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{{Adams
#REDIRECT [[NLS2014062, Licensee Guarantees of Payment of Deferred Premiums]]
| number = ML14195A001
| issue date = 07/02/2014
| title = Licensee Guarantees of Payment of Deferred Premiums
| author name = VanDerkamp D W
| author affiliation = Nebraska Public Power District (NPPD)
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000298
| license number = DPR-046
| contact person =
| case reference number = NLS2014062
| document type = Financial Assurance Document, Letter
| page count = 43
}}
 
=Text=
{{#Wiki_filter:H Nebraska Public Power District Always there when you need us NLS2014062 140.21 July 2, 2014 Attention:
Document Control Desk U. S. Nuclear Regulatory Commission Washington, D.C. 20555-0001
 
==Subject:==
Licensee Guarantees of Payment of Deferred Premiums Cooper Nuclear Station, Docket No. 50-298, DPR-46
 
==Dear Sir or Madam:==
The purpose of this letter is to transmit information in accordance with the requirements of 10 CFR Part 140.21, relative to deferred insurance premiums, for the Nebraska Public Power District (NPPD). NPPD believes this information demonstrates our ability to obtain funds in the amount of $19 million for payment of such premiums within the specified three-month period.To demonstrate the ability to provide funds in the required amount for such deferred insurance premiums, NPPD's 2013 Financial Report is enclosed for your review. This report is NPPD's audited financial statement.
Please refer to Page 15 of the enclosure where the Balance Sheet of NPPD is listed. Cash and investments of NPPD total over $1 billion as indicated on Pages 22-23, Note 3 of the enclosure.
Liquidity can be provided by unrestricted cash and investments, and through reserve and special purpose funds that, with the, approval of the NPPD Board of Directors, can be utilized for any lawful purpose. The portion of cash and investments that can be utilized to provide such liquidity for the payment of the subject deferred premiums is $444.1 million as of December 31, 2013.Also on Page 15 of the enclosure, under the heading "Long-Term Debt," there is a line item titled "Commercial paper notes and revolving credit agreements" in the amount of $149.4 million. As noted on Page 29, Note 9 and Note 11 of the enclosure, NPPD is authorized to issue up to $150 million of tax-exempt commercial paper notes (TECP), and an aggregate of $200 million of the Revolving Credit Agreements.
As of December 31, 2013, NPPD had $47.7 million remaining capacity in its TECP program, and $50.6 million remaining capacity of the Revolving Credit Agreements, for a total of $98.3 million, which is available to fund the payment of the subject deferred premiums.It is NPPD's intent to continue to publish this report on an annual calendar year basis. A subsequent report, covering financial information for calendar year 2014, will be submitted no later than July 31, 2015.COOPER NUCLEAR STATION J..A Q..i I P.O. Box 98 / Brownville, NE 68321-0098 Telephone:
(402) 825-3811 / Fax: (402) 825-5211 www.nppd.com NLS2014062 Page 2 of 2 This letter contains no new commitments.
Should you have questions, or require additional information, please contact me at (402) 825-2904.Sincerely, David W. Van Der Kamp Licensing Manager Jo
 
==Enclosure:==
 
Nebraska Public Power District 2013 Financial Report cc: Regional Administrator w/enclosure USNRC -Region IV Cooper Project Manager w/enclosure USNRC -NRR Project Directorate IV-1 Senior Resident Inspector w/o enclosure USNRC -CNS NPG Distribution w/o enclosure D. K. Starzec w/o enclosure D. M. Blatchford w/o enclosure CNS Records w/enclosure NLS2014062 Enclosure ENCLOSURE NEBRASKA PUBLIC POWER DISTRICT 2013 FINANCIAL REPORT COOPER NUCLEAR STATION DOCKET NO. 50-298, DPR-46 S.j Statistical Review I Management's Discussion and Analysis 2 Report of Independent Auditors 14 Financial Statements 15 Notes to Financial Statements 19 20 3 Y AR- A A G ANC KILOWATT-HOUR SALES OPERATING REVENUES COST OF POWER PURCHASED AND GENERATED OTHER OPERATING EXPENSES INCREASE IN NET POSITION DEBT SERVICE COVERAGE 20.8 BILLION 1,106.3 MILLION 614.1 MILLION 327.8 MILLION 97.4 MILLION 1.73 2013 STATISTICAL REVIEW Average Electric Energy Number of MWh Sales Customers Amount %Revenues from Electric Sales (000's)Amount %Revenue Per kWh SALES Retail: Residential 68,775 Rural and Farm 3,159 Commercial 15,223 Industrial 57 Public Lighting 194 Municipal Power 184 Miscellaneous Municipal 2,012 Total Retail Sales 89,604 Wholesale:
51 Municipalities (Total Requirements) 25 Public Power Districts and Cooperatives (Total Requirements)
Total Wholesale Sales (Excluding Sales to LES and Other Utilities)
Total Retail and Wholesale Sales (Excluding Sales to LES and Other Utilities)
Nonfirm Sales LES" 1'Other Utilities 829,141 4.0 $ 103,674 9.4 12.50¢80,490 0.4 9,278 0.8 11.530 916,107 4.4 91,039 8.2 9.94¢1,238,762 5.9 74,155 6.7 5.990 18,990 0.1 3,184 0.3 16.770 29,053 0.1 2,830 0.3 9.74¢140,779 0.7 10,079 0.9 7.16*3,253,322 15.6 294,239 26.6 9.040 1,932,268 9.3 118,393 10.7 6.13¢7,955,005 38.2 465,692 42.1 5.850 9,887,273 47.5 584,085 52.8 5.910 13,140,595 4,526,320 1,215,129 1,948,050 63.1 21.7 5.8 9.4 878,324 116,890 37,631 74,430 79.4 10.6 3.4 6.7 6.680 2.580 3.100 3.82t Total Electric Energy Sales Other Operating Revenues (Net of Deferred)20,830,094 100.0 1,107,275 100.1 (984) (0.1)5.32¢Total Operating Revenues $1,106,291 100.0 Production Costs MWh (000's)GENERATION Amount % Amount %Production (Including Interchange)(2) 18,044,219 83.3 $ 465,064 75.7 Power Purchased 3,625,967 16.7 148,986 24.3 Total Power Produced and Purchased 21,670,186 100.0 $ 614,050 100.0 (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 Number of Employees (Filled Full-Time and Part-Time Positions) 2013 Contractual and Tax Payments (000's): Payments to Retail Communities Payments in Lieu of Taxes 5,188 2,076$ 27,092$ 10,130 SOURCES OF ENERGY -2013 For service to retail and total requirements wholesale customers, and nonfirm sales (excludes sales to LES and Other Utilities).
Hydro & Renewable (7.1%)Gas & Oil -(0.8%)Nuclear -0 (30.0%) O Purchases/ -(5.5%)h-- Coal (56.6%)
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 15.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 3,030 MW was established in July 2012 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 30 generating plants, which had a combined accredited capacity during the summer of 2013 of 3,073.7 MW.GENERATION PLANTS Summer 2013 Number of Accredited Percent of Type: Plants(1) Capability (MW) Total Coal -Gerald Gentleman Station 1 1,365.0 44.4 Coal -Sheldon Station 1 225.0 7.3 Gas -Beatrice Power Station 1 217.0 7.1 Gas/Oil -Canaday Station 1 115.0 3.7 Nuclear -Cooper Nuclear Station 1 766.0 24.9 Hydro 9 164.5 5.4 Diesel 12 93.7 3.0 Combustion Turbine 3 127.5 4.2 Wind 1 0.0 0.0 30 3,073.7 100.0 (1) Includes six hydro plants and 12 diesel plants under contract to the District.In addition to the above generating plants, the District purchases 447.8 MW of firm power from the Western Area Power Administration and other energy on both a short-term and nonfirm basis in the wholesale energy market.The District had other capacity purchases of 162.6 MW from Omaha Public Power District's
("OPPD") Nebraska City Station Unit 2 ("NC2") coal-fired plant. Of the total capacity resources, 371.7 MW are being sold via participation sales or other capacity sales agreements.
The District owns and operates 5,188 miles of transmission and subtransmission lines, encompassing the entire State of Nebraska.The District's customer base for firm energy sales consists of approximately 89,604 retail customers plus 76 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 25,000 -20,000 -15,000 12,047 7,380 7,474 6,106 7,689 nn 12,044.35 12,422 1 12,395 1 13,169 1 13,141 0-U~U1 2010 zu011 2012 2U13 U Firm Energy Sales N Additional Energy Sales CONDENSED BALANCE SHEETS 2013 2012 2011 Condensed Balance Sheets (000's): Current Assets Special Purpose Funds Utility Plant, net Other Long-Term Assets Deferred Outflows of Resources Total Assets and Deferred Outflows Current Liabilities Long-Term Debt Other Long-Term Liabilities Deferred Inflows of Resources Net Position Total Liabilities, Deferred Inflows, and Net Position$ 665,854 688,220 2,500,069 795,792 16,504$ 4,666,439$ 352,229 1,845,244 1,109,567 180,637 1,178,762$ 4,666,439$ 608,912 744,982 2,513,511 729,867 18,066$ 4,615,338$ 386,256 1,972,951 1,053,502 121,250 1,081,379$ 4,615,338$ 567,237 790,264 2,402,025 706,816 7,091$ 4,473,433$ 270,795 2,063,901 995,224 137,178 1,006,335$ 4,473,433 CONDENSED RESULTS OF OPERATIONS 2013 2012 2011 Condensed Statements of Revenues, Expenses, and Changes in Net Position (000's): Operating Revenues Operating Expenses Operating Income Investment and Other Income Debt and Other Expenses Increase in Net Position$ 1,106,291 (941,887)164,404 15,221 (82,242)$ 97,383$ 1,080,998 (947,766)133,232 31,112 (89,300)$ 75,044$ 998,691 (902,523)96,168 42,622 (93,053)$ 45,737 The sources of operating revenues were as follows (000's): Firm Sales -Wholesale and Retail Participation Sales to LES Sales to Other Utilities Other Operating Revenue Unearned Revenue Total Operating Revenue 2013$ 878,324 37,631 191,320 59,162 (60,146)$ 1,106,291 2012$ 835,956 34,673 136,599 49,216 24,554$ 1,080,998 2011$ 755,984 33,633 183,759 40,811 (15,496)$ 998,691 NI-M ASK Pmi o i~i i-m Revenues from Firm Sales -Wholesale and Retail Revenues from firm sales increased
$42.3 million, or 5.1%, from $836.0 million in 2012 to $878.3 million in 2013.This increase is due primarily to 3.75% wholesale and retail rate increases effective January 1, 2013, as a result of increases in debt payments, current capital expenditures, and increases in operating costs. An additional increase is due to a 1.2% increase in kilowatt-hour energy sales to retail customers.
