from the net revenues availab l e under the General Revenue Bond Resolution

(" General Resolution

") to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues avai l able under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken i nto account in setting rates. The D i strict recogn iz es any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues , even though the r evenue accrual will not be rea l ized as " cash" until some future rate period. Such revenue deficiency is included , in the year accrued , in the net revenues ava i lable under the General Resolution to meet debt service requ i rements for such year. Revenue deficiencies are excluded in the determination of net revenues available under the General Resolut i on to meet debt serv i ce requirements in the year that such reve nue deficit is taken into account in setting rates. The District recognized or increased revenues a net amount of $54.8 million in 2016. The District's revenues i n 2016 from electric sa l es 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 20 1 6 included a refund of $17.4 mill i on 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 i n revenues) for such amount. The District also recognized or increased revenues by $24.7 mill i on 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 m illi on for OPES expenses related to past service for wholesale customers under Financial Re po rt 20 the 2016 Contracts. The OPEB expenses were included in 2016 rates and financed with proceeds from Genera l Reven ue Bonds , 2016 Series E. The District deferred or decreased revenues a net amount of $23.7 million in 2015. The District's revenues in 2015 from electric sales t o retail , wholesale , and othe r utilities resulted in a surp l us , or over collection of costs. of $11.0 mill i on , which was deferred (decrease i n revenues). In addit i on , the wholesale rates that were in place for 2015 included a refund of $12.0 million of surplus net revenues from past rate per i ods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly , the 2015 revenues from electric sales , which reflect the surplus being refunded, were offset by a revenue adjustment (in crease in revenues) for such amount. The District a l so deferred or decreased revenues by $24.7 million for the pre-collection of CNS refue li ng and maintenance outage costs. This regulatory l i ability will be eliminated through revenue recognition during the 2016 outage year. The Dis trict deferred or decreased revenues a net amount of $77.1 million in 2014. The Distric t's revenues i n 2014 from electric sales t o retail , wholesale , and othe r utilit i es resulted in a surplus , or over collection of costs , of $91.4 mi llion, which was deferred (decrease i n revenues). In addition , the wholesale rates that were in place for 2014 included a refund of $14.3 million of surp l us net revenues from past rate periods. Such surplus had prev i ously been accounted for as a reduction i n revenues in the year(s) the surplus occurred. Accord i ngly , the 2014 revenues from electric sales , which reflect the surplus being refunded , were offset by a revenue adjustment (inc rease in revenues) for such amount. Unearned revenues from prior periods of $1.9 million were refunded directly to customers in 2014. The balance of the regulatory liab i lity for unearned revenues to be applied as credits against revenue requirements i n future rate periods was $168.7 million , $176.1 m i llion , and $177.1 million , as of December 31, 2016 , 2015 , and 2014 , respect i vely. Operat ing Expenses The following chart illustrates operating expenses for the years ended December 31 , 2014 through 2016. $1,2 00 $1,041 Power Purchased

& Fuel $1,000 Production Operation

& Maintenance

(" O&M") -T ransmission & D i s tr ibution O&M (/j $800 c: .S! Customer Service & Information

$600 (/j ... Admin i strative & General ..!!! 0 $400 0 Decommissioning

$200 Deprecia ti on & Amortization

$0 Other 2014 2015 2016 Tota l operating expenses in 2016 we r e $1 , 040.7 million , an increase of $80.4 million from 2015. Total operating expenses in 2015 were $960.3 m illion, a decrease of $50.4 million from 2014. The changes were due primarily to the following: Power purchased and fuel expenses were $347.6 million , $365.1 million , and $386.3 million in 2016 , 2015 , and 2014 , respectively. These expenses decreased

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

$21.2 million in 2015 as compared to 2014 due pr im arily to lower fuel 21 Financ ial Report costs as a result of decreased generation , lower market prices and fewer energy purchases in the SPP Integrated Market. Product i on operation and ma in tenance expenses were $287.7 million, $242.8 million , and $281.7 million in 2016 , 2015 , an d 2014 , respectively. These costs i ncreased $44.9 mill io n due pr i marily to the costs associated with a planned refueling and ma i ntenance outage at CNS completed on November 8 , 2016. These costs decreased

$38.9 m ill ion in 2015 as compared to 2014 due primar i ly to the costs associated with a planned refueling and ma i ntenance outage at CNS completed on November 2 , 2014 , which ended the station's first 24-month operat i ng cycle. No such outage occurred i n 2015. Transmiss i on and distribut i on operation and ma i ntenance expenses were $102.0 million , $87.3 million , and $83.8 m illi on , in 2016 , 2015 , and 2014 , respect i vely. These costs increased

$14.7 million in 2016 as compared to 2015 due primarily to higher fees charged by SPP fo r the Distr i ct's share of qualify i ng transmission upgrade projec t s , in cluding an SPP resettlement for prior periods for the i mp l ementat i on of a tariff provision to compensate transmission upgrade sponsors for qualifying upgrades used by other transmission customers. These costs increased

$3.5 m illi on in 2015 as compa r ed to 2014 due primarily to an i ncrease i n SPP fees. The D i strict is charged by SPP fo r firm requ ir ements customers for the qualify i ng transmission system upgrade projects of other SPP transmiss i on owners. Customer serv i ce and informat i on expenses were $17.7 m ill ion , $17.2 m ill i on , and $17.5 m i llion , in 2016 , 2015 , and 2014 , respectively. Admin i strative and general expenses were $94.1 m i llion , $66.3 million, and $59.4 mi lli on , in 2016 , 2015 , and 2014 , respect i vely. These costs increased

$27.8 m i llion in 2016 as compared to 2015 due primarily to OPEB expenses related to past service and included i n 2016 rates. Details regarding OPEB , includ i ng the early adoption o f new accounting gu i dance in 2016 , are i ncluded in Note 11 in the Notes to F i nanc i al Statements. Admin i strative and general expenses i ncreased $6.9 million in 2015 as compared to 2014 due pr i mari ly to in creases in healthcare costs along with increased expenses for outside services. Decommiss i oning expenses were $21.4 million , $14.7 million , and $18.5 million , in 2016 , 2015 , and 2014 , respective ly. Decommissioning expenses represent the net amount accrued each year for the future decomm i ss i oning of CNS. Such expenses are recorded in an amount equivalent to the i ncome on investments i n the nuclear facility decomm i ssioning fund plus amounts collected for decomm i ssioning in the rates for electric service in such year. Decomm i ssioning expenses increased by $6.7 million in 2016 as compared to 2015 due to an inc r ease in interest income on investments. Decommission i ng expenses decreased

$3.8 million in 2015 as compared to 2014 due to a decrease in income on i nvestments. No additional amounts for decommissioning were collected through rates in 2016 , 2015 , and 2014. Depreciation and amortization expenses were $133.7 million , $130.2 million , and $126.4 m i llion , in 2016 , 2015 , and 2014 , respectively. Increase i n Net Position The increase in net position was $82.9 million , $91.1 m illion , and $62.4 million , in 2016 , 2015 , and 2014 , respective ly. The change in net pos i tion in 2016 as compared to 2015 decreased

$8.2 mill i on and was due primar i ly to a decrease in 2016 revenue requirements from decreased collections for principa l payments for revenue bonds and construction from revenue , partially offset by increased collections for pr i ncipa l payments on commercial paper notes. The change in net position i n 2015 as compared to 2014 increased

$28.7 million and was due primarily to an increase in 2015 revenue requirements from increased collections for construction from revenue and for principa l payments on commercial paper notes , partially offset by reduced collections for principal payments for re venue bonds. Financial Report 22 The following chart i llustrates the D i strict's operating revenues , other revenues , operating expenses , and other expenses for the years ended December 31 , 2014 through 2016. Revenues & Expenses $1,250 $1,200 -+-----------------------

Ci) $1, 150 -+----. ...

_____ ..... _lii\------c: .2 $1,100 ____ _, $1,050 --$1,000 $950 c 2014 2015 2016 FINANCIAL MANAGEMENT POLICY Other Expenses Operating Expenses Other Revenues Operat i ng Revenues The Distr i ct has a F i nancial Management Policy (the " Pol i cy"), which is subject to periodic review and revisions by the Board. This Pol i cy represents general financia l strategies and procedures that are implemented to demonstra t e financial i ntegrity and fisca l r espons i bility in the management of the District's bus i ness and i ts assets. Employees must abide by all applicable District bylaws , Board resolutions , bond resolutions , federal and state laws , other relevant lega l requirements and the Policy. DEBT SERVICE COVERAGE Under t he Policy , the District has established a minimum debt service coverage ratio on the General Revenue Bonds of 1.5 times the debt service on the Genera l Revenue Bonds. The D i str i ct's debt service coverage rat i o was 1.98 , 1.84 , and 1.50 , in 2016 , 2015 , and 2014 , respectively. The coverage was provided primarily by the amounts collected in operat i ng revenues to fund the cost of ut il ity plant additions , the amounts collected in operating revenues for principal and interest payments on the outstanding commercia l paper notes , and the amounts collected for payments to those municipalit i es served by the Distr i ct under long-term PRO Agreements. The i ncrease in the 20 1 6 debt service coverage rat i o over 2015 was pr i mar i ly due to a decrease in the required debt serv i ce depos i ts for 2016. The i ncrease i n the 2015 debt serv i ce coverage ratio over 2014 was primarily due to the fact that effective July 31 , 2015 , the obligation of the Distr i ct to pay the principal , interest , bank fees , and expens e s pursuant to t he Taxable Revolving Credit Agreement i s payable from the Pledged Property subject and subordinated to t he pledge of the Pledged P r operty to the payment of the General Revenue Bonds. FINANCING ACTIVITIES Good c r ed i t ratings allow the Distr i ct to borrow funds at more favorable interest rates. Such ratings reflect only the view of such rating organizations , and an explanation of the signi fi cance of such rating may be obtained only from the respect i ve rating agency. There is no assurance that such ratings will be maintained for any given period of t i me or that they w ill not be revised downward or be w i thdrawn ent i rely by the respective rating agency if , in i ts judgment , circumstances so warrant. Any such downwa r d revis i on or withdrawa l of such ratings may have a n adverse effect on the market prices of bonds. 23 Financial Report The District's credit ratings on its revenue bonds were as fo l lows: Moody's Investors Service .............

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

.................. A 1 Standard & Poor's Ratings Services .......................................

...................... A+ Fitch Ratings ................................................................

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

...... A+ (stab le outlook) (stable outlook) (stab le outlook) The D istrict plans , pursuant to the Policy , to issue separate series of indebtedness , inc luding separate series of General Revenue Bonds , for production projects and for transm i ssion 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 Janua ry 1 , 2036 , the end of the 2016 Contracts. Transmission indebtedness issu ed for transm iss ion 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 dur i ng the term of the 2016 Contracts and from retail sales and transmission revenues rece ived 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 transm iss ion fac i lities, as well as revenues fro m various SPP tariffs. In Apr i l 2017 , the District issued General Revenue Bonds , 2017 Ser i es A and 2017 Series B , in the amoun t of $86.0 million to refund the General Revenue Bonds , 2007 Series B. 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. The Distric t plans to issue additional revenue bonds in 2017 to finance transmission projects. In November 2016 , the District issued General Revenue Bonds , 2016 Ser ies C and 2016 Series D , in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and refund $61.7 million Tax-Exempt Commercial Paper (" TECP"). The District also issued in November 2016 , Genera l Revenue Bonds , 2016 Series E (Taxable), in the amount of $56.1 million to fund a portion of OPEB costs for customers under 2016 Contracts. In Feb r uary 2016, the District issue d Gene ra l R evenue 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 TECP. The refunding reduced total debt service payments over the life of the bonds by $29.8 million , which resulted in present value savi ngs of $20.8 million. In January 2016 , the District issued TECP in the amount of $43.6 million to refund a portion of the Genera l Revenue Bonds , 2005 Series C and General Revenue Bonds , 2006 Series A. In February 2016 , $16.5 million of TECP was refunded by General Revenue Bonds , 2016 Series A and Series B. In Feb r uary 2015 , the District issued General Revenue Bonds , 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $42.0 million , which resulted in present value savings of $26.1 million. Details of the District's debt balances and activity are include d in Note 7 in the Notes to Financial Statements. CAPITAL REQUIREMENTS The Board-authorized capital projects totaled approximately

$109.5 million , $501.0 million , and $197.4 million , in 2016 , 2015 , and 2014, respect i vely. The District's capital requirements are funded with monies generated from operations , debt proceeds , and other available reserve funds. Capital projects for 2016 included: * $22.0 mi l lion for construction of a high-voltage transmission line from the Muddy Creek substation to Ord , Nebraska * $16.4 million for construction of a high-voltage substation i n Holt County, Nebras ka 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 Financial Report 24 Capita l projects for 2015 i ncluded: * $346.8 m i llion for construction o f a h i gh-voltage transm i ss i on line and related substations from a GGS substation n orth to Cherry County , Nebraska and east to a new substation in Holt County , Nebraska * $33.9 m i llion for mod i fications to the hot flue gas ductwork at GGS Unit 2 * $33.1 million for construction of a high-voltage transmission li ne from a substation in Stegall , Nebraska to a substation in Scottsb l uff , Nebraska Capita l projects for 2014 included: * $94.9 mi lli on for construction of a h i gh-voltage transmiss i on line and related substations from the Hoskins s u bstation northeast of Norfolk , Nebraska to Neligh , Nebraska * $14.7 m i llion for replacement of a secondary super-heater out l et at GGS Unit 2 * $7.0 m i ll i o n for replacement of a s i lo dust collector at GGS Units 1 and 2 There were other author i zed capital projects for renewals and replacements to existing facilities and other additions and improvements of $59.0 mill i on , $87.2 million , and $80.8 million for 2016 , 2015 , and 2014 , respect i vely. The Board-authorized budget for capital projects for 2017 is $137.4 m i llion. The 2016 budget was much lower due to large transmission projects authorized i n 2015. The Distr i ct will rece i ve revenues from other transmission owners i n SPP for the i r share of these projec t s over the projects' depreciable li fe. Spec i fic capital projects for 20 1 7 include: * $12.5 million for implementation of Advanced/Smart Mete ri ng and I n terfaces * $7.7 million for construction of an evaporation pond at GGS * $7.4 mill i on for refurbishment of a 115 kV subs t ation i n Beatrice , Neb r aska The follow i ng chart i llustrates the Board-authorized capital projects for the years ended December 31 , 2014 through 2016 , i nclud i ng the Board-authorized budget for the year ended December 31 , 2017. C APITAL R EQU I REMEN T S $600 $50 1 $500 -ti) c: $400 .2 $300 ti) $1 97 ... ca $2 00 0 c $10 0 $-20 14 20 1 5 2016 2017 Budge t R E SOURCE PLANN I NG The D i str i ct's core plann i ng pr i nciples for its most recent Integrated Resource Plan (" IRP") align with the Board's strateg i c goals which include further divers i fying i ts m i x of genera t i ng resources (nuclear , coa l, hydro , wind , energy efficiency and demand response), energy storage , and capital i z i ng on the compe t itive strengths of Nebraska (available water , p r oximity to coal , and abundance of w i nd). Key goals from the IRP i nclude:

achi e ving a goal of 10% of the Distr i ct's energy supply from renewable resources by 2020 ,

i ncreasing focus on energy efficiency to meet customer load growth , and

increasing d i versificat i on with a trend toward cleaner energy 25 Fi n an ci al Repo rt The probabilist i c ana l ys i s under the IRP focused on key future uncertaint i es , i ncluding customer load growth , future environmenta l regulat i ons including carbon d i oxide (" CO/), capital additions and operation and ma i ntenance costs of new units , fut u re fuel , and market p r ices for elec t ricity. The results showed that with the Distr i ct's recapture of 120 MWs of base load generation from expir i ng capacity and energy contracts out of CNS , and lower projected load growth , the D i strict is posit i oned to meet i ts fi r m load requirement needs for the next 10 to 15 years. Spec i fic actions on wh i ch the District will focus to meet load growth needs include add i t i on of renewables , effect i veness of energy efficiency programs and evaluation of additional peak i ng capacity. The District's Board approved the IRP during the second quarter of 2013. Although the I RP included a power uprate for CNS , the District's most recent eva l uation of the costs and market r i sks related to a power uprate has led the District to decide not to engage in a power uprate for CNS at this time. Long-term operatio n of GGS appea r s to cont i nue to be commercially viable even if additiona l l ong-term environmenta l controls are required. The Distr ic t would need to revisit this assumption if high C0 2 costs occur. Operat i on of She l don and Canaday appea r s marg i nally beneficia l unless and until additional environmental controls or other costly ma j or mod i fications are required.

More wi n d and energy efficiency also appear beneficial , but not under a l ow native load growth scenar i o. The major uncertainties ident i fied in the IRP are continually reviewed and evaluated as to their i mpact on the District.

The D i str i ct expects to issue its next IRP in 2018. Renewable Energy The District owns and ope r ates the 60 MW Ainsworth and has 20-year participation power agreements to sell 28 MW to four other utilities. In addit i on , the District has entered into power purchase agreements with seven wind facilities having a total capacity of 435 MW. T hese agreements are for terms ra n ging from 20 to 25 years and require the District to purchase a ll of the electric power output of these wind facilities. The District has en t ered i nto power sales agreements to sell 154 MW of this capacity to four other utilities in N ebraska over similar terms. The Distr i ct will pay only for energy delivered pursuant to such power purchase wind agreements and the cost of the substation and transmission work to connect these facilities to the District's electric system. Partic i pating utilit i es will pay their pro rata share of energy delivered from these facilities along with associated capital addit i ons for substation and transmission work. Hydrogen Generation Mono l ith Materials , Inc. (" Monolith") has expressed an interest to co n struct and operate a ca r bon black facil ity adjacent to the Distr i ct's Sheldon coal-fired generating fac i lity in Nebraska. The construct i on of the carbon b l ack facility is expected to be accomplished in two phases. The electric load to serve any Monolith faci li ty will be served by Norris Publ i c Power District , a firm wholesale customer of the District.

