Text

Licensee Guarantees of Payment of Deferred Premiums
	ML18206A463
Person / Time
Site:	Cooper
Issue date:	07/17/2018
From:	Shaw J; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2018037
	Download: ML18206A463 (62)
	v • d • e

r NLS2018037 July 17, 2018 H Nebraska Public Power Distr i ct Al ways th e r e w h e n yo u n ee d u s Attention:

Document Control Desk Director , Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington , D.C. 20555-0001

Subject:

Licensee Guarantees of Payment of Deferred Premiums Cooper Nuclear Station , Docket No. 50-298 , DPR-46

Dear Sir or Madam:

140.21 The purpose of this letter i s to transmit information in accordance with the requirements of 10 CFR Part 140.21 , relati v e to deferred insurance premiums , for the Nebraska Public Power District (NPPD). NPPD believes this information demonstrates our ability to obtain funds in the amount of $19 .0 million for payment of such premiums within the specified three-month period. To demonstrate the ability to provide funds in the required amount for such deferred insurance premiums , NPPD's 2017 Financial Report is enclosed for your review. This report is NPPD's audited financial statement.

Please refer to Page 29 of the enclosure where the Balance Sheet of NPPD is listed. Cash and investments of NPPD total over $1.3 billion as indicated on Page 3 7 , N ote 2 of the enclosure. Liquidity can be provided by unrestricted cash and investments , and through reserve and special purpose funds that , with the approval of the NPPD Board of Directors , can be utilized for any lawful purpose. The portion of cash and investments that can be utilized to provide such liquidity for the payment of the subject deferred premiums is $618.0 million as of December 31 , 2017. Also on Page 2 9 of the enclosure , under the heading " Current Liabilities

," there is a line item titled " Notes and credit agreements , current" in the amount of $165.2 million , and under the heading " Long-Term Debt ," there is a line item titled " Notes and credit agreements , net of current" in the amount of $69.0 million. As noted on Pages 42-44 , Note 7 , " Tax-Exempt Re v olving Credit Agreement" and " Taxable Revol v ing Credit Agreement" of the enclosure, NPPD is authori z ed to issue up to $150 million of the Tax-Exempt Revol v ing Credit Agreement (TERCA), and an aggregate of $200 million of the Taxable Re v olving Credit Agreement (TRCA). As of December 31 , 2017 , NPPD had $81.0 million remaining capacity in its TERCA program , and $34.8 million remaining capacity of the TRCA , for a total o f $115.8 million , which is a v ailable to fund the payment of the subject deferred premiums.

COO PER NU CLEAR ST A T ION P.O. Box 98 / B rownvi ll e, NE 6832 1-0098 Tel ephone: (4 02) 825-3811 / Fax: (4 02) 825-52 11 www.nppd.co m NLS2018037 Page 2 of2 It is NPPD's intent to continue to publish this report on an annual calendar year basis. A subsequent report , covering financial information for calendar year 2018 , will be submitted no later than July 31, 2019. This letter contains no new commitments. Should you have questions or require additional information , please contact me at 402-825-2788.

Sincerely , Licensing Manager l jo

Enclosure:

Nebraska Public Power District 2017 Financial Report cc: Regional Administrator w/enclosure USNRC -Region IV Cooper Project Manager w/enclosure USNRC -NRR Plant Licensing Branch IV Senior Resident Inspector w/o enclosure USNRC-CNS NPG Distribution w/o enclosure D. K. Starzec w/o enclosure CNS Records w/enclosure r NLS2018037 Enclosure ENCLOSURE NEBRASKA PUBLIC POWER DISTRICT 2017 FINANCIAL REPORT COOPER NUCLEAR ST A TION DOCKET NO. 50-298 , DPR-46 l -Statistical Review (Unaudited) 11 Management's Discussion and Analysis (Unaudited) 12 Report of Independent Auditors 28 Financial Statements 29 Notes to Financial Statements 32 Supplemental Schedules (Unaudited) 65 2017 YEAR AT A GLANCE Kll l LJOWAifT -HOl!JR SALES 119.6 Bll.UION OA8RA1mNG RE~ENllJES

$ ;3101 6 Ml UtO:N cosr OXF ~O>W8R P!!J'R GH~S8Cl>tA1N D S8NSRAifiE[l)

S6.I MIU ION 01rH;8R CilAERA 1r llf NG E~Pt 8~S:8 S 11;2 8 M I ULl lO~ N\~SmNIENr

~m omHl!ER INO::GME $ 216 MI LIION D8BT AKD O>illt,IER E>~AENS!BS 6S:0 MI UU IOlN LNCRE~SE 1 , N NiEJ P~Sl lli lO>N $ rn .c S NIH.J L[Cil DEBTSE!il_WQEG0~8~GE 2.1 1 1Jj JMES 10 Filila m rcfa~ !l&epo n t 2017 STATISTICAL REVIEW (Unaudited)

Average Cents Per kWh Sold Average Average Less Government Cents Per Number of MI/Vh Re\Enues (i n OOO's) OPERATING REVENUES T axesfT ransfers " kWh Sold Customers Amount % Amount % Retail: Residential

....................... 10.72 ¢ 12.74 ¢ 72 , 021 809 , 095 4.1 $ 103 , 101 9.4 Commercial

...................... 8.46 ¢ 9.86 ¢ 19 , 533 1 , 125 , 311 5.8 110 , 906 10.1 Industrial

.......................... 5.22 ¢ 5.57 ¢ 60 1 , 314 , 989 6.7 73 , 244 6.6 Total Retail Sales ............ 7.71 ¢ 8.84 ¢ 91 , 614 3,249 , 395 16.6 287 , 251 26.1 Wholesale: Municipalities w ......................................... 6.33 ¢ 45 1 , 658 , 984 8.5 104 , 985 9.5 Municipalities (P artial Requirements

)c ,i ........ 5.77 ¢ 186 , 956 0.9 10 , 785 0.9 Public Pov.er Districts and Cooperati'.Es c 21 .. 5.93 ¢ 25 7 , 966 , 644 40.7 472 , 291 42.9 Total Firm Wholesale Sales...................... 5.99 ¢ 71 9 , 812 , 584 50.1 588 , 06 1 53.3 Tota l F irm Retail and Wholesale Sales.... 6.70 ¢ 91 , 685 13 , 061 , 979 66.7 875 , 3 1 2 79.4 Participation Sales.......................................... 3.71 ¢ 5 1 , 973 , 441 10.1 73 , 199 6.6 OtherSalesc*

1................................................. 2.48 ¢ 2 4 , 533 , 128 23.2 1 12 , 209 10.2 Total Electric Energy Sales .................... 5.42 ¢ 91 1 692 19 1 568,548 100.0 1 , 060 , 720 96.2 Other Operating Revenues C s J .............................................................................................................. . 76 , 182 6.9 Unearned Revenues c 6 1 ....................................................................................................................... . (35 , 260) (3.1) To tal Operating Re\Enues .................................................................................................................... . $1,101,642 100.0 MI/Vh Costs (in OOO's) COST OF POWER PURCHASED AND GENERATED Amount % Amount % Production c , i .............................................................................................. . 15 , 850 , 887 77.9 $ 424 , 190 72.4 Power Purchased*

- - - - -****-*****-****-*****-* 4 , 501 , 041 22.1 16 1 , 963 27.6 Total Produc tion and Power Purchased

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

................ . 20,35\928 100.0 $ 586, 153 100.0 CONTRACruAL AND TAX PA YMENlS (i n OOO's) <*1 Amount Payments to Retail ConTnunities

........................................................................................................ . $ 27 , 102 P a yments i n Lieu of T.vces ........................................

....................................................................... . 10 , 060 Total Contractual and Tax Payments ........................

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

.......................... . i 37, 1 62 OllER Amount Miles of T ransmission and Subtransmission lines i n SeNce ..................

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

.............. . 5 , 294 NuniJer of F u l-lilTle Enl:>k>yees

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

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

1 , 875 (1) Customer oollections for laxesllransfers to other governments are excluded from base rates. (2) Sales are t otal requirem e n ts. subject to certa i n exceptions. (3) Sales are t o a customer who lim ited !he i r requirements u nder th e 2 0 02 Co n tract. The a v erage rate was l ower than total requ i rements cuslomefS d u e t o lh e exclusion of certa i n transmission costs fiom th e wh olesale ra t e as cost recovery was th rough th e SPP transm i ssion tariff. Th ese revenues were i nd u ded i n Other Sales. (4) ln dudes sales i n th e Southwest Power Pool r sPP"') and nonfi rm sales to o lher u tilities. (5) l ndudes reven u es for transm i ssion and othe r miscelaneous reven u es. (6) ln dudes un ea rn ed revenues fiom prior periods of S6.7 mil ion , recogllized re venues of $23.0 milion for oth er postemployment bene fit f OPEB'l expenses rela t ed t o past service and in cluded i n 2 017 rates , 2 017 su rplu s r even u es d eferred to futu re periods o f $44.9 milion and collections of$2 0.0 milion for lh e 2 01 8 Cooper N u clear Stalioo (" CN S m) re fueling and ma in tena n ce outage. (7) l ndllldes fu el , opera tion , and maint enance costs. Deb t senrioe and capilal-relateli oosls are excluded_ SOURCES OF THE DISTRICT'S ENERGY SUPPLY (%0FIIWH) Thi s chart shows th e sources of energy for sales , exdud i ng participa ti o n sales t o othe r uti l iti es. Purchases were i nduded in th e appropria t e source , except for th ose pu r chases for wh i ch th e source was n ot kn o wn. Ffarnncial IR!e:F>(!ll1t 45.3% Hydro 6.3% Purchases 4.1% 1.5%

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

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

") includes the Management's Discussion and Analysis , Financial Statements , Notes to Financial Statements , and Supplemental Schedules. The financial statements consist of the Balance Sheets , Statements of Revenues , Expenses , and Changes in Net Position , Statements of Cash Flows , and Supplemental Schedules.

The following Management's Discussion and Analysis ("MD&A") provides unaudited information and analyses of activities and events related to the District's financial position or results of operations. The MD&A should be read in conjunction with the audited Financial Statements and Notes to Financial Statements. The Balance Sheets present assets , deferred outflows of resources , liabilities , deferred inflows of resources and net position as of December 31 , 2017 and 2016. The Statements of Revenues , Expenses , and Changes in Net Position present the operating results for the years 2017 and 2016. The Statements of Cash Flows present the sources and uses of cash and cash equivalents for the years 2017 and 2016. The Notes to Financial Statements are an integral part of the basic financial statements and contain information for a more complete understanding of the financial position as of December 31 , 2017 and 2016 , and the results of operations for the years 2017 and 2016. The Supplemental Schedules include unaudited information required to accompany the Financial Statements.

OVERVIEW OF BUSINESS The District is a public corporation and political subdivision of the State of Nebraska (the " State"). Control of the District and its operations are vested in a Board of Directors

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

The District's chartered territory includes all or parts of 86 of the State's 93 counties and more than 400 municipalities in the State. The right to vote for the Board i s generally limited to retail and wholesale customers receiving more than 50% of their annual energy from the District. The District operates an int egrated electric utility system in cluding facilities for generation , transmission , and distribution of electric power and energy for sales at retail and wholesale.

Management and operation of the District i s accomplished with a staff of approximately 1 , 875 full-time employees. The District has the power , among other things , to acqu ir e , construct , and operate generating plants , transmission lines , substations , and distribution systems and to purchase , generate , distribute , transmit , and sell electric energy for all purposes.

There are no inv estor-owned utiliti es providing r etail electric serv i ce in Nebraska. The District h as no power of taxation , and no governmental authority has the power to l evy or collect taxes t o pay , in whole or in part , any ind ebtedness or obligation of or incurr ed by the District or upon which th e Disbict may be li able. The Oisbict has the right of emi n ent domain. The property of th e Oisbict , in th e opinion of it s General Counsel , i s exempt under th e State Constitu tion from taxation by the State and i ts subd ivision s , but th e Disbict i s required by th e State to m ake payments i n lieu of taxes which are disbibuted to th e Sta t e and v arious governmental subdivisions. The Oisbict h as th e power and i s required to fix, establish , and collect adequate rates and other charges for electrical energy and any a nd all commodities or services sold or furnished by it. S uch rates a nd charges mu st be fair , r easonable , and nondiscrim i natory and adjusted in a fair and equitable m anner to confer upon and disbibute among th e users and consumers of sudl commodities and services the benefits of a successful and profitable operation and conduct of the busin ess of the Di s bict. THE SYSTEM To meet th e anytime peak l oad *n 20 1 7 of 2 , 891.5 megawatt s r MW), the D"sbict had available 3 , 65 1.0 MW of capacity resouroes that i ncluded 3 , 046.2 MW of generation capacity hum 12 owned and operated generating plants and 22 pla ts over which lh e District h as operating control , 447.6 MW of firm capacity purcha ses from the 12 Fimainoiaa

~8iFJOI1t Western Area Power Administration , and 157.2 MW of a capacity purchase from Omaha Public Power District's

(" OPPD") Nebraska City Station Unit 2 (" NC2") coal-fired plant. Of the total capacity resources , 275.7 MW are being sold via participation sales or other capacity sales agreements , leaving 3 , 375.3 MW to serve firm retail and wholesale customers and to meet capacity reserve requirements.

The highest summer anytime peak load of 3 , 030.3 MW was established in July 2012 and the highest winter anytime peak load of 2 , 252.0 MW was established in January 2014 for firm requirements customers.

The following table shows the District's capacity resources from generation and respective summer 2017 accredited capability. Steam -Conventional C:JJ *************.******************************

Steam -Nuclear ............

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

............................. . Combined Cycle ...................................................... . Combustion Turbine C 4> .....................*........................ Hydro ................

...................................................... . Diesel ...............................

...................................... . Wind CsJ ..*.......................*.....*.........*...*....*.**............ Number of Plants (1> 3 1 1 3 6 12 8 34 (1) lndudes three hydro plants and 1 2 diesel plants under contract to the District (2) 2017 summer acaedited net capab i lity based on SPP aiteria. Summer 2017 Accredited Ca~abilify

{MW} (ZJ 1 , 679.3 765.0 220.0 125.3 106.8 93.6 56.2 3 , 046.2 (3) lndudes Gerald Gentleman Stat i on (" GGS"), Sheldon Station (" S h eldon"), and Canaday Station. (4) lndudes the Hallam , Hebron and McCook pea kin g turbin es. (5) lndudes Ainsworth Wind Energy F acility ("Ain sworth") and seven wind facilities un der contract to the District.

Percent of Total 55.2 25.1 7.2 4.1 3.5 3.1 1.8 100.0 The following table shows the generation facilities owned by the District and their respective fuel types , summer 20 17 accredited capability , and i n-service da t es. Ty pe Gerald Gentleman Station lhts No. 1 and No. 2 ......... . Cooper lllJclear Station ...............................

............. . Beamce P0111er Station .........................

.................... . Sheldon Station l.tits No. 1 and No. 2 ................

....... . Combustion Turbi nes (3 generating plalts) ...............

... . Canaday Station ....................................................... . Hydro (3 generating plalts) ...........

............................ . Ainsworth Wind Energy Faciity u 1 *******************.********* (1) 2017 summer accredited net capabiity based oo SPP aiteriia. (2) Nominaly rated al 60 MW. F i lilanci: al :Rep:)(!mt Fuel Type Coal lllJclear Combined Cycle Coal Oil or Nab.Jral Gas Nab.Jral Gas Water Wind Surrmer 20 1 7 Accred i ted Capabilify (MIN) '11 1 , 365.0 765.0 22 0.0 2 15.0 1 25.3 99.3 21.3 8.3 2 , 819.2 ln-SeNce Date 197 9 , 1982 1 974 2005 1961 , 1968 1973 1958 1887 , 1 92 7 , 1939 2005 L THE CUSTOMERS Retail and Wholesale Customers In 2017, the District served an average of 91 , 614 retail customers. Currently the District's retail service territory includes 79 municipal-owned distribution systems operated by the District for the municipality pursuant to a Professional Retail Operations

(" PRO") Agreement.

Details of the District's PRO Agreements are included in Note 12 in the Notes to Financial Statements.

The District serves its wholesale 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 District entered into 20-year wholesale power sales contracts with a substantial number of its wholesale customers (the " 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 districts (20 of which are served under one contract with the Nebraska Generation and Transmission Cooperative), one cooperative , and 37 municipalities. Wholesale customers served under the 2002 Contracts include one public power district and nine 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 (25th percentile or less) for cost per kilowatt-hour

("kWh") purchased , as published by the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The District's wholesale power costs percentile was 28.2% for 2016 , based on the latest available data. Details of the District's Wholesale Power Contracts are i ncluded in Note 12 in the Notes to Financial Statements. The following charts show the District's average retail and wholesale cents per kVVh for the years ended December 31 , 2013 through 2017. The District also reported average cents per kVVh sold less customer collections for taxes and transfers to other governments , wh i ch are not induded in the District's base rates for retail customers. AVERAGE CENTS PER kWh SOLD -RETAIL (Retail -All Classes) 9.80 -.-------------------------.r:. 9.00 3: 8.20 Q) 0.. J!? 7.40 C: Q) u 6.60 5.80 9.04¢ 2013 Average Cents per kWh Sold 9.06¢ 9.12¢ 9.05¢ 2014 2015 2016 2017 Average Cents per kWh Sold Less Government Taxes/Transfers 14 AVERAGE CENTS PER kWh SOLD -WHOLESALE 6.40 6.00 5.91¢ .J:. 3: 5.60 Q) Q. .!!l 5.20 C: Q) u 4.80 4.40 2013 Participation Sales and Other Sales (Firm Wholesale Customers Only) 6.09¢ 2014 5.96¢ 5.93¢ I I I I I I I I I 2015 2016 5.99¢ 2017 There are participation sales agreements in place with other utilities for the sale of power and energy at wholesale from specific generating plants. Such sales are to Lincoln Electric System ("LES"), Municipal Energy Agency of Nebraska ("MEAN"), OPPD , Grand Island Utilities

("Grand Island"), and JEA. The District also sells energy on a nonfirm basis in SPP and through transactions executed with other utilities by The Energy Authority

("TEA"). T r ansmission Customers The District owns and operates 5 , 294 miles of transmission and subtransmission lines , encompassing nearty the entire State. The District became a transmission owning member of SPP , a regional transmission organization , in 2009. The District files a rate with SPP annually that provides for the recovery of all transmiss i on revenue r equirements associated with transmission facilities equal to or greater than 115 kV. SPP collects and reimburses the District for the use of the District's transm i ssion facil iti es by entities other than the District's firm requirements customers and all transmission customers still served directly by the District through grandfathered T r ansm i ssion Agreements.

Fi:n a i: ro.cial Er ei p o rnt Customers and Energy Safes The following table shows customers , energy sales , and peak loads of the System , including participation safes , in each of the three years , 2015 through 2017. Megawatt-Hour Safes Anytime Peak Load (MW} Calendar A\erage Number of Wholesale Nati'.* Load Percentage Total Percentage Busbar Nati'.* Year Retail Customers Customers<1> Sa1es<2 l Growth Sa1es<3 l Growth 14 l Load 2015 91 , 140 82 12 , 579 , 390 (2.7) 20 , 990 , 883 1.6 2 , 695.0 2016 91,457 78 12 , 901 , 989 2.6 18 , 902,173 (10.0) 2 , 963.7 2017 91 , 614 78 13 , 061 , 979 1.2 19 , 568 , 548 3.5 2 , 891.5 (1) At the end of 2017 , i ndudes sales to firm wholesale customers , participation customers (LES , MEAN , JEA , OPPD , Grand Island), and a yearly average of 2 nonfirm customers. In 2016 , three of the District's municipal wholesale customers began purchasing power from three of the District's public power district wholesale customers , and one of the District's municipal wholesale customers allowed their contract to terminate. (2) Native load sales i ndude wholesale sales to total firm requirements customers and the responsibility of replacement power being procured by the District if the District's generating assets are not operating. Predominantly , native load customers are served under long-term total requirements contracts. (3) Total sales from the System i ndude sales to LES from GGS and Sheldon , which sales from Sheldon terminated on December 31 , 2017; to MEAN , JEA , OPPD , and Grand Island from Ainsworth Wnd Energy Facility , which sales commenced October 1 , 2005 , and terminates on September 30 , 2025; to OPPD , MEAN , LES and Grand Island from Elkhorn Ridge Wnd Facility , which sales commenced March 1 , 2009 , and term i nates on February 28 , 2029; to MEAN from GGS and CNS , which sale commenced January 1 , 2011 , and terminates on December 31 , 2023; to MEAN , LES and Grand Island from Laredo Ridge Wnd Facility , which sales commenced February 1 , 2011 , and terminates on January 31 , 2031; to OPPD , LES and Grand Island from Broken Bow 1 Wind Facility , which sales commenced December 1 , 2012 , and terminates on November 30 , 2032; to OPPD , LES and MEAN from Crofton Bluffs Wind Facility , which sales commenced November 1 , 2012 , and terminates on October 31 , 2032; and t o OPPD from Broken Bow 11 Wind Facility which sale commenced October 1 , 20 1 4 , and terminates on September 30 , 2039. T he District and LES executed an agreement i n 2017 to term i nate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing alter December 31 , 2017. (4) The i ncrease i n percentage growth from 2016 to 2017 was due primarily to additional n onfirm energy sales from CNS as a result of 2017 being a non-outage year f or the un it. The decrease in percentage growth from 20 1 5 to 2016 was a result of lower nonfirm energy sales due primarily t o the planned r efueling and maintenance outage at CNS , lower n atural gas prices and additional w i nd generation i n the SPP I ntegrated Marke t. Eilil.alilcia l Rrep>(!rnt FINANCIAL INFORMATION The following tables summar i ze the District's financial position and operating results. As of December 31 , CONDENSED BALANCE SHEETS (in OOO's) 2017 Current Assets ............................................................... . Special Purpose Funds .................................................

.. Utility Plant , Net ..............................

................................ . Other Long-Term Assets ................................................. . Deferred Outflows of Resources

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

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

..... . Total Assets and Deferred Outflows ............................. . $ 858 , 872 746 , 448 2 , 569 , 898 383 , 701 295 , 402 $ $ 2016 775 , 479 782 , 857 2 , 595 , 767 406 , 149 344 , 331 4,904 , 583 Current Liabilities

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

............................................ . $ 4,854 , 321 $ 370,501 1 , 617 , 269 1 , 028 , 467 351 , 651 $ 287 , 322 Long-Term Debt ...........

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

.................................... . Other Long-Term Liabilities

............................................. . Deferred Inflows of Resources

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

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

............. . Net Position ...................................

............................... .. 1 , 486 , 433 Total Liabilities , Deferred Inflows , and Net Position ....... . $ 418541321 CONDENSED RESULTS OF OPERATIONS (in OOO's) For the years ended Decent>er 31 , 2017 1 , 867 , 768 1 , 063 , 118 271 , 258 1,41 5 , 117 2016 Operating Re1enues ...................

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

........... . $ 1 , 101 , 642 $ 1 , 1 53 , 997 Operating E>qlenses

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

........... . (988 , 93 1) (1 , 040 , 715) Operating Income .....................................................

.. 112 , 711 11 3 , 282 Investment and Other Income ................

......................... .. 23 , 59 1 31 , 772 Debt and Other E,q:>enses

............................................... . (64 , 986) (62 , 121) Increase i n Net Position ...................

.......................... . $ 71 316 $ 821933 SOURCES OF OPERATING REVENUES (in OOO's) For the years ended Oeceni>er 31 , 20 17 2016 Rrm Retai l and Wholesale Sales ......................

............... . $ 875 , 312 $ 865 , 661 Participation Sales .............................

............................ . 73 , 199 77 , 996 Olher Sales .................................