Revenues from firm sales increased
$80.0 million, or 10.6%, from $756.0 million in 2011 to $836.0 million in 2012. This increase is due primarily to 6.5% wholesale and 6.7% retail rate increases effective January 1, 2012, as a result of increases in fuel costs, related primarily to coal transportation, and infrastructure investments.
An additional increase is due to a 9.0% increase in kilowatt-hour energy sales to wholesale customers.
Cents per kWh 9.20-8.80-8.40 8.00-7.60-7.20 6.80 Cents per kWh 6.00-5.60-5.20-4.80-4.40-4.00-AVERAGE REVENUE PER kWh SOLD -RETAIL (Retail -All Classes)9.04 8.75*8.080 7.35¢ I 7 1lRt I I ZUU9 Zulu 2011 AVERAGE REVENUE PER kWh SOLD -WHOLESALE (Firm Wholesale Customers Only)5.910 5.57¢ U 5.39d 4.77d LU I I zU IL ZUMA Revenues from Participation Sales to LES and Sales to Other Utilities During 2013, the District made participation sales to LES from the capacity and energy produced at Gerald Gentleman Station ("GGS") and Sheldon Station; to KCP&L Greater Missouri Operations Company ("KCPL") from Cooper Nuclear Station ("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 increased from $34.7 million in 2012 to $37.6 million in 2013. The increase is due primarily to LES' share of operating and maintenance costs related to Sheldon Station being greater in 2013 than in 2012. Revenues from participation sales to LES increased from $33.6 million in 2011 to$34.7 million in 2012. The increase is due primarily to LES' share of fuel costs related to GGS being greater in 2012 than in 2011.Sales to other utilities consist of participation sales to KCPL, 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 $136.6 million in 2012 to $191.3 million in 2013, an increase of $54.7 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 no refueling and maintenance outage at CNS in 2013, and higher nonfirm market prices. Sales to other utilities decreased from $183.8 million in 2011 to $136.6 million in 2012, a decrease of$47.2 million. This decrease is due primarily to reduced revenues realized from nonfirm off-system sales as the result of a decrease in kilowatt-hour energy sales and a decrease in nonfirm market prices.Other Operating Revenue Other operating revenue consists primarily of transmission wheeling revenues and revenue from work for other utilities.
These revenues were $59.2 million, $49.2 million, and $40.8 million in 2013, 2012, and 2011, respectively.
The increases in 2013 and 2012 are due primarily to Southwest Power Pool ("SPP") Schedule 11 revenues which represent costs paid by other transmission customers of SPP to the District for its qualifying transmission upgrade projects.Unearned 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 postretirement 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.N1,13RSKA PU IC Pow iý i-z During 2013 and 2011, revenues from electric sales to wholesale, retail, and other utilities exceeded actual revenue requirements in each year. During 2012, actual revenue requirements exceeded electric sales to wholesale, retail, and other utilities.
The District deferred or decreased revenues a net amount of $60.1 million in 2013. The District's revenues in 2013 from electric sales to wholesale, retail, and other utilities resulted in a surplus, or over collection of costs, of$60.8 million, which surplus amount was deferred (decrease in revenues).
In addition, the wholesale rates that were in place for 2013 included a refund of $0.7 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred.Accordingly, the 2013 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 $24.6 million in 2012. The District's revenues in 2012 from electric sales to wholesale, retail, and other utilities resulted in a deficiency, or under collection of costs, of $3.7 million, which deficiency amount was accrued (increase in revenues).
In addition, the wholesale and retail rates that were in place for 2012 included a refund of $20.9 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred.
Accordingly, the 2012 revenues from electric sales, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount.The District deferred or decreased revenues a net amount of $15.5 million in 2011. The District's revenues in 2011 from electric sales to wholesale, retail, and other utilities resulted in a surplus, or over collection of costs, of$15.5 million, which surplus amount was deferred (decrease in revenues).
As of December 31, 2013, 2012, and 2011, the District had $101.9 million, $41.7 million, and $66.3 million, respectively, of surplus unearned 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 2011, 2012, and 2013.Dollars OPERATING EXPENSES (Millions) 1,000 $903 $948 $942 800-*Power Purchased
& Fuel 600 -Production
-Operation
& Maintenance
("O&M")* Transmission
& Distribution O&M 400 E Customer Service & Information
*Administrative
& General 200- Decommissioning Depreciation
& Amortization
*.Other 2011 2012 2013 Total operating expenses in 2013 were $941.9 million, a decrease of $5.9 million from 2012. Total operating expenses in 2012 were $947.8 million, an increase of $45.3 million from 2011. The changes were due primarily to the following:
Purchased power and production fuel expenses were $366.2 million, $345.1 million, and $316.4 million in 2013, 2012, and 2011, respectively.
These expenses increased
$21.1 million in 2013 as compared to 2012 due primarily to higher fuel costs as a result of increased generation and increased purchased power costs. These expenses increased
$28.7 million in 2012 as compared to 2011 due primarily to increased native wholesale load sales, higher fuel costs as a result of price increases in coal transportation costs, and increased purchased power costs.Production operation and maintenance expenses were $247.8 million, $285.0 million, and $265.9 million in 2013, 2012, and 2011, respectively.
These costs decreased
$37.2 million in 2013 as compared to 2012 due primarily to the costs associated with a planned refueling and maintenance outage at CNS in 2012. No such outage occurred in 2013. These costs increased
$19.1 million in 2012 as compared to 2011 due primarily to additional costs associated with a planned refueling and maintenance outage at CNS in 2012.Transmission and distribution operation and maintenance expenses were $76.4 million, $61.9 million, and$59.1 million in 2013, 2012, and 2011, respectively.
These costs increased
$14.5 million in 2013 as compared to 2012 and $2.8 million in 2012 as compared to 2011 both due primarily to increases in SPP wheeling and Schedule 11 fees. The District's firm requirement customers are charged on a load ratio share basis for other SPP transmission owners qualifying transmission system upgrade projects.Customer service and information expenses were $16.6 million, $16.7 million, and $19.6 million in 2013, 2012, and 2011, respectively.
These expenses did not vary significantly from 2013 to 2012. These costs decreased$2.9 million in 2012 as compared to 2011 due primarily to decreases in energy efficiency payments, advertising costs, and other customer service costs.Administrative and general expenses were $59.7 million, $51.7 million, and $51.1 million in 2013, 2012, and 2011, respectively.
These costs increased
$8.0 million in 2013 as compared to 2012 due primarily to increases in healthcare costs and the funding of retiree postemployment benefits along with less administrative and general costs being capitalized in 2013. These expenses did not vary significantly from 2012 to 2011.Decommissioning expenses were $10.7 million, $25.4 million, and $33.8 million in 2013, 2012, and 2011, 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 on investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year. Decommissioning expenses decreased by $14.7 million in 2013 as compared to 2012 due to a decrease in interest income on investments.
Decommissioning expenses decreased by $8.4 million in 2012 as compared to 2011 due to a decrease in market value changes of investments.
No amount for decommissioning was collected through rates in 2013, 2012, or 2011.To the extent that the accretion on the asset retirement obligation determined under Accounting Standards Codification 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 2013, 2012, and 2011 was $46.0 million, $43.8 million, and $41.6 million, respectively, and decommissioning expense was $10.7 million, $25.4 million, and $33.8 million, respectively.
Depreciation and amortization expenses were $127.3 million, $126.5 million, and $123.1 million in 2013, 2012, and 2011, respectively.
These expenses did not vary significantly from 2013 to 2012. These expenses increased$3.4 million in 2012 as compared to 2011 due primarily to recent investments at CNS.Increase in Net Position The increase in net position (net revenues) was $97.4 million in 2013, $75.0 million in 2012, and $45.7 million in 2011. The change in net position in 2013 as compared to 2012 was $22.4 million and reflects increases in revenue requirements used to establish rates for 2013 for the purpose of increased construction from revenue and commercial paper principal payments, along with a decrease in excess bond proceeds to pay interest, partially offset by decreased revenue bond principal payments and an increase in depreciation expense. The change in net position in 2012 as compared to 2011 was $29.3 million and reflects increases in revenue requirements used to establish rates for 2012 for the purpose of increased construction from revenue and revenue bond principal payments along with a decrease in excess bond proceeds to pay interest partially offset by decreased commercial paper principal payments and an increase in depreciation expense.7 ~ ~~~~~ NBRSAPBI o i-N irmr Dollars (Millions) 1,200 1,100 1,000-900-800-700-600 -REVENUES & EXPENSES$99$9011 ai1 Sl 08 2012$15 2013 500 Operating Revenue mu'Other Revenue Operating Expenses Other Expenses CAPITAL REQUIREMENTS The District's Board of Directors
("Board")
authorized capital projects totaling approximately
$78.9 million in 2013,$124.5 million in 2012, and $287.1 million in 2011. The amount for 2013 included $27.1 million for replacement of a low pressure turbine at GGS, $11.6 million for installation of stainless steel liners in coal silos at GGS, and$7.7 million for fire protection upgrades at CNS. The amount for 2012 included $10.2 million for replacement of service water discharge pipe at CNS, $9.6 million for replacement of a startup station service transformer at CNS,$8.1 million for installation of horizontal storage modules at CNS, and $7.2 million for replacement of boiler waterwall tubes at GGS. The amount for 2011 included $65.9 million for Phase II of construction of a high-voltage transmission line from Axtell, Nebraska to the Kansas border, $50.1 million for construction of transmission lines and substations related to the TransCanada Keystone XL Pipeline Project (this project has been put on hold as of December 31, 2013), the majority of which will be reimbursed by TransCanada, $39.3 million for installation of low nitrogen-oxide burners at GGS, and $9.2 million for Phase II of an electrical power back feed at CNS. The remaining capital projects authorized in 2013, 2012, and 2011, which totaled $32.5 million, $89.4 million, and$122.6 million, respectively, were primarily for renewals and replacements to existing facilities and other minor additions and improvements.
