NLS2016026, Annual Financial Report for 2015
| ML16141A114 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 05/03/2016 |
| From: | Shaw J Nebraska Public Power District (NPPD) |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NLS2016026 | |
| Download: ML16141A114 (49) | |
Text
H Nebraska Public Power District NLS2016026 May 3, 2016 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Always there when you need us
Subject:
Nebraska Public Power District 2015 Financial Report Cooper Nuclear Station, Docket No. 50-298, DPR-46
Dear Sir or Madam:
50.71(b)
The purpose of this letter is to transmit the Nebraska Public Power District (NPPD) Financial Report for the calendar year 2015 in accordance with the requirements of 10 CFR 50.71(b).
Copies of this report are being distributed in accordance with 10 CFR 50.4.
This letter does not contain any commitments.
Should you have any questions or require additional information, please contact me at ( 402) 825-2788.
Licensing Manager
/jo Enclosure - NPPD 2015 Financial Report cc:
Regional Administratorw/enclosure USNRC - Region IV Cooper Project Manager w/enclosure USNRC - NRR Plant Licensing Branch IV-2 Senior Resident Inspector w/enclosure USNRC-CNS NPG Distribution w/o enclosure CNS Records w/enclosure COOPER NUCLEAR STATION P.O. Box 98 /Brownville, NE 68321-0098 Telephone: (402) 825-3811 I Fax: (402) 825-5211 www.nppd.com
NLS2016026 Enclosure Page 1of48 NPPD 2015 Financial Report I
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2015 STATISTICAL REVIEW (Unaudited)
Average Cents Per kWh Sold Average Awrage Less Government Cents Per Number of MWh OPERATING REVENUES TaxesfTransfers (l) kWh Sold Customers Amount O/o Retail:
Residential......................
10.67
¢ 12.69
¢ 71,433 810,518 3.8 Commercial.....................
8.40
¢ 9.78
¢ 19,651 1, 152,656 5.5 Industrial.........................
5.64
¢ 5.99
¢ 56 1, 170,406 5.6 Total Retail Sales..........
7.96
¢ 9.12
¢ 91 140 311331580 14.9 Wholesale:
Municipalitiesc2l........................................
6.24
¢ 50 1,871,874 8.9 Public Power Districts and CooperativesC2l..
5.89
¢ 25 7,573,936 36.1 Total Firm Wholesale Sales....................
5.96
¢ 75 9A45,810 45.0 Total Firm Retail and Wholesale Sales..
6.74
¢ 91,215 12,579,390 59.9 Participation Sales........................................
3.57
¢ 5
2, 162,648 10.3 Other Salesc31...............................................
2.15
¢ 2
6,2481845 29.8 Total Electric Energy Sales..................
5.05
¢ 91,222 2019901883 100.0 Other Operating Rewnuesc*i..........................................................................................................
Unearned Revenues csi...................................................................................................................
Total Operating Rewnues..............................................................................................................
MWh COST OF POWER PURCHASED AND GENERATED Amount Productionc61..*.*..*.*****.*.......*.......*.......***......**...*.*. *..**....................... *.**....
17,089,062 79.0 Power Purchased......................................................................................
415481469 21.0 Total Production and Power Purchased...................................................
21.6371531 100.0 CONTRACTUAL AND TAX PAYMENTS Qn OOO's) <1J Payments to Retail Communities.................................................................................................
Payments in Lieu of Taxes..........................................................................................................
Total Contractual and Tax Payments........................................................................................
OTHER Miles of Transmission and Subtransmission Lines in Ser.1ce..........................................................
Number of Full-Time Employees...................................................................................................
(1)
Customer collections for taxes/transfers to other governments are excluded from base rates.
(2)
Sales are total requirements.
(3)
Includes sales in the Southwest Power Pool ("SPP") and nonfirm sales to other utilities.
(4)
Includes revenues for transmission and other miscellaneous revenues.
Rewnues (in OOO's)
Amount O/o
$ 102,870 9.4 112,735 10.3 70, 158 6.4 2851763 26.1 116,834 10.7 445,748 40.6 5621582 51.3 848,345 77.4 77, 192 7.0 1341612 12.3 1,060,149 96.7 60,730 5.5
{23,663)
{2.2)
~110971216 100.0 Costs (in OOO's)
Amount
$ 441,344 72.6 166.587 27.4 i
!ijQ71~~1 1QQ.Q Amount 26,552 10,046 i
361598 Amount 5,225 2,003 (5)
Includes unearned revenues from prior periods of $12.0 million, 2015 surplus revenues deferred to future periods of $11.0 million, and collections of $24. 7 million for the 2016 Cooper Nuclear Station ("CNS") refueling and maintenance outage.
(6)
Includes fuel, operation and maintenance costs. Debt service and capital-related costs are excluded.
SOURCES OF THE DISTRICT'S ENERGY SUPPLY (% OF MWH)
This chart shows the sources of energy for sales, excluding participation sales to other utilities. Purchases were included in the appropriate source, except for those purchases for which the source was not known.
Nuclear 33.8%
48.4%
Wind Hydro 5.9%
Purchases 4.7%
1.0%
NEBRASKA P UBLIC P OWER D ISTRICT 1
MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)
The followi OVERVIEW OF BUSINESS n o the S ale of ebf'3S a. Control of g of 11 mem s p0pula y ct e State s. 93 counlles and more han 400
'"'1'"°':~ny llmtled to um I
- s I custo THESYSTE Tom t th nyt m ak I o 2015 o :>,6 O me
- v. t ('MW.), h 01 tri t h d av table 3 660 4 of capacity resoutC s that included 3.049. 1 MW of generatwn capacity from 12 owned and operatEld ge,,erabrig I n 2' p "l ov r v, lch th O ct s ope ti con rot.
7 7 MW m c paci y purch om Westem Area Power Adm1n tratlon. af\\d 63.6 MW of a capacity purchas rom Oma a Public Pow
- Dlstr t
("OPPO ~
ebraska City St lion Unit 2 (*NC2 ) coal* ired plant. Of the total cap city resources, 223. 7
- W are bei g sold a partici a on sales or other capae1ty sa es agreements, feavmg 3,436 7 W to serve 1rm retail and whol sale custom rs and to meet capacity r s rvo requirements. The highes summer an ime p a load of 3,030 3 MW was establish d 1n July 2012 and the highest intet anytlm
~ak load of 2,252.0 MW was e ta II h d m J nuary 2014 for rm requ1r m nt c tom r T e ollow ng tab e shows the Distnct's capacity resources from generation and respective summer 2015 ccr di d c pabili y T
Steam - Conw t1onal St m -
ucl r
Combined Cycle...................................................
Combustion urbine 1 '............................................
t-tydro........
Dt Wind t oJ..................................................................
(1)
(2 )
(lt (5) I Typ Ge 1 nd No 2......
on SPP cnt ri Summer 2015 umber of Accred1 ed Plants<'
- Caeabtht~ lMW}
1 p
3 695.0 55 6 1
764 0 251 1
2200 7.2 3
125 3 4 1 6
110 7 36 12 91 4 3.0 8
2.7 3 049.1 St und oon Distnc and their spectiv fuel types, summer Fu I Typ,e Coal Nucl ar Combined Cycl Coal Oil 0t tu~ I G atural G Water Wrnd Sum r 2015 1 3650 764.0 220.0 215 0 125 1 5.0 25.2 9 1 2 838.6
) 11 1979. 982 1974 2005 6. 19 8 1973 1958 1887. 1927, 1939 200 Nr..uRAS~A PuntJL Pm\\*ER Dis-nm *1 3
THE CUSTOMERS Retail and Wholesale Customers In 2015, the District served an average of 91, 140 retail customers. Currently the District's retail service territory includes 80 municipalities, of which 79 are municipal-owned distribution systems operated by the District for the municipality pursuant to a Professional Retail Operations ("PRO") Agreement. Details of the District's PRO Agreements are included in Note 12 in the Notes to Financial Statements.
The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District, subject to certain exceptions described in Note 12 in the Notes to Financial Statements. Effective January 1, 2016, the District entered into new 20-year Wholesale Power Contracts ("2016 Contracts"). Wholesale customers being served under the 2016 Contracts include 23 public power districts, which includes one cooperative, and 39 municipalities. Two public power districts and 11 municipalities are served under 2002 Wholesale Power Contracts ("2002 Contracts"). Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements.
The following charts show the District's average retail and wholesale cents per kilowatt-hour ("kWh") for the years ended December 31, 2011 through 2015. The District also reported average cents per kWh sold less customer collections for taxes and transfers to other governments, which are not included in the District's base rates for retail customers.
9.80
.s:: 9.00
~
~ 8.20 (I)
Q.
.!!l 7.40 c
(I) 0 6.60 5.80 AVERAGE CENTS PER kWh SOLD-RETAIL (Retail -All Classes) 8.75¢ 9.04¢ 9.06¢ 2011 2012 2013 2014 9.12¢ 2015 Average Cents per kWh Sold Average Cents per kWh Sold Less Government Taxes/Transfers AVERAGE CENTS PER kWh SOLD - WHOLESALE (Firm Wholesale Customers Only) 6.40 6.09¢ 5.96¢
.s:: 6.00
~
5.57¢
~ 5.60 5.39¢ (I)
Q.
.!!l 5.20 c
(I) 0 4.80 4.40 2011 2012 2013 2014 2015 4
NEBRASKA Puuuc Pow1m. D1s*1 RICI
Other Utilities (Nonfirm and Other Sales)
In addition, there are five participation sales agreements in place with other utilities for the sale of power and energy at wholesale from specific generating plants. Such sales are to Lincoln Electric System ("LES"), Municipal Energy Agency of Nebraska ("MEAN"), OPPD, Grand Island Utilities ("Grand Island"), and the City of Jacksonville, Florida ("JEA). The District also sells energy on a nonfirm basis in SPP and through transactions executed with other utilities by The Energy Authority ("TEA").
Transmission Customers The District owns and operates 5,225 miles of transmission and subtransmission lines, encompassing nearly the entire State of Nebraska. The District became a transmission owning member of SPP, a regional transmission organization, in 2009. The District files a rate with SPP annually that provides for the recovery of all transmission revenue requirements associated with transmission facilities equal to or greater than 115 kV. SPP collects and reimburses the District for the use of the District's transmission facilities by entities other than the District's firm requirements customers and all transmission customers still served directly by the District through grandfathered Transmission Agreements.
Customers. Energy Sales. and Revenues The following table shows customers, energy sales, and peak loads of the System, including participation sales, in each of the three years, 2013 through 2015.
Megawatt-Hour Sales Anytime Peak Load {MW}
Calendar Average Number of Wholesale Nativa Load Percentage Total Percentage Busbar Native Year Retail Customers Customers(1>
Sales(2>
Growth Sales <3>
Growth Load 2013 89,604 97 13, 140,595 (0.2) 20,830,094 8.i 2,872.6 2014 90,293 86 12,932,518 (1.6) 20,658,755 (0.8) 2,807.0 2015 91,140 82 12,579,390 (2.7) 20,990,883 1.6 2,695.0 (1)
At the end of 2015, includes sales to LES, MEAN, JEA, OPPD, Grand Island, and a yearly average of two nonfirm customers. Bilateral sales to utilities have decreased since SPP's transition to an integrated market on March 1, 2014.
(2)
Native load sales include wholesale sales to total firm requirements customers and include the responsibility of replacement power being procured by the District if the District's generating assets are not operating. Predominantly, native load customers are served under long-term total requirements contracts.
(3)
Total sales from the System include sales to LES from GGS and Sheldon; to MEAN from GGS and CNS; to Heartland from CNS, which sale commenced January 1, 2004, and terminated December31, 2013; to KCPL from CNS, which sale commenced January 1, 2005, and terminated on January 18, 2014; to MEAN, JEA, OPPD, and Grand Island from Ainsworth, which sales commenced October 1, 2005, and terminates on September 30, 2025; to OPPD, MEAN, LES and Grand Island from Elkhorn Ridge Wind Facility, which sales commenced March 1, 2009, and terminates on February 28, 2029; to MEAN from GGS and CNS, which sale commenced January 1, 2011, and terminates on December 31, 2023; to MEAN, Lincoln and Grand Island from Laredo Ridge Wind Facility, which sales commenced February 1, 2011, and terminates on January 31, 2031; to OPPD, LES and Grand Island from Broken Bow I Wind Facility, which sales commenced December 1, 2012, and terminates on November 30, 2032; to OPPD, Lincoln and MEAN from Crofton Bluffs Wind Facility, which sales commenced November 1, 2012, and terminates on October 31, 2032; and to OPPD from Broken Bow II Wind Facility which sale commenced October 1, 2014, and terminates on September 30, 2039.
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FINANCIAL INFORMATION The following tables summarize the District's financial position and operating results.
CONDENSED BALANCE SHEETS (in OOO's)
As of December 31, 2015 2014 2013 Assets:
Current Assets..............................................................
764,278 719,987 665,854 Special Purpose Funds..................................................
738,967 808,552 688,220 Utility Plant, Net............................................................
2,508,971 2,495,206 2,500,069 Other Long-Term Assets...............................................
353,639 800,406 795,792 Deferred Outflows of Resources......................................
40,775 26,794 16,504 Total Assets and Deferred Outflows............................
i 4,406,630
~ 4,850,945.j 4,666,439 Liabilities:
Current Liabilities..........................................................
218,858 395,676 352,229 Long-Term Debt............................................................
1,838,672 1,802,850 1,845,244 Other Long-Term Liabilities............................................
727,070 1,159,647 1, 109,567 Deferred Inflows of Resources Unearned Revenues..................................................
176,118 177, 143 101,861 Other Deferred Inflows...............................................
113,728 74,505 78,776 Net Position:
Net Investment in Capital Assets....................................
866,699 770,514 747,650 Restricted.....................................................................
40,492 43,889 42,883 Unrestricted.................... ;.............................................
424,993 426,721 388,229
- ~
Total Liabilities, Deferred Inflows, and Net Position.......
$ 4,406,,!330
$ 4.850,945
$ 4,666,439
./:t;;
CONDENSED RESULTS OF OPERATIONS (In OOO's)
For the years ended December 31, 2015 2014 2013 J.ilt Operating Revenues......................................................
$ 1,097,216
$ 1,122,454
$ 1, 106,291 Operating Expenses......................................................
{960,25m_
{1,010,693}
{941,887}
Operating Income.....................................................
136,957 111,761 164,404 Investment and Other Income.........................................
22,355 26,039 15,221 Debt and Other Expenses..............................................
{68,252j
{75,438}
{82,242}
Increase in Net Position............................................
91,060 62,362 97,383 SOURCES OF OPIERATING REVENUES (in OOO's)
For the years ended December 31, 2015 2014 2013 Firm Retail and Wholesale Sales....................................
848,345 887,619 878,324 Participation Sales.......................................................
77,192 81,063 112,061 Other Sales..................................................................
134,612 172,521 116,890 Other Operating Revenues.............................................
60,730 58,352 59,162 Unearned Revenues.......................................................
{23,663}
{77,101}
{60, 146}
Total Operating Revenues..........................................
~i 1,097,216
~ 1, 122,454 m 1, 106,291
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- NEBRASKA PunLic POWER D1sT1ucr
CONDENSED STATEMENTS OF CASH FLOWS (in OOO's)
For the :tears ended December 31, 2015 2014 2013 Net Cash Pro\\lided by Operating Activities.......................
372,503 362,365 407, 132 Net Cash Pro\\/ided by (Used in) ln~sting Activities...........
10,961 (199,101)
(19,931)
Net Cash Used in Capital and Financing Activities............
(388,483}
(241,874}
(381,591}
Net (Decrease) Increase in Cash and Cash Equivalents....
(5,019)
(78,610) 5,610 Cash and Cash Equivalents, Beginning of Year................
90,079 168,689 163,079 Cash and Cash Equivalents, End of Year....................
85,060
~
90,079 168,689 Revenues from Firm Retail and Wholesale Sales The District allocates costs bet'Neen retail and wholesale service and establishes its rates to produce revenues sufficient to meet its estimated respective retail and wholesale revenue requirements. Wholesale revenue requirements include unbundled costs accounted for separately between generation and transmission.
Transmission costs not recovered from the District's wholesale power contracts are expected to be recovered through rates charged by SPP. The rates for retail service include an amount to recover the costs of wholesale power service in addition to distribution system costs and government taxes and transfers. The District's wholesale power contracts provide for the establishment of cost-based rates. Such rates can be adjusted at such times as deemed necessary by the District. The wholesale power contracts also provide for the creation of a rate stabilization account. Any surplus or deficiency between revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be retained in the rate stabilization account. Any amounts in excess of the limits may be included as an adjustment to revenue requirements in the next rate review. The wholesale power contracts also include a provision for establishing a new/replacement generation fund. This provision would permit the District to collect an additional 0.5 mills per kWh above the normal revenue requirements to be used for future capital expenditures associated with generation.
The District implemented a 0.6% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who signed the new 2016 20-year wholesale power contract, and a 3.8% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who remain under the 2002 20-year wholesale power contract. The rate increase was higher for the 2002 Contracts as these customers will pay their share of previously incurred other post-employment benefits ("OPEB") costs through 2021. Customers under the 2016 Contracts are paying their share of OPEB costs over a longer period. No increase in retail rates was implemented in 2016. Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements.
The District implemented a 0.5% increase in the District's wholesale rates commencing on January 1, 2015. No increase in retail rates was implemented in 2015. The District had no wholesale or retail rate increase in 2014.
The District implemented a 3.75% increase in retail and wholesale rates on January 1, 2013.
Revenues from firm sales decreased $39.3 million, or 4.4%, from $887.6 million in 2014 to $848.3 million in 2015.
The decrease was due primarily to lower unbilled retail energy with a revenue impact of $14.4 million and a 1.4%
decrease in sales volume which was the result of milder temperatures. Revenues from firm sales increased
$9.3 million, or 1.1%, from $878.3 million in 2013 to $887.6 million in 2014. This increase was due primarily to higher unbilled retail revenues of $14.1 million partially offset by a 3.4% weather-related decrease in energy sales to firm wholesale customers.
Revenues from Participation Sales The District has participation sales agreements with other utilities that share operating expenses on a pro rata basis. Revenues from participation sales decreased from $81.1 million in 2014 to $77.2 million in 2015, a decrease of $3.9 million. This decline was due primarily to participation sales to LES which decreased by $4.4 million due to a 23.0% reduction in the dispatch of generation from Sheldon due to lower prices in the SPP Integrated Market. The decrease was partially offset by increased wind participation sales. Revenue from
participation sales decreased from $112.1 million in 2013 to $81.1 million in 2014, a decrease of $31.0 million.
The decrease was due primarily to contract expirations with Heartland Consumers Power District and KCP&L Greater Missouri Operations Company on December 31, 2013 and January 18, 2014, respectively, which was partially offset by increased wind participation sales.
Revenues from Other Sales Other sales consist of sales in SPP's Integrated Market and nonfirm sales to other utilities. TEA, of which the District is a member, has energy marketing responsibilities for the District's other and nonfirm off-system sales and the related management of credit risks. Other sales decreased from $172.5 million in 2014 to $134.6 million in 2015, a decrease of $37.9 million. This decrease was a result of lower prices in the SPP Integrated Market which was driven by lower natural gas prices and additional wind generation. Other sales increased from $116.9 million in 2013 to $172.5 million in 2014, an increase of $55.6 million. This increase was due primarily to additional revenues realized from greater nonfirm sales at higher market prices, including sales in SPP's Integrated Market which began on March 1, 2014.
Other Operating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues.
These revenues were $60.7 million, $58.4 million, and $59.2 million in 2015, 2014, and 2013, respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District.
Unearned Revenues Under the provisions of the District's wholesale power contracts, any surplus or deficiency between net revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be adjusted in the rate stabilization account. Any amounts in excess of the rate stabilization limits may be included as an adjustment to revenue requirements in the next rate review. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities, the balance of such surpluses or deficiencies are accounted for as "regulatory liabilities or assets", respectively.
The District recognizes net revenues in excess of revenue requirements in any year as a deferral or reduction of revenues. Such surplus revenues are excluded from the net revenues available under the General Revenue Bond Resolution ("General Resolution") to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues, even though the revenue accrual will not be realized as "cash" until some future rate period.
Such revenue deficiency is included, in the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are excluded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates.
The District deferred or decreased revenues a net amount of $23.7 million in 2015. The District's revenues in 2015 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of
$11.0 million, which surplus amount was deferred {decrease in revenues). In addition, the wholesale rates that were in place for 2015 included a refund of $12.0 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year{s) the surplus occurred.
Accordingly, the 2015 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment {increase in revenues) for such amount The District also deferred or decreased revenues by
$24. 7 million for the pre-collection of CNS refueling and maintenance outage costs. This regulatory liability will be eliminated through revenue recognition during the 2016 outage year.
The District deferred or decreased revenues a net amount of $77.1 million in 2014. The District's revenues in 2014 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of
$91.4 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2014 included a refund of $14.3 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred.