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

............... . 112., 209 89 , 492 Olher Operating Re\ienues

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

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

............ . 76 , 182 66 , 060 l..klearned Re\ienues

- - - - {35 , 260) 54 , 788 Total Operating Re\ienues

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

................... . $ 1110\642 $ 111 531997 !Fi i n at.li 1cial Rep@rt 2015 $ 764 , 278 738 , 967 2 , 508 , 971 353 , 639 40 , 775 $ 4,4061630

$ 218 , 858 1 , 838 , 672 727 , 070 289 , 846 1 , 332 , 184 $ 4A06 1 63o 2015 $ 1,097 , 216 {960 , 259) 136,957 22 , 355 (68 , 252) $ 91 1060 2 015 $ 848 , 345 77 , 192 134 , 612 60 , 730 {23 , 663} $ 110971216 CONDENSED STATEMENTS OF CASH FLOWS (in OOO's) For the ~ears ended December 31 , 2017 2016 2015 Net Cash Provided by Operating Activities

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

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

(107 , 438) 2 , 374 10 , 961 Net Cash Used in Capital and F i nancing Activities

............. (332 , 584} (23 8 , 416} (388,483}

Net Increase (Decrease) in Cash and Cash Equivalents

..... (74,925) 17 , 669 (5,019) Cash and Cash Equivalents , Beginning of Year ................. 102 , 729 85 , 060 90 , 079 Cash and Cash Equivalents , End of Year ..................... $ 27 804 $ 1021729 $ 85 1 060 Revenues from F irm Retail and \/Vholesale Sales The District allocates costs between reta i l and wholesale service and establishes it s rates to produce revenues sufficient to meet it s est i mated respective retail and wholesale revenue requirements.

\/Vholesale revenue requirements include unbundled costs accounted for separately between generation and transmission. The rates for retail service include an amount to r ecover the costs of wholesale power service in addition to distribut i on system costs and government taxes and transfers. The District's wholesale power contracts provide for the establishment of cost-based rates. Such rates can be adjusted at such times as deemed necessary by the District.

The wholesale power contracts also provide for the creat io n of a r ate stabilization account. Any surplus or deficiency between revenues and revenue requirements , within certa in limits set forth in the wholesale power contracts , may be retained in the rate stab ili zation account. Any amounts in excess of the limits may be included as an adjustment to revenue requirements in the next rate r eview. The wholesale power contracts also include a provision for establ i shing a new/replacement generation fund. This prov isi on would permit the District to collect an additional

0.5 mills

per k\/Vh above the normal revenue r equ ir ements to be used for future capital expenditures associated with generation. There was no change to the wholesale or retail r ates on Janu ary 1 , 2 018. The District impl emented a 0.6% increase i n the District's wholesale r ates on January 1 , 2017 , for all customers. No incr ease in retail r ates was impl emented in 2017. Th e D i strict i mplemented a 0.6% increase i n th e District's wholesale r ates on Janu ary 1 , 2016 , for those wholesale customers who signed th e new 20 16 20-year wholesale power contract , and a 3.8% i ncrease in the District's wholesale rates on January 1 , 2016 , for those whol esa l e customers who remained under the 2002 20-y ear wholesale power contract. The rate incre ase was higher for th e 2002 Contracts as th ese customers will pay th e ir share of a catch-up in funding for OPEB costs rel ated to prior serv i ce through rates prior t o the exp irati on of th e ir contracts i n 2021. The District financed with t axable debt th e 2016 Contracts custom ers' share of the OPEB catdl-up tru s t funding for 2016 and 201 7 and plans to i ssue add i tional taxable debt i n 2018 for catch-up trust funding. Th e cu sto mers under th e 20 16 Contracts will commence p a yment through rate collections of th e rel ated debt service for their share of the catch-up i n funding for OPEB costs beginn i ng i n 2022 , th e year after the expiration of the 2002 Contracts , and continue making payments through 2033. No i na-ea se i n retail rates was i mplemented

n 20 1 6. Details of the Oisbict's Whol esa le Power Contracts are i nduded i n Note 12 i n th e Notes to F i nancial Statements.

Revenues from finn sales i ncreased $9.6 million , or 1.1%, from $865.7 m i llion i n 20 1 6 to $875.3 m i llion i n 201 7. The i ncrease i n r evenue was due prim a rily to a weather-related 1.2% i na-ease i n energy sales. Revenues from finn sales i ncreased $17.4 m illion , or 2.1%, from $848.3 mill i on i n 20 1 5 to $865.7 mill i on i n 2016. The i ncrease i n revenues from 20 1 5 to 2016 was du e primari l y to a weather-related 2.6% i naease i n energy sales t o firm requ i rements customers. Revenues from Participation Sales Th e D i strict h as participation sales agreements with other uti iti es th at share operating expenses on a pro rata basis. Re v enues from participation sales deaeased r ro m $7 8.0 m i on in 2016 to $73.2 m i llion *n 20 17 , a 18 reduction of $4.8 million. The reduction was due primarily to lower demand revenues for GGS and CNS , along with lower wind participation energy sales. Revenues from participation sales increased from $77.2 million in 2015 to $78.0 million in 2016 , an increase of $0.8 million. The District and LES executed an agreement in 2017 to terminate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing after December 31 , 2017. Revenues from Other Sales Other sales consist of sales i n SPP's Integrated Market and nonfirm sales to other utilities. TEA , of which the District is a member , has energy market i ng responsibilities for the Distr i ct's other and nonfirm off-system sales and the related management of credit risks. Other sales increased from $89.5 million in 2016 to $112.2 million in 2017 , an increase of $22.7 mi ll i on. The increase was a result of higher energy sales due to no refueling and maintenance outage at CNS and higher prices in the SPP Integrated Market due to higher natural gas pr i ces. Other sales decreased from $134.6 million in 2015 to $89.5 million in 2016 , a decrease of $45.1 million. The decrease was a result of reduced nonfirm revenues due to lower energy sales due to the planned refueling and maintenance outage at CNS , lower natural gas prices , and additional wind generation in the SPP I ntegrated Market. Other Operating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues. These revenues were $76.2 million, $66.1 million , and $60.7 million in 2017 , 2016 , and 2015 , respectively.

The majority of these revenues we r e from other SPP transm i ssion customers for their share of qualifying transmission upgrade projects of the D i s trict. Unearned Revenues Under the prov i s i ons of the D i s trict's wholesale power contracts , any surplus or defic i ency between net revenues and revenue requirements , within certain limits set forth in the wholesale power contracts , may be ad ju sted in the rate stabilization accoun t. Any a m ounts in excess of the rate stabil i za ti on limits may be indu ded as a n adjustment t o revenue requirements in th e n ext r ate revi ew. A s imil a r process i s foll owed in accou ntin g for an y surplus or deficiency in r evenues n ecessary t o meet r evenue r equ ir ements for r eta il electric serv i ce. Under generall y accepted acco untin g principles for r egulated elect ri c utilities , the balance of such surpluses or deficiencies a re accounted for as -r egulato ry li ab iliti es or assets" , r espective ly. Th e District recognizes n et rev e nu es in excess of revenue r equireme n ts i n a ny y ear as a deferral or reducti on of r evenues. Such surpl u s r even u es a r e exd uded fr om th e n e t r evenues a v a il able und e r th e General Revenue Bond Resolution

(" General Resolution

) to m ee t d eb t serv i ce requirem en t s for such year. Surpl u s revenu es are indud ed in th e detennination of n et r even u es a v a il ab l e und er th e General Resolution to m ee t debt service requir ements i n th e y ea r that such s urplu s r eve nu es a re t aken into accou nt in se tting rates. Th e District recogniz es any deficiency i n revenu es needed to m ee t rev e nu e requir e m e nts i n any y ea r as an accrual or incr ease in r e v e nu es , even though the r e venu e accrual will not be r ea lized as -cash" until some future rat e period. S uch r evenue deficiency i s *nduded , i n th e ye ar accrued , i n th e n e t r e venu es a v a il a bl e under th e General Resolution to meet debt service requirements for such year. Revenue deficiencies are exduded i n the determination of net revenues available under th e General Resolution to m eet debt service requirements in the y ea r th a t such revenu e deficit i s taken i nto account i n setting rat es. Th e District deferred or decreased revenues a n e t a mount of $35.2 million i n 2017. The D i strict's revenues i n 2017 from electric sales to retail, wholesale , and oth e r utiliti es resulted i n a surplus , or over collection of costs , of $44.9 million , which was deferred (decrease in revenues). In ad dition , the wholesale rates that were i n place for 2017 i nduded a refund of $6. 7 mill i on of surplus net revenu es from past rate period s. Such surplus had previously been accounted for as a reduction i n revenues i n the year (s) the surplu s occurred.

Accordingly , the 2017 revenue s from electric sales , wh i ch reflect the surplus being refunded , were offset by a revenue adjustment (i ncrea se i n revenues) for such amount Th e Di s trict also d e ferred or deaeased revenues by $20.0 m i l ion for the pre-collection of CNS refueling and maintenance outag e co sts. Th i s regulatory liabi ity will be elim*nated through revenue recog iti on during the 20 1 8 outage year. In addition , the D*stnct recognized or* creased r evenues by Fin a ncial Rep0rt

$23.0 million for OPEB expenses related to past service for wholesale customers under the 2016 Contracts. The OPEB expenses were included in 2017 rates and financed with proceeds from General Revenue Bonds , 2016 Series E (Taxable). The District recognized or increased revenues a net amount of $54.8 million in 2016. The District's revenues in 2016 from electric sales to retail , wholesale , and other utilities resulted i n a surplus , or over collection of costs , of $10.0 million , wh i ch was deferred (decrease in revenues). In addition , the wholesale rates that were in place for 2016 included a refund of $17.4 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly , the 2016 revenues from electric sales , which reflect the surplus being refunded , are offset by a revenue adjustment (i ncrease in revenues) for such amount. The District also recognized or increased revenues by $24.7 million for CNS fall refueling and maintenance outage costs , wh i c h costs were pre-collected for i n 2015. This regulatory liability was amortized through revenue during the 2016 outage year. In addition , the District recognized o r i ncreased revenues by $22. 7 million for OPEB expenses related to past service for wholesale customers under the 2016 Contracts. The OPEB expenses were included i n 2016 rates and financed with proceeds from Genera l Revenue Bonds , 2016 Ser i es E (Taxable). The District deferred or decreased revenues a net amount of $23.7 million i n 2015. The District's revenues in 2015 from electric sales to retai l , wholesale , and other ut il ities resulted i n a surplus , or over collection of costs , of $11.0 million , which was deferred (decrease in revenues). In addition , the wholesale rates that were in p l ace for 2015 included a refund of $12.0 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues i n the year (s) the surplus occurred.

Accordingly , the 2015 revenues from electric sales , which reflect the surplus being refunded , were offset by a revenue adjustmen t (i ncrease i n revenues) for such amount. The District also deferred or decreased revenues by $24. 7 million for the pre-collection of CNS refuel i ng and maintenance outage costs. This regulatory l iabil i ty was eliminated throug h revenue recogni ti on during the 2016 outage year. The balance of the regulatory liability for unearned revenues to be applied as cred i ts against revenue requirements in future r ate periods was $206.9 million , $1 68.7 m i llion , and $176.1 m i llion , as of December 3 1 , 2017 , 2016 , and 2015 , r espect i vely. Operat i ng Expenses Th e following chart illustrates operat i ng expe n ses for th e y ea r s e n ded Dece m be r 3 1 , 2 01 5 th rough 2 017. $1,200 Powe r Pur c hased & F uel $1,041 $1,000 Production Operation

& Maintenance

(" O&M") in $800 Transmiss i on & D i str i bution O&M C: .5! i Customer Service & I nformation

-$600 U) ... Administrative

& General .!!! 0 $400 Cl De c ommissioning

$200 Depreciation

& Amort i zation $0 Other 2015 2016 2017 20 Total operating expenses in 2017 were $988.9 million , a decrease of $51.8 million from 2016. Total operating expenses in 2016 were $1 , 040.7 million , an i ncrease of $80.4 million from 2015. The changes were due primarily to the following: Power purchased and fuel expenses were $342.8 million , $347.6 million , and $365.1 million in 20 1 7 , 2016 , and 2015 , respectively. These expenses decreased

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

$17.5 million in 2016 as compared to 2015 due primarily to addit i onal energy purchases from NC2 and the w i nd facilities , and lower fuel costs as the r esult of decreased generat i on. Production operation and maintenance expenses were $243.3 million , $287.7 million , and $242.8 million in 2017 , 2016 , and 2015 , respect i vely. These costs decreased

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

$44.9 million due primar i ly to the costs associated wit h the plan n ed refueling and m aintenance outage at CNS. Transm i ssion and d i str i bution operation and maintenance expenses we r e $100.9 m i llion , $102.0 m i llion , and $87.3 million , in 2017 , 2016 , a n d 2015 , r espect i vely. These costs decreased

$1.1 millio n in 2017 as compared to 2016. These costs i ncreased $1 4.7 million in 2016 as compared to 2015 due prima ri ly to higher fees charged by SPP for the Dist ri ct's share of qual i fying transmission upg r ade projects , including an SPP resettlement for prio r periods for the i mplementation of a tar i ff provision to compensate transm i ssion upgrade sponsors for qual i fying upgrades used by other trans mi ssion customers. C u stomer serv i ce and i nforma ti on expenses were $1 6.0 m i llion , $17.7 milli on , a n d $1 7.2 mi llion , in 20 1 7 , 20 1 6 , and 2015 , r espect i vely. Administrative and ge n era l expenses were $1 06.2 mill i o n , $94.1 mill i o n , and $66.3 m illi o n , in 2 0 17 , 2016 , a n d 2015 , r espect i vely. Admin i s tr a ti ve and gene r al expenses i ncreased $1 2.1 m i llio n in 2 017 as compared to 2016 due pr i ma ri ly t o a r eclass ifi ca ti o n i n 20 1 7 t o in clude all OPEB costs w i th adm i n i s tr a tiv e and general expense , a po rti on of these costs were i ncl u ded i n ope r a ti on and ma i ntenance expense i n p ri or y ears. Th ese cos t s i ncreased $27.8 m i llion in 2 01 6 as co m pared t o 20 1 5 due primari l y to OPEB expe n ses related to p as t serv i ce a n d i ncl u ded i n 20 1 6 ra t es. Deta i ls r egard in g OPEB , i ncl u d i ng th e earl y adoptio n of n ew acco untin g g ui dance in 2 01 6 , a r e in d u ded in No t e 11 in th e No t es t o F in a n cial S t a t emen t s. Deco m m i ss i o nin g expenses w ere $1 9.9 milli o n , $2 1.4 milli on , and $1 4.7 milli o n , in 2 017 , 2 016 , a n d 2 015 , r espectivel

y. P ri o r t o 2 017 , d eco m m i ss i o nin g expe n ses o nly r ep r ese nt ed th e n e t a m o unt a ccru ed ea ch y ea r for th e futu re decom mi ss i o nin g o f C N S. Co mm e nci ng in 2 017 , decomm i ss i on in g expe n ses a l so in d u ded a m ou nts co llected in r a t es for th e futur e d eco mmi ss i o ni ng of certa in n o n-nu clea r utility pl a nt assets. Decom mi ss i on in g expenses a r e record ed in a n a m o unt eq uiv a l en t t o th e in co m e on inv es bn e nts in th e nu clea r f a cility d ecomm i ssio nin g fun d plu s a mount s coll ected f or deco mmi ss i o ni ng in th e ra t es for electric servi ce i n s uch y ea r. Deco mmi ssi onin g e xpen ses d ecreased $1.5 milli o n in 2 017 as compa r ed to 2016. Thi s decr ease wa s du e to a $7.4 milli o n decr ease in inv es bnent i ncom e for th e nud ea r fa cility d eco mmi s sioning fund , which wa s parti a lly o ffse t by $5.9 million i n collection s for d eco mmi ssi onin g o f ce rtain non-nucl ear utility pl a nt asse ts. Deco mmi ssi oning expenses incr eased by $6. 7 milli o n in 2 016 as comp a red to 2 015 du e to a n in aease in int e r es t in co m e o n inv es bnents. No a ddition al a mounts for d eco mmi s sion i ng wer e collected through rat es in 2016 and 2015. Depreci a tion a nd amortization expen ses wer e $1 22.6 m i llion , $1 3 3.7 million , and $130.2 mi lion , i n 2017 , 2016 , a nd 2 01 5 , respectiv el y. The decr ease in d e preciation a nd a mortizati o n expen ses was due prim a rily to a chang e *n th e es tim a t e to lon ger a sset lives for ce rtain transmi ssi on asse ts. Incr ease i n N e t Posiliion The incr ease in net position wa s $71.3 mllion , $82.9 million , and $91.1 million ,

2017 , 2016 , and 2015 , respectively. Th e change *n net position* 2017 as compared to 2016 decreased

$11.6milion and wa s du e F i m a mci al ei p ID ri primarily to a decrease in 2017 revenue requirements from reduced collections for principal payments for debt service and utility plant additions , an increase in unrealized investment losses and lower capitalization of interest during construction.

These decreases in net position were partially offset by a reduction in depreciation expense. The change in net position in 2016 as compared to 2015 decreased

$8.2 million and was due primarily to a decrease in 2016 revenue requirements from decreased collections for principal payments for revenue bonds and construction from revenue, partially offset by increased collections for principal payments on commercial paper notes The following chart illustrates the Distr i ct's operating revenues , other revenues , operating expenses , and other expenses for the years ended December 31 , 2015 through 2017. Revenues & Expenses $1,250

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

U) $1,150 L-------lii~----------

c: .!:! $1,100 +----Ul----------1 [ $1,050 I!! $1,000 +------t $950 __ _, o $900 -i----1 $850 +----1 $800 -'--~-'----2015 2016 2017 FINANCIAL MANAGEMENT POLICY Other Expenses Operating Expenses Other Revenues Operating Revenues The District has a Financial Management Policy (th e " Policy~). which is subject to periodic review and revision s by the Board. This Policy represents general financial strategies and procedures that are impl emented to demonstrate financial integrity and fiscal responsibility i n th e management of the District's business and its assets. Employees must ab ide by all applicable District bylaws , Board resolution s , bond re solutions , federal and state l aws , other relevant legal requir ements and the Policy. DEBT SERVICE COVERAGE Under the Policy , U,e District ha s establ i s hed a minimum debt service coverage ratio on the General Revenue Bonds of 1.5 tim es the debt service on th e General Revenue Bonds. The District's debt service coverage ratio was 2.13 , 1.98 , and 1.84 , i n 2017 , 2016 , and 2015 , respectively. The coverage was provided primarily by U,e amounts collected i n operating revenues for utility plant addit i ons , for principal and int eres t payments on outstanding commercial paper notes and revolving credit agreements , and for payments to Uiose municipalities served by th e District under long-term PRO Agreements. The i ncrease i n the 2017 debt service coverage ratio over 2016 and the increase in the 2016 debt service coverage ratio over 2015 were primarily due to a decrease i n the requ i red debt service deposits.

ANANC NG ACTIVITIES Good credit ratings allow the 0-strict to borrow funds at more favorable i nterest rates. Such ratings reflect only the view of such rating organizations , and an explanation of the significance of such rating may be obtained only from the respective rating agency. There i s no assurance that such ratings will be maintained for any given period of ti me or th at they will not be revised downward or be withdrawn en ti rely by the respective rating agency i f , i n its 22 judgment, circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the market prices of bonds. The District's credit rat i ngs on its revenue bonds were as follows: Moody's Investors Service ............................................................................ A 1 Standard & Poor's Ratings Services ............................................................. A+ Fitch Ratings . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A+ (stable outlook) (stable outlook) (stable outlook) The District plans , pursuant to the Policy , to issue separate series of indebtedness , including separate series of General Revenue Bonds , for production projects and for transmission projects. No more than 20.0% of the amount of outstanding indebtedness issued for production projects , calculated at the time of issuance of each series of such i ndebtedness , or $200.0 million , whichever is less , will be permitted to mature after January 1, 2036 , the end of the 2016 Contracts. Transmission indebtedness issued for transmission projects is expected to mature over the useful life of the asset that is being financed.

New transm i ssion indebtedness may mature after January 1 , 2036. The District's transmission indebtedness i s payable from the revenues received during the term of the 2016 Contracts and from r etail sales and transmission revenues r eceived under various SPP tariffs. After January 1 , 2036 , transmission i ndebtedness will be payable from revenues to be derived from wholesale and retail customers who use the District's transmission facilit i es , as well as revenues from various SPP tariffs. On January 1 , 2018 , the District called the remaining outstanding General Revenue Bonds , 2012 Series C , with a principal amount that aggregated

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

(" TERCA") with two commercial banks to prov i de for loan commitments to the District up to an aggregate amount not to exceed $150.0 million , which replaced it s Commercial Paper Notes program. In April 2017 , the District issued General Revenue Bonds , 2017 Series A and 2017 Series B , in the amount of $86.0 million to refund the General Revenue Bonds , 2007 Series 8. Th e refunding reduced total debt service payments over the lif e of the bonds by $11.8 million , which r esulted in present value sav in gs of $10.0 million. In November 2016 , the District i ssued General Revenue Bonds , 2016 Se ri es C and 20 16 Se ri es 0 , in the amount of $113.5 million to finance the costs of certain generation and transmiss i on capita l projects and refund $61.7 million Tax-Exempt Commercial Paper r TECP"). The District also i ssued in November 2016 , General Revenue Bonds , 2016 Series E (fax ab l e), in the a m ount of $56.1 million t o fund a portion of OPEB costs for customers under 2016 Contracts. In February 2 016 , the District i ssued General Revenue Bonds , 20 16 Se ri es A and 2016 Se ri es 8 , i n th e amount of $139.2 million to advance r efund $138.9 million of bonds and r efund $16.5 million of TECP. The refunding redu ced t otal debt service payments over th e lif e of the bonds by $29.8 million , which resulted i n present value sa ving s of $20.8 million. In January 2016 , th e D istri ct i ss ued TECP in th e amou nt of $43.6 million to refund a portion of th e General Revenue Bonds , 2005 Series C and General Revenue Bonds , 2006 Se ri es A In February 2016 , $16.5 million of TECP was refunded by General Revenue Bonds , 20 16 Series A a nd Series B. Details of the District's debt balances and a ctivity a re in duded in Note 7 in the Notes to Financi al Statements.

CAPITAL REQUIREMENTS Th e B<>arlkluthorized capital projects totaled approximately

$85.0 mi l ion , $109.5 m*mon , and $501.0 mill i on , in 20 17 , 2016 , and 2015 , respectively. The District's capital r equ i rements are funded with moni es generated from operations , debt proceeds , and other available reserve fund s. F i Nar,m i a l R~FJ 0r t Capital projects for 2017 included:

$14.7 million for implementation of Advanced/Smart Metering and Interfaces

$11.2 million for construction of an evaporation pond at GGS * $6.4 m i ll i on for refurbishment of a 115 kV substation in Beatrice , Nebraska Capita l proj e cts for 20 1 6 included:

$22.0 million for construction of a high-voltage transmission line from the Muddy Creek substation to Ord , Nebra s ka * $16.4 million for construction of a h i gh-voltage substation in Holt County , Nebraska and expansion of the GGS 345 kV substation

$12.6 million for installation of sta i nless steel liners in coal silos at GGS Units 1 and 2 Capital projects for 2015 included:

$346.8 million for construction of a high-voltage transmission line and related subst a tions from a GGS substation north to Cherry County , Nebraska and east to a new substation in Holt County , Nebraska * $33.9 million for modifications to the hot flue gas ductwork at GGS Unit 2 * $33.1 million for construction of a high-voltage transmission line from a substation in Stegall , Nebraska to a substation in Scottsbluff , Nebraska There were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $52.7 million , $59.0 million , and $87.2 million for 2017 , 2016 , and 2015 , respectively. The Board-authorized budget for capital projects for 2018 i s $118.9 million. Specific capital projects for 2018 indude: * $25.5 million for retrofit of the low pressure turbine for GGS Un it 2 * $4.5 million for refurb i shment of the main generator exciter at CNS * $4.3 mi ll ion for a train in g facility in Yonc , Nebraska The following chart illustrates the Board-authorized cap i tal projects for the years ended Decembe r 3 1 , 2015 through 2017 , in cluding the Board-authorized budget for the year ended December 3 1 , 2018. $600 $500 -Ill C: $400 .2 *-:ii: $300 -Ill ... Ill $200 0 C $100 $-$501 .*

2015 $110 $1 19 2 01 6 2017 201 8 Budg et RESOURCE PLANNING The District u ses a diverse mix of generation resources sudl as coal , nuclear , n a tural gas , hydro and wind to meet its firm requiremen customer's needs. In 20 17 , th e n on<arbon energy r esources as a percentage of native l oad sales were 65%. 24 Fin a n:cia l l&~J!)@lit The District's last comprehens i ve 20-year Integrated Resource Plan (" IRP") was completed and approved by the Board in 2013. Since that time there have been several changes in assumptions that have now been i ncluded in the limited scope , five-year IRP approved by the Board at the i r March 2018 meeting. The 2018 IRP shows the Distr i ct does not require new resources for the next five years. The changes in assumptions i n the 2018 IRP i ncluded:

2016 Wholesale Powe r Contracts

-The negot i at i on of new contracts w i t h the Distr i ct's wholesale customers , which extended the term 20 years fo r all but ten of t h e current c u stomers. The new contrac t allows a 10% renewab l e self-supply option , or 2 MW , whichever i s greater.