Monol i t h may be the sing llargest industrial customer served in the District's territory. The District entered into a 20-year contract w i th Monolith to purchase the carbon black plants' production of hydrogen rich tai l gas , which will be produced by Monolith during production of carbon black. The District will have to convert i ts exist i ng coal-fired boiler at Sheldon Station Unit No. 2 to burn the hydrogen rich ta i l gas. The boiler conversion is expected to result in a reduction of C0 2. sulfur diox i de (" SO i"), mercury , and other air emissions. Groundbreaking f or Phase 1 occurred in October 2016 and is expected to be mechanically complete and operational in 2018. Phase 2 is schedu l ed to begin i n the second half of 2019. The commercia l 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 convers i on to burn the hydrogen r ic h ta i l gas and convert it to electricity) is scheduled for the second quarter of 2021. ENERG Y R I SK MANAG E MEN T P R ACT ICE S The nature of the District's business exposes it to a variety of risks , including exposure to volatility in electric energy and fuel prices , uncertainty in load and resource availability , the cred i tworthiness of its counterparties , and the operat i onal risks associated with transact i ng in the wholesale energy markets. To help manage energy risks , in cluding the r i sks related to the District's participation in the SPP Integrated Market , the District relies upon TEA to both transact on its behalf in the wholesale ene r gy marke t s and to develop and recommend strateg i es to manage the Dist r ict's exposure to risks in the wholesa l e energy markets. F i nanc i al Report 26 TEA combines a s t rong know l edge of the D i s t rict's sys t em , an i n-depth understanding of the wholesale ene r g y m arkets , expe ri enced people , a nd s t ate-of-the-art technology to del i ver a broad range of standardized and customized energy products and serv i ces to the D i s t r i c t. TEA has assisted the Distr i ct i n develop i ng i ts E n ergy R i s k Management

(" E R M") prog r am. The program or i ginates with t he Board-approved ERM Govern i ng Po li cy and the ERM-Approved Pr oducts and L i m i ts S tandard. These documents establish the philosophy , ob j ect i ves , de l egation of authorit i es , approved products and the i r li mits on t he D i str i ct's energy and fuel act i v i ties necessary to govern i ts ERM program. The object i ve of the ERM program i s to increase fuel a n d energy pr i ce stab ilit y by hedging the risk of sign i ficant adverse impacts to cash flow. These adverse impacts cou l d be caused by events suc h as nat u ral gas or power price v o l a t ility , or extended unplanned outages. The ERM program has been developed to provide assura n ce to the B oard that the r i sks i nheren t i n the wholesale energy market are be i ng quant i fied and appropr i ate l y managed. ECONOM I C FACTORS The r ecent slow i ng of growth of Nebraska's economy continued in 2016. The state's inflation adjusted gross state produc t (" GSP") inc r eased by only 1.1 % from the third quarter of 2015 to the third quarter of 2 0 1 6. Th i s was less than the 1.6% increase i n t he nat i ona l gross domes ti c product over the same 12-mo nth per i od and a substantia l decrease from Nebraska's rev i sed est i mated 2.0% increase i n GSP f r om the th i rd quarter of 2014 to t he th i rd quarter of 20 1 5. Nebraska's slowdown i n GSP growth over the l atest 12 months has been due to declines i n t he " Managemen t of companies and enterprises, " Transporta ti on and warehous i ng" and " Durable goods manufact u r i ng" i ndustr i es. Neb r aska and the Midwest reg i on con ti nue to expe ri ence unemployment rates that are below the nat i ona l average. However , 20 1 6 saw the state's fi rst increase i n its average annual unemp l oyment rate s i nce 2009. Nebraska's unemplo y ment rate i ncreased from an annua l average of 3.0% for 2015 to 3.2% in 2016 but rema i ned well be l ow the 20 1 6 nationa l a v erage unemployment rate of 4.9%. Nebraska's prel i minary , seasonally adjusted unemployment rate was 3.3% i n December 2016 , up slightly from 3.2% in Decemb e r 2 015. B oth numbers were well below the nationa l D ecembe r s e asonally a d justed unemp l oyment r a t es of 4.7% i n 2016 a n d 5.0% in 20 1 5. After severa l years of consistently be i ng o n e of t h e three states w i th the lowest u n emp l oyme n t rates , Nebraska's pre li m in ary , December 2016 unemploymen t rate was the ninth l owest in the nation. T he D i str i ct cont i nues t o monito r changes in national and global econom i c cond i tions , as th ese cou l d impact cost of debt and access t o cap i ta l markets. CERTAIN FACTORS AFFECTING THE ELECTR I C UTI LI TY I NDUSTRY The Electr i c Utility Industry In General The elect r ic util i ty i nd u stry has been , and in the future may be , affected by a number of factors which could impac t the financ i a l cond i t i on and co m pe ti t i veness of e l ectr i c ut i lities , such as t h e District.

S uch factors include , amon g o t hers:

effects of compliance with changing env i ronmental , safety , licensing , regulatory , and leg i slat i ve requirements ,

changes res u l ti ng fro m energy efficiency and demand-side management programs on the t imi ng and u se of electr i c energy ,

ot h er federa l and state legislat i ve and regulatory changes ,

in c reased wholesale compet i tion from independent power producers , marketers , and b rokers , * " self-generatio n" by certa i n industr i al and commercial customers ,

issues relating to the ab i lity to issue tax-exempt obligations ,

severe restrict i ons on the ab il i ty to se ll to nongovernmenta l entities electricity from generat i on projects financed w i th outstand i ng tax-exempt ob l igatio n s ,

changes from projected future load requ i reme n ts ,

increases in costs ,

sh i fts in the avai l ability and relative costs of differen t fuels , 27 Financ i al Report

i nadequate r i sk management procedures and pract i ces with respect to , among other things , the purchase and sale of energy , fuel , and transmission capacity ,

effects of financial instabil ity of various part icipants in the power ma rke t ,

climate change and the potential contributions made to climate change by coal-fired and other fueled generating units ,

inc reased regulat ion of nuclear power plants in the United States resulting from the earthquake and tsunami damage to certain nuc lear power plants in Japan , and

issues relating to cyber and physical security.

Any of these general factors (as well as other factors) could have an effect on the financial condition of the Distr ict. Competitive Environment in Nebraska While wholesale competition is expected to increase in the future, there is a Nebraska statute that prohibits competition for re tail customers. Pursuant to state statutes , retail suppliers of electricity have exclusive rights to serve customers at retail in thei r respective service territories. Any transfer of retail customers or service terr i tor ies between re ta il electric suppliers may be done on ly upon agreement of the respective retail electr i c suppl iers and/or pursuant to an order of the Nebraska Power Review Board. Wh i le state statutes do not prov ide 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 int o agree ments with other wholesale power suppliers l i miting the areas or customers to whom they may sell energy at wholesale.

The District has entered into several such agreements. Financial Report 28 REPORT OF INDEPENDENT AUDITORS To t h e Board of Directors of the Nebraska Pub l ic Powe r D i strict: We have aud i ted the accompanying financial statements of Nebraska Public Power Distr i ct (the " District") wh i ch consist of the balance sheets as of December 3 1, 2016 and 2015 , and the related statements of revenues , expenses , and changes i n net position , cash flows , and the related notes to the financial statements for the years then ended. Management

's Responsibility for the Financial Statements Management i s responsible for the preparation and fair presentation of the financial statements in accordance with accoun ti ng principles generally accepted i n the Un i ted States of Ame rica; t his includes the design , implementation , and ma in tenance of inte rna l control relevant to the preparation and fair presentation of financ i al statements that are free from mater i a l misstatement , whether due to fraud or error. Auditors' Responsibility Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits i n accordance with auditing standards generally accepted in the United States of A merica. Those standa r ds require t h at we plan and perform the audit to obtain reasonable assurance about whether the finan cial statements a r e free from mater ial misstatement.

An audit i nvolves performing procedures to obtain audit evidence about the amounts a nd d i sclos u res i n the financial statements. The procedures selected depend on our judgment , including the assessment of the risks of mater i al m i sstatement of the fi nancial statements , whether due to fraud or error. In making those risk assessments , we consider int ernal control relevant to the District's preparat ion and fa ir presentation of the financial statements in order to design audit procedures that are appropriate in the circ u mstances , but not for the purpose of expressing an o pinion on the effectiveness of the Dis trict's inte rnal control. Accordingly, we express no such op i n i on. An audit also includes evaluating t he appropriateness of accounting policies used and the reasonableness of sign ificant account i ng estimates made by management , as well as evaluating the overall presentation of the financial statements.

We believe that the audit ev idence we have obtained is sufficient and appropriate to provide a basis for our audit opin i on. Opinion In our opinio n , the financial statements r efe rr ed to above present fairly , in all materia l respec t s , the financial position of the D ist r ict as of December 31 , 2016 and 2015 , and the respective changes in fi nancial position and cash flows for the years t hen ended in accordance with accounting princ i ples generally accepted i n the United States of America. Emphasis of Matter As discussed in Note 1 to the financial statements , the Company changed the manner in whic h it accounts for Other Postemploymen t Benefits in 2016. Our opinion is not modi fied with respect to t his matter. Other Matters The accompany i ng management

's discussion and analysis and t h e supplemental schedules on pages 14 through 28 and 62 through 64 , respectively , are required by accounting principles generally accepted in the United S t ates of Amer i ca to supplement the basic fina ncial statements.

Suc h information , a l though not a part of the basic financial statements , is requ ired by the Governmenta l Accounting Standards Board who considers i t to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational , economic , or historical context. We have applied certain limited procedures to the required supplementary informat ion in accordance with aud i ting standa rds generally accepted in t h e United States of America , which consisted of i nq u i r ies of management abou t the methods of preparing the infor mat ion and comparing the info r mation for consiste ncy with management's responses to our inqui ries , the basic financial sta t ements , and other knowledge we obtained during our audits of the basic financial sta t ements. We do not express an opinion or provide any assurance on the i nformation because the limited procedures do not provide us wit h suffic i ent evidence to express an opinion or provide any assurance.

Our a u dits were conducted for the purpose of forming a n opinion on the fina n cial statements that collect iv ely comp r ise the D is trict's basic finan cial statements. The statistical rev i ew is presen ted for purposes of additio na l analysis and is not a required part of the basic f in ancial statements. Such information has not been subjected to the aud i ting procedures app l ied in the audits of t h e basic fina n cial statements , and acco r ding l y , we do not express an opinion or provide any assurance on i t. R, ...... +..L-. c"'I'"" St. Louis , Missouri April 13 , 2017 29 Financial Report LLP F I NANCIAL STATEMENTS Nebraska Public Power D istrict Ba l ance Sheets as of December 31 , (i n OOO's) ASSETS AND DEFERRED OUTFLOWS Current Assets: Cash and cash equivalents

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

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

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

............... . ln1.estments

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

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

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

................... . Rece i vables , less allowance for doubtfu l accounts of $530 and $515 , respecti1.ely

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

.......................... . Foss i l fuels , at a1.erage cost ..............................

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

...........

.. . Materials and supplies , at a1.erage cost ...................................

............... . Prepayments and other current assets ...................................

................ . Special Purpose Funds: Construction funds .....................

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

............... . Debt reserve funds ..................

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

.................................. . Employee benefit funds .............

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

............. . Decommissioning funds ...........

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

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

......... . Ut i li ty Plant , at Cost: Utility plant in service ....................................................

........................ . Less reserve for depreciation

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

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

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

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

............... . Nuclear fuel , at amortized cost ............................................................... . O ther Long-Term Assets: Regulatory asset for asset retirement obligation

....................................... . Regulatory asset for other postemployment benefits .....................

........... . L ong-t erm capacity contracts

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

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

................ .. Unamortized financing costs ......................

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

............ . l n1.es tm e nt in The Energy Authority

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

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

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

.................................... . Total Assets ................................................................................ . Deferred Outflows of Resources: Unamortized cost of refunded debt ......................................................... . Other post employment benefits ..........................

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

...... . TOTAL ASSETS AND DEFERRED OUTFLOWS .......................................... . 2016 $ 102,729 373 , 331 123 , 905 43 , 620 114 , 640 17 , 254 775,479 106 , 204 90 , 032 4 , 851 581 , 770 782 , 857 4 , 971 , 259 2 , 708 , 036 2 , 263 , 223 135 , 853 197,730 2 , 596 , 806 44 , 899 221 , 973 159 , 445 8 , 945 6 , 370 9,416 451 , 048 4 , 606 , 190 42 , 664 82 , 289 12'1'., 953 $ 4 , 731 , 143 LIABILITIES , DEFERRED INFLOWS , AND NET POSITION Current Liabilities

Re1.enue bonds , current ......................................................................... . $ 81 , 250 Notes and credit agreements , current .................

.................................... . 74 , 000 Accounts payable and accrued l iabilities

................................................. . 87 , 061 Accrued in lieu of tax payments .............................

................................ . 10 , 008 Accrued payments to retail communities

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

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

...... . 6 , 037 Accrued compensated absences ........................................................... . 17 , 594 Other .....................................

.............................................................. . 11 , 372 287 , 322 Long-Term Debt: Re1.enue bonds , ne t of current ............................

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

............. . 1,678 , 844 Notes and credit agreements , net of current .........................

................... . 188 , 924 1 , 867 , 768 Other Long-Term Liabilities

Asset retirement obligat i on ...................

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

..................... . 627 , 707 N et other postemployment benefit liability

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

.... . 258 , 609 Other .......................................................................................

............ . 3 , 362 889 , 678 Total Liabil i t i es ...............

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

.. . 3 , 044,768 Deferred Inflows of Resources: Unearned re1.enues

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

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

................. . 168,710 Other deferred in flows .......................................

..................................... . 102 , 548 271 , 258 Net Pos iti on: Net in1.es tment in capital assets ............................................................. . 928 , 967 Restricted

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

........................................................................ . 38 , 776 Unrestricted

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

................... . 447 , 374 1,415 , 117 TOTAL LIABILITIES , DEFERRED INFLOWS , AND NET POSITION ................ . $ 4 , 731 , 143 The accompanying notes to financ ia l s tatement s are an Integral part of these state ments. 2015 $ 85,060 400,426 110 , 089 39 , 335 117,430 11 , 938 764 , 278 76,503 91 , 772 3,344 567 , 348 738 , 967 4,751 , 016 2 , 620 , 091 2 , 130 , 925 209 , 626 168,420 2 , 508 ,971 32 , 323 121 , 595 1 72 , 966 8 , 654 7 , 018 11 , 083 353 , 639 4 , 365 , 855 40 , 775 'l'.0 , 775 $ 4 , 406 , 630 $ 114 , 860 63 , 614 9 , 948 6 , 087 16 , 857 7,492 218,858 1 , 596 , 972 241 , 700 1 , 838,672 600 , 311 121,595 5 , 164 727 , 070 2,784 , 600 176 , 118 113 , 728 289 , 846 866 , 699 40,492 424 , 993 1 , 332 , 184 $ 4,406,630 F i nancia l Report 30 Nebras k a Pub li c Power D i st rict Statemen ts o f Re1.enues , Expenses , and Changes i n Net Position For the y ears ended Decem b er 31 , (i n OOO's) Ope r a ti ng R e1.enu es .................................................................................. . Opera t ing Ex penses: Po w e r purchased

.................................................................................. . Prod u c t ion: F u el ................................................................................................ . Operat i o n and m a i n t enance ............................................................... . Tra n s m iss i on and distribut i on operation an d ma i nte n an c e ..................

....... . Cus t omer ser\1ce and i nformat i on ........................................................... . Adm ini s t ra t i1.e a n d general ..........

........................................................... . Pay m ents to reta il commun i t i es ............................................................. . Decomm i ssioning ................

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

........................ . Dep r ec i at i on and amorti z at i on ................................................................ . Payments i n l ieu of ta x es ...................................................................... . Opera tin g Income ........................

.............................................................. . ln1.eS tm e n t and O t her Income: ln1.es tm en t i nco m e ............................................................................

.... . Othe r i ncome ..........................

............................................................. . Increase in Net Pos it ion Befo r e Debt and Other Expenses ....................

........ . Debt and Other Expenses: Interes t on long-term deb t .................

.................................................... . Allowance for funds used du ri ng construction

.......................................... . Bo n d prem i um amort i zat i on net of debt i ssuance expense ........................ . Other expenses .......................................................

............................. . Increase in Ne t Pos iti o n .................

............................................................ . Net Pos iti o n: Beg i nn i ng balance .................................................

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

.. . End i ng balance .......................

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

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

.................. . 20 1 6 $ 1 , 1 53 , 997 1 77 , 121 1 70,450 287 , 672 1 01 , 952 17 , 696 94 , 112 26 , 553 21,429 1 33 , 666 10 , 064 1 , 040 , 715 1 13 , 282 28 , 239 3 , 533 3 1 , 772 145 , 054 75,415 (4 , 120) (11 ,427) 2 , 253 62 , 121 82 , 933 1 , 332 , 184 $ 1,415 , 117 The accompanying no t es to f in anc i al stat e me n ts are an i ntegral part of these s t atements. 31 Financ i al Report 20 1 5 $ 1 , 097 , 21 6 166 , 58 7 198 , 557 242 , 787 87 , 259 1 7 , 2 1 3 66 , 291 26 , 55 2 14 , 720 130 , 247 1 0 , 04 6 960 , 259 136 , 957 18 , 952 3 ,4 03 22 , 355 159 , 312 80 , 485 (3 , 414) (10 , 392) 1 , 573 68 , 252 91 , 060 1 , 241 , 124 $ 1 , 332 , 184 Nebraska Publ i c Power D istrict Statements of Cash Flows For the years ended December 31 , (in OOO's) Cash Flows from Operating Act i"1ties: Rece i pts from customers and others ...................