Accordingly, the 2014 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount.
The District deferred or decreased revenues a net amount of $60.1 million in 2013. The District's revenues in 2013 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of
$60.8 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2013 included a refund of $0.7 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred.
Accordingly, the 2013 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount.
Unearned revenues from prior periods of $1.9 million were refunded directly to customers in 2014. The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements in future rate periods was $176.1 million, $177.1 million, and $101.9 million, as of December 31, 2015, 2014, and 2013, respectively.
Operating Expenses The following chart illustrates operating expenses for the years ended December 31, 2013 through 2015.
$1,200
$1,000 Ill c
$800 0
- E
$600 Ill...
~ $400 0 c
$200
$0 2013
$1,011 2014 2015
- Power Purchased & Fuel
- Production Operation & Maintenance ("O&M")
Transmission & Distribution O&M
- Customer Service & Information Administrative & General
- Decommissioning Depreciation & Amortization Other Total operating expenses in 2015 were $960.3 million, a decrease of $50.4 million from 2014. Total operating expenses in 2014 were $1,010.7 million, an increase of $68.8 million from 2013. The changes were due primarily to the following:
Power purchased and fuel expenses were $365.1 million, $386.3 million, and $366.2 million in 2015, 2014, and 2013, respectively. These expenses decreased $21.2 million in 2015 as compared to 2014 due primarily to lower fuel costs as a result of decreased generation, lower market prices and fewer energy purchases in the SPP Integrated Market. These expenses increased $20.1 million in 2014 as compared to 2013 due primarily to activity in the SPP Integrated Market and the District's participation in new wind facilities.
Production operation and maintenance expenses were $242.8 million, $281. 7 million, and $24 7.8 million in 2015, 2014, and 2013, respectively. These costs decreased $38.9 million in 2015 as compared to 2014 due primarily to the costs associated with a planned refueling and maintenance outage at CNS completed November 2, 2014, which ended the station's first 24-month operating cycle. No such outage occurred in 2015. These costs NEBRASKA PUBLIC PmHR Dis !RIC r 9
increased $33.9 million in 2014 as compared to 2013 due primarily to additional costs associated with a planned refueling and maintenance outage. No such outage occurred in 2013.
Transmission and distribution operation and maintenance expenses were $87.3 million, $83.8 million, and
$76.4 million, in 2015, 2014, and 2013, respectively. These costs increased $3.5 million in 2015 as compared to 2014 and $7.4 million in 2014 as compared to 2013 both due primarily to increases in SPP fees. The District is charged by SPP for firm requirements customers for the qualifying transmission system upgrade projects of other SPP transmission owners.
Customer service and information expenses were $17.2 million, $17.5 million, and $16.6 million, in 2015, 2014, and 2013, respectively.
Administrative and general expenses were $66.3 million, $59.4 million, and $59.7 million, in 2015, 2014, and 2013, respectively. These costs increased $6.9 million in 2015 as compared to 2014 due primarily to increases in healthcare costs along with increased expenses for outside services.
Decommissioning expenses were $14.7 million, $18.5 million, and $10.7 million. in 2015, 2014, and 2013, respectively. Decommissioning expenses represent the net amount accrued each year for the future decommissioning of CNS. Such expenses are recorded in an amount equivalent to the income on investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year. Decommissioning expenses decreased $3.8 million in 2015 as compared to 2014 due to a decrease in income on investments. Decommissioning expenses increased $7.8 million in 2014 as compared to 2013 due to an increase in income on investments. No additional amounts for decommissioning were collected through rates in 2015, 2014, and 2013.
Depreciation and amortization expenses were $130.2 million. $126.4 million, and $127.3 million, in 2015, 2014, and 2013, respectively.
Increase in Net Position The increase in net position was $91.1 million, $62.4 million, and $97.4 million, in 2015, 2014, and 2013, respectively. The change in net position in 2015 as compared to 2014 increased $28.7 million and was due primarily to an increase in 2015 revenue requirements from increased collections for construction from revenue and for principal payments on commercial paper notes. partially offset by reduced collections for principal payments for revenue bonds. The change in net position in 2014 as compared to 2013 decreased $35.0 million and was due primarily to a decrease in 2014 revenue requirements for collections related to construction from revenue and commercial paper principal payments.
The following chart illustrates the District's operating revenues, other revenues, operating expenses, and other expenses for the years ended December 31, 2013 through 2015.
$1,200 ~-------------------
_ $1,150 Ill 5 $1,100
§ $1,050
~ $1,000 f
$950 0
$900 0
$850
$800 +-----
2013 2014 2015 Other Expenses
- Operating Expenses
- Other Revenues Operating Revenues 10 N1.11RASK.\\ Punuc PowLR Dis 1 RICT
DEBT SERVICE COVERAGE The District's debt service coverage ratio was 1.84, 1.50, and 1.73, in 2015, 2014, and 2013, respectively. The coverage was provided primarily by the amounts collected in operating revenues to fund the cost of utility plant additions, the amounts collected in operating revenues for principal and interest payments on the outstanding commercial paper notes, and the amounts collected for payments to those municipalities served by the District under long-term PRO Agreements. The increase in the 2015 debt service coverage ratio was primarily due to the fact that effective July 31, 2015, the obligation of the District to pay the principal, interest, bank fees, and expenses pursuant to the Taxable Revolving Credit Agreement is payable from the Pledged Property subject and subordinated to the pledge of the Pledged Property to the payment of the General Revenue Bonds.
FINANCING ACTIVITIES Good credit ratings allow the District to borrow funds at more favorable interest rates. Such ratings reflect only the view of such rating organizations, and an explanation of the significance of such rating may be obtained only from the respective rating agency. There is no assurance that such ratings will be maintained for any given period of time or that they will not be revised downward or be withdrawn entirely by the respective rating agency if, in its judgment, circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the market prices of bonds.
The District's credit ratings on its revenue bonds were as follows:
Moody's Investors Service............................................................................ A 1 Standard & Poor's Ratings Services............................................................. A+
Fitch Ratings................................................................................................. A+
(stable outlook)
(stable outlook)
(stable outlook)
In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series Bin the amount of
$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of Tax-Exempt Commercial Paper ("TECP"). The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.
In January 2016, the District issued TECP in the amount of $43.6 million to refund a portion of the 2005 Series C and 2006 Series A General Revenue Bonds. In February 2016, $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and B. The District plans to issue additional revenue bonds in 2016 to finance capital projects.
In February 2015, the District issued General Revenue Bonds, 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $42.0 million, which resulted in present value savings of $26.1 million.
Revenue bonds were issued in 2014 to refund existing bonds at lower rates and to finance capital projects.
Details of the District's debt balances and activity are included in Note 7 in the Notes to Financial Statements.
CAPITAL REQUIREMENTS The Board-authorized capital projects totaled approximately $501.0 million, $197.4 million, and $78.9 million, in 2015, 2014, and 2013, respectively. The District's capital requirements are funded with monies generated from operations, debt proceeds, and other available reserve funds.
NEURAsKA Punuc Powrn Dis 1 RICI
- 11 -
Capital projects for 2015 included:
$346.8 million for construction of a high-voltage transmission line and related substations from a GGS substation north to Cherry County, Nebraska and east to a new substation in Holt County, Nebraska
$33.9 million for modifications to the hot flue gas ductwork at GGS Unit 2
$33.1 million for construction of a high-voltage transmission line from a new Stegall, Nebraska substation to the existing Scottsbluff, Nebraska substation Capital projects for 2014 included:
$94.9 million for construction of a high-voltage transmission line and related substations from Hoskins Substation northeast of Norfolk, Nebraska to Neligh, Nebraska
$14. 7 million for replacement of a secondary super-heater outlet at GGS Unit 2
$7.0 million for replacement of a silo dust collector at GGS Units 1 and 2 Capital projects for 2013 included:
$27.1 million for replacement of a low pressure turbine at GGS Unit 1
$11.6 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2
$7. 7 million for fire protection upgrades at CNS There were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $87.2 million, $80.8 million, and $32.5 million for 2015, 2014, and 2013, respectively.
The Board-authorized budget for capital projects for 2016 is $147.2 million. The increase in the 2015 budget was due to large transmission projects authorized by SPP. The District will receive revenues from other transmission owners in SPP for their share of these projects over the projects' depreciable life.
Specific capital projects for 2016 include:
$25.0 million for construction of a high-voltage transmission line from a new Broken Bow, Nebraska substation, to an existing substation near Ord, Nebraska.
$16.4 million for construction of a new substation in Holt County, Nebraska
$12.7 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2 The following chart illustrates the Board-authorized capital projects for the years ended December 31, 2013 through 2015, including the Board-authorized budget for the year ended December 31, 2016.
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2013 2014 2015 2016 Budget RESOURCE PLANNING The District's core planning principles for its most recent Integrated Resource Plan ("IRP } aligns with the Board's strategic goals which include further diversifying its mix of generating resources (nuclear, coal, hydro, wind, energy efficiency and demand response}, energy storage, and capitalizing on the competitive strengths of Nebraska (available water, proximity to coal, and abundance of wind}. Key goals from the IRP include:
- 12 NE13RASKA P Ul3LIC Powi.:R Dis 1 RICT
Achieving a goal of 10% of the District's energy supply from renewable resources by 2020,
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Increasing focus on energy efficiency to meet customer load growth, and Increasing diversification with a trend toward cleaner energy The probabilistic analysis under the IRP focused on key future uncertainties, including customer load growth, future environmental regulations including carbon dioxide ("C02"), capital additions and operation and maintenance costs of new units, future fuel, and market prices for electricity. The results showed that with the District's recapture of 120 MWs of base load generation from expiring capacity and energy contracts out of CNS, and lower projected load growth, the District is positioned to meet its firm load requirement needs for the next 10 to 15 years. Specific actions on which the District will focus to meet load growth needs include addition of renewables, effectiveness of energy efficiency programs and evaluation of additional peaking capacity.
The District's Board approved the IRP during the second quarter of 2013. Although the IRP included a power uprate for CNS, the District's most recent evaluation of the costs and market risks related to a power uprate has led the District to decide not to engage in a power uprate for CNS at this time. Long-term operation of GGS appears to continue to be commercially viable even if additional long-term environmental controls are required.
The District would need to revisit this assumption if high C02 costs occur. Operation of Sheldon and Canaday appears marginally beneficial unless and until additional environmental controls or other costly major modifications are required. More wind and energy efficiency also appear beneficial, but not under a low native load growth scenario. The major uncertainties identified in the IRP are continually reviewed and evaluated as to their impact on the District. The District expects to issue its next IRP in 2018.
Renewable Energy The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition, the District has entered into power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all of the electric power output of these wind facilities. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities in Nebraska over similar terms. The District will pay only for energy delivered pursuant to such power purchase wind agreements and the cost of the substation and transmission work to connect these facilities to the District's electric system. Participating utilities will pay their pro rata share of energy delivered from these facilities along with associated capital additions for substation and transmission work.
Hydrogen Generation Monolith Materials, Inc. ("Monolith") has expressed an interest to construct and operate a carbon black facility adjacent to the District's Sheldon coal-fired generating facility in Nebraska. The electric load to serve any Monolith facility will be served by Norris Public Power District, a firm wholesale customer of the District. Monolith may be the single-largest industrial customer served in the District's territory. The District is in negotiations with Monolith to purchase the carbon black plants' production of hydrogen, which will be produced by Monolith as a co-product from its production of carbon black. The District then expects to convert its existing coal-fired boiler at Sheldon Station Unit No. 2 to burn hydrogen fuel. The boiler conversion is expected to result in a reduction of C02, sulfur dioxide, mercury, and other air emissions.
ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks, including exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the creditworthiness of its counterparties, and the operational risks associated with transacting in the wholesale energy markets.
To help manage energy risks, including the risks related to the District's participation in the SPP Integrated Market, the District relies upon TEA to both transact on its behalf in the wholesale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets.
TEA combines a strong knowledge of the District's system, an in-depth understanding of the wholesale energy
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markets, experienced people, and state-of-the-art technology to deliver a broad range of standardized and customized energy products and services to the District.
TEA has assisted the District in developing its Energy Risk Management ("ERM"} program and associated ERM Governing Policy ("ERM Policy"}. The ERM Policy, approved by the Board, establishes guidelines and objectives and delegation of authorities necessary to govern activities related to the District's ERM program. The objective of the ERM program is to increase fuel and energy price stability by hedging the risk of significant adverse impacts to cash flow. These adverse impacts could be caused by events such as natural gas or power price volatility, or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed.
The District's ERM Policy has been revised to reflect the District's participation in the SPP Integrated Market. In addition, the Board has also approved an Energy Risk Management Approved Products and Limits guideline that will be applicable to all physical and financial energy or power-related transactions of the District, including transactions related to the District's participation in the SPP Integrated Market.
ECONOMIC FACTORS Nebraska's economy continues to grow but at a slower rate than in recent years. The state's inflation adjusted gross state product ("GSP"} increased by.1.1 % from the third quarter of 2014 to the third quarter of 2015. This was less than the 2.0% increase in the national gross domestic product over the same 12-month period and was a sharp decrease from Nebraska's 2.7% increase in GSP from the third quarter of 2013 to the third quarter of 2014. Nebraska's slowdown in GSP growth has been due to declines in the value of agricultural outputs and durable goods manufacturing during the latest two-year period and more recent declines in the transportation and warehousing sector.
Nebraska and the Midwest region continue to experience unemployment rates that are near pre-recession levels and are well below the national averages. Nebraska's unemployment rate decreased from an annual average of 3.3% for 2014 to 3.0% in 2015 and remained well below the 2015 national average unemployment rate of 5.3%.
Nebraska's preliminary, seasonally adjusted unemployment rate was 3.0% in December 2015, up slightly from 2.9% in *December 2014. Both numbers were well below the national December seasonally adjusted unemployment rates of 5.0% in 2015 and 5.6% in 2014. In December 2015, Nebraska's preliminary unemployment rate was the third lowest in the nation. The District continues to monitor changes in national and global economic conditions, as these could impact cost of debt and access to capital markets CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY The Electric Utility Industry In General The electric utility industry has been, and in the future may be, affected by a number of factors which could impact the financial condition and competitiveness of electric utilities, such as the District. Such factors include, among others:
o effects of compliance with rapidly changing environmental, safety, licensing, regulatory, and legislative requirements, Q
changes resulting from energy efficiency and demand-side management programs on the timing and use of electric energy, other federal and state legislative and regulatory changes, increased wholesale competition from independent power producers, marketers, and brokers, "self-generation" by certain industrial and commercial customers, e
issues relating to the ability to issue tax-exempt obligations, e
severe restrictions on the ability to sell to nongovernmental entities electricity from generation projects financed with outstanding tax-exempt obligations, changes from projected future load requirements, o
increases in costs, shifts in the availability and relative costs of different fuels,
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inadequate risk management procedures and practices with respect to, among other things, the purchase and sale of energy, fuel, and transmission capacity, effects of financial instability of various participants in the power market, climate change and the potential contributions made to climate change by coal-fired and other fossil-fueled generating units, increased regulation of nuclear power plants in the United States resulting from the earthquake and tsunami damage to certain nuclear power plants in Japan, and issues relating to cyber and physical security.
Any of these general factors (as well as other factors) could have an effect on the financial condition of the District.
Competitive Environment in Nebraska While wholesale competition is expected to increase in the future, there is a Nebraska statute that prohibits competition for retail customers. Pursuant to state statutes, retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppliers and/or pursuant to an order of the Nebraska Power Review Board. While state statutes do not provide for wholesale suppliers of electricity to have exclusive rights to serve a particular area or customer at wholesale, wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements.
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INDEPENDENT AUDITOR'S REPORT To the Board of Directors of the Nebraska Public Power District:
We have audited the accompanying financial statements of Nebraska Public Power District (the "District") which comprise the balance sheets as of December 31, 2015 and 2014, and the related statements of revenues, expenses, and changes in net position, and statements of cash flows for the years then ended.
fJianagement's Responsibili'iy for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditor's Responsibility Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the District's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the District's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the District as of December 31, 2015 and 2014, and the respective changes in financial position and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Other Matters The accompanying management's discussion and analysis and the supplemental schedules on pages 2 through 15 and 43 and 44, respectively, are required by accounting principles generally accepted in the United-States of America to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential partYof financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audits of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
Our audits were conducted for the purpose of forming an opinion on the financial statements that collectively comprise the District's basic financial statements. The statistical review is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has not been subjected to the auditing procedures applied in the audits of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.
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FINANCIAL STATEMENTS Nebraska Public Power District Balance Sheets as of December 31, (in OOO's)
ASSETS AND DEFERRED OUTFLOWS Current Assets:
Cash and cash equivalents.....................................................................
Investments...........................................................................................
Receivables, less allowance for doubtful accounts of $515 and $497, respectively..............................................................
Fossil fuels, at average cost...................................................................
Materials and supplies, at average cost...................................................
Prepayments and other current assets....................................................
Special Purpose Funds:
Construction funds.................................................................................
Debt reser-.e funds.................................................................................
Employee benefit funds..........................................................................
Decommissioning funds.........................................................................
Utility Plant, at Cost:
Utility plant in ser'IJice.............................................................................
Less reser.e for depreciation...................................................................
Construction work in progress.................................................................
Nuclear fuel, at amortized cost................................................................
Other Long-Term Assets:
Regulatory asset for asset retirement obligation........................................
Regulatory asset for other postemployment benefit obligation....................
Long-term capacity contracts.................................................................
Unamortized financing costs...................................................................
Investment in The Energy Authority.........................................................
Other....................................................................................................
Total Assets.................................................................................
Deferred Outflows of Resources:
2015 85,060 400,426 110,089 39,335 117,430 11 938 764,278 76,503 91,772 3,344 567,348 738,967 4,751,016 2,620,091 2, 130,925 209,626 168,420 2,508,971 32,323 121,595 172,966 8,654 7,018 11 083 353,639 4,365,855 Unamortized cost of refunded debt..........................................................
40 775 TOTAL ASSETS AND DEFERRED OUTFLOWS...........................................
$ 4.406 630 LIABILmES, DEFERRED INFLOWS, AND NET POSmON Current Liabilities:
Revenue bonds, current..........................................................................
114,860 Notes and credit agreements, current......................................................
Accounts payable and accrued liabilities..................................................
63,614 Accrued in lieu of tax payments..............................................................
9,948 Accrued payments to retail communities.................................................
6,087 Accrued compensated absences............................................................
16,857 Other....................................................................................................
7,492 218,858 Long-Term Debt:
Re11enue bonds, net of current.................................................................
1,596,972 Notes and credit agreements, net of current.............................................
241,700 1,838,672 Other Long-Term Liabilities:
Asset retirement obligation.....................................................................
600,311 Other postemployment benefit obligation..................................................
121,595 Other....................................................................................................
5164 727,070 Total Liabilities.............................................................................
2,784,600 Deferred Inflows of Resources:
Unearned revenues................................................................................
176, 118 Other deferred inflows.............................................................................
113,728 289,846 Net Position:
Net investment in capital assets..............................................................
866,699 Restricted.............................................................................................
40,492 Unrestricted..........................................................................................
424,993 1,332, 184 TOTAL LIABILmES, DEFERRED INFLOWS, AND NET POSITION.................
~ 4,406,6~0 The accompanying notes to financial statements are an integral part of these statements.
2014 90,079 336,753 122,686 36,574 121,764 12 131 719,987 143,490 95,463 4,055 565,544 808,552 4,674,500 2,533,100 2,141,400 151,712 202,094 2,495,206 459,991 125,747 179,938 10,278 7,895 16 557 800,406 4,824, 151 26,794
~ ~ ~5Q 945 109,835 185,503 58,073 10,040 6,148 16,569 9,508 395,676 1,710,850 92,000 1,802,850 1,026,357 127,247 6043 1,159,647 3,358, 173 177, 143 74505 251,648 770,514 43,889 426,721 1,241,124
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Principal Amounts Due Within One Year 114,860 114,860 In February 2015, the District issued General Revenue Bonds, 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $42.0 million, which resulted in present value savings of $26.1 million.
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Also in February 2015, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2026 through January 1, 2041 General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2036 through January 1, 2041 General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2023 through January 1, 2037 General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2024 through January 1, 2038, and General Revenue Bonds, 2012 Series C, maturing on January 1 *. 2024 In December 2014, the District issued General Revenue Bonds, 2014 Series C in the amount of $162.9 million to advance refund $170.6 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $16.5 million, which resulted in present value savings of $12.4 million.
Also in December 2014, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
0 General Revenue Bonds, 2005 Series A, maturing on January 1, 2026, General Revenue Bonds, 2005 Series B-2, maturing on January 1, 2017, General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2017 through January 1, 2030, General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2017 through January 1, 2036, General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2018 through January 1, 2022, o
General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2019 through January 1, 2023, and General Revenue Bonds, 2012 Series C, having maturity dates ranging from January 1, 2019 through
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In July 2014, the District issued General Revenue Bonds, 2014 Series A in the amount of $195.2 million to finance $114.0 million of the costs of transmission capital additions and to advance refund $81.2 million of bonds.