The Board-approved budget for capital projects for 2014 is $249.2 million, which includes $98.3 million for construction of a high-voltage transmission line and related substations from Hoskins Substation northeast of Norfolk, Nebraska to Neligh, Nebraska, $26.1 million to apply a protective coating to the interior of the torus at CNS, and $7.1 million for installation of wet dust collectors in coal silos at GGS. 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.Dollars (Millions) 400 300 200 100 CAPITAL REQUIREMENTS 542AQ$125$79 idget ZUllI ZU I0 FINANCING ACTIVITIES Revenue Bonds The District had $1.733 billion (par amount) of outstanding revenue bonds at December 31, 2013, as compared to$1.888 billion (par amount) at December 31, 2012, and $1.954 billion (par amount) at December 31, 2011. The revenue bonds outstanding are at fixed interest rates and were issued at premiums or discounts.
In October 2013, the District issued $118.3 million of tax-exempt revenue bonds to advance refund $154.9 million of bonds.In October 2012, the District issued $220.2 million of tax-exempt revenue bonds to advance refund $198.3 million of bonds, to finance $35.0 million of the costs of certain generation and transmission capital additions, and to refund $7.0 million of tax-exempt commercial paper (CTECP").In February 2012, the District issued $212.4 million of tax-exempt revenue bonds to advance refund$167.2 million of bonds, to finance $40.3 million of the costs of certain generation and transmission capital additions, and to refund $20.2 million of the tax-exempt revolving credit agreement
("TERCA")
indebtedness.
In May 2011, the District issued $61.4 million of tax-exempt revenue bonds to refund $64.2 million of taxable commercial paper ("TCP") notes.The District retired $118.9 million, $133.1 million, and $120.8 million of General System Revenue Bonds in 2013, 2012, and 2011, 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)Commercial Paper Notes The District had outstanding
$102.3 million of TECP notes at December 31, 2013, $102.3 million at December 31, 2012, and $110.0 million at December 31, 2011. The District is authorized to issue up to $150.0 million of TECP notes and has a bank credit agreement, expiring August 1, 2014, maintained to support the sale of the commercial paper notes. The District anticipates renewing this agreement prior to its August 2014 expiration.
Revolving Credit Agreements In 2011, the District established tax-exempt and taxable revolving credit agreements.
The District had outstanding under the TERCA $109.0 million at December 31, 2011. The District had outstanding under the taxable revolving credit agreement
("TRCA") $149.4 million at December 31, 2013, $148.6 million at December 31, 2012, and$6.1 million at December 31, 2011. The District is authorized to borrow up to an aggregate amount of$200.0 million on the revolving credit agreements.
Both the TERCA and TRCA have a bank credit agreement, expiring August 31, 2015, maintained to support the lines of credit.DEBT SERVICE COVERAGE The District's debt service coverage was 1.73 in 2013, 1.61 in 2012, and 1.65 in 2011. 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 NEBRAKA PBLICPowviz i~w-long-term Professional Retail Operations 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 18, 2034.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 agreements for the sale of capacity and energy from CNS to Heartland, to KCPL, and to MEAN. The Heartland agreement provided 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 KCPL agreement provides for delivery of 75 MW of capacity and energy from January 1, 2005 through January 18, 2014. The MEAN agreement, amended on December 27, 2010, provided for delivery of capacity and energy from January 1, 2011 through the last day of the month prior to the commercial operation of the Whelan Energy Center 2 ("WEC2"), a 220 MW coal-fired power plant, of 45 MW, of which 29 MW was provided from CNS and 16 MW from GGS. MEAN has an ownership interest in WEC2, which began commercial operation on May 1, 2011, and such agreement terminated on April 30, 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. In accordance with a settlement agreement between the District and the DOE that was executed on May 18, 2011, the District has received $87.4 million from the DOE for damages from 2009 through 2012. The settlement agreement addressed future claims through 2013. In January 2014, the DOE extended the settlement agreement through 2016. The District also reserves the right to pursue future damages through the contract claims process. The District plans to use the funds to pay for future costs related to CNS.RESOURCE PLANNING The Board approved the 2013 Integrated Resource Plan ("IRP") at the June 2013 Board meeting. The IRP indicated that an extended power uprate at CNS appeared beneficial.
In August 2013, after further investigation and analysis of the costs and risks of an extended power uprate, the Board decided not to pursue this project.The District is still well positioned to meet its firm load requirement needs for approximately the next 15 years.After the commercial operation of the 75 MW Broken Bow II Wind Facility in Custer County, Nebraska, planned for the first quarter of 2015, the District will be supplying its firm requirement customers with approximately 9% of their energy usage from renewable wind as compared to the District's renewable energy goal of 10% by 2020.Renewable Additions In January 2013, the District entered into a 25-year power purchase agreement with Steele Flats Wind Project, LLC to purchase electric power from the 75 MW Steele Flats Wind Facility near Steele City, Nebraska, which began commercial operation on November 1, 2013. The District is required to take all the capacity and energy of this facility for the first twenty years of operation and one percent of the capacity and energy for the remaining five years.As of December 31, 2013, the District had entered into power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities.
The District has entered into power sales agreements to sell 155 MW of this capacity to four other utilities in Nebraska over similar terms.N1:13RSKA Pu-ic Po iizDsric 1 In addition, the District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities.
The District will pay only for energy delivered pursuant to such power purchase wind agreements and the cost of the substation and transmission work to connect these facilities to the District's electric system. Participating utilities will pay their pro rata share of energy delivered from these facilities along with associated capital additions for substation and transmission work.ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks, including exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the creditworthiness of its counterparties, and the operational risks associated with transacting in the wholesale energy markets.To help manage energy risks, 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 ERM program. The objective of the ERM program is to increase fuel and energy price stability by hedging the risk of significant adverse impacts to cash flow. These adverse impacts could be caused by events such as natural gas or power price spikes or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed.The District is a member of SPP, a regional transmission organization
("RTO") based in Little Rock, Arkansas.Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration, including generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning.
The District was able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost, through February 2014.On March 1, 2014, SPP successfully implemented its integrated market which is expected to operate similar to other RTOs that are currently in place throughout the United States. The goal of the SPP integrated market is to reduce total production costs within the SPP region. TEA is registered as the market participant for the District in the new SPP integrated market.ECONOMIC FACTORS The continuing strong overall performance of Nebraska's agricultural sector, as measured by net farm income, and recent growth in the state's manufacturing sector, as measured by growth in employment, have both contributed to the state's positive economic performance.
Nebraska and the Midwest region continue to experience unemployment rates that are higher than pre-recession levels, but far below the national averages.Nebraska's unemployment rate decreased from an average of 4.0% for 2012 to an average of 3.9% for 2013 and remained well below the 2013 national average unemployment rate of 7.4%, Nebraska's seasonally adjusted unemployment rate was 3.6% in December 2013, down from 4.0% in December 2012. Both numbers were well below the national December seasonally adjusted unemployment rates of 6.7% in 2013 and 7.9% in 2012. For December 2013, Nebraska was tied for the second lowest unemployment rate 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.1~~ ~ ~~~~ 11VRSAPmicPwizDsic POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS 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 Board. 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.In 2008, the District established an irrevocable trust to begin funding the unamortized Other Postemployment Benefits ("OPEB") obligation.
Total contributions to the plan in 2013 were $23.6 million which included$10.0 million paid to the trust and $13.6 million for the cost of benefits.
Total contributions to the plan in 2012 were $15.6 million which included $4.0 million paid to the trust and $11.6 million for the cost of benefits.
Total contributions to the plan in 2011 were $21.0 million which included $10.0 million paid to the trust and $11.0 million for the cost of benefits.
It is currently projected that funding above the pay-as-you-go amount will remain at$10.0 million in 2014. The final funding will be determined annually by the Board. 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 $520.7 million, $498.5 million, and $427.7 million as of January 1, 2013, 2012, and 2011, 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) M ((b-a)/c)2013 $ 30,781 $ 520,705 $ 489,924 5.9% $ 187,378 261%2012 $ 24,900 $ 498,485 $ 473,585 5.0% $ 189,211 250%2011 $ 15,086 $ 427,709 $ 412,623 3.5% $ 189,428 218%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.Projections of benefits for financial reporting purposes are based on the substantive plan (the plan as understood by the employer and the plan members) and include the types of benefits provided at the time of each valuation and the historical pattern of sharing benefit costs between the employer and plan members to that point. The actuarial methods and assumptions used include techniques that are designed to reduce the effects of short-term volatility in actuarial accrued liabilities and the actuarial value of assets, consistent with the long-term perspective of the calculations.
In the January 1, 2012 actuarial valuation, which is the most recent actuarial study, the Unit Credit Actuarial Cost method was used for 2013, 2012, and 2011. In 2013, the actuarial assumptions included an annual healthcare cost trend rate of 8.5% initially, reduced by decrements to an ultimate rate of 4.6%. In 2012, the actuarial assumptions included an annual healthcare cost trend rate of 8.1% initially, reduced by decrements to an ultimate rate of 4.6%. In 2011, the actuarial assumptions included an annual healthcare cost trend rate of 7.2% initially, reduced by decrements to an ultimate rate of 4.4%. The discount rate used for 2013 and 2012 was 5.0% and for 2011 was 5.75%. The discount rate 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.The actuarial valuation of plan assets was based on market values as of January 1, 2012. The market value of plan assets was $48.3 million, $31.7 million, and $24.9 million at December31, 2013, 2012, and 2011, respectively.
NE131ZA~~SKPULCPwi iTI 1 COMMITMENTS AND CONTINGENCIES The District entered into a Transmission Facilities Construction Agreement 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 $6.1 million as of December 31, 2013.The District entered into a second Transmission Facilities Construction Agreement with TransCanada Keystone XL Pipeline, LP ("Keystone XL"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. The initial estimated cost of the project was$52.9 million and was to be paid by Keystone XL over a ten-year period anticipated to begin July 2013. However, the project was recently delayed due to routing concerns of the pipeline across the Nebraska Sandhills.
