Revision as of 01:47, 30 October 2019

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

H Nebraska Public Power District Always there when you need us NLS2017062 140.2 1 July 18, 2017 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:

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 37, 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 investments 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 .com

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 Nebraska Public Power District 2016 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 BILLION OPERATING REVENUES $ 1,154.0 MILLION COST OF POWER PURCHASED AND GENERATED $ 635.2 MILLION OTHER OPERATING EXPENSES $ 405.5 MILLION INVESTMENT AND OTHER INCOME $ 31.7 MILLION DEBT AND OTHER EXPENSES $ 62.1 MILLION INCREASE IN NET POSITION $ 82.9 MILLION DEBT SERVICE COVERAGE 1.98 TIMES Financial Report 12

2016 STATISTICAL REVIEW (Unaudited)

A-.erage Cents Per kWh Sold A-.erage A-.erage Less Go-.emment Cents Per Number of MWh Re-.enues (in OOO's)

OPERATING REVENUES Taxes/Transfers (1 l kWh Sold Customers Amount % Amount %

Retail :

Residential ..................... . 10.77 ¢ 12. 79 ¢ 71 ,868 818,305 4.3 $ 104,642 9.1 Commercial ... .. ... .. .. .. .... .. . 8.50 ¢ 9.88 ¢ 19,530 1,131 ,223 6.0 111 ,722 9.7 Industrial .................. .... .. . 5.57 ¢ 5.93 ¢ 59 1,277,557 6.8 75,777 6.5 Total Retail Sales ... ...... . ¢ ¢

7.91 9.05 91,457 3,227,085 17.1 292, 141 25.3 Wholesale:

Municipalities c21 ........................................ 6.26 ¢ 46 1,868,510 9.9 116,906 10.1 Public Power Districts and Cooperati-.es<21 .. 5.85 ¢ 25 7,806,394 41 .3 456,614 39.6 Total Firm Wholesale Sales .................... 5.93 ¢ 71 9,674,904 51 .2 573,520 49.7 Total Firm Retail and Wholesale Sales .. 6.71 ¢ 91 ,528 12,901 ,989 68.3 865,661 75.0 Participati on Sales ..... ................. ......... ......... 4.05 ¢ 5 1,926,845 10.2 77,996 6.8 Other Sales <3J ............................................... 2.20 ¢ 2 4,073,339 21.5 89,492 7.7 Total Electric Energy Sales ............... .. . 5.47 ¢ 91 ,535 18,902,1 73 100.0 1,033, 149 89.5 Other Operating Re-.en ues <~J .. ................................................... ........... ..... .. ... ......................... ...... . 66,060 5.7 Unearned Re-.enues csi ........... ............... ....................... .............................................................. ... . 54,788 4.8 Total Operating Re-.enues ................ ...................... ....................................................................... . $ 1, 153,997 100.0 MWh Costs (in OOO's)

COST OF POWER PURCHASED AND GENERATED Amount % Amount %

Productionc6 J .. ..... ......... ..... ... ................. ... ... ..... .... .................................... . 14,787,399 75.2 $ 458,122 72.1 Power Purchased .. ... .. .. .. .. .. .. .. ..... .. .. ... ..... .. ........... ... ................................. . 4,864,394 24.8 177, 121 27.9 Total Production and Power Purchased .... ..... .. ..... ...... ...... ... .. ..... ..... ...... .. 19,651,793 100.0 $ 635,243 100.0 CONTRACTUAL AND TAX PAYMENTS (in OOO's) (1l Amount Payments to Retail Communities .. ....... ............ .... .... ....... ..... .... .... ...... .... .. .. ....... .. .. ... .... ........... ... .. $ 26,553 Payments in Lieu of Taxes ................. ............... ....... .. ............................................................. ... . 10,064 Total Contractual and Tax Payments ...................................................................................... .. $ 36,617 OTHER Amount Mi les of Transmission and Subtransmission Lines in Service ......................................................... . 5,267 Number of Full-Time Employees ................. ........................................................................... ..... .. 1,966 (1) Customer collections for taxes/transfers to other governments are excluded from base rates.

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

(3) Includes sales in the Southwest Power Pool ("SPP") and nonfirm sales to other utilities.

(4) Includes revenues for transmission and other miscellaneous revenues.

(5) Includes unearned revenues from prior periods of $17.4 million, 2016 surplus revenues deferred to future periods of $10.0 million, recognized 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 in 2016 rates.

(6) Includes fuel , operation, and maintenance costs. Debt service and capital-related costs are excluded.

SOURCES OF THE DISTRICT'S ENERGY SUPPLY

(%OF MWH) Wind This chart shows the sources of energy for Hydro sales , excluding participation sales to other 6.8%

utilities. Purchases were included in the appropriate source, except for those purchases for which the source was not known . --~-- Purchases 4.5%

1.5%

48.0%

13 Financial Report

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

The financial report for the Nebraska Public Power District ("District") includes this Management's Discussion and Analysis, Financial Statements , Notes to Financial Statements and Supplemental Schedules . The financia l statements consist of the Balance Sheets, Statements of Revenues , Expenses, and Changes in Net Position ,

Statements of Cash Flows, and Supplemental Schedules.

The following Management's Discussion and Analysis ("MD&A") provides unaudited information and ana lyses of activities and events related to the District's finan cial position or results of operations . The MD&A should be read in conjunction with the audited Financial Statements and Notes to Financial Statements.

The Balance Sheets present assets, deferred outflows of resources, liabilities, deferred inflows of resources and net position as of December 31 , 2016 and 2015. The Statements of Revenues , Expenses, and Changes in Net Position present the operating results for the years 20 16 and 2015. The Statements of Cash Flows present the sources and uses of cash and cash equ iva lents for the years 2016 and 2015 . The Notes to Financial Statements are an integral part of the basic financial statements and conta in information for a more complete understanding of the financial position as of December 31 , 2016 and 2015, and the results of operations for the years 2016 and 2015. The Supplemental Schedules include unaudited information required to accompany the Financial Statements.

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

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

The District operates an integrated electric utility system including facilities for generation , transmission , and distribution of electric power and energy for sales at reta il and wholesale . Management and operation of the District is accomplished with a staff of approximately 1,960 full-time employees. The District has the power, among other things, to acquire , construct, and operate generating plants, transmission lines, substations, and distribution systems and to purchase, generate, distribute, transmit, and sell electric energy for all purposes.

There are no investor-owned utilities provid ing retail electric service in Nebraska .

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

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

THE SYSTEM To meet the anytime peak load in 2016 of 2,963.7 megawatts ("MW"), the District had available 3,638.2 MW of capacity resources that included 3,033.3 MW of generation capacity from 12 owned and operated generating plants and 22 plants over which the District has operating control , 447 .7 MW of firm capacity purchases from the Western Area Power Admin istration, and 157 .2 MW of a capacity purchase from Omaha Public Power District's Financial Report 14

("OPPD") Nebraska City Station Unit 2 ("NC2") coal-fired plant. Of the total capacity resources , 223 .7 MW are being sold via participation 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 highest summer anytime peak load of 3,030 .3 MW was establ ished in Ju ly 2012 and the highest winter anytime peak load of 2,252 .0 MW was established in January 2014 for firm requ irements customers .

The following table shows the District's capacity resources from generation and respective summer 2016 accredited capability.

Summer 2016 Number of Accredited Type Plants(1 ) Capability (MW ) (2> Percent of Total 3

Steam - Con-.entional C l ** ** ** *. . ** *** ** *** **** **** ****** **** **** .

3 1,674.0 55.2 Steam - Nuclear .. ....... ... ........ ........ ..... .... ... ... .......... . 765.0 25.2 Combined Cycle .... .... ............ .. .... .... .. .... ... .... .......... . 220.0 7.3 Combustion Turbine c4l . .... ....... .. ...... . ...... .. ... . . ...... ... . 3 125.3 4.1 Hydro ...... .. .. .... ... .... ....... .. ................. .............. ....... . 6 110.7 3.7 Diesel ...... .. .... ...... .......... .. .... ........ ........... .... ...... .... . 12 91 .5 3.0 Wind csl .. ... .. ...... ..... .... ............. .. ... .... .. ... ....... ......... . 8 46.8 1.5 34 3,033.3 100.0 (1) Includes three hydro plants and 12 diesel plants under contract to the District.

(2) 2016 summer accredited net capability based on SPP criteria .

(3) Includes Gerald Gentleman Station ("GGS"), Sheldon Station ("Sheldon"), and Canaday Station ("Canaday").

(4) Includes the Hallam, Hebron and McCook peaking turbines.

(5) Includes Ainsworth Wind Energy Facility ("Ainsworth") and seven wind facilities under contract to the District.

The following table shows the generation facilities owned by the District and the ir respective fuel types , summer 2016 accred ited capabi lity , and in-service dates .

Summer 2016 Accredited Type Fuel Type Capability (MW ) (1> In-Ser.ice Date Gerald Gentleman Station Units No. 1 and No. 2 ...... . . Coal 1,365.0 1979, 1982 Cooper Nuclear Station .... ............. ....... .... ... .... .. .... ... Nuclear 765.0 1974 Beatrice Power Station ..... ........ .. ...... ... .. ....... .... ...... . Combined Cycle 220.0 2005 Sheldon Station Units No. 1 and No. 2 ... ....... ... ........ . Coal 215.0 1961 , 1968 Combustion Turbines (3 generating plants) ....... .. .. ... .. Oil or Natural Gas 125.3 1973 Canaday Station .... ..... ...... ......... .......... .... .... ..... .. ... . Natural Gas 94.0 1958 Hydro (3 generating plants ) ...... .... .. .. ... .... .. ..... ... .. .... . Water 25.2 1887, 1927, 1939 Ainsworth W ind Energy Facility<2l ... ........ ...... ... ... .... . W ind 10.1 2005 2,819.6 (1) 2016 summer accredited net capability based on SPP criteria.

(2) Nominally rated at 60 MW.

THE CUSTOMERS Retail and Wholesale Customers In 2016, the District served an average of 91,457 reta il customers . Currently the District's retail service territory includes 80 municipalities, of which 79 are municipal-owned distribution systems operated by the District for the municipal ity pursuant to a Professiona l Retail Operations ("PRO") Agreement. Details of the District's PRO Agreements are included in Note 12 in the Notes to Financial Statements.

15 FIMndal Report

The District serves its wholesale customers under total requirements contracts that require them to purchase total power and energy requirements from the District, subject to certain exceptions. In 2016 , the District entered into 20-year wholesale power sales contracts with a substantial number of its wholesale customers (the '2016 Contracts"). The 2016 Contracts replaced wholesale contracts that were entered into in 2002 {the "2002 Contracts"). Wholesa le 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 ities . Wholesale customers served under the 2002 Contracts include one public power district and nine municipalities. The District's goal , with respect to the cost of wholesale service (production and transmission), is that such costs are among the lowest quartile (25th percentile or less) for cost per kilowatt-hour

("kWh ") purchased, as published by the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analys is (Ratio 88) (the "CFC Data"). The District's wholesale power costs percentile 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 following 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 collections for taxes and transfers to other governments, which are not included in the District's base rates for retail customers.

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

9.04¢ 9.06¢ 9.12¢ 9.05¢ 7.91 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 Only) 6.40 . . . . - - - - - - - - - - - - - - - - - - - - -

6.09¢ 5.91 ¢ 6.00 - - - - - - - - - - -

2012 2013 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 Island Utilities ("Grand Island"), and JEA. The District also sells energy on a nonfirm basis in SPP and through transactions executed with other util ities 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.

Anytime Peak Megawatt- Hour Sales 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 Load 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, includes sales to firm wholesale customers, participation customers (LES, MEAN, JEA, OPPD, Grand Island), and a yearly average of 2 nonfirm customers . Bilateral sales to utilities decreased in 2014 due to SPP's transition to an integrated market. In 2016, three of the District's municipal wholesale customers began purchasing power from three of the District's public power district wholesale customers , and one of the District's municipal wholesale customers allowed their contract to terminate .

(2) Native load sales include wholesale sales to total firm requirements customers and include the responsibility of replacement power being procured by the District if the District's generating assets are not operating . Predominantly, native load customers are served under long-term total requirements contracts.

(3) Total sales from the System include 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 Facility, 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 maintenance outage at CNS, lower natural gas prices and additional wind generation in the SPP Integrated Market.

17 Financial Report

FINANCIAL INFORMATION The following tables summarize the District's financial position and operating results .