Additionally, the District issued General Revenue Bonds, 2014 Series B {Taxable) in the amount of $24.4 million to advance refund $24.2 million of bonds. The refundings reduced total debt service payments over the life of the bonds by $11.4 million, which resulted in present value savings of $6.9 million.
Also in July 2014, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
o General Revenue Bonds, 2005 Series A, having maturity dates ranging from January 1, 2016 through January 1, 2025, ca General Revenue Bonds, 2005 Series B-1, maturing on January 1, 2016,
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General Revenue Bonds, 2005 Series B-2, maturing on January 1, 2016, General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2019 through January 1, 2030, and General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2020 through January 1, 2031.
Certain of the General Revenue Bonds, from the following series, with outstanding principal amounts that aggregate $472.2 million as of December 31, 2015, were legally defeased and are no longer outstanding: 2005 Series C, 2006 Series A, 2007 Series B, 2008 Series B, and 2012 Series C.
Certain of the General Revenue Bonds, from the following series, with outstanding principal amounts that aggregate $337.3 million as of December 31, 2014, were legally defeased and are no longer outstanding: 2005
Series A, 2005 Series B-1, 2005 Series B-2, 2005 Series C, 2006 Series A, 2007 Series B, 2008 Series B, and 2012 Series C. Said defeased bonds are payable solely from United States Treasury Obligations in irrevocable escrow accounts. Accordingly, the bonds and the related escrow accounts are not included in the Balance Sheets.
Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2015, are as follows (in OOO's):
Debt Seruce Principal Year Payments Payments 2016............................................
191,325 114,860 2017............................................
163,208 91,795 2018............................................
163,211 96,310 2019............................................
138,727 76,435 2020............................................
138,620 79,930 2021-2025....................................
631, 132 393,840 2026-2030....................................
470,980 323,790 2031-2035....................................
333,616 261,345 2036-2040....................................
138,918 117, 110 2041-2043 ************************************
35,035 32,435 Total Payments....................,.......
$ 2,404,772
$ 1,587,850 The fair value of outstanding revenue bonds was determined using currently published rates. The fair value was estimated to be $1,765.4 million and $1,891.5 million at December 31, 2015 and 2014, respectively.
Commercial Paper Notes The District is authorized to issue up to $150.0 million of TECP notes. A $150.0 million line of credit expiring July 1, 2017, is maintained with two commercial banks to support the sale of the TECP notes. The District had
$83.0 million and $92.0 million of TECP notes outstanding at December 31, 2015 and 2014, respectively. The proceeds of the TECP notes have been used to provide short-term financing for certain capital additions and for other lawful purposes of the District. The effective interest rate on outstanding TECP notes was 0.06% and 0.08%
for 2015 and 2014, respectively. The notes outstanding are anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the commercial paper notes approximates market value due to the short-term nature of the notes.
Line of Credit Agreement The District has a line of credit of $150.0 million expiring July 1, 2017, that supports the payment of the principal outstanding of the TECP notes. No amounts were drawn on the line of credit as of December 31, 2015 and 2014.
Taxable Revolving Credit Agreement The District has entered into a Taxable Revolving Credit Agreement ("TRCA") with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 million. The TRCA allows the District to increase the loan commitments to $300.0 million. The District had outstanding balances under the TRCA of $158.7 million and $185.5 million, at December 31, 2015 and 2014, respectively. The TRCA was renewed on July 31, 2015 and terminates on July 30, 2018. The outstanding amount is anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the revolving credit agreements approximates market value due to the short-term nature of the agreements.
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Rewnue bonds consist of the following (in OOO's except interest rates):
December 31 Interest Rate 2015 2014 General Rewnue Bonds:
2005 Series A Serial Bonds 2015............................
5.25%
15 2005 Series C:
Serial Bonds: 2015-2025, 2040.....................
3.875% -
5.00%
44,230 45,985 2030-2034..............................
4.75%
18,240 2035-2040..............................
5.00%
27,500 2006 Series A:
Serial Bonds: 2015-2025..............................
4.00% -
5.00%
5,145 2031-2035..............................
5.00%
10,240 2036-2040..............................
4.375%
400 400 2036-2040..............................
5.00%
30,020 2007 Series B:
Serial Bonds: 2015-2026 ******************************
4.375% -
5.00%
111,825 142,565 Term Bonds:
2027-2031..............................
4.65%
31,190 36,140 2032-2036..............................
5.00%
7,120 19,270 2008 Series B:
Serial Bonds: 2015-2029... ~..........................
4.00% -
5.00%
38,785 136,245 Term Bonds:
2030-2032..............................
5.00%
22,860 32,390 2033--2037..............................
5.00%
40,375 50,880 2038-2040..............................
5.00%
7,180 7,180 2009 Series A Taxable Build America Bonds:
Term Bonds:
2019-2025..............................
6.606%
17,465 17,465 2026-2034..............................
7.399%
32,890 32,890 2009 Series C Serial Bonds 2014-2019...................
3.50% -
4.25%
6,595 8,515 201 O Series A Taxable Build America Bonds:
Serial Bonds: 2019-2024..............................
3.98% -
4.73%
31,875 31;015 Term Bonds:
2025-2029..............................
5.323%
27,985,,
27,985 2030-2042..............................
5.423%
54,190 54,190 2010 Series B Taxable Serial Bonds 2015-2020.......
2.858% - 4.18%
4,415 5,210 2010 Series C:
Serial Bonds: 2015-2025..............................
3.00%" 5.00%
64,520 79,615 Term Bonds:
2026-2030..............................
4.00%
6,165 6,165 2026-2030..............................
5.00%
14,180 14,180 2011 Series A Serial Bonds 2015-2016...................
2.50% -
5.00%
7,115 ;
15,815 2012 Series A Serial Bonds 2015-2034...................
3.00% - 5.00%
198,310 205,905 2012 Series B:
Serial Bonds: 2015-2032..............................
2.00% -
5.00%
95,875 99,325 Term Bonds:
2033--2036..............................
3.625%
2,320 2,320 2037-2042..............................
3.625%
4,155 4,155 2012 Series C Serial Bonds 2015-2028...................
3.00% -
5.00%
37,340 52,735 2013 Series A Serial Bonds 2015-2033...................
3.00% -
5.00%
103,815 111,480 2014 Series A:
Serial Bonds: 2015-2038..............................
2.00% -
5.00%
156, 145 161,385 Term Bonds:
2039-2043..............................
4.00%
31,650 31,650 2039-2043..............................
4.125%
1,945 1,945 2014 Series B Taxable Serial Bonds 2015................
0.48%
24,415 2014 Series C Serial Bonds 2015 - 2033..................
2.00% -
5.00%
162,415 162,890 2015 Series A-1 Serial Bonds 2022-2034................
3.00% -
5.00%
119,400 2015 Series A-2:....................................................
Serial Bonds: 2015-2034..............................
3.00% -
5.00%
56,915 Term Bonds:
2035-2039..............................
5.00%
461205 Total par amount of rewnue bonds...................................................................
1,587,850 1,714,325 Unamortized premium net of discount..........................................................
1231982 106,360 1,711,832 1,820,685 Less - current maturities of revenue bonds...................................................
(114,860}
(109,83fil.
Total rewnue bonds................................................................................J.1,596,9?.f..
~1,l10.850
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- 8. PAYMENTS IN LIEU OF TAXES:
The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District. Such payments totaled $10.0 million and $10.1 million for each of the years ended December31, 2015 and 2014, respectively.
- 9. ASSET RETIREMENT OBLIGATIONS:
Asset retirement obligations ("ARO") are calculated at the present value of a long-lived asset's applicable disposal costs and are recorded in the period in which the liability is incurred. This liability is accreted during the remaining life of the associated assets and adjusted periodically based upon updated estimates. The District has recorded an obligation for the fair value of its legal liability for the ARO associated with CNS, 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. A study was completed to update the costs for the ARO for CNS in 2015 because the last study was completed in 2008 and changes were expected due to the recent decommissioning of plants by other industry participants. Based on the results of the 2015 study and refreshed assumptions, the ARO was reduced by $477.8 million with a corresponding reduction in the related regulatory asset.
ASC 410, Asset Retirement and Environmental Obligations, requires capitalization of the costs to the related asset and depreciation of these costs over the same period as the related asset. The District does not use depreciation as a cost component for rates. Accordingly, the District has established a regulatory asset, under accounting guidance in Re10, for the costs that will be recovered in future rates. A significant amount of the ARO was funded by decommissioning funds of $567.3 million and $565.5 million as of December 31, 2015 and 2014, respectively. See Note 2 for additional information.
The following table shows changes to the ARO that occurred during the years ended December 31,
- 2015 and 2014, and are included in Other long-term liabilities section of the accompanying Balance Sheets as of December 31, (in OOO's):
2015 2014 Balance, beginning of year.............................................................................. $ 1,026,357 977,083 Accretion......................................................................................................
51,764 49,274 ARO adjustment............................................................................................
{477,810}
Balance, end of year..................................................... _................................. $
600,311
$ 1,026,357
- 10. RETIREMENT PLAN:
The District's Employees' Retirement Plan (the "Plan") is a defined contribution pension plan established and administered by the District to provide benefits at retirement to regular full-time and part-time employees. There were 1,955 active plan members at December 31, 2015. Plan provisions and contribution requirements are established and may be amended by the Board.
Plan members are eligible to begin participation in the Plan immediately upon hire. Contributions ranging from 2%
to 5% of base pay are eligible for District matching dollars after six months of employment. The District contributes two times the Plan member's contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District contributes one times the Plan member's contribution. The Participants' contributions were $12.8 million and $11.9 million for 2015 and 2014, respectively. The District's matching contributions were $12.1 million and $11.8 million for 2015 and 2014, respectively. Total contributions of $1.4 million and $1.3 million were accrued in Accounts payable and accrued liabilities for the years ended December 31, 2015 and 2014, respectively.
Plan members are immediately vested in their own contributions and earnings and become vested in the District's contributions and earnings based on the following vesting schedule:
Years of Vesting Participation 5 years or more....................................
4 years................................................
3 years................................................
2 years................................................
Less than 2 years................................
Percent 100%
75%
50%
25%
0%
Nonvested District contributions are forfeited upon termination of employment. Such forfeitures are first used to cover Plan administrative expenses and any remaining forfeitures are used to reduce District matching contributions.
- 11. OTHER POSTEMPLOYMENT BENEFITS:
A. Plan Description and Funding Policy -
The District's Post-Employment Medical and Life Benefits Plan ("Plan") provides postemployment hospital-medical and life insurance benefits to qualifying retirees, surviving spouses, and employees on long-term disability and their dependents. Benefits and related eligibility, funding and other Plan provisions, for this single-employer, defined benefit Plan, are authorized by the Board.
Contributions from Plan members are the required premium share, which is based on date of hire and/or age. The District pays all or part of the cost (determined by age) for employees hired before 1993. Qualifying employees hired after 1992 are subject to a contribution cap that limits the District's portion of the cost of such coverage to the full premium the year the employee retired or the amount at the time the employee reaches age* 65, or the year in which the employee retires if older than age 65. Any increases in the cost of such co~erage in subsequent years are paid by Plan members. Qualifying employaes hired after 1998 are not eligible for postemployment hospital-medical benefits once they reach age 65 or Medicare eligibility. Employees hired after 2003 are not eligible for postemployment hospital-medical benefits. The District amended the plan effective July 1, 2007, to provide that any former employee who is rehired will receive credit for prior years of service. The District further amended the plan effective September 1, 2007, to provide that employees hired or rehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for postemployment hospital-medical benefits.
In May 2015, the Board approved a change for Medicare-eligible retirees for prescription drugs from the District's self-insured employee prescription plan to a group insured Medicare Part D supplement effective January 1, 2016. The District also changed its funding plan to contribute, at a minimum, the actuarially-determined annual required contribution ("ARC") to achieve full funding status on or before December 31, 2033, and to pay benefits/expenses from the OPEB Trusts.
Contributions in the form of premium payments by OPEB Plan members were $0.6 million, $0.5 million and $0.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Members do not contribute to the cost of the life insurance benefits.
B. Annual OPEB Cost and Net OPEB Obligation -
The annual OPEB costs are determined by actuaries and equal (a) the ARC, (b) one year's interest on the net OPEB obligation, and (c) an adjustment to the ARC to offset the effect of actuarial amortization of past under-or over-collected contributions. Commencing in 2016, the OPEB Trusts will be funded with the entire ARC and benefits/expenses will be paid directly from the Trusts. Prior to 2016, the District included in expenses and rates the OPEB benefits/expenses expected in the current period and the amount authorized for funding in the Trust for OPEB benefit payments for future periods. The difference between the annual OPEB cost and the District's contributions are included in the net OPEB obligation. As the District uses regulatory accounting to ensure costs are consistent with those included in the rates, the offset to the net OPEB obligation is a regulatory asset.
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The following table shows the components of the District's OPEB cost for the year, the amount actually contributed, and changes in the District's net OPES obligation as of December 31, (in OOO's):
2015 2014 2013 Annual required contribution................................................... $
28,223 32,026 35,030 Interest on net OPEB obligation..............................................
7,859 5,865 5,583 Adjustment to annual required contribution..............................
{11,832}
{5,803}
{5, 191}
Annual OPEB cost................................................................
24,250 32,088 35,422 Contributions made...............................................................
{28,402)
{29,816)
{23,603)
(Decrease} Increase in net OPES obligation............................
(4, 152) 2,272 11,819 Net OPES obligation, beginning of year...................................
125,747 123,475 111,656 Net OPES obligation, end of year........................................... $
121,595
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125,747 123,475 The District's annual OPES cost, the percentage of annual OPEB cost contributed, and the net OPEB obligation for 2015, 2014, and 2013 were as follows (in OOO's):
Annual OPES Percentage of Net OPES Year Cost Annual OPEB Obligation Cost Contributed 2015 24,250 117.1%
121,595 2014 32,088 92.9%
125,747 2013 35,422 66.6%
123,475 C. Funded Status and Funding Progress -
At December 31, 2015, there ware two Trusts for OPES, the "Nebraska Public Power District Post-Employment Medical and Life Benefits Trust" and the "Nebraska Public Power District Retired Employee Life Benefit Trust". In 2016, the OPES Trust for Medical and Life Benefits was amended as the "Amended and Restated Nebraska Public Power District Medical and Life Benefits Trust for Employees in Retirement Status" and a separate, OPES Trust was established for employees in disability status as the, "Nebraska Public Power District Hospital-Medical and Employee Life Insurance Benefit Trust for Employees in Disability Status." Retiree Life Benefits will continue to be paid from the Nebraska Public Power District Retired Employee Life Benefit Trust until funds are exhausted.
This Trust will then be terminated and these benefits will be paid from the OPEB Trust for employees in retirement status. Stand-alone financial reports will be prepared for OPEB commencing in 2016.
Total OPEB contributions in 2015 were $28.4 million, which included $11.5 million deposited in the Trust and
$16.9 million paid for the cost of benefits/expenses. Total contributions in 2014 were $29.8 million, which included
$11.9 million deposited in the trust and $17.9 million paid for the cost of benefits. Total contributions in 2013 were
$23.6 million, which included $10.0 million deposited in the trust and $13.6 million paid for the cost of benefits.
Actuarial valuations were completed as of January 1, 2015 and 2014. The information as of January 1, 2013, was based on information from the actuary's model. The Actuarial Value of Assets was based on the market values of the Plan's assets. The Actuarial Accrued Liability ("AAL ") was the present value of benefits attributable to past accounting periods and decreased by $196.3 million in the 2015 valuation. The decrease was due primarily to the plan change for prescription drugs for Medicare-eligible retirees and the commitment to fund the entire ARC and pay benefits/expenses from the OPEB Trusts which accounted for $132.8 and $65.5 million of the decrease, respectively.
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Actuarial Actuarial Unfunded Funded Cow red UAAL to Value of Accrued Actuarial Accrued Cow red Assets Liability (AAL)
Liability (UAAL)
Ratio Payroll Payroll
{a}
{b}
{b-a}
{alb}
{c}
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2015
$64,487
$309,908
$245,421 20.8%
$186,952 131%
2014
$48,274
$506,200
$457,926 9.5%
$186,637 245%
2013
$30,781
$520,705
$489,924 5.9%
$187,378 261%
The above schedule presents multiyear trend information about whether the actuarial value of plan assets is increasing or decreasing over time relative to the actuarial accrued liability for benefits. Actuarial valuations of an ongoing plan involve estimates of the value of reported amounts and assumptions about the probability of occurrence of events far into the future. Examples include assumptions about future employment, mortality, and the healthcare cost trend. Amounts determined regarding the funded status of the plan and the annual required contributions of the employer are subject to continual revision as actual results are compared with past expectations and new estimates are made about the future.
D. Actuarial Methods and Assumptions -
Projections of benefits for financial reporting purposes are based on the substantive plan (the plan as understood by the employer and the plan members) and include the types of benefits provided at the time of each valuation and the historical pattern of sharing benefit costs between the employer and plan members to that point. The actuarial methods and assumptions used include techniques that are designed to reduce the effects of short-term volatility in actuarial accrued liabilities and the actuarial value of assets, consistent with the long-term perspective of the calculations.
The actuarial assumptions and methods used for the valuations on January 1, 2015, 2014 and 2013, were as follows:
The Pre-Medicare healthcare cost trend rates ranged from 8.0% initial to 6.2% ultimate for 2015, from 5.9% initial to 4.4% ultimate for 2014, and from 8.5% initial to 4.6% ultimate for 2013.
f)
The Post-Medicare healthcare cost trend rates ranged from 6.8% initial to 6.2% ultimate for 2015, from 6.2% initial to 4.5% ultimate for 2014, and from 8.5% initial to 4.6% ultimate for 2013.'"
The discount rate used was 6.25%, 4.75%, and 5.0% for 2015, 2014, and 2013, respectively, which was based on the expected return on investments used to fund benefit payments. The higher rate for 2015 was due to the commitment to fund at least 100% of the ARC and to pay all benefits/expenses directly from the Trusts commencing in 2016.
An inflation rate of 2.1% was assumed for 2015 and 3.5% was assumed for 2014 and 2013.
e Commencing in 2015, the unfunded AAL will be amortized over a period of time such that the plan will be fully funded by 2033. For 2015, the amortization period was 18 years. For 2014 and 2013, amortization for the initial unfunded AAL was determined using a closed period of 30 years and the level percentage of projected payroll method.
o The Unit Credit Actuarial Cost method was used for all three years.
o The mortality table used for participants was the RP2014 Aggregate/Scale MP2014 for 2015 and the RP2000HA/Scale BB for 2014 and 2013.
E. Market Value of Plan Investments -
The investments in the OPEB plan include corporate and government debt, foreign and domestic stocks, mutual funds and cash. Plan assets included funds in the Employee Benefit Funds for retiree life insurance of $1.1 million, $1.2 million, and $1.4 million at December 31, 2015, 2014, and 2013, respectively. The market value of plan assets, including the funds in the Employee Benefit Funds, was $75.2 million, $64.5 million, and $48.3 million at December 31, 2015, 2014, and 2013, respectively.
- 12. COMMITMENTS AND CONTINGENCIES:
A. Fuel Commitments -
The District has various coal supply contracts and a coal transportation contract with minimum future payments of
$273.0 million at December 31, 2015. These contracts expire at various times through the end of 2018. The coal transportation contract in place is sufficient to deliver coal to the generation facilities through the expiration date of the aforementioned contracts and is subject to price escalation adjustments.
The District has a contract for conversion services of uranium to uranium hexafluoride which is in effect through 2018, a contract for enrichment services through 2024, and a contract for fabrication services through January 18, 2034, the end of the current operating license of CNS. These commitments for nuclear fuel material and services have combined estimated future payments of $265.0 million.
- 8. Power Purchase and Sales Agreements -
The District has entered into a participation power agreement (the "NC2 Agreement") with OPPD to purchase 23.7% of the power of the NC2, estimated to be 161 MW of the power from the 663 MW coal-fired power plant constructed by OPPD. The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs, and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursuant to such step-up provision is limited to 160% of its original participation share (23.7%). No such default has occurred to date.
The District has entered into a participation power sales agreement with Municipal Energy Agency of Nebraska ("MEAN") for the sale to MEAN of the power and energy from Gerald Gentleman Station ("GGS") and CNS of 50 MW which began January 1, 2011 and continues through December 31, 2023.
The District has entered into power sales agreements with Lincoln Electric System CULES") for the sale to LES of 30% of the net power and energy of Sheldon Station ("Sheldon") and 8% of the net power and energy of GGS. In return, LES agrees to pay 30% and 8% of all costs attributable to Sheldon and GGS, respectively. Each agreement is to terminate upon the later of the last maturity of the debt attributable to the respective station or the date on which the District retires such station from commercial operation.