Cooper Nuclear Station Power Uprate -The dec i s i on by the Boa r d n ot to proceed w i th a power uprate at its nuclea r facility , a low-cost resource opt i on i ncluded i n the 20 1 3 IRP , due to a mo r e deta i led evaluation of costs and market r i sk.

Renewable Energy -Th e addit i on of two new w i nd fac i l i ties of wh i c h 7 4 MW will be used to serve the District's firm custome r s. This br i ngs the total amount of w i nd in t h e portfolio of r esou r ces serv i ng i ts fir m customers to 281 M W.

Sheldon Station -The r ecapture of approx i mately 65 MW of capacity and e n e r gy from Sheldon after the Board approved end i ng the participation sale for 30% of Sheldo n's output to LES.

Southwest Power Pool In t egrated Market -In 2014 , SPP com m enced a Day-Ahead , Ancilla ry Services , and Real-T i me Balancing Marke t. The District , in tum , began participa ti ng as a membe r ut i l i ty in the energy m arket place. T h e market coordinates n ext-day generat i on across it s f ootp ri nt to m ax i mize cos t effec ti veness for it s members. The District sells and pu r chases power i n t h e SPP Integrated Market. A significa n t amoun t of r enewables , p ri marily wind , continue to be added i n the SPP Integrated Market.

Hydrogen Generation

-Monolith Materials , Inc. (" Monolith") has expressed a n i nterest to construct and operate a carbon black f acility adjacent t o the D i s tri ct's Sheldon coa l-fi r ed gene r ating facili ty in Nebraska. The co n struc ti on o f th e carbon black facility i s expected to be accompl i shed in two phases. Th e elect ri c l oad t o serve an y Monol i th facil i ty will be served by Norris P u b li c Powe r Dis tri ct , a firm wholesale custome r o f the Dis trict. At full bu i ldout , Monol i th may be the s i ng l e-l a r ges t in dus tri al custome r served in the Dis tri ct's te rri to ry. T h e District en t ered i nto a 20-yea r con tr act wi th Mono lith t o purchase t he carbo n black plants' prod u ction of hydrogen ri ch tail gas , wh i ch will be p r oduced b y Monol i th du ri ng product i on o f carbo n black. The Di s tri ct will have t o conve rt it s ex i st i ng coal-fir ed boile r a t S h e l don Un it No. 2 to bu m th e h ydrogen ri ch tai l gas. T h e bo il er convers i o n i s expected t o r es u lt in a r ed ucti o n of carbo n d i oxide (" CO2"), s ulfu r d i o xi de (" S02"), me r c ury , and ot h e r a ir e mi ss i o n s. G ro undb r ea ki ng for P h ase 1 occurred in O ct obe r 20 1 6 a n d i s expected t o be mecha ni ca lly co m p l e t e in 2 01 8 a nd fully opera ti ona l i n 20 1 9. P h ase 2 co n s tructi o n i s planned t o b eg in i n t h e second h a lf of 2 0 2 0. Th e co mm e rci a l ope r a ti o n da t e (d e fin ed join t l y as th e da t e on wh i c h P h ase 2 i s ca p able o f s ufficient, s t ead y s t a t e h ydrogen rich ta il gas s u pp ly , an d th e S h e ld o n Unit No. 2 bo i le r h as bee n con v e rt ed a nd commi ss i on ed) i s sch ed ul ed f o r th e seco nd qu a rt er of 2 0 2 1. ENERGY RISK MANAGEMENT PRAC TI CES Th e n a tur e of th e Di s trict's busin ess exposes it t o a v a ri e ty of ri s k s , i ndudin g e xpo s ur e to vol a tility i n el ectri c en e rgy an d fuel pri ces , un ce rt a inty in l oad a nd r eso u rce a v a il a bility , th e aeditworth i n ess of it s counterp a rti es , an d th e ope ra ti o n a ri sk s as soci a ted with tr a n sa ctin g in th e whol e sal e e n e rgy markets. To help man a g e e nergy ri sks , i ndu d in g th e ri s k s r elated to th e District's participation i n th e S PP Int eg r a ted M a rk e t , th e D i s trict r el i es upon TEA to both tran sa ct on its behalf i n th e whol esa l e e nergy mark e ts a nd to de v e lop a nd recommend strat eg i es t o m a n age th e Di s trict's exposure to ri sks i n th e whol esale energy m a rk e ts. TEA comb i n es a s trong knowled ge of th e D i s trict's s yst e m , a n i n-depth understand i ng of the whol esa l e e n e rgy m a rk ets , e xperienced peopl e , a nd sta t e-o f-the-art technology t o del iv er a broad range of s tand a rdized a nd cu s tomized energy products and serv i ces to th e Di s trict TEA h as assisted th e D i strict i n d e velop i ng its E nergy Risk Management

(" ERM~) program. The program orig i nat es with th e Board-approved E RM G overn i n g Policy and th e ERM-Approved Products and Li mits Standard. Th ese dooument s establ i sh the ph il osophy , objectiv es , deleg a tion of aulhorili es , approved products and thei r i m i ts on th e 0-stricf s energ y and fuel acti viti es n ecessa ry t o govern its ERM program. Th e objectiv e of the E RM program i s t o *ncrease fuel and energ y price stab i l ity b y hedg i ng th e ri sk of sig ifii can t adverse im pacts t o ca sh W i nan c ial Rep0rt flow. These adverse impacts could be caused by events such as natural gas or power price volatility , or extended unplanned outages. The ERM program has been developed to prov i de assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed. ECONOMIC FACTORS Preliminary data indicated Nebraska's economy experienced a decline in 2017, after three years of slowing growth rates. The State's inflation adjusted , estimated gross state product ("GSP") decreased by 0.8% from the third quarter of 2016 to the third quarter of 2017. The U.S. economy experienced a 2.2% increase in national gross domestic product over the same 12-month period. Previous estimates of Nebraska's GSP were also revised downward.

The third quarter estimates for 2016 , 2015 , and 2014 were decreased 1.3%, 0.9%, and 0.7%, respectively.

Nebraska's decl i ne in GSP over the latest 12 months was due to declines in the " Agriculture , forestry , fishing , and hunting" , " Real estate and rental and leasing" , " Management of companies and enterprises

" , " Construction" and " Utilities" industries.

Nebraska and the Midwest r egion cont in ue to experience unemployment rates that are below the national average. Nebraska's average annual unemployment rate decreased from the revised 2016 value of 3.1 % to 2.9% i n 2017. These rates were well below the national December seasonally adjusted unemployment rates of 4.4% and 4. 7% in 2017 and 2016 , respectively.

After several years of consistently being one of the three states with the lowest unemployment rates , Nebraska's preliminary December 2017 and revised December 2016 unemployment rates were the fourth and ninth lowest in the nation, respectively. The District continues to monitor changes in national and global economic conditions , as these could impact the cost of debt and access to capital markets. CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY The Electric Utility Industry In General The electric utility industry has been , and in the future may be , affected by a number of factors which could impact the financial cond i tion and competitiveness of electric utilities , such as the District. Such factors include , among others:

effects of compl i ance with changing env ir onmental , safety , licensing , regulatory , and legislative requirements ,

changes resulting from energy efficiency and demand-s i de management programs on the timin g and use of electric energy ,

increasing demand by customers for self-managing energy use to l ower their energy costs ,

other federal and state legislative and r egulatory changes ,

increased wholesale competition from in dependen t power producers , marketers , and brokers ,

low market prices for wholesale power , * ~self-generation

by certain i ndustrial a nd commercial customers ,

i ssues relating to the ability to i ssue tax-exempt obligations ,

severe restrictions on th e ab ility to sell to nong ove rnm ental entities electricity from generation projects financed with outstand ing tax-exempt obligations ,

changes from projected futu re l oad requirements

in creases in costs ,

shifts in th e ava il ab ility and relativ e costs of different fuel s ,

in adequate risk m a nagement procedur es and practices with respect to , amo ng other things , the purchase and sale of energ y , fuel , and transm i ssion capacity ,

effects of fin ancial i n stabi lity of various participants i n the power market,

dimate change and the potential contributions mad e to dimate ch ange by coal-fired and other fueled generating units ,

incr eased regulation of nucl ear power pl ants *n the United States resulting from the earthquake and tsunam i damage to certain nuclear power pl an t s i n Jap a n , and

issu es rel a tin g to cyber and physi ca l security. Any of these general factors (as well as other factors) could hav e an effect on the financial condition of the Di s trict. 26 iEi , llalQoial Report Competitive Environment in Nebraska While wholesale competition is expected to increase in the future , there is a Nebraska statute that prohibits competition for retail customers. Pursuant to state statutes , retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories.

Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppliers and/or pursuant to an order of the Nebraska Power Review Board. While state statutes do not provide for wholesale suppliers of electr i city to have exclusive rights to serve a particular area or customer at wholesale , wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements. F i:na m 1cial R!e_l!><!ll1t REPORT OF INDEPENDENT AUDITORS T o the Board of Directors of the Nebraska Public Power District: We have audited the accompanying financial statements of Nebraska Public Power District (the " Distr i ct"), which compr i se the balance s heets as of December 31 , 2017 and 2016 , and the related statements of revenues , expenses , and changes i n net pos i tion , of cash flows , and the related notes to the financial statements for the years then ended. Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of the financia l statements in accordance with accounting p rinciples generally accepted in the United States of America; this includes the design , i mplementation , and maintenance of internal c ontrol relevant to the preparation and fair presentation of financial statements that are free from material misstatement , whether due to fr aud or error. Auditors' Responsibility Our responsibility is to express an op ini on on the financial statements based on our aud i ts. We conducted our aud its i n accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the a udit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

A n audit i nvolves perform in g procedures to obta i n aud it evidence about the amounts and disclosures in the financial s t atements. The p rocedures selected depend on our ju dgment , including the assessment of the risks of material misstatement of the financial s tatements , whether due to fraud or error. In making those risk assessments , we consider i nternal control relevant to the District's p reparation and fa i r presentation of the financial statements i n order to des i gn aud it procedures that are appropriate in the circumstances , but not for the purpose of expressing an opinion on the effectiveness of the District's int ernal control. Accordingly , we e xpress no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of sign i ficant accounting estimates made by management , as well as evaluating the overall presentatio n of the financial statements. We b elieve that the audit ev i dence we h ave obta in ed i s sufficient and approp ri ate to prov i de a basis for o ur audit op ini on. Opinion In our opinion , the financial statements r eferred to above present fa irty , in all material respects , the fin ancia l pos iti on of th e District as of December 31 , 2017 and 2016 , and the results of i ts operations and i ts cash flows for the years then ended in accordance with accounting principles generally accepted i n th e United States of America. Emphasis of Matter As d i scussed i n Note 1 and No t e 9 to th e fin ancial sta t eme nt s , th e District changed th e manner in which it acco unts for Asse t R etirement Obliga ti ons in 2017. Our op i nion i s not modifi ed with respect to thi s matter. Other Matters The accompany in g m anagemen t's di scuss i on a nd a n a ly s i s a nd th e s upplem ental schedules on pages 11 through 27 and 65 through 6 7 , respectively , are required by acco untin g principles generally accepted i n the Unit ed States of Ame ri ca to suppleme nt th e b as i c fin ancial stateme nts_ S uch i nfonna ti on , although not a p a rt of th e bas i c fin a nci al sta tem e nts , i s requ i red by th e Governmenta l Accounting Sta ndard s Board who considers it to be a n esse nti al p a rt of fin a nci a l reporting for placing th e basic fin a nci a l sta tem e nts i n an appropriate operational , econom ic, or hi s tori ca l context. We h a v e applied certa in li mited procedures t o th e requ i red supplementary

nfonn a li on in accorda n ce with a uditing standards generally accepted i n th e United Sta t es of Ame ri ca , which consisted of inquiri es of m a n ageme nt abo ut th e m e thods of prepa rin g th e

nfonn a ti on a nd comp a rin g th e infonn a lion fo r cons i ste ncy with m a n ageme nt's responses t o our in qu iri es , th e b as ic fin ancial sta tements , and o th e r knowled ge we obtained du rin g o ur a udits o f the basic fi nancia l s tatements. We do n ot express a n oJfn*on or pro v't de a ny ass u ra n ce on th e -nfonn a li o n because th e imited procedu r es do n ot provide u s with suffici e nt evidence t o express an op" nion or provide a ny assura nce. Our a udits were conducted for th e purpose o f l'onning opin on s on th e fin a nci a l statements th at co lectively compl1ise th e Disb1idt's basic fin a cial statements. The sra li stical review is presented for purposes of add iti onal analysis and -s n o t a required part of lhe basic fin ancial stateme n ts. S uch i nformaliion h as ot been s ubj ected to th e a d itin g procedures applied in th e a udi ts of th e basic fin a cial s tatements , a nd aooord ingly , do not express an op*nion or provid e a ny ass ranee on it ~0) Sit. Lou* s , Mi sso ri April 1 2 , 20 1 8 28 Fin.alilcial B!eport FINANCIAL STATEMENTS Nebraska Pub l ic Power Distr i ct B al a nce Sheets as of December 31 , (i n OOO's) ASSETS AN D DEFERRED OUTFL0\11/S Current Assets: Cash and cas h equivalents

....................................................................... . I nvestrnents

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

...........

................................................... . Receivables , less allowance for d o ubtful accounts of $541 and $530 , respectively

.............................................................. . Fossil fuels , at average cost ..................................................................... . Mater i als and supplies , at average cost ..........

........................................... . Prepayments and other current ass e ts .........................................

............ .. Spec i al Purpose Funds: Construction funds .................................................................................. . Debt reserve funds ......................................................

............................ . El'Tl)loyee benefit funds ...............................................

............................ . Decorm,issioning funds .......................................................................

.... . Utitity Plant, at Cost Utitity plant in service .......................................

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

.......... . Less reserve for deprec i ation ...........

........................................................ . Construction IMlrk in progress ..................

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

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

......... . Nuclear f uel , at amortized cost ................................................................. . Other Long-Term Assets: Regulatory asset for other postel'Tl)loyment benefits ................................... . Long-term capacity contracts

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

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

...................................................... . I n vestment in The Ener gy Authority

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

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

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

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

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

...................................... . Deferred Oulflows of Resources: Asset retirement obligation

....................................................................... . Unamortized cost of refunded debt*************************************-*-*-*-*-************** Other poslernployment benefits .................

................................................ . 2017 $ 27 , 804 539 , 1 7 3 120 , 254 43 , 264 111 , 644 16 733 858 , 872 54 , 808 88 , 764 1 , 934 600 , 942 746 448 4 , 928 , 370 2 , 658 206 2 , 270 , 164 1 33 , 515 166 219 2 , 569 , 898 2 1 0 , 362 152 , 83 1 8 , 20 1 6 , 17 5 6132 383 70 1 4558 9 1 9 222 , 369 38 , 430 34 , 603 295,402 T O T AL ASSETS AN) DEFERRED OUTFLCMIS

- - - - -*********************** LIABILITIES , DEFERRED IIIFLCMIS , AN) !ET POSITION I 4 , 854 , 32 1 Cu rrent Liabiliti es: Rellenue bonds , curren t************************************************-*******-**-*****-********** Noles and c r ed i t agreements , current ........................................

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

Accounts payable and accrued li abi liti es*-**--*-******-*----------*---------****-*-*--*--**-Accrued i n li e u of tax payments ... *-......................... *****-************ ................ . Accrued pa y ments ID r etail c011TI1Un iti es **********-**************************

- - - - -Accrued ~ted absences*--***-*-*-*-*-*-*-**-************-******-*-**--*****-****---Olher *-*---*-*-***-*****-***-*-***********-*-*******************************************-

- - - - Long-Term Debt Rellenue bonds , net of current**-*-******-**-**-*--*-*-*****-*****-************************-***** Noles and credit agreements. net d current**************-******************************** Olher Long-Term Liabiliti es: Asset retirement obligation . *********************************************-*-*********************-* Nell: dher ~ymenl benefit li ability .................................................. . Olher **********-**-***********-*-*-*****-********************** ********-************************************ Total Liabiliti es***********************-************************************************

- - - - Defened lnfbws d Resourt:es::

lklearned relBIIJeS

- - - - Olher deferred i nfbws ......................................

....................................... . Nell: Pos* " oo: Nell:

mes!lnent in capilal asse1s .........................

....................................... . Resilricied

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

- - - - lJlnlresilrit:I

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

- - - - lOTAL LIABILITIES , DEFERRED I IIFLONS , AN) tET POS ITIOII ................. . The ac companying notes to financial st atements are an i ntegral part of these statements. Fi i:nwncial R!epornt $ 98 , 205 165 , 212 64 , 981 10 , 000 6 , 074 16 , 97 1 9058 370501 1 , 548 , 269 69000 1,617, 269 823 , 794 1 82,835 2 1 838 1,028,467 3,016,237 206 , 927 1 44.724 35 1, 65 1 1 , 029 , 230 37 , 782. 4 1 9421 1., 486.433 i 4.,854,321 2016 $ 102 , 729 373 , 331 1 23 , 905 43 , 620 11 4 , 640 17 254 775 479 106 , 204 90 , 032 4 , 851 581 770 782 857 4 , 835 , 829 2 573 645 2 , 262 , 1 84 135 , 853 197 730 2 , 595 , 767 221 , 973 159 , 445 8 , 945 6 , 370 9416 406149 4 , 560 , 252 2 1 9 , 378 42 , 664 82 , 289 344 331 I 4 , 904 , 583 $ 8 1 , 250 74 , 000 87 , 061 10 , 008 6 , 037 17 , 594 11372 287 , 322 1 , 678 , 844 188924 1867768 801 , 147 258 , 609 3362 1,063,118 3,218 , 208 1 68,,710 102,548 2 71, 258 928 , 967 38 , 776 44 7.374 1,.415 , 117 i 4,904.,583 Nebraska Public Power Distr i ct Statements of Revenues , Expenses , and Changes in Net Position For the years ended December 31 , (in OOO's) Operating Revenues ..............................................................

....................... . Operating Expenses: Power purchased

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

Fuel .......................................................................................

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

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

........................................ . Transmission and distr i bution operation and maintenance

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

.......... . Customer service and i nformation

............................................................. . Administrative and general ..................................

..................................... . Payments to retail communities

................................................................ . DecomlTlissioning

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

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

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

........ . Payments in lieu of ta>les ......................................................................... . Operating Income ........................................................................................ . Investment and Other Income: Investment i ncome ................................................................................... . Other income .......................................................................................... . Increase in Net Position Before Debt and Other Expenses ............................... . Debt and Other E>cpenses: Interest on long-term deb t ........................................................................ . Alowance for funds used du ri ng construc ti on ............................................ . Bond premium amortization net of debt i ssuance expense ...................

....... . Other expenses ........................................................................................ . Increase i n Net Posi ti on ............................................................................

.... . Net Position: Beginn i ng balance .................................................................................... . Ending balance ....................

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

..................... . $ $ 2017 1 , 101 , 642 161 , 963 180 , 858 243 , 332 100 , 945 1 5 , 988 106 , 190 27 , 102 19 , 934 122 , 559 10 , 060 988 , 931 112,711 20 , 09 1 3 , 500 23 , 59 1 1 36 , 302 7 6 , 1 86 (2 , 3 17) (1 2 , 598) 3 , 7 1 5 64 , 986 7 1 , 3 1 6 1 , 41 5 , 117 1 , 486 , 433 The accompanying notes to financial statements are an integral part of these statements. 30 2016 $ 1 , 153 , 997 177 , 121 170 , 450 287 , 672 101 , 952 17 , 696 94 , 112 26 , 553 21 , 429 133 , 666 10 , 064 1 , 040 , 715 113 , 282 28 , 239 3 , 533 31 , 772 145 , 054 75,4 1 5 (4 , 1 2 0) (11 ,42 7) 2 , 253 62 , 12 1 82 , 933 1 , 332 , 1 84 $ 1 ,4 1 5 , 117 f i~mm ia[ Rr~J)(i H i t Nebraska Public Power District Statements of Cash FloVvS For the years ended December 31 , (in OOO's) Cash FloVvS from Operating Activities

Receipts from customers and others ................................................

......... . Other receipts ...........

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

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

....................... . Payments to suppliers and vendors ........................................................... . Payments to employees

..........

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

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

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

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

......... . Cash FloVvS from Investing Activities

Proceeds from sales and maturities of investments

..................................... . Purchases of investments

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

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

..................... . Income received on investments

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

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

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

........... . Net cash prm,;ded by (used in) investing activities

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

..................... . Cash Flows from Capital and Related Financing Activities:

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

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

.... . Proceeds from notes and credit agreements

.............................................. . Capital expenditures for utility plant ........................................................

... . Contributions in aid of construction and other reimbursements

.................... . Principal payments on long-term debt ..............................

......................... . Interest payments on long-term debt .............

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

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

..... . Interest paid on defeasance debt ..................

............................................ . Principal payments on notes and credit agreements

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

....................... . Interest payments on notes and credit agreements

..................................... . ()ther non-operating revenues ..................................

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

..... . Net cash used in capital and related financing activities

......................... . Net increase (decrease) in cash and cash equivalents

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

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

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

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

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

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

................ . Reconciliation of Operating In come to Cash Provided By Operating Activities

Operating i ncome ...................................................................

................... . Adjustments to reconcile operating income to net cash provided by operating activi ti es: Depreciation and amortization

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

....... . Uldistributed net r e\letlue -The Energy Authority

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

...... . Decormissioning , net of customer conbibutions

................................... . Amortization of nuclear fuel ...........................................

...................... . Changes in assets and liabiliti es v.hich (used) provided cash: Receivables , net .......................................

..................................... . Fossil fuels ..............................................................

...................... . IIAaterials and supplies .................................................................... . Prepayments and other current assets ............................................ . Olher long-term assets ......................................................

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

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

.... . Accounts payable and accrued payments to relail COffflUliti es ......... . lk1earned re,,ienues

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

... . Olher deferTed i nflows .................................................................... . Olher liabiliti es ............................................................................... . Net cash provided by operating ac ti\iti es ...............