CONDENSED BALANCE 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 Utility Plant, Net .... .... .............. ....................... .. ... .. ........ 2,596,806 2,508,971 2,495,206 Other Long- Term Assets ......................... .. ....... ..... ...... .. 451 ,048 353,639 800,406 Deferred Outflows of Resources ... ...... ........................ ..... 124,953 40,775 26,794 Total Assets and Deferred Outflows ............................ $ 4, 731 , 143 $ 4,406,630 $ 4,850,945 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 Liabilities , Deferred Inflows , and Net Position ....... $ 4,731 ,143 $ 4,406,630 $ 4,850,945 CONDENSED RESU LTS OF OPERATIONS (in OOO's)

For the years ended December 31 , 2016 2015 2014 Operating Re\nues .... .... ....................... ... .. ... ............ .. . $ 1, 153,997 $ 1,097,216 $ 1, 122,454 Operating 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 ition .. ...... ..... ..... ...... .... ........... ..... $ 82,933 $ 91 ,060 $ 62,362 SOURCES OF OPERATING REVENUES (in OOO's)

For the years ended December 31 , 2016 2015 2014 Firm Retail and Wholesale Sales ............ ... ..... ... .. ....... .... $ 865,661 $ 848,345 $ 887,619 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, 122,454 Financial Report 18

-- - --- - - - - - --~

CONDENSED STATEMENTS OF CASH FLOWS (in OOO's)

For the years ended December 31 , 2016 2015 20 14 Net Cash Pro\1ded by Operating Acti"1ties ... ..... ... .. ....... .. . $ 253,711 $ 372,503 $ 362,365 Net Cash Pro\1ded by (Used in) Im.es ting Activities .. ......... 2,374 10,961 (199, 101)

Net Cash Used in Capital and Financing Activities .. .... ... ... (238,416) (388,483) (241 ,874)

Net Increase (Decrease) in Cash and Cash Equivalents .. .. 17,669 (5,019) (78,610)

Cash and Cash Equivalents , Beginning of Year ..... ... ... .. ... 85,060 90,079 168,689 Cash and Cash Equivalents , End of Year ...... ....... .. ... .. $ 102,729 $ 85,060 $ 90,079 Revenues from Firm Retail and Wholesale Sales The District allocates costs between reta il and wholesale service and establishes its rates to produce revenues sufficient to meet its estimated respective reta il and wholesale revenue requirements . Wholesale revenue requirements include unbundled costs accounted for separately between generation and transmission .

Transmission costs not recovered from the District'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 District's wholesale power contracts provide for the establishment of cost-based rates . Such rates can be adjusted at such times as deemed necessary by the District. The wholesale power contracts also provide for the creation of a rate stabilization account. Any surplus or deficiency between revenues and revenue requirements , within certa in limits set forth in the wholesale power contracts, may be retained in the rate stabilization account. Any amounts in excess of the limits may be included as an adjustment to revenue requirements in the next rate review. The wholesale power contracts also include a provision for establishing a new/replacement generation fund . This provision would permit the District to collect an additional 0.5 mills per kWh above the normal revenue requ irements to be used for future capital expenditures associated with 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 implemented a 0.6% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who signed the new 2016 20-year wholesale power contract, and a 3.8% increase in the District's wholesale rates on January 1, 20 16, 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 their share of a catch-up in funding for other post-employment benefits ("OPES") costs in 2016 and 2017 . The District 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 service associated with such debt beginning in 2022 and continu ing through 2033. No increase in reta il rates was implemented in 2016. Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements.

The District implemented a 0.5% increase in the District's wholesale rates commencing on January 1, 2015. No increase in retail rates was implemented in 2015. The District had no wholesale or retail rate increase in 2014.

Revenues from firm sales increased $17.4 million , or 2.1%, from $848.3 million in 2015 to $865.7 million in 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 sales decreased $39.3 million , or 4.4% , from

$887.6 million in 2014 to $848.3 million in 2015. The decrease was due primarily to lower unbilled retail energy with a revenue impact of $14.4 million and a 1.4% decrease in sales volume which was the result of milder temperatures.

Revenues from Participation Sales The District has participation sales agreements with other utilities that share operating expenses on a pro rata basis. Revenues from participation sales increased from $77 .2 million in 2015 to $78 .0 million in 2016, an 19 Rnancial Report

increase of $0.8 million . Revenues from participation sales decreased from $81 .1 million in 2014 to $77.2 million in 2015, a decrease of $3.9 million . This decline was due primarily to participation sales to LES which decreased by $4.4 million due to a 23 .0% reduction in the dispatch of generation from Sheldon due to lower prices in the SPP Integrated Market. The decrease was partially offset by increased wind participation sales Revenues from Other Sales Other sales consist of sales in SPP's Integrated Market and nonfirm sales to other utilities. TEA, of which the District is a member, has energy marketing responsibilities for the District's other and nonfirm off-system sales and the related management of cred it risks . Other sales decreased from $134.6 million in 2015 to $89.5 million in 2016 , a decrease of $45.1 million . The decrease was a result of reduced nonfirm revenues due to lower energy sales due to the planned refueling and maintenance outage at CNS, lower natural gas prices and additional wind generation in the SPP Integrated Market. Revenue from participation sales decreased from $172.5 million in 2014 to $134.6 million in 2015, a decrease of $37.9 million . This decrease was a result of lower prices in the SPP Integrated Market which was due to lower natural gas prices and additional wind generation .

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

These revenues were $66.1 million , $60.7 million , and $58.4 million in 2016, 2015, and 2014 , respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District.

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

The District recognizes net revenues in excess of revenue requ irements in any year as a deferral or reduction of revenues . Such surplus revenues are excluded from the net revenues available under the General Revenue Bond Resolution ("General Resolution") to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or 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 , in the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are excluded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates .

The District recognized or increased revenues a net amount of $54 .8 million in 2016 . The District's revenues in 2016 from electric sales to retail , wholesale , and other utilities resulted in a surplus, or over collection of costs , of

$10.0 million , which was deferred (decrease in revenues). In addition , the wholesale rates that were in place for 2016 included a refund of $17 .4 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s ) the surplus occurred . Accordingly, the 2016 revenues from electric sales, which reflect the surplus being refunded , are offset by a revenue adjustment (increase in revenues) for such amount. The District also recognized or increased revenues by $24.7 million for CNS fall refueling and maintenance outage costs , which costs were pre-collected for in 2015. This regulatory liability was amortized through revenue during the 2016 outage year. In addition , the District recognized or increased revenues by $22.7 million for OPES expenses related to past service for wholesale customers under Financial Report 20

the 2016 Contracts. The OPEB expenses were included 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 District's revenues in 2015 from electric sales to retail , wholesale , and other utilities resulted in a surplus, or over collection of costs , of

$11 .0 million , which was deferred (decrease in revenues) . In addition, the wholesale rates that were in place for 2015 included a refund of $12 .0 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly, the 2015 revenues from electric sales , which reflect the surplus being refunded , were offset by a revenue adjustment (increase in revenues) for such amount. The District also deferred or decreased revenues by $24.7 million for the pre-collection of CNS refueling and maintenance outage costs. This regulatory liability will be eliminated through revenue recognition during the 2016 outage year.

The District deferred or decreased revenues a net amount of $77.1 million in 2014 . The District's revenues in 2014 from electric sales to retail , wholesale , and other utilities resulted in a surplus, or over collection of costs , of

$91.4 million, 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. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred . Accord ingly, the 2014 revenues from electric sales, which reflect the surplus being refunded , were offset by a revenue adjustment (increase in revenues) for such amount.

Unearned revenues from prior periods of $1.9 million were refunded directly to customers in 2014. The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements in future ra te periods was $168.7 million, $176 .1 million, and $177.1 million , as of December 31 , 2016, 2015, and 2014, respectively.

Operating Expenses The following chart illustrates operating expenses for the years ended December 31 , 2014 through 2016.

$1 ,200 Power Purchased & Fuel

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

Iii Transmiss ion & Distribution O&M c: $800

.!:!

- Customer Service & Information

~ $600

...

ti)

Adm inistrative & General

..!!!

0 0 $400 Decommissioning

$200 Depreciation & Amortization

$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 in 2015 were $960 .3 million , a decrease of $50.4 million from 2014 . The changes were due primarily to the following:

Power purchased and fuel expenses were $347.6 million , $365.1 million, and $386.3 million in 2016, 2015, and 2014, respectively. These expenses decreased $17.5 million in 2016 as compared to 2015 due primarily to additional energy purchases from NC2 and the wind facilities , and lower fuel costs as the result of decreased generation . These expenses decreased $21 .2 million in 2015 as compared to 2014 due primarily to lower fuel 21 Flnandal Report

costs as a result of decreased generation , lower market prices and fewer energy purchases in the SPP Integrated Market.

Production operation and maintenance expenses were $287 .7 million , $242.8 million , and $281 .7 million in 2016, 2015, and 2014 , respectively. These costs increased $44.9 million due primarily to the costs associated with a planned refueling and maintenance outage at CNS completed on November 8, 2016 . These costs decreased

$38.9 million in 2015 as compared to 2014 due primarily to the costs associated 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 in 2015.

Transmission and distribution 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 to 2015 due primarily to higher fees charged by SPP for the District's share of qualifying transmission upgrade projects, including an SPP resettlement for prior periods for the implementation of a tariff provision to compensate transmission upgrade sponsors for qualifying upgrades used by other transmission customers . These costs increased $3.5 million in 2015 as compared to 2014 due primarily to an increase 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 million , $17.2 million , and $17 .5 million, in 2016, 2015, and 2014, respectively.

Administrative and general expenses were $94.1 million , $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 related to past service and included in 2016 rates . Details regarding OPES, including the early adoption of new accounting guidance in 2016 , are included in Note 11 in the Notes to Financial Statements.

Administrative and general expenses increased $6.9 million in 2015 as compared to 2014 due primarily to increases in healthcare costs along with increased expenses for outside 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 in an amount equivalent to the income on investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year. Decommissioning expenses increased by $6.7 million in 2016 as compared to 2015 due to an increase in interest income on investments. Decommissioning 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 position was $82.9 million , $91 .1 million , and $62.4 million , in 2016 , 2015, and 2014, respectively . 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 primarily 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 principal payments for revenue bonds.

Financial Report 22

The following chart illustrates the District's operating revenues , other revenues , operating expenses, and other expenses for the years ended December 31 , 2014 through 2016.

Revenues & Expenses

$1 ,250 . . . . - - - - - - - - - - - - - - - - - - - - - - - - - - -

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

I $1 ,150 t--M...., -----==--:------:--r----- Other Expenses

.~ $1 ,100 + - --II

~ $1 ,050 Operating Expenses

~ $1 ,000 - -- Other Revenues 0~ $950 - - - Operating Revenues c $900 + - --i.

$850 + - --t

$800 -.....-~

20 14 2015 2016 FINANCIAL MANAGEMENT POLICY The District has a Financial Management Policy (the "Policy"), which is subject to periodic review and revisions by the Board. This Policy represents general financial strategies and procedures that are implemented to demonstrate financial integrity and fiscal responsibi lity in the management of the District's business and its assets. Employees must abide by all applicable District bylaws, Board resolutions, bond resolutions, federal and state laws, other relevant legal requirements and the Policy.

DEBT SERVICE COVERAGE Under the Policy, the District has established a minimum debt service coverage ratio on the General Revenue Bonds of 1.5 times the debt service on the General Revenue Bonds. The District's debt service coverage ratio was 1.98, 1.84, and 1.50, in 2016 , 2015, and 2014, respectively. The coverage was provided primarily by the amounts collected in operating revenues to fund the cost of utility plant additions, the amounts collected in operating revenues for principal and interest payments on the outstanding commercial paper notes , and the amounts collected for payments to those municipalities served by the District under long-term 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 increase in the 2015 debt service coverage ratio over 2014 was primarily due to the fact that effective July 31 , 2015, the obligation of the District to pay the principal , interest, bank fees , and expenses pursuant to the Taxable Revolving Credit Agreement is payable from the Pledged Property subject and subordinated to the pledge of the Pledged Property 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 that they will not be revised downward or be withdrawn entirely by the respective rating agency if, in its 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 (stable outlook)

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

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

The District plans, pursuant to the Policy, to issue separate series of indebtedness, including separate series of General Revenue Bonds, for production projects and for transmission projects . No more than 20.0% of the amount of outstanding indebtedness issued for production projects, calculated at the time of issuance of each series of such indebtedness, or $200 .0 million , whichever is less, will be perm itted to mature after January 1, 2036, the end of the 2016 Contracts. Transmission indebtedness issued for transmission projects is expected to mature over the useful life of the asset that is being financed . New transmission indebtedness may mature after January 1, 2036. The District's transmission indebtedness is payable from the revenues received during the term of the 2016 Contracts and from retail sales and transmission revenues received under various SPP tariffs . After January 1, 2036, transm ission indebtedness will be payable from revenues to be derived from wholesale and retail customers who use the District's transm ission facilities , as well as revenues from various SPP tariffs .

