ML17095A918
| ML17095A918 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 03/30/2017 |
| From: | Stull A Wolf Creek |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| CO 17-0003 | |
| Download: ML17095A918 (377) | |
Text
{{#Wiki_filter:Annette F. Stull Vice President and Chief Administrative Officer March 30, 2017 co 17-0003 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555
Subject:
Docket No. 50-482: Wolf Creek Generating Station (WCGS) Financial Assurance Requirements for Decommissioning Nuclear Power Reactors 10 CFR 50.75(f)(1) To Whom It May Concern: Pursuant to 10 CFR 50. 75(f)(1 ), each power reactor licensee is required to report to the NRC the status of its decommissioning funding for each reactor or part of each reactor it owns on a calendar year basis, beginning March 31, 1999, and every two years thereafter. Wolf Creek Nuclear Operating Corporation (WCNOC) holds the operating license for Wolf Creek Generating Station (WCGS) which is jointly owned by Kansas Gas and Electric Company (KGE), a wholly owned subsidiary of Westar Energy, Inc.; Kansas City Power & Light Company (KCPL), a wholly owned subsidiary of Great Plains Energy Incorporated; and Kansas Electric Power Cooperative, Inc. (KEPCo). Accordingly, WCNOC provides the information for WCGS in accordance with the requirements of 10 CFR 50. 75(f)(1 ). This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4004, or Cynthia R. Hafenstine at (620) 364-4204. Sincerely, Annette F. Stull AFS/rlt P.O. Box 411 I Burlington, KS 66839 /Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET
.i*, i co 17-0003
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- I Enclosure I - Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status
.*, Report as of 3/31/17
,I11: Enclosure II - Wolf Creek Nuclear Operating Corporation Minimum Decommissioning Funds Estimate pursuant to 10 CFR 50. 75 (b) and (c)
Enclosure Ill - Wolf Creek Nuclear Operating Corporation Decommissioning Funds as of December 31, 201610 CFR 50.75 (b) and (c)
.I Enclosure IV - Kansas Gas & Electric Company (KGE) Wolf Creek Decommissioning Costs
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- 11 External Trust Fund
'1 11 Enclosure V - Kansas City Power & Light Company (KCPL) Wolf Creek Decommissioning
*' Cost Trust Analysis by Jurisdiction
- 11 Enclosure VI - Kansas Electric Power Cooperative, Inc. (KEPCo.) Decommissioning Fund
)i Statement 11 Enclosure VII - Non-Unanimous Stipulation and Agreement
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I, Enclosure VI 11 - State of Missouri Public Service Commission Order Approving Stipulation and I' Agreement Enclosure IX The State Corporation Commission of the State of Kansas Order Approving Unopposed Stipulation and Agreement Enclosure X The State Corporation Commission of the State of Kansas Order Approving Stipulation and Agreement Enclosure XI - Before the State Corporation Commission of the State of Kansas Direct Testimony Enclosure XII - Decommissioning Cost Analysis for the Wolf Creek Generating Station Enclosure XIII McDermott Will & Emery Memorandums cc: K. M. Kennedy (NRC), w/e
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"*1* B. K. Singal (NRC), w/e 11 N. H. Taylor (NRC), w/e Senior Resident Inspector (NRC), w/e
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Enclosure I to CO 17-0003 Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 3/31/17 (1 page}
Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 3/31/17 Owned by Kansas Gas & Electric (KGE), Kansas City Power and Light (KCPL) and Kansas Electric Power Cooperative (KEPCo) Westar Energy Great Plains Energy (KGE, 47% ownership) (KCPL, 47% ownership) KEPCo, 6% ownership TOTAL 10 CFR 50.75(f)(1) Requirement
- 1) NRC minimum decommissioning estimate pursuant to 10 CFR 50.75( b) and ( c) Dollars in Millions. $231.16 $231.16 $29.50 $491.82
- 2) The amount of accumulated funds at the end of the calendar year preceding the date of the report for items
$200.12 $222.89 $21.66 $444.68 included in 10 CFR 50.75 ( b) and ( c ). Dollars in Millions.
