NLS2010068, Licensee Guarantees of Payment of Deferred Premiums
| ML102070107 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 07/20/2010 |
| From: | Vanderkamp D Nebraska Public Power District (NPPD) |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NLS2010068 | |
| Download: ML102070107 (39) | |
Text
N Nebraska Public Power District Always there when you need us NLS2010068 140.21 July 20, 2010 Attention: Document Control Desk Director, Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D.C. 20555-0001
Subject:
Licensee Guarantees of Payment of Deferred Premiums Cooper Nuclear Station, Docket No. 50-298, DPR-46
Dear Sir or Madam:
The purpose of this letter is to transmit information in accordance with the requirements of 10 CFR Part 140.21, relative to deferred insurance premiums, for the Nebraska Public Power District (NPPD). NPPD believes this information demonstrates our ability to obtain funds in the amount of $17.5 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 2009 Financial Report is enclosed for your review. This report is NPPD's audited financial statement. Please refer to Page 13 of the enclosure where the Balance Sheet of NPPD is listed. Cash and investments of NPPD total over $900 million as indicated on Page 20, 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 $193.7 million as of December 31, 2009.
Also on Page 13 of the enclosure, under the heading "Long-Term Debt," there is a line item titled "Commercial paper notes" in the amount of $234.2 million. As noted on Page 26, Note 9 of the enclosure, NPPD is authorized to issue up to $200 million of taxable commercial paper notes and up to $150 million of tax-exempt commercial paper notes, which make up NPPD's Commercial Paper Program. As of December 31, 2009, NPPD had remaining capacity in its Commercial Paper Program of $115.8 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 2010, will be submitted no later than July 31, 2011.
COOPER NUCLEAR STATION 0 P.C. Box 98 / Brownville, NE 6832 1-0098 Telephone: (402) 825-3811 / Fax: (402) 825-52711 ww.nppd~com j(L4C
NLS2010068 Page 2 of 2 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 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
4 ATTACHMENT 3 LIST OF REGULATORY COMMITMENTS© ATTACHMENT 3 LIST OF REGULATORY COMMITMENTS© Correspondence Number: NLS2010068 The following table identifies those actions committed to by Nebraska Public Power District (NPPD) in this document. Any other actions discussed in the submittal represent intended or planned actions by NPPD. They are described for information only and are not regulatory commitments. Please notify the Licensing Manager at Cooper Nuclear Station of any questions regarding this document or any associated regulatory commitments.
COMMITMENT COMMITTED DATE COMMITMENT NUMBER OR OUTAGE None PROCEDURE 0.42 REVISION 24 PAGE 18 OF 25
NLS2010068 Enclosure ENCLOSURE NEBRASKA PUBLIC POWER DISTRICT 2009 FINANCIAL REPORT COOPER NUCLEAR STATION DOCKET NO. 50-298, DPR-46
2009 FINANCIAL Statistical Review I Management's Discussion and Analysis 2 Report of Independent Auditors 12 Financial Statements 13 Notes to Financial Statements 17
ýý @T ý) W [ýý 1ýs 12 &S CT 1_ý @ I LM~1@~
KILOWATT-HOUR SALES 19.5 BILLION OPERATING REVENUES 863.4 MILLION COST OF POWER PURCHASED AND GENERATED 505.3 MILLION OTHER OPERATING EXPENSES 291.6 MILLION INCREASE IN FUND EQUITY 16.2 MILLION DEBT SERVICE COVERAGE 1.69
2009 STATISTICAL REVIEW Revenues from Average Electric Energy Electric Sales Number of MWh Sales (000's) Revenue SALES Customers Amount % Amount % Per kWh Retail:
Residential 68,501 810,711 4.1 $ 76,086 8.8 9.390 Rural and Farm 3,083 72,306 0.4 5,982 0.7 8.270 Commercial 14,912 909,328 4.7 68,534 7.9 7.540 Industrial 53 1,026,062 5.3 52,237 6.0 5.090 Public Lighting 195 18,976 0.1 2,175 0.3 11.460 Municipal Power 183 26,568 0.1 1,981 0.2 7.460 Miscellaneous Municipal 1,967 132,825 0.7 7,377 0.9 5.550 Total Retail Sales 88,894 2,996,776 15.4 214,372 24.8 7.150 Wholesale:
52 Municipalities (Total Requirements) 1,952,736 10.0 92,625 10.7 4.740 25 Public Power Districts and Cooperatives (Total Requirements) 7,093,214 36.3 314,988 36.5 4.440 Total Wholesale Sales (Excluding Sales to LES, MEC, and Other Utilities) 9,045,950 46.3 407,613 47.2 4.510 Total Retail and Wholesale Sales (Excluding Sales to LES, MEC, and Other Utilities) 12,042,726 61.7 621,985 72.0 5.16¢ LES and MEC(1' 3,243,998 16.6 77,307 9.0 2.380 Other Utilities (Nonfirm and Other Sales) 4,230.944 21.7 123.711 14.3 2.92d Total Electric Enerav Sales 19.517.668 100.0 823,003 95.3 4.22¢ Other Operating Revenues (Net of Deferred) 40,395 4.7 Total Operating Revenues $ 863,398 100.0 Production MWh Costs (000's)
GENERATION Amount % Amount %
Production (Including Interchange) 18,000,409 88.2 $414,344 82.0 Power Purchased 2,411,311 11.8 90,934 18.0 Total Power Produced and Purchased 20,411,720 100.0 $ 505,278 100.0 (1) Sales to Lincoln Electric System ("LES") include power and energy produced at Nebraska Public Power District's Gerald Gentleman Station and Sheldon Station. Sales to MidAmerican Energy Company ("MEC")
are for power and energy produced at Cooper Nuclear Station.
Miles of Transmission and Subtransmission Line in Service 5,124 Number of Employees 2,288 2009 Contractual and Tax Payments (000's):
Payments to Retail Communities $ 19,965 Payments in Lieu of Taxes $ 7,576 Hydro & Renewable Purchases SOURCES OF ENERGY - 2009 (5.0%) (9.0%)
For service to retail and to total Gas & Oil requirements wholesale customers (1.3%)
(excludes sales to Other Utilities and Coal LES and MEC). (64.0%)
Nuclear (20.7%)
1 NEBRASKA PUBLIC POWFR DisTRICT
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 13.
OVERVIEW OF BUSINESS Nebraska Public Power District (the "District") operates an integrated electric utility system including facilities for generation, transmission, and distribution of electric power and energy for sales to wholesale and retail customers. The District is a summer peaking utility. An all-time system summer peak demand of 2,671 MW was established in July 2006 for the District's firm requirements customers. The District's all-time winter peak demand is 2,219 MW, which was established in December 2009. The District owns or has operating control over 37 generating plants, which had a combined accredited capacity during the summer of 2009 of 3,154.2 MW.
GENERATION PLANTS Summer 2009 Number of Accredited Percent of Type: Plants(1 ) Capability (MW) Total Coal - Gerald Gentleman Station 1 1,365.0 43.3 Coal - Sheldon Station 1 225.0 7.1 Gas - Beatrice Power Station 1 237.0 7.5 Gas/Oil - Canaday Station 1 118.0 3.8 Nuclear - Cooper Nuclear Station 1 774.1 24.5 Hydro 9 164.8 5.2 Diesel 19 105.5 3.3 Combustion Turbine 3 153.0 4.9 Wind 1 11.8 0.4 37 3,154.2 100.0 (1) Includes six hydro plants and 17 diesel plants under contract to the District.
In addition to the above generating plants, the District purchases 450.5 MW of firm power from the Western Area Power Administration and other capacity and energy on both a short-term and nonfirm basis in the wholesale energy market. The District had other capacity purchases of 161.4 MW from Omaha Public Power District's
("OPPD") Nebraska City Station Unit 2 ("NC2") coal-fired plant and 6.8 MW from the Elkhorn Ridge Wind Farm.
Of the total capacity resources, 747.3 MW are being sold via participation sales or other capacity sales agreements. The District owns and operates 5,124 miles of transmission and subtransmission lines, encompassing the entire State of Nebraska.
The District's customer base for firm energy sales consists of approximately 88,900 retail customers plus 77 municipalities, public power districts, and cooperatives that are total requirements wholesale customers of the District. In addition, the District has several participation sale contracts in place with other utilities for the sale of power and energy at wholesale from specific generating plants. The District also sells energy on a nonfirm basis in the wholesale energy market.
ENERGY SALES (1)
Gigawatt Hours 20,000 15,000 7,066 7,156 7,157 6,718 7,475 10,000o 5,000 11,134 11,265 11,607 12,079 12,043 2005 2006 2007 2008 2009 Firm Energy Sales Additional Energy Sales (1) All years include the sale of energy to MidAmerican Energy Company from Cooper Nuclear Station.
CONDENSED BALANCE SHEETS 2009 2008 2007 Condensed Balance Sheets (000's):
Utility Plant, net $ 2,235,069 $2,123,284 $1,824,798 Special Purpose Funds 767,497 859,656 742,528 Current Assets 383,128 370,528 348,353 Deferred Charges and Other Assets 811,805 717,388 503,262 Total Assets $4,197,499 $ 4,070,856 $3,418,941 Fund Equity $ 899,866 $ 883,676 $ 857,617 Long-Term Debt 2,009,021 1,921,968 1,469,166 Current Liabilities 206,642 244,083 291,700 Deferred Credits and Other Liabilities 1,081,970 1,021,129 800,458 Total Fund Equity and Liabilities $4,197,499 $ 4,070,856 $ 3,418,941 CONDENSED RESULTS OF OPERATIONS 2009 2008 2007 Condensed Statements of Revenues, Expenses, and Changes in Fund Equity (000's):
Operating Revenues $ 863,398 $ 831,259 $ 780,693 Operating Expenses (796,904) (778,351) (715,051)
Operating Income 66,494 52,908 65,642 Investment and Other Income 31,860 48,789 53,190 Debt and Other Expenses (82,164) (75,638) (72,647)
Increase in Fund Equity $ 16,190 $ 26,059 $ 46,185 The sources of operating revenues were as follows (000's):
2009 2008 2007 Firm Sales - Wholesale and Retail $ 621,985 $ 574,339 $ 529,429 Participation Sales to LES and MEC 77,307 90,825 87,302 Sales to Other Utilities 123,711 124,937 127,296 Other Operating Revenue 31,304 28,121 28,037 Deferred Revenue 9,091 13,037 8,629 Total Operating Revenue $ 863,398 $ 831,259 $ 780,693 3 NEBRASKA PUBLIC POWER DISTRICT
Revenues From Firm Sales - Wholesale and Retail Revenues from firm sales increased $47.6 million, or 8.3%, from $574.3 million in 2008 to $622.0 million in 2009.
This increase is due primarily to 7.0% wholesale and 6.0% retail rate increases effective January 1, 2009, as a result of increased fuel and energy costs and other inflationary costs of operations. Revenues from firm sales increased $44.9 million, or 8.5%, from $529.4 million in 2007 to $574.3 million in 2008. This increase is due primarily to a 12.0% wholesale rate increase effective April 1, 2008, and a 5.3% retail rate increase effective May 1, 2008, as the result of increased fuel and energy costs, the reduced availability of prior year surplus revenues, and the increasing electrical demands on the System. The 2008 wholesale and retail rate increases coincided with the expiration of a 12-month Production Cost Adjustment ("PCA") charge, 2.9% wholesale and 1.7% retail, implemented in April and May 2007, respectively. The District used available prior year surplus revenues and the PCA to recover the replacement energy costs resulting from the December 2006 ice storms.
