Text

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

H Nebraska Public Power District Alwa1s there when 1ou need us NLS2018032 50.7l(b)

May 8, 2018 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

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

Dear Sir or Madam:

The purpose of this letter is to transmit the Nebraska Public Power District (NPPD) Financial Report for the calendar year 2017 in accordance with the requirements of 10 CFR 50.71 (b ).

Copies of this report are being distributed in accordance with 10 CFR 50.4.

This letter does not contain any commitments.

Should you have any questions or require additional information, please contact me at (402) 825-2788.

Sincerely, Licensing Manager

/jo Enclosure - NPPD 2017 Financial Report cc: Regional Administrator w/enclosure USNRC - Region IV Cooper Project Manager w/enclosure USNRC - NRR Plant Licensing Branch IV Senior Resident Inspector w/enclosure USNRC-CNS NPG Distribution w/o enclosure CNS Records w/enclosure COOPER NUCL EAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Te lepho ne: {402) 825-3811 / Fax: {402) 825-5211 www.nppd.com

NLS2018032 Enclosure Page 1 of 60 NPPD 2017 Financial Report

FINANCIAL 2 0 17 NEBRASKA PUBLIC POWER DISTRICT REPORT OFTHE 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 KIILJOWATT- HOUR SALES d9 6 LIJIO>N QPBRAm NG REWENUes $ .~01 6 MILl.LtON COSif OF D>~ER Pl!lRCHl~SEO l(ND S6N ERA1'iEO $

1 K6.1 011:t,:IBR Q'AE:~1111:N'.G lE~PEflSBS $ re s

~esmMENtt ~\N[i) om.it:SR UiO::GME 316 iMlllUJ DBBT AiNCi> OllhlBR EiXJPtBNSBS $ 65.0 iMJUUIOlN INCRE~SE IN EU' asJ IOlN $ iT'!l .3 IMll.i l<DN DEBT SER~IQE OOJ~BRAGE 2.13 mlMBS Fimanoial Report 10

2017 STATISTICAL REVIEW (Unaudited)

Average Cents Per kWh Sold Average Average Less Government Cents Per Number of M\Nh Revenues (in OOO's) bl OPERATING REVENUES Taxes/Transfers kWh Sold Customers Amount % Amount %

Retail:

Residential .... ... .. .... ...... .... 10.72 ¢ 12.74 ¢ 72,021 809,095 4.1 $ 103,101 9.4 Corrrnercial ..... ... ........... ... 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 W holesale:

Municipalitiesc,1 . . .. .... ...... .... .. . . . ..... .. .. .. . ..... . 6.33 ¢ 45 1,658,984 8.5 104,985 9.5 Municipalities (Partial Requirements)l31 * .* ** * ** 5.n ¢ 1 186,956 0.9 10,785 0.9 Public Power Districts and Cooperativesw .. 5.93 ¢ 25 7,966,644 40.7 472,291 42.9 Total Firm Wholesale Sales .... .. ..... ...... .. .. . 5.99 ¢ 71 9,812,584 50.1 588,061 53.3 Total Firm Retail and Wholesale Sales ... . 6.70 ¢ 91 ,685 13,061 ,979 66.7 875,312 79.4 Participation Sales .. ............ ..... ....... ... ....... .... .. 3.71 ¢ 5 1,973,441 10. 1 73,199 6.6 Other sa1esc*J ... ............ ..... .. ......... .. .... ............ 2.48 ¢ 2 4,533,128 23.2 112,209 10.2 Total Electric Energy Sales ... ........ ... ...... 5.42 ¢ 9l692 1915681548 100.0 1,060,720 96.2 Other Operating RevenueslsJ ............... ....... ........ ....... .. .. .. .... .... .. ........ ............... ................ .. ... .......... ... . 76,182 6.9 Unearned Revenuesl&J ......................... .. .. .... .. .... .. .. . .. .............. ............. ..... .... ... ... ............. ... .. .. ..... .... .. . {35,260} (3.1}

Total Operating Revenues ... .... ..... ........... ............ ..... ..... ..... ..... . ......... .... ........ .. ..... .. . ...... ... ... ...... .... ...... . $1.101.642 100.0 MVVh Costs (in OOO's)

COST OF POVVER PURCHASED AND GENERATED Amount % Amount %

ProductionC7 l .. * . . *......* . .. .. ...... .. . . . .. .. . . . . . . . . ..... . *.... . .................*... . .... ... . .. . ... .. . . . . 15,850,887 n .9 $ 424,190 72.4 Power Purchased ........ ..... .... ........................ .... ... .................. ...... ... ............ . 4,501 ,041 22.1 161 ,963 27.6 Total Production and Power Purchased ............. ..... ...... ..... ............. ......... . 20.351.928 100.0 $ 586.153 100.0 CONTRAClUAL AND TAX PAYMENTS (in OOO's) 111 Amount Payments to Retail Corrrn.mities ........................ .......................... .............. .......................... .......... ... . $ 27,102 Payments in lieu of Ta,es ... ................. .................................................. ... .. ................. .......... .. ....... . 10,060 Total Contraclual and Tax Payments ........................................ ...................... ................ ............... . I 37,162 OllER Amount Mies of Transmission and Subtransrrission Lines in Sen,ice ............................................................... 5,294

~ of Ful-lirne Efil>layees ....................................................................................................... . 1,875 (1) Customer colections for taxes/lransl'ers to other governments are excluded from base rates.

(2) Sales are total requirements, subject to certain exceptions.

(3) Sales are to a wstomer who limited their requirements under the 2002 Contract. The average rate was lower" than total requirements wstomers due to the exclusion of certain transmission costs from the wholesale rate as cost recovery was through the SPP transmission tariff. These revenues were included in Other Sales.

(4) Includes sales in the Southwest Power- Pool ("'S PP1 and nonlirm sales to other" utiities.

(5) Includes revenues for transmission and other" miscelaneous revenues.

(6) Includes unearned revenues from prior periods of $6.7 milion, recognized revenues of S23.0 milion for other' poslemployment benefit

("'OPEB1 expenses related to past service and included in 2017 rates, 2017 surplus revenues deferred to future periods of s<<.9 million and coledions of $20.0 milion for the 2018 Cooper- Nuclear Station ("'CNS~j refueling and maintenance outage.

(7) Includes fuel, operation, and maintenance costs. Debt service and capilal-related costs are exduded.

SOURCES OF THE DISTRICT'S ENERGY SUPPLY (Y.OFIIWH)

This chart shows the sources of energy for Hydro sales, exduding participation sales to other 6.3%

utilities. Purchases were induded in the appropriate source, except for those purchases Purchases for which the source was not known. 4.1%

1.5%

45.3%

Finailil'cial IR~p:<!rnt l

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

The financial report for the Nebraska Public Power District ("District") includes the Management's Discussion and Analysis, Financial Statements, Notes to Financial Statements, and Supplemental Schedules. The financial 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 201 6. The Supplemental Schedules include unaudited information required to accompany the Financial Statements.

OVERVIEW OF BUSINESS The District is a public corporation and political subdivision of the State of Nebraska (the "Staten). Control of the District and its operations are vested in a Board of Directors ("Boardn) consisting of 11 members popularty elected from districts comprising subdivisions of the District's chartered territory.

The District's chartered territory indudes 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 is generally limited to retail and wholesale customers receiving more than 50% of their annual energy from the District.

The District operates an integrated electric utility system induding facilities for generation, transmission, and disbibution of electric power and energy for sales at retail and wholesale. Management and operation of the District is accomplished with a staff of approximately 1,875 full-time employees. The District has the power, among other things, to acquire, 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 investor-owned utilities providing retail electric service in Nebraska.

The District has no power of taxation, and no governmental authority has the power to levy or collect taxes to pay, in whole or in part, any indebtedness or obligation of or incurred by the District or upon which the Disbict may be liable. The Oisbict has the right of eminent domain. The property of the District, in the opinion of its General Counsel, is exempt under the State Constitution from taxation by the State and its subdivisions, but the District is required by the State to make payments in lieu of taxes which are distributed to the State and various governmental subdivisions.

The District has the power and is required to fix, establish, and collect adequate rates and other charges for electrical energy and any and all commodities or services sold or furnished by it Such rates and charges must be fair, reasonable, and nondiscriminatory and adjusted in a fair and equitable manner to confer upon and distribute among the users and consumers of such commodities and services the benefits of a successful and profitable operation and conduct of the business of the District.

THE SYSTEM To meet the anytime peak load in 2017 of 2,891 .5 megawatts rMW), the District had available 3,651.0 MW of capacity resomces that included 3,046.2 MW of generation capacity from 12 owned and operated generating plants and 22 plants over which the District has operating control, 447.6 MW of firm capacity purdlases from the 12 L

Western Area Power Adm inistration, 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.

Summer 2017 Nurrber of Accredited Plants<1> Capabili!i: {MW}

2

<> Percent of Total Steam - Conventional C J . *.*.** ****.* *** **** ***.** **** * ** *. *** ** ** **

3 3 1,679.3 55.2 Steam - Nuclear ..... ........ ..... ... .. ............ ....... ..... ..... ... . 1 765.0 25.1 Corrbined Cycle ......... ....................... .. .... .... ... ......... . 1 220.0 7.2 Corrbustion Turbine w .... ................. ...... ......... ......... . 3 125.3 4.1 Hydro .... .. ... ... .... ... ... ........ .. ............ .................. ........ . 6 106.8 3.5 Diesel ..... ....... .. ..... ........ ............... .. ................... ...... . 12 93.6 3.1 Wind esJ ........... ..... ... .. . ... ..**.. .. . ... .. .. .. . .**. .. ...... *. ...... ... 8 56.2 1.8 34 3,046.2 100.0 (1) lndudes three hydro plants and 12 diesel plants under contrad to the District.

(2) 2017 summer accredited net capability based on SPP criteria.

(3) lndudes Gerald Gentleman Station ("GGS1 , Sheldon Station ("Sheldon1 , and Canaday Station.

(4) lndudes the HaUam, Hebron and McCook peaking turbines.

(5) lndudes Ainsworth Wind Energy Facility ("Ainsworlh1 and seven wind facilities under contrad to the District.

The following table shows the generation facilities owned by the District and their respective fuel types, summer 2017 accredited capability, and in-service dates.

Sumner 2017 Accredited Type Fuel Type Capabiity (MN) <1> ln-Seniice Date Gerald Gentleman Station ltits No. 1 and No. 2 ......... . Coal 1,365.0 1979, 1982 Cooper fllJclear Station ............................................ . fllJclear 765.0 1974 Beatrice Power Station ............................................. . Cormined Cycle 220.0 2005 Sheldon Station ltits No. 1 and No. 2 ........................ Coal 215.0 1961, 1968 Cont>uslion Tlrllines (3 generating plants) ................. . Oil or Natural Gas 125.3 1973 Canaday Station ....................................................... Nalural Gas 99.3 1958 Hy<<t"o (3 geneiating plants) ....................................... . WaeT 21.3 1887, 1927, 1939 Ainsworth Wind Energy FaciityW ............................ . Wind 8.3 2005 2,819.2 (1) 2017 summer aa:redited net capabiity based on SPP aiteria.

(2) Nominaly rated at 60 lM'.

Fim.amoial R~p011t

THE CUSTOMERS Retail and \/Vholesale 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"). \/Vholesale customers served under the 2016 Contracts indude 23 public power districts (20 of which are served under one contract with the Nebraska Generation and Transmission Cooperative), one cooperative, and 37 municipalities. VVholesale customers served under the 2002 Contracts indude 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

("k\/Vh") 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 \/Vholesale Power Contracts are included 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, which are not included in the District's base rates for retail customers.

AVERAGE CENTS PER kWh SOLD - RETAIL (Retail - All Classes) 9.80 ~ - - - - - - - - - - - - - - - - - - - - - - -

9.04¢ 9.06¢ 9.12¢ 9.05¢

.s::. 9.00 3:

~ 8.20 Q)

C.

.!!l 7.40 C:

Q) u 6.60 5.80 2013 2014 2015 2016 2017 Average Cents per kWh Sold Average Cents per kWh Sold Less Government Taxes/Transfers Fina,n oial Rep011t 14

AVERAGE CENTS PER kWh SOLD - WHOLESALE (Firm Wholesale Customers Only) 6.40 6.09¢ 5.91¢ 5.96¢ 5.93¢ 5.99¢ 6.00

.s::.

~

~ 5.60 Q)

Q.

.l!! 5.20 I I I I I I C:

Q)

(..)

4.80 4.40 2013 2014 l __~ _____ l _~__I 2015 2016 2017 Participation Sales and Other Sales 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 nonfinn basis in SPP and through transactions executed with other utilities by The Energy Authority (*TEA").

Transmission Customers The District owns and operates 5,294 miles of transmission and subtransmission lines, encompassing near1y 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 transmission revenue requirements associated with transmission facilities equal to or greater than 115 kV. SPP collects and reimburses the District for the use of the District's transmission facilities by entities other than the District's firm requirements customers and all transmission customers still served directly by the District through grandfathered Transmission Agreements.

Financial R~p@rt

Customers and Energy Sales The following table shows customers , energy sales, and peak loads of the System , including participation sales, in each of the three years, 2015 through 2017.

Anytime Peak Megawatt-Hour Sales Load {MW)

Calendar A..erage Number of Wholesale Nati..e Load Percentage Total Percentage Busbar Nati..e Year Retail Customers Customers< >

1 Sa1es<2> Grov.fu Sa1es <3 > Grov.fu(4) Load 2015 91 ,140 82 12,579,390 (2.7) 20,990,883 1.6 2,695.0 2016 91 ,457 78 12,901 ,989 2.6 18,902,173 (10.0) 2,963.7 2017 91 ,614 78 13,061 ,979 1.2 19,568,548 3.5 2,891 .5 (1) At the end of 2017, indudes sales to finn wholesale customers, participation customers (LES, MEAN, JEA, OPPD, Grand Island), and a yearly average of 2 nonfinn customers. In 2016, three of the District's municipal wholesale customers began purchasing power from three of the District's public power district wholesale customers, and one of the District's municipal wholesale customers allowed their contract to tenninate.

(2) Native load sales indude 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. Predominandy, native load wstomers are served under long-tenn total requirements contracts.

(3) Total sales from the System indude 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 \llllnd Energy Facility, which sales commenced October 1, 2005, and terminates on September 30, 2025; to OPPD, MEAN, LES and Grand Island from Elkhorn Ridge \llllnd Facility, which sales commenced March 1, 2009, and tenninates on 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 \llllnd Facility, which sales commenced February 1, 2011 , and terminates on January 31, 2031 ; to OPPD, LES and Grand Island from Broken Bow I \llllnd Facility, which sales commenced December 1. 2012, and terminates on November 30, 2032; to OPPD, LES and MEAN from Crofton Bluffs \llllnd Facility, which sales commenced November 1, 2012, and tenninates on October 31, 2032; and lo OPPO from Broken Bow II Wind Facility which sale commenced October 1, 2014, and terminates on September 30, 2039. The District and LES exewted an agreement in 2017 to terminate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing alter December 31 , 2017.

(4) The inaease in percentage growth from 2016 to 2017 was due primariy to additional nonfinn energy sales from CNS as a result of 2017 being a non-outage year for the unit The deaease in percentage growth from 2015 to 2016 was a rest.fi of lower nonfinn energy sales due primarily to the planned refueling and maintenance ootage al CNS, lower natural gas prices and additional wwtd generation in the SPP Integrated Market Financial Repmt 16

FINANCIAL INFORMATION The following tables summarize the District's finan cial position and operati ng results.

