callan ndt study 2016

CALLAN INSTITUTE

Study

2016 Nuclear Decommissioning Funding StudyNDT Fund Balances, Annual Contributions, and Decommissioning Cost Estimates as of December 31, 2015

2016 Nuclear Decommissioning Funding Study 1Knowledge. Experience. Integrity.

Table of Contents

Executive Summary 2

Methodology 4

Investor-Owned Utilities 5

Public Power Utilities 6

Fund Balances 7

Contributions 8

Cost Estimates 9

Funding Status 10

Pro Forma vs. Actual Contributions 12

Cost Comparisons 14

Escalation Rates 15

Asset Allocations 16

Investment Returns of Investor-Owned Utilities 17

Global Nuclear Power Generation 19

Endnotes 20

Certain information herein has been compiled by Callan and is based on information provided by a variety of sources believed to be reliable for which Callan has not necessarily verified the accuracy or completeness of or updated. This report is for informational purposes only and should not be construed as legal or tax advice on any matter. Any investment decision you make on the basis of this report is your sole responsibility. You should consult with legal and tax advisers before applying any of this information to your particular situation. Reference in this report to any product, service or entity should not be construed as a recom-mendation, approval, affiliation or endorsement of such product, service or entity by Callan. Past performance is no guarantee of future results. This report may consist of statements of opinion, which are made as of the date they are expressed and are not statements of fact. The Callan Institute (the “Institute”) is, and will be, the sole owner and copyright holder of all material prepared or developed by the Institute. No party has the right to reproduce, revise, resell, dissemi-nate externally, disseminate to subsidiaries or parents, or post on internal websites any part of any material prepared or developed by the Institute, without the Institute’s permission. Institute clients only have the right to utilize such material internally in their business.


Callan’s annual Nuclear Decommissioning Funding Study offers key insights into the status of nuclear decommissioning funding in the U.S. to make peer comparisons more accurate and rel-evant. The 2016 study covers 27 investor-owned and 27 public power utilities (excluding public power owners with small shares)1 with an ownership interest in the 99 operating nuclear reactors and 10 of the non-operating reactors in the U.S. The number of utilities with an ownership interest declined steadily in the early- to mid-2000s, due primarily to mergers/acquisitions and the sale of nuclear-generating facilities. However, in recent years the number of these utilities has remained fairly steady.

What Is Nuclear Decommissioning?After a nuclear power plant is closed, the facility must be decommissioned by safely removing it from service and reducing residual radioactivity to a level that permits release of the property and termination of the operating license. Decommissioning involves removing spent fuel from the reactor vessel, dismantling and disposing of radioactive components and materials such as the reactor and piping, and clean-ing up any radioactive or hazardous contamination that remains on site.

Decommissioning Funding and Reporting The U.S. Nuclear Regulatory Commission (NRC) oversees the decommissioning of nuclear facilities and requires owners to set aside funds for the work. Approximately 70% of licensees are authorized to accumulate decommissioning funds over the operating life of their plants. These owners—gener-ally traditional, rate-regulated utilities—gradually build up money for decommissioning over the plant’s operating life by collecting money from customers through rates which are then placed in a nuclear decommissioning trust (NDT). The remaining licensees (approximately 30%) must provide financial assurance through other methods, such as prepaid decommissioning funds and/or a surety method or guarantee.

Executive Summary

1 Public power owners excluded: Dalton Utilities (Edwin Hatch 1 & 2 and Vogtle 1 & 2), Hudson Light and Power Department (Seabrook 1), Seminole Electric Cooperative (Crystal River 3), Taunton Municipal Lighting Plant (Seabrook 1), and seven munici-palities in Florida (Crystal River 3).

5

3

2

4

4

11

2

1

6

1

2

4

3

1

1

2

5

29

7

2

1

4

4

3

2

11

42

99 Operating Nuclear Power Reactors in the U.S.

(Number of Reactors per State)

Source: Nuclear Energy Institute

West of the Mississippi East of the Mississippi

Investor-owned vs. Public Power

NDTFunds

CostEstimates

87%

85%

13%

15%

http://www.nei.org/Knowledge-Center/Nuclear-Statistics/US-Nuclear-Power-Plants/US-Nuclear-Operating-Plant-Basic-Information


Each year, owners must review the decommissioning cost requirements and the status of their decommissioning funding for each reactor or share of a reactor they own. The findings must be reported to the NRC every two years, or annually within five years of shutdown or once the plant ceases operation.

Labor, energy, and waste material transportation and disposal are the primary components of decommissioning costs. Costs can be based on either the NRC minimum cost formula or a site-specific cost estimate calculated by an engineer-ing firm—as long as that amount is greater than the NRC cost figure. Site-specific engineering studies provide the most reliable decommissioning cost estimates. These studies often include costs beyond the NRC’s scope of decommission-ing, such as spent fuel management and site restoration (also known as “green fielding”), which together can run into the hundreds of millions of dollars.

