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Text

Licensee Guarantees of Payment of Deferred Premiums
	ML17206A198
Person / Time
Site:	Cooper
Issue date:	07/18/2017
From:	Shaw J; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2017062
	Download: ML17206A198 (57)
	v • d • e

NLS2017062 July 18 , 2017 H Nebraska Public Power District Always there w h en you need us Attention:

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

Subject:

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

Dear Sir or Madam:

140.2 1 The purpose of this letter is to transmit information in accordance with the requirements of 10 CFR Part 140.21 , relative to deferred insurance premiums , for the Nebraska Public Power District (NPPD). NPPD believes this information demonstrates our ability to obtain funds in the amount of $19.0 million for payment of such premiums within the specified three-month period. To demonstrate the ability to provide funds in the required amount for such deferred insurance premiums, NPPD's 2016 Financial Report is enclosed for your review. This report is NPPD's audited financial statement.

Please refer to Page 30 of the enclosure where the Balance Sheet of NPPD is listed. Cash and investments of NPPD total over $1.2 billion as indicated on Page 3 7, Note 2 of the enclosure.

Liquidity can be provided by unrestricted cash and investments, and through reserve and special purpose funds that , with the approval of the NPPD Board of Directors , can be utilized for any lawful purpose. The portion of cash and in v estments that can be utilized to provide such liquidity for the payment of the subject deferred premiums is $527.3 million as of December 31 , 2016. Also on Page 30 of the enclosure , under the heading " Current Liabilities

," there is a line item titled " Notes and credit agreements , current" in the amount of $74.0 million, and under the heading " Long-Term Debt," there is a line item titled " Notes and credit agreement, net of current" in the amount of $188.9 million. As noted on Pages 43-45 , Note 7, "Commercial Paper Notes" and " Taxable Revolving Credit Agreement" of the enclosure, NPPD is authorized to issue up to $150 million of tax-exempt commercial paper notes (TECP), and an aggregate of $200 million of the Taxable Revolving Credit Agreement.

As of December 31 , 2016 , NPPD had $76.0 million remaining capacity in its TECP program , and $11.1 million remaining capacity of the Taxable Revolving Credit Agreement, for a total of $87.1 million, which is available to fund the payment of the subject deferred premiums.

COOPER NUCLEAR STATION P.O. Box 98 /Brownville, NE 68321*0098 Telephone: (402) 825-3811 /Fax: (402) 825-5211 www.n ppd.co m NLS2017062 Page 2 of2 Effective June 29 , 2017 , NPPD terminated its TECP program and replaced it with a Tax-Exempt Revolving Credit Agreement, of which NPPD is authorized to issue up to $150 million. As with the TECP program , the remaining capacity of the Tax-Exempt Revolving Credit Agreement will be available to fund the payment of the subject deferred premiums. As of June 30 , 2017 , this amount was $81.0 million. It is NPPD's intent to continue to publish this report on an annual calendar year basis. A subsequent report , covering financial information for calendar year 2017 , will be submitted no later than July 31 , 2018. This letter contains no new commitments.

Should you have questions or require additional information , please contact me at 402-825-2788. Sincerely , Licensing Manager /jo

Enclosure:

Nebraska Public Power District 2016 Financial Report cc: Regional Administrator w/enclosure USNRC -Region IV Cooper Project Manager w/enclosure USNRC -NRR Plant Licensing Branch IV Senior Resident Inspector w/o enclosure USNRC-CNS NPG Distribution w/o enclosure D. K. Starzec w/o enclosure CNS Records w/enclosure NLS2017062 Enclosure ENCLOSURE NEBRASKA PUBLIC POWER DISTRICT 2016 FINANCIAL REPORT COOPER NUCLEAR STATION DOCKET NO. 50-298, DPR-46 FINANCIAL REPORT of the 2016 Nebraska Public Power District Statistical Review (Unaudited) 13 Management's Discussion and Analysis (Unaudited) 14 Report of Independent Auditors 29 Financial Statements 30 Notes to Financial Statements 33 Supplemental Schedules (Unaudited) 62 2016 YEAR AT A GLANCE KILOWATT*

HOUR SALES 18.9 B I LLION OPERATING REVENUES $ 1,154.0 MILLION COST OF POWER PURCHASED AND GENERATED

$ 635.2 MILLION OTHER OPERATING EXPENSES $ 405.5 MILLION INVESTMENT AND OTHER INCOME $ 31.7 MILLION DEBT AND OTHER EXPENSES $ 62.1 MILLION INCREASE IN NET POSITION $ 82.9 MILLION DEBT SERVICE COVERAGE 1.98 TIMES Fi n ancial Report 12 2016 STATISTICAL REVIEW (Unaudited)

A-.erage Cents Pe r kWh Sold A-.er age A-.erage Less Go-.emment Cents Per Number of MWh OPERATING REVENUES Taxes/T r ansfers (1 l kWh So ld Customers Amount % Reta il: Residential

..................... . 10.77 ¢ 12.79 ¢ 71 , 868 818 , 305 4.3 Commercial

.................... . 8.50 ¢ 9.88 ¢ 19 , 530 1 , 131 , 223 6.0 Industri a l ..................

...... . 5.57 ¢ 5.93 ¢ 59 1 , 277 , 557 6.8 Total Re tail S ales ......... . 7.91 ¢ 9.05 ¢ 91,457 3 , 227 , 085 17.1 ------Wholesale: Mu n ici pal ities c 21 ........................................

6.26 ¢ 46 1 , 868 , 510 9.9 Public Po wer D istricts and Cooperati-.es

<21 .. 5.85 ¢ 25 7 , 806 , 394 41.3 Total F i rm Wholesale Sales....................

5.93 ¢ 71 9 , 674 , 904 51.2 Total Firm Retail and Who l esale Sales.. 6.71 ¢ 91 , 528 12 , 901 , 989 68.3 Part icip a ti on Sa l es......................

.................. 4.05 ¢ 5 1 , 926 , 845 10.2 Other Sales<3 J ...............................................

2.20 ¢ 2 4 , 073 , 339 21.5 Tota l Electric Ene rgy Sales...............

... 5.47 ¢ 91 , 535 18 , 902 ,1 73 100.0 Othe r Operat ing .....................................................

...........

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

...... . Unearned Re-.e nues csi ...........

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

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

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

... . Total Operating Re-.enues

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

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

....................................................................... . MWh COST OF POWER PURCHASED AND GENERA TED Amoun t % Produ cti on c 6 J .........................................

................................................... . 14,787 , 399 75.2 Power Purchased

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

.................................... . 4 , 864 , 394 24.8 Total Product i on and Power Pur chased ................................................. .. 19 , 651,793 100.0 CONTRACTUAL AND TAX PAYME N TS (in OOO's) (1 l Pa ymen ts to Retail Communities

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

... .. Payments i n Lieu of Taxes .................

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

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

....... . Total Contractual and Tax Pa yments ......................................................................................

.. OTHER Mi les of Transmission and Subtransmiss i on Lines in Service ......................................................... . Number of Fu ll-Time Employ ees .................

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

........ .. (1) Customer collections for taxes/transfers to othe r governments are excluded from base rates. (2) Sales are total requ ire ments , subject to certain exceptions. (3) Includes sales i n the Southwest Power Pool (" SPP") and nonfirm sales to other utilities. (4) Includes revenues for transmission and other miscellaneous revenues.

Re-.enues (in OOO's) A mo unt % $ 104 , 642 9.1 111 , 7 22 9.7 75 , 777 6.5 292 , 141 25.3 116,906 10.1 456 , 614 39.6 573 , 520 49.7 865 , 661 75.0 77 , 996 6.8 89,492 7.7 1 , 033 , 149 89.5 66 , 060 5.7 54 , 788 4.8 $1 , 153 , 997 100.0 Costs (in OOO's) Amoun t % $ 458 , 122 72.1 177 , 121 27.9 $ 635 , 243 100.0 Amo unt $ 26 , 553 10,064 $ 36 , 617 Amoun t 5 , 267 1 , 966 (5) Incl udes unearned revenues from prior periods of $17.4 mill ion, 2016 surplus revenues deferred to future periods of $10.0 million , recogn ize d revenues of $24.7 million for the 2016 Cooper Nuclear Station (" CNS") refueling and maintenance outage, and recognized revenues of $22.7 million for OPEB expenses related to past service and included i n 2016 rates. (6) Includ es fuel , operation , and maintenance costs. Debt service and capital-related costs are excluded. SOURCES OF THE DISTRICT'S ENERGY SUPPLY (%OF MWH) This chart shows the sources of energy for sales , excluding part i cipat i on sales to other utilities. Purchases were incl uded i n the appropr i ate source , except for those purchases for which the source was not known. 13 Financial Report 48.0% Wind Hydro 6.8%

Purchases 4.5% 1.5%

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

The financ i a l report for t he Nebraska Pub li c Power D i str i ct (" Distr i c t") i ncludes this Management's Discuss i on and Analys i s , Financ i a l Sta t ements , Notes to Fina n cial S t a t ements and Supp l emental Schedu l es. The financia l statements consis t of the Ba l ance Sheets , Statemen t s of Revenues , Expenses , and Changes in Ne t Pos i t i on , Statements of Cash Flows , and Supplemental Schedules. The following Management's D i scussion and Analys i s (" MD&A") prov i des unaud i ted information and ana l yses of a ct i v i t i es and events re l ated t o t he Dist ri c t's finan ci al pos i t i on or resul t s of operat i ons. The MD&A should be read i n conjunc ti on w i th the audited F i nancial Statements and Notes to F i nancial Statements. The Balance Sheets presen t assets , deferred outflows of r esources , liabilities , deferred i nflows of resour c es a n d net position as of December 31 , 2016 and 2015. T he S t atements of Revenues , Expenses , and Changes in Net Pos i t i on present the operating results fo r the years 20 1 6 and 2015. The Statements of Cash Flows present the sources and uses of cash and cash equ i va l ents for the years 2016 and 2015. The Notes to Financial Statements are an integral part of the basic financ i a l statements and conta i n informat i on for a more complete understand i ng o f the financ i al position as of December 31 , 2016 and 2015 , and the results of operations for the years 2016 and 2015. The S u pplemental Schedules include unaudited i nformation required to accompany the Financ i al Statements. OVERVIEW OF BUSINESS The District is a public corpora ti on and po li t i cal subdivis i on of the State of Nebraska (the " State"). Control of the Dist ri ct and i ts operat i ons are ves t ed in a Board of Directors

(" Board") consist i ng of 11 members popularly e l ected from dis t r i cts comprising subd i v i s i ons of the D i s t ric t's chartered territory. The D i strict's chartered territory i ncludes all or parts of 86 of the State's 93 count i es and more than 400 municipalities in the State. The r i ght to vote for the Board i s generally l i mited to retail and wholesale customers rece i ving more than 50% of the i r annual energy from the Distric t. The Distr i ct operates an i ntegrated electr i c u tility system i ncluding facilit i es for generat i on , transmission , and d i str i bution of electr i c power and energy for sales at reta i l and wholesale. Management and operation of t he D i str i ct is accomplished w i th a s t aff of approx i mately 1 , 960 full-t i me employees. The D i strict has the power , among other t hings , to acqu i re , construct , and ope r ate generating p l ants , transmission lines, substations , and distribut i on systems and to purchase , genera t e , distribute , t ransmit , and sell electric energy for all purposes. There are no i nvestor-owned util i t i es provid i ng reta il e l ectr i c service in Nebraska. The D istrict has no power of taxat i on , and no governmental authority has the power to levy or collect taxes to pay , in whole or i n part , any indebtedness or obligation of or incurred by the D i strict or upon which the D i strict may be liable. The Distr i ct has the r i ght of em i nent domain. The property of the Distr i ct , i n the opinion of its Genera l Counsel , is exempt under the State Constitution from taxat i on by the State and its subd i v i sions , but the District i s required by the State to make payments i n li eu of taxes wh i ch are distributed to the State and var i o u s governmental subdivis i ons. The D istrict has the power and is required to fix , establ i sh , and collect adequate rates and other charges f or electr i cal energy and any and all commodit i es o r serv i ces sold o r furn i shed by it. Such rates and charges must be fair , reasonab l e , and nond i scr i minatory and ad j usted in a fair and equ i tab l e manner to confer upon and distribute among the users and consumers of such commod i t i es and services the benefits of a successfu l and profitab l e operation and conduct of the bus i ness of the Distric t. THE SYSTEM To meet the anytime peak load in 2016 of 2 , 963.7 megawatts

(" MW"), the District had available 3 , 638.2 MW of capac i ty resources that included 3 , 033.3 MW of generation capacity from 12 owned and operated generating plants and 22 plants over which the D i strict has operating control , 447.7 MW of firm capacity purchases from the Western Area Power Admin i stration , and 157 .2 MW of a capacity purchase from Omaha Pub l ic Power Distric t's Financial Report 14

(" OPPD") Neb r aska C i ty S t at i on U n it 2 (" NC2") c oal-fired p l ant. Of the total capacity resources , 223.7 M W are being sold via participat i on sales or other capacity sales agreements , leaving 3,414.5 MW to serve firm retail and wholesale customers and to meet capacity reserve requirements. The h i ghest summer anytime peak l oad of 3 , 030.3 MW was establ i shed in Ju l y 2012 and the highest winter anytime peak load of 2 , 252.0 MW was established in January 2014 for firm requ i rements customers. The follow i ng table shows the Distr i ct's capacity resources from generation and respective summer 2016 accredited capability. Number of T y pe Plants (1) S t eam -Con-.ent i onal C 3 l *******..********************************.* 3 Steam -N u clear ..................................................... . Combined Cycle ....................

................................. . Combust i on Turbine c 4 l ........................................... . 3 Hydro ...............................................

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

....... . 6 D i esel .....................................................

.............. . 12 W i nd csl ...................................

.............................. . 8 34 (1) Includes three hydro plants an d 12 di e s e l p l a nts un de r contract t o the D istrict. (2) 2016 s umme r accr e dited n e t capability b ase d on SPP criteria. Summer 2016 Accred it ed Capability (MW) (2> 1 , 674.0 765.0 220.0 125.3 110.7 91.5 46.8 3 , 033.3 (3) Includ e s G erald G entleman St ati o n (" GGS"), S heldo n S tation (" S he l don"), an d Can a day S tati o n (" Canaday"). (4) Includes the H a ll a m , Hebron a nd McC oo k pe akin g tu rb ines. (5) Inclu de s A insw orth W i nd Energy F ac i lity (" A i n sworth") a nd seven wind facilitie s und e r contr a ct to the D istrict. Percent of T otal 55.2 25.2 7.3 4.1 3.7 3.0 1.5 100.0 The following tab l e shows the generation facilities owned by the D i str i ct and the i r respective f u el types , summer 2016 accred i ted capabi li ty , and in-service dates. Type Gera l d Gentleman Stat i on Un i t s No. 1 and No. 2 ....... . Cooper Nuclear Stat i on .................

.......................... . Beatrice Power Station ........................................... . Sheldon Station Units No. 1 and No. 2 ..................... . Combustion Turb i nes (3 generating plan t s) ............... . Canaday Station .................................................... . Hydro (3 generat i ng plants) ..................................... . A i ns w orth W i nd Energy Facility<2l ........................... . (1) 2016 s ummer accre d ited net capability based on S P P cri t er i a. (2) Nomin a lly rated at 60 MW. Fue l Type Coa l N u c l ear Comb i ned Cycle Coal Oil or Natural Gas Natural Gas Water W i nd T HE C U STO M ERS Retail and Who l esale Customers Summer 2016 Accredited Capab i lity (MW) (1> 1 , 365.0 765.0 220.0 215.0 1 25.3 94.0 25.2 10.1 2 , 819.6 In-Ser.ice Date 1 979 , 1982 1974 2005 1961 , 1968 1973 1958 1887 , 1927 , 1 93 9 2005 In 2016 , the District served an average of 91,457 reta i l customers. Currently the District's reta i l serv i ce territory includes 80 municipalities , of wh i ch 79 are municipal-owned d i stribution systems operated by the D i str i ct for the munic i pal i ty pu r suant to a Profess i ona l Retail Operations

(" PRO") Agreement.

Details of the District's PRO Agreements are included i n Note 12 in the Notes to Financial Statements. 15 FIMndal Report The Distr i ct serves i ts 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 i nto 20-year wholesale power sales contracts with a substantial number of i ts wholesale customers (the '2016 Contracts"). The 2016 Contracts replaced wholesale contracts that were entered into in 2002 {the " 2002 Contracts"). Wholesa l e customers served under the 2016 Contracts include 23 public power districts (20 of which are served under one contract with the Nebraska Generation and Transmission Cooperative), one cooperative , and 37 municipal i ties. Wholesale customers served under the 2002 Contracts i n clude one public power district and nine municipalities. The District's goal , with respect to t he cost of wholesale service (product i on and transmission), is that such costs are among the lowest quartile (25 th percentile or less) for cost per kilowatt-hour

(" kWh") purchased , as published by the National Rural Utilities Coopera t ive Finance Corporation Key Ratio Trend Analys i s (Ratio 88) (the " CFC Data"). The D istrict's wholesale power costs percen t ile was 31.3% for 2015 , based on the latest available data. Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements. The fo ll owing charts show the District's average retail and wholesale cents per kWh for the years ended December 31 , 2012 through 2016. The District also reported average cents per kWh sold less customer co l lections for taxes and transfers to o t her governments , which are not i ncluded in the District's base r ates for retail customers.

AVERAGE CENTS PER kWh SOLD -RETAIL (Retail -All Classe s) 9.80 9.04¢ 9.06¢ 9.12¢ 9.05¢ 7.9 1 7.65¢ 5.80 2012 2013 201 4 2015 2016 Average Cents per kWh Sold Average Cents per kWh Sold Less Government TaxesfTransfers AVERAGE CENTS PER kWh SOLD -WHOLESALE (Firm Wholesale Customers O nl y) 6.40 ....-----------

5.91¢ 6.00 -----------

2012 2013 6.09¢ 2014 2015 2016 Financial Report 16 Participation Sales and Other Sales In addition , there are five 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 Isla nd Utilities

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

(" TEA"). Transmission Customers The District owns and operates 5 , 267 miles of transmission and subtransmission lines , encompassing nearly the entire State of Nebraska.