The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately $36.3 million. These purchases are subject to rate changes.
The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition, the District has power purchase agreer:nents with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities in Nebraska over similar terms.
The District has entered into a power purchase agreement with Central for the purchase of the net power and energy produced by the Kingsley Project during its operating life. The Kingsley Project is a hydroelectric generating unit at the Kingsley Dam in Keith County, Nebraska with an accredited net capacity of 37 MW.
The District has entered into long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO Agreements expire on various dates between March 1, 2023 and May 1, 2033. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreement.
C. Wholesale Power Contracts The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District The District entered into new 20-year Wholesale Power Contracts ("2016 Contracts") with 23 public power districts, which includes one cooperative, and 39 municipalities,
effective January 1, 2016. Two public power districts and 11 municipalities are served under 2002 Wholesale Power Contracts ("2002 Contracts"), which expire on December 31, 2021.
The 2016 Contracts allow a wholesale customer to give notice to reduce its purchase of demand and energy requirements from the District based on a comparison of the District's average annual wholesale power costs in a given year compared to power costs of U.S. utilities for such year listed in the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given utility can compare its power costs on a percentile basis to the CFC published quartile information. The 2016 Contracts allow a wholesale customer to reduce its demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given year is higher than the 451h percentile level (the "Performance Standard Percentile") of the power costs of U.S. utilities for such year as listed in the CFC Data. The 2016 Contracts would not allow any reductions in demand and energy purchases by a wholesale customer as long as the District's average annual wholesale power costs percentile remained below the Performance Standard Percentile. The following table lists the District's wholesale power costs percentile for the calendar years 2010 to 2014 set forth in the CFC Data:
CFC Data Year Percentile 2010 18.3%
2011 24.4%
2012 29.1%
2013 31.0%
2014 27.6%
The 2002 Contracts allow a wholesale customer to reduce its purchases of demand and energy upon giving appropriate notice. Reductions could amount to as much as 90% of their demand and energy requirements under certain circumstances. All wholesale customers under the 2002 wholesale contracts are required to purchase at least 10% of their demand and energy from the District through December 31, 2021.
The District has received notices from nine wholesale customers as to their intent to level off, reduce, or terminate the requirements under their 2002 wholesale contracts for various amounts from 2017 through 2021. The nine customers include one municipality which has a short-term wholesale contract terminating _in May 2016. These wholesale customers represented 4.5% of the District's 2015 operating revenues. The District expects that no requirements of said nine wholesale customers will be served by the District in 2022, and such wholesale customers will purchase all of their electric requirements from other suppliers. The District expects '*to sell the energy not sold to such wholesale customers into the SPP Integrated Market and continues to explore additional firm requirement and/or fixed price agreements. Four wholesale customers have not given notice to reduce and continue under the 2002 wholesale contracts. These customers represented 1.2% of the District's 2015 operating revenues.
Five wholesale customers under the 2002 Contracts have filed a lawsuit in state court challenging the 2016 wholesale rates. The 2016 wholesale rates result in a 0.6% increase for wholesale customers who sign the new 2016 Contracts and a 3.8% increase for those wholesale customers who remain under the 2002 Contracts. The rate increase was higher for the 2002 Contracts as these customers will pay their share of previously incurred OPEB costs through 2021. Customers under the 2016 Contracts are paying their share of OPEB costs over a longer period. The five wholesale customers filing the lawsuit have notified the District that they will not remain wholesale customers of the District after 2021. Said wholesale customers allege the 2016 rates are unreasonable, discriminatory and unfair. Said wholesale customers seek injunctive relief and damages. In December 2015, the District filed a motion to dismiss, alleging that Nebraska law requires wholesale rate disputes to be submitted to binding arbitration. A hearing on the motion to dismiss occurred in February 2016. The parties submitted briefs and are awaiting a ruling on the motion. If these wholesale customers would be successful on the merits of their claim, the District's Board may need to reconsider the 2016 wholesale rate change.
The Northeast Nebraska Public Power District filed a lawsuit in the District Court of Wayne County, Nebraska regarding the demand and energy reduction provisions under the 2002 Contract. The court issued an order dated February 26, 2016, in favor of the Northeast Nebraska Public Power District which allows them to reduce their demand and energy purchases from the District by 30% in 2018, 60% in 2019 and 90% in 2020. The court decision will apply to certain other customers who have given notice for demand and energy reductions under the 2002 Contract. On March 23, 2016, the District filed a notice of appeal.
D. SPP Membership and Transmission Agreements -
The District is a member of SPP, a regional transmission organization based in Little Rock, Arkansas.
Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration, including generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning. The District was able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost, through February 2014. On March 1, 2014, SPP commenced a Day-Ahead, Ancillary Services, and Real-Time Balancing Market Integrated Market. The Integrated Market also provides a financial market to hedge unplanned transmission congestion, or financial virtual products to hedge uncertainties, such as unplanned outages.
The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system. Cost of the project was
$8.4 million and repayment by Keystone, over a 10-year period, began in June 2010 with a remaining balance due the District of $4.4 million and $5.2 million as of December 31, 2015 and 2014, respectively.
The District entered into a second Transmission Facilities Construction Agreement effective July 17, 2009, with TransCanada Keystone XL Pipeline, LP ("Keystone XL"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection *and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. Construction of these facilities for Keystone XL has been cancelled. TransCanada Corporation and TransCanada Pipeline USA Ltd.
have jointly and severally guaranteed the payment obligations of Keystone under its agreements with the District.
As of December 31, 2015 and 2014, actual project costs totaled $13.2 million and $12.8 million, respectively, and the District has received payment of $10.3 million.
E.
Cooper Nuclear Station -
On November 29, 2010, the Nuclear Regulatory Commission ("NRC") formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until Janua,.Y 18, 2034.
CNS entered the 20-year period of extended operation on January 18, 2014.
In October 2003, the District entered into an agreement (the "Entergy Agreement") for support services at CNS with Entergy Nuclear Nebraska, LLC ("Entergy"), a wholly-owned indirect subsidiary of Entergy Corporation. In 2010, the Entergy Agreement was amended and extended by the parties until January 18, 2029, subject to either party's right to terminate without cause by providing notice and paying a $20 million termination charge. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services, and to pay Entergy annual management fees. These annual management fees were $18.4 million for 2015 and 2014. In 2016, the annual management fee is $18.5 million. This amount will increase by an additional $1.0 million in 2019, and by an additional $3.0 million in 2024. Entergy is eligible to earn additional incentive fees in an amount not to exceed
$4.0 million annually if CNS achieves identified safety and regulatory performance targets. Entergy may earn additional incentive fees estimated to be $2.5 million for 2015 and earned $3.8 million in 2014.
Since the earthquake and tsunami of March 11, 2011, that impacted the Fukushima Dai-ichi Plants in Japan, the District, as well as the rest of the nuclear industry, has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the GE boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes this same containment system; however, significant enhancements to the design have been made over the life of the plant.
- ./
An NRC Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12, 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report, on October 18, 2011, the NRC approved seven of the Task Force recommendations for implementation.
On March 12, 2012, the NRC issued three orders to the U.S. nuclear industry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nuclear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened containment wetwell vents. The third order requires nuclear plant operators to add reliable spent fuel pool water level instrumentation. The NRC has also issued a request for information pertaining to re-evaluation of seismic and flooding hazards, and a communications and staffing assessment for emergency preparedness.
Plant modifications resulting from the orders for modifications to the wetwell vent and fuel pool instrumentation are currently planned for the fall 2016 refueling and maintenance outage which is consistent with the requirements of the NRC's orders that require compliance no later than two refueling cycles following submittal of the Licensee's overall integrated plan or December 31, 2016, whichever comes first. Additional NRC orders and regulations resultant from the Fukushima Dai-ichi event may be forthcoming. The specific impacts of any additional orders and regulations on CNS have not yet been evaluated.
On June 6, 2013, the NRC issued an order to require the addition of a drywell vent to supplement the capabilities of this existing wetwell vent. This work is required to be completed in two phases, with phase one to be completed not later than the startup from the second refueling outage that begins after June 30, 2014 or June 30, 2018, whichever comes first and phase two to be completed no later than the startup from the first refueling outage that begins after June 30, 2017 or June 30, 2019, whichever comes first. Phase one of this order will be completed by the conclusion of the fall 2016 refueling and maintenance outage at CNS. Phase two will be completed by the conclusion of the fall 2018 refueling and maintenance outage. Also, after extensive analysis by the industry and the NRC, it was determined that U.S. reactors would not be required to add a filter on the hardened drywall vent.
After completion of the initial site-specific seismic reevaluation analysis for CNS, the District believed that no seismic-related modifications to CNS were required. Since that time, the District has performed an additional seismic analysis and has worked to answer additional questions from the NRC on this topic. The NRC has determined that CNS will have to perform the High Frequency Evaluation and a Spent Fuel Pool Evaluation, but will not have to complete a Seismic Probabilistic Risk Assessment. Unknown to the District at this time is the extent of modifications that will be required as a result of these additional seismic reevaluations.
The District continues to work with the U.S. Army Corps of Engineers (the "Corps") and the NRC to validate the data necessary to perform the flood hazard reevaluation. The District submitted its updated flooding analysis to the NRC in February 2015. Unknown to the District at this time is the extent of modifications that will be required as a result of the flood hazard reevaluations.
The District's cost estimate for plant modifications associated with the NRC's Fukushima Dai-ichi-related orders is currently estimated to cost $46.7 million, which is expected to be funded primarily from the revenues of the District and from the proceeds of General Revenue Bonds.
After the events at Fukushima Dai-ichi, several individuals and antinuclear groups petitioned the NRC's Office of Reactor Regulation pursuant to 10 CFR 2.206 to take various actions in relation to General Electric boiling water reactors with Mark 1 and Mark 2 containment systems. The petitions range from requests for information to suspension of the operating licenses for all Mark 1 and Mark 2 reactors. Petitions were also filed regarding concerns relating to the consequences of nuclear plants being located near earthquake fault lines or flood zones.
As of November 2015, all the petitions potentially affecting CNS have been closed, either through denial or NRC Director's Decisions. There have been no additional impacts to CNS as a result of these petitions.
CNS substantially completed the construction of a dry cask used fuel storage project in December 2009 to support plant operations until 2034, which is the end of the Operating License. The first loading campaign was
completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool into eight dry used fuel storage casks for on-site storage. A second loading campaign, encompassing the loading of 610 used fuel assemblies into 10 dry used fuel storage casks, began in April 2014 and was completed in June 2014.
As part of various disputed matters between GE and the District, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility. After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.
As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 2001. The initial settlement agreement addressed future claims through 2013. On January 13, 2014, the DOE extended the settlement agreement through 2016.
In accordance with a settlement agreement between the District and the DOE that was executed on May 18, 2011, the District has received $115.0 million from the DOE for damages from 2009 through 2015. The District also reserves the right to pursue future damages through the contract claims process. A corresponding regulatory liability for these DOE receipts has been established in Other deferred liabilities line of the Deferred Inflows of Resources section of the accompanying Balance Sheets. The District plans to use the funds to pay for costs related to CNS. The balance in the regulatory liability was $79.5 million and $71.3 million at December 31, 2015 and 2014, respectively.
Under the terms of the DOE contracts, the District was also subject to a one mill per kilowatt-hour ("kWh") fee on all energy generated and sold by CNS which was paid on a quarterly basis to DOE. The District includes a component in its Retail and Wholesale rates for the purpose of funding the costs associated with nuclear fuel disposal. While the District expects that the revenues developed therefrom will be sufficient to cover the District's responsibility for costs currently outlined in the Nuclear Waste Policy Act, the District can give no assurance that such revenues will be sufficient to cover all costs associated with the disposal of used nuclear fuel. On May 9, 2014, the DOE provided notice that they would adjust the spent fuel disposal fee to zero mills per kWh effeciive May 16, 2014. Correspondingly, no additional payments have been made to the DOE for fuel disposal since that date. The Board authorized the continued collection of this fee at the same rate. This approach ensures costs are recognized in the appropriate period with current customers receiving the benefits from CNS paying the appropriate costs. The expense for spent nuclear fuel disposal is recorded based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal.
Under the provisions of the Federal Price-Anderson Act, the District and all other licensed nuclear power plant operators could each be assessed for claims in amounts up to $127.3 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation, with a maximum assessment of $19.0 million per year per incident per unit owned.
The NRC evaluates nuclear plant performance as part of its reactor oversight process ("ROP"). The NRC has five performance categories included in the ROP Action Matrix Summary that is part of this process. As of December 31, 2015, CNS was in the Licensee Response Column, which is the first or best of the five NRC defined performance categories and has been in this column since the first quarter of 2012.
Refueling and maintenance outages are required to be performed at CNS approximately every two years.
Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs, commencing in 2015. The regulatory liability for the pre-collection of outage costs was $24.7 million at December 31, 2015 and will be eliminated through revenue recognition during the 2016 outage year.
F.
Environmental -
On November 3, 2015, EPA published the final Steam Electric Power Plant Effluent Guidelines (40 CFR 423). The rule would strengthen the existing controls on discharges from steam electric power plants. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants. District facilities subject to the rule are CNS, GGS, Sheldon, and Canaday Station. The rule has no impact on CNS or GGS. Sheldon will be required to be a zero discharge facility for bottom ash transport water. Compliance is required between November 1, 2018 and December 31, 2023. The District is currently analyzing the options for compliance.
On February 16, 2012, the EPA issued a final rule intended to reduce emissions of toxic air pollutants from power plants. Specifically, the Mercury and Air Toxics Standards ("MATS") Rule will require reductions in emissions from new and existing coal-and oil-fired steam utility electric generating units of toxic air pollutants. Sheldon began complying with the MATS rule on April 16, 2015. GGS was granted an additional year to achieve compliance.
GGS will be in compliance with the MATS rule on or before April 16, 2016.
As part of EPA's nationwide investigation and enforcement program for coal-fired power plants' compliance with the Clean Air Act including new source review requirements, on December 4, 2002, the Region 7 office of the EPA sent a letter to the District and three other electric utilities pursuant to Section 114(a) of the Federal Clean Air Act requesting documents and information pertaining to GGS and Sheldon. On April 10, 2003, Region 7 of the EPA sent a supplemental request for documents and information to the District and the other three electric utilities. These EPA requests for information are part of an EPA investigation to determine the Clean Air Act compliance status of GGS and Sheldon, including the potential application of new source review requirements.
The District provided the documents and information requested to the EPA within the time allowed. As a supplement to the 2002 and 2003 requests, EPA Region 7 sent another letter to the District on November 8, 2007, requesting additional documents and information pertaining to GGS and Sheldon. The District provided a response to the new request within the time allowed and provided supplemental information to EPA in February and April 2011 in response to an EPA email inquiry. By letter dated December 8, 2008, EPA Region 7 sent a Notice of Violation ("NOV") to the District which alleges that the District violated the Clean Air Act by undertaking five projects at GGS from 1991 through 2001 without obtaining the necessary permits. In February and August 2009, District representatives met with federal government representatives to discuss the NOV and no additional meetings have been scheduled. In general, enforcement action by EPA against the District for alleged noncompliance with Clean Air Act requirements, if upheld after court review, can result in the requirement to install expensive air pollution control equipment that is the BART and the imposition of monetary penalties ranging from $25,000 to $32,500 per day for each violation. The District cannot determine at this time whether it will have any future financial obligation with respect to the NOV.
On October 23, 2015, ihe EPA published the final Clean Power Plan ("CPP") rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determining how to achieve the reduction targets through the development of a State Plan. Each state was given a reduction target to be achieved by 2030 with interim reductions required between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 emissions. On February 9, 2016, the U.S. Supreme Court granted a stay, halting implementation of the CPP pending the resolution of legal challenges to the program. That challenge is currently before the U.S. Court of Appeals for the D.C. Circuit. An initial State Plan providing a general outline of potential compliance options was due September 6, 2016. These deadlines are no longer in effect and state actions have been placed on hold pending the outcome of litigation. It is not possible to determine the impact to the District until the resolution of the legal challenges.
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.
G. Sale of Spencer Hydro Facility -
In September 2015, a memorandum of understanding ("MOU") was signed for the sale of the District's Spencer Hydro ("Spencer") facility, including dam, structures, land, water appropriations and perpetual easements for the reservoir, to the Niobrara River Basin Alliance (Five Natural Resource Districts) and the Nebraska Game and
Parks Commission. The MOU provides that the parties will work for passage of legislation by the State of Nebraska for a permanent transfer of existing hydro water appropriation to a new multi-purpose use, and it identifies potential sources of funding for the sale. The District will continue to operate Spencer until transfer of ownership, including water appropriations, is completed. The transfer is expected to take approximately two years to complete.
H. Other-In October 2015, the Internal Revenue Service affirmed, pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, that the 35% interest subsidy provided by the United States Treasury on the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds), will be reduced by 6.8% for fiscal year ending September 30, 2016. Previous reductions were 7.3% for fiscal year ending September 30, 2015, and 7.2% for fiscal year ended September 30, 2014. The reduction rate is subject to change by Congressional action. This loss of subsidy totals approximately $0.2 million annually.
- 13. LITIGATION:
A number of 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, 2015 and 2014. Information on litigation with wholesale customers is included in Note 12.
- 14. SUBSEQUENT EVENTS:
In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series Bin the amount of
$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of TECP. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.
Also in February 2016, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
General Revenue Bonds, 2007 Series B, having maturity dates ranging from January t, 2026 through January 1, 2037 General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2026 through January 1, 2041, and General Revenue Bonds, 2012 Series C, maturing on January 1, 2025 and January 1, 2026 In January 2016, the District issued TECP in the amount of $43.6 million to refund a portion of the 2005 Series C and 2006 Series A General Revenue Bonds. In February 2016, $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and B.
Effective January 1, 2016, the District entered into new 20-year Wholesale Power Contracts with certain wholesale customers as described in Note 12.
SUPPLEMENTAL SCHEDULES (UNAUDIYED)
Calculation of Debt Seniice Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (in OOO's)
Operating revenues......................................................................................
Operating expenses.....................................................................................
Operating income....................................................................................
Investment and other income.........................................................................
Debt and other expenses..............................................................................
Increase in net position............................................................................
Add:
Collections for future debt retirement.........................................................
Debt and related expenses.......................................................................
Depreciation and amortization...................................................................
Payments to retail communitiesC1l.............................................................
Amortization of current portion of financed nuclear fuel................................
Amounts collected from third party financing arrangementsc2l......................
Deduct:
Investment income retained in construction funds.......................................
Unrealized (loss) gain on investment securities..........................................
Re\\Ohling credit agreement interest...........................................................
Net position available for debt seniice for the General Revenue Bond Resolution.
Amounts deposited in the General System Debt Sennce Account:
Principal.................................................................................................
Interest...................................................................................................
Ratio of net position available for debt ser\\1ce to debt senhce deposits..............
2015 1,097,216 (960,259) 136,957 22,355 (68,252) 91,060 68,252 130,247 26,552 24,675 850 250,576 302 (1,245) 1,010 67 341,569 110,265 75,372 185,637 1.84 2014
$ 1,122,454 (1,010,693) 111,761 26,039 (75,438) 62,362 1,188 75,438 126,440 26,874 20,700 1,276 251,916 190 203 1,731 '
2,124 312, 154 124,780 82,978
$, 207,758 1.50 (1) Under the provisions of the General Revenue Bond Resolution, the payrrents required to be made by the District with respect to the A"ofessional Retail Operations Agreerrents are to be made on the sarre basis as subordinated debl (2) Under the provisions of the General Revenue Bond Resolution, the payrrents received by the District from third party financing arrangerrents provide for debt service coverage, but are not recognized as revenue under Generally Accepted Accounting A"inciples.
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Schedule of Funding Progress for OPEB as of January 1, (in OOO's)
Actuarial Actuarial Unfunded Actuarial Co..ered UAAL to Value of Accrued Accrued Liability Funded Ratio Payroll Co..ered Assets Liability (AAL)
(UAAL)
Payroll (a)
(b)
(b-a)
(alb)
(c)
((b-a)/c) 2015 <1l
$64,487
$309,908
$245,421 20.8%
$186,952 131%
2014
$48,274
$506,200
$457,926 9.5%
$186,637 245%
2013
$30,781
$520,705
$489,924 5.9%
$187,378 261%
(1) The decrease in the AAL in the 2015 valuation was due to a change for Medicare-eligible retirees for prescription drugs from the District's self-insured employee prescription plan to a group insured Medicare Part D supplement effective January 1, 2016 and a change in funding. The District changed its funding plan to contribute, at a minimum, the actuarially-detennined ARC to achieve full funding status on or before December 31, 2033, and to pay benefitslexpenses from the OPES Trusts.
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H Nebraska Public Power District NLS2016026 May 3, 2016 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Always there when you need us
Subject:
Nebraska Public Power District 2015 Financial Report Cooper Nuclear Station, Docket No. 50-298, DPR-46
Dear Sir or Madam:
50.71(b)
The purpose of this letter is to transmit the Nebraska Public Power District (NPPD) Financial Report for the calendar year 2015 in accordance with the requirements of 10 CFR 50.71(b).
