NLS2011048, Submittal of 2010 Annual Financial Report

Submittal of 2010 Annual Financial Report

ML11132A025
Person / Time
Site:	Cooper
Issue date:	05/05/2011
From:	Vanderkamp D Nebraska Public Power District (NPPD)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NLS2011048
Download: ML11132A025 (39)

Text

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

NLS2011048 May 5, 2011 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Nebraska Public Power District 2010 Annual 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 Annual Financial Report for the calendar year 2010 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.

Should you have any questions or require additional information, please contact me at (402) 825-2904.

Sincerely, David W. Van Der Kamp Licensing Manager

/jo Enclosure 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 /Y0.1 COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3871 / Fax: (402) 825-5211 www.nppd.com

4 ATTACHMENT 3 LIST OF REGULATORY COMMITMENTS© ATTACHMENT 3 LIST OF REGULATORY COMMITMENTS©O Correspondence Number: NLS2011048 The following table identifies those actions committed to by Nebraska Public Power District (NPPD) in this document. Any other actions discussed in the submittal represent intended or planned actions by NPPD. They are described for information only and are not regulatory commitments. Please notify the Licensing Manager at Cooper Nuclear Station of any questions regarding this document or any associated regulatory commitments.

COMMITMENT COMMITTED DATE COMMITMENT. NUMBER OR OUTAGE None 4- A 4- 4

4. 4 1- I 1~ I 1* I

.1 &

I &

I ______________________ L ___________________________

I PROCEDURE 0.42 REVISION 27 PAGE 18 OF 25

Statistical Review 1 Management's Discussion and Analysis 2 Report of Independent Auditors 13 Financial Statements 14 Notes to Financial Statements 18 201 YEAR A A G ANC KILOWATT-HOUR SALES 19.8 BILLION OPERATING REVENUES 925.1 MILLION COST OF POWER PURCHASED AND GENERATED 506.7 MILLION OTHER OPERATING EXPENSES 302.2 MILLION INCREASE IN FUND EQUITY 60.7 MILLION DEBT SERVICE COVERAGE 1.73

2010 STATISTICAL REVIEW Revenues from Average Electric Energy Electric Sales Number of MWh Sales (000's) Revenue SALES Customers Amount  % Amount  % Per kWh Retail:

Residential 68,545 841,645 4.2 $ 83,883 9.1 9.97¢ Rural and Farm 3,093 72,000 0.4 6,406 0.7 8.900 Commercial 14,929 926,691 4.7 74,149 8.0 8.00¢ Industrial 55 1,223,628 6.2 61,675 6.7 5.04¢ Public Lighting 195 19,012 0.1 2,356 0.2 12.390 Municipal Power 184 27,051 0.1 2,119 0.2 7.83¢ Miscellaneous Municipal 1,988 137,584 0.7 8,073 0.9 5.870 Total Retail Sales 88,989 3,247,611 16.4 238,661 25.8 7.350 Wholesale:

52 Municipalities (Total Requirements) 2,017,389 10.2 100,701 10.9 4.99¢ 25 Public Power Districts and Cooperatives (Total Requirements) 7,156,665 36.1 337,137 36.4 4.710 Total Wholesale Sales (Excluding Sales to LES and Other Utilities) 9,174,054 46.3 437,838 47.3 4.770 Total Retail and Wholesale Sales LES(')(Excluding Sales to LES and Other Utilities) 12,421,665 62.7 676,499 73.1 5.450 1,277,349 6.5 35,186 3.8 2.750 Other Utilities (Nonfirm and Other Sales) 6.103,281 30.8 180.168 19.5 2.95d Total Electric Energy Sales 19,802,295 100.0 891,853 96.4 4.50¢ Other Operating Revenues (Net of Deferred) 33,288 3.6 Total Operating Revenues $ 925,141 100.0 Production MWh Costs (000's)

GENERATION Amount  % Amount  %

Production (Including Interchange)(2) 17,761,278 86.3 $ 395,365 78.0 Power Purchased 2,819,714 13.7 111,364 22.0 Total Power Produced and Purchased 20,580,992 100.0 $506,729 100.0 (1) Sales to Lincoln Electric System ("LES") include power and energy produced at Nebraska Public Power District's Gerald Gentleman Station and Sheldon Station.

(2) Costs include only fuel, operation, and maintenance costs. Debt service and capital related costs are excluded.

Miles of Transmission and Subtransmission Line in Service 5,124 Number of Employees (Filled Full-Time and Part-Time Positions) 2,267 2010 Contractual and Tax Payments (000's):

Payments to Retail Communities $ 21,970 Payments in Lieu of Taxes $ 8,333 Hydro & Renewable Purchases SOURCES OF ENERGY - 2010 (7.3%) __ (7.7%)

For service to retail and to total requirements wholesale customers Gas & Oil A (0.7%)

(excludes sales to Other Utilities and Coal LES). (43.6%)

Nuclear (40.7%)

MANAGEMENT'S DISCUSSION AND ANALYSIS The following Management's Discussion and Analysis should be read in conjunction with the audited Financial Statements and Notes to Financial Statements beginning on page 14.

OVERVIEW OF BUSINESS Nebraska Public Power District (the "District") operates an integrated electric utility system including facilities for generation, transmission, and distribution of electric power and energy for sales to wholesale and retail customers. The District is a summer peaking utility. An all-time system summer peak demand of 2,671 MW was established in July 2006 for the District's firm requirements customers. The District's all-time winter peak demand is 2,219 MW, which was established in December 2009. The District owns or has operating control over 37 generating plants, which had a combined accredited capacity during the summer of 2010 of 3,127.3 MW.

GENERATION PLANTS Summer 2010 Number1 of Accredited Percent of Type: Plants( ) Capability (MW) Total Coal - Gerald Gentleman Station 1 1,365.0 43.7 Coal - Sheldon Station 1 225.0 7.2 Gas - Beatrice Power Station 1 237.0 7.6 Gas/Oil - Canaday Station 1 111.0 3.5 Nuclear - Cooper Nuclear Station 1 767.2 24.5 Hydro 9 164.6 5.3 Diesel 19 105.3 3.4 Combustion Turbine 3 151.0 4.8 Wind 1 1.2 0.0 37 3,127.3 100.0 (1) Includes six hydro plants and 17 diesel plants under contract to the District.

In addition to the above generating plants, the District purchases 450.5 MW of firm power from the Western Area Power Administration and other capacity and energy on both a short-term and nonfirm basis in the wholesale energy market. The District had other capacity purchases of 162.0 MW from Omaha Public Power District's

("OPPD") Nebraska City Station Unit 2 ("NC2") coal-fired plant and 1.2 MW from the Elkhorn Ridge Wind Facility.

Of the total capacity resources, 491.7 MW are being sold via participation sales or other capacity sales agreements. The District owns and operates 5,124 miles of transmission and subtransmission lines, encompassing the entire State of Nebraska.

The District's customer base for firm energy sales consists of approximately 88,990 retail customers plus 77 municipalities, public power districts, and cooperatives that are total requirements wholesale customers of the District. In addition, the District has 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 the wholesale energy market.

ENERGY SALES Gigawatt Hours 20,000 /

15,000 7,156 7,157 6,718 7,475 7,380 10,000 11,265 11,607 12,079 12,043 12,422 5,000 0

2006 2007 2008 2009 2010 U Firm Energy Sales N Additional Energy Sales

CONDENSED BALANCE SHEETS 2010 2009 2008 Condensed Balance Sheets (000's):

Utility Plant, net $2,318,607 $ 2,235,069 $2,123,284 Special Purpose Funds 882,484 767,497 859,656 Current Assets 442,806 383,128 370,528 Deferred Charges and Other Assets 695,211 811,805 717,388 Total Assets $4,339,108 $4,197,499 $4,070,856 Fund Equity $ 960,598 $ 899,866 $ 883,676 Long-Term Debt 1,943,728 2,009,021 1,921,968 Current Liabilities 426,394 206,642 244,083 Deferred Credits and Other Liabilities 1,008,388 1,081,970 1,021,129 Total Fund Equity and Liabilities $4,339,108 $4,197,499 $4,070,856 CONDENSED RESULTS OF OPERATIONS 2010 2009 2008 Condensed Statements of Revenues, Expenses, and Changes in Fund Equity (000's):

Operating Revenues $ 925,141 $ 863,398 $ 831,259 Operating Expenses (808,864) (796,904) (778,351)

Operating Income 116,277 66,494 52,908 Investment and Other Income 32,768 31,860 48,789 Debt and Other Expenses (88,313) (82,164) (75,638)

Increase in Fund Equity $ 60,732 $ 16,190 $ 26,059 The sources of operating revenues were as follows (000's):

2010 2009 2008 Firm Sales - Wholesale and Retail $ 676,499 $ 621,985 $ 574,339 Participation Sales to LES and MEC(1) 35,186 77,307 90,825 Sales to Other Utilities 180,168 123,711 124,937 Other Operating Revenue 40,239 31,304 28,121 Deferred Revenue (6,951) 9,091 13,037 Total Operating Revenue $ 925,141 $ 863,398 $ 831,259 (1) The participation sales to MEC from CNS ended in December 2009.

NEBRASKA PBIC POE ISRC

Revenues from Firm Sales - Wholesale and Retail Revenues from firm sales increased $54.5 million, or 8.8%, from $622.0 million in 2009 to $676.5 million in 2010.

This increase is due primarily to 5.9% wholesale and 5.7% retail rate increases effective January 1, 2010, as a result of a $140.0 million investment in a high-voltage transmission line needed in eastern Nebraska and a

$198.2 million investment in its shared costs of OPPD's NC2 power plant. An additional increase is due to a 3.1% increase in Kilowatt-hour energy sales. Revenues from firm sales increased $47.7 million, or 8.3%, from

$574.3 million in 2008 to $622.0 million in 2009. This increase is due primarily to 7.0% wholesale and 6.0% retail rate increases effective January 1, 2009, as a result of increased fuel and energy costs and other inflationary costs of operations.