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.

Customers.

Energy Sales, and Revenues The following table shows customers, energy sales , and peak loads of the System , including participation sales, in each of the three years, 2014 through 2016. Megawatt-Hour Sales Anytime Peak Load (MW) Calendar Awrage Number of Wholesale Nati-..e Load Percentage Total Percentage Busbar Nati-.e Year Retail Customers Customers<1> Sales<2 l Growth Sales <3 l Growth Lo ad 2014 90 , 293 86 12 , 932 , 518 (1.6) 20,658,755 (0.8) 2 , 811.0 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 (1) At the end of 2016 , i ncludes sales to firm wholesale customers , participat i on customers (LES, MEAN , JEA , OPPD , Grand Island), and a yearly average of 2 nonfirm customers. Bilatera l sales to utilities decreased in 2014 due to SPP's transition to an integrated market. In 2016 , three of the District's mun icipal wholesa l e customers began purchasing power from three of the District's public power d i strict wholesale customers , and one of the District's municipal wholesale customers allowed their contract to terminate. (2) Native load sales i nclude wholesale sales to total firm requirements customers and i nclude the responsibility of replacement power being procured by the District i f the District's generating assets are not operating. Predominantly , native load customers are served under long-term total requirements contracts.

(3) Total sales from the System i nclude sales to LES from GGS and Sheldon; to Heartland from CNS, which sale commenced January 1 , 2004 , and terminated December 31 , 2013; to KCPL from CNS , which sale commenced January 1 , 2005 , and terminated on January 18 , 2014; to MEAN , JEA , OPPD , and Grand Island from Ainsworth Wind Energy Facility , which sales commenced October 1 , 2005 , and terminates on September 30, 2025; to OPPD, MEAN , LES and Grand Island from Elkhorn Ridge Wind Facility , which sales commenced March 1 , 2009 , and terminates 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 Wind Fac ility , which sales commenced February 1 , 2011 , and terminates on January 31 , 2031; to OPPD , Lincoln and Grand Island from Broken Bow I Wind Facility , which sales commenced December 1 , 2012 , and terminates on November 30 , 2032; to OPPD , LES and MEAN from Crofton Bluffs Wind Facility , which sales commenced November 1 , 2012 , and terminates on October 31 , 2032; and to OPPD from Broken Bow II Wind Facility which sale commenced October 1 , 2014 , and terminates on September 30 , 2039. (4) The decrease in percentage growth from 2015 to 2016 was a result of reduced nonfirm revenues due to lower energy sales due to the planned refueling and ma i ntenance outage at CNS , lower natural gas prices and additional wind generation in the SPP Integrated Market. 17 Financial Report FINANCIAL I NFORMAT I ON The following tables summari z e the Distr i ct's financial pos i t i on and operating results. CONDENSED BALANC E SHEETS (i n OOO's) As of December 31 , 2016 2015 2014 Current Assets ...............................

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

............. $ 775,479 $ 764 , 278 $ 719 , 987 Special Purpose Funds .................................................. 782 , 857 738 , 967 808 , 552 Ut i l i ty Plant , Ne t ......................

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

............... 2 , 596 , 806 2 , 508 , 971 2,495 , 206 Other Long-Term Assets .........................

...................... 451 , 048 353 , 639 800,406 Deferred Outflows of Resources

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

..... 124 , 953 40 , 775 26 , 794 Total Assets and Deferred Outflows ............................

$ 4 , 731 , 143 $ 4,406 , 630 $ 4 , 850 , 945 Current Liabilities

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

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

.. $ 287 , 322 $ 218 , 858 $ 395 , 676 Long-Term Debt ............................................................

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

..........

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

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

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

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

271 ,258 289 , 846 251 , 648 Net Position .................................

................................. 1,415 , 117 1 , 332 , 184 1 , 241 , 124 Total Liab i lities , Deferred Inflows , and Net Position ....... $ 4,731 , 143 $ 4,406 , 630 $ 4,850 , 945 CONDENSED RESU LT S O F OPERAT I ONS (i n OOO's) For the years ended December 31 , 2016 2015 2014 Operating Re\*nues ...............................

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

... $ 1 , 153 , 997 $ 1 , 097 , 216 $ 1 , 122,454 Opera t i ng Expenses ......................................................

(1 , 040 , 715) (960 , 259) (1,010 , 693) Operating Income .....................................................

113 , 282 136 , 957 111 , 761 ln\*stment and Other Income .............

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

......... 31 , 772 22 , 355 26 , 039 Debt and Other Expenses ...................

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

........ (62 , 121) (68 , 252) (75,438) Increase in Net Pos i t ion .......................................

..... $ 82 , 933 $ 91 , 060 $ 62 , 362 SOURCES OF OPERATING REVENUES (in OOO's) For the years ended December 31 , 2016 2015 2014 F i rm Reta i l and Wholesa l e Sales ............

........................ $ 865 , 661 $ 848 , 345 $ 887,619 Participation Sales ..........................................

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

77 , 996 77 , 192 81 , 063 Other Sales ..............

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

89,492 134 , 612 172 , 521 Other Operating Re\*nues ............................................. 66 , 060 60 , 730 58 , 352 Unearned Re\*nues .................

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

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

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

$ 1 , 153 , 997 $ 1 , 097 , 216 $ 1 , 1 22,454 Financial Report 18

CONDENSED STATEMENTS OF CASH FL O WS (in O OO's) For the years ended December 31 , 2016 20 1 5 20 1 4 Net Cash Pro\1ded by Operating Acti"1t i es ....................... $ 253 , 711 $ 372 , 503 $ 362 , 365 Net Cash Pro\1ded by (Used i n) Im.es t i ng Activities

........... 2 , 374 10 , 961 (199 , 101) Net Cash Used in Capital and Financing Activities

............ (238 , 416) (388,483)

(241 , 874) Net Inc r ease (Decrease) i n Cash and Cash Equivalents

.... 17 , 669 (5 , 019) (78 , 610) Cash and Cash Equivalents , Beginn i ng of Year ................ 85 , 060 90 , 079 168 , 689 Cash and Cash Equ i va l ents , End of Year .................... $ 102,729 $ 85 , 060 $ 90 , 079 Revenues from Firm Reta i l and Wholesale Sales The District allocates costs between reta i l and wholesale service and establ i shes its rates to produce revenues sufficient to meet its estimated respective reta i l and wholesale revenue requirements. Wholesale revenue requirements include unbundled costs accounted for separately between generation and transmission. Transm i ssion costs not recovered from the Distr i ct's wholesale power contracts are expected to be recovered through rates charged by SPP. The rates for retail service include an amount to recover the costs of wholesale power service in addition to distribution system costs and government taxes and transfers. The D i strict'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 prov i de for the creat i on of a rate stabilization account. Any surplus or defic i ency between revenues and revenue requirements , within certa i n li m i ts set forth i n the wholesale power contracts , may be retained in the rate stabilization account. Any amounts in excess of the l i m i ts may be i ncluded as an adjustment to revenue requirements i n the next rate review. The wholesale power contracts also i nclude a prov i sion for establishing a new/replacement generation fund. Th i s prov i sion would permit the D i strict to collect an additional 0.5 mills per kWh above the normal revenue requ i rements to be used for future capital expenditures associated w i th generation. 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 has been implemented in 2017. The District i mplemented a 0.6% increase in the District's wholesale rates on January 1 , 2016 , for those wholesa l e customers who signed the new 2016 20-year wholesale power contract , and a 3.8% increase i n the Distr i ct's wholesale rates on January 1 , 20 1 6 , for those wholesale customers who remain under the 2002 20-year wholesale power contract.

The rate increase was higher for the 2002 Contracts as these customers will pay thei r share of a catch-up in funding for other post-employment benefits (" OPES") costs in 2016 and 2017. The D i strict financed with taxable debt the 2016 Contracts customers' share of the OPES catch-up trust funding and the 2016 Contracts customers will pay the debt serv i ce associated w i th such debt beginning in 2022 and continu i ng through 2033. No increase in reta i l rates was i mplemented in 2016. Details of the District's Wholesale Power Contracts are included i n Note 12 i n the Notes to Financial Statements. The District implemented a 0.5% i ncrease i n the District's wholesale rates commencing on January 1 , 2015. No increase i n retail rates was implemented in 2015. The District had no wholesale or retail rate increase i n 2014. Revenues from firm sales increased

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

$39.3 million , or 4.4%, from $887.6 million i n 2014 to $848.3 million in 2015. The decrease was due primarily to lower unbilled retail energy with a revenue impact of $14.4 m i llion and a 1.4% decrease in sales volume which was the result of m i lder temperatures. Revenues from Participation Sales The District has participation sales agreements with other utilit i es that share operating expenses on a pro rata basis. Revenues from participation sales increased from $77 .2 million in 2015 to $78.0 million in 2016 , an 19 Rnancial Report increase of $0.8 m i llion. Revenues from participation sales decreased from $81.1 million i n 2014 to $77.2 m i ll i on i n 2015 , a decrease of $3.9 m i ll i on. This decline was due primarily to participation sales to LES which decreased by $4.4 million due to a 23.0% reduct i on in the dispatch of generation from She l don due to lower pr i ces in the SPP Integrated Market. The decrease was partially offset by increased wind participation sales Reven u es from Other Sales Other sales consist of sales in SPP's Integrated Market and nonfirm sales to other utilities. TEA , of wh i ch the Distr i ct is a member , has energy marketing responsib i lities for the District's other and nonfirm off-system sales and the related management of cred it r i sks. Other sales decreased from $134.6 million in 2015 to $89.5 million in 2016 , a decrease of $45.1 m i ll i on. The decrease was a result of reduced nonfirm revenues due to lower energy sales due to the planned refuel i ng and maintenance outage at CNS , lower natural gas prices and additional w i nd generation i n the SPP Integrated Market. Revenue from participation sales decreased from $172.5 million i n 2014 to $134.6 million in 2015 , a decrease of $37.9 million. This decrease was a result of lower prices in the SPP Integrated Market which was due to lower natural gas prices and additional w i nd generat i on. Other Operating Revenues Other operat i ng revenues consist primarily of revenues for transm ission and other m i scellaneous revenues. These revenues were $66.1 million , $60.7 million , and $58.4 million in 2016 , 2015 , and 2014 , respectively. The majority of these revenues were from other SPP transmiss i on customers for their share of qualifying transmission upgrade pro j ects of the Distr i ct. Unearned Revenues Under the provisions of the D i str i ct's who l esale 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 amoun t s in excess of the rate stabilization limits may be included as an adjustment to revenue requirements in the next rate review. A similar process is fo ll owed in accounting for any surplus or deficiency in revenues necessary to meet revenue requiremen t s for retail electric service. Under generally accepted accounting principles for regulated electr i c utilities , the balance of such surpluses or deficiencies are accounted for as " regulatory liabil i ties or assets" , respectively. The District recognizes net revenues in excess of revenue requ i rements i n any year as a deferral or reduction of revenues. Such surplus revenues are excluded from the net revenues ava i lable under the General Revenue Bond Reso l ution (" General Resolution

") to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues availab l e under the General Reso l ution to meet debt service requirements i n the year that such surp l us revenues are taken into account in setting rates. The D i str i ct recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues , even though the revenue accrua l will not be realized as " cash" until some future rate period. Such revenue deficiency is included , i n the year accrued , in the net revenues available under the General Resolution to meet debt serv i ce requirements for such year. Revenue deficiencies are excluded in the determination of net revenues avai l able 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 recognized or increased revenues a net amount of $54.8 million in 2016. The District's revenues i n 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 i ncluded a refund of $17.4 mill i on of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduct i on in revenues in the year(s) the surplus occurred. Accordingly , the 2016 revenues from electric sales , which reflect the surplus being re f unded , are offset by a revenue adjustment (increase in revenues) for such amount. The D i strict also recognized or increased revenues by $24.7 million for CNS fall refuel i ng a n d maintenance outage costs , which costs were pre-collected for in 2015. This regulatory liab i lity was amortized through revenue during the 2016 outage year. In add i tion , the District recognized or increased revenues by $22.7 mi ll ion for OPES expenses related to past service for wholesale customers under Financial Report 20 the 2016 Contracts. The OPEB expenses were in cluded in 2016 rates and financed with proceeds from General Revenue Bonds , 2016 Series E. The District deferred or decreased revenues a net amount of $23.7 million in 2015. The Distr ict's revenues in 2015 from electr i c sales to retail , wholesale , and other utilities resulted in a surplus , or over collection of costs , of $11.0 mi llion , which was deferred (decrease in revenues). In addit i on , the wholesale rates that were in place for 2015 included a refund of $12.0 million of surplus net revenues from past rate periods. Such surplus had prev i ously been accounted for as a reduction i n revenues in the year(s) the surplus occurred. Accordingly , the 2015 revenues from electr i c sales , which reflect the surplus being refunded , were offset by a revenue adjustment (in crease in revenues) for such amount. The Distr ic t also deferred or decreased revenues by $24.7 mill i on for the pre-collection of CNS refueling and ma i ntenance outage costs. This regulatory liability will be eliminated through revenue recognition during the 2016 outage year. The Distr i ct deferred or decreased revenues a net amount of $77.1 million i n 2014. The D istrict's revenues in 2014 from electric sales to retail , wholesale , and other ut il ities resulted in a surplus , or over collection of costs , of $91.4 mill i on , which was deferred (decrease in revenues). In addition , the wholesale rates that were in place for 2014 included a refund of $14.3 million of surplus net revenues from past rate periods. S uch surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accord i ngly , the 2014 revenues from electric sales , which reflect the surplus being refunded , were offset by a revenue adjustment (in crease in revenues) for such amount. Unearned revenues from prior periods of $1.9 mill i on were refunded directly to customers in 2014. The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements in future ra te per i ods was $168.7 million , $176.1 mill i on , and $177.1 mill i on , as of December 31 , 2016 , 2015 , and 2014 , respect i vely. Operating Expenses The following chart illustrates operating expenses for the years ended December 31 , 2014 through 2016. $1 , 200 Power Pur chased & Fuel $1,000 Production Operation

& Maintenance

(" O&M") Iii $800 c: .!:! Transmiss i on & D istr i bution O&M *-$600 Customer Servi ce & Information ti) ... ..!!! Adm inistra t ive & Gen eral 0 $400 0 Decommissioning

$200 Depreciation

& Amort iza tion $0 Other 2014 2015 2016 Total operating expenses in 2016 were $1 , 040.7 million , an in crease of $80.4 million from 2015. Total operating expenses i n 2015 were $960.3 million , a decrease of $50.4 million from 2014. The changes were due primar ily to the follow i ng: Power purchased and fuel expenses were $347.6 million , $365.1 million , and $386.3 million in 2016 , 2015 , and 2014 , respect ive ly. These expenses decreased

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

$21.2 mill i on in 2015 as compared to 2014 due pr i marily to lower fu el 21 Flnandal Report costs as a result of decreased generation , lower market prices and fewer energy purchases in the SPP Integrated Market. Product i on operation and ma i ntenance expenses were $287.7 million , $242.8 million , and $281.7 mil l ion i n 2016 , 2015 , and 2014 , respectively. These costs increased

$44.9 mill i on due primarily to the costs associated with a planned refue li ng and maintenance outage at CNS completed on November 8 , 2016. These cos t s decreased

$38.9 million in 2015 as compared to 2014 due primarily to t he costs assoc i ated with a planned refueling and maintenance outage at CNS completed on November 2 , 2014 , which ended the station's first 24-month operating cycle. No such outage occurred i n 2015. Transmission and distribut i on operation and maintenance expenses were $102.0 million , $87.3 million , and $83.8 million , in 2016 , 2015 , and 2014 , respectively. These costs increased

$14.7 million in 2016 as compared t o 2015 due primari l y to higher fees charged by SPP for the District's share of qualifying transmission upgrade projects , includ i ng an SPP resettlement for prior periods for the i mplementation of a tar i ff provision to compensate transmission upgrade sponsors for qualifying upgrades used by other transmission customers. These costs increased

$3.5 million in 2015 as compared to 2014 due primarily to an i ncrease in SPP fees. The District is charged by SPP for firm requirements customers for the qualifying transmission system upgrade projects of other SPP transmission owners. Customer service and information expenses were $17.7 m i llion , $17.2 million , and $17.5 million , in 2016 , 2015 , and 2014 , respectively. Administrative and general expenses were $94.1 mill i on , $66.3 million , and $59.4 million , in 2016 , 2015 , and 2014, respectively. These costs increased

$27.8 million in 2016 as compared to 2015 due primarily to OPES expenses re l ated to past service and included in 2016 rates. Details regarding OPES , including the ear l y adoption of new accounting guidance i n 2016 , are included in Note 11 in the Notes to Financial Statements.

