NLS2015053, Submittal of 2014 Financial Report for the Calendar Year 2014

Submittal of 2014 Financial Report for the Calendar Year 2014

ML15121A018
Person / Time
Site:	Cooper
Issue date:	04/24/2015
From:	Shaw J Nebraska Public Power District (NPPD)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NLS2015053
Download: ML15121A018 (44)

Text

H Nebraska Public Power District Always there when you need us NLS2015053 50.71 (b)

April 24, 2015 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Nebraska Public Power District 2014 Financial Report Cooper Nuclear Station, Docket No. 50-298, DPR-46

Dear Sir or Madam:

The purpose of this letter is to transmit the Nebraska Public Power District (NPPD) Financial Report for the calendar year 2014 in accordance with the requirements of 10 CFR 50.71(b).

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

This letter does not contain any commitments.

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

Sincerely,

ýim Shaw Licensing Manager Jo Enclosure - NPPD 2014 Financial Report cc:

Regional Administrator w/enclosure USNRC - Region IV Cooper Project Manager w/enclosure USNRC - NRR Project Directorate IV-1 Senior Resident Inspector w/enclosure USNRC-CNS NPG Distribution w/o enclosure CNS Records w/enclosure COE UR5.O

(..IY9 COOPE

.NUCLEA STATION P 0. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www.nppd.com

NLS2015053 Enclosure Page 1 of 43 NPPD 2014 Financial Report

AC

20 1 4

E TA A

2014 STATISTICAL REVIEW (Unaudited)

Average Number of OPERATING REVENUES Customers MWh Amount Retail: (1)(2)

Residential......................................

70,880 912,998 4.4 Commercial.....................................

19,357 1,225,908 6.0 Industrial.........................................

56 1,245,793 6.0 Total Retail Sales..........................

90,293 3,384,699 16.4 Wholesale:

51 Municipalities

41).........................................

1,934,513 9.4 25 Public Power Districts and Cooperatives(3......

7,613,306 36.8 Total Firm W holesale Sales...........................

9,547,819 46.2 Total Firm Retail and W holesale Sales...........

12,932,518 62.6 Participation Sales............................................

2,240,152 10.8 Other Salesc51...................................................

5,486,085 26.6 Total Electric Energy Sales...........................

20,658,755 100.0 Other Operating Revenues(6)............................................................

Unearned Revenues"7 )................................................................

Total Operating Revenues................................................................

MWh COST OF POWER PURCHASED AND GENERATED Amount Production").....................................................

16,485,699 77.7 Power Purchased..............................................

4,718,424 22.3 Total Production and Power Purchased...........

21,204,123 100.0 Revenues (000's)

Amount 111,432 9.9 119,783 10.7 75,342 6.7 306,557 27.3 120,478 10.7 460,584 41.1 581,062 51.8 887,619 79.1 81,063 7.2 172,521 15.4 1,141,203 101.7 58,352 5.2 (77,101)

(6.9)

$ 1.122.454 100.0 Costs (000's)

Amount 493,655 73.9 174,348 26.1

$ 668,003 100.0 Average Cents Per kWh 12.21 e

9.77 0

6.05 0

9.06

¢ 6.23

¢ 6.05 o

6.09

¢ 6.86

¢ 3.62

¢ 3.14 0

5.52

¢ (1) Customer classifications changed from the 2013 Annual Report. Rural and Farm customers are reported in the Residential or Commercial classification based upon their energy usage. Public Lighting, Municipal Power, and Miscellaneous Municipal customers are reported in the Commercial classification.

(2) Operating revenues included energy billed to retail customers in 2014 and estimated unbilled energy at December 31, 2014.

(3) Sales are Total Requirements.

(4) The City of Edgar, Nebraska transitioned to the South Central Public Power District on January 1, 2015. With this change, the District's total number of municipalities served decreased from 51 to 50.

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

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

(7) Includes unearned revenues from prior periods of $14.3 million and 2014 surplus revenues deferred to future periods of $91.4 million.

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

Miles of Transmission and Subtransmission Lines in Service.............................................................

5,232 Num ber of Full-lim e Em ployees......................................................................................................

2,010 CONTRACTUAL AND TAX PAYMENTS (000's):

Payments to Retail Communities....................................................................................................

$26,874 Paym ents in Lieu of Taxes.............................................................................................................

10,141 Total Contractual and Tax Payments...........................................................................................

$37,015 SOURCES OF ENERGY This chart shows the sources of energy for sales, excluding participation sales to other utilities. Purchases were included in the appropriate source, except for those purchases for which the source was not known.

Nuclear 29.9%

Purchases 5.5%

Hydro 5.3%

Wind 6.5%

Gas & Oil 1.1%

Coal.

51.7%

NEýBRASKAS PULCPWRDSRC

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

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

The following MD&A provides unaudited information and analyses of activities and events related to the District's financial position or results of operations. The MD&A should be read in conjunction with the audited Financial Statements and Notes to Financial Statements.

The Balance Sheets present assets, deferred outflows of resources, liabilities, deferred inflows of resources and net position as of December 31, 2014 and 2013. The Statements of Revenues, Expenses, and Changes in Net Position present the operating results for the years 2014 and 2013. The Statements of Cash Flows present the sources and uses of cash and cash equivalents for the years 2014 and 2013. The Notes to Financial Statements are an integral part of the basic financial statements and contain information for a more complete understanding of the financial position as of December 31, 2014 and 2013, and the results of operations for the years 2014 and 2013. 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. Control of the District and its operations are vested in a Board of Directors ("Board") consisting of 11 members popularly elected from districts comprising subdivisions 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 retail and wholesale. Management and operation of the District is accomplished with a staff of approximately 2,010 full-time employees. The District has the power, among other things, to acquire, construct, and operate generating plants, transmission lines, substations, and distribution systems and to purchase, generate, distribute, transmit, and sell electric energy for all purposes.

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

The District has no power of taxation, and no governmental authority has the power to levy or collect taxes to pay, in whole or in part, any indebtedness or obligation of or incurred by the District or upon which the 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 which are distributed to the State and various governmental subdivisions.

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

The District had available 3,626.5 MW of capacity resources that included 3,015.1 MW of generation capacity from 12 owned and operated generating plants and 21 plants over which the District has operating control, 447.8 MW of firm capacity purchases from the Western Area Power Administration, and 163.6 MW of a capacity purchase from Omaha Public Power District's ("OPPD") Nebraska City Station Unit 2 ("NC2") coal-fired plant. Of the total capacity resources, 248.7 MW are being sold via participation sales or other capacity sales agreements, leaving 3,377.8 MW to serve firm retail and wholesale customers and to meet capacity reserve requirements. The 1

NEBRASKA PUBLIC' P*

VE DS TRC

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

The following table shows the District's capacity resources from generation and respective summer 2014 accredited capability.

CAPACITY RESOURCES Type Steam - Conwentional (3.....................................

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

Combined Cycle................................................

Combustion Turbine (4).......................................

H yd ro................................................................

D ies e l...............................................................

W ind (5)............................................................

Summer 2014 Number of Accredited Percent of Plants(1 )

Capability (MW) (2)

Total 3

1,695.0 56.2 1

764.0 25.3 1

220.0 7.3 3

125.3 4.2 6

110.6 3.7 12 88.9 2.9 7

11.3 0.4 33 3,015.1 100.0 (1)

(2)

(3)

(4)

(5)

Includes three hydro plants and 12 diesel plants under contract to the District.

Accreditation by SPP for the summer season 2014, pursuant to standard performance tests conducted by the District. Pursuant to agreements with other utilities, a portion of the accredited capability of certain generating plants has been sold to such utilities.

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

Includes the Hallam, Hebron and McCook peaking turbines.

Includes Ainsworth Wind Energy Facility and six wind facilities under contract to the District.

The customer base for firm energy sales consists of approximately 90,293 retail customers, plus 51 municipalities and 25 public power districts and cooperatives that are total requirements wholesale customers of the District.

The City of Edgar, Nebraska transitioned to the South Central Public Power District on January 1, 2015. With this change, the District's total number of municipalities served decreased from 51 to 50. In addition, there are several participation sale contracts in place with other utilities for the sale of power and energy at wholesale from specific generating plants. The District also sells energy on a nonfirm basis in SPP and through transactions executed with other utilities by The Energy Authority ("TEA").

The following chart shows firm energy and additional energy sales December 31, 2010 through 2014.

in gigawatt hours for the years ended ENERGY SALES 0)

I-0 Lu

=u 0

30,000 25,000 20,000 15,000 10,000 5,000 19,802 19,869 19,275 20,830 20,659 2010 2011 2012 2013 2014 InFirm Energy Sales NAdditional Energy Sales NEBRASK PBICOE DISRC

The District owns and operates 5,232 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.

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

CONDENSED BALANCE SHEETS (000's)

As of December 31, Assets:

Current Assets..........................................................

Special Purpose Funds..............................................

Utility Plant, net.........................................................

Other Long-Term Assets............................................

Deferred Outflows of Resources..................................

Total Assets and Deferred Outflows........................

Liabilities:

Current Liabilities.......................................................

Long-Term Debt........................................................

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

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

Net Position:

Net investment in capital assets..................................

Restricted.................................................................

Unrestricted..............................................................

Total Liabilities, Deferred Inflows, and Net Position...

2014 2013 2012 719,987 808,552 2,495,206 800,406 26,794 4,850,945 395,676 1,802,850 1,159,647 251,648 770,514 43,889 426,721 4,850.945 665,854 688,220 2,500,069 795,792 16,504 4,666,439 352,229 1,845,244 1,109,567 180,637 747,650 42,883 388,229 4,666,439 608,912 744,982 2,513,511 729,867 18,066

$ 4,615,338 386,256 1,972,951 1,053,502 121,250 613,866 49,290 418,223

$ 4,615,338 CONDENSED RESULTS OF OPERATIONS (000's)

For the years ended December 31, Operating Revenues...................................................