AVERAGE REVENUE PER kWh SOLD - RETAIL Cents per kWh (Retail - All Classes) 7 "r 7.40-7.20-7.00-6.80-6.60-6.40-6.20-6.00-5.80 5.60 2006 2008 AVERAGE REVENUE PER kWh SOLD - WHOLESALE Cents per kWh (Firm Wholesale Customers Only) 4.80 -

4.774 4.60- A 4,14 4.40-4.20-

'AQ"4#

4.00 -

3.80 - 7A.4 3.60-3.40-3.20-3.00-Revenues from Participation Sales to LES and MEC and Sales to Other Utilities During 2010, the District made participation sales to LES from the capacity and energy produced at Gerald Gentleman Station ("GGS") and Sheldon Station; to KCP&L from GGS and CNS; to Heartland Consumers Power District ("Heartland") from CNS; and to the Municipal Energy Agency of Nebraska ("MEAN") from GGS and CNS. The District also engaged in sales of energy with other utilities on a nonfirm basis.

Revenue from participation sales to LES and MEC decreased from $77.3 million in 2009 to $35.2 million in 2010.

The decrease is due primarily to the MEC power sales contract expiring at the end of 2009. This contract was not renewed. Revenue from participation sales to LES and MEC decreased $13.5 million from $90.8 million in 2008 to

$77.3 million in 2009. The decrease is due primarily to LES's share of capital costs related to Sheldon Station being less in 2009 than in 2008, and a decrease of 4.8% in kilowatt-hour energy sales from CNS to MEC in 2009 from 2008 in addition to a decrease in the 2009 MEC contracted sales price.

Sales to other utilities consist of participation sales to KCP&L, Heartland, and MEAN and nonfirm off-system sales. The Energy Authority ("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. Sales to other utilities increased from $123.7 million in 2009 to $180.2 million in 2010, an increase of $56.5 million. This increase is due primarily to additional revenue realized from nonfirm off-system sales as the result of excess generation being available to sell on the open market due to the expiration of the MEC power sales contract at the end of 2009 and no refueling outage in 2010 for CNS versus 2009. Sales to other utilities decreased from $124.9 million in 2008 to

$123.7 million in 2009, a decrease of $1.2 million. This decrease is due primarily to lower contract prices in 2009 than in 2008.

Other OperatinQ Revenue Other operating revenue consists primarily of transmission wheeling revenues and revenue from work for other utilities. These revenues were $40.2 million, $31.3 million, and $28.1 million in 2010, 2009, and 2008, respectively. The increase in 2010 is due primarily to Southwest Power Pool ("SPP") Schedule 11 revenues which represent costs paid by other transmission owners of SPP to the District for its qualifying transmission upgrade projects, net of similar costs paid by the District to the other transmission owners for their qualifying transmission upgrade projects within the SPP service area.

Deferred Revenue The District's wholesale and retail electric rates are established on a prospective basis. The estimated revenue requirements used to establish rates include operating expenses, excluding depreciation and amortization; debt service requirements on revenue bonds; payments of principal and interest on subordinated debt; amounts for capital projects to be paid from current revenues; amounts for reserves to pay future costs, such as future nuclear facility decommissioning costs; and other post retirement benefit costs, net of revenue received from LES and other utilities (nonfirm and other sales).

Under the provisions of the District's wholesale power contracts, if the rates for wholesale power service in any year result in a surplus or deficiency in revenues necessary to meet revenue requirements, such surplus or deficiency, within certain limits set forth in the wholesale power contracts, may be retained in a rate stabilization account. Any amounts in excess of the limits will be included as an adjustment to revenue requirements in future rate periods. 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, such surpluses or deficiencies are accounted for as "regulatory assets or liabilities." The District follows this accounting treatment.

The District recognizes all 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.

During 2010 and 2009, actual revenue requirements exceeded firm wholesale and retail sales in each such year.

During 2008, revenues from firm wholesale and retail sales exceeded actual revenue requirements.

The District deferred or decreased revenues a net amount of $7.0 million in 2010. The District's revenues in 2010 from firm wholesale and retail electric sales resulted in a deficiency, or under collection of costs, of $0.2 million, which deficiency amount was accrued (increase in revenues). In addition, the wholesale rates that were in place 5 ERSK PBIC POE ISRC

for 2010 included a collection of $7.2 million of deferred costs from past rate periods. Such deferral had previously been accounted for as an increase in revenue in the year(s) the deficiency occurred. Accordingly, the 2010 revenues from electric sales, which reflect the deferred costs being collected, are offset by a revenue adjustment (decrease in revenues) for such amount.

The District recognized or increased revenues a net amount of $9.1 million in 2009. The District's revenues in 2009 from firm wholesale and retail electric sales resulted in a deficiency, or under collection of costs, of

$4.3 million, which deficiency amount was accrued (increase in revenues). In addition, the wholesale and retail rates that were in place for 2009 included a refund of $4.8 million of surplus net revenues from past rate periods.

Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred.

Accordingly, the 2009 revenues from electric sales, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount.

The District recognized or increased revenues a net amount of $13.0 million in 2008. The District's revenues in 2008 from firm wholesale and retail electric sales resulted in a surplus, or over collection of costs, of $3.8 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale and retail rates that were in place for 2008 included a refund of $16.8 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred. Accordingly, the 2008 revenues from electric sales, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount.

As of December 31, 2010, 2009, and 2008, the District had $50.8 million, $43.8 million, and $52.9 million, respectively, of surplus deferred revenues yet to be applied as credits against revenue requirements in future rate periods.

Operating Expenses The following chart illustrates operating expenses for the years 2008, 2009, and 2010.

Dollars OPERATING EXPENSES (Millions) 1,000-

$778 $797 $809 800-

• Power Purchased & Fuel 600- Production - Operation &Maintenance ("O&M")

• Transmission &Distribution O&M 400- Customer Service & Information

• Administrative & General 200- Decommissioning

• Depreciation &Amortization

• .Other 2008 2009 2010 Total operating expenses in 2010 were $808.9 million, an increase of $12.0 million from 2009. Total operating expenses in 2009 were $796.9 million, an increase of $18.5 million from 2008. The changes were due primarily to the following:

Purchased power and production fuel expenses were $286.4 million, $259.0 million, and $259.2 million in 2010, 2009, and 2008, respectively. These expenses increased $27.4 million in 2010 as compared to 2009 due primarily to increased native load sales, a full year of purchases from NC2, increased hydro purchases, and higher fuel costs as a result of continued price increases in both coal and nuclear fuel and related transportation costs. These expenses remained consistent between 2009 and 2008.

I,[ wl

Production operation and maintenance expenses were $220.3 million, $246.3 million, and $241.5 million in 2010, 2009, and 2008, respectively. These costs decreased $26.0 million in 2010 as compared to 2009 due primarily to the costs associated with a planned refueling and maintenance outage at CNS in 2009. No such outage occurred in 2010. These costs increased $4.8 million in 2009 as compared to 2008 due primarily to outside contractor costs associated with CNS.

Transmission and distribution operation and maintenance expenses were $54.3 million, $55.7 million, and

$47.8 million in 2010, 2009, and 2008, respectively. These expenses did not vary significantly from 2010 to 2009.

These costs increased $7.9 million in 2009 as compared to 2008 due to additional vegetation management charges and the addition of the SPP Market Administration monitoring and compliance services, along with other SPP fees, which were offset, in part, by additional other operating revenues. The District joined SPP in April 2009.

Additional increases are due to the acquisition of computer and communications equipment to meet certain North American Electric Reliability Corporation and SPP requirements.

Customer service and information expenses were $18.1 million, $18.7 million, and $16.8 million in 2010, 2009, and 2008, respectively. These expenses did not vary significantly from 2010 to 2009. These costs increased

$1.9 million in 2009 as compared to 2008 due to a full year of activity for the Energy Efficiency Program which was implemented in the fourth quarter of 2008.

Administrative and general expenses were $53.2 million, $53.2 million, and $48.8 million in 2010, 2009, and 2008, respectively. These expenses remained consistent between 2010 and 2009. These costs increased $4.4 million in 2009 as compared to 2008 due primarily to less administrative and general costs being capitalized in 2009 as the result of a decrease in authorized capital projects.

Decommissioning expenses were $27.1 million, $25.8 million, and $32.0 million in 2010, 2009, and 2008, 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 interest income and market value changes of investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year. Decommissioning expenses increased by

$1.3 million in 2010 as compared to 2009 due to an increase in interest income on investments. Decommissioning expenses decreased by $6.2 million in 2009 as compared to 2008 due to a decrease in interest income on investments and no amount for decommissioning was collected through rates in 2009 or 2010.

To the extent that the accretion on the asset retirement obligation determined under ASC 410 is different from the total of amounts collected in rates and investment earnings on monies accumulated in the decommissioning funds, the District will defer that difference as a regulatory asset or liability to be recovered or refunded in future periods. Accretion for 2010, 2009, and 2008 was $44.8 million, $46.2 million, and $33.6 million, respectively, and decommissioning expense was $27.1 million, $25.8 million, and $32.0 million, respectively.

Depreciation and amortization expenses were $119.2 million, $110.7 million, and $106.5 million in 2010, 2009, and 2008, respectively. These expenses increased $8.5 million in 2010 as compared to 2009 due primarily to the depreciation of a new high-voltage transmission line in eastern Nebraska beginning in January 2010 and a full year of amortization of the NC2 prepaid power purchase and prepaid transmission costs. These expenses increased $4.2 million in 2009 as compared to 2008 due primarily to the amortization of the NC2 prepaid power purchase and prepaid transmission costs beginning in May 2009.

Increase in Fund Equity The increase in fund equity (net revenues) was $60.7 million in 2010, $16.2 million in 2009, and $26.1 million in 2008. The increase in fund equity of $44.5 million in 2010 as compared to 2009 reflects increases in revenue requirements used to establish rates for 2010 for the purpose of increased revenue bond and commercial paper principal payments partially offset by increased depreciation expense and decreased interest income on construction funds. The decrease in fund equity of $9.9 million in 2009 as compared to 2008 reflects, primarily, an increase in unrealized losses of the District's investments and an increase in depreciation expense offset, in part, by increased revenue requirements used to establish rates for 2009.

NEIJRASK PBIC POE ISRC

13=%/CK1HCC J? CVOCKICCO Dollars r ,- v ,- I- I i-(Millions) 1,000-900 800

$863 700 $797 600.