AVERAGE REVENUE PER kWh SOLD - RETAIL Cents per kWh (Retail - All Classes) 7.15 7.00 6.80 6.60 6.40 6.43 6.21 6.20 6.05 6.03 6.00 6 5.80 5.60 5.40 5.20 5.00 2005 2006 2007 2008 2009 AVERAGE REVENUE PER kWh SOLD - WHOLESALE (Firm Wholesale Customers Only)
Cents per kWh 4.51 4.40 4.201 4.16 4.00- 3.93 3.80- 3.73 3.74 3.60-3.40-3.20-3.00-2005 2006 2007 2008 2009 Revenues From Participation Sales to LES and MEC and Sales to Other Utilities During 2009, the District made participation sales to Lincoln Electric System ("LES") from the capacity and energy produced at Gerald Gentleman Station ("GGS") and Sheldon Station; to MidAmerican Energy Company ("MEC")
from Cooper Nuclear Station ("CNS"); to KCP&L from GGS and CNS; to Heartland Consumers Power District
("Heartland") from CNS; and to the Municipal Energy Agency of Nebraska ("MEAN") from GGS and CNS. The District also engaged in sales of energy with other utilities on a nonfirm basis.
Revenue from participation sales to LES and MEC decreased $13.5 million from $90.8 million in 2008 to
$77.3 million in 2009. The decrease is due primarily to LES's share of capital costs related to Sheldon Station being less in 2009 than in 2008, and a decrease of 4.8% in kilowatt-hour energy sales from CNS to MEC in 2009 from 2008 in addition to a decrease in the 2009 MEC contracted sales price. Revenue from participation sales to LES and MEC increased $3.5 million from $87.3 million in 2007 to $90.8 million in 2008. The increase is due primarily to LES's share of capital costs related to Sheldon Station being greater in 2008 than in 2007.
NEBRASKA PUBLIC POWER DISTRICT 4 .
Sales to other utilities consist of participation sales to KCP&L, Heartland, and MEAN and nonfirm off-system sales. The Energy Authority ("TEA"), of which the District is a member, has energy marketing responsibilities for the District's nonfirm off-system sales and the related management of credit risks. Sales to other utilities decreased from $124.9 million in 2008 to $123.7 million in 2009, a decrease of $1.2 million. This decrease is due primarily to lower market prices in 2009 than in 2008. Sales to other utilities.decreased from $127.3 million in 2007 to $124.9 million in 2008, a decrease of $2.4 million. This decrease is due primarily to a reduction in revenues realized from nonfirm off-system sales as the result of less excess generation being available to sell on the open market due to 2008 being a refueling year for CNS versus 2007 and increased firm energy sales in 2008 due to load growth.
Other Operating Revenue Other operating revenue consists primarily of transmission wheeling revenues and revenue from work for other utilities. These revenues were $31.3 million, $28.1 million, and $28.0 million in 2009, 2008, and 2007, respectively.
Deferred Revenue The District's wholesale and retail electric rates are established on a prospective basis. The estimated revenue requirements used to establish rates include operating expenses, excluding depreciation and amortization; debt service requirements on revenue bonds; payments of principal and interest on subordinated debt; amounts for capital projects to be paid from current revenues; and amounts for reserves to pay future costs, such as future nuclear facility decommissioning costs.
Under the provisions of the District's wholesale power contracts, if the rates for wholesale power service in any year result in a surplus or deficiency in revenues necessary to meet revenue requirements, such surplus or
'deficiency, within certain limits set forth in the wholesale power contracts, may be retained in a rate stabilization account. Any'amounts in excess of the limits will be included as an adjustment to revenue requirements in future rate periods. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities, such surpluses or deficiencies are accounted for as "regulatory assets or liabilities." The District follows this accounting treatment.
The District recognizes all revenues in excess of revenue requirements in any year as a deferral or reduction of revenues. Such surplus revenues are excluded from the net revenues available under the General Revenue Bond Resolution ("General Resolution") to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues, even though the revenue accrual will not be realized as "cash" until some future rate period.
Such revenue deficiency is included, in the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are excluded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates.
During 2009, actual revenue requirements exceeded firm wholesale and retail sales. During 2008 and 2007, revenues from firm wholesale and retail sales exceeded actual revenue requirements in each suchyear.
The District recognized or increased revenues a net amount of $9.1 million in 2009. The District's revenues in 2009 from firm wholesale and retail electric sales resulted in a deficiency, or under collection of costs, of
$4.3 million, which deficiency amount was accrued (increase in revenues). In addition, the wholesale and retail rates that were in place for 2009 included a refund of $4.8 million of surplus net revenues from past rate periods.
Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred.
Accordingly, the 2009 revenues from electric sales, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount.
5 NEBRASKA PUBLIC POWER DISTRICT
The District recognized or increased revenues a net amount of $13.0 million in 2008. The District's revenues in 2008 from firm wholesale and retail electric sales resulted in a surplus, or over collection of costs, of $3.8 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale and retail rates that were in place for 2008 included a refund of $16.8 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred. Accordingly, the 2008 revenues from electric sales, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount.
The District recognized or increased revenues a net amount of $8.7 million in 2007. The District's revenues in 2007 from firm wholesale and retail electric sales resulted in a surplus, or over collection of costs, of $42.1 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2007 included a refund of $50.8 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred. Accordingly, the 2007 revenues from electric rates, which reflect the surplus being refunded, are offset by a revenue adjustment (increase in revenues) for such amount.
As of December 31, 2009, 2008, and 2007, the District had $43.8 million, $52.9 million, and $65.9 million, respectively, of surplus deferred revenues yet to be applied as credits against revenue requirements in future rate periods. The District's wholesale and retail electric rates for 2010 include a collection of $7.2 million for previously deferred costs.
Operating Expenses Total operating expenses in 2009 were $796.9 million, an increase of $18.5 million from 2008. Total operating expenses in 2008 were $778.4 million, an increase of $63.3 million from 2007. The changes were due primarily to the following:
Purchased power and production fuel expenses were $259.0 million, $259.2 million, and $240.8 million in 2009, 2008, and 2007, respectively. These expenses remained consistent between 2009 and 2008. These expenses increased $18.4 million in 2008 as compared to 2007 due primarily to increased native load sales, increased nonfirm energy purchased due to a refueling outage at CNS, increased average nonfirm energy market prices, and higher fuel costs as a result of continued price increases in both coal and nuclear fuel and related transportation costs.
Production operation and maintenance expenses were $246.3 million, $241.5 million, and $191.2 million in 2009, 2008, and 2007, respectively. These costs increased $4.8 million in 2009 as compared to 2008 due primarily to outside contractor costs associated with CNS. These costs increased $50.3 million in 2008 as compared to 2007 due primarily to the costs associated with a planned refueling and maintenance outage at CNS in 2008 along with increases in materials and outside contractor costs associated with planned and unplanned outages at the District's other major base load generation facilities.
Transmission and distribution operation and maintenance expenses were $55.7 million, $47.8 million, and
$42.6 million in 2009, 2008, and 2007, respectively. These costs increased $7.9 million in 2009 as compared to 2008 due to additional vegetation management charges and the addition of the Southwest Power Pool ("SPP")
Market Administration monitoring and compliance services, along with other SPP fees, which were offset, in part, by additional other operating revenues. Additional increases are due to the acquisition of computer and communications equipment to meet certain North American Electric Reliability Corporation and SPP requirements. These costs increased $5.2 million in 2008 due to increased maintenance work being done as compared to 2007 when the District spent the first few months of the year rebuilding transmission and distribution lines damaged by the December 2006 ice storms. Additional increases are due to increased material costs.
Customer service and information expenses were $18.7 million, $16.8 million, and $15.6 million in 2009, 2008, and 2007, respectively. These costs increased $1.9 million in 2009 as compared to 2008 due to a full year of activity for the Energy Efficiency Program which was implemented in the fourth quarter of 2008. These expenses did not vary significantly from 2008 to 2007.
NEBRASKA PUBLIC POWER DISTRICT 6
Administrative and general expenses were $53.2 million, $48.8 million, and $47.1 million in 2009, 2008, and 2007, respectively. These costs increased $4.4 million in 2009 as compared to 2008 due primarily to less administrative and general costs being capitalized in 2009. These costs remained consistent between 2008 and 2007.
Decommissioning expenses were $25.8 million, $32.0 million, and $35.9 million in 2009, 2008, and 2007, respectively. Decommissioning expenses represent the net amount accrued each year for the future decommissioning of CNS. Such expenses are recorded in an amount equivalent to the interest income and market value changes of investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year. Decommissioning expenses decreased by
$6.2 million in 2009 as. compared to 2008 due to decrease in interest income on investments and no amount for decommissioning was collected through rates in 2009. Decommissioning expenses decreased by $3.9 million in 2008 as compared to 2007 due to decreases in interest income and market fluctuations in the value of investments.
To the extent that the accretion on the asset retirement obligation determined under ASC 410 is different from the total of amounts collected in rates and investment earnings on monies accumulated in the decommissioning funds, the District will defer that difference as a regulatory asset or liability to be recovered or refunded in future periods. Accretion for 2009, 2008, and 2007 was $46.2 million, $33.6 million, and $32.0 million, respectively, and decommissioning expense was $25.8 million, $32.0 million, and $35.9 million, respectively.
Depreciation and amortization expenses were $110.7 million, $106.5 million, and $116.6 million in 2009, 2008, and 2007, respectively. These expenses increased $4.2 million in 2009 as compared to 2008 due primarily to the amortization of the NC2 prepaid power purchase and prepaid transmission costs beginning in May 2009. These expenses decreased $10.1 million in 2008 as compared to 2007 due primarily to the submission of the CNS 20-year license extension in September 2008 at which time the District reevaluated all assets associated with CNS and revised their remaining useful lives accordingly. This change was effective January 1, 2008.
Increase in Fund Equity The increase in fund equity (net revenues) was $16.2 million in 2009, $26.1 million in 2008, and $46.2 million in 2007. The decrease in fund equity of $9.9 million in 2009 as compared to 2008 reflects, primarily, an increase in unrealized losses of the District's investments and an increase in depreciation expense offset, in part, by increased revenue requirements used to establish rates for 2009. The decrease in fund equity of $20.1 million in 2008 as compared to 2007 reflects decreases in revenue requirements used to establish rates for 2008 for the purpose of decreased investment in facilities from current year revenues and decreased commercial paper principal payments offset, in part, by an increase in bond principal payments. In addition, there was a decrease in depreciation expense in 2008.