CONDENSED BALANCE SHEETS (in OOO's)

As of December 31, 2017 2016 2015 Current Assets .. ................ ... ..... .......... ... .... .. .................. . $ 858,872 $ 775,479 $ 764,278 Special Purpose Funds .. ..... .. ....... .... .... ....... ..... ...... .... .... . 746,448 782,857 738,967 Utility Plant, Net .......... ... ...... ..... ........... ........... ......... .. ..... . 2,569,898 2,595,767 2,508,971 Other Long-Term Assets ......... ...................... ........... ... .... . 383,701 406,149 353,639 Deferred Outflows of Resources ..... ......... .. ........ .. ..... ...... . . 295,402 344,331 40,775 Total Assets and Deferred Outflows ................. .. .......... . $ 4 ,854,321 $ 419041583 $ 4 ,4061630 Current Liabitities .................. ......... .. ....... .. ... ..... ... .......... . $ 370,501 $ 287,322 $ 218,858 Long-Term Debt ....... ..... ... .................................. ....... ..... . 1,617,269 1,867,768 1,838,672 Other Long-Term Liabifities .. ............. ...... .......... .......... .. .. . 1,028,467 1,063,11 8 727,070 Deferred Inflows of Resources ..... ........ ... ..... ......... ......... .. 351 ,651 271,258 289,846 Net Position .............. .. ............. .... .. .......... .... .......... ...... ... 1,486,433 1,415,117 1,332,184 Total Liabilities, Deferred Inflows, and Net Position ...... .. $ 418541321 $ 419041583 $ 4z4061630 CONDENSED RESULTS OF OPERATIONS (in OOO's)

For the years ended Decerrber 31, 2017 201 6 2015 Operating Rewnues ............................. ....... ... ................ . $ 1,101 ,642 $ 1,153,997 $ 1,097,216 Operating E>epenses .................. .............. ................... .... . (988,931} {1,040,71 5} (960,259}

Operating Income ..... .......... ........ .......................... ..... . 11 2,711 113,282 136,957 lrNeSlrnent and Other Income .................... ...................... . 23,591 31 ,772 22,355 Debt and Other E>epenses ********* ...................................... . {64,986} {62,121} (68,252}

Increase in Net Position ............................................. . $ 711316 $ 821933 $ 91 060 SOURCES OF OPERATING REVENUES (in OOO's)

For the years ended Oecermer 31, 2017 2016 2015 Rrm Retail and Wholesale Sales ..................................... . $ 875,312 $ 865,661 $ 848,345 Participation Sales ........................................................ . 73,199 77,900 77,192 Other Sales ................................................................... . 112,209 89,492 134,612 Other Operating Re\iet1ues ......... ********* ............................ . 76,182 66,060 60,730 Ulearned Re\iet1ues ....................................................... . (35,260) 54,788 {23,663)

Total Operating Re\iet1ues ................... -******* *************** * $ 1110\642 $ \1 531997 $ 110971216 Financial R!epc1rnt

CONDENSED STATEMENTS OF CASH FLOWS (in OOO's)

For the :tears 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 Financing Activities ..... ... .. ... {332,584} {238,416} {388,483}

Net Increase (Decrease) in Cash and Cash Equivalents .. ... (74,925) 17,669 (5,019)

Cash and Cash Equivalents, Beginning of Year ......... ....... . 102,729 85,060 90,079 Cash and Cash Equivalents, End of Year .. ............... ... . $ 271804 $ 1021729 $ 851060 Revenues from Finn Retail and VVholesale Sales The District allocates costs between retail and wholesale service and establishes its rates to produce revenues sufficient to meet its estimated respective retail and wholesale revenue requirements. VVholesale revenue requirements include unbundled costs accounted for separately between generation and transmission. The rates for retail service indude an amount to recover the costs of wholesale power service in addition to distribution 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 creation of a rate stabilization account. Any surplus or deficiency between revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be retained in the rate stabilization account Any amounts in excess of the limits may be induded as an adjustment to revenue requirements in the next rate review. The wholesale power contracts also indude a provision for establishing a new/replacement generation fund. This provision would pennit the District to collect an additional 0.5 mills per kWh above the nonnal revenue requirements to be used for Mure capital expenditures associated with generation.

There was no change to the wholesale or retail rates on January 1, 2018.

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

No increase in retail rates was implemented in 2017.

The District implemented a 0.6% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who signed the new 2016 20-year wholesale power contract, and a 3.8% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who remained under the 2002 20-year wholesale power contract The rate increase was higher for the 2002 Contracts as these customers will pay their share of a catch-up in funding for OPEB costs related to prior service through rates prior to the expiration of their contracts in 2021 . The District financed with taxable debt the 2016 Contracts customers' share of the OPEB catdHJp trust funding for 2016 and 2017 and plans to issue additional taxable debt in 2018 for catdHJp trust funding. The rustomers under the 2016 Contracts will commence payment through rate collections of the related debt service for their share of the catch-up in funding for OPEB costs beginning in 2022, the year after the expiration of the 2002 Contracts, and continue making payments through 2033. No inaease in retail rates was implemented in 2016. Details of the District's Wholesale Power Contracts are inducled in Note 12 in the Notes to Financial Statements.

Revenues from firm sales inaeased $9.6 million, or 1.1%, from $865.7 million in 2016 to $875.3 million in 2017.

The inaease in revenue was due primarily to a weather-related 1.2% increase *n energy sales. Revenues from firm sales *naeasec:1 $17.4 m*trJOO, or 2.1%, from $848.3 minion in 2015 to $865.7 mil ion in 2016. The increase in revenues from 2015 to 2016 was due primarily to a weather-related 2.6% inaease in energy sales to firm requirements rustomers.

Revenues from Participation Sales The District has participation sales agreements with othe,: uti ities that share operating expenses on a pro rata basis. Revenues from participation sales decreased from $78.0 milion in 2016 to $73.2 million in 2017, a Financial Repo11t 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 in SPP's Integrated Market and nonfirm sales to other utilities. TEA, of which the District is a member, has energy marketing responsibilities for the District's other and nonfirm off-system sales and the related management of credit risks. Other sales increased from $89.5 million in 2016 to $112.2 million in 2017, an increase of $22.7 million. The increase was a result of higher energy sales due to no refueling and maintenance outage at CNS and higher prices in the SPP Integrated Market due to higher natural gas prices.

Other sales decreased from $134.6 million in 2015 to $89.5 million in 2016, a decrease of $45.1 million. The decrease was a result of reduced nonfirm revenues due to lower energy sales due to the planned refueling and maintenance outage at CNS, lower natural gas prices, and additional wind generation in the SPP Integrated Market.

Other Operating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues.

These revenues were $76.2 million, $66.1 million, and $60.7 million in 2017, 2016, and 2015, respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District.

Unearned Revenues Under the provisions of the District's wholesale power contracts, any surplus or deficiency between net revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be adjusted in the rate stabilization account. Any amounts in excess of the rate stabilization limits may be induded as an adjustment to revenue requirements in the next rate review. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities, the balance of such surpluses or deficiencies are accounted for as *regulatory liabilities or assets*. respectively.

The District recognizes net revenues in excess of revenue requirements in any year as a defenal or reduction of revenues. Such surplus revenues are exduded from the net revenues available under the General Revenue Bond Resolution f'General Resolution1 to meet debt service requirements for such year. Surplus revenues are induded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or inaease in revenues, even though the revenue accrual will not be realized as ~cash* until some future rate period.

Such revenue deficiency is induded, *n the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are exduded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates.

The District deferred or decreased revenues a net amount of $35.2 million in 2017. The District's revenues in 2017 from electric sales to retai , wholesale, and other utilities resulted *n a surplus, or over collection of costs, of

$44.9 mil ion, which was deferred (deaease in revenues). In addition, the wholesale rates that were *n place for 2017 included a refund of $6.7 milion of SlB"plus net revenues from past rate periods. Such surplus had previously been aa:ounted for as a reduction in revenues in the year(s) the SlB"plus occurred. Accordingly, the 2017 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjusbnent (increase in revenues) for such amount The District also deferred or decreased revenues by $20.0 milion for the pre-colection of CNS refueling and mamenance outage costs.. This reg~ory liabiity will be eliminated throlql revenue recognition dlM'ing the 2018 outage yea,-. In ad<ition, the District recognized or increased revenues by Fina]loial Rep©11t

$23.0 million for OPES expenses related to past service for wholesale customers under the 2016 Contracts. The OPES expenses were included in 2017 rates and financed with proceeds from General Revenue Bonds, 2016 Series E (Taxable) .

The District recognized or 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 in a surplus, or over collection of costs, of

$10.0 million, which was deferred (decrease in revenues) . In addition, the wholesale rates that were in place for 2016 included a refund of $17.4 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly, the 2016 revenues from electric sales, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount. The District also recognized or increased revenues by $24.7 million for CNS fall refueling and maintenance outage costs, which costs were pre-collected for in 2015. This regulatory liability was amortized through revenue during the 2016 outage year. In addition, the District recognized or increased revenues by $22.7 million for OPES expenses related to past service for wholesale customers under the 2016 Contracts. The OPES expenses were included in 2016 rates and financed with proceeds from General Revenue Bonds, 2016 Series E (Taxable).

The District deferred or decreased revenues a net amount of $23.7 million in 2015. The District's revenues in 2015 from electric sales to retail , wholesale, and other utilities resulted in a surplus, or over collection of costs, of

$11 .0 million, which was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 20 15 induded 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 in the year(s) the surplus occurred. Accordingly, the 20 15 revenues from electric sales, which reflect the surplus being refunded , were offset by a revenue adjustment (increase in revenues) for such amount. The District also deferred or decreased revenues by $24.7 million for the pre-collection of CNS refueling and maintenance outage costs. This regulatory liability was eliminated through revenue recognition during the 2016 outage year.

The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements in future rate periods was $206.9 million, $168.7 million, and $176.1 million, as of December 31 ,

2017, 2016, and 2015, respectively.

Operating Expenses The following chart illustrates operating expenses for the years ended December 31, 2015 through 2017.

$1,200 Power Purchased & Fuel

$1,041

$1,000 Production Operation & Maintenance ("O&M")

U) Transmission & Distribution O&M s:: $800 0

Customer Service & Information

E

$600 VI Administrative & General 0

0 $400 Decommissioning

$200 Depreciation & Amortization

$0 Other 2015 2016 2017 Financial Rep011t 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 increase of $80.4 million from 2015. The changes were due primarily to the following :

Power purchased and fuel expenses were $342.8 million, $347.6 million, and $365.1 million in 2017, 2016, and 2015, respectively. These expenses decreased $4.8 million in 2017 as compared to 2016 due primarily to fewer energy purchases in the SPP Integrated Market as there was no refueling and maintenance outage at CNS. The favorable power purchased variance was partially offset by an unfavorable fuel variance from higher generation in 2017. These expenses decreased $17.5 million in 2016 as compared to 2015 due primarily to additional energy purchases from NC2 and the wind facilities, and lower fuel costs as the result of decreased generation.

Production operation and maintenance expenses were $243.3 million , $287.7 million, and $242.8 million in 2017, 2016, and 2015, respectively. These costs decreased $44.4 million in 2017 as compared to 2016 due primarily to the costs associated with a planned refueling and maintenance outage at CNS completed on November 8, 2016.

No such outage occurred in 2017. In 2016 these costs increased $44.9 million due primarily to the costs associated with the planned refueling and maintenance outage at CNS.

Transmission and distribution operation and maintenance expenses were $100.9 million, $102.0 million, and

$87.3 million, in 2017, 2016, and 2015, respectively. These costs decreased $1.1 million in 2017 as compared to 2016. These costs increased $14.7 million in 2016 as compared to 2015 due primarily to higher fees charged by SPP for the District's share of qualifying transmission upgrade projects, induding an SPP resettlement for prior periods for the implementation of a tariff provision to compensate transmission upgrade sponsors for qualifying upgrades used by other transmission customers.

Customer service and information expenses were $16.0 million, $17.7 million, and $17.2 million, in 2017, 2016, and 2015, respectively.

Administrative and general expenses were $106.2 million, $94.1 million, and $66.3 million, in 2017, 2016, and 2015, respectively. Administrative and general expenses increased $12.1 million in 2017 as compared to 2016 due primarily to a reclassification in 2017 to indude all OPEB costs with administrative and general expense, a portion of these costs were induded in operation and maintenance expense in prior years. These costs increased

$27.8 million in 2016 as compared to 2015 due primarily to OPEB expenses related to past service and induded in 2016 rates. Details regarding OPEB, induding the earty adoption of new accounting guidance in 2016, are induded in Note 11 in the Notes to Financial Statements.

Decommissioning expenses were $19.9 million, $21.4 million, and $14.7 million, in 2017, 2016, and 2015, respectively. Prior to 2017, decommissioning expenses only represented the net amount accrued each year for the future decommissioning of CNS. Commencing in 2017, decommissioning expenses also induded amounts collected in rates for the future decommissioning of certain non-nudear utility plant assets. Decommissioning expenses are recorded in an amount equivalent to the income on investments in the nudear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year.

Decommissioning expenses deaeased $1.5 million in 2017 as compared to 2016. This decrease was due to a

$7.4 million decrease in investment income for the nudear facility decommissioning fund, which was partially offset by $5.9 million in collections for decommissioning of certain nOl'Hludear utility plant assets.

Decommissioning expenses increased by $6.7 million in 2016 as compared to 2015 due to an *naease in interest income on investments. No additional amounts for decommissioning were collected through rates in 2016 and 2015.

Depreciation and amortization expenses were $122.6 miUion, $133.7 million, and $130.2 m"lion, in 2017, 2016, and 2015, respectively. The deaease in depreciation and amortization expenses was due primarily to a change in the estimate to longer asset lives for certain transmission assets.

Increase in Net Position The increase in net position was $71.3 milion, $82.9 million, and $91.1 m* *on, in 2017, 2016, and 2015, respectively. The change in net position in 2017 as compared to 2016 decreased $11 .6 million and was due Fiiliumcial R~p©rt

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 District's operating revenues, other revenues, operating expenses, and other expenses for the years ended December 31 , 2015 through 20 17.

Revenues & Expenses

$1,250 ~ - - - - - - - - - - - - - - - - - - - - - -

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

en $1 ,150 L--------*,...L ---------

.2 $1,100 +---lii& iiil- - - --1 Other Expenses

~ $1,050 -+-----i

-f $1,000 + - ---I Operating Expenses Other Revenues

~ $950 - - -- $1,09 Operating Revenues o $900 + - -.....;

$850 _____,

$800 + - -_Ji,_..,.....,,!

2015 2016 2017 FINANCIAL MANAGEMENT POLICY The District has a Financial Management Policy (the *Policy"), which is subject to periodic review and revisions by the Board. This Policy represents general financial strategies and procedures that are implemented to demonstrate financial integrity and fiscal responsibility in the management of the District's business and its assets. Employees must abide by all applicable District bylaws, Board resolutions, bond resolutions, federal and state laws, other relevant legal requirements and the Policy.

DEBT SERVICE COVERAGE Under the Policy, the District has established a minimum debt service coverage ratio on the General Revenue Bonds of 1.5 times the debt service on the General Revenue Bonds. The District's debt service coverage ratio was 2.13, 1.98, and 1.84, in 2017, 2016 , and 2015, respectively. The coverage was provided primarily by the amounts collected in operating revenues for utility plant additions, for principal and interest payments on outstanding commercial paper notes and revolving credit agreements, and for payments to those municipalities se,ved by the District under long-term PRO Agreements. The increase in 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 deaease in the required debt service deposits.

A NANCING ACTMTIES Good credit ratings allow the District to borrow funds at more favorable interest 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 is no assurance that such ratings will be maintained for any given period of time or that they wil not be revised downward or be withdrawn entirely by the respective rating agency if, in its FiJ;umcial Repo]t 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 ratings on its revenue bonds were as follows:

Moody's Investors Service ....... ........ ... .... ...... .. .... ..... ..... .. ..... ........... ...... ........ A 1 (stable outlook)

Standard & Poor's Ratings Services .. ........... ... ....... ........... ........................... A+ (stable outlook)

Fitch Ratings .... ........... ...... ..... ....... .... .. .. ...... ..... ...... .. .. .. .............................. ... A+ (stable outlook)

The District plans, pursuant to the Policy, to issue separate series of indebtedness, including separate series of General Revenue Bonds, for production projects and for transmission projects. No more than 20.0% of the amount of outstanding indebtedness issued for production projects, calculated at the time of issuance of each series of such indebtedness, or $200.0 million, whichever is less, will be permitted to mature after January 1, 2036, the end of the 2016 Contracts. Transmission indebtedness issued for transmission projects is expected to mature over the useful life of the asset that is being financed . New transmission indebtedness may mature after January 1, 2036. The District's transmission indebtedness is payable from the revenues received during the term of the 2016 Contracts and from retail sales and transmission revenues received under various SPP tariffs. After January 1, 2036, transmission indebtedness will be payable from revenues to be derived from wholesale and retail customers who use the District's transmission facilities, as well as revenues from various SPP tariffs.

On January 1, 2018, the District called the remaining outstanding General Revenue Bonds, 2012 Series C, with a principal amount that aggregated $4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of 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 provide for loan commitments to the District up to an aggregate amount not to exceed $150.0 million, which replaced its Commercial Paper Notes program.

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 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.

In November 2016, the District issued General Revenue Bonds, 2016 Series C and 2016 Series D, in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and refund $61 .7 million Tax-Exempt Commercial Paper ("TECP"). The District also issued in November 2016, General Revenue Bonds, 2016 Series E (Taxable), in the amount of $56.1 million to fund a portion of OPEB costs for rustomers under 2016 Contracts.

In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series B, in the amount of

$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of TECP. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.

In January 2016, the Dismct issued TECP in the amount of $43.6 million to refund a portion of the General Revenue Bonds, 2005 Series C and General Revenue Bonds, 2006 Series A. In February 2016 , $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and Series B.

Details of the District's debt balances and activity are induded in Note 7 in the Notes to Financial Statements.

CAPITAL REQUIREMENTS The Board-authorize capital projects totaled approximately $85.0 mil ion, $109.5 million, and $501.0 milion, in 2017, 2016, and 2015, respectively. The District's capital requirements are funded with monies generated from operations, debt proceeds, and other available reserve funds.