Operating Expenses..................................................

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

Investment and Other Income......................................

Debt and Other Expenses..........................................

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

2014 1,122,454 (1,010,693) 111,761 26,039 (75,438) 62,362 2013 1,106,291 (941,887) 164,404 15,221 (82,242) 97,383 2012 1,080,998 (947,766) 133,232 31,112 (89,300) 75,044 NEBRASK PBICPWRDSIT

SOURCES OF OPERATING REVENUES (000's)

For the years ended December 31, 2014 2013 2012 Firm Retail and W holesale Sales................................

887,619 Participation Sales....................................................

81,063 Other Sales...............................................................

172,521 Other Operating Revenues..........................................

58,352 Unearned Revenues...................................................

(77,101)

Total Operating Revenues......................................

1 1 22.454 878,324 112,061 116,890 59,162 (60,146) 1,106,291 835,956 101,493 69,779 49,216 24,554 1.080,998 CONDENSED STATEMENTS OF CASH FLOWS (000's)

For the years ended December 31, Net Cash Provided by Operating Activities...............

Net Cash Used in Investing Activities...........................

Net Cash Used in Capital and Financing Activities........

Net (Decrease) Increase in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year.............

Cash and Cash Equivalents, End of Year.................

Revenues from Firm Retail and Wholesale Sales 2014 2013 2012 362,365 (199,101)

(241,874)

(78,610) 168,689

$ 90,079 407,132 (19,931)

(381,591) 5,610 163,079 168,689 313,019 (29,929)

(353,576)

(70,486) 233,565

$ 163,079 The District allocates costs between retail and wholesale service and establishes its rates to produce revenues sufficient to meet its estimated respective retail and wholesale revenue requirements. 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. The District's wholesale power contracts provide for the establishment of cost-based rates. Such rates can be adjusted at such times as deemed necessary by the District. The wholesale power contracts also provide for the creation of a rate stabilization account. Any surplus or deficiency between revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be retained in the rate stabilization account. Any amounts in excess of the limits may be 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 kilowatt hour ("kWh") above the normal revenue requirements to be used for future capital expenditures associated with generation.

The District implemented a 0.5% increase in the wholesale rates commencing January 1, 2015. No increase in retail rates was implemented in 2015. The District had no wholesale or retail rate increase in 2014. The District implemented a 3.75% increase in the retail and wholesale rates on January 1, 2013.

Revenues from firm sales increased $9.3 million, or 1.1%, from $878.3 million in 2013 to $887.6 million in 2014.

This increase was due primarily to higher unbilled retail revenues of $14.1 million partially offset by a 3.4%

weather-related decrease in energy sales to firm wholesale customers. Revenues from firm sales increased

$42.3 million, or 5.1%, from $836.0 million in 2012 to $878.3 million in 2013. This increase was due primarily to 3.75% wholesale and retail rate increases effective January 1, 2013, as a result of increases in debt payments, current capital expenditures, and increases in operating costs. An additional increase was due to a 1.2% increase in energy sales to retail customers.

NEBASK PULCPWRDSRC

The following charts show the District's average December 31, 2010 through 2014.

AVERAGE CENTS PER kWh SOLD -

RETAIL (Retail - All Classes) 99.04¢t 9.06¢ 8.751 retail and wholesale cents per kWh for the years ended AVERAGE CENTS PER kWh SOLD -

WHOLESALE (Firm Wholesale Customers Only) 6.40 6.090 8.8u Ad 8.40

• "8.00 8 7.60 7.20 6.80 6.00 5.60

. 5.20 0 4.80 4.40 4.00 5.390 2010 2011 2012 2013 2014

-00 2010 2011 2012 2013 2014 Revenues from Participation Sales The District has participation sales agreements with other utilities that share operating expenses on a pro rata basis. Revenue from participation sales decreased from $112.1 million in 2013 to $81.1 million in 2014, a decrease of $31.0 million. The decrease was due primarily to contract expirations with Heartland Consumers Power District and KCP&L Greater Missouri Operations Company on December 31, 2013 and January 18, 2014, respectively, which was partially offset by increased wind participation sales. Revenue from participation sales increased from $101.5 million in 2012 to $112.1 million in 2013, an increase of $10.6 million. The increase was due primarily to the increased participation sales from the Crofton and Broken Bow Wind Facilities.

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 nonfirm off-system sales and the related management of credit risks. Other sales increased from $116.9 million in 2013 to $172.5 million in 2014, an increase of $55.6 million. This increase was due primarily to additional revenues realized from greater nonfirm sales at higher market prices, including sales in SPP's Integrated Market which began on March 1, 2014. Other sales increased from $69.8 million in 2012 to $116.9 million in 2013, an increase of $47.1 million. This increase was due primarily to additional revenue realized from nonfirm off-system sales as the result of excess generation being available to sell in the open market, due to no refueling and maintenance outage at CNS in 2013, and higher market prices.

Other Op1erating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues.

These revenues were $58.4 million, $59.2 million, and $49.2 million in 2014, 2013, and 2012, respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District.

NERAK PULI POL *srI

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 requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities, the balance of such surpluses or deficiencies are accounted for as "regulatory liabilities or assets," respectively.

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

$91.4 million, which surplus amount 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.

Accordingly, the 2014 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount.

The District deferred or decreased revenues a net amount of $60.1 million in 2013. The District's revenues in 2013 from electric sales to wholesale, retail, and other utilities resulted in a surplus, or over collection of costs, of

$60.8 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2013 included a refund of $0.7 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 2013 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount.

The District recognized or increased revenues a net amount of $24.6 million in 2012. The District's revenues in 2012 from electric sales to wholesale, retail, and other utilities resulted in a deficiency, or under collection of costs, of $3.7 million, which deficiency amount was accrued (increase in revenues). In addition, the wholesale and retail rates that were in place for 2012 included a refund of $20.9 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 2012 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 rate periods was $177.1 million, $101.9 million, and $41.7 million, as of December 31, 2014, 2013, and 2012, respectively.

NEBRSKA UBLI POWR DITRIC

Operatina Expenses The following chart illustrates operating expenses for the years ended December 31, 2012 through 2014.

OPERATING EXPENSES

$1,200

)1011 0 Power Purchased & Fuel a Production Operation & Maintenance ("O&M")

c

$800.

Transmission & Distribution O&M 2

$600 n Customer Service & Information a

wAdministrative & General 00 N Decommissioning

$200 a-Depreciation & Amortization

$1 mOther 2012 2013 2014 Total operating expenses in 2014 were $1,010.7 million, an increase of $68.8 million from 2013. Total operating expenses in 2013 were $941.9 million, a decrease of $5.9 million from 2012. The changes were due primarily to the following:

Power purchased and production fuel expenses were $386.3 million, $366.2 million, and $345.1 million in 2014, 2013, and 2012, respectively. These expenses increased $20.1 million in 2014 as compared to 2013 due primarily to activity in the SPP Integrated Market and the District's participation in new wind facilities. These expenses increased by $21.1 million in 2013 as compared to 2012 due primarily to higher fuel costs as a result of increased generation and increased purchased power costs.

A participation purchase capacity resource, NC2, was removed from service for an unplanned outage to repair the turbine on November 28, 2014. The plant returned to service on March 13, 2015. There was no significant impact to the District's financial position in 2014 or 2015 from this outage.

Production operations and maintenance expenses were $281.7 million, $247.8 million, and $285.0 million in 2014, 2013, and 2012, respectively. These costs increased $33.9 million in 2014 as compared to 2013 due primarily to additional costs associated with a planned refueling and maintenance outage at CNS in 2014. No such outage occurred in 2013. These costs decreased $37.2 million in 2013 as compared to 2012 due primarily to the costs associated with a planned refueling and maintenance outage at CNS in 2012.

Transmission and distribution maintenance expenses were $83.8 million, $76.4 million, and $61.9 million in 2014, 2013, and 2012, respectively. These costs increased $7.4 million in 2014 as compared to 2013 and $14.5 million in 2013 as compared to 2012 both due primarily to increases in SPP fees. The District is charged by SPP on a load ratio share basis for firm requirements customers for the qualifying transmission system upgrade projects of other SPP transmission owners.

Customer service and information expenses were $17.5 million, $16.6 million, and $16.7 million in 2014, 2013, and 2012, respectively.

Administrative and general expenses were $59.4 million, $59.7 million, and $51.7 million in 2014, 2013, and 2012, respectively. These costs increased $8.0 million in 2013 as compared to 2012 due primarily to increases in healthcare costs and the funding of other postemployment benefits along with less administrative and general costs being capitalized in 2013.

NERAKAPULI Pw~,

ISI IC

Decommissioning expenses were $18.5 million, $10.7 million, and $25.4 million in 2014, 2013, and 2012, 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 $7.8 million in 2014 as compared to 2013 due to an increase in income on investments. Decommissioning expenses decreased $14.7 million in 2013 as compared to 2012 due to a decrease in income on investments. No additional amounts for decommissioning were collected through rates in 2014, 2013, and 2012.

Depreciation and amortization expenses were $126.4 million, $127.3 million, and $126.5 million in 2014, 2013, and 2012, respectively.

Increase in Net Position The increase in net position was $62.4 million, $97.4 million, and $75.0 million in 2014, 2013, and 2012, respectively. The change in net position in 2014 as compared to 2013 decreased $35.0 million and was due primarily to a decrease in 2014 revenue requirements for collections related to construction from revenue and commercial paper principal payments. The change in net position in 2013 as compared to 2012 increased

$22.4 million and reflected increases in revenue requirements used to establish rates for 2013 for the purpose of increased collections related to construction from revenue and commercial paper principal payments, along with a decrease in excess bond proceeds to pay interest, partially offset by decreased revenue bond principal payments and an increase in depreciation expense.