Admin i strative and general expenses increased

$6.9 million in 2015 as compared to 2014 due pr i marily to increases in healthcare costs along with increased expenses for outs i de services. Decommissioning expenses were $21.4 million , $14.7 million , and $18.5 million , in 2016 , 2015 , and 2014 , respectively. Decommissioning expenses represent the net amount accrued each year for the future decommissioning of CNS. Such expenses are recorded i n an amount equivalent to the i ncome on investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service i n such year. Decommissioning expenses increased by $6.7 million in 2016 as compared to 2015 due to an increase in i n terest inc ome on investments. Decommissioni n g expenses decreased

$3.8 million in 2015 as compared to 2014 due to a decrease in income on investments. No additional amounts for decommissioning were collected through rates in 2016 , 2015 , and 2014. Depreciation and amortization expenses were $133.7 million , $130.2 million , and $126.4 million , in 2016 , 2015 , and 2014 , respectively. Increase in Net Position The increase in net posit i on was $82.9 million , $91.1 million , and $62.4 million , in 2016 , 2015 , and 2014 , respect i vely. 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 change in net position in 2015 as compared to 2014 increased

$28.7 million and was due pr i marily to an increase in 2015 revenue requirements from increased collections for construction from revenue and for principal payments on commercial paper notes , partially offset by reduced collections for princ i pal payments for revenue bonds. Financial Report 22 The following chart illustrates the D istrict's o perating revenues , other revenues , operating expenses , and other expenses for the years ended December 31 , 2014 through 2016. Revenues & Expenses $1 , 250 ....----------------

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

I $1 , 150 t--M .... ,-----==--:------:--r-----$1 , 100 +---II $1 , 050 $1 , 000 ---$950 ---0 c $900 +---i. $850 +---t $800 -..... 20 1 4 20 1 5 2016 FINANCIAL MANAGEMENT POLICY Other Expenses Operating E xpenses Other Revenues Operating R evenues The District has a Financial Management Policy (the " Policy"), which is subject to periodic review and revisions by the Board. This Pol i cy represents general financial strategies and procedures that are implemented to demonstrate financial integrity and fiscal responsibi l ity in the management of the District's bus i ness and its assets. Employees must abide by all applicable District bylaws , Board resolutions, bond resolut i ons , federal and state laws , other re l evant l egal requirements and the Po l icy. DEBT SERVICE COVERAGE Under the Policy , the D i strict 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 1.98 , 1.84 , and 1.50 , in 2016 , 2015 , and 2014 , respectively. The coverage was provided primar i ly by the amounts collected in operating revenues to fund the cost of utility plant additions , the amounts collected in operating revenues for principal and i n terest payments on the outstanding commercial paper notes , and the amounts collected for payments to those municipalities served by the District under long-ter m PRO Agreements. The increase in the 2016 debt service coverage ratio over 2015 was primarily due to a decrease in the required debt service deposits for 2016. The inc r ease in the 2015 debt service coverage ratio over 2014 was primar i ly due to the fact that effective July 31 , 2015 , the obligation of the District to pay the principal , interest , bank fees , and expenses p ursuant t o the Taxable R evo l ving C redit Agreement is payable from the Pledged P roperty subject and s u bordinate d to the pledge o f the Pledged P roperty to the payment of the General Revenue Bonds. FINANCING ACTIVITIES 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 t h at they will not be revised downward or be withdrawn entirely by the respective rating agency if , in i ts judgment , circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the market prices of bonds. 23 Financial Report The District's credit ratings on its revenue bonds were as follows: Moody's Investors Service ...................................................

......................... A 1 Standard & Poor's Rat i ngs Serv i ces .........................

.................................... A+ Fitch Ratings ................................................................................................. A+ (stable outlook) (s t able outlook) (stable outlook) The D istrict pla n s , pursuant to the Policy , to issue separate series of indebtedness , i ncluding separate series of Genera l Revenue Bonds , for product i on projects and for transm ission projects. No more than 20.0% of the amount of outstanding i ndebtedness issued for production projects , calculated at the time of issuance of each series of such i ndebtedness , or $200.0 million , whichever i s less , will be perm i tted to mature after January 1 , 2036 , the end of the 2016 Contracts. Transmiss i on i ndebtedness i ssued for transmission projects is expected to mature over the useful life of the asset that i s be in g financed. New transmission indebtedness may mature after January 1 , 2036. The District's transmission i ndebtedness is payab l e from the revenues rece i ved during the term of the 2016 Contracts and from reta i l sales and transm i ss i on revenues received under various SPP tariffs. After January 1 , 2036 , transm i ssion indebtedness will be payable from revenues to be derived from wholesale and retail customers who use the District's transm i ssion facilities , as well as revenues from various SPP tariffs. In Apr i l 2017 , the District issued General Revenue Bo n ds , 2017 Ser i es A and 2017 Series B , in the amount of $86.0 m i llion to refund the General Revenue Bonds , 2007 Series B. The refunding reduced total debt service payments over the life of the bo n ds by $1 1.8 m i llion , which resulted i n present value savings of $10.0 million. The Distr i ct plans to i ssue add it ional r evenue bonds in 2017 to finance transmiss i on projects. In November 2016 , the District i ssued General Revenue Bonds , 2016 Series C and 2016 Series D , in the amount of $113.5 million to finance the costs of certain generation and transm i ssion capital projects and refund $6 1.7 million Tax-Exempt Commerc i al Paper (" TECP"). The District also issued i n November 2016 , General Revenue Bonds, 2016 Ser i es E (Taxable), in the amount of $56.1 m i llion to fund a port i on of OPEB costs for customers 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 mill i on of TECP. The refunding reduced total debt service payments over the l i fe of the bonds by $29.8 million , which resu l ted i n present value sav i ngs of $20.8 million. In January 2016 , the D i strict i ssued TECP i n 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 m i llio n of TECP was refunded by Genera l Revenue Bonds , 2016 Series A and Series B. In February 2015 , the D i strict issued General Revenue Bonds , 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced tota l debt serv i ce payments over the life of the bonds by $42.0 mi ll ion , which resulted in present va l ue savings of $26.1 million. Deta i ls of the D i strict's debt balances and activity are i ncluded in Note 7 in the Notes to Financial Statements. CAPITA L REQUIR E MENTS The Board-authorized capital projects totaled approximate l y $109.5 mill i on , $501.0 million , and $197.4 m ill ion , in 2016 , 2015 , and 2014 , respectively. The District's capital requirements are funded with monies generated from operations , debt proceeds , and other available reserve funds. Cap it al 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 construct i on of a h i gh-voltage substation in Holt County , Nebraska an d expansion of the GG S 345 kV substation. * $12.6 million for i nstallation of stainless steel liners in coal silos at GGS Un i ts 1 and 2 Financial Report 24 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 Capital projects for 2014 included: * $94.9 million for construction of a high-voltage transmission l i ne and related substations from the Hoskins substation northeast of Norfolk , Nebraska to Ne l igh , Nebraska * $14.7 million for replacement of a secondary super-heater outlet at GGS Unit 2 * $7.0 million for replacement of a silo dust collector at GGS Units 1 and 2 There were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $59.0 million , $87.2 mill i on , and $80.8 m i llion for 2016 , 2015 , and 2014 , respectively. The Board-authorized budget for capital projects for 2017 is $137.4 million. The 2016 budget was much lower due to large transmission projects authorized i n 2015. The District will receive revenues from othe r transmission owners in SPP for their share of these projects over the projects' depreciable life. Spec ific capital projects for 2017 include: * $12.5 million for implementation of Advanced/Smart Metering and Interfaces

$7.7 million for construct i on of an evaporation pond at GGS * $7.4 million for refurbishment of a 115 kV substation i n Beatr i ce , Nebraska The following chart illustrates the Board-authorized capital projects for the years ended December 31 , 2014 through 2016 , including the Board-authorized budget for the year ended December 31 , 2017. U) c: .!2 Ill ... "' 0 c $600 $500 $400 $300 $200 $100 $-$197 ..I_ ---2014 CAPITAL REQUIREMENTS

$501 2015 2016 2017 Budget RESOURCE PLANNING The District's core plann i ng principles for its most recent Integrated Resource Plan (" IRP") align with the Board's strategic goals which include further diversifying its m i x of generating resources (nuclear , coal , hydro , wind , energy efficiency and demand response), energy storage , and capita li zing on the competitive strengths of Nebraska (available water , proximity to coal , and abundance of wind). Key goals from the IRP include:

achiev i ng a goal of 10% of the D istrict's energy supply from renewable resources by 2020 ,

increasing focus on energy efficiency to meet customer load growth , and

increasing diversification with a trend toward cleaner energy 25 Financial R eport The probabilistic analysis under the IRP focused on key future uncertainties , including customer l oad growth , future environmental regu l ations including carbon dioxide (" CO/), capital additions and operation and maintenance costs of new units , future fuel , and market prices for electricity. The results showed that with the District's recapture of 120 MWs of base l oad generation from expi r ing capacity and energy contracts out of CNS , and lower projected load growth , the District is positioned to meet its fi r m load requirement needs for the next 1 O to 15 years. Specific actions on which the District will focus t o meet load growth needs include addition of renewables , effectiveness of energy efficiency programs and e v a l uation of additiona l peaking capacity.

The District's Board approved the IRP during the second quarter of 2013. Although the I RP included a power uprate for CNS , the District's most recent evaluation of the costs and market risks related to a power uprate has led the District to decide not to engage in a power uprate for CNS at this time. Long-term opera t ion of GGS appears to continue to be commercially viable even if additional long-term environmental controls are required. The District would need to revisit this assumption if high C0 2 costs occur. Operation of Sheldon and Canaday appears marginally beneficial unless and until additional environmental controls or other costly major modifications are required. More wind and energy efficiency a l so appear beneficial , but not under a low native load growth scenario. The major uncertainties identified in the IRP are continually reviewed and evaluated as to their i m pact on the District.

The Distr i ct expects to issue its next IRP in 2018. Renewable Energy The Distr i ct owns and operates the 60 MW Ainsworth and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition , the District has entered into 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 of 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 in Nebraska over similar terms. The District will pay only for energy delivered pursuant to such power purchase wind agreements and the cost of the substation and transmission work to connect these facilities to the District's electric system. Participating utilities will pay their pro rata share of energy delivered from these facilities along with associated capital additions for substation and transmission work. 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 firm wholesale customer of the District.

Monolith may be the largest industrial customer served in the District's territory. The District entered into a 20-year contract with Monolith to purchase the carbon b l ack plants' production of hydrogen rich tail gas , which will be produced by Monolith during production of carbon black. T h e District will have to convert its existing coal-fired boiler at Sheldon Station Unit No. 2 to burn the hydrogen rich tail gas. The boiler conversion is expected to result in a reduction of C0 2 , sulfur dioxide (" S0 2"), m ercury, and other air emissions.

Groundbreaking for Phase 1 occurred in October 2016 and is expected to be mechanically complete and operational in 2018. Phase 2 is schedu l ed to begin in the second half of 2019. The commercial 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 conversion to burn the hydrogen rich tail gas and convert it to electricity) is scheduled for the second quarter of 2021. EN ERGY RISK MANAGEME NT PRAC TI CES The nature of the District's business exposes it to a variety of risks , including exposure to volatil i ty in electric energy and fuel prices , uncertainty in load and resource ava i lability , the creditworthiness of its counterparties , and the operational risks associated with transacting in the wholesale energy markets. To help manage energy risks, including the risks related to the District's participation in t he SPP Integrated Market , the District relies upon TEA to both transact on its behalf in the who l esale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets. Financial Report 26 TEA combines a strong knowledge of the D i strict'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 customized energy products and services to the District.

TEA has assisted the Distr i ct in developing i ts Energy Risk Management

(" ERM") program. The program originates with the Board-approved ERM Govern i ng Policy and the ERM-Approved Products and L i mits Standard. These documents establish the philosophy , objectives , delegation of authorities , approved products and the i r lim i ts on the D i str i ct's energy and fuel act i vities necessary to govern i ts ERM program. The objective of the ERM program i s to increase fuel and energy price stabil i ty by hedgi ng the r i sk of significant adverse i mpacts to cash flow. These adverse impacts could be caused by events such as natural gas or power price volatil i ty , or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the r i sks i nherent i n the wholesale energy market are being quantified and appropr i ately managed. ECONOMIC FACTORS The recent slow i ng of growth of Nebraska's economy continued in 2016. The state's inflation ad j usted gross state product (" GSP") increased by only 1.1 % from the third quarter of 2015 to the third quarter of 2016. This was less than the 1.6% increase in t he nat i onal gross domestic product over the same 12-month period and a substantial decrease from Nebraska's revised estimated 2.0% increase i n GSP from the th i rd quarter of 2014 to the th i rd quarter of 2015. Nebraska's slowdown i n GSP growth over the latest 12 months has been due to declines i n the " Management of companies and enterprises , " Transportation and warehousing" and " Durable goods manufactur i ng" industries.

Nebraska and the Midwest reg i on continue to experience unemployment rates that are below the nat i onal average. However , 2016 saw the state's first increase in its average annual unemployment rate since 2009. Nebraska's unemployment rate increased from an annual average of 3.0% for 2015 to 3.2% in 2016 but remained well below the 2016 nati onal average unemployment rate of 4.9%. Nebraska's pre l iminary , seasonally adjusted unemployment rate was 3.3% in December 2016 , up slightly from 3.2% in December 2015. Bot h numbers were well below the national December seasonally adjusted unemployment rates of 4.7% in 2016 and 5.0% in 2015. After several years of consistently being one of the three states with the lowest unemployment rates , Nebraska's preliminary , December 2016 unemployment rate was the ninth lowest in the nation. The District continues to monitor changes in national and global economic conditions , as these could impact cost of debt and access to capital markets. CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY The Electric Utility Industry In General The electric utility industry has been , and in the future may be , affected by a number of factors which could impact the financial condition and competitiveness of electric utilities , such as the District.

Such factors include , among others:

effects of compliance with changing env i ronmental , safety , licensing , regulatory , and legis l ative requirements ,

changes result i ng from energy efficiency and demand-side managemen t programs on the timing and use of e l ectric energy ,

other federal and state leg islative and regulatory changes ,

increased wholesale competition from independent power producers , marketers , and brokers , * " self-generation" by certa i n industrial and commercial customers ,

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

severe restr ic tions 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 d i fferent fuels , 27 Fi nancial Report

inadeq uate risk management procedures and pract i ces with respect to , among other things , the purchase and sale of energy , fuel , and transmission capacity ,

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

climate change and the potent i al contr i butions made to climate change by coal-fired and othe r fueled generat i ng units ,

increased regulati on of nuclear power p l ants in the United States resu lting from the earthquake and tsunami damage to certain nuclea r power plants i n Japan , and

i ssues relat ing to cyber and phys i cal secur it y. Any of these general factors (as well as other fact ors) could have an effect on the financial condition of the D i strict. Competitive Environment i n Nebraska While wholesale competit i on is expected to increase in the future , there is a Nebraska statute that prohibits competition for retai l customers. Pursuant to state statutes , retail suppliers of electricity have exclusive rights to serve customers at retail in the ir respective service territor i es. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppl i ers and/or pursuan t to an order of the Nebraska Power Review Board. While state statutes do not prov id e for wholesale suppliers of electric i ty 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 li miting the areas or customers to whom they may sell energy at wholesale.

The District has entered i nto several such agreements. Financial Report 28 REPORT OF INDEPENDENT AUDITORS To the Board of Directors of the Nebraska Public Power District:

We have aud i ted the accompany i ng financia l statements of Nebraska Publ i c Power Distr i ct (the " D i stric t") which cons i st of the balance sheets as of December 3 1, 2016 and 2015 , and t h e related statements of revenues , expenses , and changes i n net pos i tion , cash flows , and the re l ated notes to the finan ci al statements for the years then ended. Management's Responsibility for the Financial Statements Management i s responsible for the preparation and fa i r presentat i on of the fi n ancial statements in accordance with accounting pr i nciples generally accepted in the United States of America; this i ncludes the desig n , implementation , and maintenance of internal contro l relevant to the preparation and fair presentation of financial statemen t s that are free from mater i al m i sstatement , whether due to fraud or error. Auditors' Respons ibility Our respons i b ili ty is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted i n the Un i ted States of Ame r ica. Those standards requ i re that we plan and perform the audit to obtain reasonable assurance about whether the financ i a l statements are free from m a terial m i sstatement.

A n audit involves performing p r ocedures to obtain audit evidence about the amounts and d i sclosures i n the financial statements. The procedures selected depend on our judgment , including the assessment of the r i sks of mate ri al m i sstatement of t he financial statements , whether due to fraud or error. In mak i ng those r isk assessments , we cons i der internal contro l relevant to the District's preparation and fair presentation of the financial statements in orde r to des i gn audit procedures that are appropr i ate in the circumstances , but not for the purpose of expressing an opin ion on the effectiveness of the D i strict's internal contro l. Accordingly , we express no such opin i on. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting est i mates made by management , as well as evaluating the overall presentation of the financial statements. We believe that the aud i t evidence we have obta i ned i s suffic i ent and appropr i ate to provide a basis for our aud i t op i nion. Opinion In our opinion , the financial statements referred to above present fa i rly , in all material respects , the financ i al pos i tion of the Distr i ct as of December 31 , 2016 and 2015 , and the respective changes in financial pos i tion and cash flows for the years then ended in accordance wit h accounting principles generally accepted i n the United States of Amer i ca. Emphasis of Matter As d i scussed i n Note 1 to the financia l statements , the Company changed the manner in which it accounts for Other Postemploymen t Benefits i n 2016. Our opinion i s not modified w i th respect to this matter. Other Matters The accompany i ng management's d i scussion and analysis and the supplemental schedules on pages 14 through 28 and 62 through 64 , respective l y , are required by accounting pr i nciples generally accepted in the United States of America to supplement the basic financial statements. Such information , although not a part of the bas i c financia l statements , i s requ i red by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financia l statements in an appropriate operat i onal , econom i c , or h i stor i ca l context. We have applied certain lim i ted procedu r es to the requ i red supplementary information i n accordance w i th auditing standards generally accepted in the Un i ted States of Amer i ca , wh i ch consisted of inqu i ries of management about the methods of preparing the information and compar i ng the i nformation for cons i stency with management

's responses to our i nquiries , the bas i c financial statements , and other knowledge we obtained during our audits of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient ev i dence to express an opin i on or prov i de any assurance. Our aud i ts were conducted for the purpose of forming an opinion on the financ i al statements that collective l y comprise the District's basic financial statements. The statist i cal review is presented for purposes of addit i onal ana l ysis and is not a requ i red part of the basic financial statements. Such information has not been subjected to the auditing procedures applied i n the audits of the basic finan ci al statements , and accord i ng l y , we do not express an opinion or provide any assurance on it. .........

+J-. Cnr..,. St. Louis , Missour i April 13 , 2017 29 Financial Report FINANCIAL STATEMENTS Nebraska Public Power D i strict Balance Sheets as of December 31 , (in OOO's) ASSETS AND DEFERRED OUTFLOWS Current Assets: Cash and cash equivalents

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

......................................... . Investments

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

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

........................ . Rece i vables , less allowance for doubtful accounts of $530 and $515 , respect i vely .........................................

................... .. Foss i l fuels , at average cost ...........................................

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

.... . Materials and supplies , at average cost ...........................................

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

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

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

... . Debt res er.A:! funds .............