Fi:nam:oial Rep01;t

Capital projects for 2017 included:

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

$11 .2 million for construction of an evaporation pond at GGS

$6.4 million for refurbishment of a 115 kV substation in Beatrice, Nebraska Capital projects for 2016 included:

$22.0 million for construction of a high-voltage transmission line from the Muddy Creek substation to Ord, Nebraska

$16.4 million for construction of a high-voltage substation in Holt County, Nebraska and expansion of the GGS 345 kV substation

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

$346.8 million for construction of a high-voltage transmission line and related substations from a GGS substation north to Cherry County, Nebraska and east to a new substation in Holt County, Nebraska

$33.9 million for modifications to the hot flue gas ductwork at GGS Unit 2

$33.1 million for construction of a high-voltage transmission line from a substation in Stegall, Nebraska to a substation in Scottsbluff, Nebraska 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 is $118.9 million. Specific capital projects for 2018 indude:

$25.5 million for retrofit of the low pressure turbine for GGS Unit 2

$4.5 million for refurbishment of the main generator exciter at CNS

$4.3 million for a training facility in York, Nebraska The following chart illustrates the Board-authorized capital projects for the years ended December 31, 2015 through 2017, induding the Board-authorized budget for the year ended December 31, 2018.

$600

$501

-C/l C:

$500

.2 $400

=

E $300 C/l

~

$200 0 $119 0 $110 --~

$100 2015 2016 2017 2018 Budget RESOURCE PLANNING The District uses a diverse mix of generation resources such as coal, nuclear, natural gas, hydro and wind to meet its firm requirement customer's needs. In 2017, the non-carbon energy resom:es as a percentage of native load sales were 65%.

Fifa1ai:ncial ReJil(!llit 24

The District's last comprehensive 20-year Integrated Resource Plan ("IRP") was completed and approved by the Board in 2013. Since that time there have been several changes in assumptions that have now been included in the limited scope, five-year IRP approved by the Board at their March 2018 meeting. The 2018 IRP shows the District does not require new resources for the next five years. The changes in assumptions in the 2018 IRP included:

2016 V\/holesale Power Contracts - The negotiation of new contracts with the District's wholesale customers, which extended the term 20 years for all but ten of the current customers. The new contract allows a 10% renewable self-supply option, or 2 MW, whichever is greater.

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

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

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

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

Hydrogen Generation - Monolith Materials, Inc. ("Monolith* ) has expressed an interest to construct and operate a carbon black facility adjacent to the District's Sheldon coal-fired generating facility in Nebraska.

The construction of the carbon black facility is expected to be accomplished in two phases. The electric load to serve any Monolith facility will be served by Norris Public Power District, a finn wholesale customer of the District. At full buildout, Monolith may be the single-largest industrial customer served in the District's territory. The District entered into a 20-year contract with Monolith to purchase the carbon black plants' production of hydrogen rich tail gas, which will be produced by Monolith during production of carbon black. The District will have to convert its existing coal-fired boiler at Sheldon Unit No. 2 to bum the hydrogen rich tail gas. The boiler conversion is expected to result in a reduction of carbon dioxide

("C02u). sulfur dioxide ("S02u). mercury, and other air emissions. Groundbreaking for Phase 1 occurred in October 2016 and is expected to be mechanically complete in 2018 and fully operational in 2019.

Phase 2 construction is planned to begin in the second half of 2020. The oommercial operation date (defined jointly as the date on which Phase 2 is capable of sufficient, steady state hydrogen rich tail gas supply, and the Sheldon Unit No. 2 boiler has been converted and oommissioned) is scheduled for the second quarter of 2021 .

ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks, induding exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the aeditworthiness of its counterparties, and the operational risks associated with transacting in the wholesale energy markets.

To help manage energy risks, induding the risks related to the District's participation in the SPP Integrated Market, the District relies upon TEA to both transact on its behalf in the wholesale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets.

TEA oombines a strong knowledge of the District's system, an in-depth understanding of the wholesale energy markets, experienced people, and state-Of-the-art technology to deliver a broad range of standardized and wstomized energy products and services to the District.

TEA has assisted the District in developing its Energy Risk Management CERM") program. The program originates with the Board-approved ERM Governing Policy and the ERM-Approved Products and Limits Standard.

These documents establish the philosophy, objectives, delegation of authorities, approved producls and their limits on the District's energy and fuel activities necessary to govern its ERM program. The objective of the ERM program is to increase fuel and energy price stabiflly by hedging the risk of significant adverse impacts to cash Finainoial Rep0lit 25

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 provide 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 20 17. 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 decline 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 region continue 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%

in 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 201 6 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 Bectric 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 condition and competitiveness of electric utilities, such as the Disbict. Such factors indude, among others:

effects of compliance with changing environmental, safety, licensing, regulatory, and legislative requirements,

changes resulting from energy efficiency and demand-side management programs on the timing and use of electric energy,

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

other federal and state legislative and regulatory changes,

increased wholesale competition from independent power producers, marketers, and brokers,

low market prices for wholesale power,

~self-generation* by certain indusbial and commercial customers,

issues relating to the ability to issue tax-exempt obligations,

severe resbictions on the ability to sell to nongovernmental entities electricity from generation projects financed with outstanding tax-exempt obligations,

changes from projected future load requirements,

increases in costs,

shifts in the availability and relative costs of different fuels,

inadequate risk management procedures and practices with respect to, among other things, the purdlase and sale of energy, fuel, and transmission capacity,

effects of financial instability of various participants in the power market,

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

increased regulation of nuclear power plants in the United States resulting from the earthquake and tsunami damage to certain nuclear power plants in Japan, and

issues relating to cyber and physical security.

Any of these general factors (as well as other factors) could have an effect on the financial condition of the District.

Eiililam:cfall :Re:p011.t 26

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 electricity to have exclusive rights to serve a particular area or customer at wholesale, wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements.

Finanoial R~piont

REPORT OF INDEPENDENT AUDITORS To the Board of Directors of the Nebraska Public Power District:

We have aud ited the accompanying financial statements of Nebraska Public Power District (the "District"}, which comprise the balance sheets as of December 31 , 2017 and 2016, and the related statements of revenues, expenses, and changes in net position, of cash flows , and the related notes to the financial statements for the years then ended.

Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation , and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the District's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the District's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion In our opinion, the financial statements referred to above present fair1y, in all material respects, the financial position of the District as of December 31 , 2017 and 2016, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter As discussed in Note 1 and Note 9 to the financial statements, the District changed the manner in which it accounts for Asset Retirement Obligations in 2017. Our opinion is not modified with respect to this matter.

Other Matters The accompanying management's discussion and analysis and the supplemental schedules on pages 11 through 27 and 65 through 67, respectively, are required by accounting principles generally accepted in the United States of America to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inqu*ries, the basic financial statements, and other knowledge we obtained during our audits of the basic financial statements. We do no express an opinion or provide any assurance on the information because the limited procedures do not provide us with sullicienl evidence to express an op"nion or provide any assurance.

Our audits were conducted for the purpose of tonn*ng opinions on the financial statements that colledively comprise the District's basic financial slatements. The statistical review is presented for purposes of additional analysis and is not a req "red part of the basic financial stalements. SUch information has not been subjected to the auditing procedures applied in the audi!s of the basic financial statements, and acmrdingly, we do not express an op- iion or provide any assurance on it

~LuJ St Louis,, Missouri April 12, 2018 Hinmmial Rl~port 28

FINANCIAL STATEMENTS Nebraska Public Power District Balance Sheets as of Decermer 31 , (in OOO's) 2017 2016 ASSETS AND DEFERRED OUTFLOWS Current Assets:

Cash and cash equivalents ...... ..... ................ ......... ...... ....... ...................... . $ 27,804 $ 102,729 lnwstrnents .. ... ......... .......... .. .. ....... .... ... .. ... ... ... ....... .... ..... ... .......... ........ ... . 539,173 373,331 Receivables, less allowance for doubtful accounts of $541 and $530, respectil.ely ........................................ .. ......... .. ........ .. 120,254 123,905 Fossil fuels , at awrage cost ... ........ ...... .. .... .... ......... .... ............ .... ...... ...... .. 43,264 43,620 Materials and supplies, at aw rage cost .... ........................... ........ .. ... ......... . 111 ,644 114,640 Prepayments and other current assets .. .. .................................................. . 16 733 17 254 858 872 775479 Special Purpose Funds:

Construction funds ... ........... ................................................... ........... ... ... . 54,808 106,204 Debt resen.e funds ............................ ...... ....................... ............... ...... ... .. 88,764 90,032 El11)1oyee benefit funds ... .... .............. ............................... ....... ....... ........ .. 1,934 4 ,851 Decorrrnissioning funds ....... ........... ....................................... ....... .... ...... .. 600,942 581 770 746448 782 857 Utility Plant, at Cost Utility plant in ser"1ce ........ .. .............. .. .................................................... .. 4,928,370 4 ,835,829 Less resen.e for depreciation ............................................................. ...... . 2,658,206 2 573 645 2,270,164 2,262,184 Construction work in progress ............ ............................................ .. .. ...... . 133,515 135,853 l'lk.lclear fuel, at amortized cost ................................................................ .. 166,21l;l 197 730 2,569,898 2,595,767 Olher Long-Term Assets:

Regulatory asset for other posfenl>loyment benefits ................................... . 210,362 221 ,973 Long-term capacity contracts ................................................................... . 152,831 159,445 lxlamortized financing costs .................................................................... . 8,201 8,945 lm.estment in The Energy Autholity ........................................................... . 6,175 6,370 Other ...................................................................................................... . 6132 9416 383,701 406149 Total Assets ................................................................................... . 4,558,919 4,560,252 Deferred Outflows d Resources:

Asset retirement obligation ................................................................... ... .. 222,369 219,378 lklamortized cost of refunded debt ........................................................... . 38,430 42,664 Other posler1')ioyment benefits ..................................................... ............ . 34,603 82,289 295,402 344331 IDTAL ASSElS ANJ DEFERRED OOTFLOIVS ............................................. . I 4,854,321 I 4,904 583 LIABILITIES, DEFERRED 11\FLOIVS, ANJ flET POSITION Current Liabilities:

Rel.enue bonds, current -***********************************************************-*************** s 98,205 s 81 ,250 Noles and credit ag,eernenls, current *******-************* .. *****************************---- 165,212 74,000 Accounls payable and accrued labilities **************------*---*-*---**-*-***-*-******--*-* 64,981 87,061 Accrued in leu d 1aX payments *********************************-----*-***************-*******-* 10,000 10,008 Accrued payments ID retail cornn.mities *-----********************************************** 6 ,074 6,037 Accrued COl1l)el1S3led absences -*---***-**************-********--------*-**-*********-*-*-**** 16,971 17,594 Olher *-*-***---*-*-*-*********-*-***************************************-**********************-*-*-*****-*- 9058 113n 370,501 'ZP.7,322 Long-Term Debt Rel.enue bonds, net d a.-rent --*-----*-----*---*--------*-------***-*-*-*****************-****** 1,548,269 1,678,844 Noles and credit agieernenls,, net d a.-rent --***---*-------*-***-**-*--*-*--**-----**-**** 69000 188,924 1,617,269 1,867,768 Olher Long-Term LiablDes:

Asset retirement obligation ***********--********-************************************************** 823,794 801,147 Net oiler poslerr'*1Jrnen benefit iabiity *-*-*---*-***--*****-*-************-*-************* 182,835 258,609 Olher ***********-***-******--*-*-**--*-*****-*-----**--*---*----**----------***-****-***-*-*-*-**-**-*--**-* 2 1 838 3362 1,028.467 1,063,118 Total Liabiilies --***------*-*---------------**--**--***-**---******-*******-**********-*-****** 3,016.,237 3,,218,208 Deferred lnllows d Rescuces:

Lheamed rewenues .................................................................................. 206,927 168,,710 Olher derened inflows *******************************************-************-*-*-**************** 144n4 102..548 351,651 271,258 Net Position:

Net inwestnent in eapital assets ********-******************************************************** 1,029,230 928,,967

~ ................................................................................................ 37,782 38,,776 Lhreslricled ****************************-***********************************************-***-*-*****-**** 41~,421 447374 1,486,433 1,415,117 IDTAL LIABILITIES, DEFERIED 11\FLOIIIS, AN> flET POSITION **********-*-****- i 4,854321 i 4,904,583 The accompanying notes to financial statements are an integral part of these statements.

Financial Report

Nebraska Public Power District Statements of Revenues, E><penses, and Changes in Net Position For the years ended December 31, (in OOO's) 2017 2016 Operating Revenues ... ... .... ...... ..... ..... .... .... ....... ..... ..... .. ..... .. ...... .. ....... .. ...... ... $ 1,101 ,642 $ 1,153,997 Operating E><penses:

Pov.,er purchased ........ .. .... ..... ... ..... ... ........ ......... ..... .. .. .... ... ... ..... ...... ... .... . 161 ,963 177,121 Production:

Fuel ... ... ........ ... ..... ...... .. .... .... .......... ..... .. ... ..... ..... ... ..... .. ..... ... ....... .. .... . 180,858 170,450 Operation and maintenance ..... ..... .... .... ....... .... ......... ... ... ... ... ....... ........ . 243,332 287,672 Transmission and distribution operation and maintenance .......... ... ........... ... . 100,945 101 ,952 Customer service and information ........ ... ....... ... .... .. ... ....... ... .. .... .... .. ... .. .... . 15,988 17,696 Administrative and general ... ...... .... .... ... ........... .. ... ... ... ...... ..... .... ............. . . 106,190 94,112 Payments to retail comrrunities ...... .... ..... .... .... .. .. ...... ... ......... ... ... ....... .. .... . 27,102 26,553 Decommissioning ...... .. ... ... .... .... ... ........ ... .. ........ ..... .... .... ...... ..... ...... .... .. .. . 19,934 21 ,429 Depreciation and amortization .......... ..... ........ ... .... ... ...... ........ ...... .. ........... . 122,559 133,666 Payments in lieu of taxes ...... ... ..... .............. ....... .. ... ....... ... ...... .. ....... ..... ... . 10,060 10,064 988,931 1,040,715 Operating Income ..... ....... .. .. ... ....... .. ..... ... ... ..... ... ... .. .. .... ...... ... ..... ... ........... ... 112,711 113,282 Investment and Other Income:

Investment income ............ ....................... ...... ....... ....... ..... ..................... .. . 20,091 28,239 Other income ........................................................... .... ........................... . 3,500 3,533 23,591 31 ,772 Increase in Net Position Before Debt and Other Expenses ... ............................ . 136,302 145,054 Debt and Other Expenses:

Interest on long-term debt ... .... ......... ... ... ..................... ........... .................. . 76,186 75,415 AbAance for finis used during construction ........................ .................... . (2,31 7) (4,120)

Bond prenium amortization net of debt issuance expense ........................... (1 2,598) (1 1,427)

Other e>q:>enses ...........*..........*...*.*. .......**..***.*******..**.*****.**.* .**********...****.** 3,715 2,253 64,986 62,121 Increase in Net Position ................................................................................ . 71,316 82,933 Net Position:

Beginning balance ................................................................................... . 1,415,117 1,332,184 Encing balance ....................................................................................... . $ 1,486,433 $ 1,415,117 The accompanying notes to financial statements are an integral part of these statements.

Financial Rep@Iit 30

Nebraska Public Povver District Statements of Cash Flows For the years ended December 31 , (in OOO's) 2017 2016 Cash Flows from Operating Activities:

Receipts from customers and others .. ....... ... ... ..... ........ .......... ................... . $ 1,112,281 $ 1,067,143 Other receipts ........... .. ... ... .. .......... ... ......... .. ......... ... .. .... .... .......... .. ..... ... .. . 679 209 Payments to suppliers and vendors ..... ... .. ... .. ... ...... .. ........ ... .... .... ............. . . (503,685) (565,252)

Payments to employees ... ... ......... ........ .......... .. .... ...... .. ..... .. .... .. .............. .. (244,178) (248,389)

Net cash provided by operating activities ... ........ ..... ...... .. ..... ..... .... ..... ... . 365,097 253,711 Cash Flows from Investing Activities:

Proceeds from sales and maturities of investments ............ ...... .... ............... . 2,792,011 2,775,601 Purchases of investments .. ... ....... .. ........................... ............. ... ... ........ .... . (2,920,4 11) (2,800,722)

Income received on investments ....... .. ..... ... ............ .. ........ ...... ....... ...... .. .... 20,962 27,495 Net cash prO\,;ded by (used in) investing activities ... ..... ........ .... ... ...... .... . (107,438) 2,374 Cash Flows from Capital and Related Financing Activities:

Proceeds from issuance of bonds ..... .......... ....... ......... ...................... ...... .. 96,957 354,776 Proceeds from notes and credit agreements .. ....... .... .... ....... ...... .. .. .. .......... . 98,737 163,807 Capital expenditures for utitity plant ... ....... ........ .... .. .. ..... ........ .......... ....... .. .. (1 40,665) (261,900)

Contributions in aid of construction and other reirmursements .................... . 9,062 18,864 Principal payments on long-term debt ..... .... ... .... ........... ... ... ...... .... ... .. ....... . (191 ,160) (284,710)

Interest payments on long- term debt ......................................................... . (76,920} (77,776}

Interest paid on defeasance debt .................. .... ............................. ........... . (1 ,107) (10,194)

Principal payments on notes and credit agreements ......... .......................... . (1 27,449} ( 142,583)

Interest payments on notes and credit agreements ..... ....... ............ ............. . (3,554} (2,145)

Olher non-operating r~ues .......................... ........................................ . 3,515 3,445 Net cash used in capital and related financing acti\nties ......................... . {332,584) (238,4 16)

Net increase (decrease) in cash and cash equivalents .. ...................... ... (74,925} 17 ,669 Cash and cash equivalents, beginning of year ................. ................... ............ . 102,729 85,060 Cash and cash equivalents, end of year .... ..................... ................................ . $ 27,804 $ 102.729 Reconciliation of Operating Income to Cash Pro\lided By Operating Acti\lities:

Operating income .................................................................................... . $ 112 ,711 $ 113,282 Adjustments to reconcile operating income to net cash pro\lided by operating acti\lities:

Depreciation and amortization ............................................................. . 122,559 133,666 Uldisbibuted net revenue - The Energy Authority ................................. . 108 648 Decormissioning, net of cuslomef" contributions ................................... . 14 ,006 21,429 Amortization of nuclear fuel ................................................................. . 43,490 40,754 Changes in assets and liabiities Wlich (used) pro\lided cash:

Receivables, net ............................................................................ . 5,409 (10,911)

Fossil fuels **** ************************************-**--*****************-**********-*-**-**** ** 356 (4 ,285)

Nlalerials and Slff)lies ---****---**-****-***-**************-*-*******--*-*-*-*****-*--**-*** 2 ,996 2,790 Prepayments and olher c..-rent assets -*--*--* * --**- *-*--** * ****--*--**-* -*--*--**- 443 1,022 Other long- term assets * * * -*-*****-***-*---* *- * ***-*- * *-****---*--*********-**-*---*****-** 938 935 Defened outflows ---*-**-* * *-*------**-*--****-*-* - *--**-** * -- **--*-****--* * -**-------*-**-- (45,654)

.Accomls payable and accrued paymenls to retail cormu,ities ---**--*-- (11 ,275) 19,122 ltlearned rewenues **-**------*--***----*--*----**--**-*-**-*-*-*-*--------*-----------**--* 38,2 17 (7,408)

Other defened inflows ----**---*-*--*----***---*----**---**----*---*-*-*--*-**---*--***---- 33,404 (14 ,342)

Other liabiities ---*---*-**--*--*----*--------*---------------*----*-------*---*-*-------*---*** 1,735 2,663 Net cash prOlided by operating aclnities **-------------*******-***-********--**-**-**** $ 365,097 $ 253,711

~ e l l a y l'bl-Cash CapitalAciNties:

Change in utiity pall: addtions in accol.W1ls payable ********************-************** $ (10,768! $ 4,273 The accompanying notes to financial statements are an integral part of these statements .