The following chart illustrates the District's operating revenues, other revenues, operating expenses, and other expenses for the years ended December 31, 2012 through 2014.

REVENUES & EXPENSES

$1,200 lo,%$1 150

$2 0$1100 a Other Expenses

.* $1,050

$15 Operating Expenses

_-$1,000

')

m Other Revenues

$ 9 5 0 1

$900 a Operating Revenues 0

8O0

$800 2012 2013 2014 DEBT SERVICE COVERAGE The District's debt service coverage ratio was 1.50, 1.73, and 1.61 in 2014, 2013, and 2012, 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, the amounts collected in operating revenues for principal associated with the 2008 Series A Bonds maturing January 1, 2014 and the 2009 Series B Bonds maturing January 1, 2013 and 2014, and the cost of payments made to those municipalities served by the District under long-term Professional Retail Operations Agreements. The District has a goal to maintain a debt service coverage ratio of approximately 1.50 times annual debt service.

NEBASK PULIPOE DISTIC

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.

The District's credit ratings on its revenue bonds were as follows:

Moody's Investors Service.............................................................

............ Al (stable outlook)

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

A (stable outlook)

Fitch Ratings.................................................................................................

A +

(stable outlook)

Revenue bonds were issued in 2014 to refund existing bonds at lower rates and to finance capital projects.

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

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 value savings of $26.1 million. The District plans to issue additional revenue bonds in 2015 to finance capital projects.

CAPITAL REQUIREMENTS The Board-authorized capital projects totaling approximately $197.4 million, $78.9 million, and $124.5 million in 2014, 2013, and 2012, respectively. The District's capital requirements are funded with monies generated from operations, debt proceeds, and other available reserve funds.

Capital projects for 2014 included:

$94.9 million for construction of a high-voltage transmission line and related substations from Hoskins Substation northeast of Norfolk, Nebraska to Neligh, Nebraska 0

$14.7 million for replacement of a secondary super-heater outlet at GGS Unit 2 0

$7.0 million for replacement of a silo dust collector at GGS Units 1 and 2 Capital projects for 2013 included:

$27.1 million for replacement of a low pressure turbine at GGS Unit 1

$11.6 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2

$7.7 million for fire protection upgrades at CNS Capital projects for 2012 included:

$10.2 million for replacement of a service water discharge pipe at CNS

$9.6 million for replacement of a startup station service transformer at CNS 0

$8.1 million for installation of horizontal storage modules at CNS

$7.2 million for replacement of boiler water-wall tubes at GGS Unit 1 There were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $80.8 million, $32.5 million and $89.4 million for 2014, 2013, and 2012, respectively.

10 NEB ASK PU LI

'OE5 IS RC

The Board-authorized budget for capital projects for 2015 is $537.2 million. The increase from prior periods was due to large transmission projects authorized by SPP. The District will receive revenues from other transmission owners in SPP for their share of these projects. Specific capital projects for 2015 include:

0

$347.2 million for construction of a high-voltage transmission line and related substations from GGS substation north to Cherry County, Nebraska and east to a new substation in Holt County, Nebraska 0

$34.5 million for construction of a high-voltage transmission line from a new Stegall, Nebraska substation to the existing Scottsbluff, Nebraska substation 0

$13.3 million for replacement of the secondary super-heater outlet at GGS Unit 2 0

$12.2 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2 The following chart illustrates the Board-authorized capital projects for the years ended December 31, 2012 through 2014, including the Board-authorized budget for the year ended December 31, 2015.

CAPITAL REQUIREMENTS

$600

$537 0

$500

$400

$300

$$197

$100

$125

$79 2012 2013 2014 2015 Budget RESOURCE PLANNING The District's core planning principles for its most recent Integrated Resource Plan ("IRP") aligns 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. The probabilistic analysis under the IRP focused on key future uncertainties, including customer load growth, future environmental regulations including carbon dioxide ("CO 2"), 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 firm load requirement needs for the next 10 to 15 years. Specific actions on which the District will focus to meet load growth needs include addition of renewable, 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 CO2 costs occur. Operation of Sheldon Station and Canaday Station 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.

NEBRASK PB IC POE ISRC

Renewable Energy 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 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 155 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.

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. 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 and associated ERM Governing Policy. The ERM Governing Policy, approved by the Board, establishes guidelines and objectives and delegation of authorities necessary to govern activities related to the District's 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 spikes 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.

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. On March 1, 2014, SPP commenced an 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 goal of the SPP Integrated Market is to reduce total production costs within the SPP region. TEA is registered as the market participant for the District in the SPP Integrated Market.

ECONOMIC FACTORS Nebraska's economy continues to experience solid economic growth due in large part to continuing strength in its agricultural sector as measured by net farm income. Solid demand for livestock, especially cattle, has offset most of the negative impacts associated with the strong U.S. dollar and the mid-2014 decline in crop prices.

Additionally, Nebraska continues to enjoy consistent employment growth, especially in the financial and health services sectors. The strength of the agricultural, financial services, and health services sectors have been major contributors to Nebraska's strong economic performance.

12N3AKAPBIC POWE DITRC

Nebraska and the Midwest region continue to experience declining unemployment rates that are approaching pre-recession levels, and are far below the national averages. Nebraska's unemployment rate decreased from an annual average of 3.8% for 2013 to 3.3% in 2014 and remained well below the 2014 national average unemployment rate of 6.2%. Nebraska's preliminary, seasonally adjusted unemployment rate was 2.9% in December 2014, down from 3.6% in December 2013. Both numbers were well below the national December seasonally adjusted unemployment rates of 5.6% in 2014 and 6.7% in 2013. In December 2014, Nebraska's preliminary unemployment rate was the second 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 Utilitv Industrv 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 rapidly 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 certain 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, 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 other fossil-fueled generating units, increased regulation of nuclear power plants in the United States resulting from the earthquake and tsunami damage to certain nuclear power plants in Japan, and issues relating to cyber and physical security.

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

Competitive Environment in Nebraska While wholesale competition is expected to increase in the future, there is a Nebraska statute that prohibits competition for retail customers. Pursuant to state statutes, retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppliers and/or pursuant to an order of the Nebraska Power Review Board. While state statutes do not provide for wholesale suppliers of electricity to have exclusive rights to serve a particular area or customer at wholesale, wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements.

NEBRASKA PULI

.3 DSRIT1

INDEPENDENT AUDITOR'S REPORT To the Board of Directors of the Nebraska Public Power District:

We have audited the accompanying financial statements of Nebraska Public Power District (the "District") which comprise the balance sheets as of December 31, 2014 and 2013, and the related statements of revenues, expenses, and changes in net position, and statements of cash flows for the years then ended.

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

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

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

Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the District as of December 31, 2014 and 2013, 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.

Other Matters The accompanying management's discussion and analysis and the supplemental schedules on pages 2 through 13 and 38 and 39, respectively, are required by accounting principles generally accepted in the United States of America to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our 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 required 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.

St. Louis, Missouri April 9, 2015 14 NERASKAPUBLI POWE DISRC

FINANCIAL STATEMENTS Balance Sheets as of December 31, (000's) 2014 ASSETS AND DEFERRED OUTFLOWS Current Assets:

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

Investm e nts.......................................................................................

Receivables, less allowance for doubtful accounts of $497 and $478, respectively..........................................................

Fossil fuels, at average cost................................................................

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

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

Special Purpose Funds:

Construction funds.............................................................................

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

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

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

Utility Plant, at Cost:

Utility plant in service..........................................................................

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

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

Nuclear fuel, at amortized cost............................................................

Other Long-Term Assets:

Regulatory asset for asset retirement obligation....................................

Regulatory asset for other postemployment benefit obligation.................

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

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

Investment in The Energy Authority......................................................

O th e r................................................................................................

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

Deferred Outflows of Resources:

Unamortized cost of refunded debt.......................................................

TOTAL ASSETS AND DEFERRED OUTFLOW S.......................................

90,079 336,753 122,686 36,574 121,764 12,131 719,987 143,490 95,463 4,055 565,544 808,552 4,674,500 2,533,100 2,141,400 151,712 202,094 2,495,206 459,991 125,747 179,938 10,278 7,895 16,557 800,406 4,824,151 2013 162,384 230,452 102,805 35,951 123,084 11,178 665,854 53,930 94,795 5,756 533,739 688,220 4,549,279 2,433,049 2,116,230 170,083 213,756 2,500,069 442,338 123,475 186,810 10,687 6,695 25,787 795,792 4,649,935 26,794 16,504 4.850.945 4,666,439 LIABILITIES, DEFERRED INFLOWS, AND NET POS1ITON Current Liabilities:

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

Notes and credit agreements, current...................................................

Accounts payable and accrued liabilities..............................................

Accrued in lieu of tax payments...........................................................

Accrued payments to retail communities..............................................

Accrued compensated absences.........................................................

O th e r................................................................................................

Long-Term Debt:

Revenue bonds, net of current.............................................................

Notes and credit agreements, net of current..........................................

Other Long-Term Liabilities:

Asset retirement obligation..................................................................

Other postemployment benefit obligation..............................................

O th e r................................................................................................

Total Liabilities..........................................................................

Deferred Inflows of Resources:

Unearned revenues.............................................................................

Settlement reimbursement and fuel disposal.........................................

Net Position:

Net investment in capital assets..........................................................

R e stric te d..........................................................................................

U nre stricted.......................................................................................

TOTAL LIABILITIES, DEFERRED INFLOWS, AND NET POSITION.............