................................... . Other rece i pts ........................................................................

...........

... . Payments t o supp li ers and l.*ndors ..................

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

......... . Payments to employees

........................................................................ . Net cash pro"1ded by operating acti"1ties

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

....................... . Cash Flows from lnl.*sting Acti"1t i es: Proceeds from sa le s and maturities of in l.*stments

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

..... . Purchases of inl.*stments

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

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

............ . Income rece i l.*d on inl.*stments

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

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

.................. . Net cash pro"1ded by i nl.*sting acti"1ties

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

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

........... . Cash F l ows from Capital and Related Financing Act i"1ti es: Proceeds from issuance of bonds ...............

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

...........

................................. . Cap it al expenditures for ut i lity plant ..................

...................................... . Contributions in aid of co n struct i on and other reimbursements

.................. . Principal payments on l ong-temi debt .................................................... . I nterest payments on long-temi debt ..........................

............................ . Intere st paid on defeasance debt ...................

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

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

.. . Principal payments on notes and credit agreements

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

.............. . I nterest payments on notes and cred it agreements

.................................. . Other non-operating rel.*nues

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

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

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

....... .. Net cash used in capital and re l ated financi n g acti"1ties

....................... . Net i ncrease (decrease) in cash and cash equ i valents ......................... . Cash and cash equivalents , beg i nning of year ..........................

.................... . Cash and cash equivalents , end of year ................

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

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

.. . Reconc i liation of Operating Income to Cash Pro"1ded By Operating Acti"1t i es: Operating i ncome ..............................

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

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

............ . Adjustments to reconcile operating income to net cash pro"1ded by operating acti"1ties:

Depreciat i on and amort izati on ...............................................

............ . Und i stributed net rel.*nue -The Energy Authority

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

... .. Decomm i ss i oning , net of customer contributions

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

................ . Amortization of nuclear fue l ............................................

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

..... . Changes in assets and liabil i ties which (used) pro"1ded cash: Receivables , net ............

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

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

............................. . Foss i l fuels .........................

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

.................................. . Materials and supplies ........................................................

......... . Prepayments and other current assets .......................................... . Other long-temi assets .................................

............................... . Deferred outflows .........................

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

............................... . Accounts payab l e and accrued payments to retail communities

....... . Unearned rel.*nues

...................................................................... . Other deferred inflows ..............................

..................................... . Other liabilities

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

........................................ . Net cash pro"1ded by operating acti\1ties

............................................ . Supplementary Non-Cash Capital Acti"1ties

Change in ut i lity plant additions in accounts payable ................................ . The a ccom pan yi ng n o tes to finan cial statements are an integral part of these stateme nts. $ $ $ $ $ 2016 2015 1,067 , 143 $ 1 , 101 , 150 209 8 , 082 (565 , 252) (498,959)

(248,389)

(237 , 770) 253 , 711 372 , 503 2 , 775 , 601 597 , 190 (2 , 800 , 722) (591 , 330) 27,495 5 ,1 01 2 , 374 10,961 354 , 776 261 , 189 163 , 807 10 , 363 (261 , 900) (175,744) 18 , 864 12 , 575 (284 , 710) (349 , 425) (77 , 776) (81 , 800) (10 , 194) (21 , 268) (142 , 583) (46 , 166) (2 , 145) (1 , 611) 3 , 445 3 , 404 (238 , 416) (388,483) 17 , 669 (5 , 019) 85 , 060 90 , 079 102 , 729 $ 85 , 060 113 , 282 $ 136 , 957 133 , 666 130 , 247 648 (956) 21 , 429 14 , 720 40 , 754 47 , 626 (10 , 911) 5 , 973 (4 , 285) (2 , 761) 2 , 790 4 , 334 1 , 022 (40) 935 850 (45 , 654) 19 , 122 (2 , 443) (7,408) (1 , 025) (14 , 342) 36 , 715 2 , 663 2 , 306 253 , 711 $ 372,503 4 , 273 $ 7 , 924 Financial Report 32 NOTES TO FINANC I AL STATEMENTS

1.

SUMMARY

OF SIGNIF I CANT ACCOUNTING POLICIES: A. Orga ni zation -Neb r aska Public Power Distr i ct (" Dist r ic t"), a publ i c corporat i on and a political subdivis i on of the State of Nebraska , operates an i ntegr a ted elect ri c ut ility system which includes fac i lities fo r the generation , transm i ss i on , and d i stribution of e l ect ri c power and ene r gy to its Reta i l and Who l esale customers. The control of the D i stric t and i ts operat i ons is ves t ed in a Board of Direc t ors (" Board") cons i s t ing of 11 members popularly elected from distr i cts compris i ng subd i v i s i ons of t he D i stric t's c h artered terr it ory. The Board is author i zed to establ i sh rates. B. Basis of Accounting

-T he finan c ia l statements are prepared in a c cordance w i th Genera l ly Accepted Accounting Princ i ples (" GMP") for account in g guidance provided b y the Go v ernmental Accoun ti ng S t andards Board (" GASS") for prop r ietary funds of governmental en titi es. I n the absence of establ i shed GASB pronouncements , other accounting li teratu r e is followed i nclud i ng gu i dance provided in the Finan ci al Acco u nt i ng S t andards Board (" FASS") Accoun ti ng Standards Codifica ti on (" ASC"). The Distr i ct applies t he accoun ti ng polic i es estab l ished in the GASB cod i fication Section Re10 , Regulated Operat i ons. Th i s gu i dance perm i ts an ent i ty w i th cost-based rates and Board authorization to i nclude revenues or costs in a per i od othe r than t he per i od in wh i ch the r evenues or costs would be reported by an unregu l ated en ti ty. C. Re v enue -Retai l and wholesale revenues are recorded i n the period i n which serv i ces are r endered. Revenues and expenses r elated to prov i d i ng energy services i n connect i on w i th t he Dist ri c t's principal ongoing operations are classified as operat i ng. All othe r revenues and expenses are class i fied as non-operating and reported as i nvestment and other i ncome or debt and o th e r expenses on the Statements of Revenue , Expenses and Changes i n Net Position.

D. Cash and Cash Equivalents

-The operat i ng fund ac c ounts are called Revenue Funds. There is a separate i nvestment account for the Revenue Funds. The Dist r ict reports highly l iqu i d i nvestments in t he Revenue Funds w i th an or i ginal maturity of three months or less to be cash and cash equiva l ents on the balance sheet , except for these type o f investments in the Revenue Funds i nvestment acco u nt. Cash and cash equivalents i n the investment accounts for the Revenue Funds and the Specia l Purpose Funds are r eported as investments on the ba l ance sheet. E. Foss il Fuel and Materials and Supplies -The D i s t r i ct ma i nta i ns i nventories fo r fossil fuels , and ma t erials a n d supplies wh i ch are valued at average cos t. Obsole t e i nventory is expensed and removed from inventory. F. Utility Plant , Depreciation , Amort i zation , and Ma i ntenance -Util i ty plant is stated at cost , wh i ch i ncludes property add i tions , replacements of units of property and betterments. The Distr i c t charges ma i ntenance and repa ir s , including the cost of renewals and rep l acements of m i nor items of property , t o ma i ntenance expense accounts when i ncurred. Upon r etiremen t of property subject to depreciation , the cost of property i s removed from the plant accounts and c harged to the reserve for depreciation , net of salvage. The D i str i ct records d epreciat i on over the est i mated useful life of the property primarily on a straight-line bas i s. Deprec i at ion on ut i li ty plant was approxima t ely 2.6% for the years ended December 31 , 2016 and 2015. The District had f ull y depreciated ut i lity plant , pr i marily related to Cooper Nuclear Station (" CNS"), which was st ill i n service of $927 .5 m i ll i on and $867 .5 million at December 31 , 2016 and 2015 , respectively. The D i s tri c t owns and operates the elect ri c d i str i but i on system in one of the 80 municipalities that i t serves at r eta i l. I n add i t i on , the Distric t has long-term Professional Retail Operations

(" PRO") Agreements w i th 79 mun ici pal i ties for c erta i n retai l electr i c d i str i bution systems. These PRO Agreements obligate the Distr i ct t o make payments based on gross revenues from the municipalities and pay for normal property addit i ons during the 33 Financ i al Report term of the agreements. The District recorded prov1s1ons , net of retirements , for amortization of these plant additions of $5.9 million and $6.3 million in 2016 and 2015, respectively, which was included in depreciation and amortization expense. These plant additions , which were fully depreciated , totaled $185.6 million and $180.9 million at December 31 , 2016 and 2015 , 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 financed 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"), or taxable revolving credit agreement

(" TRCA") is charged a rate based upon the projected average interest cost of TECP or TRCA outstanding. 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 with TECP , the rate was 1.0% for 2016 and 2015. H. Nuclear Fuel -Nuclear fuel inventories are included in utility p l ant. 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 uran i um hexafluoride on the spot market and carries i nventory in advance of the refueling requ i rements 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 outstand i ng method. Deferred unamortized financing costs associated with bonds refunded are amortized using the bonds outstanding method over the shorter of the original or refunded life of the respective bonds. Regulatory accounting , GASB codification section Re10 , Regulated Operations , is used to amortize these costs over their respective periods. J. Asset Retirement Obligations

-Asset retirement obligations

(" ARO") represent the fair value of the District's legal liabil i ty assoc i ated with the retirement of CNS , various ash landfills at its two coal-fired power stations , and the removal of asbestos at i ts various generating facilities. K. Other Postemployment Benefits ("OPEB'J -For purposes of measuring the net OPEB liability , deferred outflows of resources and deferred inflows of resources related to OPEB , and OPEB expense, information about the fiduciary net position of the District's Employment Medical and Life Benefits Plan (" Plan") and additions to/deductions from the Plan's fiduciary net position have been determined on the same basis as they are reported by the P l an. For this purpose , the Plan recognizes benefit payments when due and payable in accordance with the benefit terms. Investments are reported at fair value. The District has elected to early adopt the provisions of GASB Statement No. 75 (" GASB 75"), Accounting and Financial Reporting for Postemployment Benefits Other than Pensions , in 2016. Additional disclosures related to OPEB are in Note 11. L. Auction Revenue Rights and Transmission Congestion Rights -The District uses Auction Revenue Rights (" ARR") and Transmission Congestion Rights (" TCR") in the Southwest Power Pool (" SPP") Integrated Market to hedge against transmission congestion charges. These financial instruments were primari l y designed to allow firm transmission customers the opportunity to offset price differences due to transmission congestion costs between resources and loads. Awarded ARR provide a fixed revenue stream to offset congestion costs. TCR can be acquired through the conversion of ARR or purchases from SPP auctions or secondary market trades. Financial Report 34 M. Defe rr ed Outflows of Resou r ces and Deferred Inflows of Resources Deferred outflows of resources are consump t ions of assets t ha t are applicable to futu r e report i ng. The cos t o f refunded debt is the difference i n the reacqu i sition pr i ce and the net carrying amount of the refunded debt in an advance refunding. Deferred outflows related to OPES i nclude contributions made dur i ng the current year and experience losses. Deferred inflows of resources are acqu i red assets tha t are appl i cab l e to future reporting per i ods and cons i s t o f regulatory l i abilit i es for unearned revenues and other deferred i nflows. Othe r deferred i nflows inc l ude CNS outage collections , Department of Energy (" DOE") settlements , nuclear fuel disposal collect i o n s and a sa l es tax refund from the State of Nebraska for the construct i on of a renewable energy fac i lity. The Distr i ct i s requ i red under the Genera l Revenue Bond Resolu t i on (" Reso l ut i on") to charge rates for e l ec t r i c power and energy so that reven u es will be at l east sufficient to pay operating expenses , aggregate debt service on the Genera l Revenue Bonds , amounts to be pa i d into the Debt reserve fund and all other charges or liens payable out of revenues. In the event the District's r ates for who l esale service result in a surp l us or defic i t in revenues dur i ng a rate period , such surp l us or deficit , within certa i n lim i ts , may be retained in a rate stabi l izat i on accoun t. Any amoun t s in excess of the l i mits w i ll be taken i nto account i n projecting revenue requirements and establishing rates i n future r ate per i ods. Such t reatment of wholesa l e revenues i s stipulated by the Distr i c t's long-term who l esa l e power s u pp l y contrac t s. The Dis t r i ct accoun t s for any surp l us or deficit i n revenues for reta i l serv i ce in a s i m i l ar m anne r. The fo ll ow i ng tab l e summarizes the balance of Unearned revenues as o f December 31 , 2016 and 2015 and act i v i ty for the years then ended (i n OOO's): 20 1 6 2015 Unearned re\.*nues , beg i nning o f year ............................................................. . $ 176 , 118 $ 177 , 143 Surpluses

.................................................................................................... . 9 , 992 10 , 975 Use of p ri or per i od r ate stabil iz a ti on funds i n rates ........................................... . (1 7,400) (12 , 000) Unearned re\.*nues , end of year ..................................................................... . $ 168 , 710 $ 176 , 118 ====== The DOE settlement regulatory liability was established for the reimbursement from the DOE for costs incurred b y the Distr i ct i n con ju nction with the d i sposal of spent nuclear fuel from CNS. Deta il s of the Distr i ct's DOE settlement are i nc l uded in Note 1 2 in the Notes to F i nancia l Statements. Beg i nn in g i n 2015 , the Distr i ct began collecting revenues for the costs of the 20 1 6 CNS refueling and maintenance outage. This regulatory liab i lity was included in Other deferred inflows on the Balance Sheets and amortized through revenue dur i ng 2016 , the year of the outage. The District began collecting revenues fo r the 2018 CNS r efue l ing and maintenance outage in 2017. The D i st r ic t includes in rates t he costs associated w i th nuclear fuel disposal.

Such collections were rem i tted to the DOE under the Nuclear Waste Policy Act unti l the DOE adjusted the spen t fuel disposal fee to zero. effect i ve May 16 , 2014. The Board authorized the use of regulatory accounting for the continued collection of these costs. Th i s approach ensu r es costs are r ecogn i zed in the appropriate period with customers receiving the benefits from CNS paying the appropriate costs. The expense for spent nuclea r fuel disposa l is recorded at the previous DOE rate based on net e l ectricity generated and so l d and the regulatory l i ability will be eliminated when payments are made for spe n t nuclear fuel disposal.

Add i tional deta i ls of the D i strict's DOE spent nuclear fuel collections are i ncluded i n Note 12 i n the Notes t o Financial Statements. 35 Financial Report The following table summar i zes the balance of Deferred outflows of resources as of December 31 , 2016 and 2015 (in OOO's ): 2016 20 1 5 Unamort iz ed cost of refunded debt ....... ..........

... . .. ... . .... ....... .. . . . ... . . ... . . .... .. . .. . . . . $ 42 , 664 $ 40 , 775 O P EB contributions after measurement date ....................................................

74 , 658 Unamort i zed OPEB loss for earnings . . . . . ......... .. .. ... . ....... .. .. ......... .. ... . ... . . . . ....... 3 , 862 Unamort i zed OPEB loss for experience . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 , 769 ---,,-------,-$ 124 , 953 $ 40 , 775 The following tab l e summarizes the balance of Other deferred inflows of resources as of D ecember 31 , 2016 and 2015 (in OOO's): 2016 2015 DOE settlements

...........

............................................................................... . $ 82 , 664 $ 79 , 501 CNS outage collections

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

..................................................................... . 24 , 688 Nuclear fuel disposal co ll ec ti ons .................................................................... . 15 , 098 9 , 539 Renewable Energy Facility Sales Tax Refund .....................

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

... . 4 , 786 $ 102 , 548 $ 1 13,728 N. Net Position -Net posit i on is made up of three components

Net i nvestment in cap it al assets , Restricted , and Unrestricted. Net investment i n capital assets cons i sted of utility plant assets , net of accumulated depreciation and reduced by the outstanding balances of any bonds or notes that are attributable to the acqu i sition , construc t ion , or improvement of these assets. Th i s component also inc l uded long-term capacity contracts net of the outstanding balances of any bonds or notes attributable to these assets. Restricted net position consisted of the Primary account in the Debt reserve funds that are required deposits under the Resolution , and the Decommiss i oning funds net of any relate d liabil iti es. Unrestricted net pos i tion consisted of any remaining net position that does not meet the definition of Net investment i n capital assets or Restricted , and are used to provide for work i ng capital to fund non-nuclear fuel and inventory requirements , as well as other operating needs of the District.

0. Use of Estimates

-The preparation of financia l statements in conformity with accounting principles generally accepted in the United States of America requires management to make est i mates and assumptions that affect the reported amounts of assets and li abilit i es and disclosure of cont in gent assets and liab i lities at the date of the financial statements and the reported amounts of revenues and expenses dur i ng the reporting period. Actual results could differ from those est i mates. P. Recent Accounting Pronouncements

-GASB Statement No. 85 , Omnibus 2017 , was i ssued in March 2017. This Statement addresses practice issues that were identified during implementation and application of certain GASB statements i ncluding statemen t s on OPEB. This Statement provides clarificat i on for the presentation of payroll-related measures in requ i red supp l ementary information for purposes of reporting by OPEB plans and emp l oyers that provide OPEB. This Statement requires the disclosure of covered-employee payroll by the emp l oyer if contributions to the O P EB plan are not based on a measure of pay. Covered-employee payroll is defined as the payroll of emp l oyees that are prov i ded w it h OPEB through the OPEB plan. However , t he financial statements for the OPEB p l an shou l d not present any measure of payroll if contr i butions to the plan are not based on a measure of pay. This Statemen t i s effective for fiscal years beginning after June 15 , 2017. The District adopted this Statement in 2017 to coincide with its i mplementation of re l ated gu i dance in GASB Statement No. 7 5 , Accounting and Financ i al Reporting for Postemployment Benefits Other Than Pens i ons. The OPEB guidance was the only port i on of this Statement with an impact on the District.