500-400 -

2008 2009 2010 Operating Revenue Other Revenue Operating Expenses Other Expenses CAPITAL REQUIREMENTS The District's Board of Directors ("Board") authorized capital projects totaling approximately $214.3 million in 2010, $186.9 million in 2009, and $357.6 million in 2008. The amount for 2010 included $32.6 million for construction of transmission lines and substations related to the South Sioux City Expansion Project, $27.7 million for the replacement of a high pressure turbine at CNS, $21.7 million for replacement of four main power transformers at CNS, and $11.0 million for initial costs related to the construction of a high-voltage transmission line from Axtell, Nebraska to the Kansas border. The amount for 2009 included an additional supplement of

$19.3 million for a dry cask fuel storage facility at CNS, $17.2 million for the security facility modification at CNS,

$16.1 million for replacement of four feedwater heaters at CNS, $12.8 million for Phase I of the installation of a statewide radio system, and $12.5 million for the first campaign to move spent nuclear fuel from the cooling pool to the storage pad. The amount for 2008 included $147.0 million for Phase II of the Electric Transmission Reliability ("ETR") Project, $41.9 million for the purchase of several transformers, $17.2 million for a new water treatment and discharge system at Sheldon Station, $18.7 million for a new all-purpose operations facility in Norfolk, Nebraska, and $9.6 million for replacement of Unit 1 cooling towers at Sheldon Station. The remaining capital projects authorized in 2010, 2009, and 2008, which totaled $121.3 million, $109.0 million, and

$123.2 million, respectively, were primarily for renewals and replacements to existing facilities and other minor additions and improvements. The District's Board-approved budget for capital projects for 2011 is $330.7 million, which includes $79.2 million for construction of a high-voltage transmission line from Axtell, Nebraska to the Kansas border, $50.8 million for construction of transmission lines and substations related to the TransCanada Keystone XL Pipeline Project, the majority of which will be reimbursed by TransCanada, $39.3 million for installation of low nitrogen-oxide burners at GGS, and $10.6 million for Phase II of an electrical power back feed at CNS. The District's capital requirements are funded by a combination of monies generated from operations, issuance of revenue bonds, issuance of short-term debt, and other available reserve funds.

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Dollars L;AV'I IPL K _UUIKtIMIN I Zý (Millions) 500-400 - $358

$331 300-

$214 200- $187 1001 2008 2009 2010 2011 Budget FINANCING ACTIVITIES The District had $2.014 billion of outstanding revenue bonds at December 31, 2010, as compared to

$1.843 billion (par amount) at December 31, 2009, and $1.756 billion (par amount) at December 31, 2008. The revenue bonds outstanding are at fixed interest rates and were issued at premiums or discounts. The District had outstanding $122.0 million of tax-exempt commercial paper ("TECP") notes at December 31, 2010, $117.0 million at December 31, 2009, and $92.0 million at December 31, 2008. Also, the District had outstanding $98.9 million of taxable commercial paper ("TCP") notes at December 31, 2010, $117.2 million at December 31, 2009, and

$121.3 million at December 31, 2008. Both the TECP notes and the TCP notes have a bank credit agreement, each expiring August 1, 2011, maintained to support the sale of the commercial paper notes.

In September 2010, the District issued $114.1 million of taxable revenue bonds (Build America Bonds) and

$147.1 million of tax-exempt revenue bonds to finance $164.8 million of the costs of certain generation, transmission, and distribution capital additions, to refund $77.6 million of TCP notes, and to refund $16.8 million of TECP notes. Also in September 2010, the District issued $8.4 million of taxable revenue bonds to refund

$8.2 million of TCP notes.

In June 2009, the District issued $50.4 million of taxable revenue bonds (Build America Bonds) and $17.9 million of tax-exempt revenue bonds for certain generation and other transmission capital additions. Also in June 2009, the District issued $100.0 million of taxable revenue bonds to refund $69.5 million of TCP notes and to provide

$28.4 million for certain capital additions at CNS.

In March 2008, the District issued $137.8 million of taxable revenue bonds to advance refund $93.7 million of taxable revenue bonds issued in 2007 and to refund $43.1 million of TCP notes used to redeem the taxable revenue bonds issued in 2004. In September 2008, the District issued $332.2 million of tax-exempt revenue bonds at a net premium to provide $148.0 million for the remaining cost of the ETR Project, to provide

$80.0 million for certain generation and other transmission capital additions, to refund $57.0 million of TECP notes that were issued to pay for costs associated with the December 2006 ice storms, the purchase of several transformers and other capital additions, and to provide $26.0 million for the District's remaining share of the OPPD NC2 coal-fired generating plant and associated transmission facilities. Under the terms of a power purchase agreement with OPPD, the District is receiving 23.7% of the output of NC2, approximately 162 MWs since it began commercial operation on May 1, 2009.

The District retired $99.0 million, $81.2 million, and $82.6 million of General System Revenue Bonds in 2010, 2009, and 2008, respectively.

The District's current credit ratings on its long-term debt are as follows:

Moody's Investors Service Al (stable outlook)

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

Fitch Ratings A+ (stable outlook)

DEBT SERVICE COVERAGE The District's debt service coverage was 1.73 in 2010, 1.69 in 2009, and 1.59 in 2008. The coverage is 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 amounts collected in operating revenues to fund the cost of payments made to those municipalities served by the District under long-term Professional Retail Operating Agreements. The District has established a goal in its planning process to maintain a debt service coverage of approximately 1.5 times annual debt service.

CNS FUTURE OPERATION Cooper Nuclear Station is currently licensed to operate until January 2034. On November 29, 2010, the Nuclear Regulatory Commission ("NRC") formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until January 18, 2034. The issuance of this certificate by the NRC marked the culmination of the six-year effort to reach this milestone. The District is also evaluating the potential for an extended power uprate of CNS.

The District entered into an agreement for support services at CNS with Entergy Nuclear Nebraska, LLC

("Entergy"), a wholly-owned indirect subsidiary of Entergy Corporation, in October 2003. The Entergy agreement was for an initial term ending January 18, 2014. The agreement was subsequently extended, effective January 1, 2010, to January 18, 2029. The agreement requires the District to reimburse Entergy's costs of providing services and to pay Entergy annual management fees. Since 2007, Entergy has been eligible to earn additional incentive fees if CNS achieves identified safety and regulatory performance targets during each such year.

The District entered into a power sales contract with MEC to provide 250 MW of capacity and energy from January 1, 2005 through December 31, 2009. This contract was not renewed. The District also entered into agreements for the sale of capacity and energy from CNS to Heartland, to KCP&L, and to MEAN. The Heartland agreement provides for delivery of capacity and energy from January 1, 2004 through December 31, 2013, in amounts ranging from 5 MW up to 45 MW. The KCP&L agreement provides for delivery of 75 MW of capacity and energy from January 1, 2005 through January 18, 2014. The MEAN agreement, amended on December27, 2010, provides for delivery of capacity and energy from July 1, 2008 through December 31, 2010, of 95 MW, of which 60% will be provided from CNS and 40% from GGS. In addition, the amended agreement provides for delivery of capacity and energy from January 1, 2011 and terminating the last day of the month prior to the commercial operation of the Whelan Energy Center 2 ("WEC2") fossil plant, of 45 MW, of which 29 MW will be provided from CNS and 16 MW from GGS. If CNS is removed from commercial operation or off-line continuously for six months, the associated energy will be supplied from GGS. MEAN has an ownership interest in WEC2, a 220 MW coal-fired power plant, and it is expected to begin commercial operation in May 2011. On December 27, 2010, the District entered into a second MEAN agreement for the delivery of capacity and energy from January 1, 2011 through December 31, 2023, of 50 MW, of which 26 MW will be provided from CNS and 24 MW from GGS.

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. On March 17, 2011, the District offered to settle its litigation against the DOE for spent nuclear fuel disposal damages in exchange for the payment of approximately $60.6 million representing costs incurred for the on-site storage of spent nuclear fuel at CNS through December 31, 2009, along with subsequent claims pursuant to the provisions of the settlement agreement. The District anticipates a response from the DOE in April 2011.

RESOURCE PLANNING The District increased its base load resources when OPPD's NC2 coal-fired plant began commercial operation on May 1, 2009. The District's share of this facility is 162 MW. With this addition to its already diverse power resource mix, and with various capacity and energy contracts between 2009 and 2014, the District is well positioned to meet its firm load requirement needs for the next 15 to 20 years. The District also continues to focus NEBRASK PULCPWR ITIT1

on the (i) addition of renewables, (ii) effectiveness of energy efficiency programs, (iii) evaluation of additional peaking capacity, and (iv) evaluation of an extended power uprate of CNS.

In February 2008, the District entered into a 20-year power purchase agreement with Elkhorn Ridge Wind, LLC to purchase electric power from the 80 MW Elkhorn Ridge Wind Facility developed near Bloomfield, Nebraska, which became commercially operational March 1, 2009. The District has entered into agreements to sell one-half of the capacity of this project to other utilities in Nebraska. In April 2008, the District entered into a 20-year power purchase agreement with Community Wind Energy Transmission, LLC to purchase electric power from the 42 MW Crofton Hills Wind Facility planned for development in 2012 near Crofton, Nebraska. Construction of this facility has not yet commenced.

In February 2010, the District entered into a 20-year power purchase agreement with Laredo Ridge Wind, LLC to purchase electric power from the 80 MW Laredo Ridge Wind Facility near Petersburg, Nebraska, which became commercially operational February 1, 2011. The District has entered into agreements to sell 19 MW of the capacity of this project to other utilities in Nebraska. In September 2010, the District entered into a 20-year power purchase agreement with Broken Bow Wind, LLC to purchase electric power from the 80 MW Broken Bow Wind Facility planned for development near Broken Bow, Nebraska. This wind facility is scheduled to begin commercial operation in December 2012. Construction of this facility has not yet commenced. The District plans to sell 37 MW of the capacity of this project to other utilities in Nebraska. In October 2010, the District entered into a 20-year power purchase agreement with Bluestem, LLC to purchase electric power from a 3 MW wind facility planned for development near Springview, Nebraska. This wind facility is scheduled to begin commercial operation in the third quarter of 2012. Construction of this facility has not yet commenced. The District plans to share the cost of this project with other utilities in Nebraska and will share the knowledge gained from the operation of these direct drive wind turbines.

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 projects to the District's electric system. Participating utilities will pay their pro rata share of capital additions.