FinaiRcial Repo11t

NOTES TO FINANCIAL STATEMENTS

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES:

A. Organization -

Nebraska Public Power District ("District"), a public corporation and a political subdivision of the State of Nebraska, operates an integrated electric utility system which includes facilities for the generation, transmission, and distribution of electric power and energy to its Retail and VVholesale customers. The control of the District and its operations is 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 proprietary funds of governmental entities. In the absence of established GASS pronouncements, other accounting literature is followed induding guidance provided in the Financial Accounting Standards Board ("FASS") Accounting Standards Codification ("ASC").

The District applies the accounting policies established in the GASS codification Section Re10, Regulated Operations. This guidance permits an entity with cost-based rates and Board authorization to ind ude 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 services are rendered. Revenues and expenses related to providing energy services in connection with the District's principal ongoing operations are dassified as operating. All other revenues and expenses are dassified as non-operating and reported as investment and* other income or debt and other expenses on the Statements of Revenues, Expenses and Changes in Net Position.

D. Cash and Cash Equivalents -

The operating fund accounts are called Revenue Funds. There is a separate investment account for the Revenue Funds. The District reports highly liquid investments in the Revenue Funds with an original maturity of three months or less to be cash and cash equivalents on the balance sheet, except for these type of investments in the Revenue Funds investment account. Cash and cash equivalents in the investment accounts for the Revenue Funds and the Special Purpose Funds are reported as investments on the balance sheet E. Fossil Fuel and Materials and Supplies -

The District maintains inventories for fossil fuels and materials and supplies which are valued at average cost Obsolete inventory is expensed and removed from inventory.

F. Utility Plant, Depreciation, Amortization, and Maintenance-Utility plant is stated at cost. which indudes property additions, replacements of units of property and betterments.

The District charges maintenance and repairs, including the cost of renewals and replacements of minor items of property, to maintenance expense accounts when incurred. Upon retirement of property subject to depeciation, the cost of property is removed from the plant accounts and charged to the reserve for depreciation, net of salvage.

The District records depreciation over the estimated useful life of the property primarily on a straight-line basis.

Depeciation on utility plant was approximately 2.3% and 2.6% for the years ended December 31, 2017 and 2016.

The District had fully depeciated utility plant, primarily related to Cooper Nuclear Station ("CNS"), which was still in service of $978.1 milion and $927.5 milion as of December 31 , 2017 and 2016, respectively.

The District has long-term Professional Retail Operations ("PRO'") Agreements with 79 mlMlicipalities for certm retail electric dislri>ution systems. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreements.

The District recorded provisions, net of retirements, for amortization of these plant a<kitions of $7.5 million a1d Fhiancial Repont 32

$5.9 million in 2017 and 2016, respectively, which was included in depreciation and amortization expense. These plant additions, which were fully depreciated , totaled $191 .8 million and $185.6 million as of December 31 , 2017 and 2016, respectively.

G. Allowance for Funds Used During Construction ("AFUDC'J -

This allowance, which represents the cost of funds used to finance construction, is capitalized as a component of the cost of the utility plant. The capitalization rate depends on the source of financing . The rate for construction financed with revenue bonds is based upon the interest cost of each bond issue less interest income.

Construction financed on a short-term basis with tax-exempt commercial paper ("TECP"), tax-exempt revolving credit agreement ("TERCA"), or taxable revolving credit agreement ("TRCA") is charged a rate based upon the projected average interest cost of the related debt outstanding. The TECP program was terminated in 2017 and replaced with the TERCA. For the periods presented herein, the AFUDC rates for construction funded by revenue bonds varied from 2.2% to 4.9%. For construction financed on a short-term basis, the rate was 1.0% for 2017 and 201 6.

H. Nuclear Fuel -

Nuclear fuel inventories are included in utility plant. The nuclear fuel cycle requirements are satisfied through the procurement of raw material in the form of natural uranium, conversion services of such material to uranium hexafluoride, uranium hexafluoride that has already been converted from uranium, enrichment services, and fuel fabrication and related services. The District purchases uranium and uranium hexafluoride on the spot market and canies inventory in advance of the refueling requirements and schedule. Nuclear fuel in the reactor is being amortized on the basis of energy produced as a percentage of total energy expected to be produced. Fees for disposal of fuel in the reactor are being expensed as part of the fuel cost.

I. Unamortized Financing Costs -

These costs include issuance expenses for bonds which are being amortized over the life of the respective bonds using the bonds outstanding method. Deferred unamortized financing costs associated with bonds refunded are amortized using the bonds outstanding method over the shorter of the original or refunded life of the respective bonds. Regulatory accounting, GASB codification section Re10, Regulated Operations, is used to amortize these costs over their respective periods.

J. Asset Retirement Obligations -

Asset retirement obligations ("ARO* ) represent the best estimate of the current value of cash outtays expected to be incurred for legally enforceable retirement obligations of tangible capital assets. Regulatory accounting, GASB codification section Re10, Regulated Operations, is used to recognize these costs consistent with the rate treatment.

K. Other Postemployment Benefits ("OPEB 'J -

For purposes of measuring the net OPEB liability, deferred outflows of resources and deferred inflows of resources related to OPEB, and OPEB expense, information about the fiduciary net position of the District's Postemployment Medical and Life Benefits Plan r Plan*) and additions to/deductions from the Plan's fiduciary net position have been determined on the same basis as they are reported by the Plan. For this purpose, the Plan recognizes benefit payments when due and payable in accordance with the benefit terms. Investments are reported at fair value, except for certain investments in real estate which are reported at net asset value.

L. Auction Revenue Rights and Transmission Congestion Rights -

The District uses Auction Revenue Rights r ARR1 and Transmission Congestion Rights ("TCR1 in the Southwest Power Pool r sPP1 Integrated Market to hedge against transmission congestion charges. These financial instruments were primarily designed to allow firm transmission customers the opportunity to offset price differences due to transmission congestion costs between resources and loads. Awarded ARR provide a fixed revenue stream to offset congestion costs. TCR can be acquired through the conversion of ARR or pmchases from SPP auctions or secondary market trades.

Financial Repo11t

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 refunding . Deferred outflows related to OPES include 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 inflows include Department of Energy ("DOE") settlements, nuclear fuel disposal collections, CNS outage collections, OPES actuarial experience gains, a settlement for termination of a participation power sales agreement, non-nuclear decommissioning collections and a sales tax refund from the State of Nebraska for the construction of a renewable energy facility.

The District is required under the General Revenue Bond Resolution ("Resolution") to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses, aggregate debt service on the 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 limits, may be retained in a rate stabilization account. Any amounts in excess of the limits will be taken into account in projecting revenue requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the District's long-term wholesale power supply contracts. The District accounts for any surplus or deficit in revenues for retail service 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 Ulearned revenues, beginning of year ...... ......................................................... $ 168,710 $ 176,118 Surpluses* ** * *** * ****** * ********** * ******** ** *** * ***** * * * ***** * * * ***** ** ******* * ******** *** ****** **** ***** *** ****

44,888 9,992 Use of prior period rate stabiization finis in rates ............................... .............. . {6,671 } {17,400)

Ulearned revenues, end of year ....................................................................... . $

The DOE setUement regulatory liability was established for the reimbursement from the DOE for costs incurred by 206,927 $ 168,710 the Disbict in conjunction with the disposal of spent nudear fuel from CNS. Details of the Disbict's DOE setUement are induded in Note 12 in the Notes to Financial Statements.

The Disbict indudes in rates the costs associated with nudear fuel disposal. Such collections were remitted to the DOE under the Nudear Waste Policy Act until the DOE adjusted the spent fuel disposal fee to zero, effective May 16, 2014. The Board authorized the use of regulatory accounting for the continued collection of these costs.

This approach ensures costs are recognized in the appropriate period with rustomers receiving the benefits from CNS paying the appropriate costs. The expense for spent nuclear fuel disposal is recorded at the previous DOE rate based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal. Adartional details of the Oisbict's DOE spent nuclear fuel collections are induded in Note 12 in the Notes to Financial Statements.

FiinaRcial Repont

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 Electric System (" LES") executed a termination and release agreement in May 2017 for the Sheldon Station Participation Power Agreement. The Board authorized the use of regulatory accounting for the settlement payment as the term of the Agreement was for the life of Sheldon Station (" Sheldon"). This regulatory liability was included in Other deferred inflows on the Balance Sheets and will be eliminated as revenues from the settlement payment are incorporated in future rates.

The District began collecting in rates for non-nuclear decommissioning costs in 2017. The collections for assets which do not have a legally required retirement obligation are recorded as a regulatory liability, instead of an ARO , and are included in Other deferred inflows on the Balance Sheets.

The following table summarizes the balance of Deferred outflows of resources as of December 31 , 2017 and 2016 (in OOO's):

2017 2016 Asset retirement obligation ....... .... .. ... ...... .. ..................... .... ....... ..... .. .... ..... ...... ... $ 222,369 $ 219,378 Unamortized cost of refunded debt .... ....... ............... ........ ................... .... ...... ... ... 38,430 42,664 OPEB contributions after the measurement date ... ..... ..... .... ... ....... .. . ..... .... .. .. .. ... .. 28,290 74,658 Unamortized OPEB losses for differences in actual and e,cpected earnings .. ......... 3,283 3,862 l..klamortized OPEB losses for differences in actual and e,cpected e>eperience ....... . ____ 3~,0_30_ 3,769

$ 295,402 $ 344,331 The following table summarizes the balance of Other deferred inflows of resources as of December 31 , 2017 and 2016 (in OOO's):

2017 2016 DOE settlements . ............ ... ...... ........ ........................... ............ .... .. .... ... ............. $ 66,227 $ 82,664 Nuclear fuel disposal colections ..... ............................................................ ........ 21 ,570 15,098 CNS outage colections ................ ............................................................... ...... 20,005 l..klamortized OPEB gains for differences in actual and e,cpecled ellperience ......... 16,475 SeUlement for termination of participation power sales agreement......................... 10,500

"°1-nuclear decormissioning colections ........................................................... 5,444 Renevleble energy facility sales tax refund .......................................................... _ _ _4~,50_3_ 4,786

$ 144,724 $ 102,548 N. Net Position -

Net position is made up of three components: Net investment in capital assets, Restricted, and Unrestricted.

Net investment in capital assets consisted of utility plant assets, net of accumulated depreciation and reduced by the outstanding balances of any bonds or notes that are attributable to the acquisition, construction, or improvement of these assets. This component also included long-term capacity contracts, net of the outstanding balances of any bonds or notes attributable to these assets.

Resbicted net position consisted of the Primary account in the Debt reserve funds that are required deposits under the Resolution and the Decommissioning funds, net of any related liabilities.

Unrestricted net position consisted of any remaining net position that does not meet the definition of Net investment in capital assets or Restricted and is used to provide for working capital to fund non-nuclear fuel and inventory requirements, as well as other operating needs of the District.

0 . Use of Estimates -

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

P. Recent Accounting Pronouncements -

GASS Statement No. 87, Leases, was issued in June 2017. This Statement will bring substantially all leases for lessees on to the balance sheet. For operating leases, lessees will be required to recognize an asset for the right to use the leased item and a corresponding lease liability. Lease liabilities will be considered long-term debt and lease payments will be capital financing outflows in the cash flow statement. In the activity statement, lessees will no longer report rent expense for operating-type leases, but will instead report interest expense on the liability and amortization expense related to the asset. For lessors, the accounting will mirror lessee accounting. Lessors will recognize a lease receivable and a corresponding deferred inflow of resources (with certain exceptions), while continuing to report the asset underlying the lease. Interest income associated with the receivable will be recognized using the effective interest method. Lease revenue will arise from amortizing the deferred inflow of resources in a systematic and rational manner over the lease term. The requirements of this Statement are effective for reporting periods beginning after December 15, 2019, with earlier application encouraged.

Management is currently evaluating the impact of this statement.

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

GASB Statement No. 84, Fiduciary Activities, was issued in January 2017. This Statement addresses accounting and financial reporting requirements for certain fiduciary funds in the basic financial statements. Governments with activities meeting the aiteria are required to present a statement of fiduciary net position and a statement of changes in fiduciary net position. The requirements of this Statement are effective for reporting periods beginning after December 15, 2018. The implementation of this Statement will require the District to indude fiduciary statements with the statements for its business-type activities.

GASB Statement No. 83, Certain Asset Retirement Obligations, was issued in November 2016. This Statement addresses accounting and financial reporting requirements for certain AROs. This Statement imposes requirements in regards to the ARO liability recognition, measurement and specifics on when re-measurement should occur. This Statement also requires disclosures regarding the methods and assumptions used to estimate the ARO, the remaining useful life of capital assets associated with the liability, any governmental legal funding requirements, any assets restricted for payment and any minority share ARO liability. The requirements of this Statement are effective for reporting periods beginning after June 15, 2018. The District previously reported AROs under the FASB guidance, which differs from the GASB guidance. The FASB guidance required measurement of the liability based on the present value of the asset's disposal costs whereas measurement under this GASB Statement is based on the best estimate of the current value of cash ouffays expected to be incurred. The FASB guidance required the recognition of a corresponding capital asset whereas the GASB Statement requires the recognition of a corresponding deferred outflow of resources. The Disbict adopted this Statement in 2017 and uses regulatory accounting to align asset retirement costs with 1heir related recognition in rates.

FiNa,ncia!l iR~JJOllt 36

GASB Statement No. 75 , Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions, was issued in June 2015 . The requirements of this Statement will improve accounting and financial reporting for OPEB. This Statement requires the liability for defined benefit OPEB (net OPEB liability) to be measured as the portion of the present value of projected benefit payments to be provided to current active and inactive employees that is attributed to those employees' past periods of service (total OPEB liability) , less the amount of the OPEB plan's fiduciary net position. Enhanced disclosures and additional required supplementary information are also required under the Statement. This Statement is effective for fiscal years beginning after June 15, 2017. The District adopted this Statement in 2016 and deferred costs through regulatory accounting, to be amortized during the period in which they are recovered in rates. Additional disclosures related to OPEB are in Note 11 .

2. CASH AND INVESTMENTS:

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

The fair value of all cash and investments, regardless of classification on the Balance Sheets, were as follows as of December 31 (in OOO's):

2017 2016 Weighted Weighted Average Maturity Average Maturity Fair Value (Years} Fair Value (Years)

U.S. Treasury and government agency securities .. $ 998,148 4.7 $ 936,317 4.0 Corporate bonds .............................................. ... 169,051 9.3 181 ,438 9.6 Municipal bonds ............. ..................................... 11 ,900 14.3 11 ,901 12.4 Cash and cash equivalents ............................ .... .. _ _ 134___,_,3_2_6_ 0.1 129,261 Total cash and investments ............. ................. $1 ,313,425 $1 ,258,917 Portfoio weighted average maturity ..................................... . 4.9 4.5 Interest Rate Risk- The investment strategy for all investments, except for the decommissioning funds, is to buy and hold securities until maturity, which minimizes interest rate risk. The investment strategy for decommissioning funds is to actively manage the diversification of multiple asset dasses to achieve a rate of return equal to or exceeding the rate used in the decommissioning funding plan model assumptions. Accordingly, securities are bought and sold prior to maturity to increase opportunities for higher investment returns.