Financ i a l Repo rt 36 GASB Statement No. 84 , Fiduciary Activities , was issued in Ja nuary 2017. Th i s Statement addresses account ing and financ i al reporting requirements for certain fiduc i a ry funds i n the basic financial statements. Governments with activ i ties meeting the criteria are required to p resent a statement of fiduciary net position and a statemen t of changes in fiduciary net position.

The requirements of this Statement are effective for reporting per i ods beginn ing afte r December 15 , 2018. The im p l ementat ion of this Statement will require the District to incl ude fiduc iary statements with the statements for its business-type activities. GASB Statement No. 83 , Certain Asset Retirement Obligations , was iss ued in November 2016. This Statemen t addresses accounting and financial reporting requirements for certain AROs. This Statement imposes requirements in regards to the ARO liability recogn i tion , measurement and specifics on when re-measurement should occur. This Statement a l so requires disclosures regarding the methods and assu mpti ons used to estimate the ARO , the remaining useful life of capital assets associated with the liabi l i ty , any governmenta l legal fund i ng requirements , any assets restricted for payment and any minority share ARO liab il i ty. The requirements o f this Statement are effective for reporting periods beginning after June 15 , 2018. The implemen tati on of th is State ment will impact the District's financial statements. The Distr i ct has reported AROs under the FASB guidance , which differs from the GASB gu i dance. The FASB guidance requires measurement of the liabil ity based o n the prese nt value of the asset's disposal costs whereas measurement under this GASB Statement is based on the best estimate of the current value of cash outlays expected to be incurred. The FASB guidance required the recogn i tion of a corresponding capital asset whereas the GASB State ment requires the recogn iti on of a corresponding deferred outflow of resources. The Dis trict uses regulat ory accounting for AROs under the FASS guidance and plans to continue to u se regu lat ory accounting under the GASS guidance. GASB Statement No. 75 , Accounting and Financial Reporting for Postemployment Benefits Other Than Pens ions , was issued in June 2015. The requirements of this Statement will i mprove 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 t hat i s attributed to those employees' past periods of service (total OPEB liability), less the amount of the OPES plan's fiduc iary ne t position. Enhanced disclosures and additional required supplementary information are also required under the Sta te ment. 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 per i od in which they are recovered in rates. Additional disc l osures related to OPEB are i n Note 11. 2. CASH AND INVESTMENTS

Investments are recorded at fair value with the changes in the fai r value of inve stments reported as Investmen t income i n the accompanying Statemen t s of Revenues , Expenses , and Changes in Net Position. The District had an unrealized net gain of less than $0.1 m i llion for the year ended December 31 , 2016 and an unrealized net loss of $1.2 million for the year ended December 31 , 2015. The fair va lue of all cash and i nvestments , regardless of classification on the Balance Sheets , were as follows at Decem ber 31 (in OOO's): Fair Value U.S. Treasury and go\emment agency securities . $ 936 , 317 Corporate bonds . .. .. . .. . . .. .. . .. . . . . . . . . . . . .. . . .. .. .. . . . .. .. . . . 181,438 Municipal bonds . . . . . . . . . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 , 901 Cash and cash equivalents

................................. 129 , 261 Total cash and in'.estments

........................... $1 , 258 , 917 Portfolio weighted a\erage maturity ................................... . 2016 Weighted A\*rage Maturity (Years) 4.0 9.6 12.4 4.5 2015 Weighted A\*rage Fair Value Maturity (Years) $ 909 , 449 3.7 196 , 766 11.8 10 , 184 15.6 108,054 $1 , 224,453 4.8 Interest Rate Risk-The investment strategy for all investments , except for the decommissioning funds , is to buy and hold securities until maturity , which minimizes interest rate ris k. The investment strategy for decommissioning 3 7 Financ i al Report funds is to active ly manage the diversificat i on of multiple asset classes to achieve a rate of return equal to or exceeding the rate used in the decommissioning funding plan model assumptions. Accordingly , securities are bought and sold pr i or to maturity to inc rease opportunities for higher investment returns. Credit R i sk-The District follows a Board-approved Investment Policy. This policy compl i es with state and federa l laws , and the Resolut i on's provisions govern i ng the investment of all funds. The major i ty of investment s are direct obliga ti ons of , or ob li gations guaranteed by , the Un i ted States of Amer ica. Other investments are limited to investment-grade fixed income obligations. Custodial Credit Risk-Cash deposits , pr i marily interest bearing , are covered by federal depos i tory insurance , pledged collateral consisting of U.S. Government Securit i es held by various depos i tor i es , or an irrevocable , nontransferable , unconditional lett er of credit is sued by a Federa l Home Loan Bank. The fair values of the D i str ict's Revenue and Special Purpose Funds as of De cember 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 fo r the Revenue funds i ncluded cash equivalents of $20.9 million and $6.9 million as of December 31 , 2016 and 2015 , respect iv ely. Re..enue funds -Cash and cash equ i valents ......................

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

............... $ Re..en u e funds -ln..es t ments ........................................................

................ . $ 2016 123 , 678 352 , 382 476 , 060 2015 $ 91 , 948 393 , 538 $ 485,486 The Constr uction funds are used for capital i mprovements , additions , and betterments to and extensions of the Distric t's system. The sources of monies for deposits to the construct ion funds are from revenue bond proceeds and issuance of short-term debt. 2016 2015 Construc ti on funds -Cash and cash equ i valents . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 25 $ Construct i on funds -ln..estments . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . .

.. .. . . . . . . . . . . . . . . . . . . 106 , 179 76 , 503 $ 106 , 204 $ 76 , 503 Financial Report 3 8 The Debt reserve funds , as es t ablished under the Resolut i on , cons i st of a Primary account and a Secondary account. The District is requ i red by the Resolution to ma i ntain an amount equal to 50% of the maximum amount of interes t accrued i n the current or any future year in t h e Pr i mary accoun t. Such amount totaled $38.7 m illi on and $40.5 m i llion as of December 31 , 2016 and 2015 , respect i vely. The Secondary account can be established at such amounts and can be utilized for any lawf u l purpose as determ i ned by the District's Board. Such accoun t tota l ed $51.3 m ill ion and $5 1.3 mil l ion as of December 31 , 2016 and 2015 , respectively. 2016 Debt reser\* funds -Cash and cash equivalents . . . . . . . . . . . . . . . . ... . .. .. . . . . . . . . . . . . . . . . . . . . . $ Debt reser\* funds -ln\estments

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

.............. . 90 , 032 $ 90 , 032 $ $ 2015 50 91 , 722 91 , 772 The Emp l oyee Benefit funds consist of a se l f-funded hospital-medical bene fi t plan for active employees only at December 31 , 2016. The employee benefit funds consist of both a self-funded hospital-medical benefit plan (for active and inactive employees) and a ret i red employee life insurance benefit plan at December 31 , 2015. The District pays 80% of the hosp i tal-medical premiums with the emp l oyees pay i ng the rema i ning 20% of the cost of such coverage. The self-funded hospita l-med i cal benefit plan had funds of $4.9 m i ll i on and $2.3 million at December 31 , 20 1 6 and 2015 , respective l y. The retire d employee l ife insurance benefit p l an is funded by an i rrevocab l e OPES T r ust. Commenc i ng with the implementation of GASS 75 i n 2016 , the Trust assets for inactive employees are reported in t he fiduciary fi nancial statements for the OPES Trust i nstead of in the Employee benefit f u nds. The r e was $1.1 m i l li on of OPES assets r eported i n Emp l oyee bene fit funds at December 31 , 2015. For add iti onal i nfor m a ti o n on OPES see Note 11. 2016 Emp l oyee benefit funds -Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1 , 843 Employee benefit funds -ln\estments

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

....................................... 3 , 008 -$---4-, 8-5_1_ $ $ 2015 1 , 349 1 , 995 3,344 The Decommissioning funds are ut i lized to account for the i nvestments held to fund the estimated cost of decomm i ss i oning CNS when its operating li cense exp i res. The Decomm i ssioning funds are held by outside trustees or custod i ans i n comp l iance w i th the decomm i ssioning funding plans approved by the Board which are i nvested pr i marily i n fi x ed income governmenta l secur i ties. 2016 2015 Decomm i ssion i ng funds -Cash and cash equivalents

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

...........

.............. $ 3 , 715 $ 14 , 707 Decom mi ssion i ng funds -ln\estments

........................................................... 552 , 641 $ 567 , 348 3. FA I R VALUE OF FINANCIAL INSTRUMENTS

Fa i r va l ue is the exchange pr i ce that would be received to sell an asset or paid to transfer a liabil i ty (an ex i t price) i n the pr i ncipal or most advantageous market for the asset or l iabil i ty in an orderly transaction between market part i cipants at the measurement date. GASS Statement No. 72 (" GASS 72"), Fa i r Value Measurement and Applicat i on , establ i shes a fa i r value hierarchy that prior i t i zes the inputs used to measure fa i r value. T h e hierarchy gives the h i ghest priority to unadjusted quoted pr i ces in an act i ve market for ident i cal assets or liabilit i es and the lowest priority to unobservable inputs. Financ i al assets and liabilities are class i fied i n their entirety based on the lowest level of i nput that is significant to the fair value measurement.

The three levels of fair value h i erarchy defined i n GASS 72 are as follows: Level 1 -Quoted prices are ava i lable in active markets for identical assets or liabilities as of the reporting date. Active markets are those in wh i ch transactions for the asset or liabil i ty occur in sufficient frequency and volume to 39 Financ i al Report provide pricing i nformation on an ongoing basis. The District's investments i n cash and cash equivalents are included as Level 1 assets. Level 2 -Pric i ng inputs a r e other than quoted market prices in the ac t ive markets inc l uded i n Level 1 , which are either directly or ind i rectly observable for the asset or l i ability as of the reporting da t e. Level 2 inputs include the following:

quoted pr i ces for sim i lar assets or liabi l i ties in active markets;

quoted pr i ces for ident i cal assets or liabi l ities in inactive markets;

inputs other than quoted prices that are observable for the ass e t or liab i lity; or

inputs that are der i ved principally from or corroborated by observable market data by corre l at i on or other means. Leve l 2 assets primarily include U.S. Treasury and government agency securities held in the Revenue funds and other Special Purpose Funds and U.S. Treasury and government agency securities , co r porate bonds , and m un i cipa l bonds held in the Decom m issioning funds. Level 3 -Pr i cing inputs include sign i ficant inp u ts that are u nobserva b le and cannot be corroborated b y m arket data. Level 3 assets a n d l i ab i lities a re valued based o n intern a lly developed models and a s sumpti o ns or methodologies using significant unobservable inputs. The District cur r ently does not have a n y Level 3 assets or liabil i ties. The Distr i ct performs an analysis annually to determine the appropriate hierarchy level classification of the assets and liab ili ties that are i ncluded w i thin the scope of GASB 72. F i nanci a l assets and liabilities are class i fied in their ent i rety based on the lowest level of i nput that is significant to the fair value measurement.

There were no liabilities within the scope of GASB 72 as of December 31 , 2016 and 2015. The fo ll ow i ng tables set forth the Dis t rict's financia l assets t hat are accounted for and reported at fair value on a recurring basis by level within the fair v a lue hierarchy as of D ecember 31 , (in OOO's): Le1A31 1 Assets: Re1A3nue and spec i a l purpose funds , exclud i ng decomm i ss i on i ng: U.S. Treasury and go\A3mment agency securit i es ............ $ Cash and cash equivalents

........................................... . 125 , 546 Decommiss i on i ng funds: U.S. Treasury and go\A3mment agency securit i es ........... . Corporate bonds .......................................................... . Munic i pa l bonds .......................................

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

.... . Cash and cash equivalents

............................................ -$.,-----3 , 715 129 , 261 Le1A3 1 1 Assets: Re1A3nue and spec i a l purpose funds , excluding decommiss i on i ng: U.S. Treasury and go\A3mment agenc y securit i es ............ $ Cash and c ash equivalents

........................................... . 93 , 347 Decommiss i on i ng fu n ds: U.S. Treas u ry and go\A3rnment agency secur i t i es ........... . Corporate bonds .......................................................... . Munic i pal bonds ....................

...................................... . Cash and cash equivalents

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

-$_,-----14 , 707 108 , 054 2016 Le1A31 2 $ 551 , 602 $ 384 , 7 15 1 81 , 438 11 , 901 $1 , 129 , 656 $ 2015 Le1A31 2 $ 563 , 758 $ 345 , 691 196 , 766 10 , 184 $1 , 116 , 399 $ Le1A31 3 Le1A31 3 Tota l $ 551 , 602 125 , 546 384 , 715 181,438 11 , 901 3,715 $ 1 , 258 , 917 Tota l $ 563 , 758 93 , 347 345 , 691 196 , 766 10 , 184 14,707 $ 1 , 224 , 453 F i nancial Report 4 0

4. UTILITY PLANT: Ut i lity plant activity for the year ended December 31 , 2016 , was as follows (i n OOO's ): December 31 , December 3 1 , 2015 Increases Decreases 2016 Nondepreciable ut i lity plant: Land and impro..ements

.............................. $ 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 , 0 1 7 (254 , 022) 209 , 99 1 Nuclear fue l* .................................................. 168,420 70 , 064 (40 , 754) 197,730 Deprec i able utility plant: Generat i on -Fossil .................................... 1 , 573 , 880 65 , 818 (10 ,1 03) 1 , 629 , 595 Generat i on -Nuclear ..................................

1 , 384 , 031 68 , 4 1 5 (10,481) 1 , 441 , 965 Transmission

............................................. 1 , 172 , 108 86 , 994 (4 , 682) 1 , 254,420 D i st ri bution ................................................ 221 , 791 6 , 336 (1 , 564) 226 , 563 Genera l ...............

...................................... 334 , 836 13 , 528 (3 , 786) 344 , 578 Tota l depreciable utility p l ant 4 , 686 , 646 241 , 091 (30 , 616) 4 , 897 , 121 Less reserve for depreciation

........................... (2 , 620 , 091) (118 , 561) 30 , 616 (2 , 708 , 036) Depreciable utility plant , ne t ................... 2 , 066 , 555 122 , 530 2 , 189,085 Utility plant act i-.ity , net ................................... $ 2 , 508 , 971 $ 382 , 6 1 1 $ (294 , 776) $ 2 , 596 , 806

l\llclear f ue l de c reases represent e d arrortization of $40.8 nillion. Ut i lity plan t act i vity for the year ended December 31 , 2015 , was as follows (in OOO's): December 31, December 31 , 2014 Increases Decreases 2015 Nondepreciable utility plant: Land and impro-.ements

.............................. $ 63 , 336 $ 1 , 036 $ (2) $ 64 , 370 Construction in progress ............................. 151 , 7 1 2 180 , 117 (122 , 203) 209 , 626 Total nondepreciable util i ty plant ............. 215 , 048 181 , 153 (12.2 , 205) 273 , 996 Nuclear fuel* .................................................. 202 , 094 13 , 952 (47 , 626) 168 , 420 Deprec i able ut i l i ty plan t: Generat i on -Fossil .................................... 1 , 550 , 786 31 , 495 (8 , 401) 1 , 573 , 880 Generat i on -Nuclear ..............

.................... 1 , 353 , 374 31 , 240 (583) 1 , 384 , 031 Transmission

............................................. 1 , 153,704 26 , 147 (7 , 743) 1 , 172,108 Distribution

................................................ 217 , 893 6,877 (2 , 979) 221 , 791 General .....................