CAPITAL REQUIREMENTS The District's Board of Directors ("Board") authorized capital projects totaling approximately $186.9 million in 2009, $357.6 million in 2008, and $270.7 million in 2007. The amount for 2009 included an additional supplement of $19.3 million for the dry cask fuel storage system at CNS, $17.2 million for the security facility modification at CNS, $16.1 million for replacement of four feedwater heaters at CNS, $12.8 million for Phase I of the installation of a statewide radio system, and $12.5 million for the first campaign to move spent nuclear fuel from the cooling pool to the storage pad. The amount for 2008 included $147.0 million for Phase II of the Electric Transmission Reliability ("ETR") Project, $41.9 million for the purchase of several transformers, $17.2 million for a new water treatment and discharge system at Sheldon Station, $18.7 million for a new all-purpose operations facility in Norfolk, Nebraska, and $9.6 million for replacement of Unit 1 cooling towers at Sheldon Station. The amount for 2007 included $57,0 million for the reconstruction of transmission and distribution lines as the result of the severe 2006 year-end ice, wind, and snow storms, $26.4 million for the purchase of several transformers, $25.0 million for Phase II of the installation of a dry cask fuel storage system at CNS, $22.9 million for additions to the Hoskins and Shell Creek substations as part of Phase I of the ETR Project, and $18.0 million for a reheater replacement at GGS. The remaining capital projects authorized in 2009, 2008, and 2007, which totaled $109.1 million,
$123.2 million, and $121.4 million, respectively, were primarily for renewals and replacements to existing facilities 7 NEBRASKA PUBLIC POWER DISTRICT
and other minor additions and improvements. The District's Board approved budget for capital projects for 2010 is
$348.2 million, which includes $45.4 million for construction of transmission lines and substations related to the TransCanada Keystone XL Pipeline Project, $35.6 million for construction of transmission lines and substations related to the South Sioux City Expansion Project, $25.0 million for the replacement of a high pressure turbine at CNS, $21.7 million for replacement of four main power transformers at CNS, $10.8 million for dry cask fuel loading campaign No.2 at CNS, and $10.8 million for replacement of Unit 2 cooling towers at Sheldon Station.
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.
FINANCING ACTIVITIES The District had $1.843 billion (par amount) of outstanding revenue bonds at December 31, 2009, as compared to
$1.756 billion (par amount) at December 31, 2008, and $1.515 billion (par amount) at December 31, 2007. The revenue bonds outstanding are at fixed interest rates and were issued at premiums or discounts. The District had outstanding $117.0 million of tax-exempt commercial paper ("TECP") notes at December 31, 2009, $92.0 million at December 31, 2008, and $83.6 million at December 31, 2007. Also, the District had outstanding $117.2 million of taxable commercial paper ("TCP") notes at December 31, 2009, $121.3 million at December 31, 2008, and
$34.1 million at December 31, 2007. Both the TECP notes and the TCP notes have a bank credit agreement, each expiring August 1, 2011, maintained to support the sale of the commercial paper notes.
In June 2009, the District issued $50.4 million of taxable revenue bonds (BuildAmerica Bonds) and $17.9 million of tax-exempt revenue bonds for certain generation and other transmission capital additions. Also in June 2009, the District issued $100.0 million of taxable revenue bonds to advance refund $69.5 million of TCP notes and to provide $28.4 million for certain capital additions at CNS.
In March 2008, the District issued $137.8 million of taxable revenue bonds to advance refund $93.7 million of taxable revenue bonds issued in 2007 and to refund $43.1 million of taxable commercial paper notes used to redeem the taxable revenue bonds issued in 2004. In September 2008, the District issued $332.2 million of tax-exempt revenue bonds at a net premium to provide $148.0 million for the remaining cost of the ETR Project, to provide $80.0 million for certain generation and other transmission capital additions, to refund $57.0 million of TECP notes that were issued to pay for costs associated with the December 2006 ice storms, the purchase of several transformers and other capital additions, and to provide $26.0 million for the District's remaining share of the OPPD NC2 coal-fired generating plant and associated, transmission facilities. Under the terms of a power purchase agreement with OPPD, the District is receiving 23.7% of the output of NC2, approximately 161 MWs since it began commercial operation on May 1, 2009.
In February 2007, the District issued $93.7 million of taxable auction rate revenue bonds for the purpose of funding the cost of various capital projects at CNS. In September 2007, the District issued $311.8 million of tax-exempt revenue bonds at a net premium to advance refund $210.0 million of bonds, to provide $25.0 million for Phase I of the ETR Project, and to provide $76.5 million for certain generation and transmission capital additions. The refunded bonds represent a portion of the bonds issued in 1998 with maturities from January 1, 2010 through January 1, 2028. The refunding will result in debt service savings to the District of $10.8 million during the period September 2007 through December 2027.
The District retired $81.2 million, $82.6 million, and $78.1 million of General System Revenue Bonds in 2009, 2008, and 2007, 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)
NEBRASKA PUBLIC POWER DISTRICT 8
DEBT SERVICE COVERAGE The District's debt service coverage was 1.69 in 2009, 1.59 in 2008, and 1.74 in 2007. The coverage is provided primarily by the amounts collected in operating revenues to fund thecost of utility plant additions, the amounts collected in operating revenues for principal and interest payments on the outstanding commercial paper notes, and the amounts collected in operating revenues to fund the cost of payments made to those municipalities served by the District under long-term Professional Retail Operating Agreements. The District has established a goal in its planning process to maintain a debt service coverage of approximately 1.5 times annual debt service.
CNS FUTURE OPERATION Cooper Nuclear Station is currently licensed to operate until January 2014., In November 2004, the Board approved a recommendation by management to proceed with the process to seek approval from the Nuclear Regulatory Commission ("NRC") to extend the operating license of CNS to 2034. The application was submitted to the NRC in September 2008. The NRC notified the District in December2008 that the application was considered acceptable for NRC review. The NRC's review of the license renewal application is proceeding as planned. The District is also evaluating the potential for an Extended Power Uprate of CNS.
The District entered into an agreement for support services at CNS with Entergy Nuclear Nebraska, LLC, a wholly-owned indirect subsidiary of Entergy Corporation, in October 2003. The Entergy Agreement was for an initial term ending January 18, 2014. The agreement was subsequently extended, effective January 1, 2010, to January 18, 2029. The agreement requires the District to reimburse Entergy's costs of providing services and to pay Entergy annual management fees. Since 2007, Entergy has been eligible to earn additional incentive fees if CNS achieves identified safety and regulatory performance targets during each such year.
The District entered into a power sales contract with MEC to provide 250 MW of capacity and'energy from January 1, 2005 until December31, 2009. This contract was not renewed. The District also entered into agreements for the sale of capacity and energy from CNS to Heartland, to KCP&L, and to MEAN. The Heartland agreement provides for delivery of capacity and energy beginning on January 1, 2004, and terminating on December 31, 2013, in amounts ranging from 5 MW up to 45 MW. The KCP&L agreement provides for delivery of 75 MW of capacity and energy from January 1, 2005 until January 18, 2014. The MEAN agreement, amended on July 1, 2008, provides for delivery of capacity and energy beginning July 1, 2008, and terminating on April 30, 2014, of 95 MW, of which 60% will be provided from CNS and 40% from GGS. If CNS is removed from commercial operation or off-line continuously for six months, the associated energy will be supplied from GGS. If Whelan Energy Center 2, in which MEAN has an ownership interest, begins commercial operation prior to April 30, 2014, either the District or MEAN has the right to reduce delivery by up to 50 MW.
RESOURCE PLANNING The District increased its base load resources when OPPD's NC2 coal-fired plant began commercial operation on May 1, 2009. The District's share of this facility is 161.4 MW. With this addition to its already diverse power resource mix, and with various capacity and energy contracts between 2009 and 2014, the District is well positioned to meet its firm load requirement needs for the next 12 to 15 years. The District also continues to focus on the (i) addition of renewables, (ii) effectiveness of energy efficiency programs, (iii) evaluation of additional peaking capacity, and (iv) evaluation of a CNS power uprate.
In February 2008, the District entered into a 20-year power purchase agreement with Elkhorn Ridge Wind, LLC to purchase electric power from the 80 MW Elkhorn Ridge Wind Farm developed near Bloomfield, Nebraska, which became commercially operational March 1, 2009. The District has entered into agreements to sell one-half of the capacity of this project to other utilities in Nebraska. The District also entered into a 20-year power purchase agreement with Community Wind Energy Transmission, LLC to purchase electric power from the 42 MW Crofton Hills Wind Farm planned for development in 2010 or 2011 near Crofton, Nebraska. Construction of this facility has not yet commenced. The District will pay only for energy delivered pursuant to such agreements and the cost of substation and transmission work to connect these projects to the District's electric system. The District does not currently expect to fund the cost of any such projects or guarantee any indebtedness with respect thereto.
9NEBRASKA PUBLIC POWER DISTRICT
In February 2010, the District entered into a 20-year power purchase agreement with Laredo Ridge Wind, LLC to purchase electric power from the 80 MW Laredo Ridge Wind Farm being developed near Petersburg, Nebraska, which is scheduled to begin commercial operation on December 1, 2010. The District is in discussion with other Nebraska utilities regarding their interest in purchasing output from the project. The District also is negotiating to enter into a 20-year power purchase agreement with Broken Bow, LLC to purchase electric power from an 80 MW wind farm planned for development near Broken Bow, Nebraska, which is scheduled to begin commercial operation in September 2012. Construction of this facility has not yet commenced. The District will pay only for energy delivered pursuant to such agreements and the cost of the substation and transmission work to connect these projects to the District's electric system. Participating utilities will pay their pro rata share of capital additions.
ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks, including exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the creditworthiness of its counterparties, and the operational risks associated with transacting in the wholesale energy markets.
To help manage energy risks, the District relies upon TEA to both transact on its behalf in the wholesale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets. TEA combines a strong knowledge of the District's system, an in-depth understanding of the wholesale energy markets, experienced people, and state-of-the-art technology to deliver a broad range of standard and customized energy products and. services to the District.
TEA has assisted the District in developing its Energy Risk Management ("ERM") program and associated ERM Governing Policy ("Policy"). The Policy, approved by the Board, establishes guidelines and objectives and delegation of authorities necessary to govern activities related to the District's energy risk management program.
The objective of the program is to increase fuel and energy price stability by hedging the risk of significant adverse impacts to cash flow. These adverse impacts could be caused by events such as natural gas or power price spikes or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed.
On April 1, 2009, the District became a member of the Southwest Power Pool ("SPP"), a regional transmission organization based in Little Rock, Arkansas. Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration, including generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning. The District will be able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost.
-ECONOMIC FACTORS The national economic slowdown has not had a significant impact on the District's native electrical demand. The Midwest region has experienced increased unemployment, but remains far below the national averages.
Nebraska's unemployment rate rose from an average of 3.3% for 2008-to an average of 4.6% for 2009, compared to the national average unemployment rate of 9.3%. Nebraska's seasonally adjusted unemployment rate was 4.6% in December 2009 and 3.9% in December 2008, compared to the national seasonally adjusted unemployment rate of 10.0% and 7.4% in 2009 and 2008, respectively. For December 2009, the unemployment rate in Nebraska was second lowest in the nation. The District continues to monitor changes in national and global economic conditions, as these could impact cost of debt and access to capital markets.
The District has not seen a significant increase in its uncollectible customer accounts compared to 2008.