Executive Summary

Labor

Energy

Waste material transportation & disposal

Decommissioning Costs Include:

$60billion

in total NDT funds

1.5%

The gap between assets and liabilities widened in 2015 resulting in a decline in the funding level from 69% in 2014 to 67% in 2015

2.0%

Incr

ease

in

cos

ts

Decrease

in funds

Key Findings

$7million

In 2015 NDT contributions fell

Cost Estimates of Decommissioning(2008 v. 2015)

= $10 billion

2008: $55 billion 2015: $90 billion

See page 9 for details.

See page 8 for details.See page 7 for details.See pages 7, 9, and 11 for details.



Public Power Utilities

Lic Exp [Avg Yrs]

MW Nuclear

Capacitiy

Decommissioning Cost Estimate ($mm)

Fund Balance ($mm)

Pro Forma Fund Shortfall

($mm)

Annual Contribution ($mm)

Company Cost Est Amt/KWCost or

$902/KWCurrent Amount

Pro Forma Amount Shortfall/Avg Yrs

1 Allegheny Electric Cooperative 1 2042-2044 [27] 252 $139 $551 $227 $115 $113 $0 $42 Austin Energy (City of Austin, TX) 2, 3, 4 2027-2028 [12] 413 $359 $868 $372 $205 $167 $0 $143 Central Iowa Power Cooperative 2034 [18] 124 $200 $1,616 $200 $105 $95 $0 $54 Corn Belt Power Cooperative 3 2034 [18] 62 $76 $1,228 $76 $42 $34 $0 $25 CPS Energy (City of San Antonio, TX) 2 2027-2028 [12] 1,032 $897 $869 $931 $514 $417 $1 $34

6 Energy Northwest 4, 6 2043 [28] 1,132 $584 $516 $1,021 $260 $761 $1 $277 Florida Municipal Power Agency 3, 7 2043 [27] 87 $63 $720 $78 $69 $10 $0 $08 Kansas Electric Power Cooperative 8 2045 [29] 71 $46 $647 $64 $20 $44 $0 $29 Long Island Power Authority 9 2046 [31] 206 $177 $859 $186 $110 $75 $0 $2

10 Los Angeles Dept of Water and Power 10 2045-2047 [31] 224 $137 $613 $202 $131 $71 $0 $2

11 Massachusetts Muni Wholesale Elec Co 11 2030-2045 [19] 204 $127 $624 $184 $100 $84 $1 $412 Municipal Electric Authority of Georgia 2034-2049 [28] 834 $718 $861 $752 $414 $339 $0 $1213 Nebraska Public Power District 12 2034 [18] 766 $633 $827 $691 $567 $123 $0 $714 New York Power Authority 13 2015-2034 [8] 1,893 $1,169 $617 $1,707 $1,430 $277 $0 $3316 N Carolina Electric Membership Corp 4,10, 14 2043 [28] 694 $434 $625 $626 $191 $435 $3 $1617 N Carolina Muni Power Agency No 1 10 2043 [28] 863 $529 $613 $778 $316 $462 $2 $1718 Oglethorpe Power Corporation 2034-2049 [27] 1,218 $1,068 $877 $1,098 $427 $671 $5 $2519 Old Dominion Electric Cooperative 15 2038-2040 [23] 219 $122 $559 $197 $146 $52 $0 $220 Omaha Public Power District 2033 [18] 478 $884 $1,849 $884 $373 $511 $5 $29

21 Orlando Utilities Commission 2043 [27] 60 $53 $882 $54 $41 $13 $0 $022 Piedmont Municipal Power Agency 10 2043 [28] 288 $176 $612 $260 $65 $195 $1 $723 Riverside Public Utilities 8, 16 [0] 38 $79 $2,078 $79 $84 -$5 $2 N/A24 Salt River Project 8 2045-2047 [31] 688 $641 $931 $641 $337 $304 $0 $1025 South Carolina Public Service Authority 17 2042 [27] 323 $415 $1,285 $415 $210 $205 $2 $8

26 South Mississippi Electric Power Assoc 2024 [9] 119 $131 $1,101 $131 $57 $74 $3 $827 Southern Calif. Public Power Authority 10 2045-2047 [31] 233 $142 $611 $210 $173 $37 $0 $128 Tennessee Valley Authority 18 2033-2041 [21] 6,711 $3,542 $528 $6,052 $1,536 $4,516 $0 $212

Public Power Utilities Totals 19,232 $13,541.52 $704 $18,117 $8,038 $10,079 $27 $484

See Appendix page 18 for endnotes.



Lic Exp [Avg Yrs]

MW Nuclear

Capacitiy


Fund Balance ($mm)


($mm)













This Nuclear Decommissioning Funding Study covers two types of utilities: 1. Investor-owned utilities, which are publicly traded companies that provide for-profit electric service, and2. Public power utilities, which are operated by local governments to provide not-for-profit electric service.