- 3) A schedule of the annual amounts to be collected; for items in 10 CFR 50.75 ( b) and ( c ). Dollars in Millions.
$164.02 $93.71 $17.24 $274.97 See Attached Schedules
- 4) The assumptions used regarding:
(a) Rates of escalation in decommissioning costs; Kansas 3.15% 3.15% 3.15% Missouri N/A 3.22% N/A (b) Rates of earning on decommissioning funds; Variable. See attached Variable. See attached Variable. See attached (c) Rates of other factors used in funding projections; and 0.00% 0.00% 0.00% (d) Real rate of return (2016 - 2025) rate reduces in subsequent years; Kansas 2.45% 3.14% 3.59% Missouri N/A 2.59% N/A
- 5) Any contracts upon which the licensee is relying pursuant to 10 CFR 50.75(e)(1)(v)? None None None
- 6) Any modifications to a licensee's current method of providing financial assurance occurring since the last None None None submitted report?
- 7) Any material changes to trust agreements?
None None None Other information; estimated corporate tax rate 20.00% 20.00% Non-taxable 1 to CO 17-0003 Wolf Creek Nuclear Operating Corporation Minimum Decommissioning Funds Estimate pursuant to 10 CFR 50.75 (b) and (c) (2 pages)
WOLF CREEK NUCLEAR OPERATING CORPORATION Minimum Decommissioning Funds Estimate pursuant to 10 CFR 50.75 (b) and (c) MINIMUM ESTIMATE Table (c)(1)-Jan86 dollars in Millions $ 105 [Wolf Creek is a PWR licensed for 3,565 MWt] Escalation Factor (see calculation below) 4.684 Minimum estimate - Dec16 dollars in Millions $ 491.82 Escalation per paragraph (c)(2) Escalation Factor= 0.65 Labor+ 0.13 Energy+ 0.22 Waste Burial Share 40 '16 Report Labor 65% 2.610 1.697 Energy 13% 1.870 0.243 _Waste Burial 22% 12.471 2.744 TOTAL ESCALATION FACTOR 4.684 NOTE: 4Q '16 factors per McDermott, Will & Emery memo dated March 13, 2017. Useable per RIS 14-12. SITE SPECIFIC STUDY (August 2014) Decommissioning Alternative DE CON Cost escallation rate 3.15% Obtained from KCC Docket 15-WCNE-093-GIE (2014$s) (2017 $s) (2045 $s) DEGON Period Millions Millions Millions % Total Radioactive Systems/Structures and License Termination $ 656.1 $ 711.6 $ 1,716.0 86% Preparation for Decommissioning/Spent Fuel Mgmt $ 46.0 $ 49.9 $ 120.3 6% Other Systems/Structures and Site Restoration $ 63.0 $ 68.3 $ 164.8 8% Subtotal - Not Applicable to NRC Minimum $ 109.0 $ 118.2 $ 285.1 14% TOTAL COST ESTIMATE $ 765.1 $ 829.9 $ 2,001.1 100%
WOLF CREEK NUCLEAR OPERATING CORPORATION Decommissioning Funding Status Report as of December 31, 2016 10 CFR 50.75 (b) and (c) (Dollars in Thousands) TOTAL KGE(47%) KCPL{47%) KEPCo(6%) Market Value of External Sinking $ 444,677.7 $ 200,120.0 $ .222,894.7 21,663.0 Fund as of 12/31/16 Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Study) 2017 9,623 5,806 3,317 500 2018 9,631 5,806 3.317 508 2019 9,638 5,806 3,317 515 2020 9,646 5,806 3,317 523 2021 9,654 5,806" 3,317 531 2022 9,662 5,806 3,317 539 2023 9,670 5,806 3,317 547 2024 9,678 5*,806 3,317 555 2025 9,686 5,806 3,317 563 2026 9,695 5,806 3,317 572' 2027 9,703 5,806 3,317 580 2028 9,712 5,806 3,317 589 2029 9,721 5,806 3,317 598 2030 9,730 5,806 3,317 607 2031 9,739 5,806 3,317 616 