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 District plans to issue add itional revenue bonds in 2017 to finance transmission projects.

In November 2016, the District issued General Revenue Bonds, 2016 Series C and 2016 Series D, in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and refund $61.7 million Tax-Exempt Commercial Paper ("TECP"). The District also issued in November 2016, General Revenue Bonds, 2016 Series E (Taxable), in the amount of $56.1 million to fund a portion of OPEB costs for 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 million of TECP. The refunding reduced total debt service payments over the life of the bonds by $29 .8 million , which resu lted in present value savings of $20 .8 million .

In January 2016, the District issued TECP in the amount of $43 .6 million to refund a portion of the General Revenue Bonds, 2005 Series C and General Revenue Bonds, 2006 Series A. In February 2016, $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and Series B.

In February 2015, the District issued General Revenue Bonds , 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds . The refunding reduced total debt service payments over the life of the bonds by $42.0 million , which resulted in present va lue savings of $26.1 million .

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

CAPITAL REQUIREMENTS The Board-authorized capital projects totaled approximate ly $109.5 million , $501 .0 million , and $197.4 million, 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 .

Capital projects for 2016 included :

$22 .0 million for construction of a high-voltage transmission line from the Muddy Creek substation to Ord , Nebraska

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

$12 .6 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2 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 line and related substations from the Hoskins substation northeast of Norfolk, Nebraska to Neligh, 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 million, and $80.8 million 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 in 2015. The District will receive revenues from other transmission owners in SPP for their share of these projects over the projects' depreciable life.

Specific capital projects for 2017 include:

$12.5 million for implementation of Advanced/Smart Metering and Interfaces

$7.7 million for construction of an evaporation pond at GGS

$7.4 million for refurbishment of a 115 kV substation in Beatrice, 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.

CAPITAL REQUIREMENTS

$600

$501

$500 U) c:

.!2 $400

.-

~ $300

...

Ill

$197 0"' $200

. I_---

c

$100

$-

2014 2015 2016 2017 Budget RESOURCE PLANNING The District's core planning principles for its most recent Integrated Resource Plan ("IRP") align with the Board 's strategic goals which include further diversifying its mix of generating resources (nuclear, coal , hydro, wind ,

energy efficiency and demand response) , energy storage, and capitalizing on the competitive strengths of Nebraska (available water, proximity to coal , and abundance of wind) . Key goals from the IRP include:

achieving a goal of 10% of the District'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 Report

The probabilistic analysis under the IRP focused on key future uncertainties , including customer load growth ,

future environmental regu lations 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 load generation from expiring capacity and energy contracts out of CNS ,

and lower projected load growth , the District is positioned to meet its fi rm load requirement needs for the next 1O to 15 years . Specific actions on which the District will focus to meet load growth needs include addition of renewables , effectiveness of energy efficiency programs and evaluation of additional peaking capacity.

The District's Board approved the IRP during the second quarter of 2013. Although the IRP 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 operation 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 also 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 impact on the District. The District expects to issue its next IRP in 2018 .

Renewable Energy The District 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 single-largest industrial customer served in the District's territory . The District entered into a 20-year contract with Monolith to purchase the carbon black plants' production of hydrogen rich tail gas, which will be produced by Monolith during production of carbon black. The District will have to convert its existing coal-fired boiler at Sheldon 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" ) , mercury, 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 led 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 .

ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks , including exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the 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 the SPP Integrated Market, the District relies upon TEA to both transact on its behalf in the wholesale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets .

Financial Report 26

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

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

These documents establish the philosophy, objectives, delegation of authorities, approved products and their limits on the District's energy and fuel activities necessary to govern its ERM program . The objective of the ERM program is to increase fuel and energy price stability by hedging the risk of significant adverse impacts to cash flow. These adverse impacts could be caused by events such as natural gas or power price volatility, or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed .

ECONOMIC FACTORS The recent slowing of growth of Nebraska's economy continued in 2016. The state's inflation adjusted 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 the national gross domestic product over the same 12-month period and a substantial decrease from Nebraska's revised estimated 2.0% increase in GSP from the third quarter of 2014 to the third quarter of 2015. Nebraska's slowdown in GSP growth over the latest 12 months has been due to declines in the "Management of companies and enterprises, "Transportation and warehousing" and "Durable goods manufacturing" industries.

Nebraska and the Midwest region continue to experience unemployment rates that are below the national 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 national average unemployment rate of 4.9% . Nebraska's preliminary, seasonally adjusted unemployment rate was 3.3% in December 2016, up slightly from 3.2% in December 2015. Both 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 environmental , safety, licensing , regulatory, and legislative requirements ,

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

other federal and state legislative and regulatory changes ,

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

"self-generation" by certa in industrial and commercial customers ,

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

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

changes from projected future load requirements ,

increases in costs ,

shifts in the availability and relative costs of different fuels ,

27 Financial Report

inadequate risk management procedures and practices 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 potential contributions made to climate change by coal-fired and othe r fossil-fueled generating units,

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

issues relating to cyber and physical security.

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

Competitive Environment in Nebraska While wholesale competition is expected to increase in the future , there is a Nebraska statute that prohibits competition for retail customers . Pursuant to state statutes, retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppl iers and/or pursuant to an order of the Nebraska Power Review Board . While state statutes do not provide for wholesale suppliers of electricity to have exclusive rights to serve a particular area or customer at wholesale ,

wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements.

Financial Report 28

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

We have aud ited the accompanying financia l statements of Nebraska Public Power District (the "District") which consist of the balance sheets as of December 31, 2016 and 2015, and the related statements of revenues, expenses, and changes in net position , cash flows , and the related notes to the financial statements for the years then ended .

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

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

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

Opinion In our opinion , the financial statements referred to above present fa irly, in all material respects, the financial position of the District as of December 31 , 2016 and 2015, and the respective changes in financial position and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America .

Emphasis of Matter As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for Other Postemployment Benefits in 2016 . Our opinion is not modified with respect to this matter.

Other Matters The accompanying management's discussion and analysis and the supplemental schedules on pages 14 through 28 and 62 through 64 , respectively, are required by accounting principles generally accepted in the United States of America to supplement the basic financial statements. Such information , although not a part of the basic financial statements, is requ ired by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational , economic, or historical context. We have applied certain limited procedures to the requ ired supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inqu iries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic 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 evidence to express an opinion or provide any assurance.

Our audits were conducted for the purpose of forming an opinion on the financial statements that collectively comprise the District's basic financial statements . The statistical review is presented for purposes of additional analysis and is not a requ ired part of the basic financial statements. Such information has not been subjected to the auditing procedures applied in the audits of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.

~.........+J-. Cnr..,.

St. Louis, Missouri April 13, 2017 29 Financial Report

FINANCIAL STATEMENTS Nebraska Public Power District Balance Sheets as of December 31 , (in OOO's) 2016 2015 ASSETS AND DEFERRED OUTFLOWS Current Assets :

Cash and cash equivalents .... ...... ................. ........... .......... ... ....... ... ....... . $ 102,729 $ 85,060 Investments ........ ... ... ........... ... .... ..... ....... ..... ...... ........... ... ... ... .... . .... ... ... . 373 ,331 400,426 Receivables , less allowance for doubtful accounts of $530 and $515, respect ively .. ..... ........ ... ........ ... ............ ..... ...... ........ .. 123,905 110,089 Foss il fuels , at average cost ... ... .. .. ........ .. ....................... ...... ... .......... .... . 43,620 39,335 Materials and supplies , at average cost ........ .. ... ... .. .. .... ................... .... ... . 114,640 117,430 Prepayments and other current assets ..................................... ...... ...... .. . 17,254 11 ,938 775,479 764,278 Special Purpose Funds :

Construction funds .. ........... ... .. ............ ... .... ..... ....... ........ ..... ............... ... . 106,204 76,503 Debt res er.A:! funds ............. .... ... ... ..... .. ............. ...... ......... .. .. ............ .. .... . 90,032 91 ,772 Employee benefit funds ......... ..... ...... ..... ... ... ... ... .................. .................. . 4 ,851 3,344 Decommissioning funds ........... .... ... .. .. ... ... .. ......... ........... ....... ............... . 581 ,770 567,348 782,857 738,967 Utility Plant , at Cost:

Utility plant in serv;ce ........... .... ... .... ... ....... .... ........ .... ............ ...... ....... ... . 4 ,971 ,259 4,751 ,016 Less res er.A:! for depreciation ....... .... ......... .. .......... ........... .. .. ........ ...... .. ... . 2,708,036 2,620,091 2,263 ,223 2, 130,925 Construction work in progress ... ......... ... .. ........ ........ .... ... ..... ..... ..... ......... . 135,853 209,626 Nuclear fuel , at amortized cost ... .............. ..... ... ........ .. .... .... .... .............. .. . 197,730 168,420 2,596,806 2,508,971 Other Long - Term Assets :

Regulatory asset for asset retirement obligation .............. .... ....... .... ...... ... . . 44,899 32,323 Regulatory asset for other postemployment benefits ...... .................... ...... . 221 ,973 121,595 Long - term capacity contracts .. ... ... .. ........... ..... .. ... ..... ... ..... .... ... ..... ... ... .. . 159,445 172,966 Unamortized financ ing costs ... ....... .... ....... ........ .. ........ ...... .. ...... .......... ... . 8,945 8,654 Investment in The Energy Authority ..... ............ .... .. ............... .................. . 6,370 7,018 Other .... .......... ... ........ .... .. .. .. ...... .................... ............ .... ..... .. .. .... ......... . 9,416 11,083 451 ,048 353,639 Total Assets ....... ... ..... .................. ........ .... .. ..... ....... ... ....... .... ....... . 4,606, 190 4,365,855 Deferred Outflows of Resources :

Unamortized cost of refunded debt .................................................... ..... . 42,664 40,775 Other post employment benefits ... ............ ..... .................... .. ............. ...... . 82,289 12~ . 953 ~o . 775 TOTAL ASSETS AND DEFERRED OUTFLOWS ....... ...... ...... .......... ............. . $ 4,731 ,143 $ 4,406,630 LIABILITIES , DEFERRED INFLOWS , AND NET POS ITlON Current Liabilities :

Revenue bonds , current .............. ... ..... ....... ........ ...... .......... ......... .... .. ... .. . $ 81 ,250 $ 114,860 Notes and credit agreements , current ......................... .. .............. ..... .. ..... . 74,000 Accounts payable and accrued liabilities ..... .. .... ... ... .. ....... .... .... ... ............ . 87,061 63,614 Accrued in lieu of tax payments .............. .................... ......................... .. . 10,008 9,948 Accrued payments to retail communities ..... ... ... ... ...... ...... ........... ... .... ... . . 6,037 6,087 Accrued compensated absences ... ....... .... .... .. ... ..... ..... ...... ..... ..... .......... . 17,594 16,857 Other ...... .... ............... .. ... .. .. .... ............ ... ..... .............. .. ........... ........ .. ... . . 11 ,372 7,492 287,322 218,858 Long - Term Debt:

Revenue bonds , net of current ... ..... .... ... .. .. .. ....... ...... .. ... .. .. ....... ..... .... ... .. . 1,678,844 1,596,972 Notes and credit agreements , net of current ...... .. ...... ........... ..... ...... ... .... . . 188,924 241 ,700 1,867,768 1,838,672 Other Long- Term Liabilities :

Asset retirement obligation ...... ....... .... ...... ... ... ... ..... .......... .......... ...... ..... . 627,707 600,311 Net other postemployment benefit liability ....................... .... ......... .......... . . 258 ,609 121 ,595 Other ..... ..... .. ... .... ......... ... ............. ..... ... .. .... .. ......... ......... .... ... .. ... .. ....... . 3,362 5,164 889,678 727,070 Total Liabilities ...... ...... ... ......... ................................. ............... .... . 3,044.?M 2,784,600 Deferred Inflows of Resources :

Unearned revenues ..... .. ..... ...... ..... ....... .... .. ............ ..... .... .. ... .. ... .... ........ . 168,710 176,118 Other deferred inflows ..... .. .... ........ ... ...... .... ..... ...... ...... ..... ...... ... ... ... .. ..... . 102,548 113,728 271 ,258 289,846 Net Pos ition :

Net investment in capital assets .... ...... ..... ............................ .. .... ..... ...... . . 928,967 866,699 Restricted ... .... .... ....... ....... ..... ........ ... ........ ...... ... .... .... .. .... ........ .. .... .. .. .. . 38,776 40,492 Unrestricted .... ............ .... .......... ...... ..... ........ ............... ...... ......... .... ... .. . . 447,374 424,993 1,415, 117 1, 332,184 TOTAL LIABILITIES , DEFERRED INFLOWS , AND NET POSITION ... ............. . $ 4,731 ,143 $ 4,406,630 The accompanying notes to fi na ncial statements are an integral part of these statements .