Adjustments to the facilities, project costs, and completion schedules will be made once the final route is determined, which is unknown at the present time. Keystone XL remains responsible for all present and future project costs with repayment to begin at project completion or cancellation.
As of December 31, 2013, actual project costs totaled $12.2 million.The District received written notice from the Internal Revenue Service (the "Service")
that the Service had concluded that certain of the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) did not qualify for the 35% interest subsidy provided by the United States Treasury based on an interpretation by the Service of the issue price of such Bonds to the public. While the District disagreed with the conclusion of the Service, the District has agreed to resolve the matter by entering into a closing agreement with the Service and paying $350,000 to the Service pursuant to the closing agreement.
Based on the closing agreement, the District may continue to claim credits with respect to the interest paid on the 2009 Series A Bonds and the Service has agreed not to contest such credits on the basis of the Service's conclusions referred to above.In October 2013, the Service affirmed, pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, that the 35% interest subsidy provided by the United States Treasury on the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds), will be reduced by 7.2%. This reduction in the interest subsidy will be applied to the Service payments made on or after October 1, 2013 through September 30, 2014, or intervening Congressional action, at which time the reduction rate is subject to change. This loss of subsidy totals approximately
$0.2 million.In March 2013, the District initiated a voluntary early retirement incentive program ("program")
to all regular, full-time employees, excluding senior management, who meet certain retirement-eligible criteria.
Approximately 575 District employees were eligible for the program and 110 District employees accepted the offer. Their last day of employment was no later than June 30, 2013. Those employees who participated in the program received six months of salary in one, lump sum payment. Total cost of the program was $6.0 million.The District is aware that four wholesale customers located in northeast Nebraska have made requests for proposals from power suppliers other than the District.
These customers currently represent 3% of Operating Revenues.
At this time, the District has received notice from three of the respective customers as to their intent to level off or reduce the requirements under their current contract beginning in 2019. If a substantial number of wholesale customers begin leveling off or reducing their requirements, the District would be required to increase its rates to recover costs.13 N1`13RASKA PUBLIC Po i-i i~ii INDEPENDENT AUDITOR'S REPORT To the Board of Directors of the Nebraska Public Power District: We have audited the accompanying financial statements of Nebraska Public Power District (the "District")
which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of revenues, expenses, and changes in net position, and of cash flows for the years then ended.Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.Auditor's Responsibility Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the District's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the District's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the District as of December 31, 2013 and 2012, and the respective changes in financial position and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.Other Matters The accompanying management's discussion and analysis and the calculation of debt service ratios on pages 2 through 13 and 18, respectively, are required by accounting principles generally accepted in the United States of America to supplement the basic financial statements.
Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audits of the basic financial statements.
We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
Our audits were conducted for the purpose of forming an opinion on the financial statements that collectively comprise the District's basic financial statements.
The statistical review is presented for purposes of additional analysis and is not a required part of the basic financial statements.
Such information has not been subjected to the auditing procedures applied in the audits of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.St. Louis, Missouri April 10, 2014 NE.3A K au-cP w-ý i-iir1 FINANCIAL STATEMENTS Balance Sheets -December 31, 2013 and 2012 (000's) 2013 2012 ASSETS AND DEFERRED OUTFLOWS Current Assets: Cash and cash equivalents
$ 162,384 $ 157,618 Investments 230,452 166,528 Receivables, less allowance for doubtful accounts of $478 and $476, respectively 102,805 93,893 Fossil fuels, at average cost 35,951 40,845 Materials and supplies, at average cost 123,084 133,630 Prepayments and other current assets 11,178 16,398 665,854 60a,912 Special Purpose Funds: Cash and cash equivalents:
Construction funds 264 4,513 Debt reserve fund 1,188 3 Employee benefit funds 4,853 945 Investments:
Construction funds 53,666 88,160 Debt reserve fund 93,607 101,729 Employee benefit funds 903 6,268 Decommissioning funds 533,739 543,364 688,220 744,982 Utility Plant, at Cost: Utility plant in service 4,549,279 4,434,580 Less reserve for depreciation 2,433,049 2,346,408 2,116,230 2,089,172 Construction work in progress 170,083 203,364 Nuclear fuel, at amortized cost 213,756 221,975 2,500,069 2,513,511 Other Long-Term Assets: Asset retirement obligation 442,338 385,622 OPEB obligation 123,475 111,656 Long-term capacity contracts 186,810 193,799 Unamortized financing costs 10,687 11,500 Investment in The Energy Authority 6,695 7,801 Other 25,787 19,489 795,792 729,867 Total Assets 4,649,935 4,597,272 Deferred Outflows of Resources:
Unamortized cost of refunded debt 16,504 18,066 TOTAL ASSETS AND DEFERRED OUTFLOWS $ 4,666,439
$ 4,615,338 LIABILITIES, DEFERRED INFLOWS, AND NET POSITION Current Liabilities:
Current maturities of revenue bonds $ 124,585 $ 256,680 Current maturities of commercial paper notes 102,300 -Accounts payable and accrued liabilities 84,868 86,569 Accrued in lieu of tax payments 10,057 9,605 Accrued payments to retail communities 6,426 5,685 Accrued compensated absences 16,052 16,956 Other 7,941 10,761 352,229 386,256 Long-Term Debt: Revenue bonds, net 1,695,827 1,722,096 Commercial paper notes and revolving credit agreements 149,417 250,855 1,845,244 1,972,951 Other Long-Term Liabilities:
Asset retirement obligation 977,083 930,178 Other postemployment benefits 125,375 111,656 Other 7,109 11,668 1,109,567 1,053,502 Total Liabilities 3,307,040 3,412,709 Deferred Inflows of Resources:
Unearned revenue 101,861 41,714 Settlement reimbursement 78,776 79,536 180,637 121,250 Net Position: Net investment in capital assets 747,650 613,866 Restricted 42,883 49,290 Unrestricted 388,229 418,223 1,178,762 1,051,379 TOTAL LIABILITIES, DEFERRED INFLOWS, AND NET POSITION $ 4,666,439
$ 4,615,338 The accompanying notes to financial statements are an integral part of these statements.
15 NE-1310SA PUBLIC Po i-RDsr Statements of Revenues, Expenses, and Changes in Net Position for the years ended December 31, (000's) 2013 2012 Operating Revenues $ 1,106,291
$ 1,080,998 Operating Expenses: Power purchased 148,986 143,579 Production
-Fuel 217,242 201,549 Operation and maintenance 247,822 285,027 Transmission and distribution operation and maintenance 76,352 61,883 Customer service and information 16,558 16,706 Administrative and general 59,723 51,650 Payments to retail communities 27,092 25,773 Decommissioning 10,699 25,414 Depreciation and amortization 127,283 126,512 Payments in lieu of taxes 10,130 9,673 941,887 947,766 Operating Income 164,404 133,232 Non-Operating Income: Investment income 11,839 27,552 Other income 3,382 3,560 15,221 31,112 Increase in Net Position Before Non-Operating Expenses 179,625 164,344 Non-Operating Expenses: Interest on long-term debt 91,858 100,348 Allowance for funds used during construction (2,842) (6,162)Bond premium amortization net of debt issuance expense (8,368) (6,208)Other expenses 1,594 1,322 82,242 89,300 Increase in Net Position 97,383 75,044 Net Position: Beginning balance 1,081,379 1,006,335 Ending balance $ 1,178,762
$ 1,081,379 The accompanying notes to financial statements are an integral part of these statements.
N1:13 ASKAPuin~c Po i~i i 'm r1 Statements of Cash Flows for the years ended December 31, (000's) 2013 2012 Cash Flows from Operating Activities:
Receipts from customers and others $ 1,162,065
$ 1,064,464 Other receipts 3,254 9,004 Payments to suppliers and vendors (520,342)
(523,315)Payments to employees (237,845)
(237,134)Net cash provided by operating activities 407,132 313,019 Cash Flows from Investing Activities:
Proceeds from sales and maturities of investments 1,145,451 803,650 Purchase of investments (1,168,080)
(837,347)Income received on investments 2,698 3,768 Net cash used in investing activities (19,931) (29,929)Cash Flows from Capital and Related Financing Activities:
Proceeds from issuance of bonds 126,158 209,516 Proceeds from issuance of notes -4,000 Proceeds from advance on tax-exempt and taxable revolving credit agreements 20,650 57,149 Capital expenditures for utility plant (151,128)
(260,523)Contribution in aid of construction 7,024 1,552 Principal payments on long-term debt (273,780)
(233,085)Interest payments on long-term debt (92,486) (99,076)Principal payments on notes -(11,700)Interest payments on notes (175) (184)Principal payment on tax-exempt revolving credit agreement (19,787) (23,694)Funds advanced -Whelan Energy Center 2 (1,449) (1,091)Other non-operating revenues 3,382 3,560 Net cash used in capital and related financing activities (381,591)
(353,576)Net increase (decrease) in cash and cash equivalents 5,610 (70,486)Cash and cash equivalents, beginning of year 163,079 233,565 Cash and cash equivalents, end of year 168,689 $ 163,079 Reconciliation of Operating Income to Cash Provided By Operating Activities:
Operating income $ 164,404 $ 133,232 Adjustments to reconcile operating income to net cash provided (used) by operating activities:
Depreciation and amortization 127,283 126,512 Undistributed net revenue -The Energy Authority 1,106 954 Decommissioning, net of customer contributions 10,699 25,414 Amortization of nuclear fuel 50,323 48,269 Changes in assets and liabilities which (used) provided cash: Receivables, net (7,463) (6,565)Fossil fuels 4,894 1,573 Materials and supplies 10,546 (8,247)Prepayments and other current assets (1,107) (1,403)Other long-term assets 770 386 Accounts payable and accrued payments to retail communities (13,797) 15,188 Unearned revenues 60,147 (24,554)Other liabilities (673) 2,260 Net cash provided by operating activities
$ 407,132 $ 313,019 Supplementary non-cash capital activities:
Utility plant additions in accounts payable $ 12,838 $ 4,531 The accompanying notes to financial statements are an integral part of these statements.