................................ 335,407 14 , 487 (15 , 058) 334 , 836 Total deprec i able utility plan t 4 , 611 , 164 110 , 246 (34 , 764) 4 , 686 , 646 Less reserve for depreciation

........................... (.2 , 533 , 100) (121 , 755) 34,764 (2 , 620 , 091) Deprec i able ut i l i ty plant , n et ................... 2 , 078 , 064 (11 , 509) 2 , 066 , 555 Utility plant activity , net ................................... $ 2,495 , 206 $ 183 , 596 $ (169 , 831) $ 2 , 508 , 971 *Nu c l e ar fuel d ecre as e s re p r es e nted arrort iz ation o f $47.6 ni llion. 41 Financial Report

5. LONG-TERM CAPACITY CONTRACTS: Long-term capacity contracts include the D i strict's share of the construc ti on costs of Omaha Pub l i c Power Distr ict's (" OPPD") 663 megawatt (" MW") Nebraska C i ty Station Un it 2 (" NC2") coal-fired power plant. The Dis t r ic t has a part ic ipat i on power ag re emen t with OPPD for a 23.7% share of the power from this plant. NC2 began commerc i al ope r at ion on May 1 , 2009 , a t which time the Dist rict began amortizing the amount of the capac i ty contract associated with the p l ant on a st r aight-line basis ove r the 40-yea r estimated useful li fe of the plan t. Accu m u l a t ed amort i zation was $35.4 m illi o n and $30.8 mill i on in 2016 and 2015 , respect i vely. The unamortized amount of the plan t capacity contract was $14 3.7 m i llion and $154.8 m i llion as of December 31 , 2016 and 2015 , r espectively , of which $4.4 million was i ncluded in Prepayments and othe r current assets as of December 31 , 2016 and $4.6 m i ll ion in 2015. The Distr ict's share of NC2 work i ng capital was also i ncl u ded in Prepayments and other current assets and was $6.5 million as of December 31 , 2016. Long-term capacity contracts a l so include the Distr i ct's purchase of the capacity of a 50 MW hydroelectr ic generat in g facility owned and opera t ed by The Central Nebraska Public Power and I rrigat i on Distr i ct (" Centra l"). The District is amort i zing the contract on a st r aight-line basis over the 40-year estimated use f ul life of the facility. Accumu l ated amortization was $64.3 m i ll i on and $62.0 million at December 31 , 2016 and 2015 , respect i vely. The unamort iz ed amou nt of the Central capac ity contract was $22.4 million and $24.7 million at December 31 , 20 1 6 and 2015 , r espect i vely, of which $2.3 million was in cluded in Prepaymen t s and other current assets as of December 31 , 2016 and 2015. The D i st ri ct has an agreement whereby Central makes avai l able all the production of the facil i ty and the Dis t rict pays a ll costs of opera ti ng and maintain i ng the facility plus a charge based on the amount of energy delivered to the Distr ict. Costs of $2.5 mill ion and $2.3 m ill ion i n 20 1 6 and 2015 , respectively , are i ncluded i n Power purchased i n the accompany in g Statemen t s of Revenues , Expenses , and Changes i n Net Position. 6. I NVESTMENT IN THE ENERGY AUTHORITY: The D i str i ct has an investment i n The Energy Authority

(" TEA"), a nonprofit corporation headquartered in Jacksonv ill e , Florida , and incorporated in Georgia. TEA provides public power utilities access to dedica ted resources and advanced technology systems. The D i strict's interest in TEA was 16.67% as of Decembe r 31 , 2016 and 2015 , respectively. In add i t i on to the District , the following u t ilities have interests o f 16.67% each as of December 31 , 2016 and 2015: American Mun i cipal Power , Inc.; JEA (Florida); Municipal Energy Authority of Georgia; and South Carol i na Public Serv i ce Authority (a.k.a. Santee Cooper). The following utilities have interests in TEA of 5.56% each as of December 3 1 , 2016 and 2015: C i ty Uti l ities of Springfield , Missour i; Cowlitz County Pub l ic Utility Distr i ct (Washington) and Gainesv i lle Regional Utilit i es (Florida).

Such investment was $6.4 m illi on and $7.0 million as of December 31 , 2016 and 2015 , respectively. TEA's revenues and costs are allocated to members pursuant to Settlement Procedures under the Operat ing Agreemen t. TEA prov i des the District gas contract managemen t serv i ces and is the D i strict's market partic i pant in SPP's Integrated Market. The D i strict is obligated to guaranty , d ir ec t ly or indirectly , TEA's e l ectric trading activ i ties in an amount up to $28.9 million p l us attorney's fees which any party cla i m in g and prevailing under the guaranty migh t incur and be ent i t l ed to recover under i ts contract with TEA. Gene r ally , the Distr i ct's guaranty obligat i ons for e l ectric trad in g would ar i se i f TEA did not make the contractually required payment for energy , capa ci ty , or transm i ss i on wh ic h was delivered or made available or i f TEA failed to deliver or prov i de energy , capacity , or transmission as required under a contract.

The Distr ict's exposure relating t o TEA i s lim i ted to the D i st r ict's investment in TEA , any accounts receivable from TEA , and trade guarantees provided to TEA by the Distr i ct. Upon the Dis t r ict mak i ng any payments under i ts e l ectric guaranty , it has certain contribution ri ghts with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratab l y , based upon each member's interest in TEA. A ft er such contributions have been effected , the District would only have recourse against TEA to recover amounts paid under the guaranty. The term of th is guaranty is generally indefinite , but the District has the ability to term i nate i ts guaranty ob l igations by caus in g to be prov i ded advance notice to the beneficiar i es thereof. Such Financial Report 42 terminat i on of its guaranty obligations only applies to TEA transactions not yet entered into at the t i me the termina ti on takes effect. The D i strict has no li abilities for these guarantees as of December 31 , 2016 and 2015. Financial statements for TEA m ay be obtained at The Energy Author i ty , 301 W. Bay Street , Suite 2600 , Jacksonvi ll e , Florida , 32202. 7. DEBT: The fo ll ow i ng table summarizes the debt balances , net of current maturities , as of December 31 , 2016 and 2015 , and act i v i ty for 2016 (i n OOO's ): Princ i pa l Amounts Due December 31 , December 31 , With i n One 2015 I n creases Decreases 2016 Year Re-..enue bonds ................

......... $ 1 , 596 , 972 $ 354 , 776 $ (272 , 905) $ 1 , 678 , 844 $ 81 , 250 Commerc i al paper notes ..........

.. 83 , 000 88 , 365 (97 , 365) 74 , 000 74 , 000 Re\011.ing cred i t agreements

....... 158 , 700 75 , 443 (45 , 219) 188 , 924 Tota l long-term debt actil.ity

.. $ 1 , 838 , 672 $ 5 1 8 , 584 $ (415 , 489) $ 1 , 94 1 , 768 $ 155 , 250 The follow i ng table summarizes the debt balances , net of current maturities , as of December 31 , 2015 and 2014 , and act i v i ty for 2015 (i n OOO's): Principal Amounts Due December 31 , December 31 , W i th i n One 2014 I ncreases Decreases 2015 Year Re-..enue bonds ......................... $ 1,710 , 850 $ 261 , 1 89 $ (375 , 067) $ 1 , 596 , 972 $ 114 , 860 Commerc i al paper notes ............ 92 , 000 (9 , 000) 83 , 000 Re\UllAng credit agreements

....... 185 , 503 10 , 364 (37 , 167) 158 , 700 Total long-term debt act i'vity .. $ 1 , 988 , 353 $ 271 , 553 $ (421 , 234) $ 1 , 838 , 672 $ 114,860 Revenue Bonds In Apri l 2017 , the D i st r ict issued General Revenue Bonds , 2017 Series A and 2017 Series B , in the amount of $86.0 mill i on to refund the General Revenue Bonds , 2007 Series B. T he refunding reduced total debt service payme n ts over the life of the bonds by $1 1.8 m i llion , which resu l ted i n present value savings of $10.0 million. The District plans to i ssue additional revenue bonds i n 2017 to finance transmission projects. Also in Apr i l 2017 , the Distr i ct entered i nto an escrow deposit agreement in conjunct i on with the refunding of certain of the:

General Revenue Bonds , 2007 Series B , having maturity dates ranging from January 1 , 2018 through January 1 , 2028 I n November 2016 , the Distr i ct issued General Revenue Bonds , 2016 Series C and 2016 Series D , i n the amou n t of $113.5 m i llion to finance the costs of certain generat i on and transmiss i on capital projects and to refund a portion of Commercial Paper Notes , Series A. The District also issued in November 2016 , General Revenue Bonds , 2016 Ser i es 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 D i strict issued Genera l Revenue Bonds , 2016 Series A and 2016 Series B , in the amount of $139.2 mill i on to advance refund $138.9 million of bonds and refund $16.5 m i llion of commercial paper notes. The refunding reduced total debt service payments over the life of the bonds by $29.8 million , which resulted i n presen t value savings of $20.8 million. 43 F i nan cial Repo rt Also in February 2016 , the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:

General Revenue B onds , 2007 Series B , having maturity da t es ranging from January 1, 20 2 6 through January 1 , 2037

General Revenue B onds , 2008 Series B , hav i ng maturity dates ranging from January 1 , 2024 through January 1 , 2041

General Revenue Bonds , 2012 Series C , maturing on January 1 , 2025 through January1 , 2026. In January 2016 , the D istrict issued TECP in the amount of $43.6 mi l lion to refund a portion of t h e General Revenue Bonds, 2005 Series C and the Genera l Revenue Bonds , 2006 Series A. In February 2015, the District issued General Revenue Bonds , 2015 S eries A , in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $42.0 m i llion , which resu l ted i n present value savings of $26.1 million. Also in February 2015 , the District entered into an escrow deposit agreement in c o njunct i on with the advanced re f unding of certain of the:

Genera l Revenue Bonds , 2005 Series C , having matur i ty dates r ang i ng from January 1 , 2026 t h rough January 1 , 2041

General Revenue Bonds , 2006 Series A , having maturity dates ranging from January 1 , 2036 through January 1 , 2041 , and

Genera l Revenue B onds , 2007 Series B , having maturity da t es ranging from January 1 , 20 2 3 t h rough January 1 , 2037

General Revenue Bonds , 2008 Series B , having maturity dates ranging from January 1 , 2024 through January 1 , 2038 , and

Gene r a l Revenue Bonds , 2012 Series C , maturing on January 1 , 2024 Certain of t he General Revenue Bo nds , from the following series, with ou t standing pri n cipal amo u n t s that aggregate

$407 .9 million as of Dece m ber 31 , 2016 , were lega ll y defeased and a re no longer outstanding

2007 Series B , 2008 Series B , and 2012 Series C. Debt service payments and principal payments of the General Revenue Bonds as of December 31 , 2016 , are as follows (in OOO's): D ebt Se r'..i ce P rinc i pal Year Payments Payments 2017 ....................

........................ $ 158 , 295 $ 81 , 250 2018 .........................

................... 173 , 151 100 , 010 2019 ************

- - - - 149 , 606 81 , 205 2020 .............

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

149 , 511 84 , 895 2021 **********

- - - - 147 , 300 86 , 745 2022-2026

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

....... 674 , 038 431 , 990 2027-2031

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

....... 500 , 115 355,470 2032-2036

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

....... 326 , 864 261 , 965 2037-2041

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

............... 117 , 854 98 , 355 2042-2045

.................................... 32,469 30 , 030 Tota l Payments ...........

................. $ 2,429 , 203 $ 1 ,611 , 915 The fair value of outstanding revenue bonds was determined using currently published rates. T he fair value was estima t ed to be $1 , 750.1 million and $1 ,765.4 million at December 31, 2016 and 2015 , respectively. Financial Report 44 Commercial Paper Notes The D i str ic t i s authorized to issue up to $150.0 million of TECP notes. A $150.0 million l i ne of credit expiring July 1 , 2017 , i s maintained with two commercial banks to support the sale of the T ECP notes. The Distr i c t had $74.0 million and $83.0 million of TECP notes outs t anding a t December 31 , 2016 and 2015 , respectively. The proceeds of the TECP notes have been used to prov i de short-term financ i ng for certain capital add iti ons and fo r other lawful purposes of the D i strict. The effective int erest rate on outstand in g TECP notes was 0.46% and 0.06% for 2016 and 2015 , respectively. The notes outstanding are ant ici pated to be retired by future collections through electr ic rates and the i ssuance of revenue bonds or other debt. The carry ing value of the commerc i al paper notes approx imat es ma rk et value due to the short-t erm nature of the notes. Line of Credit Agreement The Distr i ct has a li ne of credit of $150.0 mi lli on expir i ng Ju ly 1 , 20 17 , that supports the payment of the principal outstand in g of t h e TECP notes. No amounts were drawn on the lin e of cred it as of December 31 , 2016 and 2015. Taxable Revolving Cred it Agreement The Distr i ct has entered into a Taxable Revolv in g Cred i t Agreement

("TRCA") with two commercial banks to provide for loan comm i tments to the District up to an aggregate amount not to exceed $200.0 m i ll ion. The TRCA allows the District to i ncrease the loan commitments to $300.0 m i llion. The Distr i ct had outstanding balances under the TRCA of $188.9 million and $1 58.7 m i llion , at December 31 , 2016 and 2015 , r espective l y. The TRCA was renewed on July 31 , 2015 and terminates on Ju ly 30 , 2018. The outstanding amount i s anticipated to be retired by future collections th r ough e l ectr i c rates and the i ssuance of revenue bonds. The carry i ng value of the revolving cred it agreements approximates market value d u e to the short-term nature of the agreements. 45 Financial Report 1-------------*----Re-.enue bonds consis t of the following(i n OOO's except in terest rates): December 3 1, Interest R ate 2016 General Re-.enue Bonds: 2005 Series C: Seria l Bonds: 20 1 6-2025 , 204 0 ..................... 3.875% -5.00% $ 2006 Series A: Seria l Bonds: 2036-2040

............................. . 2007 Series B: Serial Bonds: 2016-2026

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

............... . Term Bonds: 2027-2031 ............................. . 2032-2036 ............................. . 2008 Series B: Serial Bonds: 2016-2029

............................. . Term Bonds: 2030-2032

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

............. . 2033-2037

............................. . 2038-2040

- - - - 2009 Series A Taxab l e Build America B onds: Term Bonds: 2019-2025

............................. . 2026-2034

- - - - 2009 Series C Seria l Bonds 20 1 6-2019 .................. . 20 1 0 Series A Taxab l e Build America B onds: Serial Bonds: 2019-2024

............................. . Term Bonds: 2025-2029

............................. . 2030-2042

- - - - 20 1 0 Se ri es B T axable Serial Bonds 2016-2020

...... . 2010 Series C: Seria l Bon d s: 2016-2025

............................. . Term Bonds: 2026-2030

............................. . 2026-2030

- - - - 2011 Series A Seria l Bonds 2016-2016

.................. . 20 1 2 Series A Seria l Bonds 2016-2034

...........

....... . 2012 Series B: Serial Bonds: 2016-2032

...........

.................. . Term Bo n ds: 2033-2036

............................. . 2037-2042 ******************************

2012 Series C Serial Bonds 2016-2028

.................. . 2013 Series A Serial Bonds 2016-2033

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

.... . 20 1 4 Series A: Serial Bonds: 2016-2038

............................. . Term Bonds: 2039-2043

............................. . 2039-2 0 43 ..................

........... . 2014 Series C Seria l Bonds 2016 -2033 ................. . 2015 Se ri es A-1 Serial Bonds 2022-2034

............... . 2015 Series A-2: ..............................................

..... . Serial Bonds: 2016-2034

............................. . Term Bo n ds: 2035-2039

............................. . 2016 Series A: ............

......................................... . Serial Bonds: 2018-2035

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

........... . Term Bonds: 2036-2040

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

............ . 2016 Series B: .................................................... . 4.375% 4.375% -5.00% 4.65% 5.00% 4.00% -5.00% 5.00% 5.00% 5.00% 6.606% 7.399% 3.50% -4.25% 3.98% -4.73% 5.323% 5.423% 2.858% -4.18% 3.00% -5.00% 4.00% 5.00% 2.50% -5.00% 3.00% -5.00% 2.00% -5.00% 3.625% 3.625% 3.00% -5.00% 3.00% -5.00% 2.00% -5.00% 4.00% 4.125% 3.00% -5.00% 3.00% -5.00% 3.00% -5.00% 5.00% 3.125% -5.00% 5.00% 5.00% 5.00% 3.00% -5.00% 2.00% -5.00% 5.00% 5.00% 2.337% -3.567% 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 , 180 190,410 92 , 320 2 , 320 4 , 155 11 , 045 91 , 100 153 , 630 31 , 650 1 , 945 143 , 025 1 1 9,400 56 , 485 46 , 205 65 , 210 5 , 595 67 , 255 1 , 165 70,685 $ 2015 44 , 230 400 111 , 825 31 , 190 7 , 120 38 , 785 22 , 860 40 , 375 7 , 180 17 , 465 32 , 890 6 , 595 31 , 875 27 , 985 54 , 190 4 , 4 1 5 64 , 520 6 , 165 14 , 180 7 , 115 198 , 310 95 , 875 2 , 320 4 , 155 37 , 340 103 , 815 156 , 145 31 , 650 1 , 945 1 62 , 415 119,400 56 , 9 1 5 46 , 205 1 , 587 , 850 123 , 982 1,711 , 832 (114 , 860) $1 , 596 , 972 Financ i al Report 46

8. PAYMENTS IN LIEU OF TAXES: The District is required to make payments in lieu of taxes , aggregating 5% of the gross revenue der i ved from e l ectric retail sales within the city limits of incorporated cities and towns served directly by the District.

Such payments totaled $10.1 mill i on and $10.0 million for each of the years ended December 31 , 2016 and 20 1 5 , respectively. 9. ASSET RETIREMENT OBLIGAT I ONS: Asset retirement obligations

(" ARO") are ca l culated at t he present value of a long-lived asset's applicable disposa l costs and are recorded i n the per i od in which the liability is incurred.

This liability is accreted during the rema i n i ng life of the associated assets and adjusted period i ca lly based upon updated estimates. The D is tr ict has recorded an obl i gat i on for the fair value of i ts legal liability fo r the ARO associated with CNS , Ainsworth W i nd Ene rgy Facility , various ash landfills at coal-fired power stations , remova l of asbestos at the various coal , gas , and hydro generating facil iti es , polychlor in ated biphenyls from substation and distr i bution equ i pment, and underground storage tanks as well as abandonment of water wells. Studies were completed for the ARO for the Ainsworth Wind Energy Facility and CNS in 2016 and 2015 , respectively. The ARO adjustment for 2016 was due primar ily to the addition of a liability fo r the A i nsworth Wind Energy Facil i ty , that was more than offset by a reduction in liabilit i es for asset reti r ements. The ARO reduction of $4 77 .8 m illi on for 20 1 5 was due pr i marily to the updated 2015 study and refreshed assumptions for CNS. ASC 410 , Asset Retirement and Environmental Obligations. requ ir es capitalization of the costs to the related asset and deprec i ation of these costs over the same period as the related asset. The D istrict does not use deprecia ti on as a cost component for rates. Accord i ngly , the D i strict has established a regulatory asset , under account i ng gu i dance i n Re10 , for the costs that will be recovered i n future rates. A significant amount of the ARO was funded by decommissioning funds of $581.8 million and $567.3 m illion as of December 31 , 20 1 6 and 2015 , respect i vely. See Note 2 for add i tional information. The following table shows changes to the ARO that occurred during the years ended December 31 , 2016 and 2015 , and are i ncluded in Other l ong-term liabilities section of the accompanying Balance Sheets as of December 31 , (in OOO's): 2016 2015 Balance , beginning of year .............