Financial Report 30

Nebraska Public Power Distri ct Statements of Re-..enues , Expenses , and Changes in Net Pos ition For the years ended December 31 , (in OOO's) 2016 2015 Operating Re-..enues .............................................................. .. .. .... ............ . $ 1, 153,997 $ 1,097,216 Operating Expenses :

Power purchased ............. ....... .......... ........ .... ..... ............... ... ............ ..... . 177, 121 166,587 Production:

Fuel ... ........ ........ ....... ...... ... .. .......... ... ..... ...... .. ............ .. ......... .... .... .. . 170,450 198,557 Operation and maintenance ............ .. ......... .. ....... ... ........................ ... .. 287,672 242,787 Transmission and distribution operation and maintenance ..... .... .... ... .... ..... . 101 ,952 87,259 Customer service and information ......... ... .... ... ................... ... ........... .. .... . . 17,696 17,213 Administrati-..e and general ... .......................................................... ........ . 94, 112 66,291 Payments to retail communities ... ............. .. .. .......................... ....... ...... .. . 26,553 26,552 Decomm issioning ... ...... .... ..... ................ .. .. .. ...... ............................ .. ..... . 21 ,429 14,720 Depreciation and amortization ..... ......... ......................... ............... .. .. .. .... . 133,666 130,247 Payments in lieu of taxes ......... .............. .... ............ ..... ... ..................... .. . 10,064 10,046 1,040,715 960,259 Operating Income .. ....... .. ..... ... .. .... .. ........... .... ...... ... .... .. .... .. ... ... .. ..... ..... ... .. . 113,282 136,957 ln-..estment and Other Income:

ln-..estment income ................... ...... .. ........ ..... ......... .. ... ... ...... ....... .... ...... . 28,239 18,952 Other income .. ...... ....... .. ....... ......... .... .... ... .............. ..... ... ........ ...... .. .... . . 3,533 3,403 31 ,772 22,355 Increase in Net Pos ition Before Debt and Other Expenses ............................ . 145,054 159,312 Debt and Other Expenses:

Interest on long-term debt ........ ... .. ..... ..... .... ....... .... ............................... . 75,415 80,485 Allowance for funds used during construction .. .......................... ..... ....... .. . (4, 120) (3,414)

Bond prem ium amortization net of debt issuance expense ... ... .. ...... ......... . . (11,427) (10,392)

Other expenses .. ..... ..... ................... ....... ........ ... ............... ..... ... ..... ...... . . 2,253 1,573 62, 121 68,252 Increase in Net Position ..... ............ ........ .. .. ...... ............... .... ....... .. .... .. ........ . 82,933 91 ,060 Net Position:

Beginning balance ..................... ........................................................... . 1,332, 184 1,241 , 124 Ending balance ................................... .. ..... .... ..... .. .. .......... ... .. .... .... ....... . $ 1,415, 117 $ 1,332,184 The accompanying notes to financial statements are an integral part of these statements.

31 Financial Report

Nebraska Public Power District Statements of Cash Flows For the years ended December 31 , (in OOO's) 2016 2015 Cash Flows from Operating Activities :

Receipts from customers and others ............ ............ ................ .............. . $ 1,067, 143 $ 1,101 ,150 Other receipts ........ ....... ...... .............. ...... ... ........ ..... ..... ..... ....... .... ........ . 209 8,082 Payments to suppliers and \ndors .................. ........... ............ ...... ....... .. . (565,252) (498,959)

Payments to employees ...... .... ............ .... ............ .. .............. .. ...... ...... .... . (248 ,389) (237,770)

Net cash provided by operating activities ...................................... .. .... . 253,711 372,503 Cash Flows from ln\sting Activities:

Proceeds from sales and maturities of in\stments ............. ..... ..... .. ........ . . 2,775,601 597, 190 Purchases of in\stments .. ..... .. .. .. ... ..... ......... ... .............. .. .... ....... ... ... .... . (2,800, 722) (591 ,330)

Income recei\d on in\stments ... ..... ....... ... .................. .... .... .... ........ ... .. . 27,495 5,101 Net cash provided by in\sting activities .... ..... .. .. .... .. .... ...... ................ . 2,374 10,961 Cash Flows from Capital and Related Financing Activities :

Proceeds from issuance of bonds ...... ...... ..... .. ..... .. .. ............ .. .... .... ...... ... . 354 ,776 261 , 189 Proceeds from notes and credit agreements ............. .. ... ...... ....... ... .. ... .... . . 163,807 10,363 Capital expenditures for utility plant ... .. ... .... .. .... ............... .... ..... .............. . (261 ,900) (175,744)

Contributions in aid of construction and other reimbursements .............. .. .. . 18,864 12,575 Principal payments on long-tenn debt ............................... ........ ...... .... .. . . (284,710) (349,425)

Interest payments on long - tenn debt ... ...... .......... ............. ... ...... ........ .. ... . (77,776) (81 ,800)

Interest paid on defeasance debt ... ................ ..... ... .... ............ .. ........... .... . (10,194) (21 ,268)

Principal payments on notes and credit agreements ........ .... ..... ......... .... .. . (142,583) (46, 166)

Interest payments on notes and credit agreements ..... .... ... ... .... .. ... .. .. ..... . . (2, 145) (1 ,611)

Other non-operating re\nues ......... ....... ...... .. .... ..... .. ... .. .... .............. ...... . 3,445 3,404 Net cash used in capital and related financing activities ....... ...... .......... . (238,416) (388,483)

Net increase {decrease) in cash and cash equivalents .. .. .. .. .. ....... ... .. ... . 17,669 (5,019)

Cash and cash equivalents , beginning of year ...... ..... ... ... ....... ... ... ..... ..... .... .. . 85,060 90,079 Cash and cash equivalents , end of year .... ... ... ................ ..... .... .... ..... .. ........ . . $ 102,729 $ 85,060 Reconciliation of Operating Income to Cash Pro\ided By Operating Acti\ities :

Operating income ..... ..... ........................ ...... .... ..... ................... .. .......... . . $ 113,282 $ 136,957 Adjustments to reconcile operating income to net cash pro\ided by operating acti\ities :

Depreciation and amortization .......... .......... ... .... ... .. ..... ... .... ..... ... ... .... . 133,666 130,247 Undistributed net re\nue - The Energy Authority ...... .... .... .... ...... .. ...... . 648 (956)

Decommiss ioning, net of customer contributions .. .. .. ... .. ... ... ... .... ...... .. . . 21,429 14,720 Amortization of nuclear fuel ...... ... ............ .... .. .... ... ....... ... ..... .. ..... ... .... . 40,754 47,626 Changes in assets and liabilities which (used) pro\ided cash:

Receivables , net ............ .... ......... ... ... ... ........ ..... .. ..... ............ ..... ... . (10,911) 5,973 Fossil fuels ........... ........ .... .......... ... .. ............... ........................... . . (4,285) (2,761)

Materials and supplies ... .... ......... ........ .......... ...... ...... .... ..... ..... ..... . 2,790 4,334 Prepayments and other current assets ............... .......................... .. 1,022 (40)

Other long - tenn assets .... ...... ........ ..... ...... .... ..... .... ... .. .... .. .. ....... .. . 935 850 Deferred outflows .............. .......... ............ .............. .... ...... ... ........ .. . (45 ,654)

Accounts payable and accrued payments to retail communities ....... . 19, 122 (2,443)

Unearned re\nues .. ........ .... .. ................. ....... .. .. ............. ..... ........ . (7,408) (1 ,025)

Other deferred inflows ... ... ........ ...... ... ....... .... ... ...... ......... ...... ... .... .. . (14,342) 36,715 Other liabilities ... .... ...... .... ..... .. ... ... ...... .. .. .. ......... ..... ..... .. .. .. ....... .. . 2,663 2,306 Net cash pro\ided by operating acti\ities .... .. .... ... ... .... ....... .... ...... ... .... . $ 253,71 1 $ 372,503 Supplementary Non - Cash Capital Acti\ities :

Change in utility plant additions in accounts payable ... ... .... ... ................... . $ 4,273 $ 7,924 The accompanying notes to financial statements are an integral part of these statements.

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 its operations is vested in a Board of Directors ("Board ") consisting of 11 members popularly elected from districts comprising subdivisions of the District's chartered territory. The Board is authorized to establish rates.

B. Basis of Accounting -

The financial statements are prepared in accordance with Generally Accepted Accounting Principles ("GAAP") for accounting guidance provided by the Governmental Accounting Standards Board ("GASS") for proprietary funds of governmental entities. In the absence of established GASS pronouncements, other accounting literature is followed 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 unregulated entity.

C. Revenue -

Retail and wholesale revenues are recorded in the period in which services are rendered. Revenues and expenses related to providing energy services in connection with the District's principal ongoing operations are 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 liquid investments in the Revenue Funds with an original maturity of three months or less to be cash and cash equivalents on the balance sheet, except for these type of investments in the Revenue Funds investment account. Cash and cash equivalents in the investment accounts for the Revenue Funds and the Special Purpose Funds are reported as investments on the balance sheet.

E. Fossil Fuel and Materials and Supplies -

The District maintains inventories for fossil fuels , and materials and supplies which are valued at average cost.

Obsolete inventory is expensed and removed from inventory.

F. Utility Plant, Depreciation, Amortization, and Maintenance -

Utility plant is stated at cost, which includes property additions, replacements of units of property and betterments .

The District charges maintenance and repairs , including the cost of renewals and replacements of minor items of property, to maintenance expense accounts when incurred . Upon retirement of property subject to 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 basis.

Depreciation on utility 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 , respectively , which was included in depreciation and amortization expense. These plant additions, which were fu lly depreciated , totaled $185.6 million and $180.9 million at December 31 , 2016 and 2015, respectively.

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

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

Construction financed on a short-term basis with tax-exempt commercial paper ("TECP"), or taxable revolving credit agreement ("TRCA") is charged a rate based upon the projected average interest cost of TECP or TRCA outstanding . For the periods presented herein , the AFUDC rates for construction funded by revenue bonds varied from 2.2% to 4.9% . For construction financed on a short-term basis with TECP, the rate was 1.0% for 2016 and 2015 .

H. Nuclear Fuel -

Nuclear fuel inventories are included in utility plant. The nuclear fuel cycle requirements are satisfied through the procurement of raw material in the form of natural uranium , conversion services of such material to uranium hexafluoride, uranium hexafluoride that has already been converted from uranium , enrichment services, and fuel fabrication and related services. The District purchases uranium and uranium hexafluoride on the spot market and 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 include issuance expenses for bonds which are being amortized over the life of the respective bonds using the bonds outstanding method . Deferred unamortized financing costs associated with bonds refunded are amortized using the bonds outstanding method over the shorter of the origina l or refunded life of the respective bonds. Regulatory accounting , GASB codification section Re 10, Regulated Operations, is used to amortize these costs over their respective periods .

J. Asset Retirement Obligations -

Asset retirement obligations ("ARO") represent the fair value of the District's legal 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 facilities.

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 , information about the fiduciary net position of the District's Post-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. Additional disclosures related to OPEB are in Note 11.

L. Auction Revenue Rights and Transmission Congestion Rights -

The District uses Auction Revenue Rights ("ARR") and Transmission Congestion Rights ("TCR") in the Southwest Power Pool ("SPP") Integrated Market to hedge against transmission congestion charges. These financial instruments were 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 reacquisition price and the net carrying amount of the refunded debt in an advance refunding . Deferred outflows related to OPEB include contributions made during the current year and experience losses.