We list these companies in alphabetical order in two separate tables (pages 5 and 6). For each table, the first column provides the range of the years of license expiration (Lic Exp) for each unit owned along with the average years to expiration in brackets.1 We collected the decommissioning cost estimates, NDT fund balances, and annual contribu-tions from sources including (but not limited to): company 10-K filings with the Securities and Exchange Commis-sion (SEC), company decommissioning report filings with the NRC in accordance with 10 CFR 50.75, and company annual reports. The NRC and Nuclear Energy Institute’s websites were also valuable resources in collecting and verifying information in this report.

Unless otherwise noted, cost estimates are in 2015 dollars and based on site-specific studies representing the total cost (license termination, spent fuel management, and site restoration) to decommission the facility. In order to make the data comparable, we have calculated a “pro forma” decommissioning cost estimate, which is the higher of either the company cost estimate of decommissioning or $902/kilowatt (KW). We arrived at $902/KW by taking the average cost per KW reported for all investor-owned utilities. Trust fund balances represent liquidation values and include any internal reserves dedicated to decommissioning unless otherwise noted. Contributions include those to both external trust funds and any internal reserves dedicated to decommissioning.

Pro forma fund shortfall is the difference between the “pro forma” cost estimate of decommissioning and the fund balance. Pro forma contribution is the pro forma fund shortfall divided by the average years until license expiration as represented in brackets under the license expiration column. The average years until license expiration weights each unit’s license by its percent of the total megawatts owned by that particular utility, and takes into account license extensions granted by the NRC as of December 31, 2015.

Methodology



Lic Exp [Avg Yrs]

MW Nuclear

Capacitiy


Fund Balance ($mm)


($mm)















Lic Exp [Avg Yrs]

MW Nuclear

Capacitiy


Fund Balance ($mm)


($mm)













1 Non-operating units are included in all figures except the range of license expiration years.


Investor-Owned Utilities

Lic Exp [Avg Yrs]

MW Nuclear Capacity


Fund Balance ($mm)


($mm)





1 Ameren Corporation 1, 2, 3 2044 [29] 1,190 $865 $727 $1,073 $556 $517 $7 $182 American Electric Power Company 2034-2037 [20] 2,069 $1,961 $948 $1,961 $1,984 -$23 $9 -$13 Constellation Energy Nuclear Group 2, 4 2029-2046 [20] 3,873 $3,677 $949 $3,677 $2,036 $1,641 $0 $804 Dominion Resources 2, 5, 6 2032-2045 [20] 6,575 $4,298 $654 $5,929 $4,183 $1,746 $2 $875 DTE Energy Company 1, 2, 3 2025 [9] 1,085 $1,700 $1,567 $1,700 $1,211 $489 $13 $53

6 Duke Energy Corporation 7 2030-2046 [20] 9,515 $8,130 $854 $8,580 $5,475 $3,105 $39 $1547 El Paso Electric Company 8 2045-2047 [31] 622 $381 $612 $561 $232 $329 $5 $118 Energy Future Holdings Corporation 2 2030-2033 [16] 2,400 $1,798 $749 $2,164 $918 $1,246 $17 $809 Entergy Corporation 9 2013-2038 [11] 8,132 $6,899 $848 $7,333 $4,620 $2,713 $39 $251

10 Exelon Corporation 2, 10 2022-2049 [18] 17,243 $13,100 $760 $15,549 $8,255 $7,294 $23 $401

11 FirstEnergy Corporation 11 2026-2047 [17] 4,726 $5,434 $1,150 $5,434 $2,272 $3,162 $15 $18412 Great Plains Energy 1 2045 [29] 552 $360 $651 $498 $191 $307 $3 $1013 Green Mountain Power Corporation 2, 6 2045 [30] 21 $12 $590 $19 $9 $10 $0 $014 MidAmerican Energy Company 2, 12 2032 [17] 455 $326 $716 $410 $429 -$19 $2 -$115 NextEra Energy 2, 13 2030-2043 [18] 6,031 $4,797 $795 $5,439 $5,039 $400 $0 $22

16 NRG Energy 2, 3, 14 2027-2028 [12] 1,136 $986 $868 $1,024 $561 $463 $1 $3817 Pacific Gas and Electric Company 15 2024-2025 [9] 2,363 $3,566 $1,509 $3,566 $2,503 $1,063 $96 $11818 Pinnacle West Capital Corporation 8 2045-2047 [31] 1,145 $701 $612 $1,033 $688 $345 $17 $1119 Public Service Company of New Mexico 2045-2047 [31] 401 $271 $676 $362 $246 $115 $5 $420 Public Service Enterprise Group 1, 2 2033-2046 [24] 3,635 $3,436 $945 $3,436 $1,754 $1,682 $0 $71

21 San Diego Gas and Electric Company 16 [0] 430 $917 $2,133 $917 $848 $69 $8 N/A22 SCANA Corporation 2, 17 2042 [27] 648 $831 $1,283 $831 $115 $716 $3 $2723 Southern California Edison 16 2045-2047 [8] 2,303 $3,978 $1,727 $3,978 $3,659 $319 $0 $3924 Southern Company 2034-2049 [25] 3,667 $3,148 $858 $3,307 $1,471 $1,836 $6 $7325 Talen Energy Corporation 2, 3, 18 2042-2044 [27] 2,268 $1,249 $551 $2,045 $951 $1,094 $0 $40

26 Westar Energy 1 2045 [29] 552 $360 $651 $498 $184 $314 $3 $1127 Xcel Energy 2 2030-2034 [17] 1,594 $3,139 $1,969 $3,139 $1,724 $1,415 $21 $83

Investor-Owned Utilities Totals 84,631 $76,318 $902 $84,464 $52,114 $32,350 $335 $1,865

See page 20 for endnotes.