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, 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 ("Policy"). The Policy, approved by the Board, establishes guidelines and objectives and delegation of authorities necessary to govern activities related to the District's energy risk management program.

The objective of the 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.

On April 1, 2009, the District became a member of the Southwest Power Pool ("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 is 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.

NEBRASK PBIC POE ITi-

ECONOMIC FACTORS The national economic slowdown and subsequent weak recovery have not had a significant impact on the District's native load electrical demand. The Midwest region has experienced unemployment rates that have been higher than pre-recession levels, but remain far below the national averages. The strong overall performance of Nebraska's agricultural sector, as measured by net farm income, has contributed to the state's positive economic performance. Nebraska's unemployment rate decreased slightly from an average of 4.8% for 2009 to an average of 4.7% for 2010, compared to the national average unemployment rate of 9.6%. Nebraska's seasonally adjusted unemployment rate was 4.3% in December2010 and 5.0% in December2009, compared to the national seasonally adjusted unemployment rate of 9.4% and 9.9% in 2010 and 2009, respectively. For December 2010, the unemployment rate in Nebraska 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.

The District has not seen a significant increase in its uncollectible customer accounts.

COMMITMENTS AND CONTINGENCIES 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 July 2010 with a remaining balance due the District of $8.3 million as of December 31, 2010.

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. Estimated cost of the project is $52.9 million and is to be paid by Keystone XL over a ten-year period anticipated to begin in July 2013. As of December 31, 2010, actual project costs totaled $2.4 million.

NEBASK PBIC PW R*DITIT1

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

We have audited the accompanying balance sheets of Nebraska Public Power District (the "District") as of December 31, 2010 and 2009, and the related statements of revenues, expenses, and changes in fund equity and of cash flows for the years then ended. These financial statements are the responsibility of the District's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the District at December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

Management's discussion and analysis included on pages two through twelve is not a required part of the basic financial statements but is supplementary information required by the Governmental Accounting Standards Board.

We have applied certain limited procedures, which consisted primarily of inquires of management, regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.

In accordance with Governmental Auditing Standards,we have also issued our report dated April 14, 2011 on our consideration of the District's internal control over financial reporting and on our test of its compliance with certain provisions of laws, regulations, contracts and grant agreements and other matters for the year ended December 31, 2010. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Governmental Auditing Standards and should be considered in assessing the results of our audits.

Our audits were conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedule, "Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, 2010 and 2009," is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.

St. Louis, Missouri April 14, 2011 13 NEBRSKA PUBIC OE DISTI

FINANCIAL STATEMENTS Balance Sheets - December 31, 2010 and 2009 (000's) 2010 2009 ASSETS Utility Plant, at Cost:

Utility plant in service $ 4,128,177 $ 3,948,830 Less reserve for depreciation 2,182,254 2,110,620 1,945,923 1,838,210 Construction work in progress 183,949 201,324 Nuclear fuel, at amortized cost 188,735 195,535 2,318,607 2,235,069 Special Purpose Funds:

Cash and cash equivalents:

Debt reserve fund 17 210 Employee benefit funds 2,433 3,167 Investments:

Construction funds 286,997 203,009 Debt reserve fund 101,925 98,283 Employee benefit funds 6,982 3,844 Decommissioning funds 484,130 458,984 882,484 767,497 Current Assets:

Cash and cash equivalents 113,213 38,002 Investments 63,260 101,714 Receivables, less allowance for doubtful accounts of $528 and $531, respectively 84,682 77,467 Fossil fuels, at average cost 41,045 31,314 Materials and supplies, at average cost 122,593 117,120 Prepayments and other current assets 18,013 17,511 442,806 383,128 Deferred Charges and Other Assets:

Deferred asset retirement obligation 358,047 482,900 Deferred OPEB obligation 80,244 62,020 Long-term capacity contracts 210,990 218,417 Deferred settlement charges 10,199 14,937 Unamortized financing costs 15,860 15,815 Investment in The Energy Authority 7,614 6,776 Other 12,257 10,940 695,211 811,805 TOTAL ASSETS $ 4,339,108 $ 4,197,499 FUND EQUITY AND LIABILITIES Fund Equity:

Invested in capital assets, net of related debt $ 568,437 $ 590,599 Restricted 50,235 46,407 Unrestricted 341,926 262,860 960,598 899,866 Long-Term Debt:

Revenue bonds, net 1,943,728 1,774,787 Commercial paper notes - 234,234 1,943,728 2,009,021 Current Liabilities:

Current maturities of revenue bonds 111,145 97,575 Current maturities of commercial paper notes 220,872 -

Accounts payable and accrued liabilities 59,660 76,331 Accrued in lieu of tax payments 8,276 7,532 Accrued payments to retail communities 4,898 4,712 Accrued compensated absences 15,760 15,175 Other 5,783 5,317 426,394 206,642 Deferred Credits and Other Liabilities:

Asset retirement obligation 843,741 943,647 Deferred revenues 50,772 43,820 Other Postemployment Benefits 80,244 62,020 Other 33,631 32,483 1,008,388 1,081,970 TOTAL FUND EQUITY AND LIABILITIES $ 4,339,108 $ 4,197,499 The accompanying notes to financialstatements are an integral part of these statements.

NERSAPBIC POEDSC 14

Statements of Revenues, Expenses, and Changes in Fund Equity for the years ended December 31, (000's) 2010 2009 Operating Revenues $ 925,141 $ 863,398 Operating Expenses:

Power purchased 111,364 90,934 Production -

Fuel 175,017 168,033 Operation and maintenance 220,348 246,311 Transmission and distribution operation and maintenance 54,296 55,734 Customer service and information 18,058 18,707 Administrative and general 53,220 53,151 Payments to retail communities 21,970 19,965 Decommissioning 27,107 25,764 Depreciation and amortization 119,151 110,729 Payments in lieu of taxes 8,333 7,576 808,864 796,904 Operating Income 116,277 66,494 Non-Operating Income:

Investment income 30,848 30,901 Other income 1,920 959 32,768 31,860 Increase in Fund Equity Before Debt and Other Expenses 149,045 98,354 Non-Operating Expenses:

Interest on long-term debt 93,061 90,161 Allowance for funds used during construction (3,406) (7,706)

Bond premium amortization net of debt issuance expense (2,170) (2,158)

Other expenses 828 1,867 88,313 82,164 Increase in Fund Equity 60,732 16,190 Fund Equity:

Beginning balance 899,866 883,676 Ending balance $ 960,598 $ 899,866 The accompanying notes to financialstatements are an integralpart of these statements.

15NERASK PUBIC POWE DITRC

Statements of Cash Flows for the years ended December 31, (000's) 2010 2009 Cash Flows from Operating Activities:

Receipts from customers and others $ 939,741 $ 862,107 Receipts from FEMA, State of Nebraska and others 1,610 7,136 Payments to suppliers and vendors (414,877) (377,849)

Payments to employees (231,539) (233,435)

Net cash provided by operating activities 294,935 257,959 Cash Flows from Investing Activities:

Proceeds from sales and maturities of investments 997,065 999,173 Purchase of investments (1,048,540) (949,238)

Income received on investments 6,032 8,797 Net cash (used in) provided by investing activities (45,443) 58,732 Cash Flows from Capital and Related Financing Activities:

Proceeds from issuance of bonds 283,636 166,880 Proceeds from issuance of notes 93,451 90,153 Proceeds from repayment of notes receivable 72 73 Capital expenditures for utility plant (251,429) (371,759)

Refurbishment at Kingsley Hydro (3,086) (994)

Principal payments on long-term debt (99,000) (81,235)

Interest payments on long-term debt (93,061) (90,161)

Principal payments on notes (107,265) (70,397)

Interest payments on notes (446) (587)

Funds advanced - Whelan Energy Center 2 - 1,755 Other non-operating revenues 1,920 913 Net cash used in capital and related financing activities (175,208) (355,359)

Net increase (decrease) in cash and cash equivalents 74,284 (38,668)

Cash and cash equivalents, beginning of year 41,379 80,047 Cash and cash equivalents, end of year $ 115,663 $ 41,379 Reconciliation of Operating Income to Cash Provided By Operating Activities:

Operating income $ 116,277 $ 66,494 Adjustments to reconcile operating income to net cash provided (used) by operating activities:

Depreciation and amortization 119,151 110,729 Undistributed net revenue - The Energy Authority (838) 813 Decommissioning, net of customer contributions 27,107 58,391 Amortization of nuclear fuel 49,667 39,485 Changes in assets and liabilities which provided (used) cash:

Receivables, net 1,934 (9,375)

Fossil fuels (9,731) 5,330 Materials and supplies (5,473) (9,166)

Prepayments and other current assets (36) 97 Deferred charges (129) (500)

Accounts payable and accrued payments to retail communities (10,733) 3,821 Deferred revenues 6,952 (9,091)

Other liabilities 787 931 Net cash provided by operating activities $ 294,935 $ 257,959 Supplementary non-cash capital activities:

Utility plant additions in accounts payable $ (5,752) $ (61,581)

The accompanying notes to financial statements are an integralpart of these statements.

PULC NEBRASKA~~ .OIDSTIT1

Supplemental Schedule - Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (000's) 2010 2009 Operating revenues $ 925,141 $ 863,398 Operating expenses (808,864) (796,904)

Operating income 116,277 66,494 Investment and other income 32,768 31,860 Debt and other expenses (88,313) (82,164)

Increase in fund equity 60,732 16,190 Add:

Collections for future debt retirement 34,981 22,231 Debt and related expenses 88,313 82,119 Depreciation and amortization 119,151 110,729 Payments to retail communities* 21,970 19,965 Amortization of current portion of financed nuclear fuel 1,280 -

Amounts collected from TransCanada 113 -

265,808 235,044 Deduct:

Investment income retained in construction funds 1,453 4,040 Unrealized loss on investment securities (1,151) (3,704) 302 336 Fund equity available for debt service under the General Revenue Bond Resolution $ 326,238 $ 250,898 Amounts deposited in the General System Debt Service Account:

Principal $ 99,000 $ 81,235 Interest 89,193 66,899

$ 188,193 $ 148,134 Ratio of fund equity available for debt service to debt service deposits 1.73 1.69

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

The accompanying notes to financialstatements are an integralpart of these statements.