Deferred inflows of resources are acquired assets that are applicable to future reporting periods and consist of regulatory liabilities for unearned revenues and other deferred inflows. Other deferred inflows include 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 is required under the General Revenue Bond Resolution ("Resolution") to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses, aggregate debt service on the General Revenue Bonds, amounts to be paid into the Debt reserve fund and all other charges or liens payable out of revenues . In the event the District's rates for wholesale service result in a surplus or deficit in revenues during a rate period , such surplus or deficit, within certain limits, may be retained in a rate stabilization account. Any amounts in excess of the limits will be taken into account in projecting revenue requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the District's long-term wholesale power supply contracts . The District accounts for any surplus or deficit in revenues for retail service in a similar manner.

The following table summarizes the balance of Unearned revenues as of December 31 , 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 lization 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 liability 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 Nuclear Waste Policy Act until the DOE adjusted the spent fuel disposal fee to zero, effective May 16, 2014. The Board authorized the use of regulatory accounting for the continued collection of these costs .

This approach ensures costs are recognized in the appropriate period with 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 following table summarizes the balance of Deferred outflows of resources as of December 31 , 2016 and 2015 (in OOO's) :

2016 2015 Unamortized 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 investment in capital assets, Restricted , and Unrestricted .

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

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

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

0 . Use of Estimates -

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

P. Recent Accounting Pronouncements -

GASS Statement No. 85, Omnibus 2017, was issued in March 2017. This Statement addresses practice issues that were identified during implementation and application of certain GASS statements including statements on OPES. This Statement provides clarification for the presentation of payroll-related measures in 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 contributions 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 is 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 guidance was the only portion of this Statement with an impact on the District.

Financial Report 36

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

GASS Statement No. 83 , Certain Asset Retirement Obligations, was issued in November 2016 . This Statement addresses accounting and financial reporting requ irements for certain AROs . This Statement imposes requirements in regards to the ARO liability recogn ition, measurement and specifics on when re-measurement should occur. This Statement also requ ires disclosures regard ing the methods and assumptions used to estimate the ARO , the remaining useful life of capital assets associated with the liability, any governmental legal fund ing requ irements , 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 ich 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 guidance 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 Pensions, was issued in June 2015. The requirements of th is 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 liability), 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 unrealized net loss of $1 .2 million for the year ended December 31 , 2015.

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

2016 2015 Weighted Weighted A-.erage A\erage Fair Value Maturity (Years) Fair Value Maturity (Years )

U.S. Treasury and go-.emment agency securities . $ 936,317 4.0 $ 909,449 3.7 Corporate bonds . .. .. .. .. ... .. .. ... .. . .... .. .. ... ... .. .. .. .... . . 181,438 9.6 196,766 11 .8 Municipal bonds ....... .......... ... ........ ... ... ...... .. .... .. 11 ,901 12.4 10, 184 15.6 Cash and cash equivalents .. .. .... .. .......... ...... .... ... 129,261 108,054 Total cash and in\estments .......... .......... .. .. .. . -$-=---1.-2.,,..58-.-9-17--- $1 ,224,453 Portfolio weighted a\erage maturity .... .. ...... .... .................. .. 4.5 4.8 Interest Rate Risk- The investment strategy for all investments, except for the decommissioning funds , is to buy and hold securities until maturity, which minimizes interest rate risk. The investment strategy for decommissioning 37 Financial Report

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

Custodial Credit Risk- Cash deposits, primarily interest bearing, are covered by federal depository insurance, pledged collateral consisting of U.S. Government 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.

2016 2015 Re1.enue funds - Cash and cash equivalents ...... ......................... .......... .... ...... $ 123,678 $ 91 ,948 Re1.enue funds - ln1.estments ......... ..... .......... ......... .. ... .. ............. ................... . 352,382 393,538

$ 476,060 $ 485,486 The Construction funds are used for capital improvements , additions, and betterments to and extensions of the District's system . The sources of monies for deposits to the construction funds are from revenue bond proceeds and issuance of short-term debt.

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 District is required by the Resolution to maintain an amount equal to 50% of the maximum amount of interest accrued in the current or any 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 lawful 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 2015 Debt reser.e funds - Cash and cash equivalents . . . .. . . .. . . . . .. . . .. . . . . . . . . . .. . . . . .. . . . . . . . . . $ $ 50 Debt reser.e funds - ln'loestments .. .... .. ..... .. ... ..... ... ......... .. ........ ........ ..... .... ... . 90,032 91,722

$ 90,032 $ 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 retired employee life insurance 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 million and $2.3 million at December 31 , 2016 and 2015 , respectively. 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 in Employee benefit funds at December 31 , 2015.

For additional information on OPEB see Note 11 .

2016 2015 Employee benefit funds - Cash and cash equivalents . .. . . . .. ... ....... .. . ... . .... .. . . . .. . . $ 1,843 $ 1,349 Employee benefit funds - ln\oestments .... . ... .. ... . . .. .. .. . . .... . ... .. .. ............ .. .. .. ... . .. 3,008 1,995

-$- - -4,851

-- $ 3,344 The Decommissioning funds are utilized to account for the investments held to fund the estimated cost of decommissioning CNS when its operating license expires. The Decommissioning funds are held by outside trustees or custodians in compliance with the decommissioning funding plans approved by the Board which are invested primarily in fixed income governmental securities.

2016 2015 Decommissioning funds - Cash and cash equivalents .. .. .. .. . . ... ... .. . . . ... . .. . .. .. ... ... $ 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 liability (an exit price )

in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date.

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

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

Active markets are those in wh ich transactions for the asset or liability occur in sufficient frequency and volume to 39 Financial Report

provide pricing information on an ongoing basis. The District's investments in cash and cash equivalents are included as Level 1 assets.

Level 2 - Pricing inputs are other than quoted market prices in the active markets 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 liabilities in active markets;

quoted prices for identical assets or liabilities in inactive markets;

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

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

Level 2 assets primarily 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 methodologies using significant unobservable inputs. The District currently does not have any Level 3 assets or liabilities.

The District performs an analysis annually to determine the appropriate hierarchy level classification of the assets and liabilities that are included within 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 special purpose funds , excluding decommissioning:

U.S. Treasury and gowmment agency securities ......... ... $ $ 551 ,602 $ $ 551,602 Cash and cash equivalents ... .. ... .. .... .... .......................... 125,546 125,546 Decommissioning 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 issioning:

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 RnandalReport 40

4. UTILITY PLANT:

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

December 31 , December 31 ,

2015 Increases Decreases 2016 Nondepreciable utility plant:

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

Generation - Fossil ......... ......... .. ..... .. ... .... .. 1,573,880 65,818 (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 Total 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 Generation - Nuclear .. .................. .............. 1,353,374 31 ,240 (583) 1,384,031 Transmission .................. ... ...... .... ... ...... ..... 1, 153,704 26, 147 (7,743) 1, 172, 108 Distribution .. .... .. .... ...... .. .......... ... ............... 217,893 6,877 (2,979) 221 ,791 General ....... ... .. .... .... ..... .................... .. .. ... . 335,407 14,487 (15,058) 334,836 Total 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 Utility plant activity , net ... ................................ $ 2,495,206 $ 183,596 $ (169,831) $ 2,508,971

Nuclear fuel decreases 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 Unit 2 ("NC2") coal-fired power plant. The District has a participation power agreement with OPPD for a 23.7% share of the power from this plant. NC2 began commercial operation on May 1, 2009, at which time the District began amortizing the amount of the capacity contract associated with the plant on a straight-line basis over the 40-year estimated useful life of the plant.

Accumulated amortization was $35.4 million and $30.8 million in 2016 and 2015, respectively. The unamortized amount of the plant capacity contract was $143.7 million and $154.8 million as of December 31 , 2016 and 2015, respectively, of wh ich $4.4 million was included in Prepayments and other current assets as of December 31 ,

2016 and $4.6 million in 2015. The District'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 facility owned and operated by The Central Nebraska Public Power and Irrigation District ("Central").

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

Accumulated amortization was $64.3 million and $62.0 million at December 31 , 2016 and 2015, respectively. The unamortized amount of the Central capacity 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 District has an agreement whereby Central makes available all the production of the facil ity and the District pays all costs of operating and maintaining the facility plus a charge based on the amount of energy delivered to the District. Costs of $2 .5 million and $2.3 million in 2016 and 2015, respectively, are included in 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 in Jacksonville, Florida , and incorporated in Georgia. TEA provides public power utilities access to dedicated resources and advanced technology systems. The District's interest in TEA was 16.67% as of December 31 ,

2016 and 2015, respectively. In addition to the District, the following utilities have interests 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: City Utilities of Springfield , Missouri ; Cowlitz County Public Utility District (Washington) 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 obligated to guaranty, directly or indirectly, TEA's electric trad ing activities in an amount up to

$28 .9 million plus attorney's fees which any party claiming and prevailing under the guaranty might incur and be entitled to recover under its contract with TEA. Generally, the District's guaranty obligations for electric trading would arise if TEA did not make the contractually required payment for energy, capacity, or transmission which was delivered or made available or if TEA failed to deliver or provide energy, capacity, or transmission as required under a contract.

The District's exposure relating to TEA is limited to the District's investment in TEA, any accounts receivable from TEA, and trade guarantees provided to TEA by the District. Upon the District making any payments under its electric guaranty, it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably, based upon each member's interest in TEA. 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 igations by causing to be provided advance notice to the beneficiaries thereof. Such Financial Report 42

termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect. The District has no liabilities for these guarantees as of December 31 , 2016 and 20 15.

Financial statements for TEA may be obtained at The Energy Authority, 301 W. Bay Street, Suite 2600, Jacksonville, Florida , 32202 .

7. DEBT:

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

Principal Amounts Due December 31 , December 31 , Within One 2015 Increases Decreases 2016 Year Re\nue bonds .. ....... .... .......... .. $ 1,596,972 $ 354,776 $ (272,905) $ 1,678,844 $ 81 ,250 Commercial paper notes .... .... .... 83,000 88,365 (97,365) 74,000 74,000 Rel.()l\ing credit agreements ... .. .. 158,700 75,443 (45,219) 188,924 Total long -term debt acti\ity .. $ 1,838,672 $ 518,584 $ (415,489) $ 1,941,768 $ 155,250 The following table summarizes the debt balances, net of current maturities, as of December 31 , 2015 and 2014, and activity for 2015 (in OOO's):

Principal Amounts Due December 31 , December 31 , Within 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 acti\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 District plans to issue additional revenue bonds in 2017 to finance transmission projects.

Also in April 2017, the District entered into an escrow deposit agreement in conjunction with the refunding of certain of the :

General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2018 through January 1, 2028 In November 2016, the District issued General Revenue Bonds, 2016 Series C and 2016 Series D, in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and to refund a portion of Commercial Paper Notes, Series A. The District also issued in November 2016, General Revenue Bonds, 2016 Series E (Taxable), in the amount of $56.1 million to fund a portion of OPEB costs for customers under the 2016 Contracts.

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

$139.2 million to advance refund $138 .9 million of bonds and refund $16.5 million of commercial paper notes. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million .

43 Financial Report

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

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

General Revenue Bonds , 2008 Series B, having maturity dates rang ing 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 District issued TECP in the amount of $43 .6 million to refund a portion of the General Revenue Bonds, 2005 Series C and the General Revenue Bonds, 2006 Series A.

In February 2015, the District issued General Revenue Bonds, 2015 Series A, in the amount of $223 .0 million to advance refund $239 .2 million of bonds. The refunding reduced tota l debt service payments over the life of the bonds by $42.0 million , which resulted in present value savings of $26.1 million .

Also in February 2015, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the :

General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2026 through January 1, 2041

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

General Revenue Bonds , 2007 Series B, having maturity dates rang ing from January 1, 2023 through January 1, 2037

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

General Revenue Bonds, 2012 Series 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 outstanding: 2007 Series B, 2008 Series B, and 2012 Series C.

Debt service payments and principal payments of the General Revenue Bonds as of December 31 , 2016, are as follows (in OOO's):

Debt Ser\1ce Principal 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 value of outstanding revenue bonds was determined using currently published rates . The fair value was estimated to be $1 ,750.1 million and $1 ,765.4 million at December 31 , 2016 and 2015, respectively .

Financial Report 44

Commercial Paper Notes The 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 District 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 issuance 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 principal outstanding of the TECP notes. No amounts were drawn on the line of credit as of December 31 , 2016 and 2015.