COMMITMENTS AND CONTINGENCIES The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and aplilicable cost recovery for the interconnection and delivery facilities NEBRASKA PUBLIC POWER DISTRICT 10
required for the interconnection of Keystone to the District's transmission system. Estimated cost of the project is
$8.4 million and is to be paid by Keystone over a ten-year period beginning in June 2010.
The District entered into a second Transmission Facilities Construction Agreement effective July 17, 2009, with TransCanada Keystone XL Pipeline, LP ("Keystone XL"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. Estimated cost of the project is $51.9 million and is to be paid by Keystone XL over a ten-year period anticipated to begin in July 2012. As of December 31, 2009, no construction had begun.
In a transmittal letter dated December 8, 2008, the Environmental Protection Agency Region 7 office issued a Notice of Violation under Section 113(a)(i) of the Clean Air Act related to certain projects undertaken from 1991 through 2001 at GGS. The District is unable to predict what future costs may be incurred with respect to the Notice of Violation. See Note 16 for additional information.
I I NEBRASKA PUBLIC POWER DISTRICT
REPORT OF INDEPENDENT AUDITORS To the Board of Directors of the Nebraska Public Power District:
We have audited the accompanying balance sheets of Nebraska Public Power District (the "District") as of December 31, 2009 and 2008, and the related statements of revenues, expenses, and changes in fund equity and of cash flovws for the years then ended. These financial statements are the responsibility of the District's management. Our responsibility is to express an opinion on these financial statements based on .our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the District at December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
Management's discussion and analysis included on pages two through eleven is not a required part of the basic financial statements but is supplementary information required by the Governmental Accounting Standards Board.
We have applied certain limited procedures, which consisted primarily of inquires of management, regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.
In accordance with Governmental Auditing Standards,we have also issued our report dated April 2, 2010 on our consideration of the District's internal control over financial reporting and on our test of its compliance with certain provisions of laws, regulations, contracts and grant agreements and other matters for the year ended December 31, 2009. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Governmental Auditing Standards and should be considered in assessing the results of our audits.
Our audits were conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedule, "Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, 2009 and 2008," is presented for. purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.
L4P St. Louis, Missouri April 2, 2010 NEBRASKA PUBLIC POWER DISTRICT 12
FINANCIAL STATEMENTS Balance Sheets - December 31, 2009 and 2008 (000's) 2009 2008 ASSETS Utility Plant, at Cost:
Utility plant in service $ 3,948,830 $ 3,686,887 Less reserve for depreciation 2,110,620 2,035,723 1,838,210 1,651,164 Construction work in progress 201,324 266,883 Nuclear fuel, at amortized cost 195,535 205,237 2,235,069 2,123,284 Special Purpose Funds:
Cash and cash equivalents:
Construction funds -1,841 Debt reserve fund 210 251 Employee benefit funds 3,167 2,822 Investments:
Construction funds 203,009 288,244 Debt reserve fund 98,283 97,972 Employee benefit funds 3,844 2,916 Decommissioning funds 458,984 465,610 767,497 859,656 Current Assets:
Cash and cash equivalents 38,002 75,133 Investments 101,714 68,783 Receivables, less allowance for doubtful accounts of $531 and $524, respectively 77,467 72,481 Fossil fuels, at average cost 31,314 36,644 Materials and supplies, at average cost 117,120 107,955 Prepayments and other current assets 17,511 9,532 383,128 370,528 Deferred Charges and Other Assets:
Deferred asset retirement obligation 482,900 398,024 Deferred OPEB obligation 62,020 41,200 Long-term capacity contracts 218,417 232,587 Deferred settlement charges 14,937 19,453 Unamortized financing costs 15,815 16,221 Investment in The Energy Authority 6,776 7,589 Other 10,940 2,314 811,805 717,388 TOTAL ASSETS $ 4,9,99 $ 4,070,856 FUND EQUITY AND LIABILITIES Fund Equity:
Invested in capital assets, net of related debt $ 590,599 $ 692,758 Restricted 46,407 45,875 Unrestricted 262,860 145,043 899,866 883,676 Long -Term Debt:
Re'venue bonds, net 1,774,787 1,708,691 Commercial paper notes 234,234 213,277 2,009,021 1,921,968 Current Liabilities:
Current maturities of revenue bonds 97,575 80,590 Accounts payable and accrued liabilities 76,331 134,634 Accrued in lieu of tax payments 7,532 7,034 Accrued payments to retail communities 4,712 4,339 Accrued compensated absences 15,175 13,229 Other 5,317 4,257 206,642 244,083 Deferred Credits and Other Liabilities:
Asset retirement obligation 943,647 896,739 Deferred revenues 43,820 52,911 Other 94,503 71,479 1,081,970 1,021,129 TOTAL FUND EQUITY AND-LIABILITIES $ 4,1ý97,499 $ 4,070,856 The accompanying notes to financial statements are an integral part of these statements.
13 NEBRASKA PUBLIC POWER DISTRICT
Statements of Revenues, Expenses, and Changes in Fund Equity for the years ended December 31, (000's) 2009 2008 Operating Revenues $ 863,398 $ 831,259 Operating Expenses:
Power purchased 90,934 79,883 Production -
Fuel 168,033 179,352 Operation and maintenance 246,311 241,466 Transmission and distribution operation and maintenance 55,734 47,821 Customer service and information 18,707 16,819 Administrative and general 53,151 48,835 Payments to retail communities 19,965 18,663 Decommissioning 25,764 31,961 Depreciation and amortization 110,729 106,463 Payments in lieu of taxes 7,576 7,088 796,904 778,351 Operating Income 66,494 52,908 Non-Operating Income:
Investment income 30,901 48,351 Other income 959 438 31,860 48,789 Increase in Fund Equity Before Debt and Other Expenses 98,354 101,697 Non-Operating Expenses:
Interest on long-term debt 90,161 77,600 Allowance for funds used during construction (7,706) (4,237)
Bond premium amortization net of debt issuance expense (2,158) (2,376)
Other expenses 1,867 4,651 82,164 75,638 Increase in Fund Equity 16,190 26,059 Fund Equity:
Beginning balance 883,676 857,617 Ending balance $ 899,866 $ 883,676 The accompanying notes to financial statements are an integralpartof these statements.
NEBRASKA PUBLIC POWER DISTRICT 14
Statements of Cash Flows for the years ended December 31, (000's) 2009 2008 Cash Flows from Operating Activities:
Receipts from customers and others $ 862,107 $ 860,142 Receipts from FEMA, State of Nebraska and others 7,136 4,775 Payments to suppliers and vendors (377,849) (411,110)
Payments to employees (233,435) (221,552)
Net cash provided by operating activities 257,959 232,255 Cash Flows from Investing Activities:
Proceeds from sales and maturities of investments 999,173 726,027 Purchase of investments (949,238) (825,865)
Income received on investments 8,797 10,322 Net cash provided by (used in) investing activities 58,732 (89,516)
Cash Flows from Capital and Related Financing Activities:
Proceeds from issuance of bonds 166,880 468,095 Proceeds from issuance of notes 90,153 195,170 Proceeds from repayment of notes receivable 73 71 Capital expenditures for utility plant (371,759) (371,028)
Long-term capacity contract expenditures - (26,358)
Refurbishment at Kingsley Hydro (994)
Principal payments on long-term debt (81,235) (229,305)
Interest payments on long-term debt (90,161) (77,862)
Principal payments on notes (70,397) (102,048)
Interest payments on notes (587) (2,303)
Funds advanced - Whelan Energy Center 2 1,755 4,881 Other non-operating revenues 913 250 Net cash used in capital and related financing activities (355,359) (140,437)
Net (decrease) increase in cash and cash equivalents (38,668) 2,302 Cash and cash equivalents, beginning of year 80,047. 77,745 Cash and cash equivalents, end of year $ 41,379 $ 80,047 Reconciliation of Operating Income to Cash Provided By Operating Activities:
Operating income $ 66,494 $ 52,908 Adjustments to reconcile operating income to net cash provided (used) by operating activities:
Depreciation and amortization 110,729 106,463 Undistributed net revenue - The Energy Authority 813 (513)
Decommissioning, net of customer contributions 58,391 51,254 Amortization of nuclear fuel 39,485 35,237 Changes in assets and liabilities which provided (used) cash:
Receivables, net (9,375) 3,110 Fossil fuels 5,330 (8,223)
Materials and supplies (9,166) (5,535)
Prepayments and other current assets 97 (544)
Deferred charges (500) 618 Accounts payable and accrued payments to retail communities 3,821 10,090 Deferred revenues (9,091) (13,037)
Other liabilities 931 427 Net cash provided by operating activities $ 257,959 $ 232,255 Supplementary non-cash capital activities:
Utility plant additions in accounts payable $ (61,581) $ 62,407 The accompanyingnotes to financial statements are an integralpart of these statements.
15 NEBRASKA PUBLIC POWER DISTRICT
Supplemental Schedule - Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (000's) 2009 2008 Operating revenues $ 863,398 $ 831,259 Operating expenses (796,904) (778,351)
Operating income 66,494 52,908 Investment and other income 31,860 48,789 Debt and other expenses (82,164) (75,638)
Increase in fund equity 16,190 26,059 Add:
Collections for future debt retirement 22,231 13,482 Debt and related expenses 82,119 75,450 Depreciation and amortization 110,729 106,463 Payments to retail communities* 19,965 18,663 235,044 214,058 Deduct:
Investment income retained in construction funds 4,040 6,184 Unrealized gain on investment securities (3,704) 4,811 336 10,995 Fund equity available for debt service under the General Revenue Bond Resolution $ 250,898 $ 229,122 Amounts deposited in the General System Debt Service Account:
Principal $ 81,235 $ 82,555 Interest 66,899 61,616
$ 148,134 $ 144,171 Ratio of fund equity available for debt service to debt service deposits 1.69 1.59
- Under the provisions of the General Revenue Bond Resolution, the payments required to be made by the District with respect to the Professional Retail Operating Agreements are to be made on the same basis as subordinated debt.
The accompanying notes to financial statements are an integralpartof these statements.
NEBRASKA PUBLIC POWER DISTRICT 16
NOTES TO FINANCIAL STATEMENTS
- 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization-Nebraska Public Power District (the "District"), a public corporation and a political subdivision of the State. of Nebraska, operates an integrated electric utility system which includes facilities for the generation, transmission, and distribution of electric.power and energy to its wholesale and retail customers. The control of the District and its operations is vested in a Board of Directors consisting of 11 members popularly elected from districts comprising subdivisions of the District's chartered territory. The Board of Directors is authorized to establish rates.
B. Basis of Accounting -
Effective July 1, 2009, the Financial Accounting Standards Board ("FASB") issued the FASB Accounting Standards Codification ("ASC"). The ASC became the single source of authoritative nongovernmental Generally Accepted Accounting Principles ("GAAP") recognized by the FASB to be applied for financial statements issued for periods ending after September 15, 2009. The ASC does not change GAAP and does not have an effect on the District's financial position or results of operation. Technical references to GAAP included in this report are provided under the new ASC structure.