............................... . Supplemel Ital .V thl-Cash Capital Acti\ities

Change in utiily plant adcitions in accool1ls payable .................................. . The accompanying notes to financial statements are an i ntegral part of these statements. F i n ai ncia~ R~po n t $ $ $ $ $ 2017 2016 1 , 112 , 281 $ 1 , 067 , 143 679 209 (503,685)

(565,252)

(244 , 178) (248 , 389) 365 , 097 253 , 711 2 , 792 , 011 2 , 775 , 601 (2 , 920 , 411) (2,800 , 722) 20 , 962 27,495 (107,438) 2 , 374 96 , 957 354 , 776 98 , 737 163 , 807 (1 40 , 665) (261 , 900) 9 , 062 1 8 , 864 (191 , 160) (284,710)

(76 , 920) (77,776) (1,1 07) (10 , 194) (1 27 , 449) (1 42 , 583) (3 , 554) (2 , 145) 3 , 515 3 , 445 {332 , 584) (238 , 416) (74 , 925) 17 , 669 102 , 729 85 , 060 27 804 $ 102,729 11 2 , 711 $ 11 3 , 282 1 22 , 559 133 , 666 10 8 648 14 , 006 2 1 , 429 43 , 490 40 , 754 5 , 409 (10 , 911) 356 (4 , 285) 2 , 996 2,790 443 1 , 022 938 935 (45 , 654) (11, 275) 19 , 122 38 , 217 (7 , 408) 33 , 404 (1 4 , 342) 1 , 735 2 , 663 3652097 $ 253µ111 (10i768l $ 42273 NOTES TO FINANCIAL STATEMENTS

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES: A. Organization

-Nebraska Public Power District (" Distr i ct"), a public corporation and a political subdivision of the State of Nebraska , operates an integrated electric utility system which i ncludes facilities for the generation , transmission , and distribution of electr ic power and energy to its Retail and Wholesale customers. The control of the District and its operations i s vested in a Board of Directors

(" Board") consisting of 11 members popularly elected from districts comprising subdivisions of the District's chartered territory. The Board is authorized to establish rates. B. Basis of Accounting

-The financial statements are prepared in accordance with Generally Accepted Accounting Principles

(" GAAP") for accounting guidance provided by the Governmental Accounting Standards Board (" GASS") for prop ri etary funds of governmental entities. In the absence of established GASS pronouncements , other account i ng literature i s followed including guidance provided in the Financial Accounting Standards Board (" FASS") Accounting Standards Codification

("ASC"). The District applies the accounting policies established in the GASB codification Section Re10 , Regulated Operations. This guidance permits an entity with cost-based rates and Board authorizat i on to include revenues or costs in a period other than the period in which the revenues or costs would be reported by an unregulated entity. C. Revenue-Retail and wholesale revenues are recorded in the period in which serv ices are r endered. Revenues and expenses related to providing energy serv i ces in connection with the District's principal ongoing operations are classified as operating.

All other revenues and expenses are classified as non-operating and reported as inv estment and other income or debt and other expenses on the Statements of Revenues , Expenses and Changes in Net Position. D. Cash and Cash Equivalen ts -The operating fund accounts are called Revenue Funds. There i s a sepa r a t e inv es tm e nt accoun t for the Revenue Funds. The District reports highly liquid inv estments in the Revenue Funds with a n original maturity of three months or less to be cash and cash equivalents on the balance sheet , except for th ese type of inv estments in the Revenue Funds inve stmen t account. Cash and cash equivalents in the i nvestment accoun t s for the Revenue Funds and the Special Purpose Funds are r eported as investments on the balance sheet. E. Fossil Fuel and Materials and Supplies -The District maintains in ventories for fossil fu els and materials and suppl i es which are valued at average cost. Obsolete in ventory i s expensed and r e moved from inventory. F. Utility Plant , Depreciation , Amortization , and Maintenance

-Utility plant is stated at cost, which in dudes property additions , repl aceme nts of units of property and bettennents. The Distrid charges mainten ance and r epa ir s , i nduding the cost of renewals and replacements of minor items of property , to maintenance expense accounts wh e n incurred. Upon retirement of property subject to depreciation , the cost of property i s removed from the plant accounts and charged to the r eserve for dep r eciation , net of salvage. The O" s bict r eoords depreciation over the estimated useful li fe of th e property primarily on a stra i gh t-l i ne basis. Depreciation on utility plant was approximately 2.3% and 2.6% for th e y ears ended December 31 , 20 17 and 20 16. The Di s trid had fully depreciated utility plant, p rim a rily rela t ed to Cooper Nuclear Sta tion r cNS m), which was still in service of $9 7 8.1 m*ll i on and $92 7.5 million as of December 3 1 , 20 17 and 20 16 , respectiv ely. The O istrid has long-term Professional Reta il Operations r PROm) Agreements with 79 mun*apal iti es for certain r etail eledric distribution systems. These PRO Agreements obligate the District to m ake payments based on gross revenues from the munici palities and pa y for normal property add ition s during the tenn of th e agreements. Th e O i s tri d recorded provisions , net of retirem ents , for a mortization of these plant a ddition s of $7.5 million and 32 Finm10ia~

R~}iHilTt

$5.9 million in 2017 and 2016 , respectively , which was included in depreciation and amortization expense. These plant additions , wh i ch were fully depreciated , totaled $191.8 million and $185.6 million as of December 31 , 2017 and 2016 , respectively. G. Allowance for Funds Use d During Cons t ru c tion (" AFUDC'J -Th i s allowance , which represents the cost of funds used t o finance construction , i s capitalized as a component of the cost of the ut i lity plant. The capitalizat i on r ate depends on the source of financing. The rate for construction fi nanced 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 commerc i al paper (" TECP"}, tax-exemp t revolving credit agreement

(" TERCA"}, or taxable revolving c r edit agreement

(" TRCA") is charged a rate based upon t he projected average i nterest cos t of the related debt outstand i ng. The TECP program was terminated i n 2017 a n d r eplaced with the TERCA. For t he periods presented herein , t he AFUDC r ates for construction funded by revenue bonds var i ed from 2.2% to 4.9%. For cons t ruct i on financed on a short-t erm bas i s , the r ate was 1.0% for 20 1 7 an d 2016. H. Nuclear F u el -Nuclear fuel i nventories are i ncluded i n ut i l i ty plant. The nuclear fuel cycle requirements are satisfied through t he procurement of raw mate ri al i n the form of natural uran i um , convers i on serv i ces of such mate ri a l to uraniu m hexafluoride , uranium hexafluor i de that h as already been converted fro m u ranium , en ri chment serv i ces , and fue l fabrication and related serv i ces. The District purchases uranium and uran i um hexafluoride on the spot marke t and carries inventory i n advance of the refueling r equirements and schedu l e. Nuclear fuel i n the reacto r i s be i ng amortized on t he bas i s of ene r gy produced as a percentage of tota l energy expected to be produced. Fees fo r d i sposal of fuel i n the reactor a r e be i ng expensed as part of t he fuel cos t. I. Unamort i zed Financing Cos t s -Th ese costs i nclude i ssuance expenses fo r b onds wh i ch a r e be in g amo rti zed over t he li fe of the respective bonds us i ng the bonds outstand in g m ethod. Deferred una m ortized financing costs associated wi th bonds refunded a r e amortized using the bonds o ut stand i ng me th od over the shorte r of the o ri g i nal or r efunded life of th e r espect iv e bonds. Regula t ory accoun ti ng , GASS cod ifi ca ti o n se cti o n Re 1 0 , Regula t ed Operations , i s u sed to amortize these costs over the ir r espective pe ri ods. J. Asset Ret i rement Obligat i ons -Asse t r etiremen t ob l iga ti o n s (" ARO") represen t th e bes t es tim a t e of th e curr en t va lu e of cas h ou tl a y s expected to b e in curred f or lega ll y enforceable r e ti reme nt ob li ga ti o n s o f t ang i ble cap i ta l asse t s. Reg u la t o ry acco untin g , GAS B cod ifi catio n se cti o n Re 10 , Regulated Operat i ons , i s u sed t o r ecog ni ze th ese cos ts cons i s t e nt with th e rate tre a tm e nt. K. Other Postemployment Be n efits (" OPEB'J -For p u rposes o f m eas urin g th e n e t OPES li a bility , d e ferr ed outfl ows o f r eso ur ces a nd d e ferred i nfl ows of r eso u rces r ela t ed t o OPEB , a nd OPEB expe n se , information abo ut th e fi d uci a ry n e t pos iti o n of th e Di s trict's P oste m plo ym e nt M ed i cal a nd Lif e Be n e fit s Pl a n r P l a n") a nd a d d iti o n s to/d ed uction s from th e Pl an's fiduciary n e t position h a v e bee n d e termin ed on th e sa m e ba s i s as th e y a r e r epo rted by th e P l a n. For thi s purpo se , the P l a n r ecog niz es ben e fit p a ym e n ts when du e and payabl e in a ccor da n ce with th e ben e fit t e rm s. Investm e nts a re r e port ed at fair valu e , e x ce pt for cert a in i nv es tm e nts in real es tat e which ar e reported at n e t asse t valu e. L. Auction Re v enue Rights and Transmission Congestion Rights-Th e Di s trict u ses Aucti o n R e venu e Ri g ht s rARR") a nd Transmission Con ges tion Rights f'TC R") i n th e S outhwest Power P ool r sP P") Int eg rated M a rk e t to hed ge a gainst tran s m i ss i on con ges tion ch a r ges. These fin a ncial in s trumen ts wer e primarily design ed to allow firm transm i ssion rustom ers th e opportunity to offset price diff erences du e to transmission con g estion costs between resou rces and l oads. Awarded ARR provide a fixed revenue stream to o ffse t cong es tion co s ts. TCR can be a cquired through the conv e rsion of ARR or purchases from S P P a uctions or second a ry m a rk e t trades. F i nancial R~p(i)n t M. Deferred Outflows of Resources and Deferred Inflows of Resources

-Deferred outflows of resources are consumptions of assets that are applicable to future reporting.

Regulatory accounting is used for ARO. The ARO deferred outflow is the difference between the related liability amount and rate collections. The cost of refunded debt is the difference in the reacquisition price and the net carrying amount of the refunded debt in an advance refund i ng. Deferred outflows related to OPEB in clude contributions made during the current year and actuarial experience losses. Deferred inflows of resources are acquired assets that are applicable to future reporting periods and consist of regulatory liabilities for unearned revenues and other deferred inflows. Other deferred infl ows include Department of Energy ("DOE") settlements , nuclear fuel disposal collections , CNS outage collections , OPEB actuarial experience gains , a settlement for term i nation of a participation power sales agreement , non-nuclear decommissioning collections and a sales tax refund from the State of Nebraska for the construction of a renewable energy facility. The District i s required under the General Revenue Bond Resolution

(" Resolution

") to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses , aggregate debt service on the General Revenue Bonds , amounts to be paid into the Debt reserve fund and all other charges or liens payable out of revenues. In the event the District's rates for wholesale service result in a surplus or deficit in revenues during a rate period , such surplus or deficit , within certain lim it s , may be retained in a rate stabilization account. Any amounts i n excess of the limits will be taken int o account in projecting revenue requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the D i strict's long-term wholesale power supply contracts. The District accounts for any surplus or deficit in revenues for retail serv i ce in a similar manner. The following table summarizes the balance of Unearned revenues as of December 31 , 2017 and 2016 and activity for the years then ended (in OOO's): 2017 2016 Uiearned re1.e1ues, beginning of year .............................

................................. . $ 168 , 710 $ 176 , 118 Surpluses

........................................................................................................ . 44 , 888 9 , 992 Use of prior period rate stabilization funds in rates ............................................. . (6 , 671) (17 , 400) Uiearned revenu es , end of year .............................

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

....................... . ------$ 206 , 927 $ 168 , 710 The DOE settlement regulatory li ability was establ i shed for th e r eimbursement from th e DOE for costs incurr ed by the District in conjunction with the disposal of spent nudear fuel from CNS. Details of the District's DOE settlement are induded in Note 12 in the Notes to Financial Statements. The District i ndudes in rates the costs associated with nuclear fuel disposal. Such collections were r em itt ed to the DOE under the Nuclear Waste Policy Act until the DOE adjusted the spent fuel disposal f ee to zero , effective May 16 , 2014. Th e Board authorized the use of regul atory accounting for the continued collection of th ese costs. This approach ensures costs are recognized i n the approp riate period with rustomers receiving the benefits from CNS paying th e appropriate costs. The expense for spent nucl ear fuel disposal i s recorded at th e previous DOE rate based on net electricity generated and sold and th e regulatory liability will be elimin ated when payments are mad e for spent nucl ear fuel d i sposal. Additional details of the D i s trict's DOE spent n uclear fuel collections are in cluded i n Note 1 2 in the Notes to F i nancial Statements. 34 Beginning in 2017, the District began collecting revenues for the costs of the 2018 CNS refueling and maintenance outage. This regulatory liability was included in Other deferred inflows on the Balance Sheets and will be amortized through revenue during 2018 , the year of the outage. The District and Lincoln Electr i c System (" LES") executed a termination and release agreement in May 2017 for the Sheldon Station Participat i on Power Agreement.

The Board authorized the use of regulatory accounting fo r the sett l ement payment as the term of the Agreement was for the life of Sheldon Station (" Sheldon"). Th i s regulatory liability was i ncluded i n Other deferred inflows on the Balance Sheets and will be eliminated as revenues from the settlement payment are i ncorporated in future r ates. The District began collecting i n rates for non-nuclear decommissioning costs in 2017. The collect i ons for assets which do not have a legally required re ti rement obligat i on a r e recorded as a regulatory l i ability , i nstead of a n ARO , and are i ncluded i n Othe r deferred i nflows on the Balance Sheets. The following table summarizes the balance of Deferred outflows of resources as of December 31 , 20 1 7 and 2016 (in OOO's): 2017 Asset retirement obligation

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

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

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

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

..................................................... 38 , 430 OPES contributions after the measurement date . .. . .. .. . . .. .... ........... .. . . . ... . ... . . . . . . . .. . . 28 , 290 Unamortized OPES losses for differences i n actual and eiq:>ected earnings .. . .. ... . . . 3 , 283 Unamortized OPES losses for differences i n actual and eiq:>ected e>q:>er i ence ........ ____ 3._, 0_3_0_ $ 295 , 402 2016 $ 219 , 378 42 , 664 74 , 658 3 , 862 3 , 769 $ 344 , 33 1 T h e following table summa ri zes t he balance of Other defe rr ed i nflows of r esources as of December 3 1 , 20 1 7 an d 20 1 6 (in OOO's): 20 17 20 1 6 DOE settlements

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

.... .. ..... .. ... . .. . .. . . ............ .. .... ... ....... ... ... $ 66 , 227 $ 82 , 664 ~clear fuel d i sposal colec tion s ...................................................

...................... 2 1 , 57 0 1 5 , 0 98 CNS outage colections

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

...... .. . ....... ....... ........... ....... ... ...... .. .. .. ... .. .. .. 2 0 , 005 Unamortized OPEB gains f or d iff erences in ac tu al and eiq:>ected e>Cpe ri ence ......... 1 6 , 4 7 5 Settlement for temination of partic i pation power sales agreement......................

... 10 , 500 Non-nuclear decormission in g colec ti ons ...........................................................

5 , 444 Renewable energy f ac ili ty sales lax r e fu n d ....................................................

...... ___ 4~, 5_0_3_ 4 , 7 86 $ 1 44 , 724 $ 10 2 , 548 N. Net Position -Ne t positio n i s m ade u p o f thr ee co mpon e nts: N e t inv es tment i n cap i tal assets , R es tricted , a n d Unr es trict ed. N e t inv es tm en t i n cap ital assets co n s i s t ed of utility pl an t asse t s , n e t of a ccumu la t ed d epreci ati o n and r ed u ced by th e outsta n d in g b ala n ces of a ny bond s or n o t es th at a r e a ttrib uta bl e t o th e a cquisition , co nstruction , or impr o v e m e nt of th ese asse ts. Thi s component also i nclu ded l o n g-t e rm cap acity contra cts , n e t of the outstanding balances of a ny bo n ds or not es a ttributabl e to th ese asse ts. Res tri cted n e t positi o n consisted of th e Prim a ry acco unt in th e D e bt r eserve fund s th a t a re required deposits und er th e R esoluti o n a nd th e Decommi ssi on*n g fund s , n e t of any rel a ted li ab iliti es. Unrestrict ed n e t position consi s ted of any remainin g net position th a t d oes not m ee t th e definition of Net inv es tm e nt in ca pital assets or Restricted and i s u sed to provi de for working capital to fund norH1ud ear fuel and in ventory requiremen ts , as well as oth er operating need s of the District. Financial R!e , p>@lit

0. Use of Estimates

-The preparation of financ i al statements i n conformity with accounting pr i nciples gene r ally accepted i n the United States of America requires management to make estimates and assumpt i ons that affect the reported amounts of assets and liabilit i es and d i sclosure of contingent assets and liabilities at the date o f t he financial statements and the reported amounts of revenues and expenses during the reporting pe ri od. Actual results could differ from those estimates. P. Recent Accounting Prono u ncements -GASS Statement No. 87 , Leases , was issued in June 2017. This Statement will b rin g substant i ally all leases fo r lessees on to the balance sheet. For operating leases , lessees will be required to recognize an asse t for the righ t to use the leased i tem and a corresponding lease liabil it y. Lease liabil i t i es will be considered long-term debt and l ease payments will be capital financing outflows in the cash flow statement.

In the ac ti v i ty statement , lessees will no longer report rent expense for operating-type leases , but w i ll instead r eport interest expense on the l i ability and amort i zation expense related to the asset. Fo r lessors , the account i ng will mirro r lessee accounting. Lessors will r ecognize a l ease receivable and a corresponding deferred i nflow of resources (with certain except i ons), whi l e continuing to r eport the asset underly i ng the lease. Interest income assoc i ated wi t h the rece i vable will be r ecogn i zed us i ng the effect i ve i nterest method. Lease r evenue will a ri se from amo rti z i ng the deferred i nflow o f resources i n a systematic and rational manner over the lease term. The requirements of this Statement a r e effective for reporting periods beg i nn i ng after December 15 , 20 1 9 , with earl i e r applicat i on encouraged. Management i s currently eval u at i ng the im pact of this sta t eme nt. GASS Statement No. 85 , Omnibus 2017 , was i ssued i n March 2017. T hi s Stateme n t addresses pract i ce issues t hat were i den ti fied dur i ng i mplementation a n d applica ti on of certain GASS statemen t s i nduding statements o n OPES. This Statement prov i des clarifica ti on for t he p r esentatio n o f payroll-r e l a t ed m easures i n requ i re d supplementary i nformat i on for purposes of reporting by OPES plans and e m ployers tha t provide OPES. Th i s S t a t ement requ i res the d i sdosu r e of covered-employee pay r oll by the e m ployer i f con tri bu ti ons t o th e OPES plan a r e n ot based on a measure of pay. Covered-employee payroll i s de fin ed as the pa yr o ll of employees tha t a r e prov i ded with OPEB t hrough t he OPES plan. However , th e financial s t a t ements fo r t h e OPES plan should no t p r esent any measure of p a y ro ll i f cont ri bu ti o n s t o the pla n a r e not based o n a meas ur e of pay. T hi s Statemen t i s effective for fi sca l years beg in n i ng after June 1 5 , 20 17. Th e Dis tri ct adop t ed th i s Sta t e m e nt i n 2 017 t o coi n cide with i ts i mpleme n tat i on o f r e l a t ed guidance i n GASS S t atement N o. 7 5 , Accounting and Financial Reporting fo r Postemployment Benefits Other Than Pensions. T h e OPES g ui dance w as th e o n l y porti o n of th i s State m e nt with a n im pact o n th e Di s tri ct. GASB State m e nt No. 84 , F i d u c i ary Activities , was i ss u ed in J a nu a ry 2 017. Th i s Sta t e m e nt addresses accoun tin g a n d fin a n cia l r epo rtin g r eq uir e m ents f or certa i n fi ducia ry fun ds in th e bas i c fin a nci a l s t a t emen t s. Go v e rn me nts with a ctiviti es m ee tin g th e crit e ri a a r e requ ir ed t o prese nt a s t a t e m e nt of fiduci a ry n e t po s iti o n a n d a sta t eme nt of ch a n ges i n fiduci a ry n e t po s iti o n. Th e requ ir eme n ts o f thi s Sta t e m e nt a r e e ffectiv e for r e portin g periods b eg inning a ft er D ece m be r 1 5 , 2 018. Th e im ple m e n ta ti o n o f thi s Sta t e m e nt will r equir e th e D i s trict to indud e fi d uci a ry sta t e m e n ts with th e s t a t e m e nt s fo r it s bu s in ess-ty pe a ctiviti e s. GA SB Sta tement No. 83 , Ce rt ain Asset Re ti rement Obl i gations , w as i ssu ed i n Nov e mber 2016. Th i s Sta t e ment a ddr esses a ccountin g a nd fin a nci a l r e portin g r eq uir e ments for certain ARO s. Th i s Sta tem e nt i mpo ses r equir e m e nt s in r ega rd s to th e A RO li ab ility r ecog nition , m eas urement a nd specifi cs on when r e-m eas ur eme nt shou d oc c ur. Thi s Sta tem e nt a l so r eq ui res discl os u res reg ar ding the m e thod s a nd a ssumption s u sed to estim at e th e AR O , th e rem a i nin g u se ful lif e of cap ital asse t s associa t ed with th e li ability , any gov e rnmental l eg al funding requir e ments , any asse ts r es trict ed for pa yment a nd a ny minority s hare ARO l i a b i lity. Th e requirements of th i s Statement a re e ffectiv e for r e portin g peri ods beg i nnin g alter Jun e 15 , 2018. Th e Di s trict previously r eported AROs under th e FA SB guidance , which diff ers from th e GA S S gu i dan ce. Th e FA SB guid a nce requ i red m ea surement of th e l i a bility ba sed on th e pre se nt v al u e of th e asse t's d i spo sal co s ts wherea s m ea su r ement under th i s GA S B Statement i s based on th e best es tim a te of the current v a lue of cas h ouU a ys expected t o be i ncurred. The FA S B guidan ce requ ir ed th e recogn iti on of a corresponding capital asse t whereas th e GA S B Statement requires the recognition of a corresponding d e ferr ed outflow of resources.

The D i strict adopted thi s Statement i n 2017 a nd uses regul a tory accounting t o al i gn asse t retirement cost s with their related recogn iti on in rat es. 36 Financial epcmt GASB Statement No. 75 , Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions , was issued in June 2015. The requirements of this Statement will improve accounting and financial reporting for OPEB. This Statement requ ire s the liability for defined benefit OPEB (net OPEB liability) to be measured as the portion of the present value of projected benefit payments to be provided to current active and inactive employees that is attributed to those employees' past periods of service (total OPEB liability), less the amount of the OPEB plan's fiduciary net position. Enhanced disclosures and additional requ ir ed supplementary information are also required under the Statement.

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

Investments are recorded at fair value with the changes in the fair value of investments reported as Investment in come in the accompanying Statements of Revenues , Expenses , and Changes in Net Position. The District had unrealized net gains of $2.6 million and less than $0.1 million in 2017 and 2016 , respectively.

The fair value of all cash and inv estments , regardless of classification on the Balance Sheets , were as follows as of December 31 (in OOO's): Fair Value U.S. Treasury and government agency securities . . $ 998 , 148 Corporate bonds ...... .....................

...........

169 , 051 Municipal bonds .................... ........................ ...... 11 , 900 Cash and cash equivalents.

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

........... 134 , 326 Total cash and investments

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

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

................ . 2017 Weighted Average Maturity {Years} 4.7 9.3 14.3 0.1 4.9 2016 Weighted Average Maturity Fair Value {Years} $ 936 , 317 4.0 181,438 9.6 11 , 901 12.4 129 , 26 1 $1 , 258 , 917 4.5 Interest Rate Risk -The inve stment strategy for all inv estments , except for the decommissioning funds , i s to buy and hold securities until maturity , which minimizes inter est rate risk. The inv estment strategy for decommissioning funds i s to actively manage the diversification of multiple asset dasses to achieve a rate of return equal to or exceeding the r ate used in the decommissioning funding plan model assumptions. Accordingly , securities are bought and sold prior to maturity to incr ease opportunities for higher inv estment returns. Credit Risk -The District follows a Board-approved Investment Policy. This policy complies with state and fed eral laws , and the Resolution

's provisions governing th e inv estment of all funds. The m a jority of i nvestments are direct obligations of , or obligations guaranteed by , the United States of America. Other in vestments are limited to i nvestment-grade fixed income obligations. Custodial Credit Risk -Cash deposits , ptjmarily i nterest bearing , are covered by federal depository i nsurance , pledged collateral consisting of U.S. Government Securities held by various depositories , or an i rrevocable , nontransferable , unconditional l etter of credit i ssued by a Federal Home Loan Bank. F i nancial R~J!>@rt The fair values of the District's Revenue and Special Purpose Funds as of December 31 were as follows (in OOO's): The Revenue funds are used for operating activities for the District.