Lic Exp [Avg Yrs]

MW Nuclear Capacity


Fund Balance ($mm)


($mm)








11 Massachusetts Muni Wholesale Elec Co 11 2030-2045 [19] 204 $127 $624 $184 $100 $84 $1 $412 Municipal Electric Authority of Georgia 2034-2049 [28] 834 $718 $861 $752 $414 $339 $0 $1213 Nebraska Public Power District 12 2034 [18] 766 $633 $827 $691 $567 $123 $0 $714 New York Power Authority 13 2015-2034 [8] 1,893 $1,169 $617 $1,707 $1,430 $277 $0 $3315 N Carolina Electric Membership Corp 4,10, 14 2043 [28] 694 $434 $625 $626 $191 $435 $3 $16

16 N Carolina Muni Power Agency No 1 10 2043 [28] 863 $529 $613 $778 $316 $462 $2 $1717 Oglethorpe Power Corporation 2034-2049 [27] 1,218 $1,068 $877 $1,098 $427 $671 $5 $2518 Old Dominion Electric Cooperative 15 2038-2040 [23] 219 $122 $559 $197 $146 $52 $0 $219 Omaha Public Power District 2033 [18] 478 $884 $1,849 $884 $373 $511 $5 $2920 Orlando Utilities Commission 2043 [27] 60 $53 $882 $54 $41 $13 $0 $0

21 Piedmont Municipal Power Agency 10 2043 [28] 288 $176 $612 $260 $65 $195 $1 $722 Riverside Public Utilities 8, 16 [0] 38 $79 $2,078 $79 $84 -$5 $2 N/A23 Salt River Project 8 2045-2047 [31] 688 $641 $931 $641 $337 $304 $0 $1024 South Carolina Public Service Authority 17 2042 [27] 323 $415 $1,285 $415 $210 $205 $2 $825 South Mississippi Electric Power Assoc 2024 [9] 119 $131 $1,101 $131 $57 $74 $3 $8

26 Southern Calif. Public Power Authority 10 2045-2047 [31] 233 $142 $611 $210 $173 $37 $0 $127 Tennessee Valley Authority 18 2033-2041 [21] 6,711 $3,542 $528 $6,052 $1,536 $4,516 $0 $212

Public Power Utilities Totals 19,232 $13,542 $704 $18,117 $8,038 $10,079 $27 $484

See page 21 for endnotes.


NDT fund balances have risen substantially since a sharp decline in 2008. The NDT funds covered in this study totaled over $60 billion in 2015. The $0.9 billion (1.5%) decrease from a year earlier can be attributed to a combination of essentially flat capital market per-formance in 2015, a greater use of liquidation asset values, and outflows to cover decommissioning costs for some non-operating units. Investor-owned funds have accounted for approximately 87% of total NDT fund balances over the past nine years, with public power funds accounting for the remaining 13%.

Fund Balances

NDT Fund Balances

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

$70,000

2008 201120102009 2014 20152007

Investor-Owned Public Power Total

2012

($ m

illio

ns)

2013

Investor-Owned ($m) 38,012 29,960 35,659 39,091 40,865 44,553 50,475 52,798 52,114Public Power ($m) 5,778 4,926 5,462 6,107 6,449 7,010 7,551 8,242 8,038

Total ($m) 43,790 34,886 41,121 45,198 47,314 51,563 58,025 61,040 60,152

Did You Know?

2015 U.S. Electricity Generation by Source

Source: U.S. Energy Information Administration

PetroleumLiquids

1%

OtherEnergy

1%

Other Renewables

Hydroelectric

Coal Natural Gas Nuclear

33% 33% 20%

7% 6%


After rising in 2014, total contributions fell almost $7 million in 2015 despite a $1.6 million increase in public power contributions. In 2015, investor-owned contributions were 75% of their 2007 level while public power contributions were just 25% of their 2007 level.

Contributions

Annual Contributions to NDT Funds

$0

$100

$200

$300

$400

$500

$600

2008 201120102009 2014 20152007


2012

($ m

illio

ns)

2013

Investor-Owned ($m) 449 461 407 429 424 388 315 344 335Public Power ($m) 109 101 46 57 20 18 18 25 27

Total ($m) 558 562 453 486 444 406 333 369 362

Did You Know?