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

................................................ . $ 600 , 311 $ 1 , 026 , 357 Accret i on ............

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

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

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

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

.......... . 28 , 902 51 , 764 ARO adjustment

........................................................................................... . (1 , 506) (477 , 810) Balance , end of year .............................

......................................................... $ 627 , 707 $ 600 , 311 10. RETIREMENT PLAN: The D istrict's Employees' Ret irement Plan (the " Plan") is a defined contribution 401 (k) pension plan established and adm i n i stered by the District to prov i de benefits at retiremen t to regular full-time and part-time employees. There were 1 , 931 and 1 , 955 act i ve plan members at December 31 , 2016 and 2015 , respectively. Plan prov i sions and contr i bution req ui rements are established and may be amended by the Board. Plan members are eligible to begin part icipation in the Plan immediately upon hire. Contr i but i ons rang ing from 2% to 5% of base pay are elig i ble for Distr i ct match i ng dollars after six months of emp l oyment. The Dist ri ct contributes two times the Plan memb er's contribut ion based on cover ed salary up to $40 , 000. On covered salary greater than $40 , 000 , the Distr i ct contributes one t i mes the Plan member's contribution. The Participants

' contribut i ons were $13.4 million and $12.8 million for 2016 and 2015 , respectively. The D istrict's match i ng contributions were $12.3 million and $12.1 million for 2016 and 2015 , respectively. Total contributions of $1.4 million were accrued i n Accounts payable and accrued liabilities as of Decembe r 31 , 2016 and 2015. 4 7 Financial Report Plan members are i mmediately vested in the i r own contributions and earn i ngs and become vested in the Distr i ct's contr i bu ti ons and earnings based on the following vesting schedule:

Years of Vesting Participat i on 5 years or more ................................... . 4 years ......................

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

........ . 3 years ...............

................................ . 2 years .....................

.......................... . Less than 2 years ............................... . Percent 100% 75% 50% 25% 0% Nonvested Distr i ct contributions are first used to cover Plan admin i s t rative expenses and any remain i ng forfeitures are allocated back to Plan part i c i pants. Employees may also contribute to a defined contribution 457 pension plan (" 457 Plan"). The 457 Plan is a deferred investment option w i th no District match. Pay period contributions can be elected and changed at any time. Early withdrawals can be made from the 457 Plan following separat i on of service regardless of age with no IRS penalty. Income taxes are owed on any withdrawals. The Partic i pants' contributions were $2.1 m i llion a n d $2.0 mill i on for 2016 and 2015 , respect i ve l y. 11. OTHER POSTEMPLOYMENT BENEFITS: The District implemented the prov i sions of GASB Statement No. 75 (" GASB 75"), Accounting and Financial Reporting for Postemployment Benefits Other than Pensions , in 2016. The District has elected to early adopt the provisions of GASB 75. GASB 75 requires retroactive application unless it is impractical to apply the r e quirements on a retrospective basis. The District has concluded that retrospective application is impr a ctical b a sed on a cosUbenefit analysis and other consi de rations. The District would incur additional third-party a ctuari a l costs to develo p the n e cessary d a ta for ret rospe c t ive ap p licatio n. A dditio n ally, g iven the D istrict's ap pl icat i on o f re gulatory acc o unting , the impact of applyin g p rovisions of G A SB 75 to p r i o r periods wou l d be entirely off se t b y the recognition of a regulatory asset re fl ecting the future recovery of any OPEB costs. Accordingly , r e trospective application of GASB 75 would not impact the District's net position for 2015. Further , there was no impact to beg i nn ing net posit i on as a result of the implementation of the prov i sions of GASB 75 i n 2016. A. General informat i on regarding the OPEB Plan -Plan Description The District's Post-Employment Medica l and Life Benefits Plan (" Plan") provides postemployment hosp i tamedical and life insurance benefits to qualifying retirees , surv i ving spouses , and employees on long-term disability and their dependents. Benefits and re l ated el i gibility , funding and other Plan provisions , for this singleemployer , defined benefit Plan , are authorized by the Board. The Plan has been amended over the years and provides different benefits based on hire date and/or the age of the employee. The D i strict pays all or part of the cost (determined by age) of certain hospital-medical premiums for employees hired on or pr i or to December 31 , 1992. Employees hired on or after January 1 , 1993 , are subject to a contr i bution cap that limits the District's portion of the cost of such coverage to the full premium the year the employee reached age 65 , or the year in which the employee ret i res i f older than age 65. Employees hired on or after January 1 , 1999 , are not eligible for other postemployment hospital-medical benefits once they reach age 65. Emp l oyees hired on or after January 1 , 2004 , are not elig i ble for other postemployment hospital-med i cal 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 elig i ble for othe r postemployment hospital-medical benefits once they retire. In May 2015 , the Board approved a change for Med i care-eligible retirees for prescr i ption drugs from the District's self-insured employee prescr i ption plan to a group insured Medicare Part D supplement effective January 1 , 2016. The D i strict also provides a postemployment death benefit of $5 , 000 for qualify i ng employees. Financial Report 48 Employees Covered by Benefit Terms The following tab l e shows the employees covered by the hospital-medical benefit terms as of January 1: 20 1 6 2015 Acti\* employees

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

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

........................................... . 1 , 175 1 , 205 lnacti\* employees or beneficiaries in retirement status ..............

...... .. 1 , 260 1 , 238 lnacti\* employees or beneficiaries in long-term disability status ....... .. 67 70 Total employees co\*red by benefit terms ..................................... . 2 , 502 2 , 513 The following tab l e shows the employees covered by the life insurance benefit terms as of January 1: 20 1 6 2015 Acti\* employees

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

...... . 2 , 003 1 , 980 lnacti\* employees in retirement status ........................................... . 1,077 1 , 047 lnacti\* employees in long-term disability status ............................... . 74 77 Total employees co\*red by benefit terms ............

........................ .. 3,154 3 , 104 Contributions The Board annually approves the funding for the Plan , which has a min i mum funding requ i rement of the actuar i ally-determined annual required contribution

(" ARC") to ach i eve full funding status on or before December 31 , 2033. The District OPEB contributions were $74.7 million in 2016 , which i nc l uded $45.7 million of financed contribut i ons deposited in the Trust , $24.5 million of revenue funded contr i butions deposited in the Trust and $4.5 million pa i d d i rectly by the Distr i ct for the cost o f benefits/expenses.

Certain wholesale customers under the 2002 Contracts filed for binding arbitration in May 2016 related to their objection of the inclus i on in rates additional collections of previously incurred OPEB costs. Collections from customers of $1.6 million collected under t he 2002 Contracts for these OPEB costs in 2016 were not transferred to the Trust , pending the outcome of the arbitration. Add i tional information about the arbitrat i on i s disclosed in Note 12. The Distr ict contributed

$28.4 million in 2015 , which included $11.5 m i llion deposited i n the Trust and $16.9 mi ll ion paid directly by the D i strict for the cost of benefits/expenses. Total contributions in 2014 were $29.8 mill i on. wh i ch included $11.9 m i llion deposited in the Trust and $17.9 million paid for the cost of benefits/expenses. Contributions from Plan members are the required premium share , which is based on hire date and/or age. Contribut i ons from Plan members were $0.5 million , $0.6 million and $0.5 million for the years ended December 31 , 2016 , 2015 and 2014 , respectively. Me m bers do not contribute to the cost of the life insurance benefits. B. Net OPEB Liability

-The Distr i ct's net OPEB liability was measured as of January 1 , 2016 , and the total OPEB liability used to calculate the net OPEB liability was determined by an ac t uarial valuation as of that date. Actuarial Assumptions The total OPEB liability in the January 1 , 2016 , actuarial valuation was determined using the following actuarial assumptions , applied to all periods included in the measurement , unless otherwise specified:

Actuar i al cost method

Amortization method

Amortization period

Asset valuation method

Discount rate

Healthcare cost trend rates

Inflation

Investment rate of return

Mortality

Retirement age 49 Financial Report Entry Age Normal Level amortization of the unfunded accrued l iability 17-year closed period 5-year smoothed market 6.25% Pre-Medicare

8% initial , ultimate 5% Post-Medicare

6.75% i nitial , ultimate 5% 2.1% 6.25%, net of investment exp e nse , including inflation RP-2014 Aggregate table projected back to 2016 using Scale MP-2014 and projected forward using Scale MP-2015 with generational projection Varies by age The ac tuar ial assumptions used in the J anuary 1 , 2016 , valuat i on were based on the results of an actuar ial experience study for the period January 1 , 2015 through Dece m ber 31 , 20 1 5. The long-term expected rate of return on OPEB plan in vestments was determined using a building-block method in wh ich best-es timate ranges of expected future rates of return (expected returns , net of OPEB plan i nvestment expense and i nflat i on) are developed for each major asset class. These ranges are combined to produce the long-ter m expected rate of return by we i ghting the expected future real rates of return by the target asset alloca t ion pe rcentage and by adding expected i nflation. The target allocation and best est i mates of geometric real rates of return for each major asset class are summar i zed in the following table for the valuation measurement date of January 1 , 2016: Asset Class Long-Term Expected Target Allocat i on Real Rate of Return Equity ......................................... . F ix ed Income ............................... . Discount Rate 68% 32% 100% 6.8% 3.5% The d i scount rate used to measure the total OPEB l i ability was 6.25%. The pro j ection 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 assumptions , the OPEB Plan's fiduciary net pos iti on was pro j ected to be available to make a ll projected benefit payments fo r current active and inact i ve employees. Therefore , the l ongterm expected rate of return on OPEB plan investments was appl i ed to all periods of projected benefit payments to determ i ne the tota l OPEB liab ility. C. Changes in the Net OPEB Liability-The follow i ng table shows the Total OPEB L i ability , Plan Fiduciary Net Position and Net OPEB Liab il ity as o f January 1 , 2015 and January 1 , 2016 , and the changes during this per i od , based on the valuation measurement date of January 1 , 2016 (in OOO's ): Year Ended December 31 , 2016 Tota l OPEB Plan Fiduciary Net OPEB Liability Net Position Liabi lity (a) (b) (a-b) Balances at 1/1/2016 (Based on 1/1/2015 Measurement Date) ........... . $ 323 , 122 $ 64 , 487 $ 258 , 635 Changes for the year: Ser.1ce c ost. ..........................................................

...................... . 3 , 228 3 , 228 Interest.

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

.................................. . 19 , 877 19 , 877 Differences between expected and actua l experience

...................... . 1 3 , 657 13 , 657 Changes of assumptions

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

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

...................... . (9 , 1 49) (9,149) Cont ri but i ons-employer ................................................................. . 28 , 242 (28 , 242) Net investment inco me .........................................................

........ . (453) 453 Benefit payments ......................................................

...........

........ . (16 , 902) (1 6 , 902) Adm ini strative expense ....................................................

............. . (150) 150 Net Changes .................................................................................. . 10 , 711 10 , 737 (26) Balances at 12/3 1/2016 (Based on 1/1/2016 Measurement Date) ....... . $ 333 , 833 $ 75 , 224 $ 258 ,609 ===== In December 2016 , the District initiated a voluntary early retirement incentive program (" Program") t o all regula r, full-time employees, excluding senior management , who met certain retirement-elig i ble criter ia. There were 121 employees who accepted the offer. These early retirements are expected to in crease the net OPEB li ab ili ty. The impact of the Program will be included in the January 1 , 2017 actuarial valuation.

Addi tiona! information on the Program is i ncluded in Note 14. Finan ci al Report 5 0 The mortality assu m ption was updated to the RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2015 with generational projection. The cost method was changed to Entry Age Normal and the actuarial asset method was changed to five-year smoothing. 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 liab ility would be i f i t were calculated using a discount rate that is 1-percentage

-point lower (5.25%) or 1-percen tage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1 , 2016 (in OOO's): 1% Decrease 5.25% Net OPES Liability............................ $306 , 681 Discount Rate 6.25% $258 , 609 1% Increase 7.25% $219 , 295 Sensitivity of the Net OPEB Liabil i ty to Changes in the Healthcare Cost Trend Rates The following table shows the net OPEB liability of the District , as well as what the net OPEB liab ility would be if i t were calculated using healthcare cost trend rates that are 1-percentage-point lower (Pre-Medicare ranging from 7% initial to 4% ultimate , Post-Medicare ranging from 5.75% ini t ial to 4% u l t i mate) or 1-percentage-point highe r (Pre-Medicare rang i ng from 9% initial to 6% ultimate , Post-Medicare ranging from 7.75% initial to 6% ultimate) than the healthcare cost trend rates (Pre-Med icare ranging from 8% ini tial to 5% ultimate , Post-Medicare ranging from 6.75% i nitial to 5% ultimate) at the measurement date of January 1 , 2016 (in OOO's): 1% Decrease (Pre-Med i care rang i ng from 7% in it i al to 4% ult i mate , Post-Med i care ranging from 5.75% init i al to 4% u l timate) Net OPES Liability........ $219 , 672 OPEB Plan Fiduciary Net Position Healthcare Cost Trend Rates (Pre-Med i care ranging from 8% i nit i al to 5% ult i mate , Post-Medicare ranging from 6.75% i nitia l to 5% u l timate) $258 , 609 1% Increase (Pre-Medicare ranging from 9% i n i tial to 6% ult i mate , Post-Medicare ranging from 7.75% initial to 6% u l timate) $306 , 151 The following table shows information on the OPEB Plan Fiduciary Net Position as of December 31 , (in OOO's): 2016 2015 Cash and cash equivalents

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

............. $ 9 , 609 $ 3 , 719 Receivables

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

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

.................... . 314 253 lm.estments , at fair value ...............

................................................. . 132 , 875 71 , 252 Tota l assets ........................................

.......................................... . 142 , 798 75 , 224 Liabilities

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

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

.............................................. . (289) Net position -restricted fo r other post-employment benefits...

............. $ 142 , 509 $ 75 , 224 51 F i nancial Report The following tables show the OPES 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 , (in OOO's): 2016 Le\*1 1 Le\*1 2 Le\*1 3 Total Cash and cash equivalents

................................ $ 9 , 609 $ $ $ 9 , 609 U.S. T reasury and go\*mment agency securities . 2 , 678 2 , 678 Corporate issues ............

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

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

18,162 18 , 162 Foreign issues ..........................

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

5 , 161 5 , 161 Municipal issues ...................................

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

766 766 Domestic common stocks .................................

39 , 002 39 , 002 Foreign stocks ................................

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

3 , 569 3 , 569 Mutual funds .....................................................

63,537 63,537 $ 115,717 $ 26 , 767 $ $ 142,484 2015 Le\*1 1 Le\*1 2 Le\*1 3 Total Cash and cash equivalents

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

............. $ 3 , 719 $ $ $ 3 , 719 U.S. Treasury and go\*mment agency securities . 1 , 819 1 , 819 Corporate issues ..................

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

......... 17 , 551 17 , 551 Foreign issues .................

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

5 , 304 5 , 304 Munic i pal issues ....................

........................... 771 771 Domest ic common stocks ................................. 29 , 833 29,833 Foreign stocks ..........................................

........ 4 , 050 4 , 050 Mutua l funds .....................................................

11 , 924 11 , 924 $ 49 , 526 $ 25 , 445 $ $ 74 , 971 D. OPEB Expense , Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB -The Board annually approves the OPES expense in rates and has authorized the use of regulatory accounting to equate OPES expense with the amount in rates. OPES expense was $20.6 million for 2016 , as calculated under the GASS 75 guidance.

With regulatory accounting , OPES expense and t he amount included in rates was $52.9 million for 2016. This amount included a $25 million catch-up rate collection for the net OPEB liability for past production-level services. There were no deferred inflows of resources related to OPES. The following table summarizes the reported deferred outflows of resources as of December 31 , 2016 (in OOO's): 2016 Difference between actual and expected experience

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

.......... . Difference between expected and actual earnings on in\*stments

...... . Contributions made during the year ended December 31 , 2016 .......... . Total Deferred Outflows ..................................................