17NERASK PUBIC POWE DISRC

NOTES TO FINANCIAL STATEMENTS

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES:

A. Organization-Nebraska Public Power District (the "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 consisting of 11 members popularly elected from districts comprising subdivisions of the District's chartered territory. The Board of Directors is authorized to establish rates.

B. Basis of Accounting -

Effective July 1, 2009, the Financial Accounting Standards Board ("FASB") issued the FASB Accounting Standards Codification ("ASC"). The ASC became the single source of authoritative nongovernmental Generally Accepted Accounting Principles ("GAAP") recognized by the FASB to be applied for financial statements issued for periods ending after September 15, 2009. The ASC does not change GAAP and does not have an effect on the District's financial position or results of operation. Technical references to GAAP included in this report are provided under the new ASC structure.

The financial statements are prepared in accordance with GAAP and follow accounting guidance provided by the Governmental Accounting Standards Board ("GASB") codification. The District elected the option permitted by GASB Codification Section ("Cod. Sec.") P80, ProprietaryFund Accounting & FinancialReporting to implement all ASC that do not conflict or contradict GASB pronouncements.

The District follows the provisions of ASC Section 980, Regulated Operations ("ASC 980"). In general, ASC 980 permits an entity with cost-based rates to defer certain costs or income that would otherwise be recognized when incurred to the extent that the rate-regulated entity is recovering or expects to recover such amounts in rates charged to its customers.

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 -

Wholesale revenues are recorded in the period in which service is rendered, and retail revenues are recorded in the month retail customers are billed. Consequently, revenues applicable to service rendered to retail customers from the period covered by the last billing in a year to the end of the year are not recorded as revenues until the following year.

The District is required under the General Revenue Bond Resolution (the "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 requireme'nts and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the District's long-term wholesale power supply contracts. The District accounts for any surplus or deficit in revenues for retail service in a similar manner.

The surpluses and deficits from prior years have been accounted for in these financial statements by either a deferral of revenue or costs. During the years ended December 31, 2010 and 2009, the District deferred net revenues of $7.0 million and deferred net costs of $9.1 million, respectively. The cumulative surplus at December 31, 2010, to be reflected in future revenue requirements, is approximately $50.8 million.

NERAK PBIC POE-ISRC 18

E. Depreciation,Amortization, and Maintenance -

The District records depreciation over the estimated useful life of the property primarily on a straight-line basis. The District's electric rates are established based upon debt service and operating fund requirements.

Straight-line depreciation is not considered in the design of rates. As such, the District has provided for depreciation of utility plant funded from debt in its rate setting process by using the debt service principal requirements as the basis for depreciation as opposed to the straight-line basis of depreciation included in the financial statements of the District. Under the methodology employed in establishing rates, the excess of accumulated depreciation expense calculated using the debt service principal approach over the amount calculated using the straight-line method is $55.3 million and $42.1 million for the years ended December 31, 2010 and 2009, respectively. Annual depreciation expense calculated under the debt service principal approach exceeded straight-line depreciation by $13.2 million and $2.0 million for the years ended December 31, 2010 and 2009, respectively. Depreciation expense recorded on a straight-line basis on utility plant was $94.2 million and

$88.2 million for the years ended December 31, 2010 and 2009, respectively. Depreciation on utility plant was approximately 2.5% and 2.4% in each of the years ended December 31, 2010 and 2009, respectively. The District has fully depreciated utility plant that is still in service of $782.3 million and $686.2 million at December 31, 2010 and 2009, respectively, primarily relating to Cooper Nuclear Station ("CNS").

Current rates for electric service provide for a portion of plant additions to be funded from revenues. These plant additions are capitalized and depreciated over their estimated useful life. At December 31, 2010 and 2009,

$532.0 million and $512.2 million, respectively, of net utility plant was funded from revenues. Provision for depreciation of utility plant funded from revenues is computed using the straight-line method.

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 Operating ("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 has recorded provisions, net of retirements, for amortization of these plant additions of $9.9 million in 2010 and $10.4 million in 2009 which is included in depreciation and amortization expense. These plant additions, which are fully depreciated, totaled $153.1 million at December 31, 2010, and

$145.9 million at December 31, 2009.

The District charges maintenance and repairs, including the cost of renewals and replacements of minor items of property, to maintenance expense accounts when incurred. Renewals and replacements of property (exclusive of minor items of property, as set forth above) are charged to utility plant accounts. 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.

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.

G. Fossil Fuel and Materials and Supplies -

The District maintains inventories for fossil fuels, and materials and supplies which are valued at average cost. Due provision is made for slow moving or obsolete items.

H. Nuclear Fuel -

The District had entered into a contract with General Electric for fuel bundle fabrication and related services.

This contract was assigned effective January 2000 by General Electric to Global Nuclear Fuels-Americas. The contract, as amended, provides for these services through 2017. The District amended its existing contract with USEC Inc. extending it through 2013 for various nuclear fuel components including enrichment services. The District has purchased uranium hexafluoride on the spot market for inventory and will pursue additional spot and term contracts for such components as needed. 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.

In December 2009, CNS completed construction of a dry cask used fuel storage facility to support planned license renewal. This facility was primarily funded from decommissioning funds and, as such, the value of the assets in Utility plant in service represents only the amounts that were not funded from decommissioning funds.

19 NE3AK ULCPWRDSRC

I. Unamortized Financing Costs -

These costs represent issuance expenses on all bonds and 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 in accordance with GASB Cod. Sec. D20, Accounting and FinancialReporting for Refundings of Debt Reported by ProprietaryActivities.

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 and is credited to Non-Operating Expenses. 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 taxable commercial paper ("TCP") or tax-exempt commercial paper ("TECP") is charged a rate based upon the projected average interest cost of TCP or TECP outstanding. For the periods presented herein, the AFUDC rates for construction funded by revenue bonds vary from 2.8% to 5.0%. For construction financed on a short-term basis with commercial paper, the rates charged vary from 1.3% to 3.5%.

K. Fund Equity -

Fund equity is made up of three components: Invested in capital assets, net of related debt, Restricted, and Unrestricted.

Invested in capital assets, net of related debt consists 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 includes long-term capacity contracts net of the outstanding balances of any bonds or notes attributable to these assets.

Restricted fund equity consists of the debt service reserve-primary funds that are required deposits under the Resolution and the Decommissioning funds net of any related liabilities.

Unrestricted fund equity consists of any remaining fund equity that does not meet the definition of Invested in capital assets, net of related debt 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 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. Recent Accounting Pronouncements -

ASC 820, Fair Value Measurements and Disclosures("ASC 820"), defines fair value, establishes criteria to be considered when measuring fair value, and expands disclosures about fair value measurements. ASC 820 clarifies that fair value is a market-based measurement that should be based on the assumptions that market participants would use in pricing an asset or liability. ASC 820 does not modify any currently existing accounting pronouncements. The District adopted ASC 820 as of January 1, 2009, for nonfinancial assets and liabilities, and had previously adopted it for financial assets and liabilities. The adoption of ASC 820 did not have a material impact on the District's financial position or results of operation. See Note 4 for additional information.

GASB Cod. Sec. D40, Derivative Instruments ("GASB Cod. Sec. D40") provides accounting and financial reporting guidance to governments for measuring derivative instruments at fair value and specific criteria to determine whether a derivative instrument results in an effective hedge. The District adopted GASB Cod.

Sec. D40 as of January 1, 2010. The adoption of GASB Cod. Sec. D40 did not have a material impact on the District's financial position or results of operation.

NEBASK PBIý POEiIST.2

2. UTILITY PLANT:

Utility plant activity for the year ended December 31, 2010, was as follows (000's):

December 31, December31, 2009 Increases Decreases 2010 Nondepreciable utility plant:

Land and improvements $ 52,323 $ 1,881 $ (729) $ 53,475 Construction in progress 201,324 204,710 (222,085) 183,949 Total nondepreciable utility plant 253,647 206,591 (222,814) 237,424 Nuclear fuel* 195,535 42,867 (49,667) 188,735 Depreciable utility plant:

Generation - Fossil 1,438,541 58,599 (15,944) 1,481,196 Generation - Nuclear 1,106,990 43,619 (3,584) 1,147,025 Transmission 899,329 63,438 (10,811) 951,956 Distribution 182,873 11,179 (2,856) 191,196 General 268,774 43,717 (9,162) 303,329 Total depreciable utility plant 3,896,507 220,552 (42,357) 4,074,702 Less reserve for depreciation (2,110,620) (113,991) 42,357 (2,182,254)

Depreciable utility plant, net 1,785,887 106,561 1,892,448 Utility plant activity, net $ 2,235,069 $ 356,019 $ (272,481) $ 2,318,607

• Nuclear fuel decreases represent amortization of $49.7 million.

The 2011 construction plan includes authorization for future expenditures of $330.7 million. These expenditures will be funded from existing bond proceeds, revenues, other available funds, and additional financings as deemed appropriate.

3. CASH AND INVESTMENTS:

The District follows GASB Cod. Sec. In5, Investment Pools (External) ("GASB Cod. Sec. In5"). GASB Cod.

Sec. In5 requires the District's investments to be 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 Fund Equity. The District had an unrealized net loss of $1.4 million as of December 31, 2010, and an unrealized net gain of $1.5 million as of December 31, 2009. Included in these amounts are an unrealized net loss on decommissioning funds of $0.2 million as of December31, 2010 and an unrealized net gain on decommissioning funds of $5.2 million as of December 31, 2009.

Cash deposits, primarily interest bearing, are covered by federal depository insurance or pledged collateral of U.S. Government securities held by various depositories. Investments were in U.S. Government securities and Federal Agency obligations held in the District's name by the custodial banks. Cash and investments totaled

$1,059.0 million and $907.2 million at December 31, 2010 and 2009, respectively.

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

2010 2009 U.S. Treasury and government agency securities $ 712,340 $ 672,165 Corporate bonds 160,550 143,786 Municipal bonds 15,613 8,657 Certificates of deposit 1,014 1,263 Cash and money market mutual funds 169,440 81,342 Total cash and investments $ 1,058,957 $ 907,213

)21 NEBRA~SK PULI POE ISRC

The fair value of the District's Special Purpose Funds as of December 31 are 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.