2032 9,748 5,806 3,317 625' 2033 9,758 5,806 3,317 635 2034 9,767 5,806 3,317 644 2035 9,777 5,806 3,317 654 2036 9,787 5,806 3,317 664 2037 9,797 5,806 3,317 674 2038 9,807 5,806 3,317 684 2039 9,817 5,806 3,317 694 2040 9,827 5,806 3,317 7041 2041 9,838 5,806 3,317 715 2042 9,849 5,806 3,317 726' 2043 9,859 5,806 3,317 736 2044 9,871 5,806 3,317 748 2045 2.281 1452 829 0 274,969 164,020 93,705 17,244 Assum1;1tions re: Rates/Factors s1;1ecific to Owner and Jurisdiction Cost Escalation Rate Obtained from KCC Docket 15-WCNE-093-GIE 3.15% 3.15% 3.15% N/A 3.22% NIA After Tax Earnings on Funds Kansas 2012- 2025 5.60% 2012 - 2025 6.29% 2012 - 2025 6.74% 2026 - 2035 4.83% 2026 - 2045 deer - .21 %/year 2026 - 2035 5.33% 2036 - 2044 3.83% 2045 - Decommissioning deer - .17%/year 2036 - 2044 4.15% 2045 - Decommissioning 2.31% 2045 - Decommissioning 1.93% Missouri 2012 - 2025 5.81% 2026 - 2045 leer - .155%/year 2045 - Decommissioning leer - .055%/year Power sale contracts None None None Modifications to method offinancial assurance None None None Material changes to trust agreements None None None
Enclosure Ill to CO 17-0003 Wolf Creek Nuclear Operating Corporation Decommissioning Funds as of December 31, 2016 10 CFR 50.75 (b) and (c) (3 pages)
WOLF CREEK NUCLEAR OPERATING CORPORATION Decommissioning Funding Status Report as of December 31, 2016 10 CFR 50.75 (b) and (c) (Dollars in Thousands) Kansas FERC TOTAL KGE Market Value of External Sinking $ 200,120.0 Fund as of 12/31/16 Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Study) 2017 5,772,700 33,321 5,806,021 5,806 2018 5,772,700 33,321 5,806,021 5,806 2019 5,772,700 33,321 5,806,021 5,806 2020 5,772,700 33,321 5,806,021 5,806 2021 5,772,700 33,321 5,806,021 5,806 2022 5,772,700 33,321 5,806,021 5,806 2023 5,772,700 33,321 5,806,021 5,806 2024 5,772,700 33,321 5,806,021 5,806 2025 5,772,700 33,321 5,806,021 5,806 2026 5,772,700 33,321 5,806,021 5,806 2027 5,772,700 33,321 5,806,021 5,806 2028 5,772,700 33,321 5,806,021 5,806 2029 5,772,700 33,321 5,806,021 5,806 2030 5,772,700 33,321 5,806,021 5,806 2031 5,772,700 33,321 5,806,021 5,806 2032 5,772,700 33,321 5,806,021 5,806 2033 5,772,700 33,321 5,806,021 5,806 2034 5,772,700 33,321 5,806,021 5,806 2035 5,772,700 33,321 5,806,021 5,806 2036 5,772,700 33,321 5,806,021 5,806 2037 5,772,700 33,321 5,806,021 5,806 2038 5,772,700 33,321 5,806,021 5,806 2039 5,772,700 33,321 5,806,021 5,806 2040 5,772,700 33,321 5,806,021 5,806 2041 5,772,700 33,321 5,806,021 5,806 2042 5,772,700 33,321 5,806,021 5,806 2043 5,772,700 33,321 5,806,021 5,806 2044 5,772,700 33,321 5,806,021 5,806 2045 1,443,175 8,330 1,451,505 1,452 164,020 Assumgtions re: Rates/Factors sgecific to Owner and Jurisdiction Cost Escalation Rate Obtained from KCC Docket 15-WCNE-093-GIE Kansas 3.15% Missouri N/A After Tax Earnings on Funds Kansas 2015 - 2025 5.60% 2026 - 2o35 :+. 4.83% 2036 - 2044 3.83% 2045 - Decommissioning 2.31% Missouri Power sale contracts None Modifications to method of financial assurance None Material changes to trust agreements None