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

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

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

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

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

...................... . Utility P l ant , at Cost: Ut ility plant in serv;ce ...........

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

................ . Less res er.A:! for depreciat io n ................................

...........

....................... . Construction work in progress ................................................................ . Nuclear fuel , at amortized cost .............................................................

.. . Other Long-Term Assets: Regulatory asset for asset retirement obligation

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

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

...... . Long-term capacity contracts

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

........................................... . Unamortized financ i ng costs .................................................................. . Inves tment in The Energy Authority

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

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

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

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

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

............................................... . Deferred Outflows of Resources: Unamortized cost of refunded debt ....................................................

..... . Other post employment benefits ........................................

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

...... . TOTAL ASSETS AND DEFERRED OUTFLOWS .............................

............. . 2016 $ 102,729 373 , 331 123,905 43 , 620 114 , 640 17 , 254 775,479 1 06 , 204 90 , 032 4 , 851 581 , 770 782 , 857 4 , 971 , 259 2 , 708 , 036 2 , 263 , 223 135 , 853 197,730 2 , 596 , 806 44 , 899 221 , 973 159 , 445 8 , 945 6 , 370 9,416 451 , 048 4 , 606 , 190 42 , 664 82 , 289 $ 4,731 , 143 LIABILITIES , DEFERRED INFLOWS , AND NET POS ITlON Current Liabilities

Revenue bonds , current ..............

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

.................... . $ 81 , 250 Notes and credit agreements , current .........................

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

............ . 74 , 000 Accounts payable and accrued l iabi lit ies ................................................. . 87 , 06 1 Accrued in lieu of tax payments ..............

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

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

.. . 10 , 008 Accrued payments to retail communities

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

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

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

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

.............. . 11 , 372 287 ,322 Long-Term Debt: Revenue bonds , net of current ................................................................ . 1 , 678 , 844 Notes and credit agreements , net of current ............................................ . 188 , 924 1 , 867 , 768 Other Lo ng-Term Liabilit i es: Asset ret i rement obligat i on .........................................................

........... . 627,707 Net other postemployment benefit liab i l ity .......................

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

....................................................... . 3 , 362 889 , 678 Total Liab ilities .........................................................

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

.... . 3 , 044.?M Deferred Inflows of Resources: Unearned revenues ................................................

............................... . 168,710 Other deferred inflow s ............................................................................ . 1 02,548 271 , 258 Net Pos i tion: Net investment in capital assets ...........................................

.................. . 928 , 967 Restricted

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

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

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

......................... . 447 , 374 1,415 , 117 TOTAL LIABILITIES , DEFERRED INFLOWS , AND NET POSITION ................ . $ 4,731 , 143 Th e accompanying note s to fi n a ncial statements are an integral part of these statemen t s. 2015 $ 85 , 060 400,426 110,089 39 ,33 5 117,430 11 , 938 764 , 278 76 , 503 91 , 772 3 , 344 567 ,348 738,967 4,751 , 016 2 , 620 , 091 2 , 130 , 925 209 , 626 168,420 2 , 508 ,971 32 , 323 121,595 172 , 966 8 , 654 7 , 018 1 1 , 083 353 , 639 4 , 365 , 855 40,775 $ 4,406 , 630 $ 114 , 860 63 , 614 9 , 948 6 , 087 16 , 857 7,492 218 , 858 1 , 596 , 972 241 , 700 1 , 838 , 672 600 , 311 1 21 , 595 5 , 164 727 , 070 2,784 , 600 176 , 118 113,728 289 , 846 866 , 699 40,492 424 , 993 1, 332 , 184 $ 4,406 , 630 Financial Report 30 Nebraska Public Power Dist ri ct Statements of Re-..enues , Expenses , and Changes in Net Pos i tion For the years ended December 31 , (in OOO's) Operating Re-..enues

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

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

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

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

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

..... . Production

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

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

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

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

... .. Transmission and distribution operation and maintenance

......................... . Customer service and info rmation ......................................

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

....... . Adm i nistrati-..e and general .............................................................

........ . Payments to reta i l commun i t i es ................

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

............... . Decomm i ssioning ..................................

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

....... . Deprec iation and amortizat i on .......................................

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

.......... . Payments i n lieu of taxes .......................

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

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

.. . Operating Income ......................................

................................................ . ln-..estment and Other Income: ln-..e st ment income ...................

............................................................. . Other income ..........................................................

............................. . Increase in Net Pos ition Before Debt and Other Expenses ............................ . Debt and Other Expenses:

Interest on long-term debt ..................................................................... . Allowance for funds used during construction

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

.............. . Bond prem ium amortization net of debt issua nce expense ........................ . Other expenses ...............................

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

.................... . Increase in Net Position .................

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

........................... . Net Position: Beg i nn ing balance .....................

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

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

.................... . 2016 $ 1 , 153,997 1 77 , 121 170,450 287 , 672 101 , 952 17 , 696 94 , 112 26 , 553 21 , 429 133 , 666 10 , 064 1 , 040 , 715 113 , 282 28 , 239 3 , 533 31 , 772 145 , 054 75 , 415 (4 , 120) (11,42 7) 2 , 253 62 , 121 82 , 933 1 , 332 , 184 $ 1 , 415 , 117 The accompanying notes to financial statements are an integral part of these statements. 31 Financial Report 2015 $ 1 , 097 , 216 166 , 587 198 , 557 242 , 787 87 , 259 17 , 213 66 , 291 26 , 552 14 , 720 130 , 247 10 , 046 960 , 259 136 , 957 18 , 952 3,403 22 , 355 159 , 312 80 , 485 (3 , 414) (10 , 392) 1 , 573 68 , 252 91 , 060 1 , 241 , 124 $ 1 , 332 , 184 Nebraska Public Power District Statements of Cash Flows For the years ended December 31 , (in OOO's) Cash Flows from Operating Act i vities: Rece i pts from customers and others ............

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

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

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

................................................... . Payments to suppliers and \*ndors ..................

...........

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

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

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

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

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

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

...... . Cash Flows from ln\*sting Activities:

Proceeds from sales and maturities of i n\*stments

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

..................... . Purchases of in\*stments

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

....................... . Income recei\*d on i n\*s tmen ts ....................................

......................... . Net cash provided by in\*st ing act i vities ............................................. . Cash Flows from Cap i tal and Related F in ancing Activities

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

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

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

............................... . Capi tal expenditures for utility plant ........................................................ . Contributions in aid of construct i on and other reimbursements

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

.... . Principal paymen ts on lo ng-tenn debt ...............................

..................... . Interest payments on long-tenn debt ................................

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

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

.... . Principal paymen ts on notes and cred it agreements

................................ . Interest payments on notes and cred it agreements

.................................. . Other non-operating re\*nues ..........................................................

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

....................... . Net incr ease {decrease) in cash and cash equivalents

......................... . Cash and cash equivalents , beg i nning of year .............................................. . Cash and cash equivalents , end of year ....................................................... . Reconc iliation of Operat i ng Income to Cash Pro\ided By Operat ing Act i\ities: Operating inco me ..................................

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

............. . Adjustments to reconcile operating income to net cash pro\ided by operating acti\ities

Deprec i at ion and amortization

........................................................... . Undistributed net re\*nue -The Energy Authority

................................ . Decommiss ion ing , net of customer contributions

................................. . Amort iza t ion o f nuclear fuel ............................................................... . Changes i n assets and liabil i ties which (used) pro\ided cash: Rece ivables , net .......................................................................... . Fossil fuels ...........

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

............................ . Materials and supp l ies ................................................................. . Prepayments and other current assets ...............

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

.. Other long-tenn assets ................................................................ . Deferred outflows ..............

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

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

....................... . Accounts payable and accrued payments to reta i l communities

....... . Unearned re\*nues .................................

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

............. . Other deferred infl ows ................................................................... . Other liabilities

............................................................................ . Net cash pro\ided by operating acti\ities

............................................ . Supplementary Non-Cash Capital Acti\ities

Change in utility plant additions in accounts payable ................................ . The accompanying notes to financial statements are an in tegral part of these statements. $ $ $ $ $ 2016 2015 1 , 067 , 143 $ 1 , 101 , 150 209 8 , 082 (565 , 252) (498 , 959) (248 , 389) (237 , 770) 253 , 711 372 , 503 2,775 , 601 597 , 190 (2,800 , 722) (591 , 330) 27 , 495 5 , 101 2 , 374 10 , 961 354 , 776 261 , 189 163 , 807 10 , 363 (261 , 900) (17 5 , 744) 18 , 864 12 , 575 (284 , 710) (349,425)

(77 , 776) (81 , 800) (10 , 194) (21 , 268) (142 , 583) (46 , 166) (2 , 145) (1 , 611) 3 , 445 3 , 404 (238,416)

(3 88 , 483) 17 , 669 (5 , 019) 85 , 060 90 , 079 102 , 729 $ 85 , 060 113 , 282 $ 136 , 957 133 , 666 130 , 247 648 (956) 21,429 14 , 720 40 , 754 47 , 626 (10 , 911) 5 , 973 (4 , 285) (2,761) 2 , 790 4 , 334 1 , 022 (40) 935 850 (45 , 654) 19 , 122 (2 , 443) (7,408) (1 , 025) (14 , 342) 36 , 715 2 , 663 2 , 306 253,71 1 $ 372 , 503 4,273 $ 7 ,9 24 Financial Report 32 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 Wholesale customers. The control of the District and i ts operations is vested in a Board of Directors

(" Board") consisting of 11 members popularly elected from distr i cts 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 including 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 include revenues or costs in a period other than the period in which the revenues or costs would be reported by an unregu l ated entity. C. Revenue -Retai l 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 classified as operating. All other revenues and expenses are classified as non-operating and reported as investment and other income or debt and other expenses on the Statements of Revenue , 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 l iquid 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 includes property additions , replacements of units of property and betterments. The District charges ma i ntenance 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 depreciation , 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 bas i s. Depreciation on ut i lity plant was approximately 2.6% for the years ended December 31 , 2016 and 2015. The District had fully depreciated utility plant , primarily related to Cooper Nuclear Station (" CNS"), which was still in service of $927 .5 million and $867 .5 million at December 31 , 2016 and 2015 , respectively. The District owns and operates the electric distribution system in one of the 80 municipalities that it serves at retail. In addition , the District has long-term Professional Retail Operations

(" PRO") Agreements with 79 municipalities for certain retail electric distribution 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 33 Financial Report term of the agreements. The District recorded prov1s1ons , net of retirements , for amortization of these plant additions of $5.9 million and $6.3 million in 2016 and 2015 , respect i vely , which was included in depreciat i on and amortization expense. These plant additions , which were fu lly depreciated , totaled $185.6 m illio n and $180.9 million at December 31 , 2016 and 2015 , respect ively. G. Allowance for Funds Used During Construction

("AFUDC) -This allowance , which represents the cost of f unds used to fina nce construction , is capitalized as a component of the cost of the utility plant. The capitalization rate depends on the source of financing. The rate for construction financed with revenue bonds is based upon the interest cost of each bond issue less interest income. Construction financed on a short-term basis with tax-exempt commercial paper (" TECP"), or taxable revolving credit agreement

(" TRCA") is charged a rate based upon the projected average inte res t cost of TECP or TRCA outstanding. For the per i ods 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 bas i s with TECP , the rate was 1.0% for 2016 and 2015. 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 uran ium , conversion services of such material to uran ium hexafluoride , uranium hexafluoride that has already been converted from uran ium , enrichment services , and fuel fabr i cation and related services. The Distr ict purchases uranium and uranium hexafluoride on the spot ma rket and carries 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. Unamorlized Financing Costs -These costs i nclude issuance expenses for bonds which are being amortized over the life of the r espective 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 origina l or refunded life of the respective bonds. Regulatory accounting , GASB codification section Re 10 , Regula ted Ope rations, is used to amortize these costs over their respective periods. J. Asset Ret irement Obligations

-Asset retirement obligations

(" ARO") represent the fair value of the District's legal liability associated with the retirement of CNS , various ash landfills at its two coa l-fired power stations , and the removal of asbestos at its various generating facilit i es. K. Other Postemployment Benefits (" OPEB) -For purposes of measuring the net OPEB liability , deferred outflows of resources and deferred inflows of resources related to OPEB , and OPEB expense , i nformat ion about the fiduciary net position of the D istr i ct's Employment Medical and Life Benefits Plan (" Plan") and additions to/deductions from the Plan's fiduciary net position have been determined on the same basis as they are reported by the 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. The District has elected to early adopt the provisions of GASB Statement No. 75 (" GASB 75"), Accounting and Financial Reporting for Postemployment Benefits Other than Pensions , in 2016. Add i tional disclosures related to OPEB are in Note 11. L. Auction Revenue Rights and Transmission Congestion Rights -The District uses Auction Revenue Rights (" ARR") and Transmission Congestion R i ghts (" TCR") in the Southwest Power Pool (" SPP") 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 purchases from SPP auctions or secondary market trades. Financial Report 34 M. Deferred Outflows of Resources and Deferred Inflows of Resources Deferred outflows of resources are consumptions of assets that are applicable to future reporting. The cost of refunded debt is the difference in the reacquis i t i on price and the net carrying amount of the refunded debt i n an advance refunding. Deferred outflows related to OPEB include contributions made dur i ng the current year and experience losses. Deferred inflows of resources are acquired assets that are appl i cable to future reporting periods and consist of regulatory liabilities for unearned revenues and other deferred inflows. Other deferred inflows include CNS outage collections , Department of Energy (" DOE") settlements , nuclear fuel disposal collections and a sales tax refund from the State of Nebraska for the construction of a renewable energy facility. The District i s required under the Genera l Revenue Bond Resolut i on (" 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 l i ens payable out of revenues. In the event the Dist rict's rates for wholesale service result in a surplus or defic i t 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 wholesa l e 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 , 2016 and 2015 and activity for the years then ended (in OOO's): 2016 2015 Unearned re\*nues , beginning of year ..........................

................................... . $ 176 , 118 $ 177 , 143 Surpluses

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

............................................................ . 9 , 992 10 , 975 Use of prior period rate stabi l ization funds in rates ..........

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

..................... . (17 , 400) (12 , 000) Unearned re\*nues , end of year ...................................................................

.. . $ 168 , 710 $ 176 , 118 ====== The DOE settlement regulatory liability was established for the reimbursement from the DOE for costs incurred by the District in conjunction with the disposal of spent nuclear fuel from CNS. Details of the District's DOE settlement are included in Note 12 in the Notes to Financial Statements. Beginning in 2015 , the District began collecting revenues for the costs of the 2016 CNS refueling and maintenance outage. This regulatory liab i lity was included in Other deferred inflows on the Balance Sheets and amortized through revenue during 2016 , the year of the outage. The District began collecting revenues for the 2018 CNS refueling and maintenance outage in 2017. The District includes in rates the costs associated with nuclear fuel disposal.

Such collections were remitted to the DOE under the Nuclea r Waste Policy Act until the DOE adjusted the spent fuel disposal fee to zero, effective May 16 , 2014. The Boa rd authorized the use of regulatory accounting for the continued collection of these costs. This approach ensures costs are recognized in the appropriate period w i th customers 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.

Additional details of the District's DOE spent nuclear fuel collections are included in Note 12 in the Notes to Financial Statements. 35 Financial Report The follow i ng table summar i zes the ba l ance of Deferred outflows of resources as of December 31 , 2016 and 2015 (i n OOO's): 2016 2015 Unamort i zed cost of refunded debt . .. . . . ... .. . .. . . . . . . . .. . . . .. ...... .. . . . . .. . . . . . .

... . . . .. ....... .. . $ 42 , 664 $ 40 , 775 OPEB contributions after measurement date ................... ...............

.................. 74 , 658 Unamortized OPEB loss for earnings .................................................

............. 3 , 862 Unamortized OPEB loss for experience

..... .. ... . .. . ..... ... . . . ... . . . . . . .. . . ... .. ... . . . . .. . . . . ... 3 , 769 --.-----$ 124 , 953 $ 40 , 775 The following table summarizes the balance of Other deferred inflows of resources as of December 31 , 2016 and 2015 (in OOO's): 2016 2015 DOE settlements

...........

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

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

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

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

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

.............. . 24 , 688 Nuclear fuel disposal collections

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

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

..................... . 15 , 098 9 , 539 Renewable Energy Facility Sales Tax Refund .........................................

......... . 4 , 786 $ 102 , 548 $ 113 , 728 N. Net Position -Net position is made up of three components:

Net i nvestment in capital assets , Restr i cted , and Unrestr i cted. 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 a l so i ncluded long-term capacity contracts net of the outstanding balances of any bonds or notes attributable to these assets. Restricted net position consisted of the Pr i mary account in the Debt reserve funds that are required deposits under the Resolution , and the Decommission i ng funds net of any related liabi l ities. Unrestricted net position consisted of any remaining net position that does not meet the definition of Net investment in capital assets or Restr i cted , and are used to provide for working capital to fund non-nuclear fuel and inventory requ i rements , as well as other operating needs of the District.

0. Use of Estimates

-The preparation of financial statements in conform i ty with accounting principles generally accepted i n the Un i ted 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 dur i ng the report i ng per i od. Actual results could differ from those estimates. P. Recent Accounting Pronouncements

-GASS Statement No. 85 , Omnibus 2017 , was issued in March 2017. This Statement addresses practice issues that were ident i fied during implementation and application of certain GASS statements including statements on OPES. This Statement provides clarification for the presentation of payroll-related measures i n required supplementary information for purposes of reporting by OPEB plans and employers that provide OPEB. This Statement requires the disclosure of covered-employee payroll by the employer if contr i butions to the OPES 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 OPES plan. However , the financial statements for the OPES plan should not present any measure of payroll if contributions to the plan are not based on a measure of pay. Th i s 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 OPES gu i dance was the only portion of this Statement with an impact on the District.