............. . $ $ 3,769 3,862 74,658 82,289 Financial Report 52 The deferred outflows re la ted to the contr i butions made dur i ng the year ended December 31 , 2016 will be recognized in the actuarial valuation with a measurement date of January 1 , 2017. The other deferred outflows of resou r ces will be recognized in OPEB expense as follows (in OOO's): Year Amount 2017 ....................... $ 1 , 705 2018 ....................... 1 , 704 2019 ....................... 1 , 705 2020 ....................... 1 , 704 2021 ....................... 739 2022 ....................... 74 Total $ 7 , 631 Additional i nformation is available in the unaudited Required Supplementary Information section following the Notes t o Financial Statements. 12. COMMITMENTS AND CONTINGENCIES

A. Fuel Commitments

-The District has various coal supp l y contracts and a coal transportation contract with minimum estimated future payments of $166.0 mill i on at December 31, 2016. These contracts expire at various times through the end of 2018. The coal transportation contract in place is sufficient to de li ver coal to the generation facilities through the expirat i on date of the aforementioned contracts and is subject to pr i ce escala tion adjustments. The Distr ict has a contract for uranium purchases and deliveries in 2017 and 2018 , a contract for conversion services of uranium to u r anium hexafluoride which is in effect through 2021 , a contract for enrichment services through 2024 , and a contract for fabrication services through January 18, 2034 , the end of the current operating licen se of CNS. These commitments for nuclear fuel material and services have combined es t im a ted future payments of $250.0 million. B. Power Purchase and Sales Agreements

-The D istrict has entered into a participation power agreement (the " NC2 Agreement") with OPPD to purchase 23.7% of the power of NC2 , estimated to be 161 MW of the power from the 663 MW coal-fired power plant constructed by OPPD. The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses , debt serv i ce , other costs , and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursu ant to such step-up provision is limited to 160% of its original participation share (23.7%). No such default has occurred to date. The D istrict has entered into a participation power sales agreement with Munic ipa l 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 , 2011 and continues through December 31 , 2023. The District has entered into power sales agreements with Linco l n Electric System (" LES") for the sale to LES of 30% of the net power and energy of She ldon Station (" Sheldon") and 8% of the net power and energy of GGS. In re turn , LES agrees to pay 30% and 8% of all costs attributable to Sheldon and GGS , respective l y. Each agreement is to terminate upon the later of the last maturity of the debt attributab l e to the respective station or the date on which the D i strict retires such stat ion from commercial operation. The District has wholesale power purchase co mm itments 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. 53 Fi n anc i al R e po rt The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year partic i pation power agreements to sell 28 MW to four other utilities. In addition , the Distr i ct has power purchase agreements w i th 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 facilit i es. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities in Nebraska over similar terms. The District has entered into a power purchase agreement with Central for the purchase of the net power and energy produced by the Kingsley Project during its operating life. The Kingsley Project is a hydroelectr i c generating unit at the Kingsley Dam in Keith County , Nebraska with an accredited net capacity of 37 MW. The District has entered into long-term PRO Agreements having initial terms of 15 , 20 , or 25 years with 79 municipalities for the operat i on of certain retail electric distribution systems. These PRO Agreements expire on va r ious dates between March 1 , 2023 and March 31 , 2042. These PRO Agreements obligate the D i strict to make payments based on gross revenues from the municipalities and pay fo r normal property additions during the term of the agreement.

C. Wholesale Power Contracts The District serves i ts wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District, subject to certain exceptions.

I n 2016 , the District entered into 20-year Wholesale Power Contracts

("2016 Contracts") with 23 pub l ic power districts , one cooperative , and 37 municipalit i es , effective January 1 , 2016. Two public power districts and 11 municipalities are served under 2002 Wholesale Power Contracts

(" 2002 Contracts"), which expire on December 31 , 2021. The 2016 Contracts allow a wholesale customer to give notice to reduce its purchase of demand and energy requirements from the District based on a comparison of the District's average annual wholesale power costs in a given year compared to power costs of U.S. utilities for such year listed in the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the " CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given utility can compare its power costs on a percentile basis to the CFC published quartile information. The 2016 Contracts allow a wholesale customer to reduce its demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given year is higher than the 45 th percentile level (the " Performance Standard Percentile

") of the power costs of U.S. ut i lities for such year as l i sted in the CFC Data. The 2016 Contracts would not allow any reductions in demand and energy purchases by a wholesale customer as long as the District's average annual wholesale power costs percentile remained below the Performance Standard Percentile. The following table lists the District's wholesale power costs percentile for the calendar years 2011 to 2015 set forth in the CFC Data: CFC Data Year Percentile 2011 24.4% 2012 29.1% 2013 31.0% 2014 27.6% 2015 31.3% The 2002 Contracts allow a wholesale customer to reduce i ts purchases of demand and energy upon giving appropr i ate notice. Reductions could amount to as much as 90% of their demand and energy r equi r ements under certain circumstances. A ll wholesale customers under the 2002 wholesale contracts are required to purchase at least 10% of their demand and energy from the District through December 31 , 2021. Financial Report 54 The Distr i ct has r ece i ved notices from nine wholesale customers as to their intent to level off , reduce , or terminate the requirements under their 2002 wholesa l e contracts for var i ous amounts from 2017 through 2021. The n i ne customers include one municipal i ty which has a short-term wholesale contract terminat i ng in May 2016. These wholesale customers represented 4.5% of the District's 2015 operating revenues. The District expects that no requirements of sa id n i ne wholesale customers wi ll be served by the D i strict in 2022 , and such wholesale customers w i ll pu r chase all of the i r electric requirements from other suppliers. The D i strict expects to sell the energy not sold to such wholesa l e customers into the SPP Integrated Market and continues to explore additional firm requ i rement and/or fixed pr i ce agreements. One wholesale customer has not given notice to reduce and cont i nue under the 2002 wholesale contracts. Th i s customer represented 0.1 % of the District's 20 1 5 operating revenues. In 2016 , three of the D i strict's municipal wholesale customers began purchasing power from three of the Distr i c t's public power district wholesale customers. These customers represented 0.1 % of the District's 2016 operat i ng revenues. One of the District's municipal wholesale customers allowed the i r contract to terminate. Th i s customer represented less than 0.1 % of the District's 2016 operat i ng revenues. The 2016 wholesale rates resu l ted in a 0.6 % increase for wholesa l e customers who signed the 2016 Contracts , and a 3.8% increase for those wholesale customers who remained under the 2002 Contracts. The 2002 Contract customers will pay their share of previously i ncurred OPEB costs through 2021. Customers under the 2016 Contracts received a d i scount for the deferral of OPEB collect i ons , extending those collections i nto the new contract period and resu l ting in the lower net wholesa le rate increase. Eight who l esale customers who rema i ned under the 2002 Contracts filed for binding arbitration in May 2016 claiming the 2016 wholesale rate v i olates the 2002 Contracts , is contrary to Nebraska's rate statute and reflects bad faith toward those not signing the 2016 Contracts.

Since May 2016 , the disputed amounts are being set aside i n eight separate accounts. The fi r st meeting of the arbitration panel occurred in September 2016. The dispute now includes the OPEB component of the 2017 wholesale rates. A decision is expected i n the second quarter of 2017. If these wholesale customers are successful on the merits of the i r claim , the D i st ri ct's Board of Directors may need to reconsider the 2016 wholesale rate change. The Distr i ct currently has 10 wholesale customers remaining on the 2002 Contracts , which i nclude the eight who l esale customers referred to above. These customers represented 4.5% of the District's 2016 operat i ng revenues. The 2016 wholesale rate increase in dispute accounts for $1.6 million of 2016 revenues. The D i str i ct estima t es the 2017 wholesale rate increase in dispute to be $2.0 million. The Northeast Nebraska Public Power District filed a l awsuit i n the District Court of Wayne County , Nebraska regarding the demand and energy reduct i on provisions under the 2002 Contract.

The court issued an order dated February 26 , 2016 , i n favor of the Northeast Nebraska Publ i c Power District which a ll ows them to reduce the i r demand and energy purchases from the District by 30% in 2018 , 60% i n 2019 and 90% in 2020. The court decision w i ll apply to certain other customers who have given notice for demand and energy reduct i ons under the 2002 Contract.

On March 23 , 2016 , the Distr i ct filed a notice of appeal. D. SPP Membership and Transmission Agreements

-The D i str i ct is a member of SPP , a regional transmission organization based in Little Rock , Arkansas. Membership in SPP provides the District rel i ab il ity coord i nation serv i ce , generation reserve sharing , regional tar i ff administration , includ i ng generation interconnection serv i ce , network , and point-to-point transmission service , and regional transmissio n expansion p l anning. The District was ab l e to participate i n SPP's energy imbalance market , a real-time balancing market that provides members the opportunity to have SPP d i spatch resources based on marginal cost , through February 2014. On March 1 , 2014 , SPP commenced a Day-Ahead , Ancillary Serv i ces , and Real-Time Balanc i ng Market Integrated Market. The Integrated Market also provides a financial market to hedge unplanned transmiss i on congestion , or financial virtua l products to hedge uncertaint i es , such as unplanned outages. The D i str i ct entered i nto a Transmiss i on Facil i t i es Construction Agreement effect i ve June 15 , 2009 , w i th TransCanada Keystone Pipeline , LP (" Keystone"). This agreement addresses the transmission facilit i es , construction , cost allocation , payment , and app l icable cost recovery for the interconnection and delivery facilities r equired for the i nterconnect i on of Keystone to the Distr i ct's transm i ssion system. Cost of the project was 55 F in a ncial Repo rt

$8.4 million and repayment by Keystone , over a 10-year period , began in June 2010 with a remaining balance due the Dist r ict of $3.5 million and $4.4 million as of December 31 , 2016 and 2015 , respectively. The District entered into a second Transmission Fac i lities Construction Agreement effective July 17, 2009 , with TransCanada Keystone XL Pipeline , LP (" Keystone XL"). This agreement addresses the transmission facilities , construction , cost allocat i on , payment , and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. Tra n sCanada Corporation and TransCanada Pipe l ine USA Ltd. have jointly and severally guaranteed the payment obligations of Keystone under its agreements w i th the District.

The agreement was cancelled in 2016 after the 2012 application for a Presidential permit for construction of the Keystone XL Pipeline was denied. All outstanding balances for Keystone XL were paid in 2016. E. Cooper Nuclear Station -On November 29 , 2010 , the Nuclear Regulatory Commission

(" NRC") formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until January 18 , 2034. CNS entered the 20-year period of extended operation on January 18 , 2014. In October 2003 , the Distr i ct entered into an agreement (the " Entergy Agreement") for support services at CNS with 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 e i ther party's right to terminate without cause by providing notice and paying a $20 million terminat i on charge. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services , and to pay Entergy annua l management fees. These annual management fees were $18.5 mill i on for 2016 and $18.4 million for years 2015 and 2014. 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 incent i ve fees in an amount not to exceed $4.0 million annually if CNS achieves 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 Dai-ichi Plants in Japan , the Distric t , 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 poo ls 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 E l ectric boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes this same containment system; however , significant enhancements to the design have been made over the life of the plant. An NRC Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12 , 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report , on October 18 , 2011 , the NRG approved seven of the Task Force recommendations for implementation. On March 12 , 2012, the NRG issued three orders to the U.S. nuc l ear industry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nuclear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened conta i nment wetwe l l vents. The thi r d order requires nuclear plant operators to add reliable spent fuel pool water level instrumentation. The NRG has also issued a request for i nformation pertaining to re-evaluation of seismic and flooding hazards , and a communications and staffing assessment for emergency preparedness. Phase one and phase three of said order have been completed. Phase two of said order , which requ i res a drywell vent or a basis and strategy for why venting the drywell would not be required, will be completed by the conc l usion of the fall 2018 refueling and maintenance outage. Since the in i tial site-specific seismic reevaluation analysis for CNS that resulted in no identified se i sm i c-related modifications to CNS , the District has performed an add i t i onal seismic 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 H i gh F in ancia l Report 56 Frequency Evaluation and a Spent Fuel Pool Evaluation , but w ill not have to complete a Seism ic Probab ilistic Risk Assessment.

Unknown to the District at this time is the extent of modifications that may be required as a result of these additional seismic reevaluations.

The District continues to work with the U.S. Army Corps of Engineers (the " Corps") and the NRC to validate the data necessary to complete the CNS flood hazard reevaluation. The District submitted its updated flood ing analys i s to the NRC in February 2015. The NRC subsequently submitted questions to which the District has responded and submittal of the updated flood hazard reevaluation was completed in September 2016. Based on current interim , and long-term strategies for flooding mitigation , it is not expected that any modifications will be required as a result of the flood hazard reevaluations. All equipment and materials required to mitigate the identified impacts associated with the flood hazard reevaluation have been purchased and the equipment required has been in stalled. Additional equipment purchased, but not required to be i nstalled unless an issue occurs, i s stored on-s it e in dedicated storage facilities. The District's cost est i mate for plant mod i fications associated with the NRC's Fukushima Dai-ichi related orders is currently estimated to cost $25.6 million , which is expected to be funded primarily from the revenues of the District and from the proceeds of General Revenue Bonds. As of December 31 , 2016 , $19.4 m i llion has been spent on plant modifications with an add i tional $6.2 million expected to be spent to establish compliance with the Fukushima Dai-ichi orders. CNS substantially completed the construction of a dry cask used fuel storage project in December 2009 to support p l ant operations until 2034 , which is the end of the Operating License. The first loading campaign was completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool into eight dry used fuel storage casks for on-site storage. A second loading campaign , encompassing the loading of 610 used fuel assemblies into 10 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 , is scheduled to begin in June 2017. As part of va r i ous disputed matters between GE and the District , GE has agreed to continue to store at the Morris Facility the spent nuc l ear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility. After that date , storage would continue to be at no cost to the District as long as GE can ma i ntain the NRC license for the Morris Fac ility on essentially the exist in g design and operat i ng configuration. As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract , the Distr ict commenced legal act i on against the DOE on March 2 , 2001. The initial settlement agreement addressed future claims through 2013. On January 13 , 2014 , the District and the DOE agreed to extend the settlement 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 2016. The Distr ict also reserves the right to pursue future damages through the contract claims process. A corresponding regulatory liability for these DOE receipts was establ i shed in Other deferred inflows of resources. The District plans to use the funds to pay for costs related to CNS. The balance in the regulatory liability was $82.7 million and $79.5 million at December 31 , 2016 and 2015 , respectively. Under t he terms of the DOE contracts , the D i strict was also subject to a one mill per kilowatt-hour

(" kWh"} fee on all energy generated and sold by CNS which was paid on a quarterly basis to DOE. The District includes a component in its wholesale and retail rates for the purpose of funding the costs associated with nuclear fuel disposal.

While the D i strict expects that the revenues developed therefrom w i ll be sufficient to cover the District's responsib i lity for costs currently outlined in the Nuclear Waste Policy Act , the District can give no assurance that such revenues will be sufficient to cover all costs assoc i ated with the disposal of used nuclear fuel. On May 9 , 2014 , the DOE provided notice that they would adjust the spent fuel d i sposal fee to zero mills per kWh effective May 16 , 2014. Correspondingly , no additional payments have been made to the DOE for fuel disposal since that date. The Board au t horized the continued collection of this fee at the same rate. This approach ensures costs are recognized in the appropriate period with current customers receiving the benefits from CNS paying the approp r iate costs. The expense for spent nuclear fuel disposal is recorded based on net electr i city generated and sold and the regulatory l i ability will be eliminated when payments are made for spent nuclear fuel disposal.

57 Financial Report Under the provisions of the Federal Pr ice-Anderson Act , the D i strict and all other licensed nuclear power p l a nt operators could each be assessed for claims i n amounts up to $127.3 million per unit owned in the event of a n y nuclear i ncident i nvolving any licensed facility in the nation , with a maximum assessment of $19.0 million per year per i n cident per unit owned. The NRC evaluates nuclear plant performance as part of its reactor oversight process (" ROP"). The NRC has five performance categories included in the ROP Action Matrix Summary that is part of this process. As of December 31 , 2016 , CNS was in the Licensee Response Column , which is the first or best of the five NRC defined performance categories and has been in this column s i nce the first quarter of 2012. Refueling and maintenance outages are requ i red to be performed at CNS approximately every two years. The most recent refue li ng and ma i ntenance outage began on September 25 , 2016 and was comp leted on November 8 , 2016. During this outage , in addition to replacing 184 fuel assemblies and conducting ro utine maintenance , equipment replacements included one of the two reactor water recirculation pump impel lers and motor , the startup station transformer and the high pressure turbine. Significant ope r ations and maintenance expenses are incurred i n the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and he l p ensure the customers receiving the benefits from CNS are paying the costs , commencing in 2015. The regulatory l iability for the pre-collec tion of outage costs was $24.7 million at December 31 , 2015 and was eliminated through revenue recognition during the 2016 outage year. The District began collecting revenues for the 2018 CNS refueling and maintenance outage in 2017. F. Environmental

-Water The Federal Clean Water Act contains requ irements with respect to effluent limitat ions relating to the discharge of any pollutant and to the environmental impact of cooling water intake structures. The Nebraska Department of Env i ronment Qual i ty (" NDEQ") establishes the requirements for the Distr i ct's compliance w i th the Clean Water Act through i ssuance of Nationa l Pollutant Discharge Elimination System permits. NDEQ issued the District permits for the following facil i ties: GGS , Sheldon , CNS , Beatr ice Power Station , Canaday Station , Kearney Hydro and the North Platte Office Building.

The District antic i pates some level of fish protection equ i pment technology installation , both for impingement and entrainment , may be necessary for CNS and on l y 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 rev i ses the technology-based effluent limitation guidelines and standards that would strengthen the exist i ng controls on discharges from steam electr i c power plants and sets the fi rs t federal limits on the le vels of tox i c 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. General l y , 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 desulfur i zation , fly ash , bottom ash , flue gas mercury control , and gasification of fuels such as coal and petroleum coke. While the D istrict faci l ities subject to the Effluent Rule are CNS , GGS , Sheldon and Canaday Station , the Effluent Rule only has an impact on the Sheldon Station. Sheldon Station will be required to be a zero discharge facility for bottom ash transport water by December 31 , 2023. The Distr i ct is currently ana l yzing the options for compliance , which is estimated to cost $2.4 million. 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 rest r ict i ons on sulfur dioxide (" S0 2") and nitrogen oxides (" NO;') emissions. Acid Rain Permits have been issued for the following facilit ies: GGS , Sheldon , Canaday Station and Beatrice Power Stat i on. The Acid Rain Permits allow for the discharge of S0 2 at each facility pursuant to an allowance system. The District expects to have suffic i ent allowances for its generating faci l ities through 2020 , but may be required to purchase add i tional allowances in the future. Finan ci al Report 58 Mercury and Air Toxic Standards On February 16 , 2012 , the EPA issued a final rule intended to reduce emissions of toxic air po ll utants from power plants. Specifically , the Mercury and Air Toxics Standards

(" MATS") Rule will require reductions in emissions from new and existing coal-and oil-fired steam utility electric generating units of toxic air pollutants. All affected District facil i ties , inc luding GGS and Sheldon , are in compliance with the MATS Ru l e. Reg i onal Haze and Cross-State Air Pollut ion Rule The E PA i ssued final regul at ions for a Reg i onal Haze Program in June 1999. The purpose of the regulations i s to improve visibi lity in the form of reducing reg i onal haze in 156 national parks and w i lderness areas across the country. Haze is form , in part , from emissions of S0 2 and N O x The EPA issued a rule in 2012 which is referred to as the Cross-State Air Po llution Rule (" CSAPR") that would require sign i ficant reductions in S0 2 and NO x emissions i n a number of states, including Nebraska.