The accompanying notes to financial statements are an integral part of these statements.

109,835 185,503 58,073 10,040 6,148 16,569 9,508 395,676 1,710,850 92,000 1,802,850 1,026,357 127,247 6,043 1,159,647 3,358,173 177,143 74,505 251,648 770,514 43,889 426,721 1,241,124

$ 4,850.945 124,585 102,300 84,868 10,057 6,426 16,052 7,941 352,229 1,695,827 149,417 1,845,244 977,083 125,375 7,109 1,109,567 3,307,040 101,861 78,776 180,637 747,650 42,883 388,229 1,178,762 4.666.439 I NBRAKA UBIC OWE DSTRC is

Statements of Revenues, Expenses, and Changes in Net Position for the years ended December 31, (000's)

Operating Revenues................................................................................

Operating Expenses:

Power purchased...............................................................................

Production:

F u e l..............................................................................................

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

Transmission and distribution operation and maintenance......................

Customer servce and information........................................................

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

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

Decommissioning...............................................................................

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

Payments in lieu of taxes....................................................................

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

Investment and Other Income:

Investment income.............................................................................

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

Increase in Net Position Before Debt and Other Expenses..........................

Debt and Other Expenses:

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

Allowance for funds used during construction........................................

Bond premium amortization net of debt issuance expense.....................

Other expenses.................................................................................

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

Net Position:

Beginning balance..............................................................................

Ending balance..................................................................................

2014 1,122,454 174,348 211,984 281,671 83,839 17,502 59,372 26,874 18,522 126,440 10,141 1,010,693 111,761 22,634 3,405 26,039 137,800 85,777 (2,857)

(9,295) 1,813 75,438 62,362 2013 1,106,291 148,986 217,242 247,822 76,352 16,558 59,723 27,092 10,699 127,283 10,130 941,887 164,404 11,839 3,382 15,221 179,625 91,858 (2,842)

(8,368) 1,594 82,242 97,383 1,178,762 1,081,379 1,241,124 1,178,762 The accompanying notes to financial statements are an integral part of these statements.

16NEBRASK PULI POWE DISRC

Statements of Cash Flows for the years ended December 31, (000's)

Cash Flows from Operating Activities:

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

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

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

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

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

Cash Flows from Investing Activities:

Proceeds from sales and maturities of investments...............................

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

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

Net cash used in investing activities................................................

Cash Flows from Capital and Related Financing Activities:

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

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

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

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

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

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

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

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

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

Funds advanced - W helan Energy Center 2..........................................

Other non-operating revenues.............................................................

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

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

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

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

Reconciliation of Operating Income to Cash Provided By Operating Activities:

Operating income...............................................................................

Adjustments to reconcile operating income to net cash provided by operating activities:

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

Undistributed net revenue - The Energy Authority.............................

Decommissioning, net of customer contributions..............................

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

Changes in assets and liabilities which (used) provided cash:

Receivables, net........................................................................

F o s s il fue ls...............................................................................

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

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

Other long-term assets.............................................................

Accounts payable and accrued payments to retail communities....

Unearned revenues....................................................................

O the r liab ilitie s..........................................................................

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

Reconciliation of Cash and Cash Equivalents:

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

Cash and cash equivalents not classified as investments in special purpose funds....................................................................

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

Supplementary Non-Cash Capital Activities:

Change in utility plant additions in accounts payable.............................

The accompanying notes to financial statements are an integral part of these statements.

2014 2013

$ 1,158,887 2,279 (563,034)

(235,767) 362,365 879,579 (1,082,215) 3,535 (199,101) 424,358 65,006 (211,966) 29,423 (400,790)

(88,766)

(21,536)

(39,220)

(86)

(1,700) 3,403 (241,874)

(78,610) 168,689 90,079 1,162,065 3,254 (520,342)

(237,845) 407,132 1,145,451 (1,168,080) 2,698 (19,931) 126,158 20,650 (151,128) 7,024 (273,780)

(92,486)

(19,787)

(175)

(1,449) 3,382 (381,591) 5,610 163,079 168,689 111,761 164,404 126,440 (1,200) 18,522 44,169 (10,943)

(623) 1,320 (690) 809 (57) 75,282 (2,425) 362,365 127,283 1,106 10,699 50,323 (7,463) 4,894 10,546 (1,107) 770 (13,797) 60,147 (673) 407,132 90,079 162,384 90,079 6,305 168,689 (27,016) 12,838 N

E B

R A S A P U B IC P O E.

D S

R C T1

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 wholesale and retail 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 ("GASB") for proprietary funds of governmental entities. In the absence of established GASB pronouncements, other accounting literature is followed including guidance provided in the Financial Accounting Standards Board Accounting Standards Codification ("ASC").

The District applies the accounting policies established in the GASB codification Section Re10, Regulated Operations. This guidance permits an entity with cost-based rates and Board 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. Use of Estimates -

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

D. 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.

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.

There were surpluses of $91.4 million and $60.8 million for the years ended December 31, 2014 and 2013, respectively. Unearned revenues from prior periods were used when establishing wholesale rates of $14.3 million and $0.7 million for the years ended December 31, 2014 and 2013, respectively. The net change was a decrease in Operating revenues of $77.1 million and $60.1 million for the years ended December 31, 2014 and 2013, respectively. Unearned revenues, which is the cumulative net surplus for use in future revenue requirements, were $177.1 million and $101.9 million at December 31, 2014 and 2013, respectively.

18 NBRAKA PBLI POWE DISRC

E. 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, 2014 and 2013, respectively. The District had fully depreciated utility plant, primarily related to Cooper Nuclear Station ("CNS"),

that was still in service of $802.0 million and $857.4 million at December 31, 2014 and 2013, 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 term of the agreements. The District recorded provisions, net of retirements, for amortization of these plant additions of $6.5 million and $6.4 million in 2014 and 2013, respectively which was included in depreciation and amortization expense. These plant additions, which were fully depreciated, totaled $176.1 million and

$171.3 million at December 31, 2014 and 2013, respectively.

F. Cash and Cash Equivalents -

The District considers highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents in the Special Purpose Funds are reported as investments.

G. 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.

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.

Unamortized Financing Costs -

These costs include issuance expenses for bonds which are being amortized over the life of the respective bonds using the bonds outstanding method. Deferred unamortized financing costs associated with bonds refunded are amortized using the bonds outstanding method over the shorter of the original or refunded life of the respective bonds. Regulatory accounting, GASB codification section Rel0, Regulated Operations, is used to amortize these costs over their respective periods.

J.

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"), tax-exempt revolving credit agreement ("TERCA"), or taxable revolving credit agreement ("TRCA") is charged a rate based upon the projected average interest cost of TECP, TERCA, or TRCA outstanding. For the periods presented herein, the AFUDC rates for construction funded by revenue bonds varied from 2.2% to 5.0%. For construction financed on a short-term basis with TECP, the rate charged was 1.0%.

NEBRASKA PUBLIC POWER DISTRICT 19

K. 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 debt service reserve-primary 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.

L. 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 coal-fired power stations, and the removal of asbestos at its various generating facilities.

M. Auction Revenue Rights and Transmission Congestion Rights -

The District uses Auction Revenue Rights ("ARR") and Transmission Congestion Rights ("TCR") in the 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. Prepayments and other current assets included $0.3 million for TCR and Other current liabilities included $0.9 million for ARR as of December 31, 2014.

N. Recent Accounting Pronouncements -

GASB Statement No. 70, Fair Value Measurement and Application, was issued in February 2015. The requirements of this Statement will enhance comparability of financial statements by requiring measurement of certain assets and liabilities at fair value using a consistent and more detailed definition of fair value and accepted valuation techniques. This Statement also will enhance fair value application guidance and related disclosures to provide information to financial statement users about the impact of fair value measurements on financial position.

The requirements of the Statement are effective for financial statements for periods beginning after June 15, 2015. The implementation of this Statement is not expected to have a significant impact on the District as fair value measurements are consistent with this guidance.

GASB Statement No. 68, Accounting and Financial Reporting for Pensions, provides guidance for the accounting and financial reporting of pensions. This Statement includes significant changes for defined benefit plans. The District's pension plan is a defined contribution plan. The changes for defined contribution plans primarily relate to note disclosures. The provisions in this Statement are effective for fiscal years beginning after June 15, 2014.

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 $0.2 million as of December 31, 2014, and an unrealized net loss of $1.3 million as of December 31, 2013.

20NBAK PUBIC POWE DISRC

The fair value of all cash and investments, regardless of balance sheet classification, as of December 31, 2014 were as follows (000's):

Weighted Average Maturity Fair Value (Years)

U.S. Treasury and government agency securities.................................

892,475 Corporate bonds................................................................................

196,960 Municipal bonds................................................................................

9,913 Cash and cash equivalents.................................................................

136,036 Total cash and investments............................................................

1,235,384 Portfolio weighted average maturity 2.8 12.4 14.8 4.1 Interest Rate Risk-The investment strategy is to buy and hold bonds until they mature, which minimizes interest rate risk.

Credit Risk-The District follows a Board approved Investment Policy. This policy complies with state and federal laws and Bond Resolution 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 Special Purpose Funds as of December 31 were as follows (000's):

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:

2014 2013 Construction funds - Cash and cash equivalents.......................................

64 264 Construction funds - Investm ents.............................................................

143,426 53,666 143,490 53,930 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 $43.9 million and

$42.9 million as of December 31, 2014 and 2013, 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 $51.6 million and $51.9 million as of December 31, 2014 and 2013, respectively.

2014 2013 Debt reserve funds - Cash and cash equivalents........................................

3 1,188 Debt reserve funds - Investm ents.............................................................