Taxable Revolving Credit Agreement The District has entered into a Taxable Revolving Credit Agreement ("TRCA") with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 million . The TRCA allows the District 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 15, 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 collections through electric rates and the issuance of revenue bonds. The carrying value of the revolving credit agreements approximates market value due to the short-term nature of the agreements.

45 Financial Report

Rel.nue bonds consis t of the following (in OOO's ex cept interest rates ):

December 31, Interest Rate 2016 2015 General Rel.nue Bonds :

2005 Series C:

Serial Bonds : 201&-2025, 2040 .... .. .. ........ ..... 3.875% - 5.00% $ $ 44 ,230 2006 Series A:

Serial Bonds : 203&-2040 ......... .... ............. ... . 4.375% 400 2007 Series B:

Serial Bonds : 201&-2026 .......... .. ..... ........ .. ... 4.375% - 5.00% 97,415 111 ,825 Term Bonds : 2027- 2031 ......... .............. ....... 4.65% 9,620 31 ,190 2032- 2036 ... ... ..... .... ..... ...... .. .. 5.00% 7,120 4.00% - 5.00% 10,700 38,785 5.00% 22,860 5.00% 40,375 5.00% 7, 180 6.606% 17,465 17,465 7.399% 32,890 32,890 3.50% - 4.25% 4,605 6,595 3.98% - 4.73% 31 ,875 31 ,875 5.323% 27,985 27,985 5.423% 54,190 54,190 2.858% - 4.18% 3,600 4,415 3.00% - 5.00% 48,760 64,520 4.00% 6,165 6,165 5.00% 14,180 14, 180 2.50% - 5.00% 7, 115 3.00% - 5.00% 190,410 198,310 2.00% - 5.00% 92,320 95,875 3.625% 2,320 2,320 3.625% 4,155 4,155 3.00% - 5.00% 11 ,045 37,340 3.00% - 5.00% 91, 100 103,815 2.00% - 5.00% 153,630 156,145 4.00% 31 ,650 31 ,650 4.125% 1,945 1,945 3.00% - 5.00% 143,025 162,415 3.00% - 5.00% 119,400 119,400 3.00% - 5.00% 56,485 56,915 5.00% 46,205 46,205 3.125% - 5.00% 65,210 5.00% 5,595 5.00% 67,255 5.00% 1, 165 3.00% - 5.00% 70,685 2.00% - 5.00%

5.00%

2.337% - 3.567%

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 les 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, respectively.

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 primarily to the add ition of a liability for the Ainsworth Wind Energy Facility, that was more than offset by a reduction in liabilities 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 established 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 ,

respectively. See Note 2 for additional information .

The following table shows changes to the ARO that occurred during the years ended December 31 , 2016 and 2015 , and are included 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 District contributes two times the Plan member's contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District contributes one times the Plan member's contribution . The Participants' contributions were $13.4 million and $12.8 million for 2016 and 2015, respectively . The District's matching contributions 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.

47 Financial Report

Plan members are immediately vested in the ir own contributions and earn ings and become vested in the District's contributions and earn ings based on the following vesting schedu le:

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

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

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

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

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

Nonvested District contributions are fi rst used to cover Plan administrative expenses and any remaining forfeitures are al located back to Plan participants .

Employees may also contribute to a defined contribution 457 pension plan ("457 Plan"). The 457 Plan is a tax-deferred investment option with no District match . Pay period contributions can be elected and changed at any time . Early withdrawals can be made from the 457 Plan following separation of service regardless of age with no IRS penalty. Income taxes are owed on any withd rawals . The Participants ' contributions were $2.1 million and

$2 .0 million for 2016 and 2015 , respectively.

11 . OTHER POSTEMPLOYMENT BENEFITS:

The District implemented the provisions of GASS Statement No. 75 ("GASS 75"), Accounting and Financial Reporting for Postemployment Benefits Other than Pensions, in 2016. The District has elected to early adopt the provisions of GASB 75. GASS 75 requires retroactive application unless it is impractical to apply the requirements on a retrospective basis. The District has concluded that retrospective application is impractical based on a cosUbenefit analysis and other considerations. The District would incur additional third-party actuarial costs to develop the necessary data for retrospective application. Additionally, given the District's application of regulatory accounting, the impact of applying provisions of GASB 75 to prior periods would be entirely offset by the recognition of a regulatory asset reflecting the future recovery of any OPEB costs . Accord ingly, retrospective application of GASB 75 would not impact the District's net position for 2015. Further, there was no impact to beginning net position as a resu lt of the implementation of the provisions of GASS 75 in 20 16.

A. General information regarding the OPEB Plan -

Plan Description The District's Post-Employment Medica l and Life Benefits Plan ("Plan") provides postemployment hospital-medical and life insurance benefits to qualifying retirees , surviving spouses, and employees on long-term disability and their dependents . Benefits and related el igibility, funding and other Plan provisions, for this single-employer, defined benefit Plan, are authorized by the Board .

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

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

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

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

2016 2015 Active employees ........ ......... .. .. ...... .................. ........... ........ .......... . 2,003 1,980 Inactive employees in retirement status .. ..... ........ ...... ......... .. ........... . 1,077 1,047 Inactive employees in long-term disability status ... ...... ....... ... ........ .. .. . 74 77 Total employees covered by benefit terms ... ....... ...... .. ........ .... ... .... . 3,154 3, 104 Contributions The Board annually approves the funding for the Plan, which has a minimum funding requirement of the actuarially-determined annual required contribution ("ARC") to achieve full funding status on or before December 31 , 2033. The District OPEB contributions were $74.7 million in 2016, which included $45.7 million of financed contributions deposited in the Trust, $24.5 million of revenue funded contributions 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 arbitration in May 2016 re lated 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 million paid for the cost of benefits/expenses.

Contributions from Plan members are the required premium share, which is based on hire date and/or age.

Contributions from Plan members were $0.5 million, $0 .6 million and $0.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. 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 liability used to calculate the net OPEB liability was determined by an actuarial valuation as of that date.

Actuarial Assumptions The total OPEB liability in the January 1, 2016, actuarial valuation was determined using the following actuarial assu mptions , applied to all periods included in the measurement, unless otherwise specified:

Actuarial cost method Entry Age Normal

Amortization method Level amortization of the unfunded accrued liability

Amortization period 17-year closed period

Asset valuation method 5-year smoothed market

Discount rate 6.25%

Healthcare cost trend rates Pre-Medicare: 8% initial, ultimate 5%

Post-Medicare: 6.75% initial , ultimate 5%

Inflation 2.1%

Investment rate of return 6.25%, net of investment expense, including inflation

Mortality RP-2014 Aggrega te table projected back to 2016 using Scale MP-2014 and projected forward using Scale MP-2015 with generational projection

Retirement age Varies by age 49 Financial Report

The actuarial assumptions used in the January 1, 2016, va luation were based on the resu lts of an actuarial experience study for the period January 1, 20 15 through December 31 , 2015 .

The long-term expected rate of return on OPES plan investments was determined using a build ing-block method in which best-estimate ranges of expected future rates of return (expected returns , net of OPES plan investment expense and inflation) are developed for each major asset class . These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected inflation . The target allocation and best estimates of geometric real rates of return for each major asset class are summarized in the following table for the valuation measurement date of January 1, 2016 :

Long-Term Expected Asset Class Target Allocation Real Rate of Return Equity ......... .. .. ................ ............ . 68% 6.8%

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

100%

Discount Rate The discount rate used to measure the total OPES liab ility was 6.25%. The projection of cash flows used to determine the discount rate assumed that contributions will be made at rates equal to the actuarially-determined contribution rates . Based on those assumptions, the OPES Plan's fiduciary net position was projected to be available to make all projected benefit payments for current active and inactive employees. Therefore , the long-term expected rate of return on OPES plan investments was appl ied to all periods of projected benefit payments to determine the total OPES liability.

C. Changes in the Net OPEB Liability -

The following table shows the Total OPES Liabil ity, Plan Fiduciary Net Position and Net OPEB Liability as of January 1, 2015 and January 1, 2016, and the changes during th is period , based on the valuation measurement date of January 1, 2016 (in OOO's):

Year Ended December 31 , 2016 Total OPES Plan Fiduciary Net OPES Liability Net Position Liabi lity (a) (b) (a-b)

Balances at 1/1/2016 (Based on 1/1/2015 Measurement Date).......... .. $ 323, 122 $ 64,487 $ 258,635 Changes for the year:

Service cost. ... .................. .... ... ... .... ..... ...... ............. ............... .... .. . 3,228 3,228 Interest. .. .. ... ...... ....................... ....... ............. .......... .. ........ ... .... .... . 19,877 19,877 Differences between expected and actual experience ...... .... ........... .. 13,657 13,657 Changes of assumptions ............ .... ...................... .................. ....... . (9, 149) (9,149)

Contributions-employer........ .. ........ .................... .... ................. ..... .. 28,242 (28,242)

Net in-.estment income ...................... ........................................... . (453) 453 Benefit payments ........................................................................ .. (1 6,902 ) (1 6,902)

Adm inistrati-.e expense ....... ... .. .. ... ................. ...... ......... ........ ...... ... (1 50) 150 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 itiated a voluntary early retirement incentive program ("Program") to all regular, full-time employees, excluding senior management, who met certain retirement-eligible criteria . There were 121 employees who accepted the offer. These early retirements are expected to increase the net OPES liability. The impact of the Program will be included in the January 1, 2017 actuarial valuation . Additional information on the Program is included in Note 14.

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The mortality assumption was updated to the RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2015 with generational projection . The cost method was changed to Entry Age Normal and the actuarial asset method was changed to five-year smoothing .

Sensitivity of the Net OPEB Liability to Changes in the Discount Rate The following table shows the net OPEB liability of the District, as well as what the net OPEB liability would be if it were calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6 .25% ) at the measurement date of January 1, 2016 (in OOO 's):

1% Decrease Discount Rate 1% Increase 5.25% 6.25% 7.25%

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

1% Decrease Healthcare Cost Trend Rates 1% Increase (Pre-Medicare ranging from (Pre-Medicare ranging from (Pre-Medicare ranging from 7% initial to 4% ultimate, 8% initial to 5% ultimate, 9% initial to 6% ultimate, Post-Medicare ranging from Post-Medicare ranging from Post-Medicare ranging from 5.75% initial to 4% ultimate) 6.75% initial to 5% ultimate) 7.75% initial to 6% ultimate)

Net OPEB Liability. ....... $219,672 $258,609 $306,1 51 OPEB Plan Fiduciary Net Position The following table shows information on the OPEB Plan Fiduciary Net Position as of December 31 , (in OOO's):

2016 2015 Cash and cash equivalents .. ... ..... .. .... ........ .. ...... ....... .... ..... .. ..... ....... $ 9,609 $ 3,719 Receivables .. ... .... .............. ............ ....... ................. .. ......... ......... .. .. . 314 253 Investments, at fair value ............. ........ ...... ...... ................ .. .... ....... .. . 132,875 71,252 Total assets ..... .. ....... .. ... ... .... .... .... ... .. .. ..... ... .... .... .... .............. ....... . 142,798 75,224 Liabilities .... ... .... .............. ... ...... ........... ........... .. .. ... .............. ......... . (289)

Net position - 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 reported 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 18, 162 Foreign issues ................... .......... .. ...... ... .... ...... 5, 161 5, 161 Municipal issues .. .............. ................ ...... .. .... ... 766 766 Domestic common stocks ................ .. .............. . 39,002 39,002 Foreign stocks ........ ... .. .. .. ..... ........ ... ........... ...... 3,569 3,569 Mutual funds .. ... ... ...... ....... .. ................ .... ... .... ... 63 ,537 63,537

$ 115,717 $ 26,767 $ $ 142,484 2015 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 ..... .. ...... ....... .... .. . $ 3,769 Difference between expected and actual earnings on investments .. .... . 3,862 Contributions made during the year ended December 31 , 2016 .... ...... . 74,658 Total Deferred Outflows .................................. ... ..... .. ..... ..... .... ..... . $ 82,289 Financial Report 52

The deferred outflows related to the contributions made during the year ended December 31 , 2016 will be recognized in the actuarial valuation with a measurement date of January 1, 2017 . The other deferred outflows of 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 information is available in the unaudited Required Supplementary Information section following the Notes to Financial Statements.