WOLF CREEK NUCLEAR OPERATING CORPORATION Decommissioning Funding Status Report as of December 31, 2016 10 CFR 50.75 (b) and (c) (Dollars in Thousands) Kansas Missouri TOTAL KCPL Market Value of External Sinking $ 222,894.7 Fund as of 12/31/16 Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Study) 2017 2,036,230 1,281,264 3,317,494 3,317 2018 2,036,230 1,281,264 3,317,494 3,317 2019 2,036,230 1,281,264 3,317,494 3,317 2020 2,036,230 1,281,264 3,317,494 3,317 2021 2,036,230 1,281,264 3,317,494 3,317 2022 2,036,230 1,281,264 3,317,494 3,317 2023 2,036,230 1,281,264 3,317,494 3,317 2024 2,036,230 1,281,264 3,317,494 3,317 2025 2,036,230 1,281,264 3,317,494 3,317 2026 2,036,230 1,281,264 3,317,494 3,317 2027 2,036,230 1,281,264 3,317,494 3,317 2028 2,036,230 1,281,264 3,317,494 3,317 2029 2,036,230 1,281,264 3,317,494 3,317 2030 2,036,230 1,281,264 3,317,494 3,317 2031 2,036,230 1,281,264 3,317,494 3,317 2032 2,036,230 1,281,264 3,317,494 3,317 2033 2,036,230 1,281,264 3,317,494 3,317 2034 2,036,230 1,281,264 3,317,494 3,317 2035 2,036,230 1,281,264 3,317,494 3,317 2036 2,036,230 1,281,264 3,317,494 3,317 2037 2,036,230 1,281,264 3,317,494 3,317 2038 2,036,230 1,281,264 3,317,494 3,317 2039 2,036,230 1,281,264 3,317,494 3,317 2040 2,036,230 1,281,264 3,317,494 3,317 2041 2,036,230 1,281,264 3,317,494 3,317 2042 2,036,230 1,281,264 3,317,494 3,317 2043 2,036,230 1,281,264 3,317,494 3,317 2044 2,036,230 1,281,264 3,317,494 3,317 2045 509,058 320,316 829,374 829 93,705 Assum[1tions re: Rates/Factors S[1ecific to Owner and Jurisdiction Cost Escalation Rate Obtained from KCC Docket 15-WCNE-093-GIE Kansas 3.15% Obtained from MPSC Docket E0-2015-0056 Missouri 3.22% After Tax Earnings on Funds Kansas 2015 - 2025 6.29% 2026 - 2045 deer - .21 %/year 2045 - Decommissioning deer - .17%/year Missouri 2015 - 2025 5.81% 2026- 2045 deer - .155%/year 2045 - Decommissioning deer - .055%/year Power sale contracts None Modifications to method of financial assurance None Material changes to trust agreements None
WOLF CREEK NUCLEAR OPERATING CORPORATION Decommissioning Funding Status Report as of December 31, 2016 10 CFR 50.75 (b} and (c} (Dollars in Thousands} KEPCo Market Value of External Sinking 21,663.0 Fund as of 12/31/16 Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Stud 2017 500 2018 508 2019 515 2020 523 2021 531 2022 539 2023 547 2024 555 2025 563 2026 572 2027 580 2028 589 2029 598 2030 607 2031 616 2032 625 2033 635 2034 644 2035 654 2036 664 2037 674 2038 684 2039 694 2040 704 2041 715 2042 726 2043 736 2044 748 2045 0 17,244 Assumptions re: Rates/Factors specific to Owner and Jurisdiction Cost Escalation Rate Obtained from KCC Docket 15-WCNE~093-GIE Kansas 3.15% Missouri N/A After Tax Earnings on Funds Kansas 2015 - 2025 6.74% 2026- 2035 5.33% 2036- 2043 4.15% 2044 - Decommissioning 1.93% Missouri Power sale contracts None Modifications to method of financial assurance None Material changes to trust agreements None
Enclosure IV to CO 17-0003 Kansas Gas & Electric Company (KGE) Wolf Creek Decommissioning Costs External Trust Fund (3 pages)
Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 12/31 /16 Line# 1 Amounts to be collected in KGE rates 1 : 2 2017 5, 772, 700 3 2018 5,772,700 4 2019 5, 772, 700 5 2020 5, 772, 700 6 2021 5,772,700 7 2022 5, 772, 700 8 2023 5, 772, 700 9 2024 5, 772, 700 10 2025 5, 772, 700 11 2026 5, 772, 700 12 2027 5, 772, 700 13 2028 5, 772, 700 14* 2029 5, 772, 700 15 2030 5, 772, 700 16 2031 5, 772, 700 17 2032 5, 77_2, 700 18 2033 5, 772, 700 19 2034 5, 772, 700 20 2035 5, 772, 700 21 2036 5, 772, 700 22 2037 5,772,700 23 2038 5, 772, 700 24 2039 5, 772, 700 25 2040 5,772,700 26 2041 5, 772, 700 27 2042 5, 772, 700 28 2043 5, 772, 700 29 2044 5, 772, 700 30 2045 1,443, 175 31 The amounts that should be collected are based on the funding schedule 32 approved by the KCC in Docket No.15-WSEE-115-RTS.
Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 12/31/16 Line# KANSAS GAS & ELECTRIC CO. 1 WOLF CREEK DECOMMISSIONING COSTS 2 EXTERNAL TRUST FUND 3 INVESTMENT ASSUMPTIONS 4 5 FOR THE YEARS 2012 THROUGH 2025 6 EXPECTED WEIGHTED AFTER 7 INVESTMENT MIX RETURNS RATIO RETURN TAX 8 9 Large Cap 7.60% 30% 2.28% 1.82% 10 Small Cap 8.81% 8% 0.70% 0.56% 11 International Equities 8.14% 16% 1.30% 1.04% 12 Core Fixed Income 4.95% 21% 1.04% 0.83% 13 High Yield Bonds 6.40% 20% 1.28% 1.02% 14 Real Estate 8.17% 5% 0.41% 0.33% 15 Cash and equivalents 2.00% 0% 0.00% 0.00% 16 100% 7.01% 5.60% 17 18 FOR THE YEARS 2026 THROUGH 2035 19 EXPECTED WEIGHTED AFTER 20 INVESTMENT MIX RETURNS RATIO RETURN TAX 21 22 Large Cap 7.60% 20% 1.52% 1.22% 23 Small Cap 8.81% 5% 0.44% 0.35% 24 International Equities 8.14% 12% 0.98% 0.78% 25 Core Fixed Income 4.95% 44% 2.18% 1.74% 26 High Yield Bonds* 6.40% 8% 0.51% 0.41% 27 Real Estate 8.17% 3% 0.25% 0.20% 28 Cash and equivalents 2.00% 8% 0.16% 0.13% 29 100% 6.04% 4.83% 30-31 FOR THE YEARS 2036 THROUGH 2044 32 EXPECTED WEIGHTED AFTER 33 INVESTMENT MIX RETURNS RATIO RETURN TAX 34 35 Large Cap 7.60% 10% 0.76% 0.61% 36 Small Cap 8.81% 2% 0.18% 0.14% 37 International Equities 8.14% 3% 0.24% 0.19% 38 Core Fixed Income 4.95% 65% 3.22% 2.58% 39 High Yield Bonds 6.40% 0% 0.00% 0.00% 40 Real Estate 8.17% 0% 0.00% 0.00% 41 Cash and equivalents 2.00% 20% 0.39% 0.31% 42 100% 4.79% 3.83% 43 44 FOR THE YEARS 2045 THROUGH COMPLETION OF DECOMMISSIONING 45 EXPECTED WEIGHTED AFTER 46 INVESTMENT MIX RETURNS RATIO RETURN TAX 47 48 Large Cap 7.60% 0% 0.00% 0.00%
.49 Small Cap 8.81% 0% 0.00% 0.00%
50 International Equities 8.14% 0% 0.00% 0.00% 51 Core Fixed Income 4.95% 30% 1.49% 1.19% 52 High Yield Bonds 6.40% 0% 0.00% 0.00% 53 Re?I Estate 8.17% 0% 0.00% 0.00% 54 Cash and equivalents 2.00% 70% 1.40% 1.12% 55 100% 2.89% 2.31% 56 57 Federal tax rate is 20%
Account Title KANSAS GAS & ELECTRIC WOLF CREEK UMB Coiporate Tmst Serrices P.O. Box419692 Kansas Oty, MO 64141-7014 GENERATING STATION DECOM TRUST Composite Statement Account Number 116889 Statement Period 12/01/2016 -12f.i1/2016 Administrator: Anthony Hawkins 816.860.3014 Anthony.Hawkins@umb.com KANSAS GAS AND ELECTRIC COMPANY ATTN: SUSAN NORTH Associate Administrator: Faith Johnson
%WESTAR ENERGY FAITH .JOH NSON@UMB.COM P 0 BOX 889 Senior Officer: Douglas Hare TOPEKA KS US 66601-0889 816.860.3006 Douglas.Hare@umb.com Investment Summa:ry