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

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

...... $ 127 , 302 $ 123,678 Re-.enue funds -ln-.estrnents

........................................................................... ___ 4_3_9~,6_7_5_

352 , 382 $ 566 , 977 $ 476 , 060 The Construct i on funds are used for capital im provements , additions , and betterments to and extens i ons of the District's system. The sources of monies for deposits to the construction funds are from revenue bond proceeds and issuance of short-term debt. 2017 2016 Construction funds -Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 25 Construction funds -ln-.estrnents

...................................................................... ___ 54~, 8_0_8_ 106 , 179 $ 54 , 808 $ 106 , 204 The Debt reserve funds , as established under the Resolut ion , consist of a Primary account and a Secondary account. The District i s required by the Resolution to maintain an amount equal to 50% of the maximum amount of int erest accrued in the current or any Mure year in the Primary accoun t. Such amount totaled $37.8 million and $38.7 million as of December 31 , 2017 and 2016 , respectively. The Secondary account can be established at such amounts and can be utilized for any lawful purpose as determined by the District's Board. Such account totaled $51.0 million and $51.3 million as of December 31 , 2017 and 2016 , respectively. 2017 2016 Debt reserw funds -ln-.estrnents

...........

.......................................................... _$ ____ aa __ . 7_64_ $ 90 , 032 Th e Employee Benefit funds consist of a self-funded hospital-medical benefit plan for active employees only as of December 31 , 2017 and 2016. The District pays 80% of the hospital-medical premiums with the employees paying the remaining 20% of the cost of such coverage. Th e self-funded hospital-medi ca l benefit plan had funds of $1.9 million and $4.9 million as of December 31 , 2017 and 2016 , respectively. For additional i nfonn a tion on OPEB see Note 11. 20 1 7 Erq>loyee benefit funds -Cash and cash equiwlents

......................... ................. $ 935 Erq>loyee benefit fund s -ln\eSbnents

............................................................... ____ 999 __ $ 1 , 934 $ $ 2016 1 , 843 3 , 008 4 , 851 The Decomm i ssioning fund s are utilized to account for the i nvesbnents held to fund the estimated cost of decomm i ssion i ng CNS when i ts operating l i cense exp i res. The Decomm i ssioning funds are held by outside tru s tees or wstod i a ns i n compliance with the decomm i ssioning fund in g plans approved by th e Board wh i ch are *nvested prima ri ly i n fixed i ncome governmental securities. 2017 Oeconmission i ng funds -Cash and cash eq NBlents ........................................ $ 6 , 089 Deconmssioning fu nds -lrneslrnents

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

.......................... ___ 594~, 853 __ $ 600 , 942 38 $ $ 2016 3 , 715 578 , 055 58 1 , 770 Finariiloial R!ep01 1 t

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value is the exchange pr i ce that would be received t o sell an asset or paid to transfer a liability (an exit price) i n the principal or most advantageous market for the asset or liability i n an orderly t r ansact i on between ma r ket participants at the measurement date. GASB Statement No. 72 (" GASB 72"), Fair Value Measurement and Application , establ i shes a fair value hierarchy that prioritizes the inputs used to measure fa i r value. The hie r archy gives the highest pr i or i ty to unadjusted quoted prices in an active market for identical assets or liabilities and the lowest priority to unobservable inputs. Financial assets and liab i lities are class i fied in their ent i rety based on the lowest level of input that is significant to the fa i r value measurement.

The t hree levels of fair value hierarchy defined in GASB 72 are as follows: Level 1 -Quoted prices are ava i lable in active markets for i dentical assets or liab i lities as of the reporting date. Active markets are those i n wh i ch transactions for the asset or liability occur i n sufficient frequency and volume to provide pricing informat i on on an ongoing basis. The Dist ri ct's investments in cash and cash equivalents are included as Level 1 assets. Level 2 -P ri c i ng inputs a r e other than quoted market prices in the act i ve markets included in Level 1 , wh i ch are either directly or ind i rectly observable for the asset or liabil i ty as of the reporting date. Level 2 inputs i nclude the following:

quoted prices for simila r assets or liabilities in act i ve markets;

quoted pr i ces for ident i cal assets or liabilities in inactive markets;

inputs other than quoted prices that are observable for the asset or liability; or

inputs t hat are derived principally from or corroborated by observable market data by correlat i on or othe r means. Level 2 assets primarily i nclude U.S. Treasury and government agency secu ri ties held i n the Revenue funds and other Special Purpose Funds and U.S. T r easury and government agency securities , corporate bonds , and municipal bonds held i n the Decommissioning funds. Level 3 -Pricing i nputs i ndude significant i nputs that are unobservable and canno t be corroborated by marke t data. Level 3 assets and liab i l i t i es are va lu ed based on i nternally developed m odels and assump ti ons or methodologies us i ng s i gn ifi can t unobservab l e i n puts. The Dist ri ct curren tl y does n o t h ave any Level 3 assets or liab i lities. The District pe rf o rm s an anal y s i s annually t o determine the appropriate h i erarchy l eve l dassi fi ca ti on o f th e assets and li abili ti es tha t are i n cl u ded within th e scope o f GASB 7 2. F i nancia l assets a n d li a biliti es a r e dass ifi ed i n th e i r en ti rety based on th e l owes t l e v e l of i np ut th at i s s i gn ifi can t t o th e fa ir va lu e m eas ur eme nt Th e r e w ere no l i ab i l iti es within th e scope of GASB 72 as of Decembe r 3 1 , 20 17 a n d 2 01 6. Th e followin g tab l es se t f o rth th e D i s tri ct's fi na n cia l assets th a t are accou nt ed for a n d r epo rt ed a t f a ir v a lu e o n a r ecu rrin g ba si s by l e v el within th e fa i r v a l ue hi era rchy as o f Dece m ber 3 1 , (i n OOO's): Rellenue and special purpose funds , eJdJding deconnission i ng: U.S. T reasury and gowemmentagency sec uri ti es ............ . $ Cash and cash eq ui valents ............................................. .. 128 , 23 7 Decormissioning funds: U.S. T reasury and gm,emment agency secu riti es ............ . Corporale bonds ........................................................... . Mun ici pal bonds ...........................

................................. . Cash and cash eqt.riiwlern'ls

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

. 6 , 089 $ 1 34 , 326 Fi: i na,noial Rep<imt 20 17 l...e\lel 2 l...e\lel 3 $ 584 , 246 $ 4 1 3 , 902 1 69 , 051 11 , 900 $1 , 17 9 , 099 $ T olal $ 584 , 246 1 2 8 , 23 7 4 1 3 , 902 1 69 , 05 1 11 , 900 6 , 089 $1 , 3 1 3 ,, 425 Level 1 Revenue and special purpose funds , excluding decommissioning:

U.S. Treasury and government agency securities

............ . $ Cash and cash equ i valents ..........................................

... . 125 , 546 Decommissioning funds: U.S. Treasury and government agency securities

............ . Corporate bonds ......................................

..................... . Municipal bonds ............................................................ . Cash and cash equivalents

............................................. . 3 , 715 $ 129 , 261 4. UTILITY PLANT: 2016 Level2 $ 551 , 602 $ 384 , 715 181 , 438 11,901 $1 , 129 , 656 $ Level 3 Total $ 551 ,6 02 125 , 546 384 , 715 181 , 438 11 , 90 1 3 , 715 $1 , 258 , 917 Utility plant activity for the year ended December 31 , 2017 , was as follows (in OOO's): December 31 , 20 1 6 Increases Decreases December 31 , 2017 Nondepreciable utility plant Land and improvements.

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

$ 74 , 13 8 $ 1 , 124 $ (68) $ 75 , 194 Construction in progress..............................

135 , 853 120 , 399 (122 , 737) 133 , 515 Total nondepreciable utility plant.............. 209 , 991 121 , 523 (122 , 805) 208 , 709 Nuclear fuer .................................................... 197 , 730 ----'----11 , 979 (43 , 490) 166 , 219 Depreciable utility plant Generation

-Fossil .................................... . 1 , 621 , 9 19 33 , 992 (5 , 754) 1 , 650 , 157 Generation

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

............ . 1 , 314 , 210 14 , 978 (7 , 182) 1 , 322 , 006 Transmission

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

.............................. . 1 , 254 , 421 47 , 223 (5 , 011) 1 , 296 , 633 Distribution

................................................ . 226 , 563 9 , 29 1 (1 , 409) 234 , 445 General ..................................................... . 344 , 578 15 , 169 (9 , 812) 349 , 935 Total depreciable utility plant 4 , 761 , 691 120 , 653 (29 , 168) 4 , 853 , 176 Less re~ for depreciation

........................... . (2 , 573 , 645) (113 , 729) 29 , 16 8 (2 , 658 , 206) Depreciable utility plant, net .................... . 2 , 188 , 046 6 , 924 2 , 194 , 970 Utility plant acli'Aly , net ..................................... . $ 2 , 595 , 767 $ 1 40 , 426 $ (1 66 , 295) $ 2 , 569 , 898 -----* Nuclear ire! decreases represented amortiz a ti on of $43.5 million. Finanoial

~epornt Utility plant act i vity for the year ended December 31 , 20 1 6 , was as follows (in OOO's): December 31 , December 31 , 2015 Increases Dec r eases 2016 Nondepreciable utility plan t: Land and improvements

...........

.................... $ 64 , 370 $ 9 , 780 $ (12) $ 74 , 138 Construction in progress ..................

............ 209 , 626 180 , 237 (254 , 010) 1 35 , 853 Total nondepreciable uti li ty plant ..............

273 , 996 190 , 017 (254 , 022) 209 , 991 Nuclear fuel* .........................

........................... 168,420 70 , 064 (40 , 754) 197 , 730 Deprec i able util i ty plant Generation

-Foss i l ...................................... 1 , 573 , 880 65 , 8 1 8 (1 7 , 779) 1, 621 , 919 Generation

-Nuclear ................................... 1 , 384 , 031 68 , 415 (1 38 , 236) 1, 314 , 210 T r ansmissio n ...........

................................... 1 , 172 , 108 86 , 994 (4 , 681) 1, 254 , 421 D i str i bution ......................

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

........ 221 , 7 91 6 , 336 (1 , 564) 226 , 563 General ...................................................... 334 , 836 1 3 , 528 (3 , 786) 344 , 578 Total depreciable utility plant 4 , 686 , 646 24 1 , 09 1 (1 66 , 046) 4 , 761 , 691 Less reserve for deprecia ti on ............................ (2 , 620 , 091) (11 9 , 600) 1 66 , 046 (2 , 573 , 645) Deprec i able utitity plan t, net .....................

2 , 066 , 555 1 2 1 , 491 2 , 188 , 046 Uti li ty plant ac ti vity , net ..................................... $ 2 , 508 , 97 1 $ 38 1 , 572 $ (294 , 776) $ 2 , 595 , 767

Nucl ear fuel decreas es represented amortiz a tion o f $40.8 million. 5. LONG-TERM CAPAC I TY CONTRACTS: L ong-t erm capaci ty con tr acts in dude th e Di s tri ct's share o f th e co n s tru ctio n cos t s o f O m aha P u bl i c Powe r D i s tri ct's (" OPPD") 664 m egawatt (" MW) Nebraska C i ty Sta ti on Un i t 2 (" Nc2*) coa l-fi red power plan t. Th e D i s trict h as a participa ti on powe r agreemen t wi th OPPD for a 23. 7% sha r e of th e power fr o m thi s p l a n t. N C2 bega n commercial opera ti on on M a y 1 , 2009 , a t whi ch tim e th e Dis tri ct bega n a m ortiz i ng th e a m oun t o f th e capa city contract associa t ed with th e pl a n t on a s tr a i ght-line bas i s ove r t he 4 0-year es tim a t ed u se fu l lif e of th e plan t. Accumulated a m ortiza ti o n was $39.9 m i llion and $35.4 m illi on as of Decembe r 3 1 , 2 017 a n d 2 01 6 , r espective ly. Th e u na m ortized amou n t o f th e pl ant capaci ty contract w as $1 39.2 m i llio n a n d $143.7 million as o f December 3 1 , 2 017 and 20 1 6 , r espective ly , of wh ich $4.4 mi llio n was i nd u ded i n P r epa ym e n ts an d o th er cu rr e n t asse t s as o f Decembe r 3 1 , 2 017 a n d 2 01 6. Th e D i s tri ct's s h a r e of NC2 w o rkin g capita l was a l s o i ndu decl in P r epa ym e nt s a nd o th e r cu rr en t assets a n d wa s $6.5 milli on as of Decembe r 3 1 , 2 017 a n d 2 01 6. lon g-t e nn capa city co ntract s a l so indu de th e D i s tri ct's purdi ase of th e capa city of a 5 0 MW hydr oelectric ge n erating facility own ed a nd opera t ed by Th e Ce n tra l N ebra sk a P ubli c P ow er a nd Irri ga tion Di s trict r c entral"). Th e D istri ct i s a mortizing th e contra ct o n a stra i g ht-li ne ba si s o v er th e 4 0-y ea r es tim at ed use ful lif e of th e fa cility. Accu mu l a t ed a m o rtizati o n was $66.6 million and $64.3 milli o n as of D ecembe r 31 , 2017 an d 2 016 , r espectiv ely. Th e un am ortiz ed a mount of the C en tral capa city co n tra ct w as $2 0.1 million a nd $22.4 million as of December 31 , 2 017 an d 2016 , r es pectively , of whidi $2.3 milli o n was indud ed in P r epa yment s a nd other cunent assets as of D ecembe r 31 , 2017 and 2016. Th e Di s tri ct has an ag reement wh ereb y Ce ntral m akes a v a ilable all the production of 1he facility a nd the District pays a I costs of operating and m ai ntain*ng the fa cility plu s a di arge based on th e amount of energy delivered to th e Di s trict. Costs of $1.8 million and $2.5 million i n 2 017 an d 2 016 , respectively , are i nduded *n P ower purch ased in the accompanying Sta tements of R e ven ues , Expen ses , and Chang es in Net Position. F i nancial ReJ!l<ill11

6. INVESTMENT IN THE ENERGY AUTHORITY:

The District has an investment in The Energy Authority

("TEA"), a nonprofit corporation headquartered in Jacksonville , Florida , and i ncorporated in Georgia. TEA provides public power utilities access to dedicated resources and advanced technology systems. The District's interest in TEA was 16.67% as of December 31 , 2017 and 2016 , respectively. In addition to the District , the following utilities have interests of 16.67% each as of December 31 , 2017 and 2016: American Municipal Power , Inc.; JEA (Florida); Municipal Energy Authority of Georgia; and South Carolina Public Service Authority (a.k.a. Santee Cooper). The following utilities have interests in TEA of 5.56% each as of December 31 , 2017 and 2016: City Utilities of Springfield, Missouri; Cowlitz County Public Utility District (Washington) and Gainesville Regional Utilities (Florida).

Such investment was $6.2 million and $6.4 million as of December 31 , 2017 and 2016 , respectively.

TEA's revenues and costs are allocated to members pursuant to Settlement Procedures under the Operating Agreement.

TEA provides the District gas contract management services and is the District's market participant in SPP's Integrated Market. The District is obligated to guaranty , directly or indirectly , TEA's electric trading activities in an amount up to $78.9 million plus attorney's fees which any party claiming and prevailing under the guaranty might incur and be entitled to recover under its contract with TEA. Generally , the District's guaranty obligations for electric trading would arise if TEA did not make the contractually required payment for energy , capacity , or transmission which was delivered or made available or if TEA failed to deliver or provide energy , capacity , or transmission as required under a contract. The District's exposure relating to TEA is limited to the District's investment in TEA , any accounts receivable from TEA , and trade guarantees provided to TEA by the District.

Upon the District making any payments under its electric guaranty, it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably , based upon each member's interest in TEA and the guarantees they have provided. The District increased its guarantee to TEA in March 2018 from $28.9 million to $78.9 million. The additional

$50.0 million of guaranty is to support additional trading for TEA on behalf of its continued business growth. After such contributions have been effected , the District would only have recourse against TEA to recover amounts paid under the guaranty. The term of this guaranty is generally indefinite , but the District has the ability to terminate its guaranty obligations by causing to be provided advance notice to the beneficiaries thereof. Such termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect. The District has no liabilities for these guarantees as of December 31 , 2017 and 2016. Financial statements for TEA may be obtained at The Energy Authority , 301 W. Bay Street , Suite 2600 , Jacksonville , Florida , 32202. 7. DEBT: The following table summarizes the debt balances , net of current matu riti es , as of December 31 , 20 17 and 2016 , and activity for 2017 (in OOO's): December 3 1, 2016 I ncreases Re~ue bonds............

.............. $ 1 , 678 , 844 $ 96 , 95 7 Conne"cial paper notes............. 7 4 , 000 Rewhing credit agreements h 1 ..... 188 , 924 ---~--11 , 320 8 7 , 4 17 T olal long-term debt actNty .... $ 1 , 941 , 7 68 $ 1 95 , 694 .-,1 , . :.:>;/ * ' ' ~; *. ,."~~ .: };~ ~*-,:~;< .:.~:~¢rbt~

Decreases

$ (227 , 532) (85 , 320) (42 , 129) $ (354 , 981) Pri ncipal AmountsOue December 3 1 , Wrlhin Ole 2017 Y ear $ 1 , 548 , 269 $ 98 , 205 234 , 2 1 2 165 , 2 1 2 $ 1 , 7 82 , 48 1 $ 263 , 4 17 FinaMia l Rep@rt l The following table summarizes the debt balances , net of current maturities , as of December 31 , 2016 and 2015 , and activity for 2016 (in OOO's): Principal Amounts Due December 31 , December 31 , Within One 2015 Increases Decreases 2016 Year Re\enue bonds ......................... $ 1 , 596 , 972 $ 354 , 776 $ (272 , 905) $ 1 , 678 , 844 $ 81 , 250 Commercial paper notes ............

83 , 000 88 , 365 (97,365) 74 , 000 74,000 Re1.0I\Ang credit agreements

....... 158 , 700 75 , 443 (45 , 219) 188 , 924 Total long-term debt acti\Aty .. $ 1 , 838 , 672 $ 518 , 584 $ (4 1 5 , 489) $ 1 , 941 , 768 $ 155 , 250 Revenue Bonds On January 1 , 2018 , the District called the remaining outstand i ng General Revenue Bonds , 2012 Ser i es C , with a principal amount that aggregated

$4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of OPEB costs for customers under the 2016 Contracts. Congress passed the Tax Cuts and Jobs Act (" Act") in December 2017 , wh i ch eliminated the use of tax-exempt advanced refunding transactions. In April 2017 , the District i ssued General Revenue Bonds , 2017 Series A and 2017 Series B , in the amount of $86.0 m i llion to refund the General Revenue Bonds , 2007 Series B. The refunding reduced total debt service payments over the life of the bonds by $11.8 million , which resulted in present value savings of $10.0 million. Also i n April 2017 , the District entered i nto an escrow deposit agreement i n conjunction 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. Congressional action reduced the 35% interest subsidy , pursuant to the r equirements of the Balanced Budget and Emergency Deficit Control Act of 1985 , as amended , on the District's General Revenue Bonds , 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds). Reductions were 6.9% and 6.8% for fiscal y ears ended September 30 , 2017 and 2016 , respect i vely. I n November 20 1 6 , the Dis tri ct i ssued General Revenue Bonds , 2016 Se ri es C and 2 01 6 Series 0 , i n the amoun t of $1 13.5 m i llion t o finance th e costs of certain genera ti on a n d tra n sm i ss i on capital projects and t o refund a portion of Commercial Paper Notes , Series A. The Dis tri ct also i ssued in Nove m ber 2016 , General Revenue Bonds , 2016 Se ri es E (Taxable), i n the amount of $56.1 m i llion t o fund a po rti o n of OPES costs for custome r s under the 20 1 6 Contracts. In February 2 01 6 , th e Dis tri ct i ssued General Revenue Bonds , 2 01 6 Se ri es A and 2016 Se ri es B , i n th e a m ount of $1 39.2 m i llion t o adva n ce r e fu nd $1 38.9 m i llion of bonds and r efu n d $1 6.5 milli o n of co mm e rci a l pape r n otes. Th e r efu n ding r ed u ced total debt service payments over th e lif e o f th e bo n ds by $2 9.8 milli on , whidl r esulted i n pr esent v alue sa vi ngs of $2 0.8 mi llio n. Al so in F ebruary 2 01 6 , th e D i s trict en t ered int o a n e scrow d epo sit agreemen t *n conjuncti o n with th e advanced r e fu nd i ng of certai n o f th e:

Ge n e ral Re v en u e Bo nd s , 2 0 0 7 Series B , h a vin g m a turity d a t es ra n g ing from J a nu ary 1 , 2 0 26 th ro u g h J a nu a ry 1 , 2 0 3 7

General Re v en u e Bo nd s , 2 00 8 Se ri es B , h a vin g m a turity d ates ran g ing from J a nu a ry 1 , 2 0 24 throu g h J a nu a ry 1 , 2 041

General Re v en u e Bon ds , 201 2 Series C , m a turin g on J a nu a ry 1 , 2025 through January 1 , 2 0 2 6 In J anua ry 2 016 , the Oisbid i ssued TEC P i n th e a mount of $4 3.6 m i l *on to refund a portion of th e General R e v en u e Bond s , 2 00 5 Series C a nd the General Re v e nu e Bo nd s , 2 006 Seri es A. F i nancial Nep01 1 t Certai n of the General Revenue B o nds , from th e following s e ries , with outst a nding princip a l am o un ts that aggre ga te $324.1 million as of December 31, 2017 , were legally d efeased and are no l o n ge r outstan d ing: 2008 Serie s B and 2012 Series C. Debt s e rvice payments and principal payments of the General Revenue Bonds as of December 31 , 2017 , are as follows (in OOO's): Year 2018 ............................................ . 2019 ********************************

- - - - 2020 ............................................ . 2021 ............................................ . 2022 ............................................ . 2023-2027

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

....... . 2028-2032

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

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

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

.................................... . Total Payments ...................

.......... . Debt Service Payments $ 170,403 146,856 146,760 143,968 136,550 637,780 469,091 270,720 103,408 15,962 $ 2 , 241 , 498 Principal Payments $ 98,205 79,320 82,915 84,085 80,825 417,475 341,640 218,700 88,685 14,895 $ 1 , 506 , 745 The fair value of outstanding revenue bonds was determined using currently published rates. The fair value was estimated to be $1 , 737.9 million and $1 , 750.1 million as of December 31 , 2017 and 2016 , respectively.

Comm e rcial Paper Notes and Line of Credit Agreement The District terminated its Commercial Paper Notes ("Notes")

program and the Line of Credit Agreement that supported the payment of the principal outstanding on the Notes after execution of the Tax-Exempt Revolving Credit Agreement

("TERCA") in 2017. Tax-Exempt Revolving Credit Agreement The District entered into a TERCA with two commercial banks to provide for loan commitments to the Disbict up to an aggregate amount not to exceed $150.0 million on June 29 , 2017. The TERCA replaced the Commercial Paper Notes and Line of Credit Agreement The District had an outstanding balance under the TERCA of $69.0 million as of December 31 , 2017. The outstanding amount i s anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the TERCA approximates market value due to the short-term nature of the agreements. The TERCA terminates on June 29 , 2020. Taxable Revolving Credit Agreement The District has entered i nto a Taxable Revolving Credit Agreement

("TRCA*) with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 m i llion. The TRCA allows the D i strict to increase the loan commitments to $300.0 m i llion. The D i strict had outstand i ng balances under the TRCA of $165.2 m i lllon and $188.9 million , as of December 31 , 2017 and 2016 , respectively. The outstanding amount i s anticipated to be retired by future collections through electric rates. The carrying value of the taxable revolving credi t agreements approximates market value due to the short-term n a tu re of the agreements.