Copies of this report are being distributed in accordance with 10 CFR 50.4.
This letter does not contain any commitments.
Should you have any questions or require additional information, please contact me at ( 402) 825-2788.
Licensing Manager
/jo Enclosure - NPPD 2015 Financial Report cc:
Regional Administratorw/enclosure USNRC - Region IV Cooper Project Manager w/enclosure USNRC - NRR Plant Licensing Branch IV-2 Senior Resident Inspector w/enclosure USNRC-CNS NPG Distribution w/o enclosure CNS Records w/enclosure COOPER NUCLEAR STATION P.O. Box 98 /Brownville, NE 68321-0098 Telephone: (402) 825-3811 I Fax: (402) 825-5211 www.nppd.com
NLS2016026 Enclosure Page 1of48 NPPD 2015 Financial Report I
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2015 STATISTICAL REVIEW (Unaudited)
Average Cents Per kWh Sold Average Awrage Less Government Cents Per Number of MWh OPERATING REVENUES TaxesfTransfers (l) kWh Sold Customers Amount O/o Retail:
Residential......................
10.67
¢ 12.69
¢ 71,433 810,518 3.8 Commercial.....................
8.40
¢ 9.78
¢ 19,651 1, 152,656 5.5 Industrial.........................
5.64
¢ 5.99
¢ 56 1, 170,406 5.6 Total Retail Sales..........
7.96
¢ 9.12
¢ 91 140 311331580 14.9 Wholesale:
Municipalitiesc2l........................................
6.24
¢ 50 1,871,874 8.9 Public Power Districts and CooperativesC2l..
5.89
¢ 25 7,573,936 36.1 Total Firm Wholesale Sales....................
5.96
¢ 75 9A45,810 45.0 Total Firm Retail and Wholesale Sales..
6.74
¢ 91,215 12,579,390 59.9 Participation Sales........................................
3.57
¢ 5
2, 162,648 10.3 Other Salesc31...............................................
2.15
¢ 2
6,2481845 29.8 Total Electric Energy Sales..................
5.05
¢ 91,222 2019901883 100.0 Other Operating Rewnuesc*i..........................................................................................................
Unearned Revenues csi...................................................................................................................
Total Operating Rewnues..............................................................................................................
MWh COST OF POWER PURCHASED AND GENERATED Amount Productionc61..*.*..*.*****.*.......*.......*.......***......**...*.*. *..**....................... *.**....
17,089,062 79.0 Power Purchased......................................................................................
415481469 21.0 Total Production and Power Purchased...................................................
21.6371531 100.0 CONTRACTUAL AND TAX PAYMENTS Qn OOO's) <1J Payments to Retail Communities.................................................................................................
Payments in Lieu of Taxes..........................................................................................................
Total Contractual and Tax Payments........................................................................................
OTHER Miles of Transmission and Subtransmission Lines in Ser.1ce..........................................................
Number of Full-Time Employees...................................................................................................
(1)
Customer collections for taxes/transfers to other governments are excluded from base rates.
(2)
Sales are total requirements.
(3)
Includes sales in the Southwest Power Pool ("SPP") and nonfirm sales to other utilities.
(4)
Includes revenues for transmission and other miscellaneous revenues.
Rewnues (in OOO's)
Amount O/o
$ 102,870 9.4 112,735 10.3 70, 158 6.4 2851763 26.1 116,834 10.7 445,748 40.6 5621582 51.3 848,345 77.4 77, 192 7.0 1341612 12.3 1,060,149 96.7 60,730 5.5
{23,663)
{2.2)
~110971216 100.0 Costs (in OOO's)
Amount
$ 441,344 72.6 166.587 27.4 i
!ijQ71~~1 1QQ.Q Amount 26,552 10,046 i
361598 Amount 5,225 2,003 (5)
Includes unearned revenues from prior periods of $12.0 million, 2015 surplus revenues deferred to future periods of $11.0 million, and collections of $24. 7 million for the 2016 Cooper Nuclear Station ("CNS") refueling and maintenance outage.
(6)
Includes fuel, operation and maintenance costs. Debt service and capital-related costs are excluded.
SOURCES OF THE DISTRICT'S ENERGY SUPPLY (% OF MWH)
This chart shows the sources of energy for sales, excluding participation sales to other utilities. Purchases were included in the appropriate source, except for those purchases for which the source was not known.
Nuclear 33.8%
48.4%
Wind Hydro 5.9%
Purchases 4.7%
1.0%
NEBRASKA P UBLIC P OWER D ISTRICT 1
MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)
The followi OVERVIEW OF BUSINESS n o the S ale of ebf'3S a. Control of g of 11 mem s p0pula y ct e State s. 93 counlles and more han 400
'"'1'"°':~ny llmtled to um I
- s I custo THESYSTE Tom t th nyt m ak I o 2015 o :>,6 O me
- v. t ('MW.), h 01 tri t h d av table 3 660 4 of capacity resoutC s that included 3.049. 1 MW of generatwn capacity from 12 owned and operatEld ge,,erabrig I n 2' p "l ov r v, lch th O ct s ope ti con rot.
7 7 MW m c paci y purch om Westem Area Power Adm1n tratlon. af\\d 63.6 MW of a capacity purchas rom Oma a Public Pow
- Dlstr t
("OPPO ~
ebraska City St lion Unit 2 (*NC2 ) coal* ired plant. Of the total cap city resources, 223. 7
- W are bei g sold a partici a on sales or other capae1ty sa es agreements, feavmg 3,436 7 W to serve 1rm retail and whol sale custom rs and to meet capacity r s rvo requirements. The highes summer an ime p a load of 3,030 3 MW was establish d 1n July 2012 and the highest intet anytlm
~ak load of 2,252.0 MW was e ta II h d m J nuary 2014 for rm requ1r m nt c tom r T e ollow ng tab e shows the Distnct's capacity resources from generation and respective summer 2015 ccr di d c pabili y T
Steam - Conw t1onal St m -
ucl r
Combined Cycle...................................................
Combustion urbine 1 '............................................
t-tydro........
Dt Wind t oJ..................................................................
(1)
(2 )
(lt (5) I Typ Ge 1 nd No 2......
on SPP cnt ri Summer 2015 umber of Accred1 ed Plants<'
- Caeabtht~ lMW}
1 p
3 695.0 55 6 1
764 0 251 1
2200 7.2 3
125 3 4 1 6
110 7 36 12 91 4 3.0 8
2.7 3 049.1 St und oon Distnc and their spectiv fuel types, summer Fu I Typ,e Coal Nucl ar Combined Cycl Coal Oil 0t tu~ I G atural G Water Wrnd Sum r 2015 1 3650 764.0 220.0 215 0 125 1 5.0 25.2 9 1 2 838.6
) 11 1979. 982 1974 2005 6. 19 8 1973 1958 1887. 1927, 1939 200 Nr..uRAS~A PuntJL Pm\\*ER Dis-nm *1 3
THE CUSTOMERS Retail and Wholesale Customers In 2015, the District served an average of 91, 140 retail customers. Currently the District's retail service territory includes 80 municipalities, of which 79 are municipal-owned distribution systems operated by the District for the municipality pursuant to a Professional Retail Operations ("PRO") Agreement. Details of the District's PRO Agreements are included in Note 12 in the Notes to Financial Statements.
The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District, subject to certain exceptions described in Note 12 in the Notes to Financial Statements. Effective January 1, 2016, the District entered into new 20-year Wholesale Power Contracts ("2016 Contracts"). Wholesale customers being served under the 2016 Contracts include 23 public power districts, which includes one cooperative, and 39 municipalities. Two public power districts and 11 municipalities are served under 2002 Wholesale Power Contracts ("2002 Contracts"). Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements.
The following charts show the District's average retail and wholesale cents per kilowatt-hour ("kWh") for the years ended December 31, 2011 through 2015. The District also reported average cents per kWh sold less customer collections for taxes and transfers to other governments, which are not included in the District's base rates for retail customers.
9.80
.s:: 9.00
~
~ 8.20 (I)
Q.
.!!l 7.40 c
(I) 0 6.60 5.80 AVERAGE CENTS PER kWh SOLD-RETAIL (Retail -All Classes) 8.75¢ 9.04¢ 9.06¢ 2011 2012 2013 2014 9.12¢ 2015 Average Cents per kWh Sold Average Cents per kWh Sold Less Government Taxes/Transfers AVERAGE CENTS PER kWh SOLD - WHOLESALE (Firm Wholesale Customers Only) 6.40 6.09¢ 5.96¢
.s:: 6.00
~
5.57¢
~ 5.60 5.39¢ (I)
Q.
.!!l 5.20 c
(I) 0 4.80 4.40 2011 2012 2013 2014 2015 4
NEBRASKA Puuuc Pow1m. D1s*1 RICI
Other Utilities (Nonfirm and Other Sales)
In addition, there are five participation sales agreements in place with other utilities for the sale of power and energy at wholesale from specific generating plants. Such sales are to Lincoln Electric System ("LES"), Municipal Energy Agency of Nebraska ("MEAN"), OPPD, Grand Island Utilities ("Grand Island"), and the City of Jacksonville, Florida ("JEA). The District also sells energy on a nonfirm basis in SPP and through transactions executed with other utilities by The Energy Authority ("TEA").
Transmission Customers The District owns and operates 5,225 miles of transmission and subtransmission lines, encompassing nearly the entire State of Nebraska. The District became a transmission owning member of SPP, a regional transmission organization, in 2009. The District files a rate with SPP annually that provides for the recovery of all transmission revenue requirements associated with transmission facilities equal to or greater than 115 kV. SPP collects and reimburses the District for the use of the District's transmission facilities by entities other than the District's firm requirements customers and all transmission customers still served directly by the District through grandfathered Transmission Agreements.
Customers. Energy Sales. and Revenues The following table shows customers, energy sales, and peak loads of the System, including participation sales, in each of the three years, 2013 through 2015.
Megawatt-Hour Sales Anytime Peak Load {MW}
Calendar Average Number of Wholesale Nativa Load Percentage Total Percentage Busbar Native Year Retail Customers Customers(1>
Sales(2>
Growth Sales <3>
Growth Load 2013 89,604 97 13, 140,595 (0.2) 20,830,094 8.i 2,872.6 2014 90,293 86 12,932,518 (1.6) 20,658,755 (0.8) 2,807.0 2015 91,140 82 12,579,390 (2.7) 20,990,883 1.6 2,695.0 (1)
At the end of 2015, includes sales to LES, MEAN, JEA, OPPD, Grand Island, and a yearly average of two nonfirm customers. Bilateral sales to utilities have decreased since SPP's transition to an integrated market on March 1, 2014.
(2)
Native load sales include wholesale sales to total firm requirements customers and include the responsibility of replacement power being procured by the District if the District's generating assets are not operating. Predominantly, native load customers are served under long-term total requirements contracts.
(3)
Total sales from the System include sales to LES from GGS and Sheldon; to MEAN from GGS and CNS; to Heartland from CNS, which sale commenced January 1, 2004, and terminated December31, 2013; to KCPL from CNS, which sale commenced January 1, 2005, and terminated on January 18, 2014; to MEAN, JEA, OPPD, and Grand Island from Ainsworth, which sales commenced October 1, 2005, and terminates on September 30, 2025; to OPPD, MEAN, LES and Grand Island from Elkhorn Ridge Wind Facility, which sales commenced March 1, 2009, and terminates on February 28, 2029; to MEAN from GGS and CNS, which sale commenced January 1, 2011, and terminates on December 31, 2023; to MEAN, Lincoln and Grand Island from Laredo Ridge Wind Facility, which sales commenced February 1, 2011, and terminates on January 31, 2031; to OPPD, LES and Grand Island from Broken Bow I Wind Facility, which sales commenced December 1, 2012, and terminates on November 30, 2032; to OPPD, Lincoln and MEAN from Crofton Bluffs Wind Facility, which sales commenced November 1, 2012, and terminates on October 31, 2032; and to OPPD from Broken Bow II Wind Facility which sale commenced October 1, 2014, and terminates on September 30, 2039.
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FINANCIAL INFORMATION The following tables summarize the District's financial position and operating results.
CONDENSED BALANCE SHEETS (in OOO's)
As of December 31, 2015 2014 2013 Assets:
Current Assets..............................................................
764,278 719,987 665,854 Special Purpose Funds..................................................
738,967 808,552 688,220 Utility Plant, Net............................................................
2,508,971 2,495,206 2,500,069 Other Long-Term Assets...............................................
353,639 800,406 795,792 Deferred Outflows of Resources......................................
40,775 26,794 16,504 Total Assets and Deferred Outflows............................
i 4,406,630
~ 4,850,945.j 4,666,439 Liabilities:
Current Liabilities..........................................................
218,858 395,676 352,229 Long-Term Debt............................................................
1,838,672 1,802,850 1,845,244 Other Long-Term Liabilities............................................
727,070 1,159,647 1, 109,567 Deferred Inflows of Resources Unearned Revenues..................................................
176,118 177, 143 101,861 Other Deferred Inflows...............................................
113,728 74,505 78,776 Net Position:
Net Investment in Capital Assets....................................
866,699 770,514 747,650 Restricted.....................................................................
40,492 43,889 42,883 Unrestricted.................... ;.............................................
424,993 426,721 388,229
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Total Liabilities, Deferred Inflows, and Net Position.......
$ 4,406,,!330
$ 4.850,945
$ 4,666,439
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CONDENSED RESULTS OF OPERATIONS (In OOO's)
For the years ended December 31, 2015 2014 2013 J.ilt Operating Revenues......................................................
$ 1,097,216
$ 1,122,454
$ 1, 106,291 Operating Expenses......................................................
{960,25m_
{1,010,693}
{941,887}
Operating Income.....................................................
136,957 111,761 164,404 Investment and Other Income.........................................
22,355 26,039 15,221 Debt and Other Expenses..............................................
{68,252j
{75,438}
{82,242}
Increase in Net Position............................................
91,060 62,362 97,383 SOURCES OF OPIERATING REVENUES (in OOO's)
For the years ended December 31, 2015 2014 2013 Firm Retail and Wholesale Sales....................................
848,345 887,619 878,324 Participation Sales.......................................................
77,192 81,063 112,061 Other Sales..................................................................
134,612 172,521 116,890 Other Operating Revenues.............................................
60,730 58,352 59,162 Unearned Revenues.......................................................
{23,663}
{77,101}
{60, 146}
Total Operating Revenues..........................................
~i 1,097,216
~ 1, 122,454 m 1, 106,291
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CONDENSED STATEMENTS OF CASH FLOWS (in OOO's)
For the :tears ended December 31, 2015 2014 2013 Net Cash Pro\\lided by Operating Activities.......................
372,503 362,365 407, 132 Net Cash Pro\\/ided by (Used in) ln~sting Activities...........
10,961 (199,101)
(19,931)
Net Cash Used in Capital and Financing Activities............
(388,483}
(241,874}
(381,591}
Net (Decrease) Increase in Cash and Cash Equivalents....
(5,019)
(78,610) 5,610 Cash and Cash Equivalents, Beginning of Year................
90,079 168,689 163,079 Cash and Cash Equivalents, End of Year....................
85,060
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90,079 168,689 Revenues from Firm Retail and Wholesale Sales The District allocates costs bet'Neen retail and wholesale service and establishes its rates to produce revenues sufficient to meet its estimated respective retail and wholesale revenue requirements. Wholesale revenue requirements include unbundled costs accounted for separately between generation and transmission.
Transmission costs not recovered from the District's wholesale power contracts are expected to be recovered through rates charged by SPP. The rates for retail service include an amount to recover the costs of wholesale power service in addition to distribution system costs and government taxes and transfers. The District's wholesale power contracts provide for the establishment of cost-based rates. Such rates can be adjusted at such times as deemed necessary by the District. The wholesale power contracts also provide for the creation of a rate stabilization account. Any surplus or deficiency between revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be retained in the rate stabilization account. Any amounts in excess of the limits may be included as an adjustment to revenue requirements in the next rate review. The wholesale power contracts also include a provision for establishing a new/replacement generation fund. This provision would permit the District to collect an additional 0.5 mills per kWh above the normal revenue requirements to be used for future capital expenditures associated with generation.
The District implemented a 0.6% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who signed the new 2016 20-year wholesale power contract, and a 3.8% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who remain under the 2002 20-year wholesale power contract. The rate increase was higher for the 2002 Contracts as these customers will pay their share of previously incurred other post-employment benefits ("OPEB") costs through 2021. Customers under the 2016 Contracts are paying their share of OPEB costs over a longer period. No increase in retail rates was implemented in 2016. Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements.
The District implemented a 0.5% increase in the District's wholesale rates commencing on January 1, 2015. No increase in retail rates was implemented in 2015. The District had no wholesale or retail rate increase in 2014.
The District implemented a 3.75% increase in retail and wholesale rates on January 1, 2013.
Revenues from firm sales decreased $39.3 million, or 4.4%, from $887.6 million in 2014 to $848.3 million in 2015.
The decrease was due primarily to lower unbilled retail energy with a revenue impact of $14.4 million and a 1.4%
decrease in sales volume which was the result of milder temperatures. Revenues from firm sales increased
$9.3 million, or 1.1%, from $878.3 million in 2013 to $887.6 million in 2014. This increase was due primarily to higher unbilled retail revenues of $14.1 million partially offset by a 3.4% weather-related decrease in energy sales to firm wholesale customers.
Revenues from Participation Sales The District has participation sales agreements with other utilities that share operating expenses on a pro rata basis. Revenues from participation sales decreased from $81.1 million in 2014 to $77.2 million in 2015, a decrease of $3.9 million. This decline was due primarily to participation sales to LES which decreased by $4.4 million due to a 23.0% reduction in the dispatch of generation from Sheldon due to lower prices in the SPP Integrated Market. The decrease was partially offset by increased wind participation sales. Revenue from
participation sales decreased from $112.1 million in 2013 to $81.1 million in 2014, a decrease of $31.0 million.
The decrease was due primarily to contract expirations with Heartland Consumers Power District and KCP&L Greater Missouri Operations Company on December 31, 2013 and January 18, 2014, respectively, which was partially offset by increased wind participation sales.
Revenues from Other Sales Other sales consist of sales in SPP's Integrated Market and nonfirm sales to other utilities. TEA, of which the District is a member, has energy marketing responsibilities for the District's other and nonfirm off-system sales and the related management of credit risks. Other sales decreased from $172.5 million in 2014 to $134.6 million in 2015, a decrease of $37.9 million. This decrease was a result of lower prices in the SPP Integrated Market which was driven by lower natural gas prices and additional wind generation. Other sales increased from $116.9 million in 2013 to $172.5 million in 2014, an increase of $55.6 million. This increase was due primarily to additional revenues realized from greater nonfirm sales at higher market prices, including sales in SPP's Integrated Market which began on March 1, 2014.
Other Operating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues.
These revenues were $60.7 million, $58.4 million, and $59.2 million in 2015, 2014, and 2013, respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District.
Unearned Revenues Under the provisions of the District's wholesale power contracts, any surplus or deficiency between net revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be adjusted in the rate stabilization account. Any amounts in excess of the rate stabilization limits may be included as an adjustment to revenue requirements in the next rate review. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities, the balance of such surpluses or deficiencies are accounted for as "regulatory liabilities or assets", respectively.
The District recognizes net revenues in excess of revenue requirements in any year as a deferral or reduction of revenues. Such surplus revenues are excluded from the net revenues available under the General Revenue Bond Resolution ("General Resolution") to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues, even though the revenue accrual will not be realized as "cash" until some future rate period.
Such revenue deficiency is included, in the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are excluded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates.
The District deferred or decreased revenues a net amount of $23.7 million in 2015. The District's revenues in 2015 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of
$11.0 million, which surplus amount was deferred {decrease in revenues). In addition, the wholesale rates that were in place for 2015 included a refund of $12.0 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year{s) the surplus occurred.
Accordingly, the 2015 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment {increase in revenues) for such amount The District also deferred or decreased revenues by
$24. 7 million for the pre-collection of CNS refueling and maintenance outage costs. This regulatory liability will be eliminated through revenue recognition during the 2016 outage year.
The District deferred or decreased revenues a net amount of $77.1 million in 2014. The District's revenues in 2014 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of
$91.4 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2014 included a refund of $14.3 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred.
Accordingly, the 2014 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount.
The District deferred or decreased revenues a net amount of $60.1 million in 2013. The District's revenues in 2013 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of
$60.8 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2013 included a refund of $0.7 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred.
Accordingly, the 2013 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount.
Unearned revenues from prior periods of $1.9 million were refunded directly to customers in 2014. The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements in future rate periods was $176.1 million, $177.1 million, and $101.9 million, as of December 31, 2015, 2014, and 2013, respectively.