. CostBas!s Market Valug Equity Securities Equity Funds Total Equity Securities 108,238,694.72 108,238,694.72 120,477,450.58 120,477,450.58 ITotal Invested Value $200,121,689.171 Fixed Income Securities Fixed Income Funds 46,309,236.21 45,610,762.80 I 60.20% Equity Securities Total Fixed Income Securities 46,309,236.21 45,610,762.80 lliiJ 22.79% Fixed Income Securities Cash & Equivalents Money Market Funds CJ 0. 04% Cash & Equivalents 73,656.06 73,656.06 Total Cash & Equivalents 73,656.06 73,656.06 §§ 16.97% Miscellaneous Miscellaneous Limited Partnership 29,523,367.46 33,959,819.73 Total Miscellaneous 29,523,367 .46 33,959,819.73 Total Assets 184,144,954.45 200, 121,689.17 Account Total 184,144,954.45 200, 121,689.17
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Please review this statement carefully and nolify us in writing within 30 days if you . have any questions or concerns about the information it contains. Unless we receive written notice within 30 days, we will assume that you have approved the statement UM8 .*1tU700., 19250l6004.17H7.17tl7.EG 1UMBP1.CUSTUMBSTMTOOOCOOOOU1047UMBSTMT115119....CSETTRANS
Enclosure V to CO 17-0003 Kansas City Power & Light Company (KCPL) Wolf Creek Decommissioning Cost Trust Analysis by Jurisdiction (3 pages)
2016 End of Year Funding Analysis KANSAS CITY POWER & LIGHT COMPANY WOLF CREEK DECOMMlsSloNING lRUST ANALYSIS KANSAS JURISDICTION
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BNY MELLON TRDB58 B58GPLNOOOOO ANNUAL FINAL 234221 2016-12-31 CYCLE A 23:42:20 RUN DATE: 02-FEB-17 INVESTMENT DETAIL PAGE: 1 B58 GPLNOOO 31 DECEMBER 2016 M1101 KANSAS CITY P&L COMBINED PLAN KANSAS CITY P&L COMBINED PLAN SHARES/ UNREALIZED PAR VALUE SECURITY DESCRIPTION GAIN/LOSS INVESTMENTS UNIT OF PARTICIPATION KANSAS CITY POWER & LIGHT 49,047,047.1170 KCPL WOLF CREEK KAN 63,471,821.12 1.7651 86,574,365.23 23, 102,544.11 77 ,229,656 .0420 KCP&L WOLF CREEK MO 97 045 492.47 1.7651 136,320,305.54 39 274 813.07 126,276, 703 .1590 160,517,313.59 222,894,670.77 62,377,357.18 TOTAL INVESTMENTS UNIT OF PARTICIPATION 160,517,313.59 222,894,670.77 62,377,357.18 TOTAL INVESTMENT 160,517,313.59 222,894,670.77 62,377,357.18
Enclosure VI to CO 17-0003 Kansas Electric Power Cooperative, Inc. (KEPCo.) Decommissioning Fund Statement (2 pages)
Year-End 2016 Mutual Fund Statement INVEST WITH CONFIDENCE Investor Number 220110870 If you have questions, please visit troweprice.com or call T. Rowe Price Mutual Funds at 1-800-225-5132. 1112143 02 MB 0.416 -AUTO T6 0 2563 66604-087777 C01-M3 °P12155 ll1lll 11ll' 1'*'I' "ll'mll II lll1l Ill 111*' 1ll1l 1111l I 11ll1I111ll' Commerce Bank & Trust Tr Kepco- Does your Household Qualify? Wolf Cr Decom Tr U/A Dtd 12/26/89 With our Household Recognition program, your Kansas Electric Power Coop Inc combined household assets may qualify you for Attn Coleen Wells complimentary benefits and services, including special P 0 Box 4877 discounts we offer within Select Client Services. Learn Topeka KS 66604-0877 more at www.troweprice.com/householdrecogn ition.