The TRCA was renewed on J y 3 1 , 20 1 5 , and t erm i nates on July 30 , 20 1 8. 44 Fi n ancial Ecep0rt R e venue bonds consist of the follolNing (OOO's except i nte r est r ates): Decem b er 31 , Inte r es t Rate 2017 General Revenue Bonds: 20 0 7 Ser i es B: Ser i al Bonds: 20 1 6-2026 .............................. . Term Bonds: 202 7-2031 .............................. . 2008 Ser i es B Ser i al Bonds 2017-2029

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

... . 2009 Ser i es A Taxable Build America Bonds: Te r m Bonds: 20 1 9-2025 .............................. . 2026-2034

.............................. . 2009 Ser i es C Ser i al Bonds 2017-2019

................... . 20 1 0 Ser i es A Taxable B uil d America Bonds: Ser i al Bonds: 20 1 9-2024 ..................

............ . Ter m Bonds: 2025--2029

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

.............................. . 2010 Ser i es B Taxable Ser i al Bonds 20 1 6-2020 ....... . 2010 Se ri es C: Ser i al Bonds: 20 17-2025 .............................. . Term Bonds: 2 0 26-2030 .............................. . 2026-2030

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

................. . 2012 Ser i es A Ser i al Bo n ds 2017-2034

................... . 20 1 2 Se ri es 8: Ser i a l Bonds: 20 17-2032 .............................. . Te rm Bonds: 2033-2036

.............................. . 203 7-2042 ******************************* 2 01 2 Se ri es C Se ri a l Bonds 20 1 7-2028 ................... . 20 1 3 Se ri es A Ser i al Bo n ds 2017-2033

................... . 20 1 4 Se ri es A:. Se ri a l Bonds: 2 017-2 0 38 .............................. . T e rm B on ds: 2 03 9-2043 .............................. . 2 0 39-2043 .............................. . 2 01 4 S eri es C Seria l Bo nd s 2017-2033

................... . 2 01 5 Series A-1 Seria l Bon ds 2022-2 0 34 ................ . 2 01 5 S eri es A-2: Seri al B on ds: 2017-2034 .............................. . Term Bon ds: 2 035-2 0 39 .............................. . 2 016 Seri es A:. Seri a l Bon ds: 2018-2 0 35 ............................... . Term Bond s: 2036-2 040 ......................

........ . 2016 Seri es B: Serial Bon ds: 2018-2 036 ....... ******** ............... . Term Bond s: 2037-2 039 ......................

........ . 20 1 6 Seri es C Serial Bond s 2017-2035 ................... . 2016 Seri es D: 4.375% -5.00% 4.65% 4.00% -5.00% 6.606% 7.399% 4.00% -4.25% 3.98% -4.73% 5.323% 5.423% 3.358% -4.1 8% 3.00% -5.00% 4.00% 5.00% 3.00% -5.00% 2.00% -5.0 0% 3.625% 3.625% 3.0 0% -5.0 0% 3.00% -5.0 0% 2.00% -5.00% 4.00% 4.1 2 5% 4.00% -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% Serial Bond s: 20 17-2035 ................................ 2.00% -5.00% T erm Bonds: 2036-2040

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

............... 5.C)0% 204 1-2045 ...................

............ 5.()()% 2016 Seri es E T axable Serial Bond s 2022-2033 ........ 2.33 7% -3.56 7% 20 17 Seri es A Serial Bonds 2 0 1 7-20 2 7 ................... . 20 17 Seri es B Serial Bonds 20 1 7-2 02 7 ..........

......... . 200% -5.00"k 5.00% $ 1 7 , 465 32 , 890 2 , 535 3 1 , 875 27 , 985 54 , 190 2 , 755 40 , 685 6 , 1 65 1 4 , 1 80 1 82 , 1 45 83 , 330 2 , 320 4 , 1 55 77 , 480 1 5 1 , 01 5 3 1 , 650 1 , 945 1 38 , 1 3 0 119 , 4 00 56 , 045 46 , 2 05 65 , 2 10 5 , 595 67 , 255 1 , 165 6 7 , 025 20 , 960 9 , 505 1 2 , 1 40 56 , 050 1 8 , 1 25 59 , 17 0 T otal par amount of revenue bonds .......................

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

........ 1 , 506 , 7 45 l.klarnorlized prenil.ffl'I net or discount .................................

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

__ 1 3_9""" , 7_29_ 1, 646 , 4 7 4 Less -Cla"T enl rnaluriti es of r e\lleflUe bonds .....................................................

-~<98~, 2_05~) T otal r ewenue bonds .................................................................................

$1 , 548 , 269 F i na n cial R!ei p o mt 2016 $ 97 , 415 9 , 620 10 , 700 17 , 465 32 , 890 4 , 605 3 1 , 875 27 , 985 54 , 190 3 , 600 48 , 760 6 , 165 14 , 180 1 90 , 410 92 , 32 0 2 , 320 4 , 1 55 11 , 045 9 1 , 1 00 1 53 , 630 3 1 , 6 50 1 , 945 1 43 , 0 25 11 9 , 40 0 56 , 485 46 , 2 0 5 6 5 , 2 10 5 , 595 6 7, 25 5 1 , 1 65 70 , 685 2 1,1 70 9 , 505 1 2, 1 40 56050 1 , 6 11 , 9 1 5 1 48 , 17 9 1,7 60 , 094 (8 1 , 250) $1, 678 , 844

8. PAYMENTS IN LIEU OF T AXES: The District i s required to make payments in lieu of taxes , aggregating 5% of the gross revenue derived from electric retail sa l es with in the city limits of incorporated cities and towns served d ir ectly by the District.

Such payments totaled $10.1 million for each of the years ended December 31 , 2017 and 20 1 6 , respectively. 9. ASSET RETIREMENT OBLIGATIONS

The District im plemented GASB Statement No. 83 , Certain Asset Retirement Obligat i ons , in 2017 , retroactive to 2016. Prior to the implementation of the GASB guidance , FASB guidance had been used for ARO reporting. The FASB guidance required measurement of the liability based on discounted dollars or the present value of the asset's disposal costs. Measu r ement under GASB guidance is based on the best estimate in today's dollars , or the current value, of cash outlays expected to be incurred in the future. The FASB guidance required the recognition of a corresponding capital asset whereas the GASB guidance requires the recognition of a corresponding deferred outflow of resources. The District uses regulatory accounting to align asset retirement costs with their related recognition in rates. The difference in the ARO amounts and the related deferred outflows represents the amounts collected in rates. AROs as of December 31 , are as follows (in OOO's): Description CNS license termination costs ..............................

.......................... . GGS and SS ash landfiUs ............................................................... . Ains1110rth

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

.................................................. . Underground storage tanks ............................................................ . 2017 $ 811 , 801 9 , 040 1 , 953 1 000 $ 8231794 2016 $ 795 , 026 3 , 208 1 , 913 1 000 $ 8011147 The District is required by the Nudear Regulatory Commission

(" NRC") to decommission CNS after cessation of plant operations , consistent with regulations in the U.S. Code of Federal Regulations. The CNS li cense termination costs were based on an external study for costs for three different scenarios: 1) immediate commencement of decommissioning after license termination in 2034; 2) delayed decommissioning for 46 years after license t erm in at i on; and 3) safe storage for 60 years after license termination. The costs were based on several key assumptions in areas of regulation , component characterization , high-l evel r ad ioactiv e waste management , low-l evel radioactive waste disposal , performance uncertainties (conting ency) and site r estora tion requirements. An expert panel , consisting of District mana gement representatives with considerable nudear experience , assigned probabilities to these different scenarios. The costs in the study were in 2015 dollars. Rates in the consumer price index for all urban consumers r cPI-U fl) were used to adjus t these obligations for infl a tion. The infl ation rate s used were 2.11 % and 2.07% for the years 2017 and 20 16 , re specti vely. The District ha s funds set aside for decommissioning of $600.9 million and $581.8 million as of December 31 , 2017 and 2016 , respectively. Th ese fund s exceeded the NRC's required funding provisions for nudear decommission in g. The District i s required by the Environmental Protection Agency r EPA.) and the Nebraska Department of Environment Quality r NDEQ*) to decomm i ss i on th e ash l andfills at GGS and Sheldon , consistent with their regulations. As GASB guidance i s undear r elated to the accounting treatment for ash l a ndfill AROs , GASB Statement No. 83 was considered analogous authoritative literature and applied in this situ a tion. The ash landfills h a ve an estimated dosure date i n the years 2086 and 2036 for GGS and Sheldon , respectively.

The AROs were based on external stud i es t o estimate oosts using one scenario after an assessment of the physical site. The dosure and post-0osure costs were based on the Closure Plan in the stud i es and *nduded final cover placements and lined surface water control structures. The costs in th e latest studies were i n 2017 dollars. The ARO in creased from 2016 because of a regulatory change whidl in creased the post-0os re period from five years to 30 years. The District provided guarantees and financial assurance through correspondence and supporting

ntonnation to NDEQ in 2017. Commencing i n 2017 , the District in duded in rates decommission

ng costs for certain assets at GGS and Sheldon. The costs *nduded in rates for the decommissioning of the ash landfills were 46 Finanoia l !Report

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

Ainsworth has an estimated closure date of September 30 , 2025. The ARO was based on an external study for costs using one scenario. The assumptions included: 1) no hazardous construction material abatement is required; 2) no environmental costs to address site clean-up; 3) floor drain and septic tanks will be decommissioned per state regulations

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

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

(" CPI-U") were used to adjust these obligations for inflation. The inflation rates used were 2.11% and 2.07% for the years 2017 and 2016 , respectively.

There are no legally required funding and assurance provisions associated with this ARO. The costs included in rates for the decommissioning of Ainsworth were $0.1 million for the year ended December 31 , 2017. These rate collections reduced the related deferred outflow for Ainsworth. The District is required by the NDEQ to decommission the underground storage tanks at various locations in the District's service area , consistent with its regulations. The remaining l i ves of the storage tanks cannot be reasonably estimated. The AROs were based on the best estimate of District management representatives with expertise i n environmental issues. The District prov i ded guarantees and financial assurance through correspondence and supporting information to NDEQ in 2017. There have not been any decommissioning costs for the underground storage tanks included i n rates. Financial Rep)()rnt The District continues to use regulatory accounting for AROs , so the amount included in rates is recorded as decommissioning expense. As a result , the impact on the District's 2016 financial statements was limited to the Balance Sheet. The changes made to the 2016 financial statements after the implementation of the GASB guidance were as follows (in OOO's): Balance Sheet Utility Plant , at Cost: Utility plant in sen,ke ..................

................................................. . Less reser\* for depreciation

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

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

...................... . Construction work i n progress ....................

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

................... . Nuclear fuel , at amortized cost ..................................................... . Other Long-Term Assets: Regulatory asset for ARO ................

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

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

... . Regulatory asset for other postemployment benefits ....................... . Long-term capacity contracts

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

...........

................ . lm.estment i n The Energy Authority

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

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

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

...........

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

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

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

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

................... . Deferred Outflows of Resources: Asset retirement obigation

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

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

............ . lklamortized cost of refunded debt ............................................... . Other postemployment benefits .......................................

............... . TOTAL ASSETS AND DEFERRED OUTFLO\NS Other Long-Term Li abi liti es: Asset retire,nent obligation

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

........................................ . Net olher fJC)Slen1>1oyment benefit li ability .......................

............... . Other .............*............................

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

..*...........*.... Tolal Li abi liti es ..................

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

.................................... . T OTAL LIABILITIES , DEFERRED ll'FLCJIN S , ANl f£T POSITION ... 48 As reported 2016 $ 4 , 835 , 829 2 , 573 , 645 2 , 262 , 184 135 , 853 197 , 730 $ 2 , 595 , 767 $ 221 , 973 159 , 445 8 , 945 6 , 370 9,416 $ 406 , 149 $ 4 , 560 , 252 $ 219 , 378 42 , 664 82 , 289 $ 344 , 331 $ 4 , 904 , 583 $ 801 , 147 258 , 609 3 , 362. $ 1 , 063 , 118 $ 3 , 2 18 , 208 $ 4 , 904 , 583 As originally reported 2016 $ 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 $ 124 , 953 $ 4 , 731 , 143 $ 627 ,707 258 , 609 3 , 362. $ 889 , 678 $ 3 , 044 , 768 $ 4 , 731 ,1 43 Change $(135,430)

(134,391)

(1 , 039) $ (1 , 039) $ (44 , 899) $ (44 , 899) $ (45 , 938) $ 219 , 378 $ 219 , 378 $ 173 , 440 $173 , 440 $173 , 440 $1 73 , 440 $173 , 440

10. RETIREMENT PLAN: The Distr i ct's Employees' Retirement Plan (the "Plan") is a defined contribution 401 (k) pension plan established and administered by the District to provide benefits at retirement to regular full-time and part-time employees. There were 1 , 848 and 1,931 active plan members as of December 31 , 2017 and 2016, respectively. Plan provisions and contribution requirements are established and may be amended by the Board. Plan members are eligible to begin participation in the Plan i mmediately upon hire. Contributions ranging from 2% to 5% of base pay are eligible for District matching dollars after six months of employment.

The District contr i butes two times the Plan member's contr i bution based on covered salary up to $40 , 000. On covered salary greater than $40 , 000 , the District contributes one times the Plan member's contribution.

The Participants

' contributions were $13.7 million and $13.4 million for 2017 and 2016 , respectively.

The District's matching contributions were $12.0 million and $12.3 million for 2017 and 2016 , respectively.

Total contributions of $1.3 and $1.4 million were accrued in Accounts payable and accrued liabilities as of December 31 , 2017 and 2016 respectively.

Beginning January 1 , 2018 , the Board approved an increase i n matching for covered salary from $40 , 000 to $75 , 000. Plan members are immediately vested in the ir own contributions and earnings and become vested in the District's contributions 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 District contributions are first used to cover Plan adm ini strat i ve expenses and any remaining forfeitures are allocated back to Plan participants. Employees may also cont ri bute to a defined contribu tion 457 pension plan r 457 Plan*). The 457 Plan i s a deferred inv estment option with no District match. Pay period con tri butions can be elected and changed at any tim e. Ear1y withdrawals can be made from the 457 Plan following separa ti on of serv i ce r egardless of age with no IRS penalty. Income taxes are owed on any withdrawals. Th e Participants

' contributions were $2.5 million a nd $2.1 million for 20 17 and 2016 , r espectively. 11. OTHER POSTEMPLOYMENT BENEFITS: Th e District ea r1y adopted th e provisions of GASB Sta t e m e nt No. 75 r GASB 75 m). Accounting and Financial Reporting for Postemployment Benefits Other than Pensions , i n 2016. Th e re was no i mpact to beginning net position as a result of th e implem e nt a tion in 2016. A. General information regarding the OPEB Plan -Plan Desalption Th e District's Postemployment Medical a nd Life Benefits Plan r Plan") provid es postemployment h ospital-med i cal and life i nsurance benefits to qualifying retirees , surviving spouses , a nd employees on lon g-t e rm d i sa bility a nd their dependent s. Benefits a nd rel ated elig i bil i ty , fund*ng and other Plan provision s , for thi s single-employer , defined benefit Plan , are a uthorized by th e Board. Th e Plan h as been a mended over th e y ears and provides different ben e fits based on h i re date and/or th e age of lh e employee. Th e D i strict pays a I or part of th e cost (determ i ned by age) of certa i n hospital-medical prem i ums for employ ees *red on or prior to December 31 , 1992. Employees h i red on or after January 1 , 1 993 , are subject t o a oonbibution cap th a t li mits th e D i strict's portion of the cost of such coverage to th e full prem i um the y ea r the employ ee reached age 65 , or th e y ear i n wh i ch th e employee retires if older than age 65. Employees hired on or after January 1 , 1999 , are no elig i bl e for other postemployment h ospital-medical benefits once th e y reach age Fi nancial Rep 0Ii t

65. Employees hired on o r after January 1 , 2004 , are not eligible for other postemployment hospital-medical benefits once th ey retire. The District amended the Plan effective July 1 , 2007 , to provide that any former employee who i s 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 reh ir ed on or afte r that date must work five consecutive years immediately prior to retirement to be eligible for other postemployment hospital-medical benefits once they retire. In May 2015 , the Board approved a change for Med i care-elig i ble retirees for prescription drugs from the District's self-in sured employee prescr i ption plan to a group i nsured Medicare Part D supplement effective January 1 , 2016. The District also provides a postemployment death benefit of $5 , 000 for qualifying employees.

Employees Covered by Benefit Terms The following table shows th e employees covered by the hospital-medical benefit terms as of January 1: 2017 2016 Acti~ efll)loyees

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

.................................... 1 , 007 lnacti~ efll)loyees in retirement status..................................... 1 , 381 lnacti~ efll)loyees in long-term disability status......................... 64 ------Total efll)loyees co~red by benefit terms.............................. 2 , 452 ------1 , 175 1 , 260 67 2 , 502 The following table shows the employees covered by the life insurance benefit terms as of January 1: 2017 2016 Acti~ efll)loyees

.................................................................... 1 , 851 lnacti~ efll)loyees in retirement status..................................... 1 , 213 lnacti~ efll)loyees in long-term disabifity status ........... .............. 72 ------Total efll)loyees co~red by benefit terms.............................. 3 , 136 ------Contributions 2 , 003 1 , 077 74 3 , 154 The Board annually approves the funding for the Plan , which has a minimum funding requirement of the actuarially-determ in ed annua l required contribution

(" ARC") to ach i eve full funding status on or before December 31 , 2033. The District OPES contributions were $28.4 million and $74.7 million in 20 17 and 20 16 , respectively. Certa i n wholesale customers under the 2002 Contracts have pursued legal action rel ated to their objection of the i ndusion in rates of additional collections of previously incurred OPES costs. S i nce th e arbitration filing i n May 2016 , collections from these customers have been held i n separate accoun t s and have not been transferred to the Trust , pending the outcome of the legal action. The revenue collections for the catch-up OPES funding from these customers , which have not yet been transferred to the Plan , were $3.5 million and $1.6 million as of December 31 , 2017 and 2016 , re spectively. Contributions from i nactive Plan m embers for their s h a re of the prem i um payments are r eported as a r eduction of benefit expenses. Contribu ti ons from Plan members were $0.6 million and $0.5 million for 20 17 and 20 1 6 , respectively. B. Net OPEB Liability-The District's n et OPES li abi lity was m easu red as of January 1 , 20 17 , and January 1 , 20 16 , and th e t otal OPES li ability used t o calculate th e net OPEB liability was determ in ed by an actuarial valu a tion as of th ese dates. 50 Finain:o ia[ IR!epolit Actuarial Assumptions The actuarial assumptions used in the January 1 , 2017 , valuation were based on the results of an actuarial experience study for the period January 1 , 2016 through December 31 , 2016. The total OPEB liability in the January 1 , 2017 , actuarial valuation was determined using the following actuarial assumptions , applied to all periods included in the measurement , unless otherwise specified: Actuarial cost method . . . . . . . . . . . . . . Entry Age Normal Amortization method ...............

Level amortization of the unfunded accrued liability Amortization period ................. 16-year closed period Asset valuation method . . . . . . . . . . . . 5-year smoothed market Discount rate.......................... 6.25% Healthcare cost trend rates .. .... Pre-Medicare

7.3% i nitial , ultimate 4.5% Post-Medicare

9.1% initial , ultimate 4.5% Inflation

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

................... . Investment rate of return ......... . Mortality************

- - - - Retirement age ...................... . 2.1% 6.25%, net of investment e,q:,ense , including inflation RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 INith generational projection Varies by age The actuarial assumptions used in the January 1 , 2016 , valuation were based on the results of an actuarial experience study for the period January 1 , 2015 through December 31 , 2015. The total OPEB liability in the January 1 , 2016 , actuarial valuation was determined using the following actuarial assumptions , applied to all periods included in the measurement , unless otherwise specified: Actuarial cost method ............. . Amortization method .............. . Amortization period .............

... . Asset valuation method ........... . D i scount rate ...............

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

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

.................. . lm estment rate of return ......... . Mlrtafily

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

......... . Entry Age Normal le'.el amortization of the unfunded accrued liability 17-year closed period 5-year smoothed market 6.25% Pre-Medicare

8% initial, ultimate 5% Post-Med i care: 6. 75% i nitial , ultimate 5% 2.1% 6.25%, net of in\eSlment e)(J)el"lse , includin g i nflation RP-2014 Aggregate table projected back to 2006 using Scale '1.P-2014 and projected forward using Scale t.P-2015 with generational projection Varies by age Th e l ong-term expected rate of return on OPEB plan i nvestments was determined using a building-block method i n which best-estimate ranges of expected future rates of return (expected return s , n e t of OPEB plan i nvestment expense and i nflation} are developed for each major asse t dass. These ranges are combined to produce the long-term expected rate of r eturn by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected i nflation. F i nanoial Rel1l01 1 t The target allocation and best estimates of geometric real rates of return for each major asset class are summarized in the following table for the valuation measurement date of January 1 ,: Discount Rate Asset Class Equity (1) .............. . Fixed Income .......... . Asset Class Equity (1) .............. . Fixed I ncorne .......... . Target Allocation 70% 30% 100% Target Allocation 68% 32% 100% 2017 Long-Term Expected Real Rate of Return 6.8% 3.6% 6.1% 2016 Long-Term Expected Real Rate of Return 6.8% 3.5% 6.1% (1) The actuary included the 10% real estate allocation

'Nith equity. The discount rate used to measure the total OPEB liability was 6.25% for the actuarial valuations as of January 1 , 2017 and 2016. The projection of cash flows used to determine the discount rate assumed that contributions will be made at rates equal to the actuarially-determined contribution rates. Based on those assumptions , the OPEB Plan's fiduciary net position was projected to be available to make all projected benefit payments for current active and inactive employees. Therefore , the long-term expected rate of return on OPEB plan investments was applied to all periods of projected benefit payments to determine the total OPEB liability. C. Changes in the Net OPEB Liability-The following table shows the Total OPES Liability , Plan Fiduciary Net Position and Net OPEB Liability as of January 1 , 2017 , and the changes during this period , based on the valuation measurement date of January 1 , 2017 (in OOO's): Li ability Net Position Liability (a) (b) (a-b) Balances at 1/1/2016 ................

.................................................. . $ 333 , 833 $ 75 , 224 $ 258 , 609 Changes for the year: .................................................................... . ~cecost ....................................

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

............................... . 3 , 322 3 , 322 Inter est ......................

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

.............. . 20 , 658 20 , 658 Differences between expected and actual e>cperience

................. . (203) (203) Changes of assurJl)tions

.......................................................... . (1 8 , 807) (1 8 , 80 7) Contributions

-~er .......................................................... . 74 , 712 (7 4 , 712) Net i nleSbnent i ncome .....................................

........................... . 6 , 101 (6 , 101) Benefit payments ********** ........................................................... . (1 3 , 459) (1 3 , 459) Adrninislrati\e ellpeflSe

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

..***...***

- ...*..***..**...** (69) 69 Net changes ...........

..................................................................... . (8 , 489) 67 , 285 (7 5 , 774) Balances at 1/1/2017 ...............

.................................................... . $ 325 , 344 $ 1 42 , 509 $ 182,835 Net position as a % d T ot:11 OPES Li abirity .................................... . 43.8% 52 Financial iR~po n t There were changes made in certain assumptions for the valuation measurement date of January 1 , 2017. The mortality assumption was updated to the RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 with generational projection.