Operating Expenses The following chart illustrates operating expenses for the years ended December 31, 2013 through 2015.
$1,200
$1,000 Ill c
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$1,011 2014 2015
- Power Purchased & Fuel
- Production Operation & Maintenance ("O&M")
Transmission & Distribution O&M
- Customer Service & Information Administrative & General
- Decommissioning Depreciation & Amortization Other Total operating expenses in 2015 were $960.3 million, a decrease of $50.4 million from 2014. Total operating expenses in 2014 were $1,010.7 million, an increase of $68.8 million from 2013. The changes were due primarily to the following:
Power purchased and fuel expenses were $365.1 million, $386.3 million, and $366.2 million in 2015, 2014, and 2013, respectively. These expenses decreased $21.2 million in 2015 as compared to 2014 due primarily to lower fuel costs as a result of decreased generation, lower market prices and fewer energy purchases in the SPP Integrated Market. These expenses increased $20.1 million in 2014 as compared to 2013 due primarily to activity in the SPP Integrated Market and the District's participation in new wind facilities.
Production operation and maintenance expenses were $242.8 million, $281. 7 million, and $24 7.8 million in 2015, 2014, and 2013, respectively. These costs decreased $38.9 million in 2015 as compared to 2014 due primarily to the costs associated with a planned refueling and maintenance outage at CNS completed November 2, 2014, which ended the station's first 24-month operating cycle. No such outage occurred in 2015. These costs NEBRASKA PUBLIC PmHR Dis !RIC r 9
increased $33.9 million in 2014 as compared to 2013 due primarily to additional costs associated with a planned refueling and maintenance outage. No such outage occurred in 2013.
Transmission and distribution operation and maintenance expenses were $87.3 million, $83.8 million, and
$76.4 million, in 2015, 2014, and 2013, respectively. These costs increased $3.5 million in 2015 as compared to 2014 and $7.4 million in 2014 as compared to 2013 both due primarily to increases in SPP fees. The District is charged by SPP for firm requirements customers for the qualifying transmission system upgrade projects of other SPP transmission owners.
Customer service and information expenses were $17.2 million, $17.5 million, and $16.6 million, in 2015, 2014, and 2013, respectively.
Administrative and general expenses were $66.3 million, $59.4 million, and $59.7 million, in 2015, 2014, and 2013, respectively. These costs increased $6.9 million in 2015 as compared to 2014 due primarily to increases in healthcare costs along with increased expenses for outside services.
Decommissioning expenses were $14.7 million, $18.5 million, and $10.7 million. in 2015, 2014, and 2013, respectively. Decommissioning expenses represent the net amount accrued each year for the future decommissioning of CNS. Such expenses are recorded in an amount equivalent to the income on investments in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year. Decommissioning expenses decreased $3.8 million in 2015 as compared to 2014 due to a decrease in income on investments. Decommissioning expenses increased $7.8 million in 2014 as compared to 2013 due to an increase in income on investments. No additional amounts for decommissioning were collected through rates in 2015, 2014, and 2013.
Depreciation and amortization expenses were $130.2 million. $126.4 million, and $127.3 million, in 2015, 2014, and 2013, respectively.
Increase in Net Position The increase in net position was $91.1 million, $62.4 million, and $97.4 million, in 2015, 2014, and 2013, respectively. The change in net position in 2015 as compared to 2014 increased $28.7 million and was due primarily to an increase in 2015 revenue requirements from increased collections for construction from revenue and for principal payments on commercial paper notes. partially offset by reduced collections for principal payments for revenue bonds. The change in net position in 2014 as compared to 2013 decreased $35.0 million and was due primarily to a decrease in 2014 revenue requirements for collections related to construction from revenue and commercial paper principal payments.
The following chart illustrates the District's operating revenues, other revenues, operating expenses, and other expenses for the years ended December 31, 2013 through 2015.
$1,200 ~-------------------
_ $1,150 Ill 5 $1,100
§ $1,050
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$950 0
$900 0
$850
$800 +-----
2013 2014 2015 Other Expenses
- Operating Expenses
- Other Revenues Operating Revenues 10 N1.11RASK.\\ Punuc PowLR Dis 1 RICT
DEBT SERVICE COVERAGE The District's debt service coverage ratio was 1.84, 1.50, and 1.73, in 2015, 2014, and 2013, respectively. The coverage was provided primarily by the amounts collected in operating revenues to fund the cost of utility plant additions, the amounts collected in operating revenues for principal and interest payments on the outstanding commercial paper notes, and the amounts collected for payments to those municipalities served by the District under long-term PRO Agreements. The increase in the 2015 debt service coverage ratio was primarily due to the fact that effective July 31, 2015, the obligation of the District to pay the principal, interest, bank fees, and expenses pursuant to the Taxable Revolving Credit Agreement is payable from the Pledged Property subject and subordinated to the pledge of the Pledged Property to the payment of the General Revenue Bonds.
FINANCING ACTIVITIES Good credit ratings allow the District to borrow funds at more favorable interest rates. Such ratings reflect only the view of such rating organizations, and an explanation of the significance of such rating may be obtained only from the respective rating agency. There is no assurance that such ratings will be maintained for any given period of time or that they will not be revised downward or be withdrawn entirely by the respective rating agency if, in its judgment, circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the market prices of bonds.
The District's credit ratings on its revenue bonds were as follows:
Moody's Investors Service............................................................................ A 1 Standard & Poor's Ratings Services............................................................. A+
Fitch Ratings................................................................................................. A+
(stable outlook)
(stable outlook)
(stable outlook)
In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series Bin the amount of
$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of Tax-Exempt Commercial Paper ("TECP"). The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.
In January 2016, the District issued TECP in the amount of $43.6 million to refund a portion of the 2005 Series C and 2006 Series A General Revenue Bonds. In February 2016, $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and B. The District plans to issue additional revenue bonds in 2016 to finance capital projects.
In February 2015, the District issued General Revenue Bonds, 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $42.0 million, which resulted in present value savings of $26.1 million.
Revenue bonds were issued in 2014 to refund existing bonds at lower rates and to finance capital projects.
Details of the District's debt balances and activity are included in Note 7 in the Notes to Financial Statements.
CAPITAL REQUIREMENTS The Board-authorized capital projects totaled approximately $501.0 million, $197.4 million, and $78.9 million, in 2015, 2014, and 2013, respectively. The District's capital requirements are funded with monies generated from operations, debt proceeds, and other available reserve funds.
NEURAsKA Punuc Powrn Dis 1 RICI
- 11 -
Capital projects for 2015 included:
$346.8 million for construction of a high-voltage transmission line and related substations from a GGS substation north to Cherry County, Nebraska and east to a new substation in Holt County, Nebraska
$33.9 million for modifications to the hot flue gas ductwork at GGS Unit 2
$33.1 million for construction of a high-voltage transmission line from a new Stegall, Nebraska substation to the existing Scottsbluff, Nebraska substation Capital projects for 2014 included:
$94.9 million for construction of a high-voltage transmission line and related substations from Hoskins Substation northeast of Norfolk, Nebraska to Neligh, Nebraska
$14. 7 million for replacement of a secondary super-heater outlet at GGS Unit 2
$7.0 million for replacement of a silo dust collector at GGS Units 1 and 2 Capital projects for 2013 included:
$27.1 million for replacement of a low pressure turbine at GGS Unit 1
$11.6 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2
$7. 7 million for fire protection upgrades at CNS There were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $87.2 million, $80.8 million, and $32.5 million for 2015, 2014, and 2013, respectively.
The Board-authorized budget for capital projects for 2016 is $147.2 million. The increase in the 2015 budget was due to large transmission projects authorized by SPP. The District will receive revenues from other transmission owners in SPP for their share of these projects over the projects' depreciable life.
Specific capital projects for 2016 include:
$25.0 million for construction of a high-voltage transmission line from a new Broken Bow, Nebraska substation, to an existing substation near Ord, Nebraska.
$16.4 million for construction of a new substation in Holt County, Nebraska
$12.7 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2 The following chart illustrates the Board-authorized capital projects for the years ended December 31, 2013 through 2015, including the Board-authorized budget for the year ended December 31, 2016.
$600 u;- $500
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2013 2014 2015 2016 Budget RESOURCE PLANNING The District's core planning principles for its most recent Integrated Resource Plan ("IRP } aligns with the Board's strategic goals which include further diversifying its mix of generating resources (nuclear, coal, hydro, wind, energy efficiency and demand response}, energy storage, and capitalizing on the competitive strengths of Nebraska (available water, proximity to coal, and abundance of wind}. Key goals from the IRP include:
- 12 NE13RASKA P Ul3LIC Powi.:R Dis 1 RICT
Achieving a goal of 10% of the District's energy supply from renewable resources by 2020,
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Increasing focus on energy efficiency to meet customer load growth, and Increasing diversification with a trend toward cleaner energy The probabilistic analysis under the IRP focused on key future uncertainties, including customer load growth, future environmental regulations including carbon dioxide ("C02"), capital additions and operation and maintenance costs of new units, future fuel, and market prices for electricity. The results showed that with the District's recapture of 120 MWs of base load generation from expiring capacity and energy contracts out of CNS, and lower projected load growth, the District is positioned to meet its firm load requirement needs for the next 10 to 15 years. Specific actions on which the District will focus to meet load growth needs include addition of renewables, effectiveness of energy efficiency programs and evaluation of additional peaking capacity.
The District's Board approved the IRP during the second quarter of 2013. Although the IRP included a power uprate for CNS, the District's most recent evaluation of the costs and market risks related to a power uprate has led the District to decide not to engage in a power uprate for CNS at this time. Long-term operation of GGS appears to continue to be commercially viable even if additional long-term environmental controls are required.
The District would need to revisit this assumption if high C02 costs occur. Operation of Sheldon and Canaday appears marginally beneficial unless and until additional environmental controls or other costly major modifications are required. More wind and energy efficiency also appear beneficial, but not under a low native load growth scenario. The major uncertainties identified in the IRP are continually reviewed and evaluated as to their impact on the District. The District expects to issue its next IRP in 2018.
Renewable Energy The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition, the District has entered into power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all of the electric power output of these wind facilities. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities in Nebraska over similar terms. The District will pay only for energy delivered pursuant to such power purchase wind agreements and the cost of the substation and transmission work to connect these facilities to the District's electric system. Participating utilities will pay their pro rata share of energy delivered from these facilities along with associated capital additions for substation and transmission work.
Hydrogen Generation Monolith Materials, Inc. ("Monolith") has expressed an interest to construct and operate a carbon black facility adjacent to the District's Sheldon coal-fired generating facility in Nebraska. The electric load to serve any Monolith facility will be served by Norris Public Power District, a firm wholesale customer of the District. Monolith may be the single-largest industrial customer served in the District's territory. The District is in negotiations with Monolith to purchase the carbon black plants' production of hydrogen, which will be produced by Monolith as a co-product from its production of carbon black. The District then expects to convert its existing coal-fired boiler at Sheldon Station Unit No. 2 to burn hydrogen fuel. The boiler conversion is expected to result in a reduction of C02, sulfur dioxide, mercury, and other air emissions.
ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks, including exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the creditworthiness of its counterparties, and the operational risks associated with transacting in the wholesale energy markets.
To help manage energy risks, including the risks related to the District's participation in the SPP Integrated Market, the District relies upon TEA to both transact on its behalf in the wholesale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets.
TEA combines a strong knowledge of the District's system, an in-depth understanding of the wholesale energy
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markets, experienced people, and state-of-the-art technology to deliver a broad range of standardized and customized energy products and services to the District.
TEA has assisted the District in developing its Energy Risk Management ("ERM"} program and associated ERM Governing Policy ("ERM Policy"}. The ERM Policy, approved by the Board, establishes guidelines and objectives and delegation of authorities necessary to govern activities related to the District's ERM program. The objective of the ERM program is to increase fuel and energy price stability by hedging the risk of significant adverse impacts to cash flow. These adverse impacts could be caused by events such as natural gas or power price volatility, or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed.
The District's ERM Policy has been revised to reflect the District's participation in the SPP Integrated Market. In addition, the Board has also approved an Energy Risk Management Approved Products and Limits guideline that will be applicable to all physical and financial energy or power-related transactions of the District, including transactions related to the District's participation in the SPP Integrated Market.
ECONOMIC FACTORS Nebraska's economy continues to grow but at a slower rate than in recent years. The state's inflation adjusted gross state product ("GSP"} increased by.1.1 % from the third quarter of 2014 to the third quarter of 2015. This was less than the 2.0% increase in the national gross domestic product over the same 12-month period and was a sharp decrease from Nebraska's 2.7% increase in GSP from the third quarter of 2013 to the third quarter of 2014. Nebraska's slowdown in GSP growth has been due to declines in the value of agricultural outputs and durable goods manufacturing during the latest two-year period and more recent declines in the transportation and warehousing sector.
Nebraska and the Midwest region continue to experience unemployment rates that are near pre-recession levels and are well below the national averages. Nebraska's unemployment rate decreased from an annual average of 3.3% for 2014 to 3.0% in 2015 and remained well below the 2015 national average unemployment rate of 5.3%.
Nebraska's preliminary, seasonally adjusted unemployment rate was 3.0% in December 2015, up slightly from 2.9% in *December 2014. Both numbers were well below the national December seasonally adjusted unemployment rates of 5.0% in 2015 and 5.6% in 2014. In December 2015, Nebraska's preliminary unemployment rate was the third lowest in the nation. The District continues to monitor changes in national and global economic conditions, as these could impact cost of debt and access to capital markets CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY The Electric Utility Industry In General The electric utility industry has been, and in the future may be, affected by a number of factors which could impact the financial condition and competitiveness of electric utilities, such as the District. Such factors include, among others:
o effects of compliance with rapidly changing environmental, safety, licensing, regulatory, and legislative requirements, Q
changes resulting from energy efficiency and demand-side management programs on the timing and use of electric energy, other federal and state legislative and regulatory changes, increased wholesale competition from independent power producers, marketers, and brokers, "self-generation" by certain industrial and commercial customers, e
issues relating to the ability to issue tax-exempt obligations, e
severe restrictions on the ability to sell to nongovernmental entities electricity from generation projects financed with outstanding tax-exempt obligations, changes from projected future load requirements, o
increases in costs, shifts in the availability and relative costs of different fuels,
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inadequate risk management procedures and practices with respect to, among other things, the purchase and sale of energy, fuel, and transmission capacity, effects of financial instability of various participants in the power market, climate change and the potential contributions made to climate change by coal-fired and other fossil-fueled generating units, increased regulation of nuclear power plants in the United States resulting from the earthquake and tsunami damage to certain nuclear power plants in Japan, and issues relating to cyber and physical security.
Any of these general factors (as well as other factors) could have an effect on the financial condition of the District.
Competitive Environment in Nebraska While wholesale competition is expected to increase in the future, there is a Nebraska statute that prohibits competition for retail customers. Pursuant to state statutes, retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppliers and/or pursuant to an order of the Nebraska Power Review Board. While state statutes do not provide for wholesale suppliers of electricity to have exclusive rights to serve a particular area or customer at wholesale, wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements.
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INDEPENDENT AUDITOR'S REPORT To the Board of Directors of the Nebraska Public Power District:
We have audited the accompanying financial statements of Nebraska Public Power District (the "District") which comprise the balance sheets as of December 31, 2015 and 2014, and the related statements of revenues, expenses, and changes in net position, and statements of cash flows for the years then ended.
fJianagement's Responsibili'iy for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditor's Responsibility Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the District's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the District's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the District as of December 31, 2015 and 2014, and the respective changes in financial position and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Other Matters The accompanying management's discussion and analysis and the supplemental schedules on pages 2 through 15 and 43 and 44, respectively, are required by accounting principles generally accepted in the United-States of America to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential partYof financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audits of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
Our audits were conducted for the purpose of forming an opinion on the financial statements that collectively comprise the District's basic financial statements. The statistical review is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has not been subjected to the auditing procedures applied in the audits of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.
R,c..--1-..i.... c.,.* l'uj St. Louis, Missouri April 14, 2016 LLP
FINANCIAL STATEMENTS Nebraska Public Power District Balance Sheets as of December 31, (in OOO's)
ASSETS AND DEFERRED OUTFLOWS Current Assets:
Cash and cash equivalents.....................................................................
Investments...........................................................................................
Receivables, less allowance for doubtful accounts of $515 and $497, respectively..............................................................
Fossil fuels, at average cost...................................................................
Materials and supplies, at average cost...................................................
Prepayments and other current assets....................................................
Special Purpose Funds:
Construction funds.................................................................................
Debt reser-.e funds.................................................................................
Employee benefit funds..........................................................................
Decommissioning funds.........................................................................
Utility Plant, at Cost:
Utility plant in ser'IJice.............................................................................
Less reser.e for depreciation...................................................................
Construction work in progress.................................................................
Nuclear fuel, at amortized cost................................................................
Other Long-Term Assets:
Regulatory asset for asset retirement obligation........................................
Regulatory asset for other postemployment benefit obligation....................
Long-term capacity contracts.................................................................
Unamortized financing costs...................................................................
Investment in The Energy Authority.........................................................
Other....................................................................................................
Total Assets.................................................................................
Deferred Outflows of Resources:
2015 85,060 400,426 110,089 39,335 117,430 11 938 764,278 76,503 91,772 3,344 567,348 738,967 4,751,016 2,620,091 2, 130,925 209,626 168,420 2,508,971 32,323 121,595 172,966 8,654 7,018 11 083 353,639 4,365,855 Unamortized cost of refunded debt..........................................................
40 775 TOTAL ASSETS AND DEFERRED OUTFLOWS...........................................
$ 4.406 630 LIABILmES, DEFERRED INFLOWS, AND NET POSmON Current Liabilities:
Revenue bonds, current..........................................................................
114,860 Notes and credit agreements, current......................................................
Accounts payable and accrued liabilities..................................................
63,614 Accrued in lieu of tax payments..............................................................
9,948 Accrued payments to retail communities.................................................
6,087 Accrued compensated absences............................................................
16,857 Other....................................................................................................
7,492 218,858 Long-Term Debt:
Re11enue bonds, net of current.................................................................
1,596,972 Notes and credit agreements, net of current.............................................
241,700 1,838,672 Other Long-Term Liabilities:
Asset retirement obligation.....................................................................
600,311 Other postemployment benefit obligation..................................................
121,595 Other....................................................................................................
5164 727,070 Total Liabilities.............................................................................
2,784,600 Deferred Inflows of Resources:
Unearned revenues................................................................................
176, 118 Other deferred inflows.............................................................................
113,728 289,846 Net Position:
Net investment in capital assets..............................................................
866,699 Restricted.............................................................................................
40,492 Unrestricted..........................................................................................
424,993 1,332, 184 TOTAL LIABILmES, DEFERRED INFLOWS, AND NET POSITION.................
~ 4,406,6~0 The accompanying notes to financial statements are an integral part of these statements.
2014 90,079 336,753 122,686 36,574 121,764 12 131 719,987 143,490 95,463 4,055 565,544 808,552 4,674,500 2,533,100 2,141,400 151,712 202,094 2,495,206 459,991 125,747 179,938 10,278 7,895 16 557 800,406 4,824, 151 26,794
~ ~ ~5Q 945 109,835 185,503 58,073 10,040 6,148 16,569 9,508 395,676 1,710,850 92,000 1,802,850 1,026,357 127,247 6043 1,159,647 3,358, 173 177, 143 74505 251,648 770,514 43,889 426,721 1,241,124
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- prior year's financial statements have been reclassified to conform to the 2015 presentation. These reclassifications had no effect on Increase in Net Position or Net Position.
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Principal Amounts Due Within One Year 114,860 114,860 In February 2015, the District issued General Revenue Bonds, 2015 Series A in the amount of $223.0 million to advance refund $239.2 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $42.0 million, which resulted in present value savings of $26.1 million.
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Also in February 2015, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2026 through January 1, 2041 General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2036 through January 1, 2041 General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2023 through January 1, 2037 General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2024 through January 1, 2038, and General Revenue Bonds, 2012 Series C, maturing on January 1 *. 2024 In December 2014, the District issued General Revenue Bonds, 2014 Series C in the amount of $162.9 million to advance refund $170.6 million of bonds. The refunding reduced total debt service payments over the life of the bonds by $16.5 million, which resulted in present value savings of $12.4 million.
Also in December 2014, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
0 General Revenue Bonds, 2005 Series A, maturing on January 1, 2026, General Revenue Bonds, 2005 Series B-2, maturing on January 1, 2017, General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2017 through January 1, 2030, General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2017 through January 1, 2036, General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2018 through January 1, 2022, o
General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2019 through January 1, 2023, and General Revenue Bonds, 2012 Series C, having maturity dates ranging from January 1, 2019 through
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January 1, 2023.
In July 2014, the District issued General Revenue Bonds, 2014 Series A in the amount of $195.2 million to finance $114.0 million of the costs of transmission capital additions and to advance refund $81.2 million of bonds.