The financial statements are prepared in accordance with GAAP and follow accounting guidance provided by the Governmental Accounting Standards Board ("GASB") codification. The District elected the option permitted by GASB Codification Section ("Cod. Sec.") P80, ProprietaryFund Accounting & FinancialReporting to implement all ASC that do not conflict or contradict GASB pronouncements.
The District follows the provisions of ASC Section 980 Regulated Operations ("ASC 980"). In general, ASC 980 permits an entity with cost-based rates to defer certain costs or income that would otherwise be recognized when incurred to the extent that the rate-regulated entity is recovering or expects to recover such amounts in rates charged to its customers.
C. Use of Estimates -
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
D. Revenue -
Wholesale revenues are recorded in the period in which service is rendered, and retail revenues are recorded in the month retail customers are billed. Consequently, revenues applicable to service rendered to retail customers from the period covered by the last billing in a year to the end of the year are not recorded as revenues until the following year.
The District is required under the General Revenue Bond Resolution (the "Resolution") to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses, aggregate debt service on the General Revenue bonds, amounts to be paid into the Debt reserve fund and all other charges or liens payable out of revenues. In the event the District's rates for wholesale service result in a surplus or deficit in revenues during a rate period, such surplus or deficit within certain limits may be retained in a rate stabilization account. Any amounts in excess of the limits will be taken into account in projecting revenue 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 su rplus 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 theyears ended December 31, 2009 and 2008, the District deferred net costs of $9.1 million and $13.0 million, respectively. The cumulative surplus at December 31, 2009, to be reflected in future revenue requirements, is approximately $43.8 million. The District's electric rates for 2010 include a collection of $7.2 million for previously deferred costs..
17 NEBRASKA PUBLIC POWER DISTRICT
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 $42.1 million and $40.1 million for the years ended December 31, 2009 and 2008, respectively. Annual depreciation expense calculated under the debt service principal approach exceeded straight-line depreciation by $2.0 million and $6.9 million for the years ended December 31, 2009 and 2008, respectively. Depreciation expense recorded on a straight-line basis on utility plant was $88.2 million and
$84.6 million for the years ended December 31, 2009 and 2008, respectively. Depreciation on utility plant was approximately 2.4% and 2.5% in each of the years ended December 31, 2009 and 2008, respectively. The District has fully depreciated utility plant that is still in service of $686.2 million and $656.5 million at December 31, 2009 and 2008, 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, 2009 and 2008,
$512.2 million and $490.1 million, respectively, of net utility plant was funded from revenues. Provision for depreciation of utility plant funded from revenues is computed using the straight-line method.
The District owns and operates the electric distribution system in one of the 80 municipalities that it serves at retail. In addition, the District has -long-term Professional Retail Operating ("PRO") Agreements with 79 municipalities for certain retail electric distribution systems. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreements. The District has recorded provisions, net of retirements, for amortization of these plant additions of $10.4 million in 2009 and $15.2 million in 2008 which is included in depreciation and amortization expense. These plant additions, which are fully depreciated, totaled $145.9 million at December 31, 2009, and
$139.2 million at December 31, 2008.
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 Investments -
The District considers highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
G. Fossil Fuel and Materialsand 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. NuclearFuel -
In March 2008, the District, amended its existing agreement for uranium concentrates, conversion, and enrichment to provide for short-term enriched uranium product and long-term enrichment services. These
.contracts do not obligate the District to purchase fuel components in excess of the requirements of operations.
Nuclear fuel in the reactor is being amortized on the basis of energy produced as a percentage of total energy expected to be produced. Fees for disposal of fuel in the reactor are being expensed as part of the fuel cost.
In December 2009, CNS completed construction of a dry cask used fuel storage facility to support planned license renewal. This facility was funded from decommissioning funds and, as such, no assets were recorded in Utility plant in service.
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 NEBRASKA PUBLIC POWER DISTRICT 18
respective bonds in accordance with GASB Statement No. 23, Accounting and FinancialReporting for Refundings of Debt Reported by ProprietaryActivities.
J. Allowance for Funds Used During Construction ("AFUDC") -
This allowance, which represents the cost of funds used to finance construction, is capitalized as a component of the cost of the utility plant and is credited to Non-Operating Expenses. The capitalization rate depends on the source of financing. The rate for construction financed with revenue bonds is based upon the interest cost of each bond issue less interest income. Construction financed on a short-term basis with taxable commercial paper ("TCP") or tax-exempt commercial paper ("TECP") is charged a rate based upon the projected average interest cost of TCP or TECP outstanding. For the periods presented herein, the AFUDC rates for construction funded by revenue bonds vary from 3.8% to 5.5%. For construction financed on a short-term basis with commercial paper, the rates charged vary from 2.0% to 5.0%.
K. Fund Equity -
Fund equity is made up of three components: Invested in capital assets, net of related debt, Restricted, and Unrestricted.
Invested in capital assets, net of related debt consists of utility plant assets, net of accumulated depreciation and reduced by the outstanding balances of any bonds or notes that are attributable to the acquisition, construction, or improvement of these assets. This component also includes long-term capacity contracts net of the outstanding balances of any bonds or notes attributable to these assets.
Restricted fund equity consists of the debt service reserve primary funds that are required deposits under the Resolution and the External Decommissioning funds net of any related liabilities.
Unrestricted fund equity consists of any remaining fund equity that does not meet the definition of Invested in capital assets, net of related debt or Restricted, and are used to provide for working capital to fund non-nuclear fuel and inventory requirements, as well as other operating needs of the District.
L. Asset Retirement Obligations-Asset retirement obligations represent the fair value of the District's legal liability associated with the retirement of CNS, various ash landfills at its two coal-fired power stations, and the removal of asbestos at its various generating facilities.
M. Reclassifications-Certain amounts in the prior year's financial statements have been reclassified to conform to the 2009 presentation. These reclassifications had no effect on Increase in Fund Equity or Total Fund Equity. During 2009, the District determined that collections for future debt retirement could be included in fund equity available for debt service under the Resolution for purposes of calculating the debt service ratios. Accordingly, the debt service ratio calculation for the year ended December 31, 2008, was revised to conform to the current year calculation.
N. Recent Accounting Pronouncements -
ASC 820, Fair Value Measurements and Disclosures("ASC 820"), defines fair value, establishes criteria to be considered when measuring fair value, and expands disclosures about fair value measurements. ASC 820 clarifies that fair value is a market-based measurement that should be based on the assumptions that market participants would use in pricing an asset or liability. ASC 820 does not modify any currently existing accounting pronouncements. The District adopted ASC 820 as of January 1, 2008, for financial assets and liabilities and as of January 1, 2009, for nonfinancial assets and liabilities. The adoption of ASC 820 did not have a material impact on the District's financial position or results of operation. See Note 4 for additional information.
In June 2008, GASB issued Cod. Sec. D40, Derivative Instruments ("GASB Cod. Sec. D40"). This standard provides accounting and financial reporting guidance to governments for measuring derivative instruments at fair value and specific criteria to determine whether a derivative instrument results in an effective hedge. GASB Cod.
Sec. D40 is effective for financial statement periods beginning after June 15, 2009. The District expects that the adoption of GASB Cod. Sec. D40 will not have a material impact on its financial position or results of operation.
19 NEBRASKA PUBLIC POWER DISTRICT
- 2. UTILITY PLANT:
Utility plant activity for the year ended December 31, 2009, was as follows (000's):
December 31, December 31, 2008 Increases -Decreases 2009 Nondepreciable utility plant:-
Land and improvements $ 43,777 $ 8,550 $ (4) $ 52,323 Construction in progress 266,883 263,403 (328,962) 201,324 Total nondepreciable utility plant 310,660 271,953 (328,966) 253,647 Nuclear fuel* 205,237 29,783 (39,485) 195,535 Depreciable utility plant:
Generation - Fossil 1,386,416 53,954 (1,829) 1,438,541 Generation - Nuclear 1,097,735 11,912 (2,657) 1,106,990 Transmission 730,552 176,074 (7,297) 899,329 Distribution 174,421 11,604 (3,152) 182,873 General 253,986 18,927 (4,139) 268,774 Total depreciable utility plant 3,643,110 272,471 (19,074) 3,896,507 Less reserve for depreciation (2,035,723) (93,971) 19,074 (2,110,620)
Depreciable utility plant, net 1,607,387 178,500 1,785,887 Utility plant activity, net $ 2,123,284 $ 480.236 $ (368,451) $ 2,235.069
- Nuclear fuel decreases represent amortization of $39.5 million.
With the submission of the CNS 20-year license extension in September 2008, the District reevaluated all assets associated with CNS and revised their remaining useful lives accordingly. The change was effective January 1, 2008.
The 2010 construction plan includes authorization for future expenditures of $348.2 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 Cod. Sec. In5, Investment Pools (External) ("GASB Cod. Sec. In5"). GASB Cod.
Sec. In5 requires the District's investments to be recorded at fair value with the changes in the fair value of investments reported as Investment income in the accompanying Statements of Revenues, Expenses, and Changes in Fund Equity. The District had an unrealized net loss of $3.7 million as of December 31, 2009, and an unrealized net'gain of $4.8 million as of December 31, 2008.
Cash deposits, primarily interest bearing, are covered by federal depository insurance or pledged collateral of U.S. Government securities held by various depositories. Investments were in U.S. Government securities and Federal Agency obligations held in the District's name by the custodial banks. Cash and investments totaled
$907.2 million and $1,003.6 million at December 31, 2009 and 2008, respectively.
The fair value of all cash and investments, regardless of balance sheet classification, as of December 31 was as follows (000's):
2009 2008 U.S. Treasury and government agency securities $ 672,165 $ 714,333 State and local government securities 2,105 Corporate bonds 143,786 117,768 Municipal bonds 8,657 Certificates of deposit 1,263 Cash and money market mutual funds 81,342 169,366 Total cash and investments $ 907,213 $1,003,572 NEBRASKA PUBLIC POWER DISTRICT 20
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 nuclear fuel and 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.
2009 2008 Construction funds - Cash and cash equivalents $ -- $ 1,841 Construction funds - Investments 203,009 288,244
$ 203,009 $ 290,085 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 $46.4 million and
$45.9 million as of December 31, 2009 and 2008, 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 $52.1 million and $52.3 million as of December 31, 2009 and 2008, respectively.
2009 2008 Debt reserve fund - Cash and cash equivalents $ 210 $ 251 Debt reserve fund - Investments 98,283 97,972
$ 98,493 $ 98,223 The Employee benefit funds consist of a self-funded hospital-medical benefit plan and a retired employee life insurance benefit plan. The District pays 80% of the hospital-medical premiums with the employees paying the remaining 20% of the cost of such coverage. The retired employee life insurance benefit plan was funded prior to the adoption of GASB Cod. Sec. P50, Postemployment Benefits Other Than Pension Benefits - Employer Reporting ("GASB Cod. Sec. P50") and creation of an irrevocable grantor trust for postretirement health and life insurance benefits. For additional information on postemployment benefits see Note 15. The plan had contributed funds of $5.0 million and $3.6 million at December 31, 2009 and 2008, respectively. The District pays the total cost of the employee life insurance benefit once the employee retires. The plan had contributed funds of
$2.0 million and $2.1 million at December 31, 2009 and 2008, respectively. Both funds are held by outside trustees in compliance with the funding plans approved by the District's Board of Directors.