The top five U.S. states in terms of number of operating nuclear power reactors:

1. Illinois (11)

2. Pennsylvania (9)

3. South Carolina (7)

4. New York (6)

5. Alabama and North Carolina (tie 5 each)


http://www.nei.org/Knowledge-Center/Nuclear-Statistics/US-Nuclear-Power-Plants/US-Nuclear-Operating-Plant-Basic-Information


Total decommissioning cost estimates have risen since a low of $55 billion in 2008. Decommission-ing cost estimates totaled almost $90 billion in 2015. The $1.8 billion (2%) increase from 2014 ($88 bil-lion) is largely due to the use of updated site-specific cost studies by several owners.

Similar to NDT fund balances, investor-owned costs have accounted for over four-fifths of total costs over the past nine years, with public power costs account-ing for less than one-fifth of the total cost.

Cost Estimates

Cost Estimates of Decommissioning in Current Dollars

$0

$20,000

$40,000

$60,000

$80,000

$100,000

2008 201120102009 2014 20152007


2012

($ m

illio

ns)

2013

Investor-Owned ($m) 49,170 45,142 50,831 57,657 59,346 64,028 66,558 74,442 76,318Public Power ($m) 9,484 9,959 10,620 11,695 11,163 12,146 12,831 13,647 13,542

Total ($m) 58,654 55,101 61,451 69,352 70,509 76,174 79,389 88,089 89,860

Did You Know?

Of the U.S. operating nuclear power plants:

Largest: Palo Verde in Arizona

Smallest: Fort Calhoun in Nebraska

Newest: Watts Bar in Tennessee

Oldest: Oyster Creek in New Jersey


http://www.nei.org/Knowledge-Center/Nuclear-Statistics/US-Nuclear-Power-Plants


Investor-owned assets have lagged behind costs by approximately $11–$24 billion over the past nine years. Public power assets have lagged behind costs by approximately $3–$6 billion over the same period.

The total deficit reached a nine-year high of almost $30 billion in 2015. The increase in the deficit is partly due to a greater percentage of utilities reporting liq-uidation fund values and updated site-specific esti-mates for several owners.

Funding Status

Decommissioning Funding Status (Assets Less Costs)

-$30,000

-$25,000

-$20,000

-$15,000

-$10,000

-$5,000

$0

2008 201120102009 2014 20152007


2012

($ m

illio

ns)

2013

Investor-Owned ($m) -11,158 -15,182 -15,172 -18,566 -18,481 -19,475 -16,083 -21,644 -24,204Public Power ($m) -3,706 -5,033 -5,158 -5,588 -4,714 -5,136 -5,281 -5,404 -5,503

Total ($m) -14,864 -20,215 -20,330 -24,154 -23,195 -24,611 -21,363 -27,048 -29,708


Assets as a percentage of costs averaged approxi-mately 71% for investor-owned utilities over the past nine years versus just 56% for public power utilities. Total funding stood at approximately 67% in 2015, a decline from the previous year (69%). The decline in the funding status is partly due to a greater percent-age of utilities reporting liquidation fund values and updated site-specific estimates for several owners.

Funding Status

Decommissioning Funding Status (Assets as Percentage of Costs)

40%

50%

60%

70%

80%

2008 201120102009 2014 20152007


2012 2013

Investor-Owned ($m) 77.3% 66.4% 70.2% 67.8% 68.9% 69.6% 75.8% 70.9% 68.3%Public Power ($m) 60.9% 49.5% 51.4% 52.2% 57.8% 57.7% 58.8% 60.4% 59.4%

Total ($m) 74.7% 63.3% 66.9% 65.2% 67.1% 67.7% 73.1% 69.3% 66.9%

Did You Know?

There are currently 99 nuclear power reac-tors operating in the U.S. in 30 states.

65 are pressurized water reactors

34 are boiling water reactors

4 reactors are currently under construction (Virgil C. Summer 2 & 3 and Vogtle 3 & 4)

Watts Bar 2 was issued an operating license by the NRC in October 2015 and is expected to begin commercial operation in the summer of 2016. This is the first nuclear power plant to come online since Watts Bar 1 began operation in 1996.


http://www.nei.org/Knowledge-Center/Nuclear-Statistics/US-Nuclear-Power-Plants


Actual investor-owned contributions outpaced the pro forma estimate in the late 1990s before fall-ing behind in 2000. In 2015, actual contributions were $1.5 billion lower than the pro forma estimate. Actual contributions were less than one-fifth of the pro forma estimate in 2015, the lowest percentage in the 18-year period.

Pro Forma vs. Actual Contributions: Investor-Owned Utilities


$0

$400

$800

$1,200

$1,600

$2,000

2009 2011 20151999

Pro Forma Actual

2013200720052001 2003

1,49

01,

490

424

892

1,16

0

1,61

5

429

889

1,22

5

1,55

1

407

875 1,

003

1,03

546

1

983

901

449

1,01

5 1,15

6

1,12

3

564

1,28

1

1,25

2

1,13

7

1,05

1

1,05

6

703

1,74

8 33

91,

865

335

1,43

038

8

($ m

illio

ns)

1,24

4

1,31

4 31

5

In order to make the data among companies more comparable, we have calculated a “pro forma” decommissioning cost estimate, which is the higher of either the company cost estimate of decommissioning or the product of the company KW times the average cost per KW reported for all investor-owned utilities. In 2015, this average cost was $902/KW. Pro forma contribution is the pro forma fund shortfall (the difference between the “pro forma” cost estimate of decommissioning and the fund balance) divided by the average years until license expi-ration. The average years until license expiration weights each unit’s license by its percent of the total megawatts owned by that particular utility and takes into account license extensions granted by the NRC as of the end of each year listed.