2010 2009 Construction funds - Investments $ 286,997 $ 203,009 The Debt reserve fund, as established under the Resolution, consists 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 $50.2 million and

$46.4 million as of December 31, 2010 and 2009, 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 of Directors. Such account totaled $51.7 million and $52.1 million as of December 31, 2010 and 2009, respectively.

2010 2009 Debt reserve fund - Cash and cash equivalents $ 17 $ 210 Debt reserve fund - Investments 101,925 98,283

$ 101,942 $ 98,493 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 retired employee life insurance benefit plan was funded prior to the adoption of GASB Cod. Sec. P50, Postemployment Benefits Other Than Pension Benefits - Employer Reporting ("GASB Cod. Sec. P50") and creation of an irrevocable grantor trust for postretirement health and life insurance benefits. For additional information on postemployment benefits see Note 15. The plan had contributed funds of $7.5 million and $5.0 million at December 31, 2010 and 2009, respectively. The District pays the total cost of the employee life insurance benefit once the employee retires. The plan had contributed funds of

$1.9 million and $2.0 million at December 31, 2010 and 2009, respectively. Both funds are held by outside trustees in compliance with the funding plans approved by the District's Board of Directors.

2010 2009 Employee benefit fund - Cash and cash equivalents $ 2,433 $ 3,167 Employee benefit fund - Investments 6,982 3,844

$ 9,415 $ 7,011 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 District's Board of Directors which are invested primarily in fixed income governmental securities.

2010 2009 Decommissioning funds $ 484,130 $ 458,984

4. FAIR VALUE OF FINANCIAL INSTRUMENTS:

As defined in ASC 820, 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, 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 currently does not have Level 1 assets and liabilities included in the Decommissioning funds, other Special Purpose Funds, or Investments in Current Assets.

NEBASK PULI POEDSRC 22

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. The District's investment in cash and money market mutual funds are excluded from the ASC 820 fair value hierarchy.

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, (in 000's):

December 31, 2010 Level 1 Level 2 Level 3 Total Assets:

Available-for-sale securities:

U.S. Treasury and government agency securities $ - $ 444,939 $ - $ 444,939 Certificates of deposit - 1,014 - 1,014 Decommissioning funds:

U.S. Treasury and government agency securities - 267,401 - 267,401 Corporate bonds - 160,550 - 160,550 Municipal bonds - 15,613 - 15,613

$ - $ 889,517 $ - $ 889,517 December 31, 2009 Level 1 Level 2 Level 3 Total Assets:

Available-for-sale securities:

U.S. Treasury and government agency securities $ - $ 396,902 $ - $ 396,902 Certificates of deposit - 1,263 - 1,263 Decommissioning funds:

U.S. Treasury and government agency securities - 275,262 - 275,262 Corporate bonds - 143,786 - 143,786 Municipal bonds - 8,657 - 8,657

$ - $ 825,870 $ - $ 825,870 Decommissioning funds reflect the assets held in trust to cover general decommissioning costs and consist primarily of fixed income governmental securities.

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 23 NEBRASK PB ICPOE.ISRC

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 $7.6 million in 2010 and $3.0 million in 2009. The unamortized amount of the plant capacity contract was $174.8 million and $179.4 million as of December 31, 2010 and 2009, respectively, of which $4.6 million was included in Prepayments and other current assets as of December 31, 2010 and 2009. The costs of the transmission facilities are being returned to the District in the form of a credit on the District's monthly transmission bill from OPPD. Accumulated credits were $5.7 million in 2010 and $2.2 million in 2009. The remaining transmission credits were $10.1 million and $13.6 million as of December 31, 2010 and 2009, respectively, of which $3.3 million was included in Prepayments and other current assets as of December 31, 2010 and 2009.

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 $50.4 million in 2010 and $48.2 million in 2009. The unamortized amount of the Central capacity contract was $36.3 million and $35.4 million as of December 31, 2010 and 2009, respectively, of which $2.3 million and $2.1 million was included in Prepayments and other current assets as of December 31, 2010 and 2009, respectively.

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 $1.4 million and $1.1 million in 2010 and 2009, respectively, are included in Power purchased in the accompanying Statements of Revenues, Expenses, and Changes in Fund Equity.

6. DEFERRED SETTLEMENT CHARGES:

The District deferred the cost of a $39.1 million payment to MidAmerican Energy Company ("MEC") in 2002 in conjunction with the settlement of litigation with respect to the operation of CNS. The deferred costs of the MEC payment will be recognized as expense in future rate periods when such costs are included in the revenue requirements used to establish electric rates. The balance of such deferral was $14.9 million and $19.5 million as of December 31, 2010 and 2009, respectively, of which $4.7 million and $4.5 million was included in Prepayments and other current assets as of December 31, 2010 and 2009, respectively.

7. INVESTMENT IN THE ENERGY AUTHORITY:

The District is a member of The Energy Authority ("TEA"), a power marketing corporation. TEA assumes the wholesale power marketing responsibilities of its members with each member having ownership in the joint venture. TEA has access to approximately 25,000 megawatts of its members' and partners' generation located across the nation. TEA also provides its members with natural gas procurement or contract management services for gas used in the generation of electricity and for local distribution. TEA provides the District with gas contract management services.

The table below contains the condensed financial information for TEA as of December 31, (000's):

Condensed Balance Sheet 2010 2009 Current Assets $ 139,924 $ 104,901 Noncurrent and Restricted Assets 25,787 20,649 Total Assets $ 165,711 $ 125,550 Current Liabilities $ 113,452 $ 85,266 Noncurrent Liabilities 5,359 3,101 Net Assets 46,900 37,183 Total Liabilities and Net Assets $ 165,711 $ 125,550 Condensed Statement of Operations Revenues $ 947,153 $ 939,940 Energy Costs (824,094) (860,171)

Gross Profit 123,059 79,769 Operating Expenses (35,131) (31,786)

Operating Income 87,928 47,983 Non-Operating Income 415 1,093 Increase in Net Assets $ 88,343 $ 49,076 NERAK PUBLI POýRISC 24

The District had a 20.0% and 21.4% ownership interest in TEA as of December31, 2010 and 2009, respectively. The decrease in ownership interest is due to the addition of a new TEA member in 2010. All of TEA's revenues and costs are allocated to the members. TEA's net revenues are allocated among the members based upon a combination of each respective member's purchased power and power sales transactions and natural gas transactions with TEA and each member's ownership interest.

The following table summarizes the transactions applicable. to the District's investment in TEA as of December 31, (000's):

2010 2009 Beginning Balance $ 6,776 $ 7,589 Reduction to power costs and increase in electric revenues 32,300 22,720 Distributions from TEA (26,791) (19,120)

Other expenses (4,671) (4,413)

Ending Balance $ 7,614 $ 6,776 The District's power purchases and sales with TEA are reflected in the Statements of Revenues, Expenses, and Changes in Fund Equity as Power purchased, and Operating Revenues, respectively. For the years ended December 31, 2010 and 2009, the District recorded Operating Revenues of $66.6 million and $29.6 million, respectively, and Power purchased expenses of $2.6 million and $5.9 million, respectively.

At December 31, 2010 and 2009, $8.3 million and $4.9 million due from TEA was included in Receivables and

$0.5 million and $2.6 million due to TEA was included in Accounts payable, respectively.

As of December 31, 2010, 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 capital investment in TEA, any accounts receivable from TEA, and trade guarantees provided to TEA by the District. These guarantees are within the scope of ASC 460, Guarantees.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.

As of December 31, 2010 and 2009, the District has not recorded a liability related to these guaranties.

8. REVENUE BONDS:

In September 2010, the District issued General Revenue Bonds, 2010 Series A and 2010 Series C, in the amount of $114.1 million and $147.1 million, respectively, to finance $164.8 million of the costs of certain generation, transmission, and distribution capital additions, to refund $77.6 million of TCP notes, and to refund

$16.8 million of TECPnotes. Also in September2010, the District issued General Revenue Bonds, 2010 Series B, in the amount of $8.4 million to refund $8.2 million of TCP notes.

In June 2009, the District issued General Revenue Bonds, 2009 Series A and 2009 Series C, in the amount of

$50.4 million and $17.9 million, respectively, to finance certain generation and other transmission capital additions. Also in June 2009, the District issued General Revenue Bonds, 2009 Series B, in the amount of

$100.0 million to advance refund $69.5 million of TCP notes and to provide $28.4 million for certain capital additions at CNS.

~

25 ~ ~ NERAK ~

• PBIC OE DISRC

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

December 31, Interest Rate 2010 2009 General Revenue Bonds:

1999 Series A Serial Bonds 2010-2011 4.70% - 5.00% $ 165 $ 715 2002 Series B:

Serial Bonds 2010-2025 5.00% 43,030 48,505 Term Bonds 2026-2032 5.00% 22,885 22,885 2003 Series A:

Serial Bonds 2010-2026 3.50% - 5.00% 91,900 95,945 Term Bonds 2027-2034 5.00% 86,095 86,095 2004 Series B Serial Bonds 2010-2013 4.25% - 5.00% 117,395 149,030 2005 Series A Serial Bonds 2010-2025 3.00% - 5.25% 85,105 88,985 2005 Series B-1 Serial Bonds 2010-2015 5.00% 65,570 75,335 2005 Series B-2 Serial Bonds 2010-2016 4.00% - 5.00% 52,815 62,225 2005 Series C:

Serial Bonds 2010-2025, 2040 3.50% - 5.125% 73,030 74,385 Term Bonds 2026-2029 5.00% 11,765 11,765 2030-2034 4.75% 18,240 18,240 2035-2040 5.00% 27,500 27,500 2006 Series A:

Serial Bonds 2010-2025 3.75% - 5.00% 73,855 76,535 Term Bonds 2026-2030 5.00% 18,680 18,680 2031-2035 5.00% 23,840 23,840 2036-2040 4.375% 400 400 2036-2040 5.00% 30,020 30,020 2007 Series B:

Serial Bonds 2010-2026 4.00% - 5.00% 222,795 241,890 Term Bonds 2027-2031 4.65% 36,140 36,140 2032-2036 5.00% 19,270 19,270 2008 Series A Taxable Term Bonds 2013 5.14% 137,765 137,765 2008 Series B:

Serial Bonds 2010-2029 3.00% - 5.00% 230,790 238,815 Term Bonds 2030-2032 5.00% 32,390 32,390 2033-2037 5.00% 50,880 50,880 2038-2040 5.00% 7,180 7,180 2009 Series A Taxable Build America Bonds:

Term Bonds 2019-2025 6.606% 17,465 17,465 2026-2034 7.399% 32,890 32,890 2009 Series B Taxable:

Term Bonds 2012 4.135% 29,180 29,180 2013 4.85% 70,820 70,820 2009 Series C Serial Bonds 2010-2019 2.00% - 4.25% 15,585 17,245 2010 Series A Taxable Build America Bonds:

Serial Bonds 2019-2024 3.98% - 4.73% 31,875 Term Bonds 2025-2029 5.323% 27,985 2030-2042 5.423% 54,190 2010 Series B Taxable Serial Bonds 2010-2020 1.03% - 4.18% 8,220 2010 Series C:

Serial Bonds 2010-2025 1.00% - 5.00% 125,475 Term Bonds 2026-2030 4.00% 6,165 2026-2030 5.00% 14,180 Total par amount of revenue bonds 2,013,530 1,843,015 Unamortized premium net of discount 41,343 29,347 2,054,873 1,872,362 Less - current maturities of revenue bonds (111,145) (97,575)

Total revenue bonds S 1.943.728 $ 1.774.787 NEBRASK PULI POERbSTRT2

Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2010, are as follows (000's):

Debt Service Principal Year Payments Payments 2011 $ 209,977 $ 111,145 2012 241,869 148,215 2013 393,622 306,800 2014 168,623 96,885 2015 148,964 81,830 2016-2020 631,317 351,750 2021-2025 517,046 .315,895 2026-2030 401,491 277,645 2031-2035 271,179 211,685 2036-2040 118,905 101,675 2041-2042 10,824 10,005 Total Payments $3,113,817 $ 2,013,530 The fair value of outstanding revenue bonds is determined using currently published rates. The fair value is estimated to be $2,072.8 million and $1,941.1 million at December 31, 2010 and 2009, respectively.

9. COMMERCIAL PAPER NOTES:

The District is authorized to issue up to $200.0 million of TCP notes and up to $150.0 million of TECP notes.

A $200.0 million credit agreement and a $150.0 million credit agreement, each expiring August 1, 2011, are maintained with several banks to support the sale of the TCP notes and TECP notes, respectively. The District had $98.9 million and $117.2 million of TCP notes outstanding at December 31, 2010 and 2009, respectively. The proceeds of the TCP notes have been used to purchase nuclear fuel and to fund capital projects at CNS. The District had $122.0 million and $117.0 million of TECP notes outstanding at December 31, 2010 and 2009, 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 TCP notes for 2010 and 2009 were 0.4% and 0.9%, respectively. The effective interest rates on outstanding TECP notes for 2010 and 2009 were 0.3% and 0.6%, respectively.

The $98.9 million of TCP notes and the $122.0 million of TECP notes outstanding at December 31, 2010, are anticipated to be retired by future collections through electric rates and issuance of revenue bonds. The carrying value of the commercial paper notes approximates market value due to the short-term nature of the notes.

The District anticipates renewing the TECP credit agreement prior to its August 2011 expiration. The District does not plan to renew the TCP credit agreement.

10. LINE OF CREDIT AGREEMENTS:

The District has two separate line of credit agreements of $200.0 million and $150.0 million that support the payment of the principal outstanding of the TCP notes and TECP notes, respectively. See Note 9 for additional information. At December 31, 2010 and 2009, no amounts have been drawn on either line of credit.

11. LONG-TERM DEBT:

Long-term debt activity, net of current activity for the year ended December 31, 2010, was as follows (000's):

Principal Amounts December 31, December 31, Due Within 2009 Increases Decreases 2010 One Year Revenue bonds $ 1,774,787 $ 289,136 $ (120,195) $ 1,943,728 $ 111,145 Commercial paper notes 234,234 1,040,060 (1,053,422) 220,872 220,872 Total long-term debt activity $ 2,009,021 $ 1,329,196 $(1,173,617) $ 2,164,600 $ 332,017 27NEBRASKA PBIC POWE DITRC

12. ASSET RETIREMENT OBLIGATION:

The District has recorded an obligation for the fair value of its legal liability for asset retirement obligations 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. In 2010, the District reevaluated its asset retirement obligation ("ARO") associated with CNS after receiving approval from the Nuclear Regulatory Commission ("NRC") to extend its operating license by 20 years. As a result, an adjustment to decrease the ARO by $145.6 million was made primarily related to changes to timing of decommissioning of CNS.

The total asset retirement obligation liability recorded by the District was $843.7 million and $943.6 million as of December 31, 2010 and 2009, respectively, and is included in the Deferred Credits and Other Liabilities section of the accompanying Balance Sheets.

The following table shows costs as of January 1, and charges to the ARO that occurred during the years ended December 31, 2010 and 2009, and are included in Deferred Credits and Other Liabilities on the balance sheet as of December 31, (000's):

For the Year Ended December 31, 2010 2009 Balance, beginning of year $ 943,647 $ 896,739 Accretion 45,735 46,908 ARO adjustment (145,641) --

Balance, end of year $ 843,741 $ 943,647 A significant amount of the ARO is funded by decommissioning funds of $484.1 million and $459.0 million as of December 31, 2010 and 2009, respectively. See Note 3 for additional information.

At the time the liability for the asset retirement is incurred, ASC 410 requires capitalization of the costs to the related asset. For asset retirement obligations 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 $45.7 million and $46.9 million for 2010 and 2009, respectively.

13. 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 $8.3 million and $7.6 million for the years ended December 31, 2010 and 2009, respectively.

14. 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 of the District. At December 31, 2010, there were 2,235 Plan members. Plan members are required to 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 District's Board of Directors. The District's contribution was

$12.1 million for 2010 and 2009 of which $1.2 million was accrued and in Accounts payable for each of the years ended December 31, 2010 and 2009.

NEBASA U6IC POI !DSRT2

15. POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS:

A. Plan Description -

The District administers a single-employer defined benefit healthcare plan that provides lifetime healthcare insurance for eligible retirees and their spouses. Eligibility and benefit provisions are established by the District's Board of Directors. In addition, the District provides employees a $5,000 death benefit when they retire and substantially all of the District's retired and active employees are eligible for such benefit.

B. Funding Policy -

The eligibility and contributions of the plan members and the funding policy of the plan is established and may be amended by the District's Board of Directors. The District, for employees hired on or prior to December 31, 1992, pays all or part of the cost (determined by retirement age) of certain hospital-medical premiums when these employees retire. The District amended the plan effective January 1, 1993. Employees hired on or after January 1, 1993, are subject to a contribution cap that limits the District's portion of the cost of such coverage to the full premium the year the employee 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 would be paid by the retired employee. The District amended the plan effective January 1, 1999.

Employees hired on or after January 1, 1999, are not eligible for postretirement hospital-medical benefits once they reach age 65 or Medicare eligibility. The District amended the plan effective January 1, 2004, to provide that employees hired on or after that date will not be eligible for postretirement hospital-medical benefits once they retire. The District amended the plan effective July 1, 2007, to provide that any former employee who is rehired will receive credit for prior years of service. The District further amended the plan effective September 1, 2007, to provide that employees hired or rehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for postretirement hospital-medical benefits once they retire.

C. Annual OPEB Cost and Net OPEB Obligation-The District's annual Other Postemployment Benefits ("OPEB") cost (expense) is calculated based on the annual required contribution ("ARC"), an amount actuarially determined in accordance with the parameters of GASB Cod. Sec. P50. The ARC represents a level of funding that, if paid on an ongoing basis, is projected to cover the normal cost each year (or benefits earned in the current year) and amortize any unfunded actuarial liabilities (or funding excess) over a period not to exceed 30 years. The following table shows the components of the District's OPEB cost for the year, the amount actually contributed to the plan, and changes in the District's net OPEB obligation as of December 31, (000's):

For the Year Ended December 31, 2010 2009 2008 Annual required contribution $ 30,932 $ 33,143 $ 30,531 Interest on net OPEB obligation 3,566 2,369 1,326 Adjustment to annual required contribution (2,992) (3,536) (1,052)

Annual OPEB cost 31,506 31,976 30,805 Contributions made (13,282) (11,156) (12,662)

Increase in net OPEB obligation 18,224 20,820 18,143 Net OPEB obligation - beginning of year 62,020 41,200 23,057 Net OPEB obligation - end of year $ 80,244 $ 62,020 $ 41,200 The District's annual OPEB cost, the percentage of annual OPEB cost contributed to the plan, and the net OPEB obligation for 2010, 2009, and 2008 were as follows (dollar amounts in thousands):

Annual Percentage of Annual Net OPEB Year OPEB Cost OPEB Cost Contributed Obligation 2010 $ 31,506 42.2% $ 80,244 2009 $ 31,976 34.9% $ 62,020 2008 $ 30,805 41.1% $ 41,200 NERAK PB IC POWE DISRC

D. Funded Status and Funding Progress-In 2008, the District established an irrevocable trust to begin funding the unamortized OPEB obligation. Total contributions to the plan in 2010 were $13.3 million which included $4.0 million paid to the trust and $9.3 million for the cost of benefits. Total contributions to the plan in 2009 were $11.2 million which included $4.0 million paid to the trust and $7.2 million for the cost of benefits. Total contributions to the plan in 2008 were $12.7 million which included $4.0 million paid to the trust and $8.7 million for the cost of benefits. It is currently projected that funding above the pay-as-you-go amount will remain at $4.0 million through 2017 and increase to $10.0 million in 2018. The final funding will be determined annually by the District's Board of Directors. The trust is currently projected to be fully funded by 2033.

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

The AAL was $404.6 million, $415.2 million, and $390.1 million as of January 1, 2010, 2009, and 2008, respectively. The AAL is presented in the table below based on the actuarial valuation as of January 1, (000's):

Actuarial Unfunded Actuarial UAAL to Actuarial Value Accrued Liability Accrued Liability Funded Covered Covered of Assets (AAL) (UAAL) Ratio Payroll Payroll (a) (b) (b-a) (a/b) (c) ((b-a)/c) 2010 $ 10,147 $ 404,646 $ 394,498 2.5% $ 182,315 216%

2009 $ 6,268 $ 415,243 $ 408,975 1.5% $ 185,200 221%

2008 $ 1,964 $ 390,074 $ 388,110 0.5% $ 177,000 219%

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.