Financial Report 36 GASS Statement No. 84 , Fiduc i ary Activities , was issued i n January 2017. This Statement addresses accounting and financia l reporting requirements for certain fiduciary funds in the basic financial statements. Governments with act i vit i es meeting the cr i teria are required to present a statement of fiduc i ary net position and a statement of changes in fiduciary net position. The requirements of this Statement are effective for reporting periods beginn i ng after December 15 , 2018. The implementation of this Statement will require the District to include fiduciary statements with the statements for its business-type activities. GASS Statement No. 83 , Certa i n Asset Retirement Obligations , was issued i n November 2016. This Statement addresses accounting and financial reporting requ i rements for certa i n AROs. This Statement imposes requirements in regards to the ARO liab i lity recogn i tion, measurement and specifics on when re-measurement should occur. This Statement also requ i res disclosures regard i ng the methods and assumptions used to estimate the ARO , the remaining useful life of capital assets assoc i ated with the liability , any governmenta l legal fund i ng requ i rements , 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 implementation of this Statement will impact the District's financial statements. The District has reported AROs under the FASS guidance , wh i ch differs from the GASS guidance. The FASS guidance requires measurement of the liability based on the present value of the asset's disposal costs whereas measurement under this GASS Statement is based on the best estimate of the current value of cash outlays expected to be incurred. The FASS guidance required the recognition of a corresponding capital asset whereas the GASS Statement requires the recognition of a corresponding deferred outflow of resources. The District uses regulatory accounting for AROs under the FASS gu i dance and plans to continue to use regulatory accounting under the GASS guidance. GASS Statement No. 75 , Accounting and Financial Reporting for Postemployment Benefits Other Than Pens i ons , was issued in June 2015. The requirements of th i s Statement will improve accounting and financial reporting for OPES. This Statement requires the liability for defined benefit OPES (net OPES 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 OPES l i ability), less the amount of the OPES 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 OPES 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 an unrealized net gain of less than $0.1 million for the year ended December 31 , 2016 and an unreal i zed net loss of $1.2 million for the year ended December 31 , 2015. The fair va l ue of all cash and investments , regardless of classification on the Balance Sheets , were as follows at December 31 (i n OOO's): Fa i r Value U.S. Treasury and go-.emment agency secu ri ties . $ 936 , 317 Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181,438 Municipal bonds................................................ 11 , 901 Cash and cash equivalents

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

..........

....... -$-=---1.-2.,,..58-

.-9-17---Portfol i o weighted a\erage maturity ................................... . 2016 We i ghted A-.erage Maturity (Years) 4.0 9.6 12.4 4.5 Fair Value $ 909 , 449 196 , 766 10 , 184 108 , 054 $1 , 224,453 2015 We i ghted A\erage Maturity (Years) 3.7 11.8 15.6 4.8 Interest Rate Risk-The investment strategy for all investments , except for the decommissioning funds , is to buy and hold securities until maturity , which minim i zes interest rate r i sk. The investment strategy for decommissioning 3 7 Financial Report funds is to actively manage the divers i fication of multiple asset classes to achieve a rate of return equal to or exceeding the rate used in the decommissioning funding plan model assumptions. Accordingly , securities are bought and sold prior to maturity to increase opportunities for higher investment returns. Credit Risk-The Distric t 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 i nves tments 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 Securities held by various depositories , or an irrevocable , nontransferable, unconditional letter of credit issued by a Federal Home Loan Bank. 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 $20.9 million and $6.9 million as of December 31 , 2016 and 2015 , respectively. Re1.enue funds -Cash and cash equivalents

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

.................... $ Re1.enue funds -ln1.estments

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

................... . $ 2016 123 , 678 352 , 382 476 , 060 2015 $ 91 , 948 393 , 538 $ 485,486 The Construction funds are used for capital i mprovemen ts , 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. 2016 2015 Construction funds -Cash and cash equivalents

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

...........

... $ 25 $ Construction funds -ln1.es tments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 , 179 76 , 503 $ 106 , 204 $ 76 , 503 Financial Report 38 The Debt reserve funds , as established under the Resolution , consist of a Primary account and a Secondary account. The D i strict is required by the Resolution to maintain an amount equal to 50% of the maximum amount of interest accrued i n the current or any future year in the Primary account. Such amount totaled $38.7 million and $40.5 million as of December 31 , 2016 and 2015 , respectively. The Secondary account can be established at such amounts and can be utilized for any l awful purpose as determined by the District's Board. Such account totaled $51.3 million and $51.3 million as of December 31 , 2016 and 2015 , respectively. 2016 Debt reser.e funds -Cash and cash equ i valents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Debt reser.e funds -ln'loestments

................................................................. . 90 , 032 $ 90 , 032 $ $ 2015 50 9 1, 722 91 , 772 The Employee Benefit funds consist of a self-funded hospital-medical benefit plan for active employees only at December 31 , 2016. The employee benefit funds consist of both a self-funded hospital-medical benefit plan (for active and inactive employees) and a ret i red emp l oyee life i nsurance benefit plan at December 31 , 2015. 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 $4.9 mill i on and $2.3 million at December 31 , 2016 and 2015 , respective l y. The retired employee life insurance benefit plan is funded by an irrevocable OPEB Trust. Commencing with the implementation of GASB 75 in 2016 , the Trust assets for inactive employees are reported in the fiduciary financial statements for the OPEB Trust instead of in the Employee benefit funds. There was $1.1 million of OPEB assets reported i n Employee benefit funds at December 31 , 2015. For additional information on OPEB see Note 11. 2016 Employee benefit funds -Cash and cash equivalents . .. . . . .. ... .......... ... . .... .. . . . .. . . $ 1 , 843 Employee benefit funds -ln\oestments

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

...... ... . .. 3 , 008 ------$ 4 , 851 $ $ 2015 1 , 349 1 , 995 3 , 344 The Decommissioning funds are ut i lized to account for the investments held to fund the estimated cost of decommiss i oning CNS when its operating l i cense expires. The Decommissioning funds are held by outside trustees or custodians i n compliance with the decommission i ng funding plans approved by the Board which are invested primarily in f i xed income governmental securities.

2016 2015 Decommissioning funds -Cash and cash equ i valents .. . . .. ... . ...... .. . . . .... .. . .. ........ $ 3 , 715 $ 14 , 707 Decommissioning funds -ln\oestments

.. .. ... .. ......... .. . . ... . .. . . . . ....... .. . . . . . . . ........... 578 , 055 552 , 641 -...,..-----

$ 581 , 770 $ 567 , 348 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 l i ability (an exit price) in the principal or most advantageous market for the asset or l iabi li ty in an orderly transaction between market participants at the measurement date. GASB Statement No. 72 (" GASB 72"), Fair Value Measurement and Application , establishes a fair value hierarchy that prioritizes the inputs used to measure fa i r 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 classified i n 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 GASB 72 are as follows: Level 1 -Quoted prices are available in active markets for identical assets or l iabilities as of the reporting date. Active markets are those i n wh i ch transactions for the asset or liability occur in sufficient frequency and volume to 39 Financial Report provide pricing information on an ongoing basis. The D i strict'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 included in Level 1 , which are either directly or indirectly observable for the asset or liability as of the reporting date. Level 2 inputs include the following:

quoted prices for similar assets or liabi l ities in active markets;

quoted prices for identical assets or liabilities in inactive markets;

inputs other than quoted prices that are observab l e 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 include U.S. Treasury and government agency securities held in the Revenue funds and other Special Purpose Funds and U.S. Treasury and government agency securities , corporate bonds , and municipal bonds held in the Decommissioning funds. Level 3 -Pricing inputs include 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 methodo l ogies using significant unobservable inputs. The District currently does not have a n y Level 3 assets or liabilities.

The District performs an analysis annually to determine the appropriate hierarchy level classification of the assets and liabilities that are included w i thin the scope of GASB 72. Financial assets and liabilities are classified 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 , 2016 and 2015. The following tables set forth the District's financial assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31, (in OOO's): 2016 Lewi 1 Lewi 2 Lewi 3 Total Assets: Rewnue and spec i al purpose funds , excluding decommissioning

U.S. Treasury and gowmment agency securities

............ $ $ 551 , 602 $ $ 55 1 , 602 Cash and cash equivalents

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

125 , 546 125 , 546 Decommission i ng funds: U.S. Treasury and gowmment 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 2015 Lewi 1 Lewi 2 Lewi 3 Total Assets: Rewnue and special purpose funds , excluding decomm i ssioning: U.S. Treasury and gowmment agency securities

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

$ $ 563 , 758 $ $ 563 , 758 Cash and cash equivalents

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

.. 93 , 347 93 , 347 Decommissioning funds: U.S. Treasury and gowmment agency securities

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

345 , 691 345 , 691 Corporate bonds ........................................................... 196 , 766 196,766 Municipal bonds ..........

...........

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

............ 10 , 184 10 , 184 Cash and cash equivalents

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

..... 14 , 707 14,707 $ 108 , 054 $1 , 116 , 399 $ $ 1 , 224 , 453 Rna n dalReport 40

4. UTILITY PLANT: Utility plant activity for the year ended December 31 , 2016 , was as follows (in OOO's): Decembe r 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 util ity plant .............

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

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

168,420 70 , 064 (40,754) 197 , 730 Depreciable utility plant: Generation

-Fossil .................................... 1 , 573 , 880 65 , 818 (10 , 103) 1 , 629 , 595 Generation

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

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

.... 1 , 384 , 031 68,415 (10,481) 1,441 , 965 Transmission

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

.............. 1 , 172 , 108 86 , 994 (4 , 682) 1 , 254,420 Distribution

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

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

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

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

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

(2 , 620 , 091) (11 8 , 561) 30 , 616 (2 , 708 , 036) Depreciable utility plant , net ................

... 2 , 066 , 555 122,530 2 , 189 , 085 Utility plant acti"1ty , net ...........

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

$ 2 , 508 , 971 $ 382 , 611 $ (294 , 776) $ 2 , 596 , 806

flllclear fuel decreases represented arrortization of $40.8 rrillion. Utility plant activity for the year ended December 31 , 2015 , was as follows (in OOO's ): December 31 , December 31 , 2014 Increases Decreases 2015 Nondepreciable utility plant: Land and improvements

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

$ 63 , 336 $ 1 , 036 $ (2) $ 64 , 370 Construction in progress ............................. 151 , 712 180 , 117 (122 , 203) 209 , 626 Total nondepreciable utility plant ............. 215,048 181 , 153 (122 , 205) 273 , 996 Nuclear fuel* ............

...................................... 202 , 094 13 , 952 (47 , 626) 168,420 Depreciable utility plant: Generation

-Fossil .........................

........... 1 , 550 , 786 31,495 (8 , 401) 1 , 573 , 880 Generat i on -Nuclear ....................

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

1 , 353 , 374 31 , 240 (583) 1 , 384 , 03 1 Transmission

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

........................... 1 , 153 , 704 26 , 147 (7 , 743) 1 , 172 , 108 Distribut i on ..............................

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

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

........ 335,407 14,487 (15 , 058) 334 , 836 Total depreciable utility plant 4 , 611 , 164 110 , 246 (34 , 764) 4 , 686 , 646 Less reserve for depreciation

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

... (2 , 533 , 100) (121,755) 34 , 764 (2 , 620 , 091) Depreciable utility plant , net ................... 2 , 078 , 064 (11 , 509) 2 , 066 , 555 Ut i li ty plant activity , net ...................................

$ 2,495 , 206 $ 183 , 596 $ (169 , 831) $ 2 , 508 , 971 *Nuclear fuel dec re ases represented arrortization of $47.6 rrillion. 41 Financial Report

5. LONG-TERM CAPACITY CONTRACTS: Long-term capacity contracts include the District's share of the construction costs of Omaha Public Power District's (" OPPD") 663 megawatt (" MW") Nebraska City Station Un i t 2 (" NC2") coal-fired power plant. The District has a part i cipation power ag r eement with OPPD for a 23.7% share of the power from this plant. NC2 began commercial operation on May 1 , 2009 , at which t i me the District began amortizing the amount of the capacity contract associated with the plant on a straight-line basis over the 40-year est i mated useful life of the plant. Accumulated amortization was $35.4 m i llion and $30.8 m i ll i on in 2016 and 2015 , respectively.

The unamortized amount of the plant capacity contract was $143.7 mill i on and $154.8 million as of December 31 , 2016 and 2015 , respectively , of wh i ch $4.4 million was included in Prepayments and other current assets as of December 31 , 2016 and $4.6 million in 2015. The Distr i ct's share of NC2 working capital was also included in Prepayments and other current assets and was $6.5 million as of December 31 , 2016. Long-term capacity contracts also include the District's purchase of the capacity of a 50 MW hydroelectric generating fac i l i ty owned and operated by The Central Nebraska Public Power and Irrigation District (" Central"). The District is amort i zing the contract on a straight-line basis over the 40-year estimated useful life of the facility. Accumulated amortiza t ion was $64.3 m i ll i on and $62.0 million at December 31 , 2016 and 2015 , respect i vely. The unamortized amount of the Central capac i ty contract was $22.4 million and $24.7 million at December 31 , 2016 and 2015 , respectively , of which $2.3 million was included in Prepayments and other current assets as of December 31 , 2016 and 2015. The Distr i ct has an agreement whereby Central makes available all the production of the facil i ty and the District pays all costs of operating and maintaining the fac i lity plus a charge based on the amount of energy delivered t o the District.

Costs of $2.5 million and $2.3 million in 2016 and 2015 , respect i vely , are included i n Power purchased in the accompanying Statements of Revenues , Expenses , and Changes in Net Position. 6. INVESTMENT IN THE ENERGY AUTHORITY:

The District has an investment in The Energy Authority

(" TEA"), a nonprofit corporation headquartered i n Jacksonv i lle , Florida , and incorporated i n Georgia. TEA provides public power uti l ities access to dedicated resources and advanced technology systems. The Distr i ct's interest in TEA was 16.67% as of December 31 , 2016 and 2015 , respectively.

In addition to the District , the following utilities have i nterests of 16.67% each as of December 31 , 2016 and 2015: 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 , 2016 and 2015: C i ty Utilities of Springfield , Missouri; Cowlitz County Public Utility District (Wash i ngton) and Gainesville Regional Utilities (Florida). Such investment was $6.4 million and $7.0 million as of December 31 , 2016 and 2015 , respectively.

TEA's revenues and costs are allocated to members pursuant to Settlement Procedures under the 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 ob li gated to guaranty , directly or indirectly , TEA's electric trad i ng activities in an amount up to $28.9 million plus attorney's fees which any party claim i ng 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 fa i led to del i ver or prov i de energy , capacity , or transmission as required under a contract.

The Distr i ct's exposure relating to TEA is lim i ted to the District's investment in TEA , any accounts receivab l e from TEA , and trade guarantees provided to TEA by the District.

Upon the District making any payments under its e l ectric guaranty , it has certain contr i bution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equa l ized ratab l y, based upon each member's interest in TEA. 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 obl i gations by causing to be provided advance notice to the beneficiaries t hereof. Such Financial Report 42 termination of its guaranty obligations only applies to TEA transactions not yet ente r ed into at the time the terminat i on takes effect. The District has no l iab i lit i es for these guarantees as of December 31 , 2016 and 20 1 5. F i nancial statements for TEA may be obtained at The Energy Author i ty , 301 W. Bay Street , Suite 2600 , Jacksonville , Florida , 32202. 7. DEBT: The follow i ng table summarizes the debt balances , net of current maturities , as of December 31 , 2016 and 2015 , and activity for 2016 (i n OOO's): Princ i pa l Amoun t s Due December 31 , December 31 , W i th i n One 2015 Increases Decreases 20 1 6 Year Re\*nue bonds ......................... $ 1 , 596 , 972 $ 354 , 776 $ (272 , 905) $ 1 , 678 , 844 $ 81 , 250 Commerc i al paper notes ............ 83 , 000 88 , 365 (97 , 365) 74 , 000 74 , 000 Rel.()l\ing credit agreements

....... 158 , 700 75 , 443 (45 , 219) 188 , 924 Tota l long-term debt acti\ity .. $ 1 , 838 , 672 $ 518 , 584 $ (415,489) $ 1 , 94 1, 768 $ 155 , 250 The following table summarizes the debt balances , net of current maturities , as of December 31 , 2015 and 2014 , and activity for 2015 (i n OOO's): Princ i pa l Amounts Due Decembe r 31 , December 31 , W i th i n One 2014 Increases Decreases 2015 Year Re\*nue bonds ......................... $ 1 , 710 , 850 $ 261 , 189 $ (375 , 067) $ 1 , 596 , 972 $ 114 , 860 Commercial paper notes ............ 92 , 000 (9 , 000) 83 , 000 Rel.()l\ing credit agreements

....... 185 , 503 10 , 364 (37 , 167) 158 , 700 Total long-term debt act i\ity .. $ 1 , 988 , 353 $ 271 , 553 $ (421 , 234) $ 1 , 838 , 672 $ 114 , 860 Revenue Bonds 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. The Distr i ct plans to issue additional revenue bonds in 2017 to finance transmission projects. Also in Apr i l 2017 , the D i str i ct entered into an escrow deposit agreement in conjunction w i th the refunding of certain of the:

Genera l Revenue Bonds , 2007 Ser i es B , having maturity dates ranging from January 1 , 2018 throug h January 1 , 2028 In November 2016 , the District issued General Revenue Bonds , 2016 Ser i es C and 2016 Ser i es D , in the amount of $113.5 million to finance the costs of certain generat i on and transm i ss i on capital projects and to refund a portion of Commercial Paper Notes , Series A. The District also issued in November 2016 , General Revenue Bonds , 2016 Series E (Taxable), in the amount of $56.1 m i llion to fund a port i on 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. 43 Financial Report A l so in February 2016 , the D i str i ct entered into an escrow depos i t agreement i n con j unction w i th the advanced refunding of certa i n of the:

Gene r al Revenue Bonds , 2007 Ser i es B , hav i ng maturity dates rang i ng from January 1 , 2026 t hrough January 1 , 2037

General Revenue Bonds , 2008 Ser i es B , hav i ng maturity dates rang i ng from January 1 , 2024 through January 1 , 2041

General Revenue Bonds , 2012 Series C , maturing on January 1 , 2025 through January1 , 2026. In January 2016 , the D i strict issued TECP in the amount of $43.6 mill i on to refund a port i on of the General Revenue Bonds, 2005 Ser i es C and the General Reven u e Bonds , 2006 Series A. In February 2015 , the D i strict issued General Revenue Bonds , 2015 Series A , in the amount of $223.0 mi lli on to advance refund $239.2 million of bonds. The refunding reduced tota l debt service payments over the l i fe of the bonds by $42.0 million , which resulted in present value sav i ngs of $26.1 million. A l so in February 2015 , the Distr i ct entered into an escrow deposit agreement i n conjunction with the advanced refunding of certain of the:

Genera l Revenue Bonds , 2005 Series C , having maturity dates rang i ng from January 1 , 2026 through January 1 , 2041

General Revenue Bonds , 2006 Series A , hav i ng maturity dates rang i ng from January 1 , 2036 through January 1 , 2041 , and

General Revenue Bonds , 2007 Ser i es B , hav i ng maturity dates rang i ng from January 1 , 2023 through January 1 , 2037

General Revenue Bonds , 2008 Ser i es B , hav i ng maturity dates rang i ng from January 1 , 2024 through January 1 , 2038 , and

General Revenue Bonds , 2012 Ser i es C , maturing on January 1 , 2024 Certain of the General Revenue Bonds , from the following series , with outstanding principal amounts that aggregate

$407.9 million as of December 31 , 2016 , were legally defeased and are no longer outstand i ng: 2007 Series B , 2008 Ser i es B , and 2012 Series C. Debt service payments and pr i nc i pal payments of the General Revenue Bonds as of December 31 , 2016 , are as follows (i n OOO's): Debt Ser\1ce P ri ncipal Year Payments Payments 2017 ******************

- - - - $ 158 , 295 $ 81 , 250 2018 ******************************************** 173 , 151 100 , 010 2019 ***************************

- - - - 149 , 606 81 , 205 2020 ............................................ 149 , 511 84 , 895 2021 ..........................