12. COMM ITMENTS AND CONTINGENCIES:

A. Fuel Commitments -

The District has various coal supply contracts and a coal transportation contract with minimum estimated future payments of $166.0 million at December 31 , 2016. These contracts expire at various times through the end of 2018. The coal transportation contract in place is sufficient to deliver coal to the generation facilities through the expiration date of the aforementioned contracts and is subject to price escalation adjustments .

The District has a contract for uranium purchases and deliveries in 2017 and 2018, a contract for conversion services of uranium to uranium hexafluoride which is in effect through 2021, a contract for enrichment services through 2024, and a contract for fabrication services through January 18, 2034, the end of the current operating license of CNS . These commitments for nuclear fuel material and services have combined estimated future payments of $250.0 million .

8 . Power Purchase and Sales Agreements -

The District has entered into a participation power agreement {the "NC2 Agreement") with OPPD to purchase 23.7% of the power of NC2, estimated to be 161 MW of the power from the 663 MW coal-fired power plant constructed by OPPD . The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs , and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursuant to such step-up provision is limited to 160% of its original participation share (23.7%). No such default has occurred to date.

The District has entered into a participation power sales agreement with Municipal Energy Agency of Nebraska ("MEAN") for the sale to MEAN of the power and energy from Gerald Gentleman Station ("GGS") and CNS of 50 MW which began January 1, 201 1 and continues through December 31 , 2023.

The District has entered into 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 is to terminate upon the later of the last maturity of the debt attributable to the respective station or the date on which the District retires such station from commercial operation .

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

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

The District has entered into long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems . These PRO Agreements expire on various dates between March 1, 2023 and March 31 , 2042. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreement.

C. Wholesale Power Contracts The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requ irements from the District, subject to certain exceptions. In 20 16, the District entered into 20-year Wholesale Power Contracts ("2016 Contracts") with 23 public power districts, one cooperative , and 37 municipalities , effective January 1, 2016. Two public power districts and 11 municipalities are served under 2002 Wholesa le Power Contracts ("2002 Contracts"), which expire on December 31 , 2021 .

The 2016 Contracts allow a wholesale customer to give notice to reduce its purchase of demand and energy requirements from the District based on a comparison of the District's average annual wholesale power costs in a given year compared to power costs of U.S. utilities for such year listed in the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given utility can compare its power costs on a percentile basis to the CFC published quartile information . The 2016 Contracts allow a wholesale customer to reduce its demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given year is higher than the 45th percentile level (the "Performance Standard Percentile") of the power costs of U.S. utilities for such year as listed in the CFC Data. The 2016 Contracts wou ld not allow any reductions in demand and energy purchases by a wholesale customer as long as the District's average annual wholesale power costs percentile rema ined below the Performance Standard Percentile.

The following table lists the District's wholesale power costs percentile for the calenda r years 20 11 to 2015 set forth in the CFC Data:

CFC Data Year Percentile 2011 24.4%

2012 29.1%

2013 31 .0%

2014 27.6%

2015 31 .3%

The 2002 Contracts allow a wholesale customer to reduce 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 District through December 31 , 2021 .

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The District has received notices from nine wholesale customers as to their intent to level off, reduce , or terminate the requirements under their 2002 wholesale contracts for various 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 District expects that no requirements of said nine wholesale customers will be served by the District in 2022 , and such wholesale customers will purchase all of their electric requirements from other suppliers. The 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 reduce 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 public power district wholesale customers . These customers represented 0.1% of the District's 2016 operating revenues . One of the District's municipal wholesale customers allowed their contract to terminate . This customer represented less than 0.1 % of the District's 2016 operating revenues.

The 2016 wholesale rates resulted in a 0.6 % increase for wholesale customers who signed the 2016 Contracts, and a 3.8% increase for those wholesale customers who remained under the 2002 Contracts. The 2002 Contract customers wi ll pay their share of previously incurred 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 increase . Eight 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 in eight separate accounts. The first meeting of the arbitration panel occurred in September 2016. The dispute now includes the OPEB component of the 2017 wholesale rates . A decision is expected 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 wholesale 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 operating 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 District Court of Wayne County, Nebraska regarding the demand and energy reduction provisions under the 2002 Contract. The court issued an order dated February 26, 2016, in favor of the Northeast Nebraska Public Power District which allows them to reduce their demand and energy purchases from the District by 30% in 2018, 60% in 2019 and 90% in 2020. The court decision will apply to certain other customers who have given notice for demand and energy reductions under the 2002 Contract. On March 23 , 2016, the District filed a notice of appeal.

0 . SPP Membership and Transmission Agreements -

The District is a member of SPP, a regional transmission organization based in Little Rock, Arkansas .

Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration , including generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning . The District was able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost, through February 2014. On March 1, 2014 , SPP commenced a Day-Ahead , Ancillary Services, and Real-Time Balancing Market Integrated Market. The Integrated Market also provides a financial market to hedge unplanned transmission congestion , or financial virtual products to hedge uncertainties, such as unplanned outages.

The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone"). This agreement addresses the transmission facil ities ,

construction , cost allocation , payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system . Cost of the project was 55 Financial Report

$8.4 million and repayment by Keystone , over a 10-year period , began in June 201 O with a remain ing balance due the District of $3.5 million and $4 .4 million as of December 31 , 2016 and 2015, respectively.

The District 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 interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system . TransCanada Corporation and TransCanada Pipeline USA Ltd . have jointly and severally guaranteed the payment obligations of Keystone under its agreements with the District. The agreement was cancelled in 2016 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 District entered into an agreement (the "Entergy Agreement") for support services at CNS with Entergy Nuclear Nebraska , LLC ("Entergy"), a wholly-owned indirect subsidiary of Entergy Corporation. In 2010, the Entergy Agreement was amended and extended by the parties until January 18, 2029, subject to either party's right to terminate without cause by providing notice and paying a $20 million termination charge . The Entergy Agreement requires the District to reimburse Entergy's cost of providing services, and to pay Entergy annual management fees. These annual management fees were $18.5 million for 2016 and $18.4 million for years 2015 and 2014. These fees will increase by an additional $1 .0 million in 2019, and by an additional

$3.0 million in 2024. Entergy is eligible to earn additional 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 incentive fee.

Since the earthquake and tsunami of March 11 , 2011 , that impacted the Fukushima Dai-ichi Plants in Japan , the District, as well as the rest of the nuclear industry, has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the General Electric 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 October 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 industry as a result of the Fukushima Dai-ichi event in Japan . The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nuclear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened 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 basis and strategy for why venting the drywell would not be required , will be completed by the conclusion of the fall 2018 refueling and maintenance outage.

Since the initial site-specific seismic reevaluation analysis for CNS that resulted in no identified seismic-related modifications to CNS, the District has performed an additional seismic analysis and has worked to answer additional questions from the 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 will not have to complete a Seismic Probabilistic Risk Assessment. Unknown to the District at th is time is the extent of modifications that may be requ ired as a result of these add itional seismic reevaluations.

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

The District's cost estimate for plant modifications associated with the NRC's Fukushima Dai-ichi related orders is currently estimated to cost $25.6 million, which is expected to be funded primarily from the revenues of the District and from the proceeds of General Revenue Bonds. As of December 31 , 2016, $19.4 million has been spent on plant modifications with an additional $6.2 million expected to be spent to establish compliance with the Fukushima Dai-ichi orders.

CNS substantially completed the construction of a dry cask used fuel storage project in December 2009 to support plant operations until 2034 , wh ich is the end of the Operating License. The first loading campaign was completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool into eight dry used fuel storage casks for on-site storage. A second loading campaign , encompassing the loading of 610 used fuel assemblies into 10 dry used fuel storage casks, began in April 2014 and was completed in June 2014. The third loading campaign , encompassing the loading of 732 used fuel assemblies into 12 dry used fuel storage casks , is scheduled to begin in June 2017 .

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

As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 200 1. The initial settlement agreement addressed future claims through 2013. On January 13, 2014, the District and the DOE agreed to extend the settlement agreement through 2016. On March 2, 2017 , the District and the DOE agreed to extend the settlement agreement through 2019 . The District has received $118 .2 million from the DOE for damages from 2009 through 2016. The District also reserves the right to pursue future damages through the contract claims process. A corresponding regulatory liability for these DOE receipts was established in Other deferred inflows of resources . The District plans to use the funds to pay for costs related to CNS . The balance in the regulatory liability was $82.7 million and $79.5 million at December 31 , 2016 and 2015, respectively.

Under the terms of the DOE contracts , the District was also subject to a one mill per kilowatt-hour ("kWh") fee on all energy generated and sold by CNS which was paid on a quarterly basis to DOE. The District includes a component in its wholesale and retail rates for the purpose of funding the costs associated with nuclear fuel disposal. While the District expects that the revenues developed therefrom will be sufficient to cover the District's responsibility for costs currently outlined in the Nuclear Waste Policy 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 collection of this fee at the same rate . This approach ensures costs are recogn ized in the appropriate period with current customers receiving the benefits from CNS paying the appropriate costs . The expense for spent nuclear fuel disposal is recorded based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal.

S7 Financial Report

Under the provisions of the Federal Price-Anderson Act, the District and all other licensed nuclear power plant operators could each be assessed for claims in amounts up to $127 .3 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation , with a maximum assessment of $19.0 million per year per incident per unit owned .

The NRC evaluates nuclear plant performance as part of its reactor oversight process ("ROP"). The NRC has five performance categories included in the ROP Action Matrix Summary that is part of this process. As of December 31 , 2016 , CNS was in the Licensee Response Column , which is the first or best of the five NRC defined performance categories and has been in this column 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 transformer and the high pressure turbine.

Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs , commencing in 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 impact of cooling water intake structures. The Nebraska Department of Environment Quality ("NDEQ") establishes the requirements for the District's compliance with the Clean Water Act through issuance of National Pollutant Discharge Elimination System permits . NDEQ issued the District permits for the following facilities : GGS, Sheldon , CNS, Beatrice Power Station , Canaday Station , Kearney Hydro and the North Platte Office Building. The District anticipates some level of fish protection equipment technology installation , both for impingement and entrainment, may be necessary for CNS and only for impingement at GGS .

Until the final compliance options are determined , the District does not know the financial impact of this regulation .

On January 2, 2016, the final Steam Electric Power Plant Effluent Guidelines rule (the "Effluent Rule") became effective . The Effluent Rule revises the technology-based effluent limitation guidelines and standards that would strengthen the existing controls on discharges from steam electric power plants and sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. Generally, the Effluent Rule establishes new or additional requirements for wastewater streams from the following processes and byproducts associated with steam electric power generation : flue gas desulfurization , fly ash, bottom ash , flue gas mercury control , and gasification of fuels such as coal and petroleum coke . While the District facilities subject to the Effluent Rule are CNS , GGS , Sheldon and Canaday Station , the Effluent Rule only has an impact on the Sheldon Station . Sheldon Station will be required to be a zero discharge facility for bottom ash transport water by December 31 , 2023 . The District is currently analyzing the options for compliance , which is estimated to cost $2.4 million .

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 ("NOx")

emissions. Acid Rain Permits have been issued for the following facilities : GGS , Sheldon , Canaday Station and Beatrice 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 intended to reduce emissions of toxic air pollutants from power plants. Specifically, the Mercury and Air Toxics Standards ("MATS") Rule will require reductions in emissions from new and existing coal- and oil-fired steam utility electric generating units of toxic air pollutants. All affected District facilities , including GGS and Sheldon, are in compliance with the MATS Rule .

Regional Haze and Cross-State Air Pollution Rule The EPA issued fi nal regulations for a Regional Haze Program in June 1999. The purpose of the regulations is to improve visibility in the form of reducing regional haze in 156 national parks and wilderness areas across the country. Haze is 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 Air Pollution Rule ("CSAPR") that would require significant reductions in S02 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 sufficient CSAPR allowances to cover affected facilities emission requirements over that timeframe , but may be required to purchase additional allowances in the future .