17 N1`.13RASK PU131-IC Po i-j i'w r Supplemental Schedule -Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (000's) 2013 2012 Operating revenues $ 1,106,291
$ 1,080,998 Operating expenses (941,887)
(947,766)Operating income 164,404 133,232 Investment and other income 15,221 31,112 Debt and other expenses (82,242) (89,300)Increase in net position 97,383 75,044 Add: Collections for future debt retirement 6,747 22,510 Debt and related expenses 82,242 89,300 Depreciation and amortization 127,283 126,512 Payments to retail communities('
27,092 25,773 Amortization of current portion of financed nuclear fuel 22,455 20,125 Amounts collected from third party financing arrangements(2) 770 733 266,589 284,953 Deduct: Investment income retained in construction funds 119 292 Unrealized loss on investment securities (1,335) (1,094)Revolving credit agreement interest 1,444 1,128 228 326 Net position available for debt service under the General Revenue Bond Resolution
$ 363,744 $ 359,671 Amounts deposited in the General System Debt Service Account: Principal
$ 118,915 $ 133,085 Interest 91,758 90,222$ 210,673 $ 223,307 Ratio of net position available for debt service to debt service deposits 1.73 1.61 (1) Under the provisions of the General Revenue Bond Resolution, the payments required to be made by the District with respect to the Professional Retail Operations Agreements are to be made on the same basis as subordinated debt.(2) Under the provisions of the General Revenue Bond Resolution, the payments received by the District from third party financing arrangements provide for debt service coverage, but are not recognized as revenue under Generally Accepted Accounting Principles.
The accompanying notes to financial statements are an integral part of these statements.
NFBIýASK PULCPw-i 3srz r1 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
-The financial statements are prepared in accordance with Generally Accepted Accounting Principles
("GAAP") and follow accounting guidance provided by the Governmental Accounting Standards Board ("GASB") codification.
The District follows the provisions of Accounting Standards Codification
("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.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 requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the District's long-term wholesale power supply contracts.
The District accounts for any surplus or deficit in revenues for retail service in a similar manner.The 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, 2013 and 2012, the District deferred net revenues of $60.1 million and deferred net costs of $24.6 million, respectively, and are reflected in the Balance Sheets within Unearned revenue. The cumulative surplus at December 31, 2013, to be reflected in future revenue requirements, is approximately
$101.9 million.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 $80.7 million and $99.0 million for the years ended December 31, 2013 and 2012, respectively.
Annual depreciation expense calculated under the debt service principal approach 19 ~ ~~~ Ni1pSAPmi Pw.ýDsru~
was less than straight-line depreciation by $4.6 million for the year ended December 31, 2013 and exceeded straight-line depreciation by $14.7 million for the year ended December 31, 2012. Depreciation expense recorded on a straight-line basis on utility plant was $108.5 million and $102.0 million for the years ended December 31, 2013 and 2012, respectively.
Depreciation on utility plant was approximately 2.6% and 2.5% for the years ended December 31, 2013 and 2012, respectively.
The District has fully depreciated utility plant that is still in service of$857.4 million and $840.5 million at December 31, 2013 and 2012, 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, 2013 and 2012,$578.7 million and $566.3 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 Operations
("PRO") Agreements with 79 municipalities for certain retail electric distribution systems. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreements.
The District has recorded provisions, net of retirements, for amortization of these plant additions of $6.4 million in 2013 and $9.0 million in 2012 which is included in depreciation and amortization expense. These plant additions, which are fully depreciated, totaled $171.3 million at December 31, 2013, and$166.3 million at December 31, 2012.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 Company ("GE") for fuel bundle fabrication and related services.
This contract was assigned effective January 2000 by GE to Global Nuclear Fuels-Americas.
The contract, as amended, provides for these services through 2017. The District's existing contract with United States Enrichment Corporation for various nuclear fuel components including enrichment services expired December 31, 2013. The District entered into a contract with Louisiana Energy Services, LLC in 2013 for enrichment services for five reloads starting in 2016 and ending in 2024. 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.CNS has a dry cask used fuel storage facility to support 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.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 Statement No. 62, Codification of Accounting and Financial Reporting Guidance Contained in Pre-November 30, 1989, FASB and AICPA Pronouncements
("GASB Statement 62") and are reflected in the Balance Sheets within Unamortized cost of refunded debt.IFRAK PULCPw-]Dsrcr2 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 tax-exempt commercial paper ("TECP"), tax-exempt revolving credit agreement
("TERCA"), or taxable revolving credit agreement
("TRCA") is charged a rate based upon the projected average interest cost of TECP, TERCA, or TRCA outstanding.
For the periods presented herein, the AFUDC rates for construction funded by revenue bonds vary from 2.2% to 5.0%. For construction financed on a short-term basis with TECP, the rate charged is 1.3%.K. Net Position -Net position is made up of three components:
Net investment in capital assets, Restricted, and Unrestricted.
Net investment in capital assets 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 net position 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 net position consists of any remaining net position that does not meet the definition of Net investment in capital assets or Restricted, and are used to provide for working capital to fund non-nuclear fuel and inventory requirements, as well as other operating needs of the District.L. Asset Retirement Obligations
-Asset retirement obligations
("ARO") represent the fair value of the District's legal liability associated with the retirement of CNS, various ash landfills at its two coal-fired power stations, and the removal of asbestos at its various generating facilities.
M. Recent Accounting Pronouncements
-GASB Statement 62 is to incorporate into the GASB's authoritative literature certain Financial Accounting Standards Board ("FASB") and American Institute of Certified Public Accountants
("AICPA")
accounting and financial reporting guidance issued on or before November 30, 1989, which does not conflict with GASB pronouncements.
GASB Statement 62 also supersedes GASB Statement No. 20, Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities That Use Proprietary Fund Accounting, thereby eliminating the election provided in that Statement for enterprise funds to apply post November 30, 1989, FASB pronouncements that do not conflict with GASB pronouncements.
However, GASB Statement 62 allows these entities to continue to apply post November 30, 1989, FASB pronouncements that do not conflict with GASB pronouncements.
The District adopted GASB Statement 62 as of January 1, 2012. The implementation of this standard did not have a material impact on the District's financial position or results of operation.
GASB Statement No. 63, Financial Reporting of Deferred Outflows of Resources, Deferred Inflows of Resources, and Net Position ("GASB Statement 63") provides guidance for the reporting of deferred outflows of resources, deferred inflows of resources, and net position in a statement of financial position.
Amounts that are required to be reported as deferred outflows of resources should be reported in a statement of financial position in a separate section following assets. Similarly, amounts required to be reported as deferred inflows of resources should be reported in a separate section following liabilities.
The statement of net position should report the residual amount as net position, rather than net assets or equity. The District adopted GASB Statement 63 as of January 1, 2012. The implementation of this standard did not have a material impact on the District's financial position or results of operation.
In March 2012, GASB issued Statement No. 65, Items Previously Reported as Assets and Liabilities
("GASB Statement 65"). GASB Statement 65 establishes accounting and financial reporting standards that reclassify as deferred outflows of resources or deferred inflows of resources, certain items that were previously reported as assets and liabilities.
It also recognizes, as outflows of resources or inflows of resources, certain items that were previously reported as assets and liabilities.
The District adopted GASB Statement 65 as of January 1, 2013. The implementation of this standard required certain amounts to be reclassified on the District's Balance Sheets.1 21 N1`13RA~~~~SK Pr ijcPwi s-m r
: 2. UTILITY PLANT: Utility plant activity for the year ended December 31, 2013, was as follows (000's): Nondepreciable utility plant: Land and improvements Construction in progress Total nondepreciable utility plant Nuclear fuel*Depreciable utility plant: Generation
-Fossil Generation
-Nuclear Transmission Distribution General Total depreciable utility plant Less reserve for depreciation Depreciable utility plant, net Utility plant activity, net December 31, 2012$ 62,887 203,364 266,251 221,975 1,493,998 1,276,823 1,071,635 208,090 321,147 4,371,693 (2,346,408) 2,025,285$ 2,513,511 Increases$ 169 126,055 126,224 42,104 32,354 34,928 52,006 7,091 13,497 139,876 (111,987)27,889$ 196,217 Decreases$ --(159,336)(159,336)December 31, 2013$ 63,056 170,083 233,139 (50,323) 213,756 (4,732)(7,071)(3,380)(2,169)(7,994)(25,346)25,346$ (209,659)1,521,620 1,304,680 1,120,261 213,012 326,650 4,486,223 (2,433,049) 2,053,174$ 2,500,069* Nuclear fuel decreases represent amortization of $50.3 million.The 2014 construction plan includes authorization for future expenditures of $249.2 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 Statement No. 31, Accounting and Financial Reporting for Certain Investment and for External Investments Pools ("GASB Statement 31 "). GASB Statement 31 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 Net Position.
The District had an unrealized net loss of $1.3 million as of December 31, 2013 and an unrealized net gain of $1.2 million as of December 31, 2012.Cash deposits, primarily interest bearing, are covered by federal depository insurance, pledged collateral of U.S. Government securities held by various depositories, or an irrevocable, nontransferable, unconditional letter of credit issued by a Federal Home Loan Bank. 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$1,081.1 million and $1,069.1 million at December 31, 2013 and 2012, respectively.
The fair value of all cash and investments, regardless of balance sheet classification, as of December 31 was as follows (000's): U.S. Treasury and government agency securities Corporate bonds Municipal bonds Certificates of deposit Cash and money market mutual funds Total cash and investments 2013$ 672,060 172,880 17,439 218,676$1,081,055 2012$ 671,381 175,972 15,972 256 205,547$1,069,128 NIA3ZASK PU31,1 Po ii Dsrzc 2 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.2013 2012 Construction funds -Cash and cash equivalents
$ 264 $ 4,513 Construction funds -Investments 53,666 88,160$ 53,930 $ 92,673 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 $42.9 million and$49.3 million as of December 31, 2013 and 2012, 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 $51.9 million and $52.4 million as of December 31, 2013 and 2012, respectively.
2013 2012 Debt reserve fund -Cash and cash equivalents
$ 1,188 $ 3 Debt reserve fund -Investments 93,607 101,729$ 94,795 $ 101,732 The Employee benefit funds consist of a self-funded hospital-medical benefit plan and a retired employee life insurance benefit plan. The District pays 80% of the hospital-medical premiums with the employees paying the remaining 20% of the cost of such coverage.