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

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

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

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

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

326 , 864 261 , 965 2037-2041

117 , 854 98 , 355 2042-2045

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

32,469 30,030 Total Payments ..........

.................. $ 2,429 , 203 $ 1 , 611 , 915 The fair va l ue of outstanding revenue bonds was determined using currently publ i shed rates. The fair value was est i mated to be $1 , 750.1 m i l l i on and $1 , 765.4 mil l ion at December 31 , 2016 and 2015 , respectively. Financial Report 44 Commercial Paper Notes The District is authorized to issue up to $150.0 million of TECP notes. A $150.0 million line of credit expiring July 1 , 2017 , is maintained with two commercial banks to support the sale of the TECP notes. The Distr i ct had $74.0 million and $83.0 million of TECP notes outstanding at December 31 , 2016 and 2015 , respectively.

The proceeds of the TECP notes have been used to provide short-term financing for certain capital additions and for other lawful purposes of the District.

The effective interest rate on outstanding TECP notes was 0.46% and 0.06% for 2016 and 2015 , respectively. The notes outstanding are anticipated to be retired by future collections through electric rates and the i ssuance of revenue bonds or other debt. The carrying value of the commercial paper notes approximates market value due to the short-term nature of the notes. Line of Credit Agreement The District has a line of credit of $150.0 million expiring July 1 , 2017 , that supports the payment of the pr i ncipal outstanding of the TECP notes. No amounts were drawn on the l i ne of credit as of December 31 , 2016 and 2015. Taxable Revolving Credit Agreement The District has entered into a Taxable Revolving C r edit Agreement

(" TRCA") 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 D i strict to increase the loan commitments to $300.0 million. The District had outstanding balances under the TRCA of $188.9 million and $158.7 million , at December 31 , 2016 and 20 1 5 , respectively. The TRCA was renewed on July 31, 2015 and terminates on July 30 , 2018. The outstanding amount is anticipated to be retired by future collect i ons through electric rates and the issuance of revenue bonds. The carry i ng value of the revolving credit agreements approximates market value due to the short-term nature of the agreements.

45 Financial Report Rel.*nue bonds c ons i s t of the following (in OOO's ex c ept inte re st rates): December 3 1 , Interest Rate 20 1 6 General Rel.*nue Bonds: 2005 Series C: Serial Bonds: 201&-2025 , 2040 ..................... 3.875% -5.00% $ 2006 Series A: Serial Bonds: 203&-2040

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

... . 4.375% 2007 Se ri es B: Serial Bonds: 201&-2026

..........

.................... 4.375% -5.00% Term Bonds: 2027-203 1 .............................. 4.65% 2032-2036 .............................. 5.00% 4.00% -5.00% 5.00% 5.00% 5.00% 6.606% 7.399% 3.50% -4.25% 3.98% -4.73% 5.323% 5.423% 2.858% -4.18% 3.00% -5.00% 4.00% 5.00% 2.50% -5.00% 3.00% -5.00% 2.00% -5.00% 3.625% 3.625% 3.00% -5.00% 3.00% -5.00% 2.00% -5.00% 4.00% 4.125% 3.00% -5.00% 3.00% -5.00% 3.00% -5.00% 5.00% 3.125% -5.00% 5.00% 5.00% 5.00% 3.00% -5.00% 2.00% -5.00% 5.00% 5.00% 2.337% -3.567% 97,4 1 5 9 , 620 10 , 700 17,465 32 , 890 4 , 605 31 , 875 27 , 985 54 , 190 3 , 600 48,760 6 , 165 14 , 180 190,410 92 , 320 2 , 320 4 , 155 11 , 045 9 1 , 100 153 , 630 31 , 650 1 , 945 143 , 025 119 , 400 56 , 485 46 , 205 65 , 210 5 , 595 67 , 255 1 , 165 70 , 685 2015 $ 44 , 230 400 111 , 825 31 , 1 90 7 , 1 20 38 , 785 22 , 860 40 , 375 7 , 180 17,465 32 , 890 6 , 595 31 , 875 27 , 985 54 , 190 4 , 415 64 , 520 6 , 165 14 , 180 7 , 115 1 98 , 3 1 0 95 , 875 2 , 320 4 , 155 37 , 340 103 , 8 1 5 156 , 145 31 , 650 1 , 945 162 , 415 119,400 56 , 915 46 , 205 1 , 587 , 850 123 , 982 1 ,711 , 832 (114 , 860) $1 , 596 , 972 Ananclal Report 46

8. PAYMENTS IN LIEU OF TAXES: The District is required to make payments in lieu of taxes , aggregating 5% of the gross revenue derived from electric retail sa l es within the city limits of incorporated cities and towns served directly by the District.

Such payments totaled $10.1 million and $10.0 million for each of the years ended December31 , 2016 and 2015 , respec t ively. 9. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations

(" ARO") are calculated at the present value of a long-lived asset's applicable disposal costs and are recorded in the period in which the liability is incurred. This liability is accreted during the remaining life of the associated assets and adjusted periodically based upon updated estimates. The District has recorded an obligation for the fair value of its legal liability for the ARO associated with CNS , Ainsworth Wind Energy Facility , various ash landfills at coal-fired power stations, removal of asbestos at the va*rious coal , gas , and hydro generating facilities , polychlorinated biphenyls from substation and distribution equipment , and underground storage tanks as well as abandonment of water wells. Studies were completed for the ARO for the Ainsworth Wind Energy Facility and CNS in 2016 and 2015 , respectively. The ARO adjustment for 2016 was due primar i ly to the add i tion of a liability for the Ainsworth Wind Energy Facility , that was more than offset by a reduction in l iabilities for asset retirements. The ARO reduction of $477.8 million for 2015 was due primarily to the updated 2015 study and refreshed assumptions for CNS. ASC 410 , Asset Retirement and Environmental Obligations , requires capitalization of the costs to the related asset and depreciation of these costs over the same period as the related asset. The District does not use depreciation as a cost component for rates. Accordingly , the District has establ i shed a regulatory asset , under accounting guidance in Re10 , for the costs that will be recovered in future rates. A significant amount of the ARO was funded by decommissioning funds of $581.8 million and $567.3 million as of December 31 , 2016 and 2015 , respective l y. See Note 2 for additional information. The following tab l e shows changes to the ARO that occurred during the years ended December 31 , 2016 and 2015 , and are inc l uded in Other long-term liabilities section of the accompanying Balance Sheets as of December 31 , (in OOO's): 2016 2015 Balance , beginning of year .........................................

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

..........

....... . $ 600 , 311 $ 1 , 026 , 357 Accretion

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

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

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

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

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

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

................ .. $ 627 , 707 -------$ 600 , 311 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 , 931and1 , 955 active plan members at December 31 , 2016 and 2015 , 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 Distr i ct contr i butes two times the Plan member's contribution based on covered salary up to $40 , 000. On covered salary greater than $40 , 000 , the D i strict contributes one times the Plan member's contribution. The Participants

' contributions were $13.4 million and $12.8 million for 2016 and 2015 , respectively. The District's matching contribut i ons were $12.3 million and $12.1 million for 2016 and 2015 , respectively. Total contributions of $1.4 million were accrued in Accounts payable and accrued liabilities as of December 31 , 2016 and 2015. 4 7 Financial Report P l an members are immediately vested in the i r own contr i but i ons and earn i ngs and become vested in the D i s t rict's contributions and earn i ngs based on t he following vesting schedu l e: Years of Vest i ng Participat i on 5 years or more ................................... . 4 years ............................................... . 3 years ............................................... . 2 years ............................................... . Less than 2 years ............................... . Percent 100% 75% 50% 25% 0% Nonvested D i str i ct contributions are fi rst used to cover Plan adm i n i strative expenses and any remain i ng forfe i tures are al l ocated back to Plan part i cipants. Employees may a l so contr i bute to a defined cont r ibution 457 pension plan (" 457 P l an"). The 457 Plan is a deferred i nvestment option with no D i strict match. Pay per i od contribut i ons can be elected and changed a t any t i me. Early withdrawals can be made from the 457 P l an following separat i on of serv i ce regardless of age wi t h no IRS penalty. Income taxes are owed on any w i thd r awals. The Participants

' contributions were $2.1 million and $2.0 m i llion for 2016 and 2015 , respectively. 11. OTHER POSTEMPLOYMENT BENEFITS: The District i mplemented the provisions of GASS Statement No. 75 (" GASS 75"), Accounting and F i nancial Reporting for Postemployment Benefits Other than Pensions , in 2016. The D i strict has elected to early adopt t he provisions of GASB 75. GASS 75 requires retroact i ve app li cat i on unless i t i s i mpractical to apply the requirements on a r etrospect i ve basis. The District has concluded that retrospective application is impract i cal based on a cosUbenefit analysis and other considerat i ons. The Dis trict would incur additional third-party actuarial costs to develop the necessary data for retrospect i ve app li ca t ion. Add i tionally , given the D i strict's application of regu l atory accounting , the impact of app l ying prov i s i ons of GASB 75 to prior per i ods would be entirely offset by the recognition of a regulatory asset reflecti n g the future recovery of any OPEB costs. Accord i ngly , retrospective applica ti on of GASB 75 would not i mpact the D i str i ct's net pos i tion for 2015. Further , there was no impact to beginning net position as a resu l t of the i mplementation of the prov i sions of GASS 75 in 20 1 6. A. General information regarding the OPEB Plan -Plan Description The Distric t's Post-Employment Med i ca l and Life Benefits Plan (" Plan") provides postemployment hosp i tamedical and life i nsurance benefits to qualifying retirees , surv i ving spouses , and employees on long-te r m disability and their dependents. Benefits and r elated el i g i bility , fund i ng and other Plan provisions , fo r this s i ng lemployer , defined benefit P l an , are author i zed by the Board. The Plan has been amended over the years and prov i des d i fferent benefits based on hire date and/or the age of t h e employee. The D i strict pays all or part of the cost (determ i ned by age) of certain hospital-med i cal premiums for employees hired on or pr i or to December 31 , 1992. Employees hired on or after January 1 , 1993 , are subject to a contr i bution cap that limits the District's portion of the cost of such cove r age to the full premium the year the employee reached age 65 , or the year in which the employee retires i f older than age 65. Employees hired on o r after January 1 , 1999 , are not el i gib l e for other postemploymen t hospital-medical benefits once they reach age 65. Employees hired on or after January 1 , 2004 , a r e not elig i ble for other postemployment hospital-medical benefits once they retire. The District amended the P l an effective July 1 , 2007 , to provide that any former employee who is rehired will receive credit for prior years of serv i ce. The Distr i ct further amended the Plan effective September 1 , 2007 , to provide that employees hired or r ehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for other postemployment hosp i tal-med i ca l benefits once they retire. In May 2015 , the Board approved a change for Med i care-el i gible retirees for prescr i ption drugs from the District's self-i nsured employee prescript i on plan to a group insured Medicare Part D supplement effective January 1, 2016. The D i str i ct also provides a postemployment deat h benefit of $5 , 000 for qua li fying employees.

Financial Report 48 Employees Covered by Benefit Terms The follow i ng tab l e shows the employees covered by the hospital-medical benefit terms as of January 1: 2016 2015 Active employees

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

.......................................................... . 1 , 175 1,260 67 1 , 205 1 , 238 70 Inactive emp l oyees or beneficiaries in retirement status ..................... . Inactive employees or beneficiaries in long-term disability status ........ . Total emp l oyees covered by benefit terms ..................................... . 2 , 502 2 , 513 The following table shows the emp l oyees covered by the life insura n ce benefit terms as of January 1: 2016 2015 Active employees

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

...........

.................. . 2 , 003 1 , 077 74 1 , 980 1 , 047 77 Inactive emp l oyees i n retirement status ........................................... . Inactive emp l oyees in long-term disability status ............................... . Total employees covered by benefit terms ..................................... . 3 , 154 3 , 104 Contribu t io n s 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 contr i butions were $74.7 million in 2016 , which included $45.7 million of financed contributions deposited in the Trust , $24.5 million of revenue funded contr i butions deposited in the Trust and $4.5 million paid directly by the District for the cost of benefits/expenses. Certain wholesale customers under the 2002 Contracts filed for binding arb i tration in May 2016 re l ated to their objection of the inclusion in rates additional collections of previously incurred OPEB costs. Collections from customers of $1.6 million collected under the 2002 Contracts for these OPEB costs in 2016 were not transferred to the Trust , pending the outcome of the arbitration. Additional information about the arbitration is disclosed in Note 12. The District contributed

$28.4 million in 2015 , which included $11.5 million deposited in the Trust and $16.9 million paid directly by the District for the cost of benefits/expenses. Total contributions in 2014 were $29.8 million, which included $11.9 million deposited in the Trust and $17 .9 m i llion paid for the cost of benefits/expenses. Contributions from Plan members are the required premi u m share , which is based on hire date and/or age. Contributions from P l an members were $0.5 million , $0.6 million and $0.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Members do not contribute to the cost of the life insurance benefits. B. Net OPEB Liability

-The District's net OPEB liability was measured as of January 1 , 2016 , and the total OPEB l i ability used to calculate the net OPEB liability was determined by an actuarial valuation as of that date. Actuarial Assumptions The total O P EB liability in t he January 1 , 2016, actuarial valuation was determined using the following actuarial assu m ptions , applied to all periods included in the measurement , unless otherwise specified:

Actuarial cost method

Amortization method

Amort i zation period

Asset valuation method

Discount rate

Healthcare cost trend rates

Inflation

Investment rate of return

Mortality

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

8% initial , ultimate 5% Post-Medicare

6.75% initial , ultimate 5% 2.1% 6.25%, net of investment expense , includ i ng inflation RP-2014 Aggrega t e table p ro jected bac k to 2016 using Scale MP-2014 and projected forward using Scale MP-2015 with generational projection Varies by age The actuarial assumptions used i n th e Janua ry 1 , 2016 , va l uat i on were based on the resu l ts of an a c tuar i a l experience study for the per i od January 1, 20 1 5 t hrough De c ember 31 , 2015. The long-term expected rate of return on OPES plan investments was determined using a build i ng-block method in which best-est i mate ranges of expected future rates of r e t urn (expected returns , net of OPES plan investment expense and i nflat i on) are developed for each major asset class. These ranges are combined to produce the l ong-term expected rate of return by weighting the expected future real rates of return by the target asset allocat i on percentage and by adding expected i nflat i on. The target allocation and best estimates of geometr ic real rates of return for each major asset class are summar i zed in the follow i ng table fo r the valuat i on measu r ement date of January 1 , 2016: Asset C l ass Long-Term Expected Target Allocat i on Real Rate of Re t urn Equity .............................

............ . F i xed Income .........................

...... . Discount Rate 68% 32% 100% 6.8% 3.5% The discount rate used to measure the total OPES l i ab i l i ty was 6.25%. The project i on of cash flows used to determ i ne the discount rate assumed that contr i but i ons will be made at rates equal to the actuar i ally-determ i ned contribut i on rates. Based on those assumptions , the OPES Plan's fiduciary net position was projected to be ava i lable to make all projected benefit payments for current act i ve and inactive employees. Therefore , the lo n gterm expected rate of return on OPES plan i nvestments was appl i ed to all periods of projected benefit payments to determ i ne the tota l OPES liab i l i ty. C. Changes in the Net OPEB Liability-The following table shows the Total OPES Liabil i ty , Plan F i duciary Net Pos i tion and Net OPEB Liabi l ity as o f January 1 , 2015 and January 1 , 2016 , and the changes during th i s period , based on the valuation measuremen t date of January 1 , 2016 (in OOO's ): Year Ended December 31 , 2016 Tota l OPES Plan Fiduciary Net OPES Liabi li ty Net Pos i t i on Liabi li t y (a) (b) (a-b) Balances at 1/1/20 1 6 (Based on 1/1/2015 Measurement Date) ..........

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

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

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

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

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

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

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

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

.. 13 , 657 13 , 657 Changes of assumpt i ons ............

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

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

....... . (9 , 149) (9 , 1 49) Contribut i ons-employer

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

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

..... .. 28 , 242 (28 , 24 2) Net i n-.estment income ......................

........................................... . (453) 45 3 Benefit payments ......................................................................

.. .. (1 6 , 902) (1 6 , 902) Adm i nistrat i-.e expense ..................................

............................... . (1 50) 1 50 Net Changes ..........................................................