Actual public power contributions have lagged well behind the pro forma estimate from 1998 to 2015. While pro forma contributions grew from $339 mil-lion in 1998 to $484 million in 2015, actual contribu-tions fell from $145 million to just $27 million. Actual contributions as a percentage of the pro forma esti-mate were at a high of 43% in 1998, but have fallen to less than 6% in 2015.

Pro Forma vs. Actual Contributions: Public Power Utilities


$0

$100

$200

$300

$400

$500

$600

2009 2011 20151999

Pro Forma Actual

2013200720052001 2003

401

401

19

84

36940

2

57

95

406

382

46

96

386

383

101

111

32134

8

109

112

376

324

100

145

405

345

145

339

87

543

2548

427

426

18

($ m

illio

ns)

465

18

In order to make the data among companies more comparable, we have calculated a “pro forma” decommissioning cost estimate, which is the higher of either the company cost estimate of decommissioning or the product of the company KW times the average cost per KW reported for all investor-owned utilities. In 2015, this average cost was $902/KW. Pro forma contribution is the pro forma fund shortfall (the difference between the “pro forma” cost estimate of decommissioning and the fund balance) divided by the average years until license expi-ration. The average years until license expiration weights each unit’s license by its percent of the total megawatts owned by that particular utility and takes into account license extensions granted by the NRC as of the end of each year listed.

Did You Know?

Public vs. Investor-Owned Generation Capacity

Public power 19% Investor-owned 81%

Source: Data from tables on pages 5-6.


AllInvestor- Owned

Public Power

75th Percentile 195% 181% 211%

Median 153% 152% 155%

25th Percentile 137% 140% 136%

Average 166% 161% 176%

Last year we gathered both NRC and site-specific total cost estimates where possible in order to cap-ture the relative magnitude of the two figures.

Site-specific cost estimates total approximately $53.0 billion versus $34.5 billion under the NRC minimum formula in 2014, a difference of $18.5 billion. The median site-specific total cost estimate was just over 1.5 times the NRC minimum formula amount for all plants regardless of ownership. Assuming license ter-mination costs (the NRC portion of decommissioning) represent approximately 60–70% of total site-specific costs, the NRC formula amounts are roughly in line with the site-specific estimates for license termination. Taking the assumption one step further, if the license termination portions of the site-specific estimates are roughly in line with the NRC formula amounts, then spent fuel management and site restoration costs are what account for most—if not all—of the additional $18.5 billion in decommissioning costs.

The distributions are positively skewed, which results in average cost comparison figures that are approximately 10%–20% greater in absolute terms than the medians. The range between the 25th and 75th percentiles for public power cost comparisons is much greater than that of the investor-owned cost estimates, though this could be the result of a much smaller public power sample size.

Cost Comparisons

Utilities Plants* Reactors*

20

42

71

25

15

1635

58

96

Investor-OwnedPublic PowerTotal

Decommissioning Cost Comparisons (Site-Specific Total/NRC Minimum)

0%

100%

200%

300%

400%

Investor-Owned Public PowerTotal

Dataset Breakdown

*Not necessarily distinct or wholly-owned plants/reactors.

Notes

This page will be updated bien-

nially to coincide with the NRC’s

filing schedule.

Bars depict the full range of cost

comparisons (site-specific total/

NRC minimum) while the darker

shading represents the 25th to

75th percentiles. The percentages

to the left show site-specific cost

estimates as a percentage of the

NRC minimum formula amounts.

The data set includes 2014 cost

estimates for 58 plants—not

necessarily distinct or wholly-

owned—owned by 35 utilities.


This year we continued to gather escalation rates, which the utilities use to forecast future decommission-ing expenditures given current dollar cost estimates. The escalation rates shown to the right are a blend of escalation rates specific to the different cost categories such as labor, energy, and burial. The data set includes escalation rates for 58 plants—not necessarily distinct or wholly-owned—owned by 32 utilities.

The median escalation rate for all plants is 3.00% with an average of 3.25%. Public power plant esca-lation rates tend to be approximately 50–150 basis points above those of investor-owned plants. The median public power plant rate is 4.00% and average is 3.63%, contrasted with the median investor-owned plant escalation rate of 2.60% and average of 3.01%.

From an owner perspective, we see the same trend of greater escalation rates for public power. The median public power utility rate is 4.00% and the average is 3.64%, versus a median investor-owned utility escalation rate of 3.15% and average of 3.27%. The median escalation rate for all owners is 3.28% with an average of 3.46%.