The plan had contributed funds of $4.4 million and $5.7 million at December 31, 2013 and 2012, respectively.
The retired employee life insurance benefit plan was funded prior to the adoption of GASB Statement No. 45, Accounting and Financial Reporting by Employers for Postemployment Benefits Other Than Pensions ("GASB Statement 45") and creation of an irrevocable grantor trust for postretirement health and life insurance benefits.
For additional information on postemployment benefits see Note 16. The District pays the total cost of the employee life insurance benefit once the employee retires. The plan had contributed funds of $1.4 million and $1.5 million at December 31, 2013 and 2012, respectively.
Both funds are held by outside trustees in compliance with the funding plans approved by the District's Board of Directors.
2013 2012 Employee benefit fund -Cash and cash equivalents
$ 4,853 $ 945 Employee benefit fund -Investments 903 6,268$ 5,756 $ 7,213 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.
2013 2012 Decommissioning funds $ 533,739 $ 543,364 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 23 N1:13RASKAPUBLIC J-)oxi-. Dsrur 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.Level2- 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): Assets: Available-for-sale securities:
U.S. Treasury and government agency securities Decommissioning funds: U.S. Treasury and government agency securities Corporate bonds Municipal bonds Assets: Available-for-sale securities:
December 31, 2013 Level 1 Level 2 Level 3 Total$ -$ 366,878 $ -$ 366,878-305,182 -305,182-172,880 -172,880-17,439 -17,439$ -$ 862,379 $ -$ 862,379 December 31, 2012 Level 1 Level 2 Level 3 Total U.S. Treasury and government agency securities
$ -$ 321,492 $ -$ 321,492 Certificates of deposit -256 -256 Decommissioning funds: U.S. Treasury and government agency securities
-349,888 -349,888 Corporate bonds -175,972 -175,972 Municipal bonds -15,972 -15,972$ -$ 863,580 $ -$ 863,580 Decommissioning funds reflect the assets held in trust to cover general decommissioning costs and consist primarily of fixed income governmental securities.
Ni~i3RASK PU3-CPw-izDsimr2
: 5. LONG-TERM CAPACITY CONTRACTS:
Long-term capacity contracts include the District's
$198.2 million share of the construction costs of Omaha Public Power District's
("OPPD") 682 MW Nebraska City Station Unit 2 ("NC2") coal-fired power plant which amount includes $15.8 million share of associated transmission facilities construction costs. The District has entered into a participation power agreement with OPPD for a 23.7% share of the power from this plant. NC2 began commercial operation on May 1, 2009, at which time the District began amortizing the amount of the capacity contract associated with the plant of $182.4 million on a straight-line basis over the 40-year estimated useful life of the plant. In July 2011, OPPD refunded the District $4.9 million representing excess construction costs and this amount was credited to Power purchased and $3.2 million of prepaid transmission costs were transferred to prepaid purchase power due to finalized construction costs. Accumulated amortization was$21.5 million in 2013 and $16.8 million in 2012. The unamortized amount of the plant capacity contract was$164.1 million and $168.8 million as of December 31, 2013 and 2012, respectively, of which $4.6 million was included in Prepayments and other current assets as of December 31, 2013 and 2012. The costs of the transmission facilities have been returned to the District in the form of a credit on the District's monthly transmission bill from OPPD. The final credit appeared on the District's December 2012 transmission bill.Accumulated credits were $12.6 million.Long-term capacity contracts also include the District's purchase of the capacity of a 50 MW hydroelectric generating facility owned and operated by The Central Nebraska Public Power and Irrigation District ("Central").
The District is recording amortization on a straight-line basis over the 40-year estimated useful life of the facility.Accumulated amortization was $57.4 million in 2013 and $55.1 million in 2012. The unamortized amount of the Central capacity contract was $29.3 million and $31.6 million as of December 31, 2013 and 2012, respectively, of which $2.3 million was included in Prepayments and other current assets as of December 31, 2013 and 2012.The District has an agreement whereby Central makes available all the production of the facility and the District pays all costs of operating and maintaining the facility plus a charge based on the amount of energy delivered to the District.
Costs of $1.5 million and $1.8 million in 2013 and 2012, respectively, are included in Power purchased in the accompanying Statements of Revenues, Expenses, and Changes in Net Position.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 were 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 $5.2 million as of December 31, 2012, of which $5.2 million was included in Prepayments and other current assets as of December 31, 2012. The deferral was fully amortized as of December 31, 2013.7. INVESTMENT IN THE ENERGY AUTHORITY:
The District is a member of The Energy Authority
("TEA"), a power marketing corporation.
TEA assumes the wholesale power marketing responsibilities of its members with each member having ownership in the joint venture. TEA has access to approximately 25,000 megawatts of its members' and partners' generation located across the nation. TEA also provides its members with natural gas procurement or contract management services for gas used in the generation of electricity and for local distribution.
TEA provides the District with gas contract management services.25 NEIBAýKA PBLIC PWF._R isric The table below contains the condensed financial information for TEA as of December 31, (000's): Condensed Balance Sheet Current Assets Noncurrent and Restricted Assets Total Assets Current Liabilities Noncurrent Liabilities Net Assets Total Liabilities and Net Assets Condensed Statement of Operations Revenues Energy Costs Gross Profit Operating Expenses Operating Income Non-Operating Income Increase in Net Assets 2013$ 145,103 16,528$ 161,631$ 126,905 1,826 32,900$ 161,631$ 1,316,708 (1,187,339) 129,369 (43,085)86,284 28$ 86,312 2012$ 127,184 18,332$ 145,516$ 104,685 1,915 38,916$ 145,516$ 1,207,495 (1,075,839) 131,656 (40,939)90,717 39$ 90,756 At December 31, 2013 and 2012, the District had a 20% ownership interest in TEA. 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): Beginning Balance Reduction to power costs and increase in electric revenues Distributions from TEA Other expenses Ending Balance 2013$ 7,801 34,409 (31,888)(3,653)$ 6,669 2012$ 8,755 25,475 (22,638)(3,791)$ 7,801 The District's power purchases and sales with TEA are reflected in the Statements of Revenues, Expenses, and Changes in Net Position as Power purchased, and Operating Revenues, respectively.
For the years ended December 31, 2013 and 2012, the District recorded Operating Revenues of $82.8 million and $45.5 million, respectively, and Power purchased expenses of $2.7 million and $10.7 million, respectively.
At December 31, 2013 and 2012, $8.8 million and $8.7 million due from TEA was included in Receivables and$0.7 million and $0.3 million due to TEA was included in Accounts payable and accrued liabilities, respectively.
As of December 31, 2013, 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 Ni-HBR SK Pp11 o ii Dsrzcr2 guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect.As of December 31, 2013 and 2012, the District has not recorded a liability related to these guaranties.
: 8. REVENUE BONDS: In October 2013, the District issued General Revenue Bonds, 2013 Series A, in the amount of $118.3 million to advance refund $154.9 million of bonds.In October 2012, the District issued General Revenue Bonds, 2012 Series B and 2012 Series C, in the amount of $116.7 million and $103.4 million, respectively, to advance refund $198.3 million of bonds, to finance$35.0 million of the costs of certain generation and transmission capital additions, and to refund $7.0 million of TECP.In February 2012, the District issued General Revenue Bonds, 2012 Series A, in the amount of $212.4 million to advance refund $167.2 million of bonds, to finance $40.3 million of the costs of certain generation and transmission capital additions, and to refund $20.2 million of the TERCA indebtedness.
In November 2013, the District entered into an escrow agreement in conjunction with the advanced refunding of General Revenue Bonds, 2005 Series A, maturing on January 1, 2017 and certain bonds maturing on January 1, 2019, and General Revenue Bonds, 2006 Series A, maturing on January 1, 2018 and January 1, 2019.In November 2012, the District entered into an escrow agreement in conjunction with the advanced refunding of General Revenue Bonds, 2002 Series B, maturing on and after January 1, 2014, and General Revenue Bonds, 2005 Series A, maturing on January 1, 2018 through January 1, 2025 and bearing interest at 5.00%.In February 2012, the District entered into an escrow agreement in conjunction with the advanced refunding of General Revenue Bonds, 2003 Series A, maturing on and after January 1, 2015.Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2013, are as follows (000's): Year 2014 2015 2016 2017 2018 2019-2023 2024-2028 2029-2033 2034-2038 2039-2042 Total Payments Debt Service Payments$ 209,205 187,034 184,801 Principal Payments$ 124,585 108,740 111,545 156,693 156,698 632,161 534,587 371,584 169,175 55,176$ 2,657,114 88,690 93,005 372,210 364,170 280,940 138,575 50,175$1,732,635 The fair value of outstanding revenue bonds is determined using currently published rates. The fair value is estimated to be $1,827.4 million and $2,096.6 million at December 31, 2013 and 2012, respectively.