Additionally, the District issued General Revenue Bonds, 2014 Series B {Taxable) in the amount of $24.4 million to advance refund $24.2 million of bonds. The refundings reduced total debt service payments over the life of the bonds by $11.4 million, which resulted in present value savings of $6.9 million.
Also in July 2014, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
o General Revenue Bonds, 2005 Series A, having maturity dates ranging from January 1, 2016 through January 1, 2025, ca General Revenue Bonds, 2005 Series B-1, maturing on January 1, 2016,
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General Revenue Bonds, 2005 Series B-2, maturing on January 1, 2016, General Revenue Bonds, 2005 Series C, having maturity dates ranging from January 1, 2019 through January 1, 2030, and General Revenue Bonds, 2006 Series A, having maturity dates ranging from January 1, 2020 through January 1, 2031.
Certain of the General Revenue Bonds, from the following series, with outstanding principal amounts that aggregate $472.2 million as of December 31, 2015, were legally defeased and are no longer outstanding: 2005 Series C, 2006 Series A, 2007 Series B, 2008 Series B, and 2012 Series C.
Certain of the General Revenue Bonds, from the following series, with outstanding principal amounts that aggregate $337.3 million as of December 31, 2014, were legally defeased and are no longer outstanding: 2005
Series A, 2005 Series B-1, 2005 Series B-2, 2005 Series C, 2006 Series A, 2007 Series B, 2008 Series B, and 2012 Series C. Said defeased bonds are payable solely from United States Treasury Obligations in irrevocable escrow accounts. Accordingly, the bonds and the related escrow accounts are not included in the Balance Sheets.
Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2015, are as follows (in OOO's):
Debt Seruce Principal Year Payments Payments 2016............................................
191,325 114,860 2017............................................
163,208 91,795 2018............................................
163,211 96,310 2019............................................
138,727 76,435 2020............................................
138,620 79,930 2021-2025....................................
631, 132 393,840 2026-2030....................................
470,980 323,790 2031-2035....................................
333,616 261,345 2036-2040....................................
138,918 117, 110 2041-2043 ************************************
35,035 32,435 Total Payments....................,.......
$ 2,404,772
$ 1,587,850 The fair value of outstanding revenue bonds was determined using currently published rates. The fair value was estimated to be $1,765.4 million and $1,891.5 million at December 31, 2015 and 2014, respectively.
Commercial Paper Notes The District is authorized to issue up to $150.0 million of TECP notes. A $150.0 million line of credit expiring July 1, 2017, is maintained with two commercial banks to support the sale of the TECP notes. The District had
$83.0 million and $92.0 million of TECP notes outstanding at December 31, 2015 and 2014, respectively. The proceeds of the TECP notes have been used to provide short-term financing for certain capital additions and for other lawful purposes of the District. The effective interest rate on outstanding TECP notes was 0.06% and 0.08%
for 2015 and 2014, respectively. The notes outstanding are anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the commercial paper notes approximates market value due to the short-term nature of the notes.
Line of Credit Agreement The District has a line of credit of $150.0 million expiring July 1, 2017, that supports the payment of the principal outstanding of the TECP notes. No amounts were drawn on the line of credit as of December 31, 2015 and 2014.
Taxable Revolving Credit Agreement The District has entered into a Taxable Revolving Credit Agreement ("TRCA") with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 million. The TRCA allows the District to increase the loan commitments to $300.0 million. The District had outstanding balances under the TRCA of $158.7 million and $185.5 million, at December 31, 2015 and 2014, respectively. The TRCA was renewed on July 31, 2015 and terminates on July 30, 2018. The outstanding amount is anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the revolving credit agreements approximates market value due to the short-term nature of the agreements.
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Rewnue bonds consist of the following (in OOO's except interest rates):
December 31 Interest Rate 2015 2014 General Rewnue Bonds:
2005 Series A Serial Bonds 2015............................
5.25%
15 2005 Series C:
Serial Bonds: 2015-2025, 2040.....................
3.875% -
5.00%
44,230 45,985 2030-2034..............................
4.75%
18,240 2035-2040..............................
5.00%
27,500 2006 Series A:
Serial Bonds: 2015-2025..............................
4.00% -
5.00%
5,145 2031-2035..............................
5.00%
10,240 2036-2040..............................
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400 400 2036-2040..............................
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30,020 2007 Series B:
Serial Bonds: 2015-2026 ******************************
4.375% -
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111,825 142,565 Term Bonds:
2027-2031..............................
4.65%
31,190 36,140 2032-2036..............................
5.00%
7,120 19,270 2008 Series B:
Serial Bonds: 2015-2029... ~..........................
4.00% -
5.00%
38,785 136,245 Term Bonds:
2030-2032..............................
5.00%
22,860 32,390 2033--2037..............................
5.00%
40,375 50,880 2038-2040..............................
5.00%
7,180 7,180 2009 Series A Taxable Build America Bonds:
Term Bonds:
2019-2025..............................
6.606%
17,465 17,465 2026-2034..............................
7.399%
32,890 32,890 2009 Series C Serial Bonds 2014-2019...................
3.50% -
4.25%
6,595 8,515 201 O Series A Taxable Build America Bonds:
Serial Bonds: 2019-2024..............................
3.98% -
4.73%
31,875 31;015 Term Bonds:
2025-2029..............................
5.323%
27,985,,
27,985 2030-2042..............................
5.423%
54,190 54,190 2010 Series B Taxable Serial Bonds 2015-2020.......
2.858% - 4.18%
4,415 5,210 2010 Series C:
Serial Bonds: 2015-2025..............................
3.00%" 5.00%
64,520 79,615 Term Bonds:
2026-2030..............................
4.00%
6,165 6,165 2026-2030..............................
5.00%
14,180 14,180 2011 Series A Serial Bonds 2015-2016...................
2.50% -
5.00%
7,115 ;
15,815 2012 Series A Serial Bonds 2015-2034...................
3.00% - 5.00%
198,310 205,905 2012 Series B:
Serial Bonds: 2015-2032..............................
2.00% -
5.00%
95,875 99,325 Term Bonds:
2033--2036..............................
3.625%
2,320 2,320 2037-2042..............................
3.625%
4,155 4,155 2012 Series C Serial Bonds 2015-2028...................
3.00% -
5.00%
37,340 52,735 2013 Series A Serial Bonds 2015-2033...................
3.00% -
5.00%
103,815 111,480 2014 Series A:
Serial Bonds: 2015-2038..............................
2.00% -
5.00%
156, 145 161,385 Term Bonds:
2039-2043..............................
4.00%
31,650 31,650 2039-2043..............................
4.125%
1,945 1,945 2014 Series B Taxable Serial Bonds 2015................
0.48%
24,415 2014 Series C Serial Bonds 2015 - 2033..................
2.00% -
5.00%
162,415 162,890 2015 Series A-1 Serial Bonds 2022-2034................
3.00% -
5.00%
119,400 2015 Series A-2:....................................................
Serial Bonds: 2015-2034..............................
3.00% -
5.00%
56,915 Term Bonds:
2035-2039..............................
5.00%
461205 Total par amount of rewnue bonds...................................................................
1,587,850 1,714,325 Unamortized premium net of discount..........................................................
1231982 106,360 1,711,832 1,820,685 Less - current maturities of revenue bonds...................................................
(114,860}
(109,83fil.
Total rewnue bonds................................................................................J.1,596,9?.f..
~1,l10.850
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- 8. PAYMENTS IN LIEU OF TAXES:
The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District. Such payments totaled $10.0 million and $10.1 million for each of the years ended December31, 2015 and 2014, respectively.
- 9. ASSET RETIREMENT OBLIGATIONS:
Asset retirement obligations ("ARO") are calculated at the present value of a long-lived asset's applicable disposal costs and are recorded in the period in which the liability is incurred. This liability is accreted during the remaining life of the associated assets and adjusted periodically based upon updated estimates. The District has recorded an obligation for the fair value of its legal liability for the ARO associated with CNS, 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. A study was completed to update the costs for the ARO for CNS in 2015 because the last study was completed in 2008 and changes were expected due to the recent decommissioning of plants by other industry participants. Based on the results of the 2015 study and refreshed assumptions, the ARO was reduced by $477.8 million with a corresponding reduction in the related regulatory asset.
ASC 410, Asset Retirement and Environmental Obligations, requires capitalization of the costs to the related asset and depreciation of these costs over the same period as the related asset. The District does not use depreciation as a cost component for rates. Accordingly, the District has established a regulatory asset, under accounting guidance in Re10, for the costs that will be recovered in future rates. A significant amount of the ARO was funded by decommissioning funds of $567.3 million and $565.5 million as of December 31, 2015 and 2014, respectively. See Note 2 for additional information.
The following table shows changes to the ARO that occurred during the years ended December 31,
- 2015 and 2014, and are included in Other long-term liabilities section of the accompanying Balance Sheets as of December 31, (in OOO's):
2015 2014 Balance, beginning of year.............................................................................. $ 1,026,357 977,083 Accretion......................................................................................................
51,764 49,274 ARO adjustment............................................................................................
{477,810}
Balance, end of year..................................................... _................................. $
600,311
$ 1,026,357
- 10. RETIREMENT PLAN:
The District's Employees' Retirement Plan (the "Plan") is a defined contribution pension plan established and administered by the District to provide benefits at retirement to regular full-time and part-time employees. There were 1,955 active plan members at December 31, 2015. Plan provisions and contribution requirements are established and may be amended by the Board.
Plan members are eligible to begin participation in the Plan immediately upon hire. Contributions ranging from 2%
to 5% of base pay are eligible for District matching dollars after six months of employment. The District contributes two times the Plan member's contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District contributes one times the Plan member's contribution. The Participants' contributions were $12.8 million and $11.9 million for 2015 and 2014, respectively. The District's matching contributions were $12.1 million and $11.8 million for 2015 and 2014, respectively. Total contributions of $1.4 million and $1.3 million were accrued in Accounts payable and accrued liabilities for the years ended December 31, 2015 and 2014, respectively.
Plan members are immediately vested in their own contributions and earnings and become vested in the District's contributions and earnings based on the following vesting schedule:
Years of Vesting Participation 5 years or more....................................
4 years................................................
3 years................................................
2 years................................................
Less than 2 years................................
Percent 100%
75%
50%
25%
0%
Nonvested District contributions are forfeited upon termination of employment. Such forfeitures are first used to cover Plan administrative expenses and any remaining forfeitures are used to reduce District matching contributions.
- 11. OTHER POSTEMPLOYMENT BENEFITS:
A. Plan Description and Funding Policy -
The District's Post-Employment Medical and Life Benefits Plan ("Plan") provides postemployment hospital-medical and life insurance benefits to qualifying retirees, surviving spouses, and employees on long-term disability and their dependents. Benefits and related eligibility, funding and other Plan provisions, for this single-employer, defined benefit Plan, are authorized by the Board.
Contributions from Plan members are the required premium share, which is based on date of hire and/or age. The District pays all or part of the cost (determined by age) for employees hired before 1993. Qualifying employees hired after 1992 are subject to a contribution cap that limits the District's portion of the cost of such coverage to the full premium the year the employee retired or the amount at the time the employee reaches age* 65, or the year in which the employee retires if older than age 65. Any increases in the cost of such co~erage in subsequent years are paid by Plan members. Qualifying employaes hired after 1998 are not eligible for postemployment hospital-medical benefits once they reach age 65 or Medicare eligibility. Employees hired after 2003 are not eligible for postemployment hospital-medical benefits. The District amended the plan effective July 1, 2007, to provide that any former employee who is rehired will receive credit for prior years of service. The District further amended the plan effective September 1, 2007, to provide that employees hired or rehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for postemployment hospital-medical benefits.
In May 2015, the Board approved a change for Medicare-eligible retirees for prescription drugs from the District's self-insured employee prescription plan to a group insured Medicare Part D supplement effective January 1, 2016. The District also changed its funding plan to contribute, at a minimum, the actuarially-determined annual required contribution ("ARC") to achieve full funding status on or before December 31, 2033, and to pay benefits/expenses from the OPEB Trusts.
Contributions in the form of premium payments by OPEB Plan members were $0.6 million, $0.5 million and $0.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Members do not contribute to the cost of the life insurance benefits.
B. Annual OPEB Cost and Net OPEB Obligation -
The annual OPEB costs are determined by actuaries and equal (a) the ARC, (b) one year's interest on the net OPEB obligation, and (c) an adjustment to the ARC to offset the effect of actuarial amortization of past under-or over-collected contributions. Commencing in 2016, the OPEB Trusts will be funded with the entire ARC and benefits/expenses will be paid directly from the Trusts. Prior to 2016, the District included in expenses and rates the OPEB benefits/expenses expected in the current period and the amount authorized for funding in the Trust for OPEB benefit payments for future periods. The difference between the annual OPEB cost and the District's contributions are included in the net OPEB obligation. As the District uses regulatory accounting to ensure costs are consistent with those included in the rates, the offset to the net OPEB obligation is a regulatory asset.
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The following table shows the components of the District's OPEB cost for the year, the amount actually contributed, and changes in the District's net OPES obligation as of December 31, (in OOO's):
2015 2014 2013 Annual required contribution................................................... $
28,223 32,026 35,030 Interest on net OPEB obligation..............................................
7,859 5,865 5,583 Adjustment to annual required contribution..............................
{11,832}
{5,803}
{5, 191}
Annual OPEB cost................................................................
24,250 32,088 35,422 Contributions made...............................................................
{28,402)
{29,816)
{23,603)
(Decrease} Increase in net OPES obligation............................
(4, 152) 2,272 11,819 Net OPES obligation, beginning of year...................................
125,747 123,475 111,656 Net OPES obligation, end of year........................................... $
121,595
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125,747 123,475 The District's annual OPES cost, the percentage of annual OPEB cost contributed, and the net OPEB obligation for 2015, 2014, and 2013 were as follows (in OOO's):
Annual OPES Percentage of Net OPES Year Cost Annual OPEB Obligation Cost Contributed 2015 24,250 117.1%
121,595 2014 32,088 92.9%
125,747 2013 35,422 66.6%
123,475 C. Funded Status and Funding Progress -
At December 31, 2015, there ware two Trusts for OPES, the "Nebraska Public Power District Post-Employment Medical and Life Benefits Trust" and the "Nebraska Public Power District Retired Employee Life Benefit Trust". In 2016, the OPES Trust for Medical and Life Benefits was amended as the "Amended and Restated Nebraska Public Power District Medical and Life Benefits Trust for Employees in Retirement Status" and a separate, OPES Trust was established for employees in disability status as the, "Nebraska Public Power District Hospital-Medical and Employee Life Insurance Benefit Trust for Employees in Disability Status." Retiree Life Benefits will continue to be paid from the Nebraska Public Power District Retired Employee Life Benefit Trust until funds are exhausted.
This Trust will then be terminated and these benefits will be paid from the OPEB Trust for employees in retirement status. Stand-alone financial reports will be prepared for OPEB commencing in 2016.
Total OPEB contributions in 2015 were $28.4 million, which included $11.5 million deposited in the Trust and
$16.9 million paid for the cost of benefits/expenses. Total contributions in 2014 were $29.8 million, which included
$11.9 million deposited in the trust and $17.9 million paid for the cost of benefits. Total contributions in 2013 were
$23.6 million, which included $10.0 million deposited in the trust and $13.6 million paid for the cost of benefits.
Actuarial valuations were completed as of January 1, 2015 and 2014. The information as of January 1, 2013, was based on information from the actuary's model. The Actuarial Value of Assets was based on the market values of the Plan's assets. The Actuarial Accrued Liability ("AAL ") was the present value of benefits attributable to past accounting periods and decreased by $196.3 million in the 2015 valuation. The decrease was due primarily to the plan change for prescription drugs for Medicare-eligible retirees and the commitment to fund the entire ARC and pay benefits/expenses from the OPEB Trusts which accounted for $132.8 and $65.5 million of the decrease, respectively.
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The Actuarial Value of Assets, AAL, and other information, are presented in the table below as of January 1, (in OOO's):
Actuarial Actuarial Unfunded Funded Cow red UAAL to Value of Accrued Actuarial Accrued Cow red Assets Liability (AAL)
Liability (UAAL)
Ratio Payroll Payroll
{a}
{b}
{b-a}
{alb}
{c}
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2015
$64,487
$309,908
$245,421 20.8%
$186,952 131%
2014
$48,274
$506,200
$457,926 9.5%
$186,637 245%
2013
$30,781
$520,705
$489,924 5.9%
$187,378 261%
The above schedule presents multiyear trend information about whether the actuarial value of plan assets is increasing or decreasing over time relative to the actuarial accrued liability for benefits. Actuarial valuations of an ongoing plan involve estimates of the value of reported amounts and assumptions about the probability of occurrence of events far into the future. Examples include assumptions about future employment, mortality, and the healthcare cost trend. Amounts determined regarding the funded status of the plan and the annual required contributions of the employer are subject to continual revision as actual results are compared with past expectations and new estimates are made about the future.
D. Actuarial Methods and Assumptions -
Projections of benefits for financial reporting purposes are based on the substantive plan (the plan as understood by the employer and the plan members) and include the types of benefits provided at the time of each valuation and the historical pattern of sharing benefit costs between the employer and plan members to that point. The actuarial methods and assumptions used include techniques that are designed to reduce the effects of short-term volatility in actuarial accrued liabilities and the actuarial value of assets, consistent with the long-term perspective of the calculations.
The actuarial assumptions and methods used for the valuations on January 1, 2015, 2014 and 2013, were as follows:
The Pre-Medicare healthcare cost trend rates ranged from 8.0% initial to 6.2% ultimate for 2015, from 5.9% initial to 4.4% ultimate for 2014, and from 8.5% initial to 4.6% ultimate for 2013.
f)
The Post-Medicare healthcare cost trend rates ranged from 6.8% initial to 6.2% ultimate for 2015, from 6.2% initial to 4.5% ultimate for 2014, and from 8.5% initial to 4.6% ultimate for 2013.'"
The discount rate used was 6.25%, 4.75%, and 5.0% for 2015, 2014, and 2013, respectively, which was based on the expected return on investments used to fund benefit payments. The higher rate for 2015 was due to the commitment to fund at least 100% of the ARC and to pay all benefits/expenses directly from the Trusts commencing in 2016.
An inflation rate of 2.1% was assumed for 2015 and 3.5% was assumed for 2014 and 2013.
e Commencing in 2015, the unfunded AAL will be amortized over a period of time such that the plan will be fully funded by 2033. For 2015, the amortization period was 18 years. For 2014 and 2013, amortization for the initial unfunded AAL was determined using a closed period of 30 years and the level percentage of projected payroll method.
o The Unit Credit Actuarial Cost method was used for all three years.
o The mortality table used for participants was the RP2014 Aggregate/Scale MP2014 for 2015 and the RP2000HA/Scale BB for 2014 and 2013.
E. Market Value of Plan Investments -
The investments in the OPEB plan include corporate and government debt, foreign and domestic stocks, mutual funds and cash. Plan assets included funds in the Employee Benefit Funds for retiree life insurance of $1.1 million, $1.2 million, and $1.4 million at December 31, 2015, 2014, and 2013, respectively. The market value of plan assets, including the funds in the Employee Benefit Funds, was $75.2 million, $64.5 million, and $48.3 million at December 31, 2015, 2014, and 2013, respectively.
- 12. COMMITMENTS AND CONTINGENCIES:
A. Fuel Commitments -
The District has various coal supply contracts and a coal transportation contract with minimum future payments of
$273.0 million at December 31, 2015. These contracts expire at various times through the end of 2018. The coal transportation contract in place is sufficient to deliver coal to the generation facilities through the expiration date of the aforementioned contracts and is subject to price escalation adjustments.
The District has a contract for conversion services of uranium to uranium hexafluoride which is in effect through 2018, a contract for enrichment services through 2024, and a contract for fabrication services through January 18, 2034, the end of the current operating license of CNS. These commitments for nuclear fuel material and services have combined estimated future payments of $265.0 million.
- 8. Power Purchase and Sales Agreements -
The District has entered into a participation power agreement (the "NC2 Agreement") with OPPD to purchase 23.7% of the power of the NC2, estimated to be 161 MW of the power from the 663 MW coal-fired power plant constructed by OPPD. The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs, and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursuant to such step-up provision is limited to 160% of its original participation share (23.7%). No such default has occurred to date.
The District has entered into a participation power sales agreement with Municipal Energy Agency of Nebraska ("MEAN") for the sale to MEAN of the power and energy from Gerald Gentleman Station ("GGS") and CNS of 50 MW which began January 1, 2011 and continues through December 31, 2023.
The District has entered into power sales agreements with Lincoln Electric System CULES") for the sale to LES of 30% of the net power and energy of Sheldon Station ("Sheldon") and 8% of the net power and energy of GGS. In return, LES agrees to pay 30% and 8% of all costs attributable to Sheldon and GGS, respectively. Each agreement is to terminate upon the later of the last maturity of the debt attributable to the respective station or the date on which the District retires such station from commercial operation.