2009 2008 Employee benefit fund - Cash and cash equivalents $ 3,167 $ 2,822 Employee benefit fund - Investments 3,844 2,916
$ 7,011 $ 5,738 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.
2009 2008 Decommissioning funds $ 458,984 $ 465,610
- 4. FAIR VALUE OF FINANCIAL INSTRUMENTS:
Effective January 1, 2008, the District adopted ASC 820, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements.
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.
21 NEBRASKA PUBLIC POWER DISTRICT
ASC 820, establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in an active market for identical assets or liabilities and the lowest priority to unobservable inputs. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels of fair value hierarchy defined in ASC 820 are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The District currently does not have Level 1 assets and liabilities included in the Decommissioning funds, other Special Purpose Funds, or Investments in Current Assets.
Level 2 - Pricing inputs are other than quoted market prices in the active markets included in Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. Level 2 inputs include the following:
" quoted prices for similar assets or liabilities in active markets;
" quoted prices for identical assets or liabilities in inactive markets;
- inputs other than quoted prices that are observable for the asset or liability; or
" inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 2 assets and liabilities primarily include U.S. treasury and other federal agency securities and corporate bonds held in the District's Decommissioning funds, other Special Purpose Funds, and certain Investments in Current Assets. The District's investment in cash and money market mutual funds are excluded from the ASC 820 fair value hierarchy.
Level 3 - Pricing inputs include significant inputs that are unobservable and cannot be corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies using significant unobservable inputs. The District currently does not have Level 3 assets or liabilities included in the Decommissioning funds, other Special Purpose Funds, or Investments in Current Assets.
The District performs an analysis annually to determine the appropriate hierarchy level classification of the assets and liabilities that are included within the scope of ASC 820. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
The following table sets forth the District's financial assets and liabilities that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31, (in 000's):
December 31, 2009 Level 1 Level 2 Level 3 Total Assets:
Available-for-sale securities $ - $ 398,165 $ - $ 398,165 Decommissioning funds - 427,705 - 427,705
$ - $ 825,870 $ - $ 825,870 December 31, 2008 Level 1 Level 2 Level 3 Total Assets:
Available-for-sale securities $ - $ 408,640 $ - $ 408,640 Decommissioning funds - 443,528 - 443,528
$ - $ 852,168 $ - $ 852,168 Decommissioning funds reflect the assets held in trust to cover general decommissioning costs and consist primarily of fixed income governmental securities.
- 5. LONG-TERM CAPACITY CONTRACTS:
Long-term capacity contracts include the District's $198.2 million share of the construction costs of Omaha Public Power District's ("OPPD") 682 MW Nebraska City Station Unit 2 ("NC2") coal-fired power plant which amount includes $15.8 million share of associated transmission facilities construction costs. The District has NEBRASKA PUBLIC POWER DISTRICT 22
entered into a participation power agreement with OPPD for a 23.7% share of the power from this plant. NC2 began commercial operation on May 1, 2009, at which time the District began amortizing the amount of the capacity contract associated with the plant of $182.4 million on a straight-line basis over the 40-year estimated useful life of the plant. Accumulated amortization was $3.0 million in 2009. The unamortized amount of the plant capacity contract was $179.4 million as of December 31, 2009, of which $4.6 million was included in Prepayments and other current assets as of December 31, 2009. The costs of the transmission facilities are being returned to the District in the form of a credit on the District's monthly transmission bill from OPPD. Accumulated credits were
$2.2 million as of December 31, 2009. The remaining transmission credits were $13.6 million as of December 31, 2009 of which $3.3 million was included in Prepayments and other current assets as of December 31, 2009.
Long-term capacity contracts also include the District's purchase of the capacity of a 50 MW hydroelectric generating facility owned and operated by The Central Nebraska Public Power and Irrigation District ("Central").
The District is recording amortization on a straight-line basis over the 40-year estimated useful life of the facility.
Accumulated amortization was $48.2 million in 2009 and $46.2 million in 2008. The unamortized amount of the Central capacity contract was $35.4 million and $36.5 million as of December 31, 2009 and 2008, respectively, of which $2.1 million was included in Prepayments and other current assets as of December 31, 2009 and 2008.
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 $1.1 million and $1.4 million in 2009 and 2008, respectively, are included in Power purchased in the accompanying Statements of Revenues, Expenses, and Changes in Fund Equity.
- 6. DEFERRED SETTLEMENT CHARGES:
The District deferred the cost of a $39.1 million payment to MidAmerican Energy Company ("MEC") in 2002 in conjunction with the settlement of litigation with respect to the operation of CNS. The deferred costs of the MEC payment will be recognized as expense in future rate periods when such costs are included in the revenue requirements used to establish electric rates. The balance of such deferral was $19.5 million and $23.8 million as of December 31, 2009 and 2008, respectively, of which $4.5 million and $4.3 million was included in Prepayments and other current assets as of December 31, 2009 and 2008, respectively.
- 7. INVESTMENT IN THE ENERGY AUTHORITY:
The District is a member of The Energy Authority ("TEA"), a power marketing corporation. TEA assumes the wholesale power marketing responsibilities of its members with each member having ownership in the joint venture. TEA has access to approximately 25,000 megawatts of its members' and partners' generation located across the nation. TEA also provides its members with natural gas procurement or contract management services for gas used in the generation of electricity and for local distribution. TEA provides the District with gas contract management services.
The table below contains the condensed financial information for TEA as of December 31, (000's):
Condensed Balance Sheet 2009 2008 Current Assets $ 104,901 $ 133,695 Noncurrent and Restricted Assets 20,649 12,126 Total Assets $ 125,550 $ 145,821 Current Liabilities $ 85,266 $ 107,185 Noncurrent Liabilities 3,101 2,119 Net Assets 37,183 36,517 Total Liabilities and Net Assets $ 125,550 $ 145,821 Condensed Statement of Operations Revenues $ 939,940 $ 1,650,564 Energy Costs (860,171) (1,469,347)
Gross Profit 79,769 181,217 Operating Expenses (31,786) (31,059)
Operating Income 47,983 150,158 Non-Operating Income 1,093 1 (596)
Increase in Net Assets $ 49,076 $ 149,562 23 NEBRASKA PUBLIC POWER DISTRICT
At December 31, 2009 and 2008, the District had a 21.4% 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):
2009 2008 Beginning Balance $ 7,589 $ 7,076 Reduction to power costs and increase in electric revenues 22,720 46,574 Distributions from TEA (19,120) (43,183)
Other expenses (4,413) (2,878)
Ending Balance $ 6,776 $ 7,589 The District's power purchases and sales with TEA are reflected in the Statements of Revenues, Expenses, and Changes in Fund Equity as Power purchased, and Operating Revenues, respectively. For the years ended December 31, 2009 and 2008, the District recorded Operating Revenues of $29.6 million and $42.1 million, respectively, and Power purchased expenses of $5.9 million and $30.3 million, respectively.
At December 31, 2009 and 2008, $4.9 million and $6.9 million due from TEA was included in Receivables and
$2.6 million and $8.6 million due to TEA was included in Accounts payable, respectively.
As of December 31, 2009, the District is obligated to guaranty, directly or-indirectly, TEA's electric trading activities in an amount up to $28.9 million plus attorney's fees which any party claiming and prevailing under the guaranty might incur and be entitled to recover under its contract with TEA. Generally, the District's guaranty obligations for electric trading would arise if TEA did not make the contractually required payment for energy, capacity, or transmission which was delivered or made available or if TEA failed to deliver or provide energy, capacity, or transmission as required under a contract.
The District's exposure relating to TEA is limited to the District's capital investment in TEA, any accounts receivable from TEA, and trade guarantees provided to TEA by the District. These guarantees are within the scope of ASC 460 Guarantees.Upon the District making any payments under its electric guaranty, it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably, based upon each member's equity ownership interest in TEA. After such contributions have been effected, the District would only have recourse against TEA to recover amounts paid under the guaranty. The term of this guaranty is generally indefinite, but the District has the ability to terminate its guaranty obligations by causing to be provided advance notice to the beneficiaries thereof. Such termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect.
As of December 31, 2009 and 2008, the District has not recorded a liability related to these guaranties.
- 8. REVENUE BONDS:
In June 2009, the District issued General Revenue Bonds, 2009 Series A and 2009 Series C, in the amount of
$50.4 million and $17.9 million, respectively, to finance certain generation and other transmission capital additions. Also in June 2009, the District issued General Revenue Bonds, 2009 Series B, in the amount of
$100.0 million to advance refund $69.5 million of TCP notes and to provide $28.4 million for certain capital additions at CNS.
In March 2008, the District issued General Revenue Bonds, 2008 Series A, in the amount of $137.8 million to advance refund the outstanding 2007 Series A Bonds and to refund the portion of TCP notes used to redeem the 2004 Series A Bonds. In September 2008, the District issued General Revenue Bonds, 2008 Series B, in the amount of $332.2 million to provide $148.0 million for the remaining cost of the Electric Transmission Reliability ("ETR") Project, a high-voltage transmission line in the east-central portion of the state, to provide
$80.0 million for certain generation and other transmission capital additions, to provide $26.0 million for the District's remaining share of OPPD NC2 coal-fired generating plant and associated transmission facilities, and to refund $57.0 million of TECP notes that were issued to pay for costs associated with the December 2006 ice storms, the purchase of several transformers and other capital additions.
NEBRASKA PUBLIC POWER DISTRICT 24
Revenue bonds consist of the following (000's except interest rates):
December 31, Interest Rate 2009 2008 General Revenue Bonds:
1999 Series A Serial Bonds 2009-2011 4.60% 5.00% $ 715 $ 10,640 2002 Series B:
Serial Bonds 2009-2025 5.00% 48,505 53,715 Term Bonds 2026-2032 5.00% 22,885 22,885 2003 Series A:
Serial Bonds 2009-2026 3.25% 5.00% 95,945 99,815 Term Bonds 2027-2034 5.00% 86,095 86,095 2004 Series B Serial Bonds 2010-2013 4.25% 5.00% 149,030 149,030 2005 Series A Serial Bonds 2009-2025 3.00% 5.25% 88,985 92,800 2005 Series B-1 Serial Bonds 2010-2015 5.00% 75,335 75,335 2005 Series B-2 Serial Bonds 2009-2016 4.00% 5.00% 62,225 102,360 2005 Series C:
Serial Bonds 2010-2025, 2040 3.50% 5.125% 74,385 74,385 Term Bonds 2026-2029 5.00% 11,765 11,765 2030-2034 4.75% 18,240 18,240 2035-2040 5.00% 27,500 27,500 2006 Series A:
Serial Bonds 2009-2025 3.50% 5.00% 76,535 78,940 Term Bonds 2026-2030 5.00% 18,680 18,680 2031-2035 5.00% 23,840 23,840 2036-2040 4.375% 400 400 2036-2040 5.00% 30,020 30,020 2007 Series B:
Serial Bonds 2009-2026 4.00% 5.00% 241,890 254,440 Term Bonds 2027-2031 4.65% 36,140 36,140 2032-2036 5.00% 19,270 19,270 2008 Series A Taxable Term Bonds 2013 5.14% 137,765 137,765 2008 Series B:
Serial Bonds 2009-2029 3.00% 5.00% 238,815 241,495 Term Bonds 2030-2032 5.00% 32,390 32,390 2033-2037 5.00% 50,880 50,880 2038-2040 5.00% 7,180 7,180 2009 Series A Taxable Build America Bonds:
Term Bonds 2019-2025 6.606% 17,465 2026-2034 7.399% 32,890 2009 Series B Taxable:
Term Bonds 2012 4.135% 29,180 2013 4.85% 70,820 2009 Series C Serial Bonds 2009-2019 2.00% - 4.25% 17,245 Total par amount of revenue bonds 1,843,015 1,756,005 Unamortized premium net of discount 29,347 33,276 I
1,872,362 1,789,281 Less - current maturities of revenue bonds (80,590)
Total revenue bonds $ 1,774.787 $ 1.708.691 25 NEBRASKA PUBLIC POWER DISTRICT
Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2009, are as follows (000's):
Debt Service Principal Year Payments Payments 2010 $ 188,112 $ 97,575 2011 189,944 103,895 2012 217,527 136,385 2013 367,020 292,225 2014 142,004 81,670 2015-2019 559,017 308,800 2020-2024 442,686 261,620 2025-2029 362,742 246,320 2030-2034 269,879 211,260 2035-2039 104,893 89,590 2040 14,352 13,675 Total Payments $ 2,858.176 $ 1.843.015 The fair value of outstanding revenue bonds is determined using currently published rates. The fair value is estimated to be $1,941.1 million and $1,681.0 million at December 31, 2009 and 2008, respectively.