27~ ~~~ N,1RSAP311 o i~i i-m' Revenue bonds consist of the following (000's except interest rates): December 31, Interest Rate General Revenue Bonds: 2003 Series A: Serial Bonds 2013-2026 3.875% -5.000 2004 Series B Serial Bonds 2013 4.25% -5.000 2005 Series A Serial Bonds 2013-2025 3.50% -5.250 2005 Series B-1 Serial Bonds 2013-2015 5.000 2005 Series B-2 Serial Bonds 2014-2016 5.000 2005 Series C: Serial Bonds 2013-2025, 2040 3.70% -5.125 Term Bonds 2026-2029 5.00Q 2030-2034 4.75*2035-2040 5.00*2006 Series A: Serial Bonds 2013-2025 4.00% 5.000 Term Bonds 2026-2030 5.000 2031-2035 5.00*2036-2040 4.375 2036-2040 5.000 2007 Series B: Serial Bonds 2013-2026 4.00% 5.000 Term Bonds 2027-2031 4.650 2032-2036 5.00e 2008 Series A Taxable Term Bonds 2013 5.14°2008 Series B: Serial Bonds 2013-2029 4.00% 5.000 Term Bonds 2030-2032 5.000 2033-2037 5.000 2038-2040 5.00*2009 Series A Taxable Build America Bonds: Term Bonds 2019-2025 6.606 2026-2034 7.399'2009 Series C Serial Bonds 2013-2019 3.00% -4.250 2010 Series A Taxable Build America Bonds: Serial Bonds 2019-2024 3.98% -4.73o Term Bonds 2025-2029 5.323'2030-2042 5.423 2010 Series B Taxable Serial Bonds 2013-2020 2.25% -4.180/2010 Series C: Serial Bonds 2013-2025 3.00% -5.000)Term Bonds 2026-2030 4.000/2026-2030 5.000/2011 Series A Serial Bonds 2013-2016 2.00% -5.000/2012 Series A Serial Bonds 2013-2034 3.00% -5.000/2012 Series B: Serial Bonds 2013-2032 2.00% -5.000j Term Bonds 2033-2036 3.625'2037-2042 3.625 2012 Series C Serial Bonds 2013-2028 3.00% -5.000j 2013 Series A Serial Bonds 2014-2033 3.00% -5.000/Total par amount of revenue bonds Unamortized premium net of discount Less -current maturities of revenue bonds Total revenue bonds 2013 2012/0/0 4,/0/0/0 10 4,/0 10 4,/0 10/,/0 4,/0/0/0 40/0 0 0o 0o 0o 0o 0o$22,840 29,180 52,780 68,675 11,765 18,240 27,500 50,425 18,680 23,840 400 30,020 170,855 36,140 19,270 204,885 32,390 50,880 7,180$2,155 28,540 32,740 43,545 52,780 70,180 11,765 18,240 27,500 66,630 18,680 23,840 400 30,020 181,775 36,140 19,270 137,765 213,910 32,390 50,880 7,180 17,465 32,890 10,365 31,875 27,985 54,190 5,985 94,055 6,165 14,180 26,595 209,110 102,675 2,320 4,155 98,410 118,270 1,732,635 87,777 1,820,412 (124,585)1,695,827 17,465 32,890 12,160 31,875 27,985 54,190 6,740 107,875 6,165 14,180 38,445 211,700 110,255 2,320 4,155 103,420 1,888,145 90,631 1,978,776 (256,680)$ 1,722,096 rN~~i~ m Z A S K /\ P u m -ic P w -A i -z c r2 81 11
: 9. COMMERCIAL PAPER NOTES: The District is authorized to issue up to $150.0 million of TECP notes. A $150.0 million line of credit expiring August 1, 2014, is maintained with two commercial banks to support the sale of the TECP notes. The District had$102.3 million of TECP notes outstanding at December 31, 2013 and 2012. The proceeds of the TECP notes have been used to provide short-term financing for certain capital additions and for other lawful purposes of the District.
The effective interest rate on outstanding TECP notes was 0.2% for 2013 and 2012.The $102.3 million of TECP notes outstanding at December 31, 2013 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 2014 expiration.
: 10. LINE OF CREDIT AGREEMENTS:
The District has a line of credit of $150.0 million expiring August 1, 2014, that supports the payment of the principal outstanding of the TECP notes. See Note 9 for additional information.
At December 31, 2013 and 2012, no amounts have been drawn on the line of credit.11. REVOLVING CREDIT AGREEMENTS:
The District has entered into two revolving credit agreements authorizing the District to borrow up to$150.0 million under a TERCA and up to $50.0 million under a TRCA. In 2012, the District amended these revolving credit agreements for an aggregate amount up to $200.0 million, expiring on August 31, 2015, and are maintained with a commercial bank to provide for these borrowings.
The District had $149.4 million and$148.6 million of TRCA outstanding at December 31, 2013 and 2012, respectively.
The borrowings are to provide short-term financing for certain capital additions and for other lawful purposes of the District.The $149.4 million of TRCA outstanding at December 31, 2013 is anticipated to be retired by future collections through electric rates and issuance of revenue bonds. The carrying value of the revolving credit agreements approximates market value due to the short-term nature of the agreements.
: 12. LONG-TERM DEBT: Long-term debt activity, net of current activity for the year ended December 31, 2013, was as follows (000's): Principal Amounts December 31, December 31, Due Within 2012 Increases Decreases 2013 One Year Revenue bonds $ 1,722,096
$ 128,804 $ (155,073)
$ 1,695,827
$ 124,585 Commercial paper notes 102,300 --102,300 102,300 Revolving credit agreements 148,555 20,650 (19,788) 149,417 --Total long-term debt activity $ 1,972,951
$ 149,454 $ (174,861)
$ 1,947,544
$ 226,885 13. ASSET RETIREMENT OBLIGATIONS:
The District has recorded an obligation for the fair value of its legal liability for the ARO associated with CNS, various ash landfills at its two coal-fired power stations, removal of asbestos at the District's various coal, gas, and hydro generating facilities, polychlorinated biphenyls from substation and distribution equipment, and underground storage tanks as well as abandonment of water wells. The total ARO liability recorded by the District was $977.1 million and $930.2 million as of December 31, 2013 and 2012, respectively, and is included in the Other Long-Term Liabilities section of the accompanying Balance Sheets.29 NI-.1RASKA PBIX Powiý i~w~
The following table shows costs as of January 1, and charges to the ARO that occurred during the years ended December 31, 2013 and 2012, and are included in Deferred Credits and Other Liabilities section of the accompanying Balance Sheets as of December 31, (000's): For the Year Ended December 31, 2013 2012 Balance, beginning of year $ 930,178 $ 885,529 Accretion 46,904 44,649 Balance, end of year $ 977,082 $ 930,178 A significant amount of the ARO is funded by decommissioning funds of $533.7 million and $543.4 million as of December 31, 2013 and 2012, 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 the ARO existing at the time of adoption of ASC 410, the statement requires capitalization of costs at the level that existed at the time of incurring the liability.
These capitalized costs are depreciated over the same period as the related asset. At the date of adoption, the depreciation expense for past periods was recorded as a regulatory asset in accordance with ASC 980 because the District will be able to recover these costs in future rates.The initial liability is accreted to its present value each period. The District defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers.
Accretion was $46.9 million and $44.6 million for 2013 and 2012, respectively.
: 14. PAYMENTS IN LIEU OF TAXES: The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District.
Such payments totaled $10.1 million and $9.7 million for the years ended December 31, 2013 and 2012, respectively.
: 15. 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, 2013, there were 1,996 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$12.0 million for 2013 and 2012 of which $1.3 million and $1.2 million was accrued and in Accounts payable and accrued liabilities for each of the years ended December 31, 2013 and 2012, respectively.
: 16. 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.N -.RA K PU LC P w i i TI C 30 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 Statement
: 45. 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, 2013 2012 2011 Annual required contribution
$ 35,030 $ 33,627 $ 33,330 Interest on net OPEB obligation 5,583 4,658 4,614 Adjustment to annual required contribution (5,191) (4,170) (4,009)Annual OPEB cost 35,422 34,115 33,935 Contributions made (23,603) (15,620) (21,018)Increase in net OPEB obligation 11,819 18,495 12,917 Net OPEB obligation
-beginning of year 111,656 93,161 80,244 Net OPEB obligation
-end of year $123,475 $ 111,656 $ 93,161 The District's annual OPEB cost, the percentage of annual OPEB cost contributed to the plan, and the net OPEB obligation for 2013, 2012, and 2011 were as follows (dollar amounts in thousands):
Annual Percentage of Annual Net OPEB Year OPEB Cost OPEB Cost Contributed Obligation 2013 $ 35,422 66.6% $123,475 2012 $ 34,115 45.8% $111,656 2011 $ 33,935 61.9% $ 93,161 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 2013 were $23.6 million which included $10.0 million paid to the trust and $13.6 million for the cost of benefits.
Total contributions to the plan in 2012 were $15.6 million which included $4.0 million paid to the trust and $11.6 million for the cost of benefits.
Total contributions to the plan in 2011 were $21.0 million which included $10.0 million paid to the trust and $11.0 million for the cost of benefits.
It is currently projected that funding above the pay-as-you-go amount will remain at $10.0 million in 2014. The final funding will be determined annually by the District's Board of Directors.
The trust is currently projected to be fully funded by 2033.31 N1:3RASKAPUBLI POA I.-, i'ii The Actuarial Accrued Liability
("AAL") is the present value of benefits attributable to past accounting periods.The AAL was $520.7 million, $498.5 million, and $427.7 million as of January 1, 2013, 2012, and 2011, 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)2013 $ 30,781 $ 520,705 $ 489,924 5.9% $ 187,378 261%2012 $ 24,900 $ 498,485 $ 473,585 5.0% $ 189,211 250%2011 $ 15,086 $ 427,709 $ 412,623 3.5% $ 189,428 218%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 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, 2012 actuarial valuation, which is the most recent actuarial study, the Unit Credit Actuarial Cost method was used for 2013, 2012, and 2011. In 2013, the actuarial assumptions included an annual healthcare cost trend rate of 8.5% initially, reduced by decrements to an ultimate rate of 4.6%. In 2012, the actuarial assumptions included an annual healthcare cost trend rate of 8.1% initially, reduced by decrements to an ultimate rate of 4.6%. In 2011, the actuarial assumptions included an annual healthcare cost trend rate of 7.2%initially, reduced by decrements to an ultimate rate of 4.4%. The discount rate used for 2013 and 2012 was 5.0%and for 2011 was 5.75%. The discount rate 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, 2012. 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 was $48.3 million, $31.7 million, and $24.9 million at December 31, 2013, 2012, and 2011, respectively.
: 17. COMMITMENTS AND CONTINGENCIES:
A. Fuel Commitments
-The District has various coal supply contracts and a coal transportation contract with minimum future payments of $520.0 million. These contracts expire at various times through the end of 2018. The coal transportation contract is in place sufficient to deliver coal to the generation facilities through the expiration date of the aforementioned contracts and is subject to price escalation adjustments.
B. Power Purchase and Sales Agreements
-The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately
$36.7 million. These purchases are subject to rate changes.N1:13ASKAPUBLC Po iizDsrc 3 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. The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs, and reserves related to NC2 as a result of a defaulting power purchaser.