95,460 93,607 95,463 94,795 NERSK UBI POWE DISTIT2

The Employee benefit funds consist of a self-funded hospital-medical benefit plan and a retired employee life insurance benefit plan. The District pays 80% of the hospital-medical premiums with the employees paying the remaining 20% of the cost of such coverage. The plan had contributed funds of $2.8 million and $4.4 million at December 31, 2014 and 2013, respectively. The retired employee life insurance benefit plan was funded prior to the implementation of GASB codification Section P50, Postemployment Benefits Other Than Pensions -

Employer Reporting, and the creation of an irrevocable grantor trust for postretirement health and life insurance benefits. For additional information on postemployment benefits see Note 11. The District pays the total cost of the employee life insurance benefit once the employee retires. The plan had contributed funds of $1.2 million and

$1.4 million at December 31, 2014 and 2013, respectively. Both funds are held by outside trustees in compliance with the funding plans approved by the Board.

2014 2013 Employee benefit funds - Cash and cash equivalents.................................

1,904 4,853 Employee benefit funds - Investments......................................................

2,151 903 4,055 5,756 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.

2014 2013 Decom m issioning funds..........................................................................

565,544 533,739

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.

ASC 820, Fair Value Measurement, 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 ASC 820 are as follows:

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

Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The District's investment 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 and liabilities primarily include U.S. treasury and other federal agency securities and corporate bonds held in the District's Decommissioning funds, other Special Purpose Funds, and certain Investments in Current Assets.

22 N

BRAS A PU LIC OWER DIST ICT.

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 Level 3 assets or liabilities included in the Decommissioning funds, other Special Purpose Funds, or Investments in Current Assets.

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 ASC 820. 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 following table sets forth the District's financial assets and liabilities that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31, (000's):

December 31, 2014 Level 1 Level 2 Level 3 Total Assets:

Available-for-sale securities:

U.S. Treasury and government agency securities...

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

Decommissioning funds:

U.S. Treasury and government agency securities...

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

Municipal bonds..................................................

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

Assets:

Available-for-sale securities:

U.S. Treasury and government agency securities...

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

Decommissioning funds:

U.S. Treasury and government agency securities...

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

Municipal bonds..................................................

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

$ 564,488 105,353 564,488 105,353 327,987 327,987 196,960 196,960 9,913 9,913 30,683 30,683

$ 136,036

$1,099,348

$1,235,384 December 31, 2013 Level 1 Level 2 Level 3 Total

$ 366,878 180,438 366,878 180,438 305,182 305,182 172,880 172,880 17,439 17,439 38,238 38,238

$ 218,676

$ 862,379

$1,081,055 NEBASAUBIC POERDSTIT2

4.

UTILITY PLANT:

Utility plant activity for the year ended December 31, 2014, was as follows (000's):

December 31, 2013 Nondepreciable utility plant:

Land and improvements............................ $

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

Total nondepreciable utility plant.............

Increases Decreases 280 63,056 170,083 233,139 Nuclear fuel*.................................................

Depreciable utility plant:

Generation - Fossil....................................

Generation - Nuclear..................................

Transmission.............................................

D istrib ution................................................

G e ne ra l.....................................................

Total depreciable utility plant 213,756 1,521,620 1,304,680 1,120,261 213,012 152,088 152,368 32,507 32,377 51,067 39,769 7,206 (170,459)

(170,459)

(44,169)

(3,211)

(2,373)

(6,326)

(2,325)

December 31, 2014 63,336 151,712 215,048 202,094 1,550,786 1,353,374 1,153,704 217,893 335,407 4,611,164 (2,533,100) 2,078,064

$ 2,495,206 326,650 12,690 (3,933) 4,486,223 143,109 (18,168)

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

(2,433,049)

Depreciable utility plant, net...................

2,053,174 Utility plant activity, net...................................

$ 2,500,069 (118,219) 24,890 209,765 18,168 (214,628)

• Nuclear fuel decreases represented amortization of $44.2 million.

5.

LONG-TERM CAPACITY CONTRACTS:

Long-term capacity contracts include the District's $198.2 million share of the construction costs of Omaha Public Power District's ("OPPD") 682 MW Nebraska City Station Unit 2 ("NC2") coal-fired power plant which amount includes $15.8 million share of associated transmission facilities construction costs. The District has entered into 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 of $182.4 million on a straight-line basis over the 40-year estimated useful life of the plant. Accumulated amortization was $26.1 million and $21.5 million in 2014 and 2013, respectively. The unamortized amount of the plant capacity contract was $159.5 million and $164.1 million as of December 31, 2014 and 2013, respectively, of which $4.6 million was included in Prepayments and other current assets as of December 31, 2014 and 2013. The costs of the transmission facilities have been returned to the District in the form of a credit on the District's monthly transmission bill from OPPD. Accumulated credits were $12.6 million.

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 recording amortization on a straight-line basis over the 40-year estimated useful life of the facility.

Accumulated amortization was $59.7 million and $57.4 million at December 31, 2014 and 2013, respectively. The unamortized amount of the Central capacity contract was $27.0 million and $29.3 million December 31, 2014 and 2013, respectively, of which $2.3 million was included in Prepayments and other current assets as of December 31, 2014 and 2013.

The District has an agreement whereby Central makes available all the production of the facility and the District pays all costs of operating and maintaining the facility plus a charge based on the amount of energy delivered to the District. Costs of $1.5 million in 2014 and 2013, are included in Power purchased in the accompanying Statements of Revenues, Expenses, and Changes in Net Position.

1 24~

NERAK PUBLI POWE DISRC

6.

INVESTMENT IN THE ENERGY AUTHORITY:

The District is an equity member of 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% and 20.00% as of December 31, 2014 and 2013, respectively. The decrease in interest was due to the American Municipal Power, Inc. joining TEA in January 2014. In addition to the District, the following utilities have equity interests of 16.67%

each as of December 31, 2014: American Municipal Power, Inc.; JEA of Florida; Municipal Energy Authority of Georgia; and South Carolina Public Service Authority (a.k.a. Santee Cooper). The following utilities have equity interests in TEA of 5.56% each as of December 31, 2014: City Utilities of Springfield, Missouri; Cowlitz County Public Utility District (Washington); and Gainesville Regional Utilities (Florida).

The District uses the equity method of accounting for its investment in TEA. Such investment was $7.9 million and

$6.7 million as of December 31, 2014 and 2013, respectively. TEA's revenues and costs are allocated to members pursuant to Settlement Procedures under the Operating Agreement. TEA provides the District gas contract management services and is the District's market participant in SPP's Integrated Market.

The District is obligated to guaranty, directly or indirectly, TEA's electric trading activities in an amount up to

$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 equity 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 equity ownership 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 obligations by causing to be provided advance notice to the beneficiaries thereof. Such termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect. The District has no liabilities for these guarantees as of December 31, 2014 and 2013.

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, 2014 and 2013, and activity for 2014 (000's):

Principal Amounts December December Due Within 31, 2013 Increases Decreases 31, 2014 One Year Revenue bonds.......................

$1,695,827 424,358

$ (409,335)

$1,710,850 109,835 Commercial paper notes..........

102,300 (10,300) 92,000 Revolving credit agreements.....

149,417 65,006 (28,920) 185,503 185,503 Total long-term debt activity

$1,947,544 489,364

$ (448,555)

$1,988,353 295,338 NERAK PULCPWR ITIT2

Revenue Bonds In December 2014, the District issued General Revenue Bonds, 2014 Series C in the amount of $162.9 million to advance refund $170.6 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $16.5 million, which resulted in present value savings of $12.4 million.

Also in December 2014, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:

General Revenue Bonds, 2005 Series A, maturing on January 1, 2026, General Revenue Bonds, 2005 Series B-2, maturing on January 1, 2017, General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2017 through January 1, 2030, General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2017 through January 1, 2036, General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2018 through January 1, 2022, General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2019 through January 1, 2023, and General Revenue Bonds, 2012 Series C, having maturity dates ranging from January 1, 2019 through January 1, 2023.

In July 2014, the District issued General Revenue Bonds, 2014 Series A in the amount of $195.2 million to finance $114.0 million of the costs of transmission capital additions and to advance refund $81.2 million of bonds.

Additionally, the District issued General Revenue Bonds, 2014 Series B (Taxable) in the amount of $24.4 million to advance refund $24.2 million of bonds. The refundings reduced total debt service payments over the life of the bonds by $11.4 million, which resulted in present value savings of $6.9 million.

Also in July 2014, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:

General Revenue Bonds, 2005 Series A, having maturity dates ranging from January 1, 2016 through January 1,2025, General Revenue Bonds, 2005 Series B-i, maturing on January 1, 2016, General Revenue Bonds, 2005 Series B-2, maturing on January 1, 2016, General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2019 through January 1, 2030, and General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2020 through January 1, 2031.

In October 2013, the District issued General Revenue Bonds, 2013 Series A, in the amount of $118.3 million to advance refund $154.9 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $1.3 million, which resulted in present value savings of $0.8 million.

In November 2013, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:

General Revenue Bonds, 2005 Series A, maturing on January 1, 2017 and January 1, 2019, and General Revenue Bonds, 2006 Series A, maturing on January 1, 2018 and January 1, 2019.

Certain of the General Revenue Bonds, from the following series, with outstanding principal amounts that aggregate $337.3 million as of December 31, 2014, were legally defeased and are no longer outstanding: 2005 Series A, 2005 Series B-i, 2005 Series B-2, 2005 Series C, 2006 Series A, 2007 Series B, 2008 Series B, and 2012 Series C. Said defeased bonds are payable solely from United States Treasury Obligations in irrevocable escrow accounts. Accordingly, the bonds and the related escrow accounts are not included in the Statement of Net Position.