........................ . 10 , 71 1 10 , 737 (26) Balances at 12/31/2016 (Based on 1/1/2016 Measurement Date) ...... .. $ 333 , 833 $ 75 , 224 $ 258 , 609 ===== In December 2016 , the District in i t i ated a voluntary early retirement i ncentive program (" Program") t o all regular , full-time employees , excluding senior management , who met certain retiremen t-eligible criteria. There were 12 1 employees who accep t ed the offer. These early retirements are expected to i ncrease the net OPES l i ability. The impact of the Program will be included in the January 1 , 2017 actuar i al valuation. Additional information on the Program is included in Note 14. Financial Report SO The mortality assumpt i on was updated to the RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Sca l e MP-2015 with generat i onal pro j ection. The cost method was changed to Entry Age Normal and the actuarial asset method was changed to five-year smooth i ng. Sens i tivity of the Net OPEB Liability to Changes in the Discount Rate The following table shows the net OPEB liab i lity of the Distr i ct , 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 5.25% Net OPEB Liability..................

..........

$306 , 681 Discoun t Rate 6.25% $258 , 609 1% Increase 7.25% $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 rang i ng from 9% initial to 6% ultimate , Post-Med i care ranging from 7.75% initial to 6% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 8% initial to 5% ult im ate , Post-Medicare ranging from 6.75% i nitial to 5% ultimate) at the measurement date of January 1 , 2016 (in OOO's): 1% Decrease (Pre-M ed icar e ran g i ng from 7% ini t i al to 4% ultimate , Post-Medicare ranging from 5.75% i nitial to 4% ultimate)

Net OPEB Liability.

....... $219 , 672 OPEB Plan Fiduciary Net Position Hea l thcare Cost Trend Rates (Pre-Med ic are ranging from 8% i n i t ia l to 5% ultimate , Post-Medicare rang ing from 6.75% i n itial to 5% u lti mate) $258 , 609 1% Increase (Pre-Medicare ranging fro m 9% i n i tial to 6% ultimate , Post-Medicare ranging from 7.75% initial to 6% ultimate) $306 ,1 51 The following table shows information on the OPEB Plan F i duciary Net Position as of December 31 , (i n OOO's): 2016 2015 Cash and cash equ i valents.............................................................. $ 9 , 609 $ 3 , 719 Rece i vables .......................

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

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

........................ . 314 253 Investments , at fair value .............

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

............... . 132 , 875 7 1, 252 Total assets ...........................................................................

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

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

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

...........

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

......... . (289) Net pos i t i on -restricted for other post-employment benefits................ $ 142 , 509 $ 75 , 224 51 Financial Report The following tables show the OPEB assets that are accounted for and r eported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , (in OOO's ): 2016 Level 1 Level 2 Level 3 Total Cash and cash equivalents

................................ $ 9 , 609 $ $ $ 9 , 609 U.S. Treasury and government agency securities . 2 , 678 2 , 678 Corporate issues ................................

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

18 , 162 1 8 , 162 Foreign issues ...................

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

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

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

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

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

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

................................ $ 3 , 719 $ $ $ 3 , 719 U.S. Treasury and government agency securities . 1 , 819 1 , 819 Corporate issues ...................

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

............... 17 , 551 17 , 551 Foreign issues .................................................. 5 , 304 5 , 304 Municipal issues ....................

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

........... 771 771 Domestic common stocks ................................. 29 , 833 29 , 833 Foreign stocks .................................................. 4 , 050 4 , 050 Mutual funds ...........................

.......................... 11 , 924 11 , 924 $ 49 , 526 $ 25 , 445 $ $ 74 , 971 D. OPEB Expense , Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB -The Board annually approves the OPEB expense in rates and has authorized the use of regulatory accounting to equate OPEB expense with the amount in rates. OPEB expense was $20.6 million for 2016 , as calculated under the GASB 75 guidance. With regulatory accounting , OPES expense and the amount included in rates was $52.9 million for 2016. This amount included a $25 million catch-up rate collection for the net OPES liability for past production-level services. There were no deferred inflows of resources related to OPES. The following table summarizes the reported deferred outflows of resources as of December 31 , 2016 (in OOO's): 2016 Difference between actual and expected experience

.......................... . Difference between expected and actual earnings on investments

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

............................. . $ $ 3 , 769 3 , 862 74 , 658 82 , 289 Financial Report 52 The deferred outflows related to the contr i but io ns made dur i ng the year ended December 31 , 2016 will be recognized in the actuar i a l valuation with a measurement date of January 1 , 2017. The other deferred ou tflow s of resources will be recognized in OPES expense as follows (in OOO's): Year Amount 2017 ....................... $ 1 , 705 2018 .............

.......... 1 , 704 2019 ....................... 1 , 705 2020 ....................... 1 , 704 2021 ..............

......... 739 2022 ....................... 74 Total $ 7 , 631 Additional i nformation is available in the unaud it ed Required Supplementary Information sect i on following the Notes to Financial Statements. 12. COMM I TMENTS AND CONTINGENCIES

A. Fuel Comm it ments -The District has various coal supply contracts and a coal transportation contract with minimum est i mated future payments of $166.0 million a t December 31 , 2016. These contracts exp i re at various times through the end of 2018. The coal transportation contract i n place is sufficient to deliver coal to the generation facilities through t he expiration date of the aforeme nt ioned contracts and i s subject to price escalation adjustments. The District has a contract for uranium purchases and deliver i es in 2017 and 2018 , a contract for convers i on services of uranium to uranium hexafluor i de which i s in effect through 202 1 , a contract for enrichment serv i ces through 2024 , and a contract for fabrication services through January 18 , 2034 , the end of the current operating license of CNS. These commitments for nuclear fuel material and services have combined est i mated future payments of $250.0 million. 8. Power Purchase and Sales Agreements

-The D i str i ct has entered i nto a part i cipation power agreement

{the " NC2 Agreemen t") with OPPD to purchase 23.7% of the power of NC2 , est i mated to be 161 MW of the power from the 663 MW coal-fired power plant constructed by OPPD. The NC2 Agreement conta i ns a step-up provision obligat i ng the District to pay a share of the cost of any deficit i n funds for operating expenses , debt serv i ce , other costs , and reserves related to NC2 as a result of a defaulting power purchaser. The Distr i ct's obligat i on 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 part ici pation power sales agreement w i th 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 , 201 1 and continues through December 31 , 2023. The District has entered i nto power sales agreements with Lincoln Electric System (" LES") for the sale to LES of 30% of the net power and energy of Sheldon Station (" Sheldon") and 8% of the net power and energy of GGS. In return , LES agrees to pay 30% and 8% of all costs attributable to Sheldon and GGS , respectively. Each agreement i s to terminate upon the later of the last maturity of the debt attr i butable to the respective station or the date on which the District reti r es such station from commercial operat i on. 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. 53 Financial Report The District owns and operates the 60 MW Ainsworth W i nd Energy Facil i ty and has 20-year participat i on power agreements to sell 28 MW to four other ut i l ities. In addition , the Distr i ct has power purchase agreements w i th seven w i nd facilities hav i ng a tota l capacity of 435 MW. T h ese agreements are for terms ranging from 20 to 25 years and require the D i str i ct to purchase all the electric power output of these wind facilit i es. The D i st ri ct has entered into power sales agreements to sell 154 MW of th i s c apacity to four other ut i l i ties in Nebraska over similar terms. The District has entered i nto a powe r purchase agreement with Centra l for the purchase of the net power and ene r gy produced by the K i ngsley Project dur i ng its ope r ating l i fe. The Kingsley Project is a hydroe l ectr i c generating unit at t he K i ngs l ey Dam i n Keith County , Nebraska with an accredited net capacity of 37 MW. The Distr i ct has en t ered i n to l ong-term PRO Agreements hav i ng i ni t ial terms of 15 , 20 , or 25 years with 79 mun i cipalities for the operation of certain retail electr i c distr i but i on sys t ems. These PRO Agreements exp i re on var i ous dates between March 1 , 2023 and March 31 , 2042. These PRO Agreements obligate the D i strict to make payments based on gross revenues from the municipalit i es and pay for normal property addit i ons dur i ng the term of the agreement.

C. Wholesale Power Contracts The D i strict serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requ i rements from the District , subject to certain exceptions. In 20 1 6 , the District entered into 20-year Wholesale Power Contracts

(" 2016 Contracts") w i th 23 public power d i st r icts , one cooperat i ve , and 37 mun i cipalities , effect i ve January 1 , 2016. Two public powe r d i stricts and 11 mun i cipalit i es are served under 2002 Wholesa l e Power Contracts

(" 2002 Contracts"), which expire on December 31 , 2021. The 2016 Contracts allow a wholesale customer to give not i ce to reduce i ts purchase of demand and energy requirements from the Distr i ct based on a compar i son 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 Util i t i es Cooperat i ve Finance Corporat i on Key Ratio Trend Analysis (Ratio 88) (the " CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given util i ty can compare its power costs on a pe r centile basis to the CFC published quartile i nformation. The 2016 Contracts allow a wholesa l e customer to reduce i ts demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given yea r is higher than the 45 th percent i le level (the " Performance Standard Percent i le") of the power costs of U.S. ut ili ties for such year as l i sted in the CFC Data. The 2016 Contracts wou l d not allow any r eductions i n demand and energy purchases by a wholesale customer as l ong as the D i str i ct's average annual who l esale power cos t s percentile rema i ned below the Performance Standard Percentile. The following table l i sts the District's wholesale power costs percenti l e for the calenda r years 20 1 1 to 2015 set forth i n the CFC Data: CFC Data Year Percentile 2011 24.4% 2012 29.1% 2013 31.0% 2014 27.6% 2015 31.3% The 2002 Contracts allow a wholesale customer to reduce its purchases 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 purchase at least 10% of their demand and energy from the D i str i ct through December 31 , 2021. Financial Report 54 The District has received notices from nine wholesale customers as to their intent to level off , reduce , or termina te the requirements under the i r 2002 wholesale contracts for variou s amounts from 2017 through 2021. The nine customers include one municipality which has a short-term wholesale contract terminating in May 2016. These wholesale customers represented 4.5% of the District's 2015 operating revenues. The D istrict expects that no requirements of said nine wholesale customers will be served by t he D istr ic t in 2022 , and such wholesale customers will purchase all of their electric requ i rements from other suppliers. The District expects to sell the energy not sold to such wholesale customers into the SPP Integrated Market and continues to explore additional firm requirement and/or fixed price agreements. One wholesale customer has not given notice to redu ce and continue under the 2002 wholesale contracts.

This customer represented 0.1 % of the District's 2015 operating revenues. In 2016 , three of the District's municipal wholesale customers began purchasing power from three of the District's pub lic power district wholesale customers. These customers rep resented 0.1 % of the Distr ict's 2016 operating revenues. One of the Distr i ct's municipal wholesale customers allowed their contract to terminate. This customer represented less than 0.1 % of the D istrict'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% increase for those wholesale customers who remained under the 2002 Contracts. The 2002 Contract customers wi ll pay their share of previously i ncurred OPEB costs through 2021. Customers under the 2016 Contracts received a discount for the deferral of OPEB collections , extending those collections into the new contract period and resulting in the lower net wholesale rate incre ase. E ight 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. Since May 2016 , the disputed amounts are being set aside i n eight separate accounts. The first meeting of the arbitrat i on panel occurred in September 2016. The dispute now includes the OPEB component of the 2017 wholesale rates. A decision is expected in the second quarter of 2017. If these wholesale customers are successful on the merits of their claim , the District's Board of Directors may need to reconsider the 2016 wholesale rate change. The District currently has 10 wholesa l e customers remaining on the 2002 Contracts , which include the eight wholesale customers referred to above. These customers represented 4.5% of the District's 2016 operat ing revenues. The 2016 wholesale rate increase in dispute accounts for $1.6 million of 2016 revenues. The District estimates the 2017 wholesale rate increase in dispute to be $2.0 million. The Northeast Nebraska Public Power District filed a lawsuit in the Distr ict 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 Distr ict which allows them to reduce their demand and energy purchases from the D istr ict 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 reduct ions under the 2002 Contract.

On March 23 , 2016, the Distr ic t filed a notice of appeal. 0. SPP Membership and Transmission Agreements

-The D istrict 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 , including generation i nterconnect ion 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 Distr ict entered into a Transmission Facilities Construction Agreement effective June 15 , 2009 , with TransCanada Keystone Pipel ine , LP ("Keys tone"). This agreement addresses the transmission facil i t ies , construction , cost allocation , payment , and applicable cost recovery for the interconnection and del ivery facilities required for the intercon nect ion of Keystone to the District's transmission system. Cost of the project was 55 Financial Report

$8.4 million and repayment by Keystone , over a 10-year period , began in June 201 O with a remain i ng balance due the District of $3.5 million and $4.4 million as of December 31 , 2016 and 2015 , respectively.

The Distr ict entered into a second Transmission Facilities Construction Agreement effective July 17 , 2009 , with TransCanada Keystone XL Pipeline, LP (" Keystone XL"). This agreement addresses the transmission facilities , construction , cost allocation , payment , and applicable cost recovery for the interconnec tion and delivery facilities required for the inte rconnection of Keystone XL to the Distr ict's transmission system. TransCanada Corporat ion and TransCanada Pipeline USA Ltd. have jointly and severally guaranteed the payment obligations of Keystone under its agreements with the D istr ic t. The agreement was cancelled in 2016 after the 2012 application for a Presidential permit for construction of the Keystone XL Pipeline was denied. All outstanding balances for Keystone XL were paid in 2016. E. Cooper Nuclear Station -On November 29 , 2010 , the Nuclear Regulatory Commission

(" NRC") formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until January 18 , 2034. CNS entered the 20-year period of extended operation on January 18 , 2014. In October 2003 , the Distr ict entered into an agreement (the " Entergy Agreement")

for support services at CNS with Entergy Nuclear Nebraska , LLC (" Ente rgy"), 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 2016 and $18.4 million for years 2015 and 2014. These fees will increase by an additional

$1.0 million in 2019 , and by an additional

$3.0 million i n 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 regu latory 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 incent ive fee. Since the earthquake and tsunami of March 11 , 2011 , that impac ted 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 reac tors and associated fuel storage pools and then look to any changes tha t might be necessary at the United States nuclear plants. Of particular interest is the performance of the General Electr ic boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes this same containment system; however , significant enhancements to the design have been made over the life of the plant. An NRC Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was publ ished on July 12 , 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report, on Octobe r 18 , 2011, the NRC approved seven of the Task Force recommendations for implementation. On March 12 , 2012, the NRC issued three orders to the U.S. nuclear in dustry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in t he event of beyond design bas is external events. The second order requires nuclear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to re liab le hardened containment wetwell vents. The third order requires nuclear plant operators to add reliable spent fuel pool water level instrumentation.

The NRC has also issued a request for information perta ining 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 bas is and strategy for why venting the drywell would not be required , will be completed by the conclus ion 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 modificat ion s to CNS, the D istrict has performed an additional seismic analysis and has worked to answer additional questions from the NRC on this topic. The NRC has determined that CNS will have to perform the High Financial Report 56 Frequency Evaluation and a Spent Fuel Pool Evaluation , but w i ll not have to complete a Se i smic Probab il istic Risk Assessment.

Unknown to the District at th is t i me is the extent of modificat i ons that may be requ i red as a result of these add i tional seismic reevaluations.

The District continues to work with the U.S. Army Corps of Engineers (the " Corps") and the NRC to va li date the data necessary to complete the CNS f l ood hazard reevaluation.

The District submitted its updated flooding analysis to the NRC in February 2015. The NRC subsequently submitted questions to which the Distr i ct has responded and submittal of the updated flood hazard reevaluation was completed i n September 2016. Based on current interim , and long-term strategies for flood i ng mit i gation, i t is not expected that any mod i fications will be requ i red as a result of the flood hazard reevaluations. All equipment and mater i als required to mitigate the identified impacts associated with the flood hazard reevaluation have been pu r chased and the equ i pment requ i red has been installed. Additional equipment purchased , but not required t o be i nstalled unless an i ssue occurs , i s stored on-site in dedicated storage facil i ties. The District's cost estimate for plant modifications associated with the NRC's Fukushima Dai-ich i related orders i s currently estimated to cost $25.6 million , which is expected to be funded primarily from the revenues of the District and from the proceeds of General Revenue Bonds. As of December 31 , 2016 , $19.4 million has been spent on plant modifications with an additional

$6.2 million expected to be spent to establish compliance with the Fukushima Da i-ichi orders. CNS substant i ally completed the construct i on of a dry cask used fue l storage project in December 2009 to support plant operations unt i l 2034 , wh i ch is the end of the Operating License. The first load i ng campaign was completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool i nto e i ght dry used fuel storage casks for on-s i te storage. A second loading campaign , encompassing the loading of 610 used fuel assemblies i nto 10 dry used fuel storage casks , began in April 2014 and was comp l eted in June 2014. The third loading campaign , encompassing the loading of 732 used fuel assemblies into 12 dry used fuel storage casks , is scheduled to begin in June 2017. As part of various disputed matters between GE and the District , GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assembl i es from the first two full core load i ngs at CNS at no additional cost to the District until the expiration of the current NRC l i cense 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 Fac i lity on essentially the existing design and operating configuration. As a result of the failure of the DOE to d i spose of spent nuclear fuel from CNS as required by contract , the District commenced legal action against the DOE on March 2 , 200 1. The initial settlement agreement addressed future claims through 2013. On January 13 , 2014 , the Distr i ct and the DOE agreed to extend the settlement agreement through 2016. On March 2 , 2017 , the District and the DOE agreed to extend the settlement agreement through 2019. The District has received $118.2 million from the DOE for damages from 2009 through 2016. The Distr i ct also reserves the right to pursue future damages through the contract cla i ms process. A corresponding regulatory li ability 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 $82.7 mil li on and $79.5 million at December 31 , 2016 and 2015 , respectively. Under the terms of the DOE contracts , the D i strict was also subject to a one mill per k i lowatt-hour

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

While the District expects that the revenues developed therefrom will be suffic i ent to cover the Distr i ct's responsibility for costs currently outlined in the Nuclear Waste Policy Act , the District can give no assurance that such revenues will be sufficient to cover all costs 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 kWh effective May 16 , 2014. Correspondingly , no additiona l payments have been made to the DOE for fuel disposal since that date. The Board authorized the continued co l lection of this fee at the same rate. This approach ensures costs are recogn i zed 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 electr i city generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal. S 7 Financial Report Under the provisions of the Federal Pr i ce-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 nuclear incident involving any licensed facility in the nation , with a max i mum 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 (" ROP"). The NRC has five performance ca tegories inc lud ed in the ROP Action Matrix Summary that is part of this process. As of December 31 , 2016 , CNS was in the Licensee Response Column , which is the first or best of the five NRC defined performance categories and has been in this column 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 recirculation pump impellers and motor , the startup station transfo rme r and the high pressure turbine. Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of t hese costs over a multi-year period to levelize revenue requ irements for expenses and he l p ensure the customers receiving the benefits from CNS are paying the costs , commencing in 2015. The regulatory liability for the pre-collection of outage costs was $24.7 million at December 31 , 2015 and was eliminated through revenue recognition during the 2016 outage year. The District began collecting revenues for the 2018 CNS refueling and maintenance outage in 2017. F. Environmental

-Water The Federal Clean Water Act contains requirements with respect to effluent limitations relating to the discharge of any pollutant and to the environmental i mpact of cooling water intake structures.