The District's obligation pursuant to such step-up provision is limited to 160% of its original participation share (23.7%).The District has entered into a power purchase agreement with Central for the purchase of the net power and energy produced by the Kingsley Project during its operating life. The Kingsley Project is a hydroelectric generating unit at the Kingsley Dam in Keith County, Nebraska with an accredited net capacity of 36 MW.The District had 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 was 54 MW. This agreement 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 participation power sales agreement with KCP&L Greater Missouri Operations Company ("KCPL") for the sale to KCPL of 75 MW of accredited capacity from CNS through January 18, 2014.The District had 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. This agreement was not renewed.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 50 MW from January 1, 2011 through December 31, 2023.As of December 31, 2013, the District had entered into power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities.
The District has entered into power sales agreements to sell 155 MW of this capacity to four other utilities in Nebraska over similar terms.In addition, the District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities.
The District has entered into a 25-year power purchase agreement with Steele Flats Wind Project, LLC to purchase electric power from the 75 MW Steele Flats Wind Facility near Steele City, Nebraska which began commercial operation on November 1, 2013. The District is required to take all the capacity and energy of the Steele Flats Wind Facility for the first twenty years of operation and one percent of the capacity and energy for the remaining five years.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% 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 is aware that four wholesale customers located in northeast Nebraska have made requests for proposals from power suppliers other than the District.
These customers currently represent 3% of Operating Revenues.
At this time, the District has received notice from three of the respective customers as to their intent to level off or reduce the requirements under their current contract beginning in 2019. If a substantial number of wholesale customers begin leveling off or reducing their requirements, the District would be required to increase its rates to recover costs.The District has entered into long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO Agreements expire on various dates between January 1, 2016 and May 1, 2033. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreement.
33 ~ ~~~ NE1RSAPmi o i-i Dsrur C. Transmission Agreements
-The District is 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 was able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost, through February 2014. On March 1, 2014, SPP successfully implemented its integrated market.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 $6.1 million as of December 31, 2013.The District entered into a second Transmission Facilities Construction Agreement effective July 17, 2009, with TransCanada Keystone XL Pipeline, LP ("Keystone XL"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. The initial estimated cost of the project was $52.9 million and was to be paid by Keystone XL over a ten-year period anticipated to begin July 2013. However, the project was recently delayed due to routing concerns of the pipeline across the Nebraska Sandhills.
Adjustments to the facilities, project costs, and completion schedules will be made once the final route is determined, which is unknown at the present time. Keystone XL remains responsible for all present and future project costs. As of December 31, 2013, actual project costs totaled $12.2 million.D. Cooper Nuclear 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 $127.3 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation, with a maximum assessment of $19.0 million per year per incident per unit owned. To satisfy this potential obligation, the District has submitted its most recent audited financial statements to the Nuclear Regulatory Commission
("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. As of December 31, 2013, CNS was in the Licensee Response Column, which is the first or best of the five NRC defined performance categories and has been in this column since the first quarter of 2012.Since the earthquake and tsunami of March 11, 2011, that impacted the Fukushima Dai-ichi Plants in Japan, the District, as well as the rest of the nuclear industry, has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the GE boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities.
CNS utilizes this same containment system; however, significant improvements to the design have been made over the life of the plant.A NRC Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12, 2011 that included 12 recommendations for improvements for U.S. reactors.
Subsequent to that report, on October 18, 2011, the NRC approved seven of the Task Force recommendations for implementation.
On March 12, 2012, the NRC issued three orders to the U.S. nuclear industry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nuclear plant operators of boiling water reactors like CNS to upgrade an existing wetwell vent. On June 6, 2013, the NRC issued an order to require the addition of a drywell vent to supplement the capabilities of this existing wetwell vent. This work is required to be completed no later than the conclusion of the fall 2018 refueling and maintenance outage or December 31, 2018, whichever comes first. The NRC continues to evaluate the possibility of requiring licensees to add a filter for both vents. The third order requires nuclear plant operators to add reliable spent fuel pool water level instrumentation.
The NRC has also issued a request for information pertaining to re-evaluation of seismic and flooding hazards, and a communications and staffing assessment for emergency preparedness.
I NI:131"ASKA PUBLICPxrzDsiw 3
These actions are to be completed no later than prior to startup from CNS's fall 2016 refueling and maintenance outage or December 31, 2016, whichever comes first. Additional NRC orders and regulations resultant from the Fukushima Dai-ichi event may be forthcoming.
The specific impacts of any additional orders and regulations on CNS have not yet been evaluated.
The District's preliminary cost estimate for modifications and other mitigation strategies associated with NRC's Fukushima Dai-ichi-related orders, including any potential modifications associated with increased requirements to add a filter on the new containment vents, is currently estimated to cost $78.1 million.In October 2003, the District entered into an agreement (the "Entergy Agreement")
for support services at CNS with Entergy Nuclear Nebraska, LLC ("Entergy"), a wholly-owned indirect subsidiary of Entergy Corporation.
The Entergy Agreement was for an initial term ending January 18, 2014, subject to either party's right to terminate without cause by providing notice and paying a termination charge. The agreement was subsequently extended, effective January 1, 2010, to January 18, 2029. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services, and to pay Entergy annual management fees. These annual management fees were $17.4 million and $17.3 million for 2013 and 2012, respectively.
In 2014, the annual management fee is$18.4 million. Entergy is eligible to earn additional annual incentive fees in an amount not to exceed $4.0 million annually if CNS achieves identified safety and regulatory performance targets. Entergy earned additional incentive fees of $2.3 million, $0.8 million, and $0.3 million for 2013, 2012, and 2011, respectively.
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.
CNS completed construction of a dry cask used fuel storage facility to support 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. A second fuel loading campaign to move used fuel into an additional ten dry used fuel storage casks is planned to begin in the spring of 2014.On November 29, 2010, the NRC formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until January 18, 2034. The issuance of this certificate by the NRC marked the culmination of the six-year effort to reach this milestone.
On January 18, 2014, CNS entered the period of extended operation beyond the initial 40-year operating license term.As part of a 1989 settlement of various disputed matters between GE and the District, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility.
After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.
As a result of the failure of the Department of Energy ("DOE") to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 2001. In accordance with a settlement agreement between the District and the DOE that was executed on May 18, 2011, the District has received $87.4 million from the DOE for damages from 2009 through 2012. The settlement agreement addresses future claims through 2013. On January 13, 2014, the DOE extended the settlement agreement through 2016.The District also reserves the right to pursue future damages through the contract claims process. A corresponding deferred credit for these DOE receipts has been established in Settlement reimbursement of the Deferred Inflows of Resources section of the accompanying Balance Sheets. The District plans to use the funds to pay for future costs related to CNS.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 and April 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
("NOV") under 35 ~ ~~~~~ Ni1RSAPmi oriý i-i Section 113(a)(1) of the Clean Air Act 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 February 16, 2012, the EPA issued a final rule intended to reduce emissions of toxic air pollutants from power plants. Specifically, the Mercury and Air Toxics Standard Rule will require reductions in emissions from new and existing coal- and oil-fired steam utility electric generating units of heavy metals, including mercury, arsenic, chromium, and nickel, dioxins, furans, and acid gases, including hydrogen chloride and hydrogen fluoride.
These toxic air pollutants are also known as hazardous air pollutants.
Facilities will have until April 16, 2015 to comply with the rule with some opportunity for an additional year to achieve compliance.
The District expects to meet the new emissions limits with its existing pollution control equipment and the installation of activated carbon injection equipment at GGS and Sheldon. Capital costs for such equipment are estimated to be$7.0 million with annual operation and maintenance costs estimated to be $3.0 million.Any changes in the environmental regulatory requirements imposed by federal or state law which are applicable to the District's generating stations could result in increased capital and operating costs being incurred by the District.
The District is unable to predict whether any changes will be made to current environmental regulatory requirements, if such changes will be applicable to the District and the costs thereof to the District.On August 19, 2002, the District received notice from the EPA identifying the District as a Potentially Responsible Party ("PRP") for liability associated with a former Manufactured Gas Plant ("MGP") located in Norfolk, Nebraska.
The District is identified as a current owner of property located adjacent to the Norfolk MGP operations.
In 2002, the EPA asked identified PRPs to participate in negotiations for completing an Engineering Evaluation/Cost Analysis ("EE/CA").
The identified PRPs met with the EPA Region 7 in October 2002 to discuss the site. No other 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. On July 17, 2012, the EPA approved the final EE/CA.Remediation under the preferred alternative is estimated to cost $2.8 million. In early 2013, the EPA contacted the PRPs to begin efforts to put in place an Administrative Order of Consent for completion of the selected remedial action. The District negotiated a settlement agreement with Centel (formerly known as Sprint) whereby the District would allow access and use of portions of District property and the District would pay a one-time settlement amount. The settlement does not have a material effect on the District.
Centel agreed to the settlement terms and the EPA also approved the agreement.
The settlement agreement was signed by the District on August 1, 2013 and payment was made on August 9, 2013.F. Other -The District received written notice from the Internal Revenue Service (the "Service")
that the Service had concluded that certain of the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) did not qualify for the 35% interest subsidy provided by the United States Treasury based on an interpretation by the Service of the issue price of such Bonds to the public. While the District disagreed with the conclusion of the Service, the District has agreed to resolve the matter by entering into a closing agreement with the Service and paying $350,000 to the Service pursuant to the closing agreement.
Based on the closing agreement, the District may continue to claim credits with respect to the interest paid on the 2009 Series A Bonds and the Service has agreed not to contest such credits on the basis of the Service's conclusions referred to above.In October 2013, the Service affirmed, pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, that the 35% interest subsidy provided by the United States Treasury on the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds), will be reduced by 7.2%. This reduction in the interest subsidy will be applied to the N113ASA U11-C ow--z isriiu 3 Service payments made on or after October 1, 2013 through September 30, 2014, or intervening Congressional action, at which time the reduction rate is subject to change. This loss of subsidy totals approximately
$0.2 million.In March 2013, the District initiated a voluntary early retirement incentive program ("program")
to all regular, full-time employees, excluding senior management, who meet certain retirement-eligible criteria.
Approximately 575 District employees were eligible for the program and 110 District employees accepted the offer. Their last day of employment was no later than June 30, 2013. Those employees who participated in the program received six months of salary in one, lump sum payment. Total cost of the program was $6.0 million.18. 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, 2013.1 37 N:13RAKA Pu -ic Pwviý ISTi
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