26NBRSAPBI POWE DISRC

Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2014, are as follows (000's):

Debt Service Principal Year Payments Payments 2 0 15............................................

2 0 16...........................................

2 0 17............................................

2 0 18............................................

2 0 19............................................

2020-2024...................................

2025-2029...................................

2030-2034...................................

2035-2039...................................

2040-2043...................................

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

191,324 191,868 163,754 163,760 139,279 652,392 519,384 376,920 175,536 63,270 2,637,487 109,835 114,430 91,355 95,855 75,965 391,005 349,965 285,530 142,370 58,015 1,714,325 The fair value of outstanding revenue bonds was determined using currently published rates. The fair value was estimated to be $1,891.5 million and $1,827.4 million at December 31, 2014 and 2013 respectively.

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 $92.0 million and $102.3 million of TECP notes outstanding at December 31, 2014 and 2013, 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 0.08% and 0.20%

for 2014 and 2013, respectively. The notes outstanding are anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the commercial paper notes approximates market value due to the short-term nature of the notes.

Line of Credit Agreements 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, 2014 and 2013.

Revolving Credit Agreements The District has entered into a Master Amendment to Revolving Credit Agreements. Such Master Amendment to Revolving Credit Agreements provides for the tax-exempt Revolving Credit Agreement and the Taxable Revolving Credit Agreement (collectively the "Revolving Credit Agreements") with a commercial bank to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 million. The District had no balance outstanding under the TERCA at December 31, 2014, and 2013. The District had outstanding balances under the TRCA of $185.5 million and $149.4 million, at December 31, 2014 and 2013, respectively. The Revolving Credit Agreements terminate on August 31, 2015. The District anticipates renewing this agreement prior to its August 2015 expiration. 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.

NEBRASKA PBIC POEDSRIT2

Revenue bonds consist of the following (000's except interest rates):

December 31, General Revenue Bonds:

2005 Series A Serial Bonds 2014-2025...................

2005 Series B-1 Serial Bonds 2014-2015................

2005 Series B-2 Serial Bonds 2014-2016................

2005 Series C:

Serial Bonds: 2014-2025, 2040.....................

Term Bonds:

2026-2029..............................

2030-2034..............................

2035-2040..............................

2006 Series A:

Serial Bonds:

Term Bonds:

2007 Series B:

Serial Bonds:

Term Bonds:

2008 Series B:

2014-2025..............................

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

2031-2035..............................

2036-2040..............................

2036-2040..............................

2014-2026..............................

2027-2031..............................

2032-2036..............................

Serial Bonds: 2014-2029..............................

Term Bonds:

2030-2032..............................

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

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

2009 Series A Taxable Build America Bonds:

Term Bonds:

2019-2025..............................

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

2009 Series C Serial Bonds 2014-2019...................

2010 Series A Taxable Build America Bonds:

Serial Bonds:

2019-2024..............................

Term Bonds:

2025-2029..............................

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

2010 Series B Taxable Serial Bonds 2014-2020.......

2010 Series C:

Serial Bonds: 2014-2025..............................

Term Bonds:

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

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

2011 Series A Serial Bonds 2014-2016...................

2012 Series A Serial Bonds 2014-2034...................

2012 Series B:

Serial Bonds: 2014-2032..............................

Term Bonds:

2033-2036..............................

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

2012 Series C Serial Bonds 2014-2028...................

2013 Series A Serial Bonds 2014-2033...................

2014 Series A:

Serial Bonds: 2014-2038..............................

Term Bonds:

2039-2043..............................

2039-2043..............................

2014 Series B Taxable Serial Bonds 2015................

2014 Series C Serial Bonds 2015 - 2033..................

Interest Rate 3.50% -

5.25%

5.00%

5.00%

3.75% - 5.125%

5.00%

4.75%

5.00%

4.00% -

5.00%

5.00%

5.00%

4.375%

5.00%

4.00% -

5.00%

4.65%

5.00%

4.00% -

5.00%

5.00%

5.00%

5.00%

6.606%

7.399%

3.00% -

4.25%

3.98% -

4.73%

5.323%

5.423%

2.25%-

4.18%

3.00% -

5.00%

4.00%

5.00%

2.00% -

5.00%

3.00% -

5.00%

2.00% -

5.00%

3.625%

3.625%

3.00% -

5.00%

3.00% -

5.00%

2.00% -

5.00%

4.00%

4.125%

0.48%

2.00% -

5.00%

45,985 18,240 27,500 5,145 10,240 400 30,020 142,565 36,140 19,270 136,245 32,390 50,880 7,180 17,465 32,890 8,515 31,875 27,985 54,190 5,210 79,615 6,165 14,180 15,815 205,905 99,325 2,320 4,155 52,735 111,480 161,385 31,650 1,945 24,415 162,890 2014 2013 68,675 11,765 18,240 27,500 50,425 18,680 23,840 400 30,020 170,855 36,140 19,270 204,885 32,390 50,880 7,180 17,465 32,890 10,365 31,875 27,985 54,190 5,985 94,055 6,165 14,180 26,595 209,110 102,675 2,320 4,155 98,410 118,270 15 22,840 29,180 52,780 Total par amount of revenue bonds..................................................................

1,714,325 Unamortized premium net of discount.........................................................

106,360 1,820,685 Less - current maturities of revenue bonds.................................................

(109,835)

Total revenue bonds.............................................................................

$1,710,850 1,732,635 87,777 1,820,412 (124,585)

$1,695,827 28 NEBRSKA PBIC POE ISRC

8.

PAYMENTS IN LIEU OF TAXES:

The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District. Such payments totaled $10.1 for each of the years ended December 31, 2014 and 2013.

9.

ASSET RETIREMENT OBLIGATIONS:

The District has recorded an obligation for the fair value of its legal liability for the ARO associated with CNS, various ash landfills at its two coal-fired power stations, removal of asbestos at the District's various coal, gas, and hydro generating facilities, polychlorinated biphenyls from substation and distribution equipment, and underground storage tanks as well as abandonment of water wells.

The following table shows costs as of January 1, and charges to the ARO that occurred during the years ended December31, 2014 and 2013, and are included in Other long-term liabilities section of the accompanying Balance Sheets as of December 31, (000's):

2014 2013 Balance, beginning of year.....................................................................

977,083 930,178 A ccretion.............................................................................................

49,274 46,905 Balance, end of year.............................................................................

$ 1,026,357 977,083 A significant amount of the ARO was funded by decommissioning funds of $565.5 million and $533.7 million as of December 31, 2014 and 2013, respectively. See Note 2 for additional information.

At the time the liability for the asset retirement is incurred, ASC 410, Asset Retirement and Environmental Obligations, requires capitalization of the costs to the related asset. For the ARO existing at the time of adoption of ASC 410, the statement requires capitalization of costs at the level that existed at the time of incurring the liability. These capitalized costs are depreciated over the same period as the related asset. At the date of adoption, the depreciation expense for past periods was recorded as a regulatory asset in accordance with ASC 980 because the District will be able to recover these costs in future rates.

The initial liability is accreted to its present value each period. The District defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers. Accretion was $49.3 million and $46.9 million for 2014 and 2013, respectively.

10. RETIREMENT PLAN:

The District's Employees' Retirement Plan (the "Plan") is a defined contribution pension plan established by the District to provide benefits at retirement to regular full-time and part-time employees. There were 1,967 Plan members at December 31, 2014. Plan members may contribute a minimum of 2%, up to a maximum of 5%, of covered salary. The District is required to contribute two times the Plan member's contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District is required to contribute one times the Plan member's contribution. Plan provisions and contribution requirements are established and may be amended by the Board. The Participants' contributions were $11.9 million and $11.7 million for 2014 and 2013, respectively.

The District's contributions were $11.8 million and $12.0 million for 2014 and 2013, respectively. Total contributions of $1.3 million were accrued in Accounts payable and accrued liabilities for each of the years ended December 31, 2014 and 2013, respectively.

NERAK PULI POWE DITRCT2

11. OTHER POSTEMPLOYMENT BENEFITS ("OPEB")

A.

Plan Description and Funding Policy -

The District's Post-Employment Medical 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 eligibility, funding and other Plan provisions, for this single-employer, defined benefit Plan, are authorized by the Board. A stand-alone financial report is not prepared for this Plan.

Contributions from Plan members are the required premium share, which is based on date of hire and/or age. The District pays all or part of the cost (determined by age) for employees hired before 1993. Qualifying employees hired after 1992 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 retired or the amount at the time the employee reaches age 65, or the year in which the employee retires if older than age 65. Any increases in the cost of such coverage in subsequent years are paid by Plan members. Qualifying employees hired after 1998 are not eligible for postemployment hospital-medical benefits once they reach age 65 or Medicare eligibility. Employees hired after 2003 are not eligible for postemployment hospital-medical benefits. 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 postemployment hospital-medical benefits.

Contributions in the form of premium payments by OPEB Plan members were $0.5 million and $0.4 million for the years ended December 31, 2014 and 2013, respectively. Members do not contribute to the cost of the life insurance benefits.

B. Annual OPEB Cost and Net OPEB Obligation -

The annual OPEB costs are determined by actuaries and equal (a) the annual required contribution ("ARC"),

(b) one year's interest on the net OPEB obligation, and (c) an adjustment to the ARC to offset the effect of actuarial amortization of past under-or over-collected contributions. The District includes in expenses and rates the OPEB benefits/expenses expected in the current period and the amount authorized for funding in the Trust for OPEB benefit payments for future periods. The difference between the annual OPEB cost and the District's contributions are included in the net OPEB obligation. As the District uses regulatory accounting to ensure costs are consistent with those included in the rates, the offset to the net OPEB obligation is a regulatory asset.