The health care trend dates were also updated. In December 2016 , the District initiated a voluntary early retirement incentive program (" Program") to all regular , full-time employees , excluding senior management , who met certain retirement-eligible criteria. There were 121 employees who accepted the offer. The impact of the Program was included in the January 1 , 2017 actuarial valuation.

Sensitivity of the Net OPES Liability to Changes in the Discount Rate The following table shows the net OPES liability of the District , as well as what the net OPES liability would be if it were calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1 , 2017 (in OOO's): 1% Decrease Discount Rate 1% Increase Net OPES Liability . . . . . . . . . . . . . . . . $224 , 980 $182 , 835 $147 , 850 Sensitivity of the Net OPES Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPES liability of the District , as well as what the net OPES liability would be if it were calculated using healthcare cost trend rates that are 1-percentage-point lower (Pre-Medicare ranging from 6.3% initial to 3.5% ultimate , Post-Medicare ranging from 8.1 % initial to 3.5% ultimate) or 1-percentage-point higher (Pre-Medicare ranging from 8.3% initial to 5.5% ultimate , Post-Medicare ranging from 10.1 % i nitial to 5.5% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 7.3% initial to 4.5% ultimate , Medicare ranging from 9.1 % initial to 4.5% ultimate) at the measurement date of January 1 , 2017 (in OOO's): 1% Decrease Net OPES Liability . .. .. .. . .. .. . . .. $148 , 629 Healthcare Cost Trend Rates $182 , 835 1% Increase $223 , 946 The following table shows the Total OPES Liability , Plan Fiduciary Net Pos iti on and Net OPES Li ability as of January 1 , 2016 , and the changes during this period , based on the valuation measurement date of January 1 , 2016 (in OOO's): Total OPEB Plan Fiduciary NetOPEB Li abiity Net Position Liability (a) (b) (a-b) Balances at 1/1/2015 ............................................

...................... . $ 323 , 1 22 $ 64 , 487 $ 258 , 635 Changes for the year: .................................................................. . Seniice cost ..................................

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

........ . 3 , 228 3 , 22 8 Inter est .................

.................................................................. . 19 , 877 19 , 877 Differences between ellpeeted and actual experience

................. . 1 3 , 657 13 , 657 Changes of assufll)lions

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

........................................... . (9 , 149) (9 , 149) Contributions

-elJl)loyer

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

..... . 28 , 242 (28 , 242) Net i nvestment i ncome ............................................................. . (453) 453 Benefit payments .............................

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

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

..... . (1 6 , 902) (1 6 , 902) Administrative e>epenSe *****************

- - - - (1 50) 150 Net changes ..........

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

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

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

............. . 10 , 711 10,7 37 (26) Balances at 1/1/201 6 ..........................................

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

........... . $ 333 , 833 $ 75 , 224 $ 258 , 609 Net position as a % of Total OPEB Li ability .................................... . 22.5% F i nancia l R!~p@nt 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 i lity would be if i t were calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) t han the d i scount rate (6.25%) at the measurement date of January 1 , 2016 (i n OOO's): 1% Decrease Discount Rate 1% Increase Net OPEB Liability................ $306 , 681 $258 , 609 $219 , 295 Sensitiv i ty of the Net OPEB Liability 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 liability would be i f it were calculated using healthcare cost trend rates that are 1-percentage-po i nt lower (Pre-Medicare r ang i ng from 7% initial to 4% ultimate , Post-Medicare ranging from 5.75% in i tial to 4% ultimate) or 1-percentage-point higher (Pre-Medicare ranging from 9% i nitial to 6% ultimate , Post-Medicare rang i ng from 7.75% initial to 6% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 8% init i al to 5% ultimate , Post-Medicare ranging from 6.75% i nit i al to 5% ultimate) at the measurement date of January 1 , 2016 (in OOO's): 1% Decrease Net OPEB Liability.

............... $219 , 672 OPEB Plan F i duciary Net Pos i t i on Healthcare Cost Trend Rates $258 , 609 1% Increase $306 , 151 The following tab l e shows i nformation on the OPEB Plan F i duciary Net Pos i tion as of December 31 , (in OOO's): Assets: Cash and cas h equivalents

..........

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

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

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

.... . Receivables

Contrib uti ons .....................................................................

................. . l n~trnent in come ............

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

........ . ln~nts .....................................................................

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

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

................................................................. . Li abi liti es: Payables: Benefits -heallh c are .....................................................

..................... . Ben efi ts -lif e i nsu ranc e ......................................

................................ . In~ e)9)el1Se

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

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

............................. . Total li abi liti es ................................................................................ . Net Position -Restri c ted for Other Postenl)loy men t Ben efi ls ......................

...... . 54 20 1 7 2016 $ 3 , 027 1 49 45 1 1 73 , 4 1 9 177 , 046 1 48 33 5 1 232 $176 , 8 14 $ 9 , 609 53 261 1 32,875 1 42 ,7 98 1 28 29 85 289 $14 2 , 509 Finalil oi al R~p 0n t The following tables show the OPEB assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , 2017 (in OOO's): Quoted Prices in Act i ve Markets for Identical Assets (Level 1) U.S. Treasury and government agency securities

.. $ Corporate issues ..............................................

.. . Foreign issues ................................................... . Municipal issues ................................................. . Domestic common stocks ................................... . 45 , 678 Foreign stocks ................................................... . 4 , 002 Mutual funds .................................................

..... . 64 ,1 83 $ 113 , 863 S i gnificant Other Observable Inputs (Level 2) $ 15,956 28,056 6 , 629 779 $ 51 , 420 Significant Unobservable Inputs (Level 3) $ $ $ $ Total 15 , 956 28 , 056 6 , 629 779 45 , 678 4 , 002 64 ,1 83 165,283 Other investments measured at net asset value (A) . 8 ,1 36 $ 173 , 419 (A) The fair value of investments i n a real estate fund has been estimated using the net asset value per share (or its equivalent) practical expedient and has not been classified in the fair value hierarchy.

The fund allows for quarterly redemption with a 90-day notice. There are no unfunded commitments to the fund as of December 31 , 2017. 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 , 2016 (in OOO's): 2016 Level 1 L e'vel 2 Le'vel 3 Total U.S. Treasury and government agency secur iti es .. $ $ 2 , 678 $ 2 , 678 Corporate issu es ................................................ . 18 , 16 2 18 , 162 Foreign issues ................................................... . 5 , 161 5 , 161 Municipal issues ...........

...................................... . 766 766 Domestic conmon stocks ................................... . 39 , 002 39 , 002 Foreign stocks ........................................

............ . 3 , 569 3 , 569 Mrtual funds ...........

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

...................... . 63 , 537 63 , 537 $106 , 108 $ 26 , 767 $ $ 132 , 875 D. OPEB Expense , Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB-The Board annually approves the OPEB expense i n rates and has authorized the use of regulatory accounting to equate OPEB expense with the amount in rates. OPEB expense was $16.7 million for 2017 , as calculated under the GASB 75 guidance. With regulatory accounting , OPEB expense and th e amount i nduded in rates was $53.3 million for 2017. This amount i nduded a $25.0 milron catch-up rate collection f or the net OPEB li ability for past production-level services. F ii namoial R!e i prnrnt The following table summarizes the reported deferred outflows and deferred inflows of resources as of December 31 , 2017 (in OOO's): Deferred Outflow Deferred Inflow Difference between actual and expected experience

$ 3 , 030 $ 16 , 475 Difference between expected and actual earnings on investments

........... . 3 , 283 Contributions made during the year ended December 31 , 2017 .............. . 28 , 290 Total Deferred Outflows .................................................................. . $ 34 , 603 $ 16 , 475 The deferred outflows of resources related to the contributions made during the year ended December 31 , 2017 will be recognized in the actuarial valuation with a measurement date of January 1 , 2018. The net of the other deferred outflows and deferred inflows of resources will be recognized as a reduction in OPEB expense as follows (in OOO's): Year Amount 2018 .......... $ (733) 2019 .......... (733) 2020 .......... (734) 2021 .......... (1 , 699) 2022 .......... (2 , 461) 2023 .......... (2 , 535) 2024 .......... {1 , 267} Total $!10 , 162~ OPEB expense was $20.6 million for 2016 , as calculated under the GASB 75 guidance. VVith regulatory accounting , OPEB expense and the 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 OPEB as of December 31 , 2016. The following table summarizes the reported deferred outflows of resources as of December 31 , 2016 (in OOO's): Difference between actual and expected experience

.......................... . $ Difference between expected and actual earnings on im estments ...... . Contribut i ons made during the year ended December 31 , 20 16 .......... . Total Deferred Outflows .....................................................

.......... . $ 2016 3 , 769 3 , 862 74 , 658 82 , 289 The deferred outflows rel ated to the contribu ti ons made during the y ear ended Decembe r 31 , 2016 were r ecognized in the actuarial valuation with a measurement date of J anuary 1 , 2017. Th e other deferred outflows o f r esources will be r ecognized in OPEB expense as follows (in OOO's): Year Amount 20 17 ...... $ 1 , 705 20 18 ...... 1 , 704 20 19 ....... 1 , 705 2 0 2 0 ...... 1 , 704 2021 ...... 739 2022 ...... 74 Total $ 7 , 631 Additional i nform a tion i s a v a ilabl e i n th e unaudited Required S upplementary lnfonnation section followin g th e Notes to Financial Statements. 56

12. COMMITMENTS AND CONTINGENCIES

A. Fuel Commitments

-The District has various coal supply contracts with minimum estimated future payments of $103.0 million at December 31 , 2017. These contracts exp i re at various t i mes through the end of 2020. The coal transportation contract in place is sufficient to deliver coal to the generation facilities through and beyond the expiration date of the aforementioned contracts and is subject to price escalation adjustments. The District has a contract for uranium purchases and deliveries in 2018 , a contract for conversion services of uranium to uranium hexafluoride which is in effect through 2021 , a contract for enrichment services through 2024 , if needed , and a contract for fabrication services through January 18 , 2034 if needed , the end of the current operating license of CNS. These commitments for nuclear fuel material and services have combined estimated future payments of $233.0 million. B. Power Purchase and Sales Agreements

-The District has entered int o a participation power agreement (the " NC2 Agreement")

with OPPD to purchase 23.7% of the power of NC2 , estimated to be 157 MW of the power from the 664 MW coal-fired power plant 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 service , other costs , and reserves related to NC2 as a result of a defaulting power purchaser. The District's obl i gation pursuant to such step-up provision i s limited to 160% of its original participation share (23.7%). No such default has occurred to date. The District has entered into a part i cipation power sales agreement with Municipal 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 int o power sales agreements with LES for the sale to LES of 8% of the net power and energy of GGS. In return, LES agrees to pay 8% of all costs attributable to GGS. This agreement i s to terminate upon the later of the last maturity of the debt attributable to the station or the date on which the District retires such station from commercial operation. The District had entered into a power sales agreement with LES for the sale to LES of 30% of the net power and energy of Sheldon. In return , LES agreed to pay 30% of all costs attributable to Sheldon. The District and LES executed a termination and release agreement in May 20 17 for the Sheldon Station Participat ion Power Agreement with the termination effective December 31 , 2017. The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately

$36.3 million. These purchases are subject to rate changes. The District owns and operates th e 60 MW Ainsworth Wind Energy Facility and h as 20-year participation power agreements to sell 28 MW to four other utiliti es. In add ition , the District has power purchase agreements with seven wind facilities having a total capacity of 435 MW. These ag r eements are for term s ranging from 20 to 25 y ears and requir e the District to purchase all the electric power output of th ese wind facilities. 11le District h as entered i nto power sales agreements to sell 1 54 MW of this capacity to four other utilities i n Nebraska over s im i lar term s. Th e District ha s entered i nto a power purchase agreemen t with Central for th e purchase of th e net power and energy produced by the Kingsl e y Project during its operating lif e. Th e Kingsley Project i s a hydroelectric generating unit at the Kingsley Dam i n Keith County , Nebraska with an accredited net capacity of 37 MW. The District ha s entered *nto l ong-term PRO Agreements h a ving i nitial term s of 1 5 , 20 , or 25 years with 79 municipaliti es for the operation of certain retail electric distribution systems. These PRO Agreements expire on variou s years between 2023 and 2042. These PRO Agreements obligate th e D i strict to make payments based on gross revenues from the mun i cipalities and pay fur normal property additions du ri ng the t erm of the agreement C. Wholesale Power Con t racts -The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District , subject to certain exceptions. In 2016 , the District entered into 20-year VVholesale Power Contracts

("2016 Contracts") with 23 public power d i stricts , one cooperative , and 37 municipalities. One public power d i str i ct and 9 municipalities are served under 2002 VVholesale Power Contracts

(" 2002 Contracts"), which expire on December 31 , 2021. The 2016 Contracts allow a wholesale customer to give not i ce to reduce its purchase of demand and energy r equirements from the Distr i ct 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 i n the Nat i onal Rural Utilities Cooperative F i nance Corporation Key Rat i o Trend Analys i s (Ratio 88) (the " CFC Data"). The CFC Data places a util i ty's power costs i n percent i les so t hat any given util i ty can compare i ts power costs on a percentile bas i s t o the CFC publ i shed quart il e i nformat i on. The 2016 Cont r acts allow a wholesale customer to reduce its demand and energ y purchases from the Distr i ct i f the District's average annual wholesale power costs pe r centile level for a given yea r i s higher than the 45 th percen ti le level (the " Performance Standard Percentile

") of the power costs of U.S. utilities for such year as l i sted in the CFC Data. The 2016 Contracts would not allow any reductions i n demand and energy purchases by a wholesale customer as long as the Distric t's average annual wholesale power costs pe r centile remained below the Performance Standard Percentile. T h e follow i ng table l i sts t he Dist ri ct's wholesale power costs percent i le for the ca l endar years 2012 to 20 1 6 se t forth i n the CFC Data: CFC Data Year Pe r centile 2012 29.1% 2013 3 1.0% 2014 27.6% 2015 3 1.3% 2016 28.2% Th e D i s tri ct h as ten wholesa l e customers r emaming o n th e 2002 Con tr acts. T h e 2002 Contracts al l ow a wh olesale custo m e r t o r educe i ts purchases of demand a n d energ y upon g i v i ng app r op ri ate not i ce. Reductio n s could amoun t t o as much as 90% of the ir demand a n d energy requ i remen t s unde r certa i n circumstances. Al l wh olesa l e custo m ers unde r th e 2002 wholesale contracts a r e r equ i red t o p ur chase a t least 1 0% of th e i r dema nd a n d energy fr o m th e D i s tri ct thro ug h Decembe r 3 1 , 2 0 2 1. Th e D i s tri ct h as r ece i ved n o ti ces fr om all wh o l esa l e cust om ers un der th e 2 00 2 Co ntr acts as t o th e i r int en t t o le v e l o ff , r educe , o r t e rmin ate th e req uir e m e n ts f or va ri o u s a m o un ts fro m 2 017 thr o u g h 2 0 2 1. The te n cus t o m ers in d u de one mun i ci pal ity wh ich h as a s h o rt-t erm wh olesale co ntr act which t e rmi nated i n May 2 01 6. Th ese wh olesale cu st o mers r eprese nt ed 4.8% an d 4.5% of opera tin g rev e nu es f o r 2 017 a n d 2 01 6 , r es pectiv el y. Th e Di s tri ct expects th a t n o r eq ui re m e nt s of sa i d wh o l esale cu s tom ers will be se rv ed by th e Di s tri ct in 2 0 22 , an d such wh olesale cu s t o m ers will p u r ch ase all o f th e ir el ectri c r eq uiremen ts fr o m o th er s uppli ers. Th e D i s tri ct expects to seU th e e n e rgy n o t so ld t o s uch wh o l esale cu s tom ers i nto th e S P P Int egra ted M a rk e t a nd contin ues t o e xplore a dditi o n al firm requirem en t a nd/or fix ed pri ce ag reem e nts. In 2016 , thr ee of th e Di s trict's munici pa l whol esale custom e rs began purch a sin g power from thr ee of th e Dismcf s publi c power district whol esa l e cu s tom ers. Th ese cu s tomers represent ed 0.1 % of th e Di s trict's 2 016 ope rating reven ues. O n e of th e District's munici pal whol esa l e customers allow ed their contract to termin a t e. Th i s customer represented l ess th a n 0.1 % of th e Di s tri ct's 2016 operating revenu es. Th e 2016 whol esa: e rat es resulted i n a 0.6 % i n aease for whole sale cu s tomers who sign ed the 2 016 Contracts , and a 3.8% i ncrea se for tho se whol esale customers wh o remained und er the 2002 Contra cts. C ustom ers under th e 200 2 Contracts will pay their shar e of previou sl y *ncurred O PEB costs (or th e catch-up amount) through rat es prior to th e e xpiration of the i r contracts

n 2 021. Cu s tom ers under th e 2016 Conbacts receiv ed a discount for lh e deferral of O P EB collections , extending th ose collection s* to th e new contract period and resulting

-n th e l ower 58 Fi:nancia[

Report net wholesale rate increase.

The District financed with taxable debt the 2016 Contracts customers' share of the OPEB catch-up amount for 2016 and 2017 and plans to issue additional taxable debt for catch-up funding in 2018. The customers under the 2016 Contracts will commence payment of the related debt service beginning in 2022 , the year after the expiration of the 2002 Contracts.

Eight of the ten wholesale customers who remained under the 2002 Contracts filed for binding arbitration in May 2016 claiming the 2016 wholesale rate violates the 2002 Contracts , is contrary to Nebraska's r ate statute and reflects bad faith toward those not signing the 2016 Contracts. These customers have since added the OPEB component of the 2017 wholesale rate to their dispute. The arbitration panel ruled in favor of the District in April 2017. This case was appealed and argued before the Nebraska State Supreme Court ("Court")

in March 2018. The District is awaiting the Court decision. Since the arbitration filing in May 2016 , disputed amounts have been set aside in separate accounts. The amount of disputed revenues in the separate accounts was $2.5 million and $0.9 million as of December 31 , 2017 and 2016 , respectively.

The Northeast Nebraska Public Power District filed a lawsuit in the District Court of Wayne County , Nebraska regarding the demand and energy reduction provisions under the 2002 Contract.

The court issued an order dated February 26 , 2016 , in favor of the Northeast Nebraska Public Power District which allows them to redu ce their demand and energy purchases from the District by 30% in 2018 , 60% in 2019 and 90% in 2020. The court decision will apply to certain other customers who have given notice for demand and energy reductions under the 2002 Contract. On March 23 , 2016 , the District filed a notice of appeal. The Nebraska Court of Appeals affirmed the District Court decision in June 2017. The Nebraska Supreme Court declined to review the matter in September 2017. D. SPP Membership and Transmission Agreements

-The District is a member of SPP, a regional transmission organization based in Little Rock , Arkansas. Membership in SPP provides the District reliability coordination service , generation reserve sharing , regional tariff administration , induding generation interconnection service , network , and point-to-point transmission service , and regional transmission expansion planning. The District was able to participate in SPP's energy imbalance market , a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost , through February 2014. On March 1 , 2014 , SPP commenced a Day-Ahead , Ancillary Services , and Real-nme Balancing Market Integrated Market. The Integrated Market also provides a financial market to hedge unplanned transmission congestion , or financial virtual products to hedge uncertainties , such as unplanned outages. The District entered int o a Transmission Facilities Construction Agreement effective June 15 , 2009 , with TransCanada Keystone Pipeline , LP ("Keystone

). This agreement addresses the transmission facilities , construction , cost allocation , payment , and applicable cost recovery for the int erconnection and delivery facilities required for the int erconnection of Keystone to the District's transmission system. Cost of the project was $8.4 million and r epayment by Keystone , over a 10-year period , began in June 2010 with a remaining balance due the District of $2.6 million and $3.5 million as of December 31 , 2017 and 2016 , r espectively. The District entered into a second Transmission Facilities Construction Agreement effective July 17 , 2009 , with TransCanada Keystone XL Pipeline , LP r Keystone XL.). This agreement addresses the transmission facilities , construction , cost allocation , payment , and applicable cost r ecovery for the int erconnection and delivery facilities required for the i nterconnection of Keystone XL to the District's transmission s yst e m. TransCanada Corporation and TransCanada Pipeline USA Ltd. h ave jointly and severally guaranteed the payment obligations of Keystone under its agreements with th e District.

The agreement was cancelled in 20 16 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 , th e NRC formally i ssued a certificate to the O"strict to commemorate the renewal of th e operating licen se for CNS ror an additional 20 y ears until January 18 , 2034. CNS entered the 20-year period of extended operation on January 18 , 2014. Fim:aJ11cial IR~p0rt 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 either party's right to terminate without cause by providing notice and paying a $20 million termination charge. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services , and to pay Entergy annual management fees. These annual management fees were $18.5 million for 2017 and $18.5 million for year 2016. These fees will increase by an additional

$1.0 million in 2019 , and by an additional

$3.0 million in 2024. Entergy is eligible to earn addit i onal incentive 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 District , as well as the rest of the nuclear industry , has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the General Electric ("GE") boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes 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 NRC approved seven of the Task Force recommendations for im plementation. On March 12 , 2012 , the NRC i ssued three orders to the U.S. nuclear in dustry as a result of the Fukushima i chi event in Japan. The first order requires all domest i c 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 containment wetwell vents. The third order requires nuclear plant operators to add reliable spent fuel pool water level in strumentation. The NRC has also i ssued a request for information pertaining to re-evaluation of seism ic 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 requires a drywell vent or a basis and strategy for why venting the drywell would not be required , will be completed by the condusion of the fall 2018 refueling and maintenance outage. Since the initial site-specific seismic r eevaluation analys i s for CNS that r esulted in no id entified se i sm i c-related modifications to CNS , the District has performed an add ition al se ismi c analys is and has worked to answer additional questions from the NRG on this topic. The NRC has determined th at CNS will have to perform the High Frequency Evaluation and a Spent Fuel Poo l Evaluation , but will not h ave to complete a Se i sm i c Probabilistic Risk Assessment.

Unknown to th e District at this tim e is the extent of modification s th at may be required as a result of these additional seismic reev alua tions. The District continues to work with the U.S. Army Corps of Engineers and the NRC to validate the data necessary to complete th e CNS flood hazard reevaluation.