Escalation Rates

Escalation Rates by Plant* Escalation Rates by Owner

AllInvestor- Owned

Public Power All

Investor- Owned

Public Power

75th Percentile 4.00% 3.43% 4.00% 4.00% 3.57% 4.00%

Median 3.00% 2.60% 4.00% 3.28% 3.15% 4.00%

25th Percentile 2.50% 2.50% 2.79% 2.51% 2.51% 2.72%

Average 3.25% 3.01% 3.63% 3.46% 3.27% 3.64%

Count 58 36 22 32 15 17

0%

1%

2%

3%

4%

5%

6%

Investor-Owned Public PowerTotal

0%

1%

2%

3%

4%

5%

6%

Decommissioning Escalation Rates

*Not necessarily distinct or wholly-owned plants.

Note: Bars depict the full range of cost comparisons (site-specific total/NRC minimum) while the darker shading represents the 25th to 75th percentiles.


We gathered NDT asset allocation information for all owners this year. Unfortunately, the public power dataset is too limited to be meaningful so only inves-tor-owned utility asset allocation data is displayed here. The dataset represents 25 of the 27 investor-owned utilities.

All 25 NDTs are invested in equity and fixed income securities with a median allocation of approximately 60% equity and 40% fixed income.

Three-fifths of the owners reported a cash equivalent allocation which tended to range in the low single digits.

Four of the utilities reported allocations to real estate, private equity, and/or hedge funds with almost a quarter indicating an “other” allocation. The “other” allocations could represent cash, alternatives, or other securities.

Asset Allocations

Investor-Owned Utilities’ Asset Allocations (as of 12/31/2015)

Equity Fixed Cash Alternatives Other75th Percentile 62% 43% 3% 20% 4%

Median 56% 40% 2% 9% 2%

25th Percentile 50% 34% 1% 2% 2%

Percent Invested 100% 100% 60% 16% 24%

Count 25 25 15 4 6

20%

60%

40%

80%

0%



We show the range of returns for 23 of the 27 investor-owned utilities for periods ended December 31, 2015. Investor-owned utilities with nuclear power reactors outperformed the S&P 500 Utilities Index over the past quarter, 1-, 3-, and 5-year periods, but under-performed the broad market S&P 500 Index. Over the past 10 years, investor-owned utilities outperformed both the S&P 500 Utilities and S&P 500 Indices.

Investment Returns of Investor-Owned Utilities

Last Quarter

Last Year

Last 3 Years

Last 5 Years

Last 10 Years

75th Percentile 6.0 0.7 14.7 15.0 10.0

Median 2.1 -2.4 12.9 12.1 7.8

25th Percentile -3.0 -13.2 7.9 6.3 4.1

S&P 500 7.0 1.4 15.1 12.6 7.3

S&P 500 Utilities 1.1 -4.8 11.6 11.0 7.4

Count 23 23 23 23 23

-80%

-40%

0%

40%

Investor-Owned Utilities’ Returns (Periods ended 12/31/2015)



This chart shows the 10-year return and standard deviation, ended Dec. 31, 2015, for the 23 investor-owned utilities along with the S&P 500 Utilities and S&P 500 Indices. A majority of investor-owned utili-ties had a more volatile (greater standard deviation) return pattern than both the S&P 500 Utilities and S&P 500 Indices over the past 10 years.

It is important to note that nuclear power generation accounts for varying degrees of the utilities’ overall businesses.

Investment Returns of Investor-Owned Utilities (Continued)

Annualized Return vs. Standard Deviation (10 years ended 12/31/2015)

10% 15% 20% 25% 30% 35%-10%

-5%

0%

5%

10%

15%

20%


Ann

ualiz

ed R

etur

n

S&P 500Utilities

S&P 500

Standard Deviation


#1 United States798.0 bn kWh19.5% total electricity99 operating units

#6 Canada95.6 bn kWh16.6% total electricity19 operating units

#3 Russia182.8 bn kWh18.6% total electricity35 operating units

#10 Spain54.8 bn kWh20.3% total electricity7 operating units

#5 South Korea157.2 bn kWh31.7% total electricity25 operating units

#4 China161.2 bn kWh3.0% total electricity33 operating units

#9 United Kingdom63.9 bn kWh18.9% total electricity15 operating units

#2 France419.0 bn kWh76.3% total electricity58 operating units

#8 Ukraine82.4 bn kWh56.5% total electricity15 operating units

#7 Germany86.8 bn kWh14.1% total electricity8 operating units

Global Nuclear Power Generation

Top 10 Nuclear Generating Countries in 2015

Top 10 Countries by Nuclear Power as a Percent of Total Electricity Generation

Share ofCountry Total ElectricityFrance 76.3%Ukraine 56.5%Slovakia 55.9%Hungary 52.7%Slovenia 38.0%Belgium 37.5%Armenia 34.5%Sweden 34.3%Finland 33.7%Switzerland 33.5%



Endnotes

Endnotes from page 5:1 Cost estimate in 2014 dollars.2 Fair market value of the fund balance.3 2014 contribution.4 Cost estimate in 2012 dollars and represents license termination costs only.5 Includes 641 MW Millstone Unit 1 and 566 MW Kewaunee which have been shut down permanently. Mill-

stone Unit 1 is assumed to be decommissioned upon the license expiration of Millstone Unit 2 in July 2035 while Kewaunee is transitioning to SAFSTOR.