- 9. COMMERCIAL PAPER NOTES:
I The District is authorized to issue up to $200.0 million of TCP notes and up to $150.0 million of TECP notes.
A $200.0 million credit agreement and a $150.0 million credit agreement, each expiring August 1, 2011, are maintained with several banks to support the sale of the TCP notes and TECP notes, respectively. The previous credit agreements each expired August 1, 2008. The District had $117.2 million and $121.3 million of TCP notes outstanding at December 31, 2009 and 2008, respectively. The proceeds of the TCP notes have been used to purchase nuclear fuel and to fund capital projects at CNS. The District had $117.0 million and $92.0 million of TECP notes outstanding at December 31, 2009 and 2008, respectively. The proceeds of the TECP notes have been used to provide short-term financing for certain capital additions and for other lawful purposes of the District.
The effective interest rate on outstanding TCP notes for 2009 and 2008 were 0.9% and 2.7%, respectively. The effective interest rates on outstanding TECP notes for 2009 and 2008 were 0.6% and 1.8%, respectively.
The $117.2 million of TCP notes and the $117.0 million of TECP notes outstanding at December 31, 2009, 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 due to the short-term nature of the notes.
- 10. LINE OF CREDIT AGREEMENTS:
The District has two separate line of credit agreements of $200.0 million and $150.0 million that support the payment of the principal outstanding of the TCP notes and TECP notes, respectively. See Note 9 for additional information. At December 31, 2009 and 2008, no amounts have been drawn on either line of credit.
- 11. LONG-TERM DEBT:
Long-term debt activity, net of current activity for the year ended December 31, 2009, was as follows (000's):
Principal Amounts December 31, December 31, Due Within 2008 Increases Decreases 2009 One Year Revenue bonds $ 1,708,691 $ 172,177 $ (106,081) $ 1,774,787 $ 97,575 Commercial paper notes 213,277 1,066,146 (1,045,189) 234,234 Total long-term debt activity $ 1,921,968 $ 1,238,323 $ (1,151,270) $ 2,009,021 $ 97,575 NEBRASKA PUBLIC POWER DISTRICT 26
- 12. ASSET RETIREMENT OBLIGATION:
The District has recorded an obligation for the fair value of its legal liability for asset retirement obligations associated with CNS, various ash landfills at its two coal-fired power stations, removal of asbestos at the District's various coal, gas, and hydro generating facilities, polychlorinated biphenyls from substation and distribution equipment, and underground storage tanks as well as abandonment of water wells. In 2008, the District reevaluated its asset retirement obligation ("ARO") associated with CNS after submitting its application in September 2008 for a 20-year operating license extension to the Nuclear Regulatory Commission ("NRC"). As a result, an adjustment to increase the ARO by $175.1 million was made primarily related to increases in overall security costs and changes to timing of decommissioning of CNS. The total asset retirement obligation liability recorded by the District was $943.6 million and $896.7 million as of December 31, 2009 and 2008, respectively, and is included in the Deferred Credits and Other Liabilities section of the accompanying Balance Sheets.
The following table shows costs as of January 1, and charges to the ARO that occurred during the years ended December 31, 2009 and 2008, and are included in Deferred Credits and Other Liabilities on the balance sheet as of December 31, (000's):
For the Year Ended December 31, 2009 2008 Balance, beginning of year $ 896,739 $ 687,287 Accretion 46,908 34,344 ARO adjustment _- 175,108 Balance, end of year $ 943,647 $ 896,739 A significant amount of the ARO is funded by decommissioning funds of $459.0 million and $465.6 million as of December 31, 2009 and 2008, respectively. See Note 3 for additional information.
At the time the liability for the asset retirement is incurred, ASC 410 requires capitalization of the costs to the related asset. For asset retirement obligations existing at the time of adoption of ASC 410, the statement requires capitalization of costs at the level that existed at the time of incurring the liability. These capitalized costs are depreciated over the same period as the related asset. At the date of adoption, the depreciation expense for past periods was recorded as a regulatory asset in accordance with ASC 980 because the District will be able to recover these costs in future rates.
The initial liability is accreted to its present value each period. The District defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers. Accretion was $46.9 million and $34.3 million for 2009 and 2008, respectively.
- 13. PAYMENTS IN LIEU OF TAXES:
The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District. Such payments totaled $7.6 million and $7.1 million for the years ended December 31, 2009 and 2008, respectively.
- 14. RETIREMENT PLAN:
The District's Employees' Retirement Plan (the "Plan") is a defined contribution pension plan established by the District to provide benefits at retirement to regular full-time and part-time employees of the District. At December 31, 2009, there were 2,310 Plan members. Plan members are required to contribute a minimum of 2%,
up to a maximum of 5%, of covered salary. The District is required to contribute two times the Plan member's contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District is required to contribute one times the Plan member's contribution. Plan provisions and contribution requirements are established and may be amended by the District's Board of Directors. The District's contribution was
$12.1 million for 2009 and $11.6 million for 2008 of which $1.2 million was accrued and in Accounts payable for each of the years ended December 31, 2009 and 2008.
27 NEBRASKA PUBLIC POWER DISTRICT
- 15. POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS:
A. Plan Description-The District administers a single-employer defined benefit healthcare plan that provides lifetime healthcare insurance for eligible retirees and their spouses. Eligibility and benefit provisions are established by the District's Board of Directors. In addition, the District provides employees a $5,000 death benefit when they retire and substantially all of the District's retired and active employees are eligible for such benefit.
B. Funding Policy -
The eligibility and contributions of the plan members and the funding policy of the plan is established and may be amended by the District's Board of Directors. The District, for employees hired on or prior to December 31, 1992, pays all or part of the cost (determined by retirement age) of certain hospital-medical premiums when these employees retire. The District amended the plan effective January 1, 1993. Employees hired on or after January 1, 1993, are subject to a contribution cap that limits the District's portion of the cost of such coverage to the full premium the year the employee retired or the amount at the time the employee reaches age 65, or the year in which the employee retires if older than age 65. Any increases in the cost of such coverage in subsequent years would be paid by the retired employee. The District amended the plan effective January 1, 1999.
Employees hired on or after January 1, 1999, are not eligible for postretirement hospital-medical benefits once they reach age 65 or Medicare eligibility. The District amended the plan effective January 1, 2004, to provide that employees hired on or after that date will not be eligible for postretirement hospital-medical benefits-once they retire. The District amended the plan effective July 1, 2007, to provide that any former employee who is rehired will receive credit for prior years of service. The District further amended the plan effective September 1, 2007, to provide that employees hired or rehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for postretirement hospital-medical benefits once they retire.
C. Annual OPEB Cost and Net OPEB Obligation -
The District's annual OPEB cost (expense) is calculated based on the annual required contribution ("ARC"),
an amount actuarially determined in accordance with the parameters of GASB Cod. Sec. P50. The ARC represents a level of funding that, if paid on an ongoing basis, is projected to cover the normal cost each year (or benefits earned in the current year) and amortize any unfunded actuarial liabilities (or funding excess) over a period not to exceed 30 years. The following table shows the components of the District's OPEB cost for the year, the amount actually contributed to the plan, and changes in the District's net OPEB obligation as of December 31, (000's):
For the Year Ended December 31, 2009 2008 Annual required contribution $ 33,143 $ 30,531 Interest on net OPEB obligation
- 2,369 1,326 Adjustment to annual required contribution (3,536) (1,052)
Annual OPEB cost 31,976 30,805 Contributions made (11,156) (12,662)
Increase in net OPEB obligation 20,820 18,143 Net OPEB obligation - beginning of year 41,200 23,057 Net OPEB obligation - end of year $ 62,020 $ 41,200 The District's annual OPEB cost, the percentage of annual OPEB cost contributed to the plan, and the net OPEB obligation for 2009 and 2008 were as follows (dollar amounts in thousands):
Annual Percentage of Annual Net OPEB Year OPEB Cost OPEB Cost Contributed Obligation 2009 $ 31,976 34.9% $ 62,020 2008 $ 30,805 41.1% $ 41,200 2007 $ 31,956 27.8% $ 23,057 NEBRASKA PUBLIC POWER DISTRICT 28
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 2009 were $11.2 million which included $4.0 million paid to the trust and $7.2 million for the cost of benefits. Total contributions to the plan in 2008 were $12.7 million which included $4.0 million paid to the trust and $8.7 million for the cost of benefits. It is currently projected that funding above the pay-as-you-go amount will remain at $4.0 million through 2013.and increase to $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.
The Actuarial Accrued Liability (AAL) is the present value of benefits attributable to past accounting periods.
The AAL was $415.2 million, $390.1 million, and $422.0 million as of January 1, 2009, 2008, and 2007, 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) 2009 $ 6,268 $ 415,243 $ 408,975 1.5% $ 185,200 221%
2008 $ 1,964 $ 390,074 $ 388,110 0.5% $ 177,000 219%
2007 $ 1,787 $ 421,975 $ 420,188 0.4% $ 163,400 257%
Actuarial valuations of an ongoing plan involve estimates of the value of reported amounts and assumptions about the probability of occurrence of events far into the future. Examples include assumptions about future employment, mortality, and the healthcare cost trend. Amounts determined regarding the funded status of the plan and the annual required contributions of the employer are subject to continual revision as actual results are compared with past expectations and new estimates are made about the future.
E. Actuarial Methods and Assumptions -
Projections of benefits for financial reporting purposes are based on the substantive plan (the plan as understood by the employer and the plan members) and include the types of benefits provided at the time of each valuation and the historical pattern of sharing of benefit costs between the employer and plan members to that point. The actuarial methods and assumptions used include techniques that are designed to reduce the effects of short-term volatility in actuarial accrued liabilities and the actuarial value of assets, consistent with the long-term perspective of the calculations.