The D i strict submitted its upd a ted flooding analysis to the NRC *n February 2015. The NRC subsequently submitted questions to which th e District h as responded and submittal of the upd ated flood h aza rd reevalu a tion was completed

n September 2016. Based on current i nterim , and term strateg i es for flooding mitig ation , it i s not expected that any modifications will be r equired as a result of the flood hazard reevaluations. All equipment and material s required to mitig ate the *dentified i mpacts associated with the flood hazard reevaluation hav e been purch ased and the equipment required has been in stalled. Additional equipment purch ased , but not r equired to be *nsta1led un ess an i ssue occurs , i s stored on-site in ded i cated storage facilities. The District's cost estimate for plant modification s associated with the NRC's Fukushima Dai-ichi related orders *s currentty estimated to cost $23.3 million , wh. ch i s expected to be funded primarily rrom th e revenues of th e D istrict and from the proceeds of General Revenue Bonds. As of December 31 , 2017 , $17.3 mi lion ha s been spent on 60 Fin.anoial Repo11t plant modifications with an additional

$6.0 million expected to be spent to establish compliance with the Fukushima Dai-ichi orders. CNS substantially completed the construct i on of a dry cask used fuel storage project in December 2009 to support plant operations unt i l 2034 , which i s 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 e i ght dry used fuel storage casks for on-site storage. A second loading campaign , encompassing the l oading of 610 used fuel asse m blies into ten dry used fuel storage casks , began in April 2014 and was completed i n June 20 1 4. The third loading campaign , encompassing the loading of 732 used fuel assemblies into 12 dry used fuel storage casks , began i n June 2017 and was completed i n Novembe r 2017. As part of va ri ous d i sputed ma tt ers between GE and the D i str i ct , GE has agreed to cont i nue to store at the Mor ri s Facility the spent nuclear fuel assemblies from the first two full core load i ngs at CNS at no additional cost to the D i strict until the expiration of the current NRC l i cense i n May 2022 for the Morris Facil i ty. After that date , storage would continue to be at no cost to the District as long as GE can mainta i n the NRC license for the Morris Facilit y on essentially the ex i sting des i gn and operat i ng configurat i o n. As a r esult of the fa i lure o f t he DOE to dispose of spent nuclear fuel from CNS as r equ i red by contract , the District commenced lega l action aga i nst t he DOE on March 2 , 200 1. The i n i t i a l settlement agreement addressed future cla i ms through 20 1 3. On January 13 , 2014 , the District and the DOE agreed to extend the settlemen t ag r eemen t t h rough 2016. On March 2 , 20 1 7 , the Dist ri ct and the DOE agreed to extend the settlement agreement throug h 2019. The D i s t r i ct has received $118.2 m i llion from the DOE for damages from 2009 through 2016. The Distr i ct also reserves the ri ght to pursue future damages through the contract cla i ms process. A correspond i ng regulatory liability for t h ese DOE rece i pts was established i n Other defer r ed i nflows of resources. The Dist ri ct plans to use t he funds to pay f o r costs re l ated to CNS. The balance in the r egu l a t o ry l i abili ty w as $66.2 million and $82. 7 mi llion as of Decembe r 3 1 , 20 17 and 2016 , respectively. Under the tenns of the DOE cont r acts , t he Distr i ct was a l so subject to a one mill pe r k i lowa tt-hour (" k\Nh") fee on all e n ergy ge n era t ed and sold by CNS wh i ch was pa i d o n a quarter1y bas i s t o DOE. The District i ncludes a component in i ts wholesale and r eta i l rates fo r the purpose of funding th e costs associated wit h n udear fue l d i sposal. V\lh il e th e Dis trict expects that the r e v enues developed therefro m will be s uffi cie nt t o cove r th e D i s tri ct's r espons i b i l i ty f o r costs cu rr e ntly outl i ned i n th e Nuclear Was t e Pol i cy Act , th e D i s tri ct ca n g i ve no assu r ance th a t s uch r even u es wi ll be s uffici e nt t o cover all costs associa t ed wi th th e d i sposal of u sed n udea r fue l. O n Ma y 9 , 20 1 4 , th e DOE pr o vi ded n ot i ce th a t they would adjust the spen t fu e l d i sposa l f ee to ze r o m ill s pe r kV\lh e ff ecti v e Ma y 1 6 , 20 1 4. Co rr espo n d in gl y , no add iti onal payments h ave bee n m ade to th e DOE fo r fu el disposa l s in ce th a t d a t e. Th e Boa rd a uth orized th e co nti nued collection of thi s fee at th e sa m e ra t e. Thi s approach e n s u res costs a re r ecognized in th e app r op ri ate pe ri od with cu rr ent cus t omers r ece ivin g th e b e n e fit s from C N S p ay i ng th e ap pr op ri ate costs. Th e expe n se f or spent nu dear fue l d i sposa l i s r eco rd ed b ased on n e t el ectricity ge n era t ed a nd so l d a n d th e r eg ul a t o ry li a bility will be el imin ated whe n pa ym e n ts are m a d e for spe nt nud ea r fu el di sposa l. Un de r th e provi s ion s of th e Fed eral Pri ce An derso n A ct , th e D i s trict a n d a ll o th e r licen sed nu dea r po wer pl a nt o perators could ea ch be assessed for d a im s in a m o u nts up to $1 2 7.3 million per unit own ed in th e e vent of a ny nud ear inci de nt i nvolvin g any li ce n sed fa ci l ity i n th e n a tion , with a maximum assess ment of $19.0 million per y ear per i ncid e n t per unit owned. Th e N RC e valu a te s nud ear pl a nt performan ce as p a rt of its r ea ctor oversi g ht process r RoP~). The NRC h as five perform a n ce ca t eg ori es induded in th e R O P Acti o n M a trix S umm a ry th a t i s part of thi s process. As of Decem be r 31 , 2017 , CN S wa s in th e Licen see Re spon se Column , which i s th e first or best of th e fiv e NRC d e fined perform a nce ca tegori es and h as been i n thi s column sin ce th e first quarter of 2012. Refuelin g and m a inten a n ce outag es a r e required to be performed a t CN S a pproxim a tely every two y ears. The most recent refuel i ng a nd m a inten ance ou ta g e beg a n on Sep tember 25 , 2016 and was compl et ed on November 8 , 2016. During thi s outag e , i n a ddition to replacin g 184 fuel assembli es a nd conducting routin e m a int e n a n ce , equ i pment replacements i ndud ed on e of th e two reactor water recirculation pump i mpell ers a nd motor , th e startup station transformer and the hi g h pressur e turbin e. F i nancial IR!ep>ID11t Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs , commencing in 2017. The regulatory liability for the pre-collection of outage costs was $20.0 million as of December 31 , 2017 and will be eliminated through revenue recognition during the 2018 outage year. F. Environmental

-Water The Federal Clean Water Act contains requirements with respect to effluent limitations relating to the discharge of any pollutant and to the environmental impact of cooling water intake structures. The NDEQ establishes the requirements for the District's compliance with the Clean Water Act through issuance of National Pollutant Discharge Elimination System permits. NDEQ issued the District permits for the following facilities

GGS , Sheldon , CNS , Beatrice Power Station , Canaday Station , Kearney Hydro and the North Platte Office Building. The District anticipates some level of fish protection equipment technology installation , both for impingement and entrainment , may be necessary for CNS and only for impingement at GGS. Until the final compliance options are determined , the District does not know the financial impact of this regulation. On January 2 , 2016 , the final Steam Electric Power Plant Effluent Guidelines rule (the " Effluent Rule") became effective.

The Effluent Rule revises the technology-based effluent limitation guidelines and standards that would strengthen the existing controls on discharges from steam electric power plants and sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants , based on technology improvements in the steam electric power industry over the last three decades. Generally , the Effluent Rule establishes new or additional requirements for wastewater streams from the following processes and byproducts associated with steam electric power generation

flue gas desulfurization , fly ash , bottom ash , flue gas mercury control , and gasification of fuels such as coal and petroleum coke. VVhile the District facilities subject to the Effluent Rule are CNS , GGS , Sheldon and Canaday Station , the Effluent Rule only has an impact on Sheldon. Sheldon will be required to be a zero discharge facility for bottom ash transport water by December 31 , 2023. The District is currently analyzing the options for compliance , which is estimated to cost $2.4 million. EPA has listed this rule as one they will consider for regulatory reform and the requirements may be subject to change. Acid Rain Program The Clean Air Act Amendments Title IV established a regulatory program , known as the Acid Rain Program , to address the effects of acid rain and impose restrictions on sulfur dioxide ("S02") and nitrogen oxides (" NO x") emissions. Acid Rain Permits have been issued for the following facilities

GGS , Sheldon , Canaday Station and Beatrice Power Station. The Acid Rain Permits allow for the discharge of S02 at each facility pursuant to an allowance system. The District expects to have sufficient allowances for its generating facilities through 2023 , but may be required to purchase additional allowances in the Mure. Mercury and Air Toxic Standards On February 16 , 2012 , the EPA i ssued a final rule int ended to reduce emiss i ons of toxic a i r pollutants from power plants. Specifically , the Mercury and Air Toxics Standards

(" MATS") Rule will require reductions in em i ssions from new and existing coal-and oil-fired steam utility electric generating units of toxic a ir pollutants. The affected District facilities , which are GGS and Sheldon , are in compliance with the MA TS Rule. Cross-State Air Pollution Rule The EPA i ssued a rule in 20 12 which i s r eferred to as th e Cross-State Air Pollution Rule r cSAPR") that would require s i gnificant r eductions in S0 2 and NOx em i ss ion s i n a number of states , indu ding Nebraska. CSAPR compliance periods went into effect on January 1 , 20 15. Based on the current CSAPR allocation methodology and current generation projections through 2023 , th e District expects to have sufficient CSAPR allowances to cover affected facil iti es e mission requ irements over th a t tim eframe , but may be r eq uir ed to purchase add itional allowances i n the futu re. Regional Haze The EPA i ssued fin al r egulations for a Reg ional Haze Program *n J ne 19 99. The pu rpose oflhe r egulations i s to *mprov e visibility i n the form of reduci g reg*ona1 h aze *n 156 national parks and wi demess areas across th e country. Haze i s formed , *n part, from em i ssions of S0 2 and o ... 62 EinaNoi~l Repc 1 rnt For phase one of the Regional Haze rule the Best Available Retrofit Technology

("BART") Report was submitted to the NDEQ in August 2007 and a revised report was submitted in February 2008. The BART Report proposed that the Best Available Retrofit Technology to meet regional haze requirements at GGS would be low NOx burners on Units No. 1 and No. 2 and no additional controls for S02. Low NOx burners have now been installed on both units at GGS. The NDEQ State Implementation Plan (" SIP") agreed with the BART Report. The NDEQ submitted the SIP to the EPA for approval on June 30 , 2011. On May 30, 2012, the EPA issued a rule pertaining to the Regional Haze Program that would approve the trading program in CSAPR as an alternative to determining BART for power plants. As a result , states in the CSAPR region may substitute the trading program in CSAPR for source-specific BART for S02 and/or NOx emissions as specified by CSAPR. On July 6 , 2012 , the EPA issued the final rule on the Nebraska Regional Haze SIP. The final rule approved the GGS NOx portion of the SIP but disapproved the S02 portion of the SIP for GGS. The EPA issued a Federal Implementation Plan (" FIP") for GGS which stated that BART for S02 control at GGS is compliance with CSAPR. The District is currently in compliance with all requirements of phase one of the Regional Haze rule. On January 10 , 2017 , the EPA issued final changes to the Regional Haze regulations for the second planning phase of the Regional Haze Rule. The District 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 is required to submit their SIP for the second phase of the Regional Haze rule by July 31 , 2021. Clean Air Act Compliance (New Source Review) As part of EPA's nationwide investigation and enforcement program for coal-fired power plants' compliance with the Clean Air Act induding new source review requirements , on December 4 , 2002 , the Region 7 office of the EPA began an investigation to determine the Clean Air Act compliance status of GGS and Sheldon. The District timely responded to EPA's requests for information.

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

("NOV") to the District which alleges that the District violated the Clean Air Act by undertaking five projects at GGS from 1991 through 2001 without obtaining the necessary permits. In February and August 2009 , District representatives met with federal government representatives to discuss the NOV and no additional meetings have been scheduled. In general , enforcement action by EPA against the District for alleged noncompliance with Clean Air Act requirements , if upheld after court review , can result in the requirement to install expensive air pollution control equipment that is the BART and the imposition of monetary penalties ranging from $25 , 000 to $32 , 500 per day for each violation. The District cannot determine at this time whether it will have any Mure financial obligation with respect to the NOV. On July 22 , 2016 , EPA Region 7 sent a new 114(a) request for documents and i nformat i on regarding the compliance status of GGS. On December 27 , 2016 , EPA Region 7 sent a 114{a} follow-up request for additional information on certain projects that were identified in the July 22 , 2016 , 114{a) request The EPA is reviewing whether there have been physical or operational changes since November 8 , 2007 which resulted i n , or could result i n , increased emissions induding projects undeJWay or planned for the next two years. The District gathered documents and i nformation and provided it to the EPA. Failure to comply with the Clean Air Act can result i n fines as described above and/or requirements to i nstall additional emission control equipment.

The District believes GGS has been operated and maintained i n compl i ance with the r equ ir ements of the Clean Air Act. Clean Power Plan On October 23 , 2015 , the EPA published the final Clean Power Plan r cPP~) rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states s i gnificant responsibility for determ i ning how to achieve the reduction targets through the development of a State Plan. Each state was given a r eduction target to be ach i eved by 2030 , with i nterim reductions r equired between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 em i ssions. On February 9 , 2016 , the U.S. Supreme Court i ssued a stay for the CPP until all l egal challenges have been decided. The O.C. C i ra.iit Court of Appeals h eard oral arguments on September 27 , 2016 and a decision was expected i n early 2017. Prior to the Court *ssu i ng a decision , the EPA asked the Court to hold the legal process *n abe y a oe wtf e the EPA worked to repeal and replace the CPP. F i nancia l R~J!>O li t On October 16 , 2017 , the EPA published a proposed rule to repeal the CPP on the basis that the CPP exceeded the authority of the EPA. Comments are due on April 26 , 2018. On December 28 , 2017 , the EPA published an Advanced Notice of Proposed Rulemaking

("ANPR") seeking input on what a CPP replacement rule should include. Comments on the ANPR were due on February 26 , 2018. Due to the stay and the EPA process to repeal and replace the CPP with a new rule , the NDEQ and the District have halted all work on implementing the CPP. It is unknown at this time what the potential impact to the District will be until the EPA finalizes the CPP replacement rule. Impact from Changes to Environmental Regulatory Requirements Any changes in the environmental regulatory requirements imposed by federal or state law which are applicable to the District's generating stations could result in increased capital and operating costs being incurred by the District.

The District is unable to predict whether any changes will be made to current environmental regulatory requirements , if such changes will be applicable to the District and the costs thereof to the District. G. Sale of Spencer Hydro Facility-In September 2015 , a memorandum of understanding

("MOU") was signed for the sale of the Distr i ct's Spencer Hydro (" Spencer")

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

") (Five Natural Resource Districts) and the Nebraska Game and Parks Commission

(" NGPC") for $12.0 million. The 2015 MOU that was signed expired on June 1 , 2017. Following the expiration , both parties have negotiated an agreement for the sale and purchase of the Spencer facility. It was distributed to the Alliance and NGPC in December 2017 for signatures.

Currently , there is no agreement in place. 13. LITIGATION

On January 1 , 2016 , Tri-State Generation and Transmission Association , Inc. (" Tri-State") became a transmission member of SPP and its transmission facilities in western Nebraska, and the corresponding annual transmission revenue requirements were placed under the SPP tariff. SPP filed at FERC to place the Tri-State transmission facilities in the District's pricing zone rather than establish a new pricing zone for Tri-State.

The District protested the filing at FERC , because it results in approximately a $4.3 million per year , or 8%, cost shift in crease to the transmission customers in the District'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 pricing zone and whether SPP's decision i s discriminatory and an unjust and unreasonable cost shift to the District. On February 23 , 2017 , the admin i strative law judge issued an initial decision upholding the SPP pricing zone placement and made recommended condusions to FERC. This i nitial decision has no l egal effect until reviewed and acted upon by FERC which will be after the District submits briefs on its excep tion to the factual and legal condusions i n the initi al decision. FERC's future ruling on the initial decision can be appealed to a federal circuit court of appeals. When FERC will rul e on the initi al decision cannot be predicted. Information on litig ation with wholesale customers under th e 2002 Contracts i s induded in Note 12.C. A num ber of daims and suits are pending against the District for alleged damages to persons and property and for other alleged li abil iti es arising out of matters usually i ncidental to th e operation of a utility , such as the District. In th e opinion of m anagemen t, based upon the advice of its General Counsel , the aggregate amounts recoverable from the District, taking i nto account estimated amounts provided in the financi al statements and i nsurance coverage , are not material as of December 31 , 2017 and 2016. 14. SUBSEQUENT EVENTS: In 2017 , th e Nebraska Department of Revenue r NDOR j conducted a sales and use tax audit on the District's records for th e audit period of June 1 , 2014 through May 31 , 2017. NOOR i ssued a Notice of Deficiency Determ i nation r 0etenn i nation j to th e District for approximately

$6.5 million , induding int erest and penalties of over $1.0 mi lion , on January 30 , 2018. Beyond the minor sales and u se tax corrections contained

n a nonnal audit Determination , the NOOR assessed a most $5.5 m

lion of tax on the payments to municipalities under PRO Agreements. Th e 0-strict disagrees with the DOR's assessment and filed a Petition for Redetemfoation lo formally challenge the Determ ination on Mardi 29. 2018. 64 Fina:noial Report SUPPLEMENTAL SCHEDULES (UNAUDITED)

Calculation of Debt Service Ratios in accordance

'Nith the General Revenue Bond Resolution fo r the years ended December 31 , (in OOO's) Operating revenues ........................................................................................ . Operating expenses ...................

.................................................................... . Operating i ncome ...................................................................................... . Investment and other income .......................................................................... . Debt and othe r expenses ...................................

............................................. . Increase in net position ............................................................................. . Add: Debt and r elated expenses (1) ...................................................................... . Depreciation and amortization c 2 i ................................................................. . Payments to retail commun i ties C 3 J .**..*..***...*..*.*..**..*.********..*************.************ Amortization of curre n t portion of financed nuclear fuel c 4 i ............................. . Amounts colected from th i rd party financing arrangements c s i ....................... . Deduct I nvestment in come reta i ned i n construction f u nds c s i ..................................... . Unrealized (loss) gain on i nvestment secur i ties ............................................ . Ne t position ava i lable for debt sen,ke for the General Revenue Bond Resolution

.. Amounts deposited i n the General System Debt Sen,ke Account P rin c i pal ...........................................

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

......................... . I nterest ....................... ., ...............................

.............................................. . Ratio of net posi ti on ava il able for debt service to debt seniice deposits ............... . $ $ $ $ 2017 2016 1 , 101 , 642 $ 1 , 153 , 997 (988 , 931) (1 , 040 , 715) 112 , 711 113 , 282 23 , 591 31 , 772 (64 , 986) (62 , 121) 71 , 316 82 , 933 64 , 986 62 , 12 1 1 22 , 559 133 , 666 27 , 102 26 , 553 42 , 198 39 , 468 938 99 1 257 , 783 262 , 799 645 354 (2 , 595) 43 (1 , 950) 397 331 , 049 $ 345 , 335 84 , 125 $ 10 1 , 135 71 , 198 72 , 959 1 55 , 323 $ 1 74 , 094 2.1 3 1.98 (1) Debt an d oth e r e xpen ses , exdu s iv e of i nteres t on cu s t ome r d e po s i ts , i s no t a n op e ra ti ng expen se as defined i n th e Re solution. (2) De p reci a ti o n a nd a mortiz a ti on a r e n o t ope r a t ing expe n ses as d e fin e d i n th e R esol u ti o n. (3) U n der lh e pr o visi o n s of the R es oluti o n , lh e pa ym e nts r eq uired to be m ade b y the District with respect t o th e Pro fessio n al Re ta il Operating Agreemen ts a re t o be m ade o n the sa me ba sis as s ubordin a ted deb t (4) General R e ven ue Bond fin a nced n u clea r fu el i s n ot a n o pera ti ng expen se as d e fined i n the Resolution. As of J u ly 3 1 , 2 015 , the e ffective dat e of the T axa.ble Revolving Oedit A g reem e n t, a mortiz a tion of nu clear fuel e xpense u nd er lhe TRCA i s excluded from the d e bt se rvice ca laJl a li on as the District's oblig a ti on t o m ake p a yments u nd er the TRCA i s subord i n a te to the Dis tri ct's oblig a tion to p a y d e bt servi ce on General R e ven u e Bond s. (5) The p a yments received by the Distri ct rrom third p a rty fin a ncing a rrangements are included as Revenues u nder the Resolution , but are n ot recog n ized as revenue under GAAP. (6) I nterest in oom e o n in ves tm ents held in oon s truc:li on fu n ds is n ot Re ven ue as d e fin ed in the Resol uti o n. F i:nanoi~l Report Schedule of Changes in the Net OPEB Liability and Related Rat i os using a January 1 Measurement Date (in OOO's) Tot al OPEB Li a bility 20 17 2 0 16 Ser...;ce Cost ....................

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

........................................................... . $ 3 , 322 $ 3 , 229 Interes t ..........................................................................................

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

.................... . 20 , 658 19 , 876 Differences Betv.een Expected and Actual Experiences

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

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

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

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

........ . (18 , 807) (9 , 149) Benefit P ayments ......................................

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

.......... . (13 , 459} (16 , 902} Net Change in Total OPES Liability

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

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

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

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

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

.... .. 333 , 833 323 , 122 Total O P EB Liability (ending) (a) ..............................

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

................................................ . $325 , 344 $333 , 833 P l a n F i duc i a ry Net Position Contributions c , i ............................

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

.......... . $ 74 , 711 $ 28 , 242 Net lnl.*strnent Income ........................................................................................................ . 6 , 102 (453) Benefit Payments c , i .........................

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

.. . (13 , 459) (16 , 902) Administratil.*

Expense ......................................

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

.......................................... . (69} (150} Net Change in Plan Fiduciary Net Position .......................

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

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

.. 67 , 285 10 , 737 Plan Fiduciary Net Position (Beginn i ng) ........................

........................................................ . 75 , 224 64 , 487 Plan Fiduciary Net Position (Ending) (b) .....................

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

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

... . $142 , 509 $ 75 , 224 Net OPES Liability (Ending) (a) -(b) ...........

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

............... . $182 , 835 $258 , 609 Net Position as a % of Total OPES Liabitity

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

................... . 43.8% 22.5% (1) Contributions are employer-only contributions. Inactil.*

member contr i butions v..ere netted wth benefit payments. GASB Statement No. 75 , Financia l Reporting for Postemployment Benefit P l ans Other Than Pension Plans , was imp l emented by the D i strict in 2016. The provisi o ns of this Statement were not applied to prior periods , as it was not practical to do so as the information was not readily avai l ab l e. The OPEB schedules are intended t o show information for ten years. Additional years will be disp l ayed when available. 66 Finanoial Rep<lm t L Schedule of OPEB Contributions for Years Ended December 31 , (in OOO's) 2017 2016 Actuarially Determined Contr i bution ..........................

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

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

........... . 28 , 439 74 , 711 Contribution Deficiency (Excess) ........................................

.............................. . $ (7 , 433) $ (46 , 428) Notes to Schedule: Valuation date -Actuarially determined contribution rates are calculated as of January 1 , one year prior to the end of the fiscal year in which contributions are reported. Methods and assumptions used for 2017 -Actuar i al cost method . . . . . . . . . . . . . . Entry Age Normal Amortization method .. . . . . . .. . .. . . . Level amortization of the unfunded accrued liability Amortization period . . . . . . . . . . . . . . . . . 16-year closed period Asset valuation method . . . . . . . . . . . . 5-year smoothed market Discount rate . .. . . . . . . .. . . . . . . . . . . . . .. . 6.25% Healthcare cost trend rates . .. ... Pre-Medicare

7.3% initial , ultimate 4.5% Post-Medicare

9.1% i nitial , ultimate 4.5% Inflation

................................. . 2.1% Investment rate of return ......... . 6.25%, net of investment e>q:>ense , including inflation Mortality**

RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 with generational projection Retirement age ...................... . Varies by age Methods and assumptions used for 2016-Actuarial cost method . . . . . . . . . . . . . . Entry Age Normal Amortization method . . . . . .. . . . . . . . . Lei.el amortization of the unfunded accrued fiability Amortization period .................

17-year closed pe riod Asset valuation method............ 5-year smoothed market Discount r ate .... . . .. .. .. . ........ ... .. 6.25% Healthcare cost trend rates . . . . . . Pre-Medicare

8% initi al , ultimate 5% Post-Medicare

6.75% initi al , ulimate 5% Inflation

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

............. 2.1% lm.estment r ate of return . . ... . . .. . 6.25%, net of im.estment ellpeflse , incl uding in flation Mortaity . . ..... .. .. .. .. . ... ... . .. . . .. . . . . RP-20 14 Aggregate table projected back to 2006 u sing Scale Ml-2014 and projected fOMard usin g Scale f&>-2015 wth generational projection Retirement age . . .............

..... .. . Varies by age Schedule of Inv estment Returns for Years Ended December 31 , 2017 2016 Annual Money-Weighted Rate of Return , Net oflm est ment Expense ............... . 14.2% 5.8% GASB Statement No. 75 , Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans , was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods , as it was not practical to do so as the information was not readily available.

The OPEB schedules are intended to show information for ten years. Additional years will be displayed when available. iF i Naincial Repe n t Vision Mission 76 049

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