Credit Risk - The District follows a Board-approved Investment Policy. This policy complies with state and federal laws, and the Resolution's provisions governing the investment of all funds. The majority of investments are direct obligations of, or obligations guaranteed by, the United States of America. Other investments are limited to investment-grade fixed income obligations.

Custodial Credit Risk - Cash deposits, primarily interest bearing, are covered by federal depository insurance, pledged collateral consisting of U.S. Government Serurities held by various depositories, or an *rrevocable, nontransferable, unconditional letter of credit issued by a Federal Home Loan Bank.

Finanoial R~p@nt

The fair values of the District's Revenue and Special Purpose Funds as of December 31 were as follows (in OOO's) :

The Revenue funds are used for operating activities for the District. Cash and cash equivalents in the Revenue funds are reported as such on the balance sheet, except cash and cash equivalents in the Revenue Fund investment account are reported as investments. The investment account for the Revenue funds included cash equivalents of $99.5 million and $20.9 million as of December 31 , 2017 and 201 , respectively.

2017 2016 Re~nue funds - Cash and cash equivalents .... .. ..... ... .. .. ..... ................ ... ........... $ 127,302 $ 123,678 Re~nue funds - ln~trnents ........ ...... .... ................ .. ..... ... .. ..... ........................ ___4_3_9.,_ ,6_7_5_ 352,382

$ 566,977 $ 476,060 The Construction funds are used for capital improvements, additions, and betterments to and extensions of the District's system. The sources of monies for deposits to the construction funds are from revenue bond proceeds and issuance of short-term debt.

2017 2016 Construction funds - Cash and cash equivalents . .. ... .. . . .. . . . .. . . . .. .. . . . . . .. . .. . . . .. . .. .. . . . . $ $ 25 Construction funds - l n ~ t s ...... .............. ...... ..... .... ... .. .............................. _ _ _54~ ,8_08_ 106,179

$ 54,808 $ 106,204 The Debt reserve funds, as established under the Resolution , consist of a Primary account and a Secondary account. The District is required by the Resolution to maintain an amount equal to 50% of the maximum amount of interest accrued in the current or any Mure year in the Primary account. Such amount totaled

$37.8 million and $38.7 million as of December 31 , 2017 and 2016, respectively. The Secondary account can be established at such amounts and can be utilized for any lawful purpose as determined by the District's Board.

Such account totaled $51 .0 million and $51 .3 million as of December 31 , 2017 and 2016, respectively.

2017 2016 Debt reserve funds - lnwstrnents ..................................................................... $ 88,764 $ 90,032 The Employee Benefit funds 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. The self-funded hospital-medical benefit plan had funds of $1 .9 million and $4.9 million as of December 31 , 2017 and 2016, respectively. For additional information on OPEB see Note 11 .

2017 2016 Erq>loyee benefit funds- Cash and cash equivalents ......................................... $ 935 $ 1,843 Erq>loyee benefit funds - ln\eStrnents ............................................................... _ _ _ _999__ _ _ _ _3..,_ ,008

$ 1,934 $ 4,851 The Decommissioning funds are utilized to account for the investments held to fund the estimated cost of decommissioning CNS when its operating license expires. The Decommissioning funds are held by outside trustees or custodians in compliance with the decommissioning fund*ng plans approved by the Board which are invested primarily in fixed income governmental serurities.

2017 2016 Decormissioning funds - Cash and cash equNBlerds ........................................ $ 6,089 $ 3,715 Decormissioning funds- lrnestrnents .............................................................. - - -594,853 ~-- 578,055

$ 600,942 $ 581770 Fi:nanoial Rep(!rnt 38

3. FAIR VALUE OF FINANCIAL INSTRUMENTS:

Fair value is the exchange price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date.

GASS Statement No. 72 ("GASS 72"), Fa ir Value Measurement and Application , establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in an active market for identical assets or liabilities and the lowest priority to unobservable inputs. Financial assets and liabilities are dassified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels of fair value hierarchy defined in GASS 72 are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The District's investments in cash and cash equivalents are included as Level 1 assets.

Level 2 - Pricing inputs are other than quoted market prices in the active markets induded in Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. Level 2 inputs indude the following:

quoted prices for similar assets or liabilities in active markets;

quoted prices for identical assets or liabilities in inactive markets;

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

inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 2 assets primarily indude U.S. Treasury and government agency securities held in the Revenue funds and other Special Purpose Funds and U.S. Treasury and government agency securities, corporate bonds, and municipal bonds held in the Decommissioning funds.

Level 3 - Pricing inputs indude significant inputs that are unobservable and cannot be corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies using significant unobservable inputs. The District currently does not have any Level 3 assets or liabilities.

The District performs an analysis annually to determine the appropriate hierarchy level d assification of the assets and liabilities that are ind uded within the scope of GASB 72. Financial assets and liabilities are dassified in their entirety based on the lowest level of input that is significant to the fair value measurement There were no liabilities within the scope of GASB 72 as of December 31, 2017 and 201 6. The following tables set forth the District's financial assets that are aa::ounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , (in OOO's):

2017 l...e\lel 2 l...e\lel 3 Total Rele1ue and special purpose finis,, erlJding dec.u111issiooing:

U S. Treasury and gowemment agency sect.rilies ............ . $ s 584,24'6 s $ 584,24'6 Cash and cash equi"8lents ********************************************** 128,237 128,237 Decormissioning fmds:

U S. Treasury and gowemment agency securities .........*... 413,902 413,902 Corporate bonds ........................................................... . 169,051 169,051 PAricipal bonds ************************************************************* 11,900 11,900 Cash and cash equi\lllenls ............................................. . 6,089 6,089 s 134,326 $1,179,099 s $ 1,313,425 Finanoial iReiJi>.@rt

2016 Level 1 Level2 Level 3 Total Revenue and special purpose funds, excluding decol'TYllissioning:

U.S. Treasury and government agency securities ............ . $ $ 551 ,602 $ $ 551,602 Cash and cash equivalents .. ..... ....... ...... ...... ........ .......... . . 125,546 125,546 DecOl'TYllissioning funds:

U.S. Treasury and government agency securities .... ... ...... 384,715 384,715 Corporate bonds ... ..... ........ ............ .. .. ............ ...... ..... .... . 181 ,438 181,438 Municipal bonds .................................................... ......... 11 ,901 11,901 Cash and cash equivalents ..................... ... ... ...... ...... ... ... . 3,715 3 715

$ 129,261 $1 ,129,656 $ $1 ,258,917

4. UTILITY PLANT:

Utility plant activity for the year ended December 31 , 2017, was as follows (in OOO's):

Decermer 31 , Oecermer 31 ,

2016 Increases Decreases 2017 Nondepreciable utility plant Land and improwments ....... ...... ......... ......... $ 74, 138 $ 1,124 $ (68) $ 75,194 Construction in progress ............. .... ... ... ..... .. 135,853 120,399 (122,737) 133,515 Total nondepreciable utility plant ........ ...... _ _2_0_9_,9_9_1_ 121,523 (1 22,805) 208,709 f'l.lclear fuel* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . 197,730 11 ,979 (43,490) 166,219 Depreciable utility plant Generation - Fossil ............................. :...... . 1,621,919 33,992 (5,754) 1,650,157 Generation - f'l.lclear ................................... 1,314,210 14,978 (7,182) 1,322,006 Transmission ......... .............. ...................... . 1,254,421 47,223 (5,0 11) 1,296,633 Distribution ................................................ . 226,563 9,291 (1 ,409) 234,445 General ..................................................... . 344,578 15,169 (9,812) 349,935 Tola! depreciable utility plant 4,761,691 120,653 (29,168) 4,853,176 Less resene for depreciation ........................... . (2,573,645) (11 3,729) 29,168 (2,658,206)

Depreciable utility plant, net ..................... 2,188,046 6,924 2,1 94,970 Utility plant actiw:y. net .................................... . $

2,595,767 $ 140,426 $ (166,295) $ 2,569,898

Nuclear- tJel decreases represented amomzalioo cif: $43.5 m ion.

Fiinmioiall Repemt

Utility plant activity for the year ended December 31 , 2016, was as follows (in OOO's):

December 31 , December 31 ,

2015 Increases Decreases 2016 Nondepreciable utility plant Land and improvements .. ...... ..... ....... .. .. ..... .. $ 64,370 $ 9,780 $ (12) $ 74,138 Construction in progress ...... .. .. ...... ... ......... .. 209,626 180,237 (254,010) 135,853 Total nondepreciable utility plant ... ...... ..... 273,996 190,017 (254,022) 209,991 Nuclear fuel* ..... .. ..... ...... .... ...... .. .. .. ....... ... ..... ... 168,420 70,064 (40,754) 197,730 Depreciable utility plant Generation - Fossil .... ... ..... ... .. ... ........ .......... 1,573,880 65,818 (17,779) 1,621 ,919 Generation - Nuclear ... .... ..... ....... ............... . 1,384,031 68,415 (138,236) 1,314,210 Transmission .. ..... ........ ............ ....... .. .... ...... 1,172,108 86,994 (4,681) 1,254,421 Distribution .... ...... .. ...... ........ ...... .......... .. ..... 221 ,791 6,336 (1 ,564) 226,563 General ... ... ........ ....... ............................ .... . 334,836 13,528 (3,786) 344,578 Total depreciable utitity plant 4,686,646 241 ,091 (166,046) 4,761 ,691 Less reserve for depreciation ...................... ...... (2,620,091) (119,600) 166,046 (2,573,645)

Depreciable utility plant, net .... ......... .. ... ... 2,066,555 121 ,491 - 2,188,046 Uliity plant acti\ftty, net .... ...... ................. .......... $ 2,508,971 $ 381 ,572_ $ (294,776} $ 2,595,767

Nuclear rue! decreases represented amortization of $40.8 million.

5. LONG-TERM CAPACITY CONTRACTS:

Long-term capacity contracts indude the District's share of the construction costs of Omaha Public Power District's r oPPD.) 664 megawatt r MW) Nebraska City Station Unit 2 r Nc2*) coal-fired power plant The District has a participation power agreement with OPPD for a 23.7% share of the power from this plant NC2 began commercial operation on May 1, 2009, at whidl time the District began amortizing the amount of the capacity contract associated with the plant on a straight-line basis over the 40-year estimated useful life of the plant Accumulated amortization was $39.9 million and $35.4 million as of December 31 , 2017 and 2016, respectively.

The unamortized amount of the plant capacity contract was $139.2 million and $143.7 million as of December 31 ,

2017 and 2016, respectively, of whidl $4.4 million was induded in Prepayments and other current assets as of December 31, 2017 and 2016. The District's share of NC2 working capital was also induded in Prepayments and other current assets and was $6.5 million as of December 31 , 2017 and 2016.

Long-term capacity contracts also indude the District's purdlase of the capacity of a 50 MW hydroelectric generating facility owned and operated by The Central Nebraska Public Power and Irrigation District r eentrat'").

The District is amortizing the contract on a straight-line basis over the 40-year estimated useful life of the facility.

Accumulated amortization was $66.6 million and $64.3 million as of December 31 , 2017 and 2016, respectively.

The unamortized amount of the Central capacity contract was $20.1 million and $22.4 million as of December 31, 2017 and 2016, respectively, of whidl $2.3 million was induded in Prepayments and other current assets as of December 31, 2017 and 2016.

The District has an agreement whereby Central makes available all the production of the facility and the District pays all costs of operating and maintaining the facility plus a charge based on the amount of energy delivered to the District Costs of $1.8 milion and $2.5 million in 2017 and 2016, respectively, are induded in Power purdlased in the accompanying Statements of Revenues, Expenses, and Changes in Net Position.

IFililancial R~prnmt

6. INVESTMENT IN THE ENERGY AUTHORITY:

The District has an investment in The Energy Authority ("TEA"), a nonprofit corporation headquartered in Jacksonville , Florida, and incorporated 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 ,

201 7 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 maturities, as of December 31, 2017 and 2016, and activity for 2017 (in OOO's):

Principal ArooU1ls Due Decermer 31, Decermer 31 , WllhinOle 2016 Increases Oeaeases 2017 Yew Rewnue bonds -------------------------- $ 1,678,844 $ 96,957 $ (227,532) $ 1,548,269 $ 98,205 Cmmercial paper no1es ------------- 74,000 11,320 (85,320)

Reldling aedit agreementsc11 ---- -----"--- 188,924 87,417 {42.129} 234,212 165,212 Tolal mg-term debt ac1ni1y ---- ___ $_1....,94__.

1,...

768_ s 195,694 s {354,9812 S 1,782,,481 $ 263,417 Einanoial Rep.011t 42

The following table summarizes the debt balances, net of current maturities, as of December 31 , 2016 and 2015, and activity for 2016 (in OOO's):

Principal Amounts Due December 31 , December 31 , Within One 2015 Increases Decreases 2016 Year Re\A:!nue bonds .. .... ..... ... .. .. .. ... .. $ 1,596,972 $ 354,776 $ (272,905) $ 1,678,844 $ 81 ,250 Commercial paper notes ........ .... 83,000 88,365 (97,365) 74,000 74,000 Rewl1Ang credit agreements ... .... 158,700 75,443 (45,219) 188,924 Total long- term debt acti1Aty .. $ 1,838,672 $ 518,584 $ (415,489) $ 1,941 ,768 $ 155,250 Revenue Bonds On January 1, 2018, the District called the remaining outstanding General Revenue Bonds, 2012 Series C, with a principal amount that aggregated $4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of OPES costs for customers under the 2016 Contracts. Congress passed the Tax Cuts and Jobs Act ("Act") in December 2017, which eliminated the use of tax-exempt advanced refunding transactions.

In April 2017, the District issued General Revenue Bonds, 2017 Series A and 2017 Series B, in the amount of

$86.0 million to refund the General Revenue Bonds, 2007 Series 8 . The refunding reduced total debt service payments over the life of the bonds by $11.8 million, which resulted in present value savings of $10.0 million. Also in April 2017, the District entered into an escrow deposit agreement in conjunction with the refunding of certain of the General Revenue Bonds, 2007 Series 8 , having maturity dates ranging from January 1, 2018 through January 1, 2028.

Congressional action reduced the 35% interest subsidy, pursuant to the requirements of the Balanced Budget and 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 years ended September 30, 2017 and 2016, respectively.

In November 2016, the District issued General Revenue Bonds, 2016 Series C and 2016 Series D, in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and to refund a portion of Commercial Paper Notes, Series A. The District also issued in November 2016, General Revenue Bonds, 2016 Series E {Taxable), in the amount of $56.1 million to fund a portion of OPEB costs for customers under the 2016 Contracts.

In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series B, in the amount of

$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of commercial paper notes. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.

Also in February 2016, the District entered into an esaow deposit agreement in conjunction with the advanced refunding of certain of the:

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

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

General Revenue Bonds, 2012 Series C, maturing on January 1, 2025 through January 1, 2026 In January 2016, the District issued TECP in the amount of $43.6 million to refund a portion of the General Revenue Bonds, 2005 Series C and the General Revenue Bonds, 2006 Series A.

Financial Rep@rt

Certain of the General Revenue Bonds, from the following series, with outstanding principal amounts that aggregate $324.1 million as of December 31 , 2017, were legally defeased and are no longer outstanding: 2008 Series B and 2012 Series C.

Debt service payments and principal payments of the General Revenue Bonds as of December 31 , 2017, are as follows (in OOO's):

Debt Service Principal Year Payments Payments 2018 ......... .. .. .... ............ .... .. ........ . . $ 170,403 $ 98,205 2019 ******* **** ***************** ***** ******** **** 146,856 79,320 2020 *** *** *** ****** ** ***** *** ******************** 146,760 82,915 2021 ......................... ..... ... ..... .. ... . . 143,968 84,085 2022 ....... .... ............ .... ... ...... ... ..... . 136,550 80,825 2023-2027 .. .. .. .. ....... .. .... .. ... .... ...... . 637,780 417,475 2028-2032 .............. ...... .......... ... ... . 469,091 341,640 2033-2037 .................. ... ....... ........ . 270,720 218,700 2038-2042 ...... ....... ...... ........ .... ..... . 103,408 88,685 2043-2045 .... .......................... .. .... . 15,962 14,895 Total Payments .. .... ....... .. ........ ..... .. $ 2,241,498 $ 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.