In the January 1, 2008 actuarial valuation, which is the most recent actuarial study, the Unit Credit Actuarial Cost method was used for 2009, 2008, and 2007. In 2009, the actuarial assumptions included an annual healthcare cost trend rate of 8.3% initially, reduced by decrements to an ultimate rate of 4.6%. In 2008, the actuarial assumptions included an annual healthcare cost trend rate of 8.9% initially, reduced by decrements to an ultimate rate of 4.6%. In 2007, the actuarial assumptions included an annual healthcare cost trend rate of 10.0% initially, reduced by decrements to an ultimate rate of 5.0%. The discount rate used for all three years was 5.75% which was based on the District's return on internal investments used to fund benefit payments blended with the expected return on assets of the OPEB Trust Fund. An inflation rate of 3.5% was also assumed for all three years. Amortization for the initial unfunded AAL was determined using a closed period of 30 years and the level percentage of projected payroll method assuming 4.0% payroll growth was used for all three years.
F. Market Value of Plan Investments -
The actuarial valuation of plan assets was based on market values as of January 1, 2008. The investments in the OPEB plan include corporate and government debt, foreign and domestic stocks, mutual funds and cash. The market value of plan assets at December 31, 2009, was $10.1 million.
- 16. COMMITMENTS AND CONTINGENCIES:
The District has various coal supply contracts and a coal transportation contract with minimum future payments of $190.4 million. The coal supply contracts expire at various times through the end of 2013. The coal transportation contract expires at the end of 2011 and is subject to price escalation adjustments.
29 NEBRASKA PUBLIC POWER DISTRICT
The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum.future payments of approximately $37.5 million. These purchases are subject to rate changes.
The District had a power sales contract with MEC for 250 MW for a term beginning January 1, 2005, and ending on December 31, 2009. The power sales contract was for the delivery of 250 MW of the accredited capacity and associated energy from CNS at prices as set forth in the contract. This contract was not renewed.
The District has entered into participation power agreements with OPPD, Municipal Energy Agency of Nebraska ("MEAN"), JEA (formerly the Jacksonville Electric Authority) and Grand Island Utilities for the sale of power from the 60 MW Ainsworth Wind Energy Facility. The participation power agreements are each for a term of 20 years and in the following amounts: OPPD for 16.8%; MEAN for 11.8%; JEA for 16.8%; and Grand Island Utilities for 1.7%.
The District has entered into power sales agreements with OPPD, MEAN, Lincoln Electric System ("LES"),
and Grand Island Utilities for the sale of power from the 80 MW Elkhorn Ridge Wind Farm. The power sales agreements are each for a term of 20 years and in the following amounts: OPPD for 31.3%; MEAN for 10.0%;
LES for 7.5%; and Grand Island Utilities for 1.3%.
The District has entered into long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreement.
The District has 20-year wholesale power contracts, with a term that expires December 31, 2021, with the majority of its firm requirements wholesale customers to provide them with their total power and energy requirements through 2007, after which the wholesale customer could level-off its power and energy purchases through 2010 and thereafter could reduce its power and energy purchases up to 10.0% per year with at least three years advance notice. No such notices have been received.
On April 1, 2009, the District became a member of the Southwest Power Pool ("SPP"), a regional transmission organization based in Little Rock, Arkansas. Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration, including generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning. The District will be able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost.
The District entered into a Whelan Energy Center 2 ("WEC2") Transmission Facilities Agreement effective August 13, 2007, with the Public Power Generation Agency ("PPGA") and the City of Hastings, Nebraska. This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable .cost recovery for the interconnection and delivery facilities required for the interconnection of WEC2 to the District's transmission system. Estimated cost of the project is $18.4 million and is to be paid by PPGA. As of December 31, 2009, PPGA had advanced all required payments of $18.4 million to the District. These advance payments are prepaid transmission service on the District's transmission system for delivery of the Participant's Participation Power.
The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system. Estimated cost of the project is
$8.4 million and is to be paid by Keystone over a ten-year period beginning in June 2010. As of December 31, 2009, the District has recorded a receivable for $8.4 million.
The District entered into a second Transmission Facilities Construction Agreement effective July 17, 2009, with TransCanada Keystone XL Pipeline, LP ("Keystone XL"). This agreement addresses the, transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. Estimated cost of the project is $51.9 million and is to be paid by Keystone XL over a ten-year period anticipated to begin in July 2012. As of December 31, 2009, no construction had begun.
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 161.4 MW of the power from the 682 MW coal-fired power plant constructed by OPPD. NC2 began commercial operation on May 1, 2009. OPPD will retain 50.0% of the output for its own use and has entered into similar participation power sales agreements with other power purchasers. The District's obligation under the NC2 Agreement to make payments is an unconditional "take-or-pay" obligation, obligating the District to make such payments whether or not NC2 or any part thereof is NEBRASKA PUBLIC POWER DISTRICT 30
completed, delayed, terminated, available, operable, operating, or retired. The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs, and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursuant to such step-up provision is limited to 160.0% of its original participation share (23.7%).
Under the provisions of the Federal Price-Anderson Act, the District and all other licensed nuclear power plant operators could each be assessed for claims in amounts up to $117.5 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation, with a maximum assessment of $17.5 million per year per incident per unit owned. To satisfy this potential obligation, the District has submitted its most recent audited financial statements to the NRC.
The NRC evaluates nuclear plant performance as part of its reactor oversight process ("ROP"). The NRC has five performance categories included in the ROP Action Matrix Summary that is part of this process. CNS is currently in the Licensee Response Column, which is the first or best of the five NRC defined performance categories, and has been in this column since the third quarter of 2009. Since 2008, CNS had been in the Degraded Cornerstone which is the third or mid-rating in the NRC's Action Matrix. This improved column placement in 2009 was due to the satisfactory resolution of a White Inspection Finding associated with a failed electrical component on the emergency diesel generator system and a White Inspection Finding associated with an NRC Triennial Fire Protection Inspection that identified errors in two fire protection procedures.
These White Inspection Findings had prompted the movement from the second to the third column of the NRC's Action Matrix in 2008. During the first quarter of 2008, a third White Inspection Finding was in effect that contributed to the placement in the third column due to a failed voltage regulator card on one of the emergency diesel generators. This White Finding was subsequently closed during the second quarter of 2008. As a result of being placed in the third column, the NRC conducted a supplemental 95002 Inspection at CNS in December 2008. The NRC subsequently notified the District that the two remaining White Inspection Findings were closed. CNS remained in the Degraded Cornerstone Column of the NRC's Action, Matrix until the end of the second quarter of 2009.
As a result of a lubricating oil pipe leak on one of the emergency diesel generators at CNS in January 2009, the NRC conducted a special inspection at CNS in February 2009. As a result of that inspection, the NRC identified six potential Inspection Findings all of which were subsequently determined to be Green (very low safety significance) in color. These findings were dispositioned using the CNS Corrective Action Program.
As part of a 1989 settlement of various disputed matters between General Electric Company ("GE") and the District, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility. After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.
In December 2009, CNS completed construction of a dry cask used fuel storage facility to support planned license renewal. The first loading campaign to move used nuclear fuel from the used fuel pool into dry used fuel storage casks for on-site storage is to occur in the fourth quarter of 2010.
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 requestingdocuments and information pertaining to Gerald Gentleman Station ("GGS") and Sheldon Station. On April 10, 2003, Region 7 of the EPA sent a supplemental request for documents and information to the District and the other three electric utilities. These EPA requests for information are part of an EPA investigation to determine the Clean Air Act compliance status of GGS and Sheldon Station, including the potential application of new source review requirements. The District provided the documents and information requested to the EPA within the time allowed. As a supplement to the 2002 and 2003 requests, EPA Region 7 sent another letter to the District on November 8, 2007, requesting additional documents and information pertaining to GGS and Sheldon Station. The District provided a response to the new request within the time allowed. In a transmittal letter dated December 8, 2008, EPA Region 7 issued a Notice of Violation under Section 113(a)(1) of the Clean Air Act ("NOV") alleging violations of pre-construction permitting requirements of the Clean Air Act and the Nebraska State Implementation Plan for five projects undertaken from 1991 through 2001 at GGS. Since receiving the NOV, the District has met twice with the government to discuss the NOV and possible future actions. No further meetings are scheduled. In the event the government pursues litigation based on the NOV and there is a court judgement 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 31 NEBRASKA PUBLIC PoWER DISTRICT
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.
Any changes in the environmental regulatory requirements imposed by federal or state law which are applicable to the District's generating stations could result in increased capital and operating costs being incurred by the District. The District is unable to predict whether any changes will be made to current environmental regulatory requirements, if such changes will be applicable to the District and the costs thereof to the District.
On August 19, 2002, the District received notice from the EPA identifying the District as a Potentially Responsible Party ("PRP") for liability associated with a former Manufactured Gas Plant ("MGP") located in Norfolk, Nebraska. The District is identified as a current owner of property located adjacent to the Norfolk MGP operations. In 2002, the EPA asked identified PRPs to participate in negotiations for completing an Engineering Evaluation/Cost Analysis ("EE/CA"). The identified PRPs met with the EPA Region VII in October 2002 to discuss the site. No other activities between the District and the EPA had taken place related to this site from the time of the October 2002 meeting with the EPA until June 2004. On June 14, 2004, PRPs received notice from the EPA that the EPA was interested again in beginning efforts to complete an EE/CA to address this site. The District has denied that it has any liability as related to the MGP operations, but has indicated to the EPA willingness to cooperate with efforts to address the site. The District has reached an agreement in principal with the other PRPs to resolve its potential liability for the EE/CA by entering into a settlement agreement under which the District would contribute 10% of the costs of the EE/CA. The settlement agreement for the EE/CA has been signed by all parties and was ratified at the February 2007 Board of Directors meeting. Phase I of the EE/CA work began at the site in November 2007. The current schedule indicates that the EE/CA should be completed in 2010. The District is unable to predict what future costs may be incurred with respect to MGP.
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 $14.0 million for 2008 and 2009. In 2010, the annual management fee is $17.2 million. Since 2007, Entergy has been eligible to earn additional annual incentive fees in an amount not to exceed $6.0 million annually if CNS achieved identified safety and regulatory performance targets. As part of the amended agreement effective January 1, 2010, the annual incentive fee was reduced to $4.0 million. Also, as part of the agreement amendment, the overall compensation to Entergy under the support services agreement was restructured such that certain private use issues that existed with the original agreement were eliminated.
- 17. LITIGATION:
A number of other claims and suits are pending against the District for alleged damages to persons and property and for other alleged liabilities arising out of matters usually incidental to the operation of a utility, such as the District. In the opinion of management, based upon the advice of its General Counsel, the aggregate amounts recoverable from the District, taking into account estimated amounts provided in the financial statements and insurance coverage, are not material as of December 31, 2009.
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H Nebraska Public Power District Always there when you need us 1414 15th Street / P.O. box 499 / Columbus, NE 68602-0499 / 1-800-282-6773 / www.nppd.com