The Nebraska Department of Environment Quality (" NDEQ") establishes the requirements for the D istrict's compliance with the Clean Water Act through i ssuance of National Pollutant Discharge Elimination System permits. NDEQ iss ued the D istrict 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 lim itation 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 the Sheldon Station. Sheldon Station w i ll 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. 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 (" SO{} and nitrogen oxides (" NO x") emissions. Acid Rain Permits have been issued for the following facilities

GGS , Sheldon , Canaday Station and Beatr ice Power Station. The Acid Ra in Permits allow for the discharge of S0 2 at each facility pursuant to an allowance system. The District expects to have sufficient allowances for its generating facilities through 2020 , but may be required to purchase additional allowances in the future. Financial Report 58 Mercury and Air Toxic Standards On February 16 , 2012 , the EPA issued a final rule i ntended to reduce emissions of toxic air pollutants from power plants. Specifically , the Mercury and Air Toxics Standards

(" MATS") Rule will require reductions in emiss i ons from new and existing coal-and oil-fired steam utility electric generating units of toxic air pollutants. All affected District facilities , including GGS and Sheldon , are in compliance w i th the MATS Rule. Regional Haze and Cross-State A ir Po lluti on Rule The EPA issued fi nal regulations for a Regional Haze Program in June 1999. The purpose of the regulations i s to improve visibility in the form of reducing regional haze in 156 national parks and wilderness areas across the country. Haze is form, in part , from emissions of S0 2 and NO *. The EPA issued a rule in 2012 which is referred to as the Cross-State A ir Pollution Rule (" CSAPR") that would require significant reductions in S0 2 and NO. emissions in a number of states , including Nebraska. CSAPR compliance periods went into effect on January 1 , 2015. Based on the current CSAPR allocation methodology and current generation projections through 2021 , the District expects to have suffic i ent CSAPR allowances to cover affected facilities emission requ i rements over t hat timeframe , but may be required to purchase add i t i onal allowances in the future. On January 10 , 2017 , the EPA issued final changes to the Regional Haze regulations for the second planning phase of the Regional Haze Rule. The D i str i ct is evaluating the proposed changes but will not know the full impact to the District until the State and the EPA begin imple menting the second phase of the Regiona l Haze rule. The State of Nebraska is required to submit their state implementat i on plan (" SIP") for the second phase of the Regional Haze rule by July 31 , 2021. On January 19 , 2017 , EPA Region 7 issued a proposed modification to the July 6 , 2012 Regional Haze federal implementation plan (" FIP"). The proposed modification would require the Distr ict to install S0 2 controls on both units at GGS within five years of the proposed FIP be ing finalized. The District is currently evaluating the proposed mod ifica tion. However , the proposed modification has not yet been published in the Federa l Register and due to the hold issued by the Trump administration on all proposed regulations yet to be published in the Federal Register , the publicat i on of this modification will be delayed or withdrawn. As part of EPA's nationwide investigation and enforcement program for coal-fired power plants' compliance with the Clean Air Act including new source review requir ements , on December 4 , 2002 , the Reg ion 7 offi ce 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 i nformat ion. By lette r dated December 8, 2008 , EPA Region 7 sent a Notice of Violation

(" NOV") to the D istrict which alleges that the District violated the Clean Air Act by undertak i ng five projects at GGS from 1991 through 2001 without obta ining the necessary permits. In February and August 2009 , Distr ict representatives met with federa l government representatives to discuss the NOV and no addit i onal meetings have been scheduled. In general , enforcement action by EPA aga i nst the District for alleged noncompliance with Clean Air Act requ i rements , i f upheld after court review , can result in the requirement to install expensive air pollution control equipment that i s the Best Available Retrofit Technology

(" 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 w i ll have any future financial obligation with respect to the NOV. On July 22 , 2016 , EPA Region 7 sent a new 1 1 4(a) r equest for documents and i nformation 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 , 1 14(a) request. The EPA is review in g whether there have been physical or operational changes since November 8 , 2007 which resulted i n , or could result in , increased emissions inclu ding projects underway or planned for the next two years. The District is in the process of gather i ng responsible documents and information. Failure to comply with the Clean Air Act can result in fines as descr i bed above and/or requirements to install additional emission control equipment. The District belie ves GGS has been operated and maintained in compliance with the requ i rements of the Clean Air Act. Clean Power Plan On October 23 , 2015 , the EPA publ i shed the final Clean Power Plan (" CPP") rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determ ining 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 int erim reductions required between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 em i ssions. On February 9 , 2016 , the U.S. Supreme 59 Financia l Report Court issued a stay for the CPP until all lega l challenges have been decided. The D.C. Circuit Court of Appeals heard oral arguments on Septembe r 27 , 2016 , with a dec isi on expected i n early 2017. An in i t i al State P l an was due September 6 , 2016 prov i d i ng a general outline of potential compliance options the State i s cons i dering. States can a l so request a two-year extension when subm i tting their initial p l an making the final State P l an due September 6 , 2018. If the CPP is upheld , the rule deadlines will likely be extended by the length of the stay. Due to the stay , the NDEQ has halted work on the State Plan. The District expects that its generat i on from coal-fired un i ts will decrease and its generation from natural gas may increase under the final ru l e but it is not possible to determine the impact of the final rule on the D i str i ct until the legal issues are ult im ately decided and the NDEQ develops the State Plan and i t receives EPA app r oval. Impact from Changes to Environmental Regulatory Requirements Any changes in the env ir onmental re gulatory requirements i mposed by federa l o r state law which are applicable to the Distr i ct's generat in g stations could result i n increased capita l and operat i ng costs being i ncurred by the D i strict. The District is unable to predict whether any changes will be made to current env i ronmenta l regulatory requ i rements , if such changes will be applicable to the Distr i ct 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 (" Spence r") facility , i ncluding dam , structures , land , water appropriations , and perpetual easements for the reservo i r , to the Niobrara River Basin Alliance (Fi ve Natural Resource Distr i cts) and the Nebraska Game and Parks Commission for $12.0 million. The D i strict i s to prov id e an in-kind contribution of $3.0 million and the other parties are to pay $9.0 million to the D istrict. The MOU provided that the parties will work for passage of leg i slation by the State of Nebraska for a permanent transfer of exist i ng hydro water appropr i ation to a ne w purpose use , and it identifies potential sources of funding for the sale. The required legislat i on for this sa l e was passed by the State of Nebraska in 2016. The D i str i ct will cont i nue to operate Spencer unt i l transfer of ownership , including water appropriations, i s completed. The transfer is expected to take approximately two years to complete. H. Other-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 D i strict's General Revenue Bonds , 2009 Series A (Taxable Build America Bonds) and 2010 Ser i es A {Taxable Bu i ld America Bonds). Reduct i ons were 6.9% and 7.3% for fiscal years ended September 30 , 2016 and 2015 , respectively. 13. LITIGATION

On January 1 , 2016 , Tri-State Generation and Transmission Associat i on , Inc. (" Tri-State") became a transm i ss i on member of SPP and its transmiss i on facilities in western Nebraska , and the corresponding annual transmiss i on revenue requirements were placed under the SPP tariff. SPP filed at FERC to place the Tri-State transmission facilities in the District's pr ici ng zone rather than establ i sh a new pricing zone for Tr i-State. The District protested the filing at FERC , because it results in approximately a $4.3 million pe r year , or 8%, cost sh i ft increase to the transmission customers in the Distr i ct's pricing zone. As a result of the District's protest , FERC set the matter for hear i ng before an administrative law judge and the District and other parties submitted briefs and test imony on the proper pric i ng zone and whether SPP's dec i s i on is d i scr imin atory and an unjust and unreasonable cost shift to the District.

On February 23 , 2017 , the adm i n i strative law ju dge i ssued an init i al dec i sion upholding the SPP pricing zone placement and made recommended conclusions to FERC. This initial decision has no legal effect unt il reviewed and acted upon by FERC which w ill be after the Dist rict submits briefs on its exception to the factual and legal conclus i ons i n the initial dec i sion. FERC's future ruling on the initial decision can be appea led to a federal circu i t court of appeals. When FERC will rule on the i n i t i al decision cannot be predicted. Financial Report 60 A number of cla i ms and suits are pending against the Distr i ct for alleged damages to persons and property and for other alleged liabilities arising out of matters usually i ncidental to the operation of a uti l ity , such as the D i strict. In the opinion of management , based upon the adv i ce of its General Counsel , the aggregate amounts recoverable from the Distr i ct , taking into account es t imated amounts provided in the financial statements and insurance coverage , are not mater i al as of December 31 , 2016 and 2015. Informat i on on l i tigat i on with wholesale customers is i ncluded in Note 12. 14. SUBSEQUENT EVENTS: In Apri l 2017 , the Distr i ct i ssued General Revenue Bonds , 2017 Series A and 2017 Series B , i n the amount of $86.0 million to refund the General Revenue Bonds , 2007 Series B. The refunding reduced total debt service payments over the li f e of the bonds by $11.8 million , which resulted in present value savings of $10.0 M i llion. The District plans to i ssue addit i onal revenue bonds in 2017 to finance transm i ssion projects. On February 5 , 2017 , operators at CNS discovered that the minimum flow isolation valve for two pumps on the Residual Heat Removal System were found closed and sealed. The required configuration for these valves is open and sealed. The issue had ex i sted for approx i mately four months , since ear l y Oc t ober during the 2016 fall refueling and maintenance outage. The cause evaluation to determine how the issue occurred and actions to preven t recurrence is ongoing at this time. Dur i ng the week of March 13 , 2017 the NRC Region IV conducted a special inspection , comprised of two inspectors , to i nvest i gate the recent Res i dual Heat Removal System Minimum Flow Va l ve issue to determ i ne the safety s i gn i ficance. If the i ssue is determined to be greater t h an a very low safety s i gnificance (a find i ng greater than Green), CNS would move from the L i censee Response Colum n to the Regulatory Response Co l umn of the NRC's Action Matrix for a period of one year. Plants in the Regulatory Response Column of the NRC's Act i on Matr i x are subject to additiona l NRC inspections.

In December 2016 , the Distr i ct i nitiated a voluntary ear l y ret i rement incentive program ('Program") to a ll r egular , full-time employees , excluding sen i or management , who met certain retirement-eligible criteria. The objective of the Prog r am was to fac i litate an acce l erated but voluntary reduction in the workforce to obtain a reduction i n costs during 2017 and in years fo ll owing by incentivizing earlier retirement of employees who were elig i ble for ret i rement. Approximately 600 employees were eligible for the Program and 121 employees accepted the offer. Their last day of full-time employment was on or before February 28 , 2017. These employees rece i ved s i x months of salary in one , lump sum payment. The total cost of the program was $5.9 million and expensed in 2016. 61 Financial Report SUPPLEMENTALSCHEOULES(UNAUDITED)

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

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

................. . Operating expenses .................................................................................... . Ope rating inc ome ...............

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

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

............ . Investment and other income .....................................................................

... . Debt and other expenses ............................................................................. . Increase in net pos i tion ..............

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

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

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

.................... . Payments to retail communities c 1 i .......................................

..................... . Amortization of current portion of financed nuclear fuel ............................... . Amounts collected from third party financing arrangements C 2 J ....*......

- ......... Deduct: Investment income retained in construct i on funds .........................

............. . Unrealized (loss) gain on investment securities

......................................... . Re\01"1ng credit agreement interest ............

.............................................. . Ne t position available for debt ser.;ce for the Ge neral Revenue Bond Resolution . Amounts deposited in the General System Debt Ser.;ce Accoun t: Principal

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

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

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

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

................. . Ratio of net position available for debt ser.;ce to debt ser.;ce deposits ............. . $ $ $ $ 2016 1 , 153 , 997 (1 , 040 , 715) 113,282 31 , 772 (62 , 121) 82 , 933 62 , 121 133 , 666 26 , 553 39 , 468 991 262 , 799 354 43 397 345 , 335 101 , 135 72 , 959 174 ,094 1.98 2015 $ 1 , 097 , 216 (960 , 259) 136 , 957 22 , 355 (68 , 252) 91 , 060 68 , 252 130 , 247 26 , 552 24 , 675 850 250 , 576 302 (1 , 245) 1 , 010 67 $ 341 , 569 $ 110 , 265 75 , 372 $ 185 , 637 1.84 (1) Debt and other expenses , exclusive of i nterest on customer deposits , is not an operating expense as defined in the General Resolut ion. (2) Depreciat ion and amortization are not operati ng expe nses as d efined i n the General Resolution. (3) Under the provisions of the G e neral Resolution , the payments required to be made by the District with respect to the Profess ional Retail Operating Agreements are to be made on the same bas i s as subordinated debt. (4) General Revenue Bond financed nu clear fue l is not an operating expense as defined in the General Resolution. As of Ju l y 31 , 2015 , the effective date of the Taxable Revolving Credit Agreement , amortizat i on of nuclear fuel expense under the Taxable Revolv ing Credit Agreement is e x cluded from the debt servi c e calculation as the Distri ct's obligat i on to make payments under the Ta xable Revolv i ng Credit Agreement is subordinate to the Distr ic t's obligation to pay debt service on Genera l Revenue Bonds. (5) The payments receiv ed by the District from th i rd party financing arrangements are i ncluded as Re venues unde r the General Resolut i on , but are not recognized as revenue under GAAP. (6) Interest income on investments held i n construction funds i s not Revenue as defined i n the General Resolution. (7) As of July 31 , 2015 , the effective date of the Taxab l e Revolving Credit Agreement , in terest expense under the Taxable Revolv in g Credit Agreement is excluded from t he debt service ca l culation as th e D istrict's obligat i on to make payments under the Ta xable Revo l ving Credit Agreement i s subord i nate to the Distr ict's obligation to pay debt service on General Revenue Bonds. Financial Report 62 Schedule of Changes i n the Net OPEB Liability and Related Ratios as of December 31 using a January 1 Measurement Date (i n OOO's) Total OPEB Liability 2016 Service Cost. ....................................................................................................

.............. . $ 3 , 229 I nterest ......................................................

.................................................................... . 19 , 876 D i fferences Between Expected and Actua l Experiences

...................................................... . 13 , 657 Changes of Assumptions

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

...................................... . (9 , 149) Benefit Payments ............................................................................................................ . (16 , 902) Net Change in Total OPEB Liability

................................................................................... . 10,711 Total OPEB Liability (beg i nn i ng) ........................................................................................ . 323, 1 22 Total OPEB Liability (end i ng) (a) ....................................................................................... . $ 333 , 833 Plan Fiduciary Net Position Contributions

................................................................................................................... . $ 28 , 242 Net Investment Income ..................................................................................................... . (453) Benefit Payments ............................................................................................................ . (16 , 902) Administrative Expense .................................................................................................... . (150) Net Change in Plan Fiduciary Net Pos i tion .............................

............................................ . 10,737 Plan Fiduciary Net Posit i on (Beginn i ng) ............................................................................. . 64,487 Plan Fiduciary Net Position (Ending) {b} .......................

..................................................... . $ 75 , 224 Net OPEB Liabil i ty (Ending) (a) -(b) .................................................................................. . $ 258 , 609 Net Position as a % of Total OPEB Liabil i ty ....................................................................... . 22.5% Covered-Employee Payroll. ............................................................................................... . $ 195 , 903 Net OPEB Liab i lity as a % of Covered-Employee Payrol l. ...........................

......................... . 132.0% GASB 75 was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods , as it was impractical to do so as disclosed in Note 11. This schedule is intended to show information for 10 years. Additional years will be displayed when available. 63 Financial Report Schedule of Contributions as of December 31 us i ng a January 1 Measurement Date (in OOO's) 2016 Actuarially Determined Contribution

.................................................................................... . $ 28 , 283 Contributions Made i n Relation to the Actuarially Determined Contribut i on ............................. . 74 , 658 Contribution Deficiency (Excess) ...................................................

..................................... . $ (46 , 375) Co-.ered-Employee Payroll. .......................

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

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

........................ . $ 195 , 903 Contributions as a % of Payroll ...................

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

................ . 38.1% Notes to Schedule: Valuation date -Actuarially determined contribution rates are calculated as of December 31 , one year pr i or to the end of the fiscal year in which contributions are reported. Methods and assumptions used -* Actuarial cost method

Amort i zation method

Amortization period

Asset valuation method

Discount rate

Healthcare cost trend rates

Inflation

Investment rate of return

Mortality

Retirement Age Entry Age Norma l Level amortization of the unfunded accrued liabil i ty 17-year closed period 5-year smoothed market 6.25% Pre-Medicare:

8% i nitial , ultimate 5% Post-Medicare

6.75% initial , ultimate 5% 2.1% 6.25%, net of investment expense , including inflat i on RP-2014 Aggregate table projected back to 2016 us i ng Scale MP-2014 and projected forward using Scale MP-2015 w i th generational projection Varies by age GASB 75 was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods , as it was impractical to do so as disclosed in Note 11. This schedule is intended to show information for 10 years. Additional years will be displayed when available. Financial Report 64

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