Commercial 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 District 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 is anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The canying 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 Crecfll Agreement The District has entered into a Taxable Revolving Credit Agreement ('TRCA1 with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 million. The TRCA allows the District to increase the loan commitments to $300.0 million. The District had outstanding balances under the TRCA of $165.2 milion and $188.9 million, as of December 31 , 2017 and 2016, respectively. The outstanding amount is anticipated to be retired by future collections through electric rates. The carrying value of the taxable revolving aedit agreements approximates market value due to the short-term nature of the agreements. The TRCA was renewed on July 31 , 2015, and terminates on July 30, 2018.

iFinan:oia R~p011t 44

Revenue bonds consist of the followng (OOO's except interest rates) :

December 31 , Interest Rate 2017 2016 General Revenue Bonds:

2007 Series B:

Serial Bonds: 2016-2026 ..... ......... ............... .. 4.375% - 5.00% $ $ 97,415 Term Bonds: 2027-2031 ...... ........................ . 4.65% 9,620 2008 Series B Serial Bonds 2017-2029 .......... .. ...... .. 4.00% - 5.00% 10,700 2009 Series A Taxable Build America Bonds:

Term Bonds: 2019-2025 .... .......................... . 6.606% 17,465 17,465 2026-2034 .. ....... ....... ........ ..... . . 7.399% 32,890 32,890 2009 Series C Serial Bonds 2017-2019 ................... . 4.00% - 4.25% 2,535 4 ,605 2010 Series A Taxable Build America Bonds:

Serial Bonds: 2019-2024 ........... ...... ... .......... . 3.98% - 4.73% 31 ,875 31 ,875 Term Bonds: 2025-2029 ....................... ...... .. 5.323% 27,985 27,985 2030-2042 ...... .. ... .... .... .. ......... . 5.423% 54,190 54,190 2010 Series B Taxable Serial Bonds 2016-2020 ...... .. 3.358% - 4.18% 2 ,755 3,600 201 O Series C:

Serial Bonds: 2017-2025 ....................... ...... .. 3.00% - 5.00% 40,685 48,760 Term Bonds: 2026-2030 .............................. . 4.00% 6,165 6,165 2026-2030 .... .... .. ..... .. ... .......... . 5.00% 14,180 14,180 2012 Series A Serial Bonds 2017-2034 .................. .. 3.00% - 5.00% 182,145 190,4 10 2012 Series B:

Serial Bonds: 2017-2032 ......................... .. .. .. 2.00% - 5.00% 83,330 92,320 Term Bonds: 2033-2036 ............. .. .............. .. 3.625% 2,320 2,320 2037-2042 .... .......... ...... .......... . 3.625% 4,155 4,155 2012 Series C Serial Bonds 2017-2028 ................... . 3.00% - 5.00% 11 ,045 2013 Series A Serial Bonds 2017-2033 ........... ........ . 3.00% - 5.00% n ,480 91 ,100 2014 Series A:.

Serial Bonds: 2017-2038 ............................. .. 2.00% - 5.00% 151 ,015 153,630 Term Bonds: 2039-2043 .............................. . 4.00% 31 ,650 31 ,650 2039-2043 .............................. . 4.125% 1,945 1,945 2014 Series C Serial Bonds 2017-2033 ................... . 4.00% - 5.00% 138,130 143,025 2015 Series A-1 Serial Bonds 2022-2034 ................ . 3.00% - 5.00% 119,400 119,400 2015 Series A-2:

Serial Bonds: 2017-2034 .............................. . 3.00% - 5.00% 56,045 56,485 Term Bonds: 2035-2039 .............................. . 5.00% 46,205 46,205 2016 Series A:.

Serial Bonds: 2018-2035 ............................... 3.125% - 5.00% 65,210 65,210 Term Bonds: 20~2040 ............................... 5.00% 5,595 5,595 2016 Series B:

Serial Bonds: 2018-2036 ............................... 5.00% 67,255 67,255 Term Bonds: 2037-2039 ............................... 5.00% 1,165 1,165 2016 Series C Serial Bonds 2017-2035 .................... 3.00% - 5.00% 67,025 70,685 2016 Series D:

Serial Bonds: 2017-2035 ............................... 200% - 5.00% 20,960 21,170 Term Bonds: 20~2040 ............................... 5.00% 9.505 9,505 2041-2045 ............................... 5.00% 12,140 12,140 2016 Series E Taxable Serial Bonds 2022-2033 ........ 2337% - 3.567% 56,050 56,050 2017 Series A Serial Bonds 2017-2027 .................... 200% - 5.00% 18,125 2017 Series B Serial Bonds 2017-2027 .................... 5.110% 59, 170 Total par anorid rewenue bonds ...................................................................... 1,506,745 1,611 ,915 Uanortized prernilnl net d ciscotri ............................................................. - -139,729 ~-- 148,179 1.646,474 1,760,094 Less - cwrent rnall.aities d rewenue bonds ..................................................... _ __..(98 .::..=,205

.c;..;;...;.L..

) (81 ,250)

Total rewenue bonds ................................................................................. $1 ,548,269 $ 1,678,844 Fina:noial :Repolit

8. PAYMENTS IN LIEU OF TAXES:

The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District. Such payments totaled $10.1 million for each of the years ended December 31 , 20 17 and 20 16, respectively.

9. ASSET RETIREMENT OBLIGATIONS:

The District implemented GASS Statement No. 83, Certain Asset Retirement Obligations, in 2017, retroactive to 2016. Prior to the implementation of the GASS guidance, FASS guidance had been used for ARO reporting. The FASS guidance required measurement of the liability based on discounted dollars or the present value of the asset's disposal costs. Measurement under GASS 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 FASS guidance required the recognition of a corresponding capital asset whereas the GASS 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 201 7 201 6 CNS license termination costs ... .............. ..... ..... ............... ......... ... .. . $ 811 ,801 $ 795,026 GC3S and SS ash landfils ............. .... .. .. .... ..... ... ...... ........................ . 9,040 3,208 Ainsv.orth ... .... ... ...... ... .... .... ............. ............. .. .. ............ .. ......... .... .. 1,953 1,91 3 Underground storage tanks ... ..... ...... ......... ...... .. ................ ............. . 1 000 1 000

$ 8231794 $ 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 license 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 termination; 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-level radioactive waste management, low-level radioactive waste disposal, performance uncertainties (contingency) and site restoration requirements. An expert panel, consisting of District management representatives with considerable nuclear 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 c PI-U"') were used to adjust these obligations for inflation.

The inflation rates used were 2 .1 1% and 2.07% for the years 2017 and 2016, respectively. The District has funds set aside for decommissioning of $600.9 million and $581 .8 million as of December 31 , 2017 and 2016 ,

respectively. These funds exceeded the NRC's required funding provisions for nudear decommissioning.

The District is required by the Environmental Protection Agency f EPA1 and the Nebraska Department of Environment Quality r NDEQ"') to decommission the ash landfiUs at GGS and Sheldon, consistent with their regulations. As GASB guidance is undear related to the accounting treabnent for ash landfiU AROs, GASB Statement No. 83 was considered analogous authoritative literature and applied in this situation. The ash landfils have an estimated dosure date in the years 2086 and 2036 for GGS and Sheldon, respectively. The AROs were based on external studies to estimate costs using one scenario after an assessment of the physical site. The dosure and post-closure costs were based on the Closure Plan in the studies and included final cover placements and lined surface water control slrudures. The costs in the latest studies were in 201 7 dolars. The ARO inaeased from 2016 because of a regulatory change which inaeasecl the post-closure period from five years to 30 years. The Oislrict provided guarantees and financial assurance through correspondence and supporting information to NDEQ in 2 017. Commencing in 2017, the District included in rates decommissioning costs for certain assets at GGS and Sheldon. The costs induded in rates for the decommissioning of the ash landfills were Fiilil:arnoiaJl Rep@nt 46

$0.4 million for the year ended December 31 , 2017. These rate collections reduced the related deferred outflow for the ash landfills.

The District is required by contracts with the landowners of the Ainsworth site to restore the property, as nearly as possible, to the condition it was in prior to the District's use of the easement. Ainsworth has an estimated closure date of September 30, 2025. The ARO was based on an external study for costs using one scenario. The assumptions included: 1) no hazardous construction material abatement is required; 2) no environmental costs to address site clean-up; 3) floor drain and septic tanks will be decommissioned per state regulations; 4) wind turbine nacelles, turbine towers, transformers and other electrical equipment are removed from the site by the demolition contractor; 5) the O&M buildings and one onsite meteorological tower were included with the demolition costs; 6) all foundations will be removed to two feet below finished grade; and 7) all concrete and crushed rock surfacing will be removed. The costs in the study are in 2015 dollars. Rates in the consumer price index for all urban consumers ("CPI-U") were used to adjust these obligations for inflation. The inflation rates used 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 lives of the storage tanks cannot be reasonably estimated. The AROs were based on the best estimate of District management representatives with expertise in environmental issues. The District provided guarantees and financial assurance through correspondence and supporting information to NDEQ in 2017. There have not been any decommissioning costs for the underground storage tanks included in rates.

Financial Report

The District 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) :

As originally As reported reported Balance Sheet 2016 2016 Change Utility Plant, at Cost:

Utility plant in ser'Ace .... .... ........ .. .. .. ......... ... .... ... ... .. .. ... ... ..... ...... .. . $ 4,835,829 $ 4,971 ,259 $ (135,4.30)

Less reserve for depreciation ...... ... .... ... ........... ..... ... .......... .. ...... .. . 2,573,645 2 ,708,036 (134,391) 2,262.184 2,263,223 (1 ,039)

Construction work in progress .... ...... .... ...... .......... ....... .... ............. . 135,853 135,853 Nuclear fuel , at amortized cost ......... .. .... ..... ... ..... ........... .. ..... .. ... .. . 197,730 197,730

$ 2 ,595,767 $ 2,596,806 $ (1 ,039)

Other Long-Term Assets:

Regulatory asset for ARO .... ... .. ....... .................... ............... ... ...... . $ $ 44,899 $ (44,899)

Regulatory asset for other posterTl)loyment benefits ... .............. ...... . 221,973 221,973 Long-term capacity contracts .. .. .... ....................... ...... ................ .. . 159,445 159,445 Unamortized fi nancing costs ....... .. .................................. .... ... ... .... 8,945 8 ,945 lmestment in The Energy Authority .. ..... .......................... ..... .... .... . 6 ,370 6 ,370 Other ....... .... .... ....... ........... ....... .......................... ............ ........ ... . 9,4 16 9,4 16

$ 406,149 $ 451,048 $ (44,899)

Total Assets .................. ..... ... .............................. .................... .... . $ 4,560,252 $ 4,606,190 $ (45,938)

Deferred Outflows of Resources:

Asset retirement obigation ........................................................... . $ 219,378 $ $ 219,378 U1amortized cost of refunded debt ............................................... . 42,664 42,664 Other ~ rnent benefits ..................................................... . 82 ,289 82 ,289

$ 344,331 $ 124,953 $ 219,378 TOTAL A SSETS AN) DEFERRED OUTFLOWS $ 4,904,583 $ 4,731 ,143 $173,440 Olher Long-Term Liabiities:

Asset retirement obligation ........................................................... . $ 801 ,147 $ 627,707 $173,440 Net other ~ r n e n t benefit iabiity ....................................... 258,609 258,609 Other ......................................................................................... . 3,362 3,362

$ 1,063,118 $ 889,678 $173,440 Total Liabiities ............................................................................ . $ 3,218,208 $ 3,044,768 $ 173,440 IDTAL LIABILITIES, DEFERRED IIIFLOWS, AN) f>ET POSITICJII ... $ 4,904,583 $ 4,731 ,143 $173,440 iFinanoia[ Rep©Iit 48

10. RETIREMENT PLAN:

The District'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 immediately upon hire. Contributions ranging from 2%

to 5% of base pay are eligible for District matching dollars after six months of employment. The District contributes two times the Plan member's contribution 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 in matching for covered salary from

$40,000 to $75,000.

Plan members are immediately vested in their own contributions and earnings and become vested in the District's contributions and earnings based on the following vesting schedule:

Years of Vesting Participation Percent 5 years or more ... ....... ... .. ... .... ...... .. ..... . 100%

4 years .... ...... .. ..... ... ..... ... ....... ... ......... . 75%

3 years ......................... ...... ...... ... ...... .. 50%

2 years .. ... ........... ...................... .......... 25%

Less than 2 years .... .... ....................... . 0%

Nonvested District contributions are first used to cover Plan administrative expenses and any remaining forfeitures are allocated back to Plan participants.

Employees may also contribute to a defined contribution 457 pension plan ("457 Plan*). The 457 Plan is a tax-deferred investment option with no District match. Pay period contributions can be elected and changed at any time. Earty withdrawals can be made from the 457 Plan following separation of service regardless of age with no IRS penalty. Income taxes are owed on any withdrawals. The Participants' contributions were $2 .5 million and

$2.1 million for 2017 and 201 6 , respectively.

11. OTHER POSTEMPLOYMENT BENEFITS:

The Disbict earty adopted the provisions of GASS Statement No. 75 ("GASB 75m). Accounting and Financial Reporting for Postemployment Benefits Other than Pensions, in 2016. There was no impact to beginn*ng net position as a result of the imp ementation in 2016.

A. General information regarding the OPEB Plan -

Plan Desaiption The Disb'ict's Postemployment Medical and Life Benefits Plan ("Plan1 provides postemployment hospital-medical and life insurance benefits to qualifying retirees, surviving spouses, and employees on long-term disability and their dependents. Benefits and related eligibility, funding and other Plan provisions, for this single-employer, defined benefit Plan, are authorized by the Board.

The Plan has been amended over the years and provides different benefits based on hire date and/or the age of the employee. The District pays all or part of the cost (determined by age) of certain hospital-medical premiums for employees hired on or prior to December 31, 1992. Employees hired on or after January 1, 1993, are subject to a conbibulion cap that limits the District's portion of the cost of such coverage to the full premium the year the employee reached age 65, or the year in which the employee retires if older than age 65. Employees hired on or after January 1, 1999, are not eligible for other postemployment hospital-medical benefits once they reach age Fi:nm10ial Repolit

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

Employees Covered by Benefit Terms The following table shows the employees covered by the hospital-medical benefit terms as of January 1:

2017 2016 Actiw erll)loyees ....... .. ............ .... .... ... .... ..... ...... ........ ......... .... 1,007 1,175 lnactiw elll)loyees in retirement status ....... ..... ..... .. ........ ..... ... .. 1,381 1,260 lnactiw elll)loyees in long-term disabitity status .. ............... ........ 64 67 Total erll)loyees cowred by benefit terms ....... .......................

2,452 2,502 The following table shows the employees covered by the life insurance benefit terms as of January 1:

2017 2016 Actiw erll)loyees .. .... .. .... .... .......... .. ... ..... ... ......... ...... ........... ... 1,851 2,003 lnactiw erll)loyees in retirement status ..... ... .. ........................... 1,213 1,077 lnactiw erll)loyees in long-term disabiity status ..... ............ ........

- - - - 74 Contributions Total erll)loyees co'v'efed by benefit terms . . . .. . . .. . . . . . .. . .. . . . .. . . . . . .

3,136 3,154 The Board annually approves the funding for the Plan, which has a minimum funding requirement of the actuarially-determined annual required contribution ("ARC*) to achieve full funding status on or before December 31 , 2033. The District OPEB contributions were $28.4 million and $74.7 million in 2017 and 2016, respectively. Certain wholesale customers under the 2002 Contracts have pursued legal action related to their objection of the indusion in rates of additional collections of previously incurred OPEB costs. Since the arbitration filing in May 2016, collections from these customers have been held in separate accounts and have not been transferred to the Trust, pending the outcome of the legal action. The revenue collections for the catdHJp OPEB 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, respectively.

Contributions from inactive Plan members for their share of the premium payments are reported as a reduction of benefit expenses. Contributions from Plan members were $0.6 million and $0.5 million for 2017 and 2016, respectively.

8 . Net OPEB Liability-The District's net OPEB liability was measured as of January 1, 2017, and January 1, 2016, and the total OPEB liability used to calculate the net OPEB liability was determined by an actuarial valuation as of these dates.

Financial ~~pont 50

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 ....... ....... . Le"1:ll 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 % initial, ultimate 4.5%

Inflation ... ...... ........................ . 2.1%

I nvestrnent rate of return ......... . 6.25%, net of in"1:lstrnent e~nse, including inflation M>rtality ................................ . 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 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 inducted in the measurement, unless otherwise specified:

Actuarial cost method ........... .. . Entry Age l'brmal Alrortization method ...... ..... ... . Lei.el arrortization of the unfunded accrued tiability Alrortization period ................ . 17-year closed period Asset valuation method ...... ..... . 5-year srroolhed market Discount rate ......................... . 6.25%

Healhcare cost trend rates ..... . Pre-Medicare: S°.k initial, ulimate 5%

Post-Medicare: 6.75% initial, ulimate 5%

Inflation ................................. . 2.1%

I n ~ rated return ......... . 6.25%, net d i n ~ e>q:>enSe, incuding inflation Nlorlaity .... --*. -* ....................... RP-2014 Aggregate table projected back to 2006 using Scale Yl-2014 and projected forward using Scae Yl-2015 \Mlh generational projection Retirement age ...................... . Varies by age The long-term expected rate of return on OPEB plan *nvesbnents was determined using a building-block method in which best-estimate ranges of expected future rates of return (expected returns, net of OPEB plan invesbnent expense and inflation) are developed for each major asset dass. These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected inflation.