E. 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 of 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.

In the January 1, 2010 actuarial valuation, which is the most recent actuarial study, the Unit Credit Actuarial Cost method was used for 2010, 2009, and 2008. In 2010, the actuarial assumptions included an annual healthcare cost trend rate of 7.7% initially, reduced by decrements to an ultimate rate of 4.4%. In 2009, the actuarial assumptions included an annual healthcare cost trend rate of 8.3% initially, reduced by decrements to an ultimate rate of 4.6%. In 2008, the actuarial assumptions included an annual healthcare cost trend rate of 8.9%

initially, reduced by decrements to an ultimate rate of 4.6%. The discount rate used for all three years was 5.75%

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 also 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 assuming 4.0% payroll growth was used for all three years.

F. Market Value of Plan Investments -

The actuarial valuation of plan assets was based on market values as of January 1, 2010. The investments in the OPEB plan include corporate and government debt, foreign and domestic stocks, mutual funds and cash. The market value of plan assets at December 31, 2010, was $15.3 million.

16. COMMITMENTS AND CONTINGENCIES:

A. Fuel Commitments -

The District has various coal supply contracts and a coal transportation contract with minimum future payments of $168.9 million. The coal supply contracts expire at various times through the end of 2013. The coal transportation contract expires at the end of 2011 and is subject to price escalation adjustments.

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B. Power Purchaseand Sales Agreements -

The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately $37.7 million. These purchases are subject to rate changes.

Effective January 2004, the District entered into a participation power agreement (the "NC2 Agreement") with OPPD to receive 23.7% of the output of NC2, estimated to be 162 MW of the power from the 682 MW coal-fired power plant constructed by OPPD. NC2 began commercial operation on May 1, 2009. OPPD will retain 50.0% of the output for its own use and has entered into similar participation power sales agreements with other power purchasers. The District's obligation under the NC2 Agreement to make payments is an unconditional "take-or-pay" obligation, obligating the District to make such payments whether or not NC2 or any part thereof is completed, delayed, terminated, available, operable, operating, or retired. 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 160.0% of its original participation share (23.7%).

The District has entered into a power purchase agreement with Central Public Power & Irrigation District

("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 hydro power purchase agreement with Central through December 31, 2013 for the purchase of the net power and energy produced by three hydroelectric plants (excludes the Kingsley Project) owned and operated by Central. Accredited capacity of the three hydroelectric plants is 54 MW.

The District had a power sales contract with MEC for 250 MW for a term beginning January 1, 2005, and ending on December 31, 2009. The power sales contract was for the delivery of 250 MW of the accredited capacity and associated energy from CNS at prices as set forth in the contract. This contract was not renewed.

The District has entered into power sales agreements with Lincoln Electric System ("LES") for the sale to LES of 30% of the net power and energy of Sheldon Station ("Sheldon") and 8% of the net power and energy of Gerald Gentleman Station ("GGS"). In return, LES agrees to pay 30% and 8% of all costs attributable to Sheldon and GGS, respectively. Each agreement is to terminate upon the later of the last maturity of the debt attributable to the respective station or the date on which the District retires such station from commercial operation.

The District has entered into a power sales agreement with KCP&L for the sale to KCP&L of 100 MW of the power and energy from GGS through May 31, 2011.

The District has entered into a participation power sales agreement with KCP&L for the sale to KCP&L of 75 MW of accredited capacity from CNS through January 18, 2014.

The District has a participation power sales agreement with Heartland Consumers Power District

("Heartland") for the sale to Heartland of 45 MW of accredited capacity from CNS through December 31, 2013.

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 GGS and CNS of 95 MW from July 1, 2008 through December 31, 2010, as amended, and 45 MW from January 1, 2011 through the last day of the month prior to the commercial operation of the Whelan Energy Center 2 ("WEC2") fossil plant. MEAN has an ownership interest in WEC2, a 220 MW coal-fired power plant, and it is expected to begin commercial operation in May 2011.

The District has also entered into a participation power sales agreement with MEAN for the sale to MEAN of the power and energy from GGS and CNS of 50 MW from January 1, 2011 through December 31, 2023.

The District has entered into participation power agreements with OPPD, MEAN, JEA (formerly the Jacksonville Electric Authority) and Grand Island Utilities for the sale of power from the 60 MW Ainsworth Wind Energy Facility. The participation power agreements are each for a term of 20 years and in the following amounts: OPPD for 16.8%; MEAN for 11.8%; JEA for 16.8%; and Grand Island Utilities for 1.7%.

The District has entered into power sales agreements with OPPD, MEAN, LES, and Grand Island Utilities for the sale of power from the 80 MW Elkhorn Ridge Wind Facility. The power sales agreements are each for a term of 20 years and in the following amounts: OPPD for 31.3%; MEAN for 10.0%; LES for 7.5%; and Grand Island Utilities for 1.3%.

The District has entered into power sales agreements with LES, MEAN, and Grand Island Utilities for the sale of power from the 80 MW Laredo Ridge Wind Facility. The power sales agreements are each for a term of 20 years and in the following amounts: LES for 12.5%; MEAN for 10.0%; and Grand Island Utilities for 1.3%.

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The District has 20-year wholesale power contracts, with a term that expires December 31, 2021, with the majority of its firm requirements wholesale customers 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 10.0% per year with at least three years advance notice. On March 16, 2011, the District received notice from the City of Neligh stating that they desire to terminate their wholesale power contract effective April 1, 2012. The City of Neligh is among the few firm requirements wholesale customers who do not have wholesale power contracts with the previously described 20-year term.

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 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. TransmissionAgreements -

On April 1, 2009, the District became a member of the Southwest Power Pool ("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 will be 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.

The District entered into a WEC2 Transmission Facilities Agreement effective August 13, 2007, with the Public Power Generation Agency ("PPGA") and the City of Hastings, Nebraska. 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 WEC2 to the District's transmission system. Estimated cost of the project is $11.8 million and is to be paid by PPGA. As of December 31, 2010, PPGA had advanced all required payments to the District. These advance payments are prepaid transmission service on the District's transmission system for delivery of the Participant's Participation Power.

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 is

$8.4 million and repayment by Keystone, over a ten-year period, began in July 2010 with a remaining balance due the District of $8.3 million as of December 31, 2010.

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. Estimated cost of the project is $52.9 million and is to be paid by Keystone XL over a ten-year period anticipated to begin in July 2013. As of December 31, 2010, actual project costs totaled $2.4 million.

D. CooperNuclear Station -

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 $117.5 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation, with a maximum assessment of $17.5 million per year per incident per unit owned. To satisfy this potential obligation, the District has submitted its most recent audited financial statements to the NRC.

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. CNS is currently 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 third quarter of 2009.

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 NEBASKTBIC POE DIfRIT3

fees were $17.2 million and $14.0 million for 2010 and 2009, respectively. In 2011, the annual management fee is

$17.3 million. Since 2007, Entergy has been eligible to earn additional annual incentive fees in an amount not to exceed $6.0 million annually if CNS achieved identified safety and regulatory performance targets. As part of the amended agreement effective January 1, 2010, the annual incentive fee was reduced to $4.0 million. Also, as part of the agreement amendment, the overall compensation to Entergy under the support services agreement was restructured such that certain private use issues that existed with the original agreement were eliminated.

In December 2009, CNS completed construction of a dry cask used fuel storage facility to support planned license renewal. The first loading campaign to move used nuclear fuel from the used fuel pool into eight dry used fuel storage casks for on-site storage commenced in October 2010 and was completed in January 2011.

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.

As part of a 1989 settlement of various disputed matters between General Electric Company ("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. On March 17, 2011, the District offered to settle its litigation against the DOE for spent nuclear fuel disposal damages in exchange for the payment of approximately $60.6 million representing costs incurred for the on-site storage of spent nuclear fuel at CNS through December 31, 2009, along with subsequent claims pursuant to the provisions of the settlement agreement. The District anticipates a response from the DOE in April 2011.

E. Environmental-As part of Environmental Protection Agency's ("EPA") nationwide investigation and enforcement program for coal-fired power plants' compliance with 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 GGS and Sheldon. 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 GGS and Sheldon, 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 GGS and Sheldon. The District provided a response to the new request within the time allowed and provided supplemental information to the EPA in February 2011 in response to an EPA e-mail inquiry. In a transmittal letter dated December 8, 2008, EPA Region 7 issued a Notice of Violation under Section 11 3(a)(1) of the Clean Air Act

("NOV") alleging violations of pre-construction permitting requirements of the Clean Air Act and the Nebraska State Implementation Plan for five projects undertaken from 1991 through 2001 at GGS. Since receiving the NOV, the District has met twice with the government to discuss the NOV and possible future actions. No further meetings are scheduled. In the event the government pursues litigation based on the NOV and there is a court judgment finding the District violated Clean Air Act requirements, if upheld after appellate court review, it can result in the requirement to install expensive air pollution control equipment that is the best available control technology and the imposition of monetary penalties. The District is unable to predict what future costs may be incurred with respect to the NOV.

On March 16, 2011, the EPA issued a proposed "Mercury/Utility Boiler MACT" rule that would require reduction of emissions of toxic air pollutants from power plants. The proposed rule is expected to be finalized in November 2011. Specifically, the proposed rule would require reductions in emissions from new and existing coal- and oil-fired steam utility electric generating units. The proposed rule would require reduced emissions of heavy metals, including mercury, arsenic, chromium, and nickel, dioxins, furans, and a6id gases, including hydrogen chloride and hydrogen fluoride. These toxic air pollutants are also known as hazardous air pollutants.

Facilities would have three years after the rule becomes effective to comply with the rule. Upon request, an additional one-year extension for compliance could possibly be granted if technology necessary to reduce the 33 NEBRASKAS PBIC POEISRC

emissions cannot be installed within the three years. The proposed rule is being analyzed and it is unknown what the impacts to the District will be until the rule is finalized.

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 VII in October 2002 to discuss the site. No other 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 of Directors meeting. Phase I of the EE/CA work began at the site in November 2007. The current schedule indicates that the EE/CA should be completed in 2011. The District is unable to predict what future costs may be incurred with respect to MGP.

17. 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, 2010.

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