*1 Portfolio Value: $21,662,906.651 . Activity Summary . :Asset Allocation. .
1 This Month Year*to*Date Beginning Value $21,376,587.41 $19,996, 196.34 Taxable Money Mork*\ Additions 223,180.00 3,278,831.39 Deductions 120,743.00 Domestic Tmcable Bond 2,865,585.31
' *¥**0** -**' "'
Income 376,150.48 572,589.74 omesticStock Market Fluctuation2 -192,268.24 680,874.49 Ending Value $21,662,906.65 $21,662,906.65 Net Change $286,319.24 $1,666,710.31
. ~-**
61.8% Stock Funds $13,378,384.82
~ lncon:e Summary .* . . . llJ 55.0% Domestic 11,909,615.48 This Month Year-to-Date 1 6.8% International/Global 1,468,769.34 Taxable $376,150.48 $572,589.74 35.4% Bond Funds $7,670,901.06 1 Year*to*date income may include closed accounts no longer shown on this 35.4% Domestic Taxable 7,670,901.06 statement.
2 "Market Fluctuation* reflects any increase or decrease in fund share prices since 2.8% Money Market Funds $613 620.77 your last statement. It does not reflect a fund's payment of dividends and interest or any reinvestment of dividends and interest into your account. If all or your k:l 2.8% Taxable 613,620.77 holdings are in retail or government money market funds, generally there should be no change in account value or principal due to market fluctuation. For institutional Investors, if all of your holdings are in an institutional money market fund, your account value may change because an institutional money market fund's share price will fluctuate. IMMl*iifli{i-11/30/16 12/31/16 Change %of Nonretirement Value Value in Value Assets T. Rowe Price Mutual Funds Equity Index 500 - I Cl $2,269,908.15 $2,314,755.97 $44,847.82 10.7% f. Growth Stock - I Cl 3,136,336.18 3,147,694.33 11,358.15 14.5 International Growth and Income - I Cl 449,299.28 459,756.21 10,456.93 2.1
Attachment A KANSAS ELECTRIC POWER COOPERATIVE, INC. Estimate for Decommissioning Fund Contributions
* *. ~' ES,*~c\latkm **t. ~$i¥r,.~ s::f::,f?(9i!Reituq@
"' KGC sti *u1ated an~1Fixea Arfioiiiffs .