CSAPR compliance per i ods went into effect on January 1 , 2015. Based on the current CSAPR allocation methodology and current generation projections through 2021 , the Distric t expects to have sufficient CSAPR allowances to cover affected facilities emission requ i rements over that ti mefram e , but may be required to purchase additional allowances in the future. On January 10 , 2017 , the EPA issued final changes to the Regional Haze regulations for the second planning phase of the Reg ional Haze Rule. The Distr i ct is evaluating the proposed changes but will not know the full impact to the District until the State and the EPA begin implementing the second phase of the Regional Haze rule. The State of Nebraska is required to submit their state implementation plan (" SIP") for the second phase of the Regiona l Haze rule by July 31 , 2021. On January 19 , 2017 , EPA Region 7 i ssued a proposed modificat ion to the July 6 , 2012 Regional Haze federal implementation plan (" FIP"). The proposed modification would require the District to ins tall S0 2 controls on both units at GGS within five years of the proposed FIP be ing finalized. The District is currently evaluating the proposed mod ifi ca tion. However , the proposed modification has not yet been published in the Federal Reg ister and due to the hold iss ued by the Trump administration on all proposed regu lations yet to be published in the Federal Reg i ster , the publication of this mod i fication w ill be de l ayed or withdrawn. As part of EPA's nationwide investigation and enforcement program for coal-fired power plants' compliance with the Clean Air Act including new source review requirements, on December 4 , 2002 , the Region 7 office o f the EPA began an i nvestigation to determine the Clean Air Act compliance status of GGS and Sheldon. The Dist rict timely responded to EPA's requests for i nformation.

By letter dated December 8 , 2008 , EPA Region 7 sent a Notice of Violation

(" NOV") to the Distr ict which alleges tha t the District vio l ated the Clean Air Act by undertaking five pro jects at GGS from 1991 through 2001 without obtaining the necessary permits. In February and Augus t 2009 , District representatives met with federal government representatives to discuss the NOV and no add i tional meetings have been scheduled. In general , enforcement action by EPA against the Distr ict for alleged noncomp l iance with Clean Air Act requirements. if upheld after court review , can result in the requirement to install expensive air pol l ution control equipment that is the Best Available Retrofit Technology

(" BART") and the imposition of monetary penalties ranging from $25 , 000 to $32 , 500 per day for each v i olation. The District cannot determine at this time whether it will have any future financial obl igat i on with r espect to the NOV. On July 22 , 2016 , EPA Reg ion 7 sent a new 114(a) request for documents and inform ation regarding the comp l iance status of GGS. On December 27 , 2016 , EPA Region 7 sent a 114 (a) follow-up request for additional informat ion on certain projects that were identified in the July 22 , 2016 , 114(a) request. The EPA is review i ng whether the r e have been physical or operational changes since November 8, 2007 which resul t ed i n , or could result in , increased emissions includi ng projects underway or planned for the next two years. The District is i n the process of gathering responsible documents and information. Failure to comply with the Clean Air Act can result in fines as described above and/or requirements to install additional emission control equipment.

The Dist rict believes GGS has been operated and maintained in compliance with the requirements of the Clean Air Act. Clean Power Plan On October 23 , 2015 , the EPA published the final Clean Power Plan (" CPP") rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determ i n i ng how to achieve the reduction targets through the development of a State Plan. Each state was given a reduction target to be achieved by 2030 with interim reduct i ons required between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 emissions. On February 9 , 2016 , the U.S. Supreme 59 Financial Report Court issued a stay for the CPP until all legal challenges have been decided. The D.C. Circuit Court of Appea ls heard oral argumen ts on September 27 , 2016 , with a decision expected in early 2017. An initial State Plan was due September 6 , 2016 prov i d ing a general outline of potentia l compliance options the State is consider ing. States can also request a two-year extens i on when submitting their initial plan making the fina l State P lan due September 6 , 2018. If the CPP is upheld , the rule deadlines will likely be extended by the length o f the stay. Due to the stay , the NDEQ has halted work on the State P l an. The D i strict expects that its generation from coal-fired units will decrease and its generation from natural gas may increase under the final rule but it is not possible to determine the im pact of the final rule on the District unt i l the legal i ssues are ultimately decided and the NDEQ develops the State Plan and i t receives EPA approva l. Impact from Changes to Env i ronmental Regulatory Requirements Any changes in the environmental regulatory requirements imposed by federal or state law wh i ch are applicab le to the Distr i ct's generating stations could result in increased capital and operating costs being incurred by the District.

The Distr ict i s unable to predict whether any changes will be made to current environmenta l regu latory requirements , i f such changes will be app li cable to the D is trict and the costs thereof to the District.

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

(" MOU") was signed for the sale of the Distr ict's Spencer Hydro (" Spence r") facility , i ncluding dam , structures , land , water appropriat i ons , and perpetual easements for the reservo ir , to the N i obrara River Basin Alliance (Five Natural Resource Districts) and the Nebraska Game and Parks Commission for $12.0 m illi on. The District is to provide an in-kind contribution of $3.0 million and the other parties are to pay $9.0 million to the District.

The MOU prov i ded that the parties will work for passage of legislation by the State of Nebraska for a permanent transfer of existing hydro water appropriation to a new multipurpose use , and it identifies potential sources of funding for the sale. The required legislation for this sale was passed by the State of Nebraska in 2016. The District will continue to operate Spencer unt i l transfer of ownersh ip , including water appropriations , i s completed. The transfer is expected to take approximately two years to complete. H. Other-Congress i onal action reduced the 35% i nterest subsidy , pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985 , as amended on the D is trict's General Revenue Bonds , 2009 Series A (Taxable Build Amer ic a Bonds) and 20 1 0 Series A (Taxable Bu i ld America Bonds). Reductions were 6.9% and 7 .3% for fiscal years ended September 30 , 2016 and 2015 , respectively.

13. LITIGATION

On January 1, 2016 , Tr i-State Generation and Transm i ssion Association , Inc. (" Tri-State") became a transmission member of SPP and i ts transmission facil i ties in western Nebraska , and the corresponding annual transm is s ion revenue requirements were placed under the SPP tariff. SPP filed at FERC to place the Tri-State transmission facilities in the Distric t's pricing zone rathe r than establish a new pricing zone for Tr i-State. The Distr ic t protested the filing at FERC , because it results in approximately a $4.3 m i llion per year , or 8%, cost shift increase to the transmission customers in the D is trict's pricing zone. As a result of the District's protest , FERC set the matter for hearing before an administrative law judge and the District and other parties submitted briefs and testimony on the proper pric i ng zone and whether SPP's decis i on i s discriminatory and an unjust and unreasonable cost shift to the District.

On February 23 , 2017, the administrative law judge issued an initial decision uphold in g the SPP pr icing zone p lac ement and made recommended conclusions to FERC. This initial dec i s i on has no legal effect until reviewed and acted upon by FERC which w ill be after the District submits briefs on its except i on to the factual and legal conclusions in the initial 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. F i nan ci al Repo rt 60 A nu m ber of claims and su i ts are pending aga i nst the District fo r alleged damages to persons and property and for o t he r alleged l iab ili ties ar i sing out of matters usually i nc i dental t o the ope r at i on of a utility , such as the D i str i ct. I n the op i n i on of management , based upon the adv i ce of its Gene r a l Counse l , the aggregate a m ounts recoverab l e from the Distr i ct , taking into account est i mated amounts p r ov i ded in the financial state m ents and insurance coverag e , a r e not ma t er i al as of Decembe r 31 , 2016 a n d 2015. I nformat i on on l iti gation w i th who l esale customers is i nclud e d i n No t e 12. 1 4. SUBSEQUEN T EVENTS: In April 2017 , the D i strict issued Genera l Revenue Bonds , 2017 Se r ies A and 2017 Series B , in t h e amount of $86.0 m i lli on to refund the Ge n eral Reve n ue Bonds , 2007 Series B. The refunding reduced tota l debt serv i ce payments over the li fe of the bonds by $1 1.8 mi l l i on , wh i ch resu l ted i n present value savings o f $10.0 Million. T h e Distr i ct p l ans t o issue additional revenue bonds in 2017 to finance t ransmission projects. On Febr u ary 5 , 20 1 7 , operators a t CNS d i scovered that the m i n i mum flow i solat i on va l ve for two pumps on t h e Res i dua l Hea t Removal Sys t em were found c l osed and sealed. The required configuration for these va l ves i s open and sealed. The issue had ex i sted f o r approx i mately fou r months , since early October dur i ng the 2016 fa ll refuel i ng a n d mainte n ance outage. The cause eva l uation to dete r mine how the issue occu r red and act i ons t o prevent recur r ence is ongoing at this t i me. Dur i ng the week of March 13 , 20 1 7 the NRC Region IV conducted a specia l in spection , comprised of two inspectors , to i nvestigate the rece n t Residua l Heat Remova l Syste m M i nimu m Flow Valve i ssue to determ i ne the safety s i gn i ficance. I f the i ssue i s dete r mined to be g r eater than a very low safety s i gnificance (a finding g r eate r than Green), CNS wou l d move from the Licensee Response Column to the Regula t ory Response Colu m n of the NRC's Action Mat r ix fo r a period of one yea r. Plants in the Regulato ry Response Column o f the N RC's Action Matr i x are subje c t to add i t i ona l N RC i nspections. In Dece m ber 2016 , the D istr i ct i nitiated a voluntary early retirement i n centive program ('P r ogram") to all r egular , f ull-time emp l oyees , excluding sen i or management , who met certain retirement-el i gi b le criteria. The object i ve of t he Program was to fac i litate an accelerated but voluntary reduction i n the wo r kforce to obta in a reduction i n costs d u ring 20 1 7 and in years following by i ncentiviz i ng ea rl ier re tir ement of emp l oyees who we r e eligible fo r retiremen t. Approxima t ely 600 employees were elig i ble for the P r ogram and 1 21 employees accepted t h e offe r. Their l as t day of full-t im e employment was on or before February 28 , 20 1 7. T hese emp l oyees rece i ved s i x mon th s of salary i n one , lump sum payment. The total cost of the program was $5.9 million and expensed in 2016. 6 1 Financial Report SUPP LEME NTA L S C HEDU LE S (UNA U DI T ED) Calculation of Debt serv;ce Rat ios in accordance with the General Revenue Bond Resolution for the years ended D ecember 31 , (in OOO's) Operating revenues ..................................................................................... . Operating expenses .................................................................................... . Operat i ng income ................................................................................... . Investment and other income ................

........................................................ . Debt and other expenses ........................

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

............... . Increase in net pos i tion ..............................................................

............. . Add: Debt and related expenses ................

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

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

..... . Depreciation and amort i zation ..........

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

................... . Payments to retail communities c 1> ............................................................ . Amortization of curren t port i on of financed nuc l ear fuel .........................

...... . Amounts collected from third party financing arrangements c 2 1 ................*.....

Deduc t: I nvestment income retained in construct i on funds .......................

............... . Unrealized (l oss) gain on investment securities

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

.......................... .. Re\Ql..,;ng credit agreement interest ............

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

.............. . Net position available for debt serv;ce for the General Revenue B ond Resolution . Amounts deposited in the General System Debt Serv;ce Account: Principa l .............

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

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

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

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

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

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

.......... . Ratio of net position available for debt serv;ce to debt serv;ce deposits ............. . 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 2015 $ 1 , 097 , 216 (960 , 259) 136 , 957 22 , 355 (68 , 252) 91 , 060 68 , 252 130 , 247 26,552 24 , 675 850 250 , 576 302 (1,245) 1 , 010 67 $ 341 , 569 $ 110,265 75 , 372 $ 185,637 1.84 (1) De bt and other expenses , exclus ive of i nterest on customer deposits , i s not an operating expense as defined i n the General Reso lution. (2) Depr eciation and amort iz ation are not operating expenses as defined in the General Resolution. (3) Unde r the provisions of the Genera l Resolution , the payments required to be made by the District with respect to the Professional Retai l Operating Ag reements are to be made on the same basis as s u bord i nated debt. (4) Genera l Revenue Bond financed nuclear fue l is not an operating expense as defined i n the General Resolution. As of July 31 , 2015 , the effect ive date of the Taxable Revolv i ng Cred i t Agreement , amortization of nuclear fue l expense under the Taxable Revol ving Credit Agreement is excluded from the debt service c alculation as the District's ob ligat ion to make payments under the Taxable Revolving Cred it Agreement i s subordinate to the District's obligation to pay debt service on Genera l Revenue Bonds. (5) Th e payments rece ived by the District from third party financing arrangements are i ncluded as Revenues under the General Resolut i on , but are not recognized as revenue under GAAP. (6) Interest i ncome on investments held in construct i on funds is not Revenue as defined in the General Resolution. (7) As of Jul y 31 , 2015 , the effect i ve date of the Taxable Revolv i ng Credit Agreement , interest expense under the Taxable Revolving Credit Agr eeme nt i s e xc luded from the debt service calculation as t he District's obligation to make payments under t he Ta xa ble Revolving Credit Agreement is subordinate to the District's obligation to pay debt serv ic e on General Revenue Bonds. Financial Report 62 Schedule of C h anges i n the Net OPEB Liab i lity and Re l a t ed Rat i os as of December 31 u s i ng a January 1 Measuremen t Date (i n OOO's) Total OPEB Liability Sen.ice Cost. .................................

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

.............................................................. . Differences Between Expected and Actual Experiences

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

................. . Changes of Assumpt i ons ................

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

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

............... . Benefit Payments ......................................................................................

...........

........... . Net Change in T otal OPEB Liab ili t y ......................................

............................................. . Total OPEB Liab i li t y (beginn i ng) ....................................................

.................................... . Total OPEB Liab i lity (ending) (a) ..........................................................................

............. . Plan Fiduciary Net Position Contributions

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

............................................................................................. . Net ln\*stment Income ......................

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

...........

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

........ . Benefit Paymen t s .......................................................................................

..................... . Admin i s t rat i\* Expense .................................................................................................... . Net C h ange in Plan F i duciary Ne t Pos i tion .....................................

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

............. . Plan F i duc i ary Net Pos i t i on (Beginn i ng) .................................

........................................... .. Plan F i duc i ary Net Position (End i ng) (b) .....................

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

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

...........

.... . Net OPEB Liab i li t y (Ending) (a) -(b) ...................

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

.......... . Net Posit i o n as a % of Total OPEB Liabil i ty ..................

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

............................. . 2016 $ 3 , 229 19 , 876 13 , 657 (9 , 149) (16 , 902) 10 , 711 323 , 122 $ 333 , 833 $ 28 , 242 (453) (16 , 902) (150) 10 , 737 64,487 $ 75 , 224 $ 258 , 609 22.5% Co\*red-Employee Payroll................................................................................................. $ 195 , 903 Net OPEB Liability as a % of Co\*red-Employee Payrol l. ............................

........................ . 132.0% GASB 75 w as i mplemented by the District i n 2016. T h e provis i ons of this Statement were not applied to pr i o r periods , as it was impractical to do so as disclosed in Note 11. This schedule i s intended to show information for 10 yea r s. Additional years will be displayed when available. 63 Financ i al Report Sched u le of Contribut i ons as of December 31 using a January 1 Measure m ent D ate (in OOO's) 2016 Ac tu a ri ally Determ i ned Con t r i bu ti on ...........................

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

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

......... . $ 28 , 283 Cont ri but i ons Made i n Relat i on t o the Actuarially Determ i ned Cont ri but i on ............................ .. 74 , 658 Con t ribut i on Defic i ency (Excess) ....................

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

...................... . $ (46 , 375) Co-.ered-Emp l oyee Payro ll. ................

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

.................................... . $ 195 , 903 Con tri bu ti ons as a % of Payro ll. ......................................................................................... . 38.1% N otes to Schedule: Valuation date -Actuarially determined contribution rates are calcula t ed as of Decembe r 3 1 , one year prior to the end of the fiscal year in which contributions are reported. Methods and assumptions used -* Actuarial cost method

Amortization method

Amortization period

Asset valuation method

Discount rate

Healthca r e cost trend rates

Inflatio n

Investment r ate of retu rn

Mortal i ty

Reti r ement Age Entry Age Normal Level amortization of the unfunded acc r u e d liabil i ty 17-year closed per i od 5-yea r smoothed marke t 6.25% Pre-Medicare

8% i n i t i al , ultimate 5% Post-Medica r e: 6.75% i n i ti al , u l t i mate 5% 2.1% 6.25%, net of investment expense , includ i ng i nflation RP-2014 Aggregate table projected back to 2016 using Scale MP-20 1 4 and projected f orward using Scale MP-2015 w i th generat i onal projection Varies by age GASB 75 was implemented by t he D istrict in 2016. The provisions of this Statement were not app li ed to pr i or periods , as i t was i mpract i cal to do so as disclosed in Note 11. This schedu l e i s intended to show information for 1 0 years. Addit i onal years will be displayed when available. Financial Report 64

NLS2017058, Nebraska Public Power District 2016 Financial Report

Contents

Text

Subject:

Dear Sir or Madam:

SUMMARY

Navigation menu

NLS2017058, Nebraska Public Power District 2016 Financial Report

Text

Subject:

Dear Sir or Madam:

SUMMARY

Navigation menu

Search