The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately $36.3 million. These purchases are subject to rate changes.
The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition, the District has power purchase agreer:nents with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities. The District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities in Nebraska over similar terms.
The District has entered into a power purchase agreement with Central for the purchase of the net power and energy produced by the Kingsley Project during its operating life. The Kingsley Project is a hydroelectric generating unit at the Kingsley Dam in Keith County, Nebraska with an accredited net capacity of 37 MW.
The District has entered into long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO Agreements expire on various dates between March 1, 2023 and May 1, 2033. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreement.
C. Wholesale Power Contracts The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District The District entered into new 20-year Wholesale Power Contracts ("2016 Contracts") with 23 public power districts, which includes one cooperative, and 39 municipalities,
effective January 1, 2016. Two public power districts and 11 municipalities are served under 2002 Wholesale Power Contracts ("2002 Contracts"), which expire on December 31, 2021.
The 2016 Contracts allow a wholesale customer to give notice to reduce its purchase of demand and energy requirements from the District based on a comparison of the District's average annual wholesale power costs in a given year compared to power costs of U.S. utilities for such year listed in the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given utility can compare its power costs on a percentile basis to the CFC published quartile information. The 2016 Contracts allow a wholesale customer to reduce its demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given year is higher than the 451h percentile level (the "Performance Standard Percentile") of the power costs of U.S. utilities for such year as listed in the CFC Data. The 2016 Contracts would not allow any reductions in demand and energy purchases by a wholesale customer as long as the District's average annual wholesale power costs percentile remained below the Performance Standard Percentile. The following table lists the District's wholesale power costs percentile for the calendar years 2010 to 2014 set forth in the CFC Data:
CFC Data Year Percentile 2010 18.3%
2011 24.4%
2012 29.1%
2013 31.0%
2014 27.6%
The 2002 Contracts allow a wholesale customer to reduce its purchases of demand and energy upon giving appropriate notice. Reductions could amount to as much as 90% of their demand and energy requirements under certain circumstances. All wholesale customers under the 2002 wholesale contracts are required to purchase at least 10% of their demand and energy from the District through December 31, 2021.
The District has received notices from nine wholesale customers as to their intent to level off, reduce, or terminate the requirements under their 2002 wholesale contracts for various amounts from 2017 through 2021. The nine customers include one municipality which has a short-term wholesale contract terminating _in May 2016. These wholesale customers represented 4.5% of the District's 2015 operating revenues. The District expects that no requirements of said nine wholesale customers will be served by the District in 2022, and such wholesale customers will purchase all of their electric requirements from other suppliers. The District expects '*to sell the energy not sold to such wholesale customers into the SPP Integrated Market and continues to explore additional firm requirement and/or fixed price agreements. Four wholesale customers have not given notice to reduce and continue under the 2002 wholesale contracts. These customers represented 1.2% of the District's 2015 operating revenues.
Five wholesale customers under the 2002 Contracts have filed a lawsuit in state court challenging the 2016 wholesale rates. The 2016 wholesale rates result in a 0.6% increase for wholesale customers who sign the new 2016 Contracts and a 3.8% increase for those wholesale customers who remain under the 2002 Contracts. The rate increase was higher for the 2002 Contracts as these customers will pay their share of previously incurred OPEB costs through 2021. Customers under the 2016 Contracts are paying their share of OPEB costs over a longer period. The five wholesale customers filing the lawsuit have notified the District that they will not remain wholesale customers of the District after 2021. Said wholesale customers allege the 2016 rates are unreasonable, discriminatory and unfair. Said wholesale customers seek injunctive relief and damages. In December 2015, the District filed a motion to dismiss, alleging that Nebraska law requires wholesale rate disputes to be submitted to binding arbitration. A hearing on the motion to dismiss occurred in February 2016. The parties submitted briefs and are awaiting a ruling on the motion. If these wholesale customers would be successful on the merits of their claim, the District's Board may need to reconsider the 2016 wholesale rate change.
The Northeast Nebraska Public Power District filed a lawsuit in the District Court of Wayne County, Nebraska regarding the demand and energy reduction provisions under the 2002 Contract. The court issued an order dated February 26, 2016, in favor of the Northeast Nebraska Public Power District which allows them to reduce their demand and energy purchases from the District by 30% in 2018, 60% in 2019 and 90% in 2020. The court decision will apply to certain other customers who have given notice for demand and energy reductions under the 2002 Contract. On March 23, 2016, the District filed a notice of appeal.
D. SPP Membership and Transmission Agreements -
The District is a member of SPP, a regional transmission organization based in Little Rock, Arkansas.
Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration, including generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning. The District was able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost, through February 2014. On March 1, 2014, SPP commenced a Day-Ahead, Ancillary Services, and Real-Time Balancing Market Integrated Market. The Integrated Market also provides a financial market to hedge unplanned transmission congestion, or financial virtual products to hedge uncertainties, such as unplanned outages.
The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system. Cost of the project was
$8.4 million and repayment by Keystone, over a 10-year period, began in June 2010 with a remaining balance due the District of $4.4 million and $5.2 million as of December 31, 2015 and 2014, respectively.
The District entered into a second Transmission Facilities Construction Agreement effective July 17, 2009, with TransCanada Keystone XL Pipeline, LP ("Keystone XL"). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection *and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. Construction of these facilities for Keystone XL has been cancelled. TransCanada Corporation and TransCanada Pipeline USA Ltd.
have jointly and severally guaranteed the payment obligations of Keystone under its agreements with the District.
As of December 31, 2015 and 2014, actual project costs totaled $13.2 million and $12.8 million, respectively, and the District has received payment of $10.3 million.
E.
Cooper Nuclear Station -
On November 29, 2010, the Nuclear Regulatory Commission ("NRC") formally issued a certificate to the District to commemorate the renewal of the operating license for CNS for an additional 20 years until Janua,.Y 18, 2034.
CNS entered the 20-year period of extended operation on January 18, 2014.
In October 2003, the District entered into an agreement (the "Entergy Agreement") for support services at CNS with Entergy Nuclear Nebraska, LLC ("Entergy"), a wholly-owned indirect subsidiary of Entergy Corporation. In 2010, the Entergy Agreement was amended and extended by the parties until January 18, 2029, subject to either party's right to terminate without cause by providing notice and paying a $20 million termination charge. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services, and to pay Entergy annual management fees. These annual management fees were $18.4 million for 2015 and 2014. In 2016, the annual management fee is $18.5 million. This amount will increase by an additional $1.0 million in 2019, and by an additional $3.0 million in 2024. Entergy is eligible to earn additional incentive fees in an amount not to exceed
$4.0 million annually if CNS achieves identified safety and regulatory performance targets. Entergy may earn additional incentive fees estimated to be $2.5 million for 2015 and earned $3.8 million in 2014.
Since the earthquake and tsunami of March 11, 2011, that impacted the Fukushima Dai-ichi Plants in Japan, the District, as well as the rest of the nuclear industry, has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the GE boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes this same containment system; however, significant enhancements to the design have been made over the life of the plant.
- ./
An NRC Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12, 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report, on October 18, 2011, the NRC approved seven of the Task Force recommendations for implementation.
On March 12, 2012, the NRC issued three orders to the U.S. nuclear industry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nuclear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened containment wetwell vents. The third order requires nuclear plant operators to add reliable spent fuel pool water level instrumentation. The NRC has also issued a request for information pertaining to re-evaluation of seismic and flooding hazards, and a communications and staffing assessment for emergency preparedness.
Plant modifications resulting from the orders for modifications to the wetwell vent and fuel pool instrumentation are currently planned for the fall 2016 refueling and maintenance outage which is consistent with the requirements of the NRC's orders that require compliance no later than two refueling cycles following submittal of the Licensee's overall integrated plan or December 31, 2016, whichever comes first. Additional NRC orders and regulations resultant from the Fukushima Dai-ichi event may be forthcoming. The specific impacts of any additional orders and regulations on CNS have not yet been evaluated.
On June 6, 2013, the NRC issued an order to require the addition of a drywell vent to supplement the capabilities of this existing wetwell vent. This work is required to be completed in two phases, with phase one to be completed not later than the startup from the second refueling outage that begins after June 30, 2014 or June 30, 2018, whichever comes first and phase two to be completed no later than the startup from the first refueling outage that begins after June 30, 2017 or June 30, 2019, whichever comes first. Phase one of this order will be completed by the conclusion of the fall 2016 refueling and maintenance outage at CNS. Phase two will be completed by the conclusion of the fall 2018 refueling and maintenance outage. Also, after extensive analysis by the industry and the NRC, it was determined that U.S. reactors would not be required to add a filter on the hardened drywall vent.
After completion of the initial site-specific seismic reevaluation analysis for CNS, the District believed that no seismic-related modifications to CNS were required. Since that time, the District has performed an additional seismic analysis and has worked to answer additional questions from the NRC on this topic. The NRC has determined that CNS will have to perform the High Frequency Evaluation and a Spent Fuel Pool Evaluation, but will not have to complete a Seismic Probabilistic Risk Assessment. Unknown to the District at this time is the extent of modifications that will be required as a result of these additional seismic reevaluations.
The District continues to work with the U.S. Army Corps of Engineers (the "Corps") and the NRC to validate the data necessary to perform the flood hazard reevaluation. The District submitted its updated flooding analysis to the NRC in February 2015. Unknown to the District at this time is the extent of modifications that will be required as a result of the flood hazard reevaluations.
The District's cost estimate for plant modifications associated with the NRC's Fukushima Dai-ichi-related orders is currently estimated to cost $46.7 million, which is expected to be funded primarily from the revenues of the District and from the proceeds of General Revenue Bonds.
After the events at Fukushima Dai-ichi, several individuals and antinuclear groups petitioned the NRC's Office of Reactor Regulation pursuant to 10 CFR 2.206 to take various actions in relation to General Electric boiling water reactors with Mark 1 and Mark 2 containment systems. The petitions range from requests for information to suspension of the operating licenses for all Mark 1 and Mark 2 reactors. Petitions were also filed regarding concerns relating to the consequences of nuclear plants being located near earthquake fault lines or flood zones.
As of November 2015, all the petitions potentially affecting CNS have been closed, either through denial or NRC Director's Decisions. There have been no additional impacts to CNS as a result of these petitions.
CNS substantially completed the construction of a dry cask used fuel storage project in December 2009 to support plant operations until 2034, which is the end of the Operating License. The first loading campaign was
completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool into eight dry used fuel storage casks for on-site storage. A second loading campaign, encompassing the loading of 610 used fuel assemblies into 10 dry used fuel storage casks, began in April 2014 and was completed in June 2014.
As part of various disputed matters between GE and the District, GE has agreed to continue to store at the Morris Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility. After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.
As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 2001. The initial settlement agreement addressed future claims through 2013. On January 13, 2014, the DOE extended the settlement agreement through 2016.
In accordance with a settlement agreement between the District and the DOE that was executed on May 18, 2011, the District has received $115.0 million from the DOE for damages from 2009 through 2015. The District also reserves the right to pursue future damages through the contract claims process. A corresponding regulatory liability for these DOE receipts has been established in Other deferred liabilities line of the Deferred Inflows of Resources section of the accompanying Balance Sheets. The District plans to use the funds to pay for costs related to CNS. The balance in the regulatory liability was $79.5 million and $71.3 million at December 31, 2015 and 2014, respectively.
Under the terms of the DOE contracts, the District was also subject to a one mill per kilowatt-hour ("kWh") fee on all energy generated and sold by CNS which was paid on a quarterly basis to DOE. The District includes a component in its Retail and Wholesale rates for the purpose of funding the costs associated with nuclear fuel disposal. While the District expects that the revenues developed therefrom will be sufficient to cover the District's responsibility for costs currently outlined in the Nuclear Waste Policy Act, the District can give no assurance that such revenues will be sufficient to cover all costs associated with the disposal of used nuclear fuel. On May 9, 2014, the DOE provided notice that they would adjust the spent fuel disposal fee to zero mills per kWh effeciive May 16, 2014. Correspondingly, no additional payments have been made to the DOE for fuel disposal since that date. The Board authorized the continued collection of this fee at the same rate. This approach ensures costs are recognized in the appropriate period with current customers receiving the benefits from CNS paying the appropriate costs. The expense for spent nuclear fuel disposal is recorded based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal.
Under the provisions of the Federal Price-Anderson Act, the District and all other licensed nuclear power plant operators could each be assessed for claims in amounts up to $127.3 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation, with a maximum assessment of $19.0 million per year per incident per unit owned.
The NRC evaluates nuclear plant performance as part of its reactor oversight process ("ROP"). The NRC has five performance categories included in the ROP Action Matrix Summary that is part of this process. As of December 31, 2015, CNS was in the Licensee Response Column, which is the first or best of the five NRC defined performance categories and has been in this column since the first quarter of 2012.
Refueling and maintenance outages are required to be performed at CNS approximately every two years.
Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs, commencing in 2015. The regulatory liability for the pre-collection of outage costs was $24.7 million at December 31, 2015 and will be eliminated through revenue recognition during the 2016 outage year.
F.
Environmental -
On November 3, 2015, EPA published the final Steam Electric Power Plant Effluent Guidelines (40 CFR 423). The rule would strengthen the existing controls on discharges from steam electric power plants. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants. District facilities subject to the rule are CNS, GGS, Sheldon, and Canaday Station. The rule has no impact on CNS or GGS. Sheldon will be required to be a zero discharge facility for bottom ash transport water. Compliance is required between November 1, 2018 and December 31, 2023. The District is currently analyzing the options for compliance.
On February 16, 2012, the EPA issued a final rule intended to reduce emissions of toxic air pollutants from power plants. Specifically, the Mercury and Air Toxics Standards ("MATS") Rule will require reductions in emissions from new and existing coal-and oil-fired steam utility electric generating units of toxic air pollutants. Sheldon began complying with the MATS rule on April 16, 2015. GGS was granted an additional year to achieve compliance.
GGS will be in compliance with the MATS rule on or before April 16, 2016.
As part of EPA's nationwide investigation and enforcement program for coal-fired power plants' compliance with the Clean Air Act including new source review requirements, on December 4, 2002, the Region 7 office of the EPA sent a letter to the District and three other electric utilities pursuant to Section 114(a) of the Federal Clean Air Act requesting documents and information pertaining to GGS and Sheldon. On April 10, 2003, Region 7 of the EPA sent a supplemental request for documents and information to the District and the other three electric utilities. These EPA requests for information are part of an EPA investigation to determine the Clean Air Act compliance status of GGS and Sheldon, including the potential application of new source review requirements.
The District provided the documents and information requested to the EPA within the time allowed. As a supplement to the 2002 and 2003 requests, EPA Region 7 sent another letter to the District on November 8, 2007, requesting additional documents and information pertaining to GGS and Sheldon. The District provided a response to the new request within the time allowed and provided supplemental information to EPA in February and April 2011 in response to an EPA email inquiry. By letter dated December 8, 2008, EPA Region 7 sent a Notice of Violation ("NOV") to the District which alleges that the District violated the Clean Air Act by undertaking five projects at GGS from 1991 through 2001 without obtaining the necessary permits. In February and August 2009, District representatives met with federal government representatives to discuss the NOV and no additional meetings have been scheduled. In general, enforcement action by EPA against the District for alleged noncompliance with Clean Air Act requirements, if upheld after court review, can result in the requirement to install expensive air pollution control equipment that is the BART and the imposition of monetary penalties ranging from $25,000 to $32,500 per day for each violation. The District cannot determine at this time whether it will have any future financial obligation with respect to the NOV.
On October 23, 2015, ihe EPA published the final Clean Power Plan ("CPP") rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determining how to achieve the reduction targets through the development of a State Plan. Each state was given a reduction target to be achieved by 2030 with interim reductions required between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 emissions. On February 9, 2016, the U.S. Supreme Court granted a stay, halting implementation of the CPP pending the resolution of legal challenges to the program. That challenge is currently before the U.S. Court of Appeals for the D.C. Circuit. An initial State Plan providing a general outline of potential compliance options was due September 6, 2016. These deadlines are no longer in effect and state actions have been placed on hold pending the outcome of litigation. It is not possible to determine the impact to the District until the resolution of the legal challenges.
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.
G. Sale of Spencer Hydro Facility -
In September 2015, a memorandum of understanding ("MOU") was signed for the sale of the District's Spencer Hydro ("Spencer") facility, including dam, structures, land, water appropriations and perpetual easements for the reservoir, to the Niobrara River Basin Alliance (Five Natural Resource Districts) and the Nebraska Game and
Parks Commission. The MOU provides that the parties will work for passage of legislation by the State of Nebraska for a permanent transfer of existing hydro water appropriation to a new multi-purpose use, and it identifies potential sources of funding for the sale. The District will continue to operate Spencer until transfer of ownership, including water appropriations, is completed. The transfer is expected to take approximately two years to complete.
H. Other-In October 2015, the Internal Revenue Service affirmed, pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, that the 35% interest subsidy provided by the United States Treasury on the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds), will be reduced by 6.8% for fiscal year ending September 30, 2016. Previous reductions were 7.3% for fiscal year ending September 30, 2015, and 7.2% for fiscal year ended September 30, 2014. The reduction rate is subject to change by Congressional action. This loss of subsidy totals approximately $0.2 million annually.
- 13. LITIGATION:
A number of 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, 2015 and 2014. Information on litigation with wholesale customers is included in Note 12.
- 14. SUBSEQUENT EVENTS:
In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series Bin the amount of
$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of TECP. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.
Also in February 2016, the District entered into an escrow deposit agreement in conjunction with the advanced refunding of certain of the:
General Revenue Bonds, 2007 Series B, having maturity dates ranging from January t, 2026 through January 1, 2037 General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2026 through January 1, 2041, and General Revenue Bonds, 2012 Series C, maturing on January 1, 2025 and January 1, 2026 In January 2016, the District issued TECP in the amount of $43.6 million to refund a portion of the 2005 Series C and 2006 Series A General Revenue Bonds. In February 2016, $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and B.
Effective January 1, 2016, the District entered into new 20-year Wholesale Power Contracts with certain wholesale customers as described in Note 12.
SUPPLEMENTAL SCHEDULES (UNAUDIYED)
Calculation of Debt Seniice Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (in OOO's)
Operating revenues......................................................................................
Operating expenses.....................................................................................
Operating income....................................................................................
Investment and other income.........................................................................
Debt and other expenses..............................................................................
Increase in net position............................................................................
Add:
Collections for future debt retirement.........................................................
Debt and related expenses.......................................................................
Depreciation and amortization...................................................................
Payments to retail communitiesC1l.............................................................
Amortization of current portion of financed nuclear fuel................................
Amounts collected from third party financing arrangementsc2l......................
Deduct:
Investment income retained in construction funds.......................................
Unrealized (loss) gain on investment securities..........................................
Re\\Ohling credit agreement interest...........................................................
Net position available for debt seniice for the General Revenue Bond Resolution.
Amounts deposited in the General System Debt Sennce Account:
Principal.................................................................................................
Interest...................................................................................................
Ratio of net position available for debt ser\\1ce to debt senhce deposits..............
2015 1,097,216 (960,259) 136,957 22,355 (68,252) 91,060 68,252 130,247 26,552 24,675 850 250,576 302 (1,245) 1,010 67 341,569 110,265 75,372 185,637 1.84 2014
$ 1,122,454 (1,010,693) 111,761 26,039 (75,438) 62,362 1,188 75,438 126,440 26,874 20,700 1,276 251,916 190 203 1,731 '
2,124 312, 154 124,780 82,978
$, 207,758 1.50 (1) Under the provisions of the General Revenue Bond Resolution, the payrrents required to be made by the District with respect to the A"ofessional Retail Operations Agreerrents are to be made on the sarre basis as subordinated debl (2) Under the provisions of the General Revenue Bond Resolution, the payrrents received by the District from third party financing arrangerrents provide for debt service coverage, but are not recognized as revenue under Generally Accepted Accounting A"inciples.
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Schedule of Funding Progress for OPEB as of January 1, (in OOO's)
Actuarial Actuarial Unfunded Actuarial Co..ered UAAL to Value of Accrued Accrued Liability Funded Ratio Payroll Co..ered Assets Liability (AAL)
(UAAL)
Payroll (a)
(b)
(b-a)
(alb)
(c)
((b-a)/c) 2015 <1l
$64,487
$309,908
$245,421 20.8%
$186,952 131%
2014
$48,274
$506,200
$457,926 9.5%
$186,637 245%
2013
$30,781
$520,705
$489,924 5.9%
$187,378 261%
(1) The decrease in the AAL in the 2015 valuation was due to a change for Medicare-eligible retirees for prescription drugs from the District's self-insured employee prescription plan to a group insured Medicare Part D supplement effective January 1, 2016 and a change in funding. The District changed its funding plan to contribute, at a minimum, the actuarially-detennined ARC to achieve full funding status on or before December 31, 2033, and to pay benefitslexpenses from the OPES Trusts.
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