On January 10, 2017, the EPA issued final changes to the Regional Haze regulations for the second planning phase of the Regional Haze Rule . The District is evaluating the proposed changes but will not know the full impact to the District until the State and the EPA begin implementing the second phase of the Regiona l Haze rule . The State of Nebraska is required to submit their state implementation 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 District to install S0 2 controls on both units at GGS within five years of the proposed FIP being finalized . The District is currently evaluating the proposed modification . However, the proposed modification has not yet been published in the Federal Register and due to the hold issued by the Trump administration on all proposed regulations yet to be published in the Federal Register, the publication 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 requirements, on December 4, 2002, the Region 7 office of the EPA began an investigation to determine the Clean Air Act compliance status of GGS and Sheldon. The District timely responded to EPA's requests for information. By letter dated December 8, 2008, EPA Region 7 sent a Notice of Violation ("NOV") to the District which alleges that the District violated the Clean Air Act by undertaking five projects at GGS from 1991 through 2001 without obtaining the necessary permits. In February and August 2009 , District representatives met with federal government representatives to discuss the NOV and no additional meetings have been scheduled . In general , enforcement action by EPA against the District for alleged noncompliance with Clean Air Act requ irements , if upheld after court review, can result in the requirement to install expensive air pollution control equipment that is the Best Available Retrofit Technology ("BART") and the imposition of monetary penalties ranging from $25,000 to $32,500 per day for each violation . The District cannot determine at this time whether it will have any future financial obligation with respect to the NOV.

On July 22 , 2016, EPA Region 7 sent a new 114(a) request for documents and information regarding the compliance status of GGS. On December 27, 2016 , EPA Region 7 sent a 114(a) follow-up request for additional information on certain projects that were identified in the July 22 , 2016, 114(a) request. The EPA is reviewing whether there have been physical or operational changes since November 8, 2007 which resulted in, or could result in , increased emissions including projects underway or planned for the next two years . The District is in the process of gathering responsible documents and information . Failure to comply with the Clean Air Act can result in fines as described above and/or requirements to install additional emission control equipment. The District believes GGS has been operated and maintained in compliance with the requ irements of the Clean Air Act.

Clean Power Plan On October 23 , 2015, the EPA published the final Clean Power Plan ("CPP") rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determining how to achieve the reduction targets through the development of a State Plan . Each state was given a reduction target to be achieved by 2030 with interim reductions required between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 emissions. On February 9, 2016, the U.S . Supreme 59 Financial Report

Court issued a stay for the CPP until all legal challenges have been decided . The D.C. Circuit Court of Appeals heard oral arguments on September 27, 2016 , with a decision expected in early 2017 . An initial State Plan was due September 6, 2016 providing a general outline of potential compliance options the State is considering.

States can also request a two-year extension when subm itting their initial plan making the final State Plan 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 generation from coal-fired units will decrease and its generation from natural gas may increase under the final ru le but it is not possible to determine the impact of the final rule on the District until the legal issues are ultimately decided and the NDEQ develops the State Plan and it receives EPA approval.

Impact from Changes to Environmental Regulatory Requirements Any changes in the environmental regulatory requirements imposed by federal or state law which are applicable to the District's generating stations could result in increased capital and operating costs being incurred by the District. The District is unable to predict whether any changes will be made to current environmenta l regulatory requ irements , if such changes will be applicable to the District and the costs thereof to the District.

G. Sale of Spencer Hydro Facility -

In September 2015, a memorandum of understanding ("MOU") was signed for the sale of the District's Spencer Hydro ("Spencer") facility, including dam, structures, land , water appropriations, and perpetual easements for the reservoir, to the Niobrara River Basin Alliance (Five Natural Resource Districts) and the Nebraska Game and Parks Commission for $12 .0 million. The District is to provid e an in-kind contribution of $3.0 million and the other parties are to pay $9.0 million to the District. The MOU provided that the parties will work for passage of legislation by the State of Nebraska for a permanent transfer of existing hydro water appropriation to a new multi-purpose use, and it identifies potential sources of funding for the sale. The required legislation for this sale was passed by the State of Nebraska in 2016. The District will continue to operate Spencer until transfer of ownership, including water appropriations, is 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 District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A {Taxable Build America Bonds). Reductions were 6.9% and 7.3% for fiscal years ended September 30, 2016 and 2015, respectively.

13. LITIGATION :

On January 1, 2016 , Tri-State Generation and Transmission Association, Inc. ("Tri-State") became a transm ission member of SPP and its transmission facilities in western Nebraska , and the corresponding annual transmission revenue requirements were placed under the SPP tariff. SPP filed at FERC to place the Tri-State transmission facilities in the District's pricing zone rather than establ ish a new pricing zone for Tri-State. The District protested the filing at FERC , because it results in approximately a $4.3 million pe r year, or 8%, cost shift increase to the transmission customers in the District's pricing zone . As a result of the District's protest, FERC set the matter for hearing before an administrative law judge and the District and other parties submitted briefs and testimony on the proper pricing zone and whether SPP's decision is discriminatory and an unjust and unreasonable cost shift to the District. On February 23, 2017, the adm inistrative law judge issued an initial decision upholding the SPP pricing zone placement and made recommended conclusions to FERC. This initial decision has no legal effect until reviewed and acted upon by FERC which will be after the District submits briefs on its exception to the factual and legal conclusions in the initial decision . FERC's future ruling on the initial decision can be appealed to a federal circuit court of appeals. When FERC will rule on the initial decision cannot be predicted .

Financial Report 60

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

In the opinion of management, based upon the advice of its General Counsel , the aggregate amounts recoverable from the District, taking into account estimated amounts provided in the financial statements and insurance coverage , are not material as of December 31 , 2016 and 2015. Information on litigation with wholesale customers is included in Note 12.

14. SUBSEQUENT EVENTS:

In Apri l 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 District plans to issue additional revenue bonds in 2017 to finance transm ission 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 existed for approximately four months , since early October during the 2016 fall refueling and maintenance outage . The cause evaluation to determine how the issue occurred and actions to prevent recurrence is ongoing at this time . During the week of March 13, 2017 the NRC Region IV conducted a special inspection , comprised of two inspectors, to investigate the recent Residual Heat Removal System Minimum Flow Va lve issue to determine the safety significance . If the issue is determined to be greater than a very low safety significance (a find ing greater than Green), CNS would move from the Licensee Response Colum n to the Regulatory Response Column of the NRC's Action Matrix for a period of one year. Plants in the Regulatory Response Column of the NRC's Action Matrix are subject to additional NRC inspections.

In December 2016, the District initiated a voluntary early retirement incentive program ('Program") to all regular, full-time employees, excluding sen ior management, who met certain retirement-eligible criteria . The objective of the Prog ram was to facilitate an accelerated but voluntary reduction in the workforce to obtain a reduction in costs during 2017 and in years following by incentivizing earlier retirement of employees who were eligible for retirement. 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 received six 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 ) 2016 2015 Operating revenues .. ................. .... .......... ...... ...... ..... ...... ............ ..... .. .... ... ... . $ 1, 153,997 $ 1,097,216 Operating expenses ... ..... .. .. ...... .. .. ...... ... ......... ..... ... .... ..... .. .... .. ....... ............ . (1 ,040,715) (960,259)

Operating income .... ........... .......... ............... ....... ..... ...... ... .......... ......... ... . 113,282 136,957 Investment and other income ... ... ......... .... ... ....... ... ..... .. ....... ....................... ... . 31 ,772 22,355 Debt and other expenses ......... ... ........ .... .. .... ...... ..... ...... .. .. ..... ...... ......... ...... . (62, 121) (68,252)

Increase in net pos ition .............. .... .. .. ... ... .. ... ..... ... ..... ... ......... ......... .. ... ... . 82 ,933 91 ,060 Add:

Debt and related expenses .. ............................ ... ...... .. ...... .... ... .. .......... .... . 62, 121 68,252 Depreciation and amortization ... ... .... ..... ............................... .. ........... .. ... .. . 133,666 130,247 Payments to retail communities c1 i . . . . ..... .. ............................ . ... . . ...... ...... ... . 26,553 26,552 Amortization of current portion of financed nuclear fuel .......... ........ ... .......... . 39,468 24,675 Amounts collected from third party financing arrangements C2J ....*...... **... ...... 991 850 262,799 250,576 Deduct:

Investment income retained in construction funds ..... .................... ... ... .... ... . 354 302 Unrealized (loss) gain on investment securities ..... ... .. .. .... .. ...... ... .. ......... ... . 43 (1 ,245)

Re\01"1ng credit agreement interest ............ ... ... .. ......... .. .. .... ..................... . 1,010 397 67 Net position available for debt ser.;ce for the General Revenue Bond Resolution . $ 345,335 $ 341 ,569 Amounts deposited in the General System Debt Ser.;ce Account:

Principal ..... ....... .............................. ... ...................................... .......... .. . . $ 101 ,135 $ 110,265 Interest ............ ..... ....... .... ... ... ... ... ..... .. ... .... ........................... ... .. ... .. .... .. . . 72,959 75,372

$ 174,094 $ 185,637 Ratio of net position available for debt ser.;ce to debt ser.;ce deposits .. ..... .. .... . 1.98 1.84 (1) Debt and other expenses, exclusive of interest on customer deposits, is not an operating expense as defined in the General Resolution .

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

(3) Under the provisions of the General Resolution , the payments required to be made by the District with respect to the Professional Retail Operating Agreements are to be made on the same basis as subordinated debt.

(4) General Revenue Bond financed nuclear fuel is not an operating expense as defined in the General Resolution . As of July 31 , 2015, the effective date of the Taxable Revolving Credit Agreement, amortization of nuclear fuel expense under the Taxable Revolving Credit Agreement is excluded from the debt service calculation as the District's obligation to make payments under the Taxable Revolving Credit Agreement is subordinate to the District's obligation to pay debt service on General Revenue Bonds.

(5) The payments received by the District from third party financing arrangements are included as Revenues under the General Resolution, but are not recognized as revenue under GAAP.

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

(7) As of July 31 , 2015, the effective date of the Taxable Revolving Credit Agreement, interest expense under the Taxable Revolving Credit Agreement is excluded from the debt service ca lculation as the District's obligation to make payments under the Taxable Revolving Credit Agreement is subordinate to the District's obligation to pay debt service on General Revenue Bonds .

Financial Report 62

Schedule of Changes in the Net OPEB Liability and Related Ratios as of December 31 using a January 1 Measurement Date (in OOO's)

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

Benefit Payments ....... .. .. .... .. ...... .... .. .... ...... ...... ........ ...... ... ... .... ...... .. ...... ...... ... ........... ..... . (16,902)

Net Change in Total OPEB Liability ............. ... .... ..... .. ..... .. ... .... ........ ....... ... .... ... ... ... ....... .... . 10,711 Total OPEB Liability (beginning)...... ...... .. .... ..... ... ...... .... ....... ..... ....... ..... ..... .... ......... ... .... ... . 323, 122 Total OPEB Liability (ending) (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 ition .. .. ...... ........ ........... .... .. ... .. ... ...... .... .. .... ... ...... ... .. . 10,737 Plan Fiduciary Net Position (Beginning)...... .... ... ... ... .. .. ... ..... .. .. .... .. ... .. .... .. .. ....... ........... ... ... 64,487 Plan Fiduciary Net Position (Ending) {b} ..... ... .. ............. .. ....... .... ......... .......... ..... .. ...... ... ... ... $ 75,224 Net OPEB Liabil ity (Ending) (a) - (b) ..... ...... ... ..... .... ....... ......... .... .... .. ......... ........ ... ... .. ........ . $ 258,609 Net Position as a % of Total OPEB Liability .. ... ... .. ....... ... ........ ..... ... .... .. .. ..... ..... .... ...... ....... . 22.5%

Covered-Employee Payroll. ... ..... ....... ... .. .. ... .... .......... .. .. .... ... ... ....... ... .. ..... ......... .. ..... ..... ... . . $ 195,903 Net OPEB Liability as a % of Covered-Employee Payroll. .......... ................. ... ... .. .... ... .. .... .... . 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 using a January 1 Measurement Date (in OOO 's) 2016 Actuarially Determined Contribution ..... .. .. ....... .. ....... .... ... .. ...... .... ....... ... ..... ......... ..... .... ..... .. . $ 28,283 Contributions Made in Relation to the Actuarially Determined Contribution ..... ........ ..... .... .. ... .. . 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 prior to the end of the fiscal year in which contributions are reported .

Methods and assumptions used -

Actuarial cost method Entry Age Normal

Amortization method Level amortization of the unfunded accrued liability

Amortization period 17-year closed period

Asset valuation method 5-year smoothed market

Discount rate 6.25%

Healthcare cost trend rates Pre-Medicare: 8% initial, ultimate 5%

Post-Medicare: 6 .75% initial, ultimate 5%

Inflation 2.1%

Investment rate of return 6.25%, net of investment expense, including inflation

Mortality RP-2014 Aggregate table projected back to 2016 using Scale MP-2014 and projected forward using Scale MP-2015 w ith generational projection

Retirement Age 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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