The following table shows the components of the District's OPEB cost for the year, the amount actually contributed, and changes in the District's net OPEB obligation as of December 31, (000's):

2014 2013 2012 Annual required contribution..........................................

32,026 35,030 33,627 Interest on net OPEB obligation.....................................

5,865 5,583 4,658 Adjustment to annual required contribution......................

(5,803)

(5,191)

(4,170)

Annual O PEB cost.......................................................

32,088 35,422 34,115 Contributions m ade.......................................................

(29,816)

(23,603)

(15,620)

Increase in net OPEB obligation....................................

2,272 11,819 18,495 Net OPEB obligation, beginning of year..........................

123,475 111,656 93,161 Net OPEB obligation, end of year................................... $

125,747 123,475 111,656 30NBAK PULI POWE DISRC

The District's annual OPEB cost, the percentage of annual OPEB cost contributed, and the net OPEB obligation for 2014, 2013, and 2012 were as follows (000's):

Annual OPEB Percentage of Net OPEB Year Cost Annual OPEB Obligation Cost______

Cost Contributed Obligation 2014 32,088 92.9%

125,747 2013 35,422 66.6%

123,475 2012 34,115 45.8%

111,656 C. Funded Status and Funding Progress -

An irrevocable trust was established to fund the OPEB obligation. Total contributions in 2014 were $29.8 million, which included $11.9 million paid to the trust and $17.9 million for the cost of benefits. Total contributions in 2013 were $23.6 million, which included $10.0 million paid to the trust and $13.6 million for the cost of benefits. Total contributions in 2012 were $15.6 million, which included $4.0 million paid to the trust and $11.6 million for the cost of benefits. The 2015 budget includes $10.0 million for funding of the trust. The final funding will be determined by the Board.

Actuarial valuations were completed biennially as of January 1 for the even-numbered years. The Actuarial Value of Assets was based on the market values of the Plan's assets for the years in which valuations were completed.

The Actuarial Accrued Liability ("AAL") was the present value of benefits attributable to past accounting periods.

The Actuarial Value of Assets and AAL were based on information from the actuaries' model for the odd-numbered years. The Actuarial Value of Assets, AAL, and other information, are presented in the table below as of January 1, (000's):

Actuarial Unfunded UAAL to Actuarial Value Acura nudd Funded Covered ALt Ac a e

Accrued Actuarial Accrued Funde Payroll Covered of Assets Liability (AAL)

Liability (UAAL)

Ratio Payroll Payroll (a)

(b)

(b-a)

(a/b)

(c)

((b-a)/c) 2014

$48,274

$506,200

$457,926 9.5%

$186,637 245%

2013

$30,781

$520,705

$489,924 5.9%

$187,378 261%

2012

$24,900

$498,485

$473,585 5.0%

$189,211 250%

The above schedule presents multiyear trend information about whether the actuarial value of plan assets is increasing or decreasing over time relative to the actuarial accrued liability for benefits. Actuarial valuations of an ongoing plan involve estimates of the value of reported amounts and assumptions about the probability of occurrence of events far into the future. Examples include assumptions about future employment, mortality, and the healthcare cost trend. Amounts determined regarding the funded status of the plan and the annual required contributions of the employer are subject to continual revision as actual results are compared with past expectations and new estimates are made about the future.

D. Actuarial Methods and Assumptions -

Projections of benefits for financial reporting purposes are based on the substantive plan (the plan as understood by the employer and the plan members) and include the types of benefits provided at the time of each valuation and the historical pattern of sharing benefit costs between the employer and plan members to that point. The actuarial methods and assumptions used include techniques that are designed to reduce the effects of short-term volatility in actuarial accrued liabilities and the actuarial value of assets, consistent with the long-term perspective of the calculations.

NERAK PBLI PoE DITRCT3

The actuarial assumptions and methods used for the valuations on January 1, 2014, 2013, and 2012 were as follows:

The Pre-Medicare healthcare cost trend rates ranged from 5.9% initial to 4.4% ultimate for 2014, from 8.5% initial to 4.6% ultimate for 2013, and from 8.1% initial to 4.6% ultimate for 2012.

The Post-Medicare healthcare cost trend rates ranged from 6.2% initial to 4.5% ultimate for 2014, from 8.5% initial to 4.6% ultimate for 2013, and from 8.1% initial to 4.6% ultimate for 2012.

The discount rate used was 4.75% for 2014 and 5.0% for 2013 and 2012, which was based on the District's return on internal investments used to fund benefit payments blended with the expected return on assets of the OPEB Trust Fund.

An inflation rate of 3.5% was assumed for all three years.

Amortization for the initial unfunded AAL was determined using a closed period of 30 years and the level percentage of projected payroll method.

The average rate of compensation increase was 4.0% for all three years.

The Unit Credit Actuarial Cost method was used for all three years.

E. Market Value of Plan Investments -

The investments in the OPEB plan include corporate and government debt, foreign and domestic stocks, mutual funds and cash. Plan assets included funds in the Employee Benefit Funds for retiree life insurance of $1.2 million, $1.4 million, and $1.5 million at December 31, 2014, 2013 and 2012, respectively. The market value of plan assets, including the funds in the Employee Benefit Funds, was $64.5 million, $48.3 million and $31.7 million at December 31, 2014, 2013, and 2012, respectively.

12. COMMITMENTS AND CONTINGENCIES:

A. Fuel Commitments -

The District has various coal supply contracts and a coal transportation contract with minimum future payments of

$400.0 million at December 31, 2014. These contracts expire at various times through the end of 2018. The coal transportation contract is in place 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 with Louisiana Energy Services for enrichment services for five reloads starting in 2016 and ending in 2024. The District entered into a contract with Converdyn for conversion services of uranium to uranium hexafluoride for a portion of fuel requirements between 2015 and 2018 on a flexible schedule. The District terminated its contract with General Electric Company that was assigned to Global Nuclear Fuels-Americas for fuel bundle fabrication and related services through the 2018 reload and entered into a new contract with Global Nuclear Fuels-Americas with a General Electric Company parental guaranty, for fuel bundle fabrication and related services through the end of the current Operating License life of CNS on January 18, 2034.

B. Power Purchase and Sales Agreements -

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 from January 1, 2011 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 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 Station 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 $36.7 million. These purchases are subject to rate changes.

32~.9 NERAK PULCPOE ISRC

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 36 MW.

The District has entered into a participation power agreement (the "NC2 Agreement") with OPPD to receive 23.7% of the output of the NC2, estimated to be 162 MW of the power from the 682 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%).

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 155 MW of this capacity to four other utilities in Nebraska over similar terms.

The District has 20-year wholesale power contracts with the majority of its firm requirements wholesale customers, with terms that expire on December 31, 2021, to provide them with their total power and energy requirements through 2007, after which the wholesale customer could level-off its power and energy purchases through 2010 and thereafter could reduce its power and energy purchases up to 10% per year with at least three years advance notice.

The District has received notice from five wholesale customers as to their intent to level off or reduce the requirements under their current contracts. These customers currently represent 3.2% of the District's 2014 operating revenues. One of said customers intends to level off the requirements under their current contract beginning in 2017 and reduce the requirements under their current contract beginning in 2018. Two of said customers intend to reduce the requirements under their current contract beginning in 2018. Two of said customers intend to reduce the requirements under their current contract beginning in 2019. The District and one of said customers disagree on the reduction rate at which the customer can reduce after 2018 and a lawsuit was filed in June 2014 by the customer in state court related to said reduction rate The District does not know if any other wholesale customer will give the required notice to begin the process of leveling off or reducing their requirements under their current contracts. However, if a substantial number of wholesale customers begin leveling off or reducing their requirements, the District may be required to increase tis rates to recover costs.

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 January 1, 2016 and May 1, 2033. 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. 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.

NE13RSKA PULI POEDSRIT3

The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system. Cost of the project was

$8.4 million and repayment by Keystone, over a ten-year period, began in June 2010 with a remaining balance due the District of $5.2 million as of December 31, 2014.

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. The initial estimated cost of the project was $32.1 million and was to be paid by Keystone XL over a ten-year period anticipated to begin July 2013. However, the project was recently delayed due to routing concerns of the pipeline across the Nebraska Sandhills. Adjustments to the facilities, project costs, and completion schedules will be made once the final route is determined, which is unknown at the present time. Keystone XL remains responsible for all present and future project costs. As of December 31, 2014, actual project costs totaled $12.8 million and the District has received payment of $10.3 million.

D. Cooper Nuclear Station -

On November 29, 2010, the NRC formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until January 18, 2034. The issuance of this certificate by the NRC marked the culmination of the six-year effort to reach this milestone. On January 18, 2014, CNS entered the period of extended operation beyond the initial 40-year operating license term.

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. The Entergy Agreement was for an initial term ending January 18, 2014, subject to either party's right to terminate without cause by providing notice and paying a termination charge. The agreement was subsequently extended, effective January 1, 2010, to January 18, 2029. 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 $18.3 million and $17.4 million for 2014 and 2013, respectively. In 2015, the annual management fee is

$18.4 million. Entergy is eligible to earn additional incentive fees in an amount not to exceed $4.0 million annually if CNS achieves identified safety and regulatory performance targets. Entergy earned additional incentive fees of

$3.8 million and $2.3 million for 2014 and 2013, respectively.

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, 2014, 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.

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 GE boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes this same containment system; however, significant improvements to the design have been made over the life of the plant.