6 Total cost less certain spent fuel costs expected to be recovered from the Department of Energy.7 Includes 860 MW Crystal River Unit 3, which has been shut down permanently and is transitioning to SAFS-

TOR. Cost estimate in 2013 and 2014 dollars.8 Cost estimate in 2013 dollars.9 Includes 620 MW Vermont Yankee, which has been shut down permanently and is in SAFSTOR. Excludes

Indian Point Unit 3 and James A. Fitzpatrick (trust funds retained by New York Power Authority). Combina-tion of site-specific total cost estimates and NRC minimums. Cost estimates for all but two units (2013 and 2014 dollars) are in 2015 dollars.

10 Includes 210 MW Dresden Unit 1 and 115 MW Peach Bottom Unit 1 which have been shut down perma-nently. Dresden Unit 1 is assumed to be decommissionined upon the license expiration of Dresden Unit 2 in December 2029 and Peach Bottom Unit 1 is assumed to be decommissioned upon the license expiration of Peach Bottom Unit 3 in July 2034. Combination of site-specific total cost estimates and NRC minimums in 2014 dollars.

11 Includes 786 MW Three Mile Island Unit 2, which has been shut down permanently and is assumed to be decommissioned upon the license expiration of Three Mile Island Unit 1 in April 2034. Three Mile Island Unit 1 is owned and operated by Exelon.

12 NRC mininum cost estimate.13 Combination of site-specific total cost estimates in 2010 dollars and NRC minimums in 2014 dollars.14 Cost estimate in 2012 dollars.15 Includes 63 MW Humboldt Bay Unit 3, which has been shut down permanently and is in decommissioning.16 Includes 1,070 MW San Onofre Unit 2 and 1,080 MW San Onofre Unit 3 which shut down permanently in

2013 and are decommissioning.17 Cost estimate in 2016 dollars.18 NRC mininum cost estimate in 2014 dollars.


Endnotes from page 6:1 NRC mininum cost estimate in 2014 dollars.2 Cost estimate in 2012 dollars.3 Fund balance as of September 30, 2015.4 2014 contribution.5 Cost estimate in 2008 dollars.6 Fund balance as of June 30, 2015.7 Cost estimate in 2010 dollars.8 Cost estimate in 2014 dollars.9 Cost estimate in 2012 dollars and represents license termination costs only.10 Cost estimate in 2013 dollars.11 Cost estimate in 2010 and 2015 dollars.12 NRC mininum cost estimate in 2012 dollars.13 Sold its interest in Indian Point Unit 3 and James A. Fitzpatrick to Entergy but retained the NDT funds until

license expiration.14 Fund balance as of December 31, 2014.15 Total cost less certain spent fuel costs expected to be recovered from the Department of Energy.16 Includes 1,070 MW San Onofre Unit 2 and 1,080 MW San Onofre Unit 3 which shut down permanently in

2013 and are decommissioning.17 Cost estimate in 2016 dollars.18 NRC mininum cost estimate.

Endnotes


Julia A. Moriarty, CFA, is a Senior Vice President and a consultant in the Capital Markets Research

group. She is responsible for assisting plan sponsor clients with their strategic planning, conducting

asset/liability studies, developing optimal investment manager structures, and providing custom re-

search on a variety of investment topics. Julia joined Callan in 1990 as an analyst in the Client Report

Services group, working on the production of comprehensive performance measurement reports and

the implementation and testing of new products. Prior to joining the Capital Markets Research group,

she was a Software Solutions Consultant in the Client Software Department. Julia is a shareholder

of the firm.

Julia earned a BS in Finance from California Polytechnic State University at San Luis Obispo and an

MBA in Finance from the University of California at Berkeley’s Haas School of Business. She earned

the right to use the Chartered Financial Analyst designation and is a member of the CFA Society of

San Francisco and CFA Institute.

About the Author

About Callan Callan was founded as an employee-owned investment consulting firm in 1973. Ever since, we have empowered institutional clients with creative, customized investment solutions that are uniquely backed by proprietary research, exclusive data, ongoing education and decision support. Today, Callan advises on $2 trillion in total assets, which makes us among the larg-est independently owned investment consulting firms in the U.S. We use a client-focused consulting model to serve public and private pension plan sponsors, endowments, foundations, operating funds, smaller investment consulting firms, invest-ment managers, and financial intermediaries. For more information, please visit www.callan.com.

About the Callan InstituteThe Callan Institute, established in 1980, is a source of continuing education for those in the institutional investment community. The Institute conducts conferences and workshops and provides published research, surveys, and newslet-ters. The Institute strives to present the most timely and relevant research and education available so our clients and our associates stay abreast of important trends in the investments industry.

For more information about this report, please contact: Your Callan consultant or Julia Moriarty at [email protected]

© 2015 Callan Associates Inc.

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