Total Cost DECON Method in 2014 $s $765,060,000 Estimated KEPCo Cost in 2014 $s $45,903,600 Forecasted Rate of Inflation 3.15% Remaining Years in Service 30 Total KEPCo Cost of Decommissioning in 2045 $s $128,057,592 Market Value of Portfolio @12/31/14 $19,378,279 Remaining $s To Be Collected $108,679,313
- REPcoVanab1es Forecasted Return on Portfolio Escalation Rate for Contributions 1.50%
Amount of Initial Payment $485,422 Amount of Excess/Shortfall 0 Total Beginning Annual Annual End of Year Balance KEPCo's Rate of Wolf Creek Year Year Balance Contribution Earnings Less Fees Decom Cost Return De com 2014 19,378,279 2015 19,378,279 485,422 1,306,096 21,094,473 6.74% 2016 21,094,473 492,704 1,421,768 22,927,614 6.74% 2017 22,927,614 500,094 1,545,321 24,885,282 6.74% 2018 24,885,282 507,596 1,677,268 26,975,548 6.74% 2019 26,975,548 515,210 1,818,152 29,206,995 6.74% 2020 29,206,995 522,938 1,968,551 31,588,759 6.74% 2021 31,588,759 530,782 2,129,082 34,130,563 6.74% 2022 34,130,563 538,743 2,300;400 36,842,749 6.74% 2023 36,842,749 546,825 2,483,201 39,736,325 6.74% 2024 39,736,325 555,027 2,678,228 42,823,004 6.74% 2025 42,823,004 563,352 2,886,270 46,115,246 6.74% 2026 46,115,246 571,803 2,457,943 48,976,088 5.33% 2027 48,976,088 580,380 2,610,425 51,987,977 5.33% 2028 51,987,977 589,085 2,770,959 55,158,563 5.33% 2029 55,158,563 597,922 2,939,951 58,495,881 5.33% 2030 58,495,881 606,891 3, 117,830 62,008,367 5.33% 2031 62,008,367 615,994 3,305,046 65,704,877 5.33% 2032 65,704,877 625,234 3,502,070 69,594,714 5.33% 2033 69,594,714 634,612 3,709,398 73,687,643 5.33% 2034 73,687,643 644,131 3,927,551 77,993,919 5.33% 2035 77,993,919 653,793 4,157,076 82,524,310 5.33% 2036 82,524,310 663,600 3,424,759 86,316,334 4.15% 2037 86,316,334 673,554 3,582,128 90,262,409 4.15% 2038 90,262,409 683,658 3,745,890 94,368,538 4.15% 2039 94,368,538 693,913 3,916,294 98,640,955 4.15% 2040 98,640,955 704,321 4,093,600 103,086,133 4.15% 2041 103,086,133 714,886 4,278,075 107,710,792 4.15% 2042 107,710,792 725,609 4,469,998 112,521,911 4.15% 2043 112,521,911 736,493 4,669,659 117,526,737 4.15% 2044 117,526,737 747,541 2,268,266 120,123,701 1.93% 2045 120,123,701 -9,796,865 2,318,387 112,217,290 9,796,865 1.93% 163,281,079 2046 112,217,290 -21,751,954 2,165,794 92,230,869 21,751,954 1.93% 362,532,571 2047 92,230,869 -26, 718,282 1,780,056 66,962,335 26,718,282 1.93% 445,304,696 2048 66,962,335 -19,966,490 1,292,373 48,046,350 19,966,490 1.93% 332,774,837 2049 48,046,350 -16,245,114 927,295 32,552,869 16,245,114 1.93% 270,751,894 2050 32,552,869 -14,564,587 628,270 18,495, 117 14,564,587 1.93% 242, 743,124 2051 18,495,117 -7,475,494 356,956 11,304,345 7,475,494 1.93% 124,591,569 2052 11,304,345 -6,991,176 218,174 4,484,278 6,991,176 1.93% 116,519,593 2053 4,484,278 -4,547,630 86,547 0 4,547,630 1.93% 75,793,831 128,057,592 2, 134,293, 195 2014decommstudy kcc.xls 3/28/20178:38 AM
Enclosure VI I to CO 17-0003 Non-Unanimous Stipulation and Agreement (14 pages)
BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI In the Matter of the Application of Kansas City ) Power & Light Company for Approval of the ) File No. E0-2015-0056 Accrual and Funding of Wolf Creek Generating ) Station Decommissioning Costs at Current Levels ) NON-UNANIMOUS STIPULATION AND AGREEMENT Kansas City Power & Light Company ("KCP&L") and the Staff of the Missouri Public Service Commission ("Staff") (collectively, the "Signatories," and individually "Signatory") hereby submit this Non-Unanimous Stipulation and Agreement ("Agreement") to the Missouri Public Service Commission ("Commission") in resolution of Case No. E0-2012-0068. The Office