The NRC Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12, 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report, on October 18, 2011, the NRC approved seven of the Task Force recommendations for implementation. On March 12, 2012, the NRC issued three orders to the U.S. nuclear industry as a result of the Fukushima Dai-ichi 34 ~ ~

~

~

~

~

m NERSAPBI PWRDSRC

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 upgrade an existing wetwell vent. On June 6, 2013, the NRC issued an order to require the addition of a drywell vent to supplement the capabilities of this existing wetwell vent. This work is required to be completed no later than the conclusion of the fall 2018 refueling and maintenance outage or December 31, 2018, whichever comes first. The NRC continues to evaluate the possibility of requiring licensees to add a filter for both 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 pertaining to re-evaluation of seismic and flooding hazards, and a communications and staffing assessment for emergency preparedness.

The plant modifications resulting from the orders for modifications to the wetwell vent and fuel pool instrumentation are currently planned for the fall 2016 refueling and maintenance outage which is consistent with the NRC's orders that require compliance no later than two refueling cycles following submittal of the Licensee's overall integrated plan or December 31, 2016, whichever comes first. Additional NRC orders and regulations resultant from the Fukushima Dai-ichi event may be forthcoming. The specific impacts of any additional orders and regulations on CNS have not yet been evaluated.

The District's preliminary cost estimate for modifications and other mitigation strategies associated with NRC's Fukushima Dai-ichi-related orders, including any potential modifications associated with increased requirements to add a filter on the new containment vents, is estimated to cost $73.3 million.

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

As part of a 1989 settlement of various disputed matters between GE and the District, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility.

After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.

As a result of the failure of the Department of Energy ("DOE") to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 2001. In accordance with a settlement agreement between the District and the DOE that was executed on May 18, 2011, the District has received $106.8 million from the DOE for damages from 2009 through 2013. The initial settlement agreement addressed future claims through 2013. On January 13, 2014, the DOE extended the settlement agreement 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 has been established in Settlement reimbursement of the Deferred Inflows of Resources section of the accompanying Balance Sheets. The District plans to use the funds to pay for costs related to CNS. Funds of $6.1 million were used to pay expenses for the second loading campaign in 2014.

Under the terms of the DOE contracts, the District was also subject to a one mill per 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 additional payments have been made to the DOE for fuel disposal since that date. The Board authorized the continued collection of this fee at the same rate. This approach will help ensure costs are recognized in the appropriate period with current customers receiving the benefits from CNS paying the NEBRASKA PULI POE.3SFT3

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.

Refueling and maintenance outages are required to be performed at CNS approximately every two years.

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 will be eliminated through revenue recognition in the outage year.

The most recent refueling and maintenance outage began on September 27, 2014 and was completed on November 2, 2014. The plant returned to service after an outage duration of approximately 36 days. This planned outage marked the successful completion of CNS's first 24-month operating cycle. With this change in operations, the District expects to eliminate one refueling outage every six years. The next refueling outage is currently planned for the fall of 2016.

E. Environmental -

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 sent a letter to the District and three other electric utilities pursuant to Section 114(a) of the Federal Clean Air Act requesting documents and information pertaining to Gerald Gentleman Station and Sheldon Station. On April 10, 2003, Region 7 of the EPA sent a supplemental request for documents and information to the District and the other three electric utilities. These EPA requests for information are part of an EPA investigation to determine the Clean Air Act compliance status of Gerald Gentleman Station and Sheldon Station, including the potential application of new source review requirements. The District provided the documents and information requested to the EPA within the time allowed. As a supplement to the 2002 and 2003 requests, EPA Region 7 sent another letter to the District on November 8, 2007, requesting additional documents and information pertaining to Gerald Gentleman Station and Sheldon Station. The District provided a response to the new request within the time allowed and provided supplemental information to EPA in February and April 2011 in response to an EPA email inquiry. 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 Gerald Gentleman Station from 1991 through 2001 without obtaining the necessary permits. In February and August 2009, District representatives met with federal government representatives to discuss the NOV and no additional meetings have been scheduled. In general, enforcement action by EPA against the District for alleged noncompliance with Clean Air Act requirements, if upheld after court review, can result in the requirement to install expensive air pollution control equipment that is the BART and the imposition of monetary penalties ranging from $25,000 to $32,500 per day for each violation. The District cannot determine at this time whether it will have any future financial obligation with respect to the NOV.

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 Standard Rule will require reductions in emissions from new and existing coal-and oil-fired steam utility electric generating units of heavy metals, including mercury, arsenic, chromium, and nickel, dioxins, furans, and acid gases, including hydrogen chloride and hydrogen fluoride. These toxic air pollutants are also known as hazardous air pollutants. Sheldon Station has until April 16, 2015 to comply with the MATS Rule. Gerald Gentleman Station was granted an additional year to achieve compliance, thus extending its compliance date to April 16, 2016.

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

On August 19, 2002, the District received notice from the EPA identifying the District as a Potentially Responsible Party ("PRP") for liability associated with a former Manufactured Gas Plant ("MGP") located in Norfolk, Nebraska.

The District is identified as a current owner of property located adjacent to the Norfolk MGP operations. In 2002, the EPA asked identified PRPs to participate in negotiations for completing an Engineering Evaluation/Cost Analysis ("EE/CA"). The identified PRPs met with the EPA Region 7 in October 2002 to discuss the site. No other 36..

NERAK PBIC POE ISRC

activities between the District and the EPA had taken place related to this site from the time of the October 2002 meeting with the EPA until June 2004. On June 14, 2004, PRPs received notice from the EPA that the EPA was interested again in beginning efforts to complete an EE/CA to address this site. The District has denied that it has any liability as related to the MGP operations, but has indicated to the EPA willingness to cooperate with efforts to address the site. The District has reached an agreement in principal with the other PRPs to resolve its potential liability for the EE/CA by entering into a settlement agreement under which the District would contribute 10% of the costs of the EE/CA. The settlement agreement for the EE/CA has been signed by all parties and was ratified at the February 2007 Board meeting. Phase I of the EE/CA work began at the site in November 2007. On July 17, 2012, the EPA approved the final EE/CA. Remediation under the preferred alternative is estimated to cost

$2.8 million. In early 2013, the EPA contacted the PRPs to begin efforts to put in place an Administrative Order of Consent for completion of the selected remedial action. The District negotiated a settlement agreement with Centel (formerly known as Sprint) whereby the District would allow access and use of portions of District property and the District would pay a one-time settlement amount. The settlement does not have a material effect on the District. Centel agreed to the settlement terms and the EPA also approved the agreement. The settlement agreement was signed by the District on August 1, 2013 and payment was made on August 9, 2013.

F Other -

In October 2013, the Internal Revenue Service affirmed, pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, that the 35% interest subsidy provided by the United States Treasury on the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds), will be reduced by 7.2% for fiscal year ended September 30, 2014, and will be reduced by 7.3% for fiscal year ending September 30, 2015. The reduction rate is subject to change by Congressional action. This loss of subsidy totals approximately $0.2 million annually.

In March 2013, the District initiated a voluntary early retirement incentive program ("program") to all regular, full-time employees, excluding senior management, who meet certain retirement-eligible criteria. Approximately 575 District employees were eligible for the program and 110 District employees accepted the offer. Their last day of employment was no later than June 30, 2013. Those employees who participated in the program received six months of salary in one, lump sum payment. Total cost of the program was $6.0 million.

13. LITIGATION:

A number of other claims 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, 2014.

14. SUBSEQUENT EVENTS:

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 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 ranging from January 1, 2036 through January 1,2041 General Revenue Bonds, 2007 Series B, having maturity dates ranging 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 NEBRASAPUBIC POE ISTIT3

SUPPLEMENTAL SCHEDULES (UNAUDITED)

Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (000's)

Operating revenues...............................................................................

Operating expenses..............................................................................

Operating income.............................................................................

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

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

Increase in net position.....................................................................

Add:

Collections for future debt retirement..................................................

Debt and related expenses................................................................

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

Payments to retail communities")......................................................

Amortization of current portion of financed nuclear fuel.........................

Amounts collected from third party financing arrangementsc2...............

Deduct:

Investment income retained in construction funds................................

Unrealized loss on investment securities............................................

Revolving credit agreement interest....................................................

Net position available for debt service for the General Revenue Bond Resolution Amounts deposited in the General System Debt Service Account:

P rin c ip a l..........................................................................................

In te re s t............................................................................................

Ratio of net position available for debt service to debt service deposits.......

2014

$ 1,122,454 (1,010,693) 111,761 26,039 (75,438) 62,362 1,188 75,438 126,440 26,874 20,700 1,276 251,916 190 203 1,731 2,124 2013 1,106,291 (941,887) 164,404 15,221 (82,242) 97,383 6,747 82,242 127,283 27,092 22,455 770 266,589 119 (1,335) 1,444 228 312,154 363,744 124,780 82,978 207,758 1.50 118,915 91,758 210,673 1.73 (1) Under the provisions of the General Revenue Bond Resolution, the payments required to be made by the District with respect to the Professional Retail Operations Agreements are to be made on the same basis as subordinated debt.

(2) Under the provisions of the General Revenue Bond Resolution, the payments received by the District from third party financing arrangements provide for debt service coverage, but are not recognized as revenue under Generally Accepted Accounting Principles.

38 NERAK PULCPOE ISRC

Schedule of Funding Progress for OPEB as of January 1, (000's)

Actuarial Value of Assets (a)

$48,274

$30,781

$24,900 Actuarial Accrued Liability (AAL)

(b)

$506,200

$520,705

$498,485 Unfunded Actuarial Accrued Liability Funded Ratio (UAAL)

(b-a)

(a/b)

$457,926 9.5%

$489,924 5.9%

$473,585 5.0%

Covered Payroll (c)

$186,637

$187,378

$189,211 UAAL to Covered Payroll

((b-a)/c) 245%

261%

250%

2014 2013 2012 I NEBRASKA P

UBI P WEDITCT31

Nerak Puli Poe Ditrc Alcr s thr ic yu edu