Financial Rep@rt

The target allocation and best estimates of geometric real rates of return for each major asset class are summarized in the following table for the valuation measurement date of January 1,:

2017 Long-Term E><pected Real Rate of Asset Class Target Allocation Return Equity (1) .............. . 70% 6.8%

Fixed Income .......... . 30% 3.6%

100% 6.1%

2016 Long-Term E><pected Real Rate of Asset Class Target Allocation Return Equity (1) .............. . 68% 6.8%

Fixed Income .......... . 32% 3.5%

100°/o 6.1 %

(1 ) The actuary included the 10% real estate alocation YAth equity.

Discount Rate 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 OPEB 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 ):

Liabii ty Net Position Liabii ty (a) (b) (a-b)

Balances at 1/1/2016 .................................................................. . $ 333,833 $ 75,224 $ 258,609 Changes for the year: .................................................................. .

Senice cost ............................................................................. 3,322 3,322 Interest .................................................................................... 20,658 20,658 Differences between elCpeC1ed and actual ellperience ................. . (203) (203)

Changes of assuJ11]1ions **.*.*.*.***.***.******.**..***..****..*..**...**.*****..** (18,807) (18,807)

Conbibulions - efl'llloyer ........................................................... 74,712 (74.712)

Net investnient income ............................................................. . 6 ,101 (6,101)

Benefit payments ..................................................................... . (13,459) (13,459)

AdmnislralNe eicpense .**********...********.*****.******.****************.********* (69) 69 Net changes ......................................................*.......................... (8,489) 67,285 (75,774)

Balances at 1/1/2017 .................................................................. . $ 325,344 $ 142,509 $ 182,835 Net position as a % d Tolal CPEB Liabiity .................................... . 43.8%

FinanciaJ1 R~p0rt 52

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 OPEB Liability to Changes in the Discount Rate The following table shows the net OPEB liability of the District, as well as what the net OPEB liability would be if it were calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1, 2017 (in OOO's):

1% Decrease Discount Rate 1% Increase Net OPEB Liability ............. ... $224,980 $182,835 $147,850 Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPEB liability of the District, as well as what the net OPEB 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% initial to 5.5%

ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 7.3% initial to 4.5% ultimate, Post-Medicare ranging from 9.1% initial to 4.5% ultimate) at the measurement date of January 1, 2017 (in OOO's):

Healthcare Cost 1% Decrease Trend Rates 1% Increase Net OPEB liabifity ................ $148,629 $182,835 $223,946 The following table shows the Total OPEB liability, Plan Fiduciary Net Position and Net OPEB liability as of January 1, 2016, and the changes during this period, based on the valuation measurement date of January 1, 2016 (in OOO's):

TotalOPEB Plan Fiduciary NetOPEB Liabiity Net Position Liability (a) (b) (a-b)

Balances at 1/1/2015 .................................................................. . $ 323,122 $ 64,487 $ 258,635 Changes for the year: ...................................................................

Seniice cost ............................................................................ . 3,228 3,228 lnlerest ................................................................ ................... . 19,877 19,877 Diffei euces between e>ipeeted and actual experience ................. . 13,657 13,657 Changes of 3SSI.ST4Jlions ........................................................... (9,149) (9,149)

Conlribulions - ffl1)1oyer ........................................................... 28,242 (28242)

Net im.esb1ell income ............................................................. . (453) 453 Benefit payrnenls ..................................................................... . (16,902) (16,902)

Adrrinislralne eJll)el'lSe ..............*.***........**..*........***.*.********.*...... (1 50) 150 Net changes ................................................................................ . 10,711 10,737 (26)

Balances at 1/1/2016 .................................................................. . $ 333,833 $ 75,224 $ 258,609 Net position as a % of Tolal OPE8 Liabiily .................................... . 22.5%

Financial Rep@rt

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

1% Decrease Discount Rate 1% Increase Net OPEB Liability .. ......... . ... . $306,681 $258,609 $219,295 Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPEB liability of the District, as well as what the net OPEB liability would be if it were calculated using healthcare cost trend rates that are 1-percentage-point lower (Pre-Medicare ranging from 7% initial to 4% ultimate, Post-Medicare ranging from 5.75% initial to 4% ultimate) or 1-percentage-point higher (Pre-Medicare ranging from 9% initial to 6% ultimate, Post-Medicare ranging from 7.75% initial to 6% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 8% initial to 5% ultimate, Post-Medicare ranging from 6.75% initial to 5% ultimate) at the measurement date of January 1, 2016 (in OOO's):

Healthcare Cost 1% Decrease Trend Rates 1% Increase Net OPEB Liability ............... . $219,672 $258,609 $306,151 OPEB Plan Fiduciary Net Position The following table shows information on the OPEB Plan Fiduciary Net Position as of December 31 , (in OOO's):

2017 2016 Assets:

Cash and cash equivalents .......................... .... .................... ................. .... . $ 3,027 $ 9,609 Receivables:

Contributions ...................................................................................... . 149 53 lnwslrnent income .......... .... ................................................................ . 451 261 lnwslrnents ........................... .... ...... .. ...................... ............................... . 173,419 132,875 Total Assets ............. ...................................................................... . 177,046 142,798 Liabilities:

Payables:

Benefits - healh care .......................................................................... . 148 128 Benefits - life insurance ...................................................................... . 33 29 lrNeStn ient ellpeflSe .**. *****.**......*...............................................*.*******.. 51 85 Tolal liabilities ................................................................................ . 232 289 Net Position - Restricted for Other Poslenl)loyment Benefits ............................ . $ 176,814 $ 142,509 Fii:namcial Rep>@rt 54

The following tables show the OPEB assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , 2017 (in OOO's):

Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total U.S. Treasury and government agency securities .. $ $ 15,956 $ $ 15,956 Corporate issues .... .. .... ..... ......... .. ... .. ..... ............ . 28,056 28,056 Foreign issues .... .. .......... ..... .............................. . 6,629 6,629 Municipal issues ... ....... ..... ............ .. .. ........ .. ......... 779 779 Domestic common stocks ....... .. .................... .. .. ... 45,678 45,678 Foreign stocks ... ....... .... ... ..... ................... ....... .... 4,002 4,002 Mutual funds ... .......... ... .... .... ......... .......... ......... ... 64,183 64,183

$113,863 $ 51 ,420 $ $ 165,283 Other investments measured at net asset value (A) . 8,136

$ 173,419 (A) The fair value of investments in a real estate fund has been estimated using the net asset value per share (or its equivalent) practical expedient and has not been dassified in the fair value hierarchy. The fund allows for quarter1y redemption with a 90-day notice. There are no unfunded commitments to the fund as of December 31 ,

2017.

The following tables show the OPEB assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , 2016 (in OOO's):

2016 Le\EI 1 Lewl2 Lewl3 Total U.S. Treasury and go\elllment agency securities .. $ $ 2,678 $ 2,678 Corporate issues ................................................ . 18,162 18,162 Foreign issues ................................................... . 5,161 5,161 M.lnicipal issues ................................................. . 766 766 DonleSlic cornrnon stocks ................................... . 39,002 39,002 Foreign stocks .................................................... 3,569 3,569 Mrtual funds ....................................................... 63,537 63,537

$106,108 $ 26,767 $ $ 132,875 D. OPEB Expense, Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB -

The Board annually approves the OPEB expense in rates and has authorized the use of regulatory accounting to equate OPEB expense with the amount in rates. OPEB expense was $16.7 milion for 2017, as cala.tlated under the GASB 75 guidance. \Mth regWltory accounting, OPEB expense and the amount included in rates was $53.3 million for 2017. This amount included a $25.0 million catch-up rate collection for the net OPEB liability for past production-level services.

Fina:ncial Repl@l1t

The following table summarizes the reported deferred outflows and deferred inflows of resources as of December 31 , 2017 (in OOO's):

Deferred Outflow Deferred Inflow Difference betv.een actual and expected experience $ 3,030 $ 16,475 Difference betv.een 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 OPES 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 $ i10,162}

OPES expense was $20.6 million for 2016, as calculated under the GASS 75 guidance. \Mth regulatory accounting, OPES expense and the amount induded in rates was $52.9 million for 2016. This amount induded a

$25 million catch-up rate collection for the net OPEB liability for past production-level services. There were no deferred inflows of resources related to OPES as of December 31, 2016 . The following table summarizes the reported deferred outflows of resources as of December 31, 201 6 (in OOO's):

2016 Difference between actual and expected experience .......................... . $ 3,769 Difference between expected and actual earnings on imestments ...... . 3,862 Contributions made during the year ended December 31, 2016 .......... . 74,658 Total Deferred Outflows ............................................................... . $ 82,289 The deferred outflows related to the contributions made during the year ended December 31 , 2016 were recognized in the actuarial valuation with a measurement date of January 1, 2017. The other deferred outflows of resources will be recognized in OPEB expense as follows (in OOO's):

Year Armunt 2017 ****** $ 1,705 2018 ..... . 1,704 2019 ..... . 1,705 2020 ..... . 1,704 2021 ..... . 739 2022 ..... . 74 Total $ 7,631 Additional information is available *n the unaudited Required Supplementary Information section following the Notes to Financial Statements.

Financia[ R~port 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 expire at various times 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 into 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 obligation pursuant to such step-up provision is limited to 160% of its original participation share (23.7%). No such default has occurred to date.

The District has entered into a participation 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 into 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 is 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 2017 for the Sheldon Station Participation Power Agreement with the termination effective December 31 ,2017.

The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately $36.3 million. These purchases are subject to rate changes.

The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition, the District has power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities *n Nebraska over similar terms.

The District has entered into a power purchase agreement with Central for the purdlase of the net power and energy produced by the Kingsley Project during its operating rite. The Kingsley Project is a hydroelectric generating unit at the Kingsley Dam in Keith County, Nebraska with an accredited net capacity of 37 MW.

The District has entered into long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO Agreements expire on various years between 2023 and 2042. These PRO Agreements obligate the District to make payments based on gross revenues from the municipailies and pay for normal property adcfrtions during the term of the agreement Financial Repm1t

C. Wholesale Power Contracts -

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 Vv'holesale Power Contracts ("2016 Contracts") with 23 public power districts, one cooperative, and 37 municipalities. One public power district and 9 municipalities are served under 2002 Vv'holesale Power Contracts ("2002 Contracts"), which expire on December 31 , 2021.

The 2016 Contracts allow a wholesale customer to give notice to reduce its purchase of demand and energy requirements from the District based on a comparison of the District's average annual wholesale power costs in a given year compared to power costs of U.S. utilities for such year listed in the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given utility can compare its power costs on a percentile basis to the CFC published quartile information. The 2016 Contracts allow a wholesale customer to reduce its demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given year is higher than the 45111 percentile level (the "Performance Standard Percentile") of the power costs of U.S. utilities for such year as listed in the CFC Data. The 2016 Contracts would not allow any reductions in demand and energy purchases by a wholesale customer as long as the District's average annual wholesale power costs percentile remained below the Performance Standard Percentile.

The following table lists the District's wholesale power costs percentile for the calendar years 2012 to 2016 set forth in the CFC Data:

CFC Data Year Percentile 2012 29.1%

2013 31.00A, 2014 27.6%

2015 31.3%

2016 28.2%

The District has ten wholesale customers remaining on the 2002 Contracts. The 2002 Contracts allow a wholesale customer to reduce its purdlases of demand and energy upon giving appropriate notice. Reductions could amount to as much as 90% of their demand and energy requirements under certain circumstances. All wholesale customers under the 2002 wholesale contracts are required to purdlase at least 10% of their demand and energy from the District through December 31, 2021.

The Disbict has received notices from all wholesale customers under the 2002 Contracts as to their intent to level off, reduce, or terminate the requirements for various amounts from 2017 through 2021. The ten customers indude one municipality which has a short-term wholesale contract which terminated in May 2016. These wholesale customers represented 4.8% and 4.5% of operating revenues for 2017 and 201 6, respectively. The Disbict expects that no requirements of said wholesale customers will be served by the District in 2022, and such wholesale customers will purchase all of their electric requirements from other suppliers. The Disbict expects to sell the energy not sold to such wholesale customers *nto the SPP Integrated Market and continues to explore additional firm requirement and/or fixed price agreements.

In 2016, three of the Disbicfs municipal wholesale customers began purdlasing power from three of the District's public power district wholesale customers. These customers represented 0.1 % of the Disbict's 2016 operating revenues. One of the District's municipal wholesale customers allowed their contract to term*nate. This customer represented less than 0.1 % of the District's 2016 operating revenues.

The 2016 wholesale rates resulted in a 0.6 % increase for wholesale customers who signed the 2016 Contracts, and a 3.8% *ncrease for those wholesale customers who remained under the 2002 Contracts. Customers under the 2002 Contracts will pay their share of previously incured OPEB costs (or the catch-up amount) through rates prior to the expiration of their contracts *n 2021 . Customers under the 2016 Contracts received a discount for the deferral of OPEB collections, extending those colections *nto the new contract period and redting in the lower Financial Re,po]t

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

Eight of the ten wholesale customers who remained under the 2002 Contracts filed for binding arbitration in May 2016 claiming the 2016 wholesale rate violates the 2002 Contracts, is contrary to Nebraska's rate statute and reflects bad faith toward those not signing the 2016 Contracts. These customers have since added the OPEB component of the 2017 wholesale rate to their dispute. The arbitration panel ruled in favor of the District in April 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 reduce 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-Time 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 into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP f Keystonee). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system. Cost of the project was

$8.4 million and repayment by Keystone, over a 10-year period, began 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, respectively.

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 recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. TransCanada Corporation and TransCanada Pipeline USA Ltd. have jointly and severally guaranteed the payment obligations of Keystone under its agreements with the District The agreement was cancelled in 2016 alter the 2012 application for a Presidential permit for construction of the Keystone XL Pipeline was denied. Al outstanding balances for Keystone XL were paid in 2016.

E. Cooper Nuclear Station -

On November 29, 2010, the NRC formally issued a certificate to the District: to commemorate the renewal of the operating license for CNS for an additional 20 years until January 18, 2034. CNS entered the 20-year period of extended operation on January 18, 2014.

In October 2003 , the District 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 additional 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 NRG Near Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12, 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report, on October 18, 2011 , the NRG approved seven of the Task Force recommendations for implementation.

On March 12, 2012, the NRG issued three orders to the U.S. nudear industry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nudear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nudear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened containment wetwell vents. The third order requires nudear plant operators to add reliable spent fuel pool water level instrumentation. The NRC has also issued a request for information pertaining to re-evaluation of seismic and flooding hazards, and a communications and staffing assessment for emergency preparedness.

Phase one and phase three of said order have been completed. Phase two of said order, which 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 reevaluation analysis for CNS that resulted in no identified seismic-related modifications to CNS, the District has performed an additional seismic analysis and has worked to answer additional questions from the NRG on this topic. The NRC has determined that CNS will have to perform the High Frequency Evaluation and a Spent Fuel Pool Evaluation, but will not have to complete a Seismic Probabilistic Risk Assessment Unknown to the District at this time is the extent of modifications that may be required as a result of these additional seismic reevaluations.

The District continues to work with the U.S. Anny Corps of Engineers and the NRG to validate the data necessary to complete the CNS flood hazard reevaluation. The District submitted its updated flooding analysis to the NRC *n February 2015. The NRG subsequently submitted questions to which the Disbict has responded and submittal of the updated flood hazard reevaluation was completed *n September 2016. Based on rurrent interim, and long-term strategies for flooding mitigation, it is not expected that any modifications will be required as a result of the flood hazard reevaluations. All equipment and materials required to mitigate the identified impacts associated with the flood hazard reevaluation have been flldlased and the equipment required has been installed. Additional equipment purchased, but not required to be "nstalled unless an issue occurs, is stored on-site *n dedicated storage facilities.

The District's cost estimate for plant mo<<ifications associated with the NRC's Fukushima Dai-ichi related orders is rurrently estimated to cost $23.3 rmllion, which is expected to be funded primarily from the revenues of the Disbid and from the proceeds of General Revenue Bonds. As of December 31, 2017, $ 17.3 milion has been spent on Financial Report

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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 construction of a dry cask used fuel storage project in December 2009 to support plant operations until 2034, which is the end of the Operating License. The first loading campaign was completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool into eight dry used fuel storage casks for on-site storage. A second loading campaign , encompassing the loading of 610 used fuel assemblies into ten dry used fuel storage casks , began in April 2014 and was completed in June 2014. The third loading campaign , encompassing the loading of 732 used fuel assemblies into 12 dry used fuel storage casks, began in June 2017 and was completed in November 2017.

As part of various disputed matters between GE and the District, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility. After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.

As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 2001 . The initial settlement agreement addressed future claims through 2013. On January 13, 2014, the District and the DOE agreed to extend the settlement agreement through 2016. On March 2, 2017, the District and the DOE agreed to extend the settlement agreement through 2019. The District has received $118.2 million from the DOE for damages from 2009 through 2016. The District also reserves the right to pursue future damages through the contract claims process. A corresponding regulatory liability for these DOE receipts was established in Other deferred inflows of resources. The District plans to use the funds to pay for costs related to CNS. The balance in the regulatory liability was $66.2 million and $82.7 million as of December 31 , 201 7 and 2016, respectively.

Under the terms of the DOE contracts, the District was also subject to a one mill per kilowatt-hour ("k\1\/h") fee on all energy generated and sold by CNS which was paid on a quarter1y basis to DOE. The District includes a component in its wholesale and retail rates for the purpose of funding the costs associated with nuclear fuel disposal. \1\/hile the District expects that the revenues developed therefrom will be sufficient to cover the District's responsibility for costs currently outlined in the Nuclear Waste Policy Ad, the District can give no assurance that such revenues will be sufficient to cover all costs associated with the disposal of used nuclear fuel. On May 9, 2014, the DOE provided notice that they would adjust the spent fuel disposal fee to zero mills per k\1\/h effective May 16, 2014. Correspondingly, no additional payments have been made to the DOE for fuel disposal since that date. The Board authorized the continued collection of this fee at the same rate. This approadl ensures costs are recognized in the appropriate period with current customers receiving the benefits from CNS paying the appropriate costs. The expense for spent nuclear fuel disposal is recorded based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal.

Under the provisions of the Federal Price Anderson Act, the District and all other licensed nuclear power plant operators could each be assessed for claims in amounts up to $127.3 million per unit owned in the event of any nudear incident involving any licensed facility in the nation, with a maximum assessment of $19.0 million per year per incident per unit owned.

The NRC evaluates nuclear plant performance as part of its reactor oversight process r ROP"). The NRC has five performance categories included in the ROP Action Matrix Summary that is part of this process. As of December 31, 2017, CNS was in the Licensee Response Column, which is the first or best of the five NRC defined performance categories and has been in this column since the first quarter of 2012.

Refueling and maintenance outages are required to be performed at CNS approximately every two years. The most recent refueling and maintenance outage began on September 25, 2016 and was completed on November 8, 2016. During this outage, in addition to replacing 184 fuel assemblies and conducting routine maintenance, equipment replacements included one of the two reactor water recirrulalion punp impelers and motor, the startup station transformer and the high pressure turbine.

Financial R~JlOlit

Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs, commencing in 2017. The regulatory liability for the pre-collection of outage costs was $20.0 million as of December 31 , 2017 and will be eliminated through revenue recognition during the 2018 outage year.

F. Environmental-Water The Federal Clean Water Act contains requirements with respect to effluent limitations relating to the discharge of any pollutant and to the environmental impact of cooling water intake structures. The NDEQ establishes the requirements for the District's compliance with the Clean Water Act through issuance of National Pollutant Discharge Elimination System permits. NDEQ issued the District permits for the following facilities: GGS, Sheldon, CNS, Beatrice Power Station, Canaday Station, Kearney Hydro and the North Platte Office Building. The District anticipates some level of fish protection equipment technology installation, both for impingement and entrainment, may be necessary for CNS and only for impingement at GGS. Until the final compliance options are determined, the District does not know the financial impact of this regulation.

On January 2, 2016, the final Steam Electric Power Plant Effluent Guidelines rule (the "Effluent Rule") became effective. The Effluent Rule revises the technology-based effluent limitation guidelines and standards that would strengthen the existing controls on discharges from steam electric power plants and sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. Generally, the Effluent Rule establishes new or additional requirements for wastewater streams from the following processes and byproducts associated with steam electric power generation: flue gas desulfurization, fly ash, bottom ash, flue gas mercury control , and gasification of fuels such as coal and petroleum coke. While the District facilities subject to the Effluent Rule are CNS, GGS, Sheldon and Canaday Station, the Effluent Rule only has an impact on Sheldon.

Sheldon will be required to be a zero discharge facility for bottom ash transport water by December 31 , 2023. The District is currently analyzing the options for compliance, which is estimated to cost $2.4 million. EPA has listed this rule as one they will consider for regulatory reform and the requirements may be subject to change.

Acid Rain Program The Clean Air Act Amendments Title IV established a regulatory program, known as the Acid Rain Program, to address the effects of acid rain and impose restrictions on sulfur dioxide fS02*) and nitrogen oxides r Nox*)

emissions. Acid Rain Permits have been issued for the following facilities: GGS, Sheldon, Canaday Station and Beatrice Power Station. The Acid Rain Permits allow for the discharge of S02 at each facility pursuant to an allowance system. The District expects to have sufficient allowances for its generating facilities through 2023, but may be required to purchase additional allowances in the future.

Mercury and Air Toxic Standards On February 16, 2012, the EPA issued a final rule intended to reduce emissions of toxic air pollutants from power plants. Specifically, the Mercury and Air Toxics Standards rMATS1 Rule will require reductions in emissions from new and existing coal- and oil-fired steam utility electric generating units of toxic air pollutants. The affected District facilities, which are GGS and Sheldon, are in compliance with the MATS Rule.

Cross-State Air Pollution Rule The EPA issued a rule in 2012 which is referred to as the Cross-State Air Pollution Rule r cSAPRm) that would require significant reductions in S02 and NOx emissions in a number of states, induding Nebraska CSAPR compliance periods went into effect on January 1, 2015. Based on the current CSAPR allocation methodology and current generation projections through 2023, the District expects to have sufficient CSAPR allowances to cover affected facilities emission requirements over that timeframe, but may be required to purchase additional allowances in the future.

Regional Haze The EPA issued final regulations for a Regional Haze Program *n JlMle 1999. The purpose of the regulations is to improve visibility in the form of reducing regional haze in 156 national parks and wilderness areas across the country. Haze is formed, *n part from emissions of SOiand NOx.

Financial R~p@rt 62

For phase one of the Reg ional 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 ind uding 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 sdleduled. 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 future financial obligation with respect to the NOV.

On July 22, 2016, EPA Region 7 sent a new 114(a) request for documents and information 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 in, or could result in, inaeased emissions including projects underway or planned for the next two years. The District gathered documents and information and provided it to the EPA. Failure to comply with the Clean Air Act can result in fines as desaibed above and/or requirements to install additional emission control equipment. The Disbict believes GGS has been operated and maintained in compliance with the requirements of the a ean Air Act..

aean Power Plan On October 23, 2015, the EPA published the final a ean Power Plan r cPPj rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determining how to achieve the reduction targets through the development of a State Plan. Each state was given a reduction target to be achieved by 2030, with interim reductions reqt.ired between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 emissions. On February 9, 2016, the U.S. Supreme Court issued a stay for the CPP until all legal challenges have been decided. The D.C. CiraJit Court of Appeals heard oral argtments on September 27, 2016 and a decision was expected in early 2017. Prior to the Court issuing a decision, the EPA asked the Court to hold the legal process in abeyance while the EPA worked to repeal and replace the CPP.

Financial Repont

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 District'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, 201 7. Following the expiration, both parties have negotiated an agreement for the sale and purchase of the Spencer facility. It was distributed to the Alliance and NGPC in December 2017 for 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 increase 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 is discriminatory and an unjust and unreasonable cost shift to the District. On February 23, 2017, the administrative law judge issued an initial decision upholding the SPP pricing zone placement and made recommended condusions to FERC. This initial decision has no legal effect until reviewed and acted upon by FERC which will be after the District submits briefs on its exception to the factual and legal condusions in the initial decision. FERC's future ruling on the initial decision can be appealed to a federal circuit court of appeals. When FERC will rule on the initial decision cannot be predicted.

Information on litigation with wholesale customers under the 2002 Contracts is induded in Note 12.C.

A number of daims and suits are pending against the District for alleged damages to persons and property and for other alleged liabilities arising out of matters usually incidental to the operation of a utility, such as the District.

In the opinion of management, based upon the advice of its General Counsel, the aggregate amounts recoverable from the District, taking into account estimated amounts provided in the financial statements and insurance coverage, are not material as of December 31 , 2017 and 2016.

14. SUBSEQUENT EVENTS:

In 2017, the Nebraska Department of Revenue r NDOR"') conducted a sales and use tax audit on the Districfs records for the audit period of June 1, 2014 through May 31 , 2017. NOOR issued a Notice of Deficiency Detenn"nation r 0etennination"') to the District for approximately $6.5 milion, including interest and penalties of over $1.0 milion, on January 30, 2018. Beyond the minor sales and use tax corrections contained in a normal audit Determination, the NOOR assessed almost $5.5 milion of tax on the payments to municipalities ooder PRO Agreements. The District disagrees with the NDOR's assessment and filed a Petition for Redetermination to formally challenge the Determ*nation on Mardi 29, 2018.

Ffoanoial Rr pomt 64

SUPPLEMENTAL SCHEDULES (UNAUDITED)

Calculation of Debt Service Ratios in accordance wth the General Revenue Bond Resolution for the years ended December 31 , (in OOO's) 2017 2016 Operating revenues ..... ................ .... .. .... .... .............. .. .... ........ ............ .... ........ . . $ 1,101,642 $ 1,153,997 Operating expenses .. ... .... .... .. ...... .... .... ...... ....... ............................... .... .......... . (988,931) (1,040,715)

Operating income .... .............. ...... .... ....... ....... ..... ... .. .................................. . 11 2,711 113,282 Investment and other income .... ...... ..... ... .. ....... .. .. .. ... .... ........ .. .... .... ....... ..... .... . 23,591 31 ,772 Debt and other expenses ..... .... .... .................... ...... ............. ..... ...... .. ....... ... ..... . (64,986) (62,121)

Increase in net position ................................... ..... ... ... .... .. ......... ................ . 71 ,316 82,933 Add:

Debt and related expensesc11 .*..*...... . .. . .. . . . .* .. ............. ... .. .. .. ...... .... ....... . .... . .. 64,986 62,121 21 Depreciation and amortizationc * ....*... ** . *. *..*. ..*.. . *...*.......*.... . ..**. .. .. . . .. ...* . .**.* 122,559 133,666 3

Payments to retail comrrunitiesCJ ............ ..... .. ....... .......... ......... ....... .. ......... . 27,102 26,553 Amortization of current portion of financed nuclear fuef'1 ... .. ....... .. .. . . .... .. .. ... . 42,198 39,468 Amounts colected from third party financing arrangementses1 . .. ...... . . . .. .. ... .... . 938 991 257,783 262,799 Deduct I n ~ income retained in construction fundsC*J ... ... ........ ... ...... .... .... ...... . 645 354 U-.realized (loss) gain on in~ securities ............................................ . (2,595) 43 (1 ,950) 397 Net position available for debt seNce for the General Re\el'lue Bond Resolution .. $ 331 ,049 $ 345,335 Amounts deposited in the General System Debt Service Account Principal .. ...................... .......... ..... ......... .................. ................................. . $ 84,125 $ 101 ,135 Interest ..................................................................................................... . 71 ,198 72,959

$ 155,323 $ 174,094 Ratio of net position available for debt seNce to debt seNce deposits ............... . 2.13 1.98 (1) Debt and other expenses, exdusive of interest on wstomer deposits, is not an operating expense as defined in the Resolution.

(2) Depreciation and amortization are not operating expenses as defined in the Resolution.

(3) Under" the provisions of the Resolution, the payments required to be made by the District with respect to the Professional Retail Operating Agreements are to be made on the same basis as subordinated debL (4) General Revenue Bond financed nuclear fuel is not an operating expense as defined in the Resolution. As of July 31 , 2015, the effective date of the T axab1e Revolving Credit Agreement, amortization of nudear fuel expense under" the TRCA is exchled from the debt service calculation as the Oislricfs obligation to make payments under" the TRCA is subordinate to the Oislricfs obligation to pay debt service on General Revenue Bonds.

(5) The payments received by the District from Ihm party financing arrangements are inchled as Revenues under" the Resolution, but are not recogrRed as revenue under" GAAP.

(6) Interest income on investments held in mnstrudion funds is not Revenue as defined in the Resolution.

Financia[ Report

Schedule of Changes in the Net OPEB Liability and Related Ratios using a January 1 Measurement Date (in OOO's)

Total OPEB Liability 2017 2016 Service Cost .. .... ... ..... ......... ... .... .. ....... .... .. ......... .. ... ...... .... ...... ......... ..... ...... .. .... ... .......... .... . $ 3,322 $ 3,229 Interest ..... ... ..... ... .... ......... .... .... .. ..... ....... ........ ..... ..... ......... ..... .... ... .... ... .... ..... ........ .... ...... .. . 20,658 19,876 Differences Between Expected and Actual Experiences ......... ...... ..... ............ ..... ..... .... .... .... ... . (203) 13,657 Changes of Assumptions .. ...... ... .. ... .... ........... ... .. ... ... .... ... .... ....... .. ...... ... ........... ...... ....... .. .. .. . (18,807) (9,149)

Benefit Payments..... .. .... ....... ... ... ...... ...... ...... .... ......... .. ........... .. ... .... ...... .. ...... ........ .. .. .. ....... . (13,459} (16,902}

Net Change in Total OPEB Liability ...... ..... .. ...... ... .. ........ .. ......... ..... ............. ........ ............. .... . . (8,489) 10,711 Total OPEB Liability (beginning) .... ... ... ............ ......... ....... .... .... .. ....... ... ...... ................ .. ......... . 333,833 323,122 Total OPEB Liability (ending) (a) .... .. ............ ....... ..... ... ............ .... ... .... .. ..... ............ ... ........ .... . $325,344 $333,833 Plan Fiduciary Net Position Contributions c11 . . . . . .. . *. ... .. .. . .... . *.......... . . .. . .. . ... . . .. . . .. . . . . .. .. . . . . . . . .... .. .. . . . .. . . . . .... . .. . . . . . . .. . ... .. .. . * . . . . . $ 74,711 $ 28,242 Net ln..estrnent Income.......... ......... ....... .... .......... ... ... .... ....... ... ... .. ..... ..... .... .. .... .... ... ....... ..... . 6,102 (453)

Benefit Payments c11 . . . .... .. . . . . .. .. . . .. . . .. . . . . . . . . . . .. ...... . . ... . . .. .* . . *.. . . .. .. .. . . .. . *. .... . .. . . ... . . ..... . . . ..*.. ... ....* (13,459) (16,902)

Administrati..e Expense... ...... ........ .... .... .. ...... .. ....... ...... .... ....... .. ... ... ........ .............. ... ... ........ . . (69} (150}

Net Change in Plan Fiduciary Net Position .. ... ........ .... ........ ... .............. ...... .................. ...... ... . . 67,285 10,737 Plan Fiduciary Net Position (Beginning) ........... ................................. ......... ... .......... ..... ... ...... . 75,224 64,487 Plan Fiduciary Net Position (Ending) (b) ....... .......... .............................. ... ... ... .... ... ... ... ........... $142,509 $ 75,224 Net OPEB Liability (Ending) (a) - (b) .... .... ......................................... ....... .................. ........ .. . $182,835 $258,609 Net Position as a % of Total OPEB Liability ....... ... ................ ......... .... .. ........ ... ...... ....... .......... . 43.8% 22.5%

(1) Contributions are ~ yer-only contributions. lnacti..e meniJer contributions v.ere netted wlh benefit payments.

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.

Fi,]la]loia1 Re,polit 66

Schedule of OPES Contributions for Years Ended December 31 , (in OOO's) 2017 2016 Actuarially Determined Contribution .. ..... ...... .. .. .......... ...... .. ..... ... ... ...... .. ........ .... . $ 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 -

Actuarial cost method . . . .. . . . .. . . .. Entry Age Normal Amortization method .. . . . . . ... .. .. . Le\tel amortization of the unfunded accrued liability Amortization period . .. . . . . . . . . . . .. . . 1~year closed period Asset valuation method .. . .. . .. . . .. 5-year smoothed market Discount rate . .... .. .. .. . . . ... .. .. .. .. . 6.25%

Healthcare cost trend rates .. ... . Pre-Medicare: 7.3% initial, ultimate 4.5%

Post-Medicare: 9.1% initial, ultimate 4.5%

Inflation .............................. .... 2.1%

ln\teStment rate of return ....... ... 6.25%, net of investment e~nse, including inflation Mortaity ....... . ..... .. .. . . .. .. . . .. .. ... . RP-2014 Aggregate table projected back to 2006 using Scale M>-2014 and projected forward using Scale M>-2016 vlilh generational projection Retirement age ..................... .. Varies by age Methods and assumptions used for 2016-Actuarial cost method . . . . .. .. .. .... Entry Age Normal Amortization method ... . . .. . ....... Le\tel amortization of the unfunded accrued liabitity Amortization period .... ............. 17-year closed period Asset valuation method .. .. . . .. .. .. 5-year smoothed market Discount rate ... .. .... ... .. . ....... .. .. 6.25%

Healhcare cost trend rates ..... . Pre-Medicare: 8% initial, ulimate 5%

Post-Medicare: 6.75% initial, ulimate 5%

Inflation ........ ... .................. .. ... 2.1%

lme;tment rate of return ......... . 6.25%, net of imestment e>cpense, including inflation Mortaity ................................. RP-2014 Aggregate table projected back to 2006 using Scale M>-2014 and projected forward using Scale M>-2015 vlilh generational projection Retirement age ..................... .. Va-ies by age Schedule of lnvesbnent Returns for Years Ended December 31 ,

2017 2016 Annual Money-Weighted Rate of Return, Net of rrnestment Expense ............... . 14.2% 5.8%

GASB Statement No. 75, Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans, was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods, as it was not 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.

Financial} RreFJ<!rnt

Mission 76 049

NLS2018032, Nebraska Public Power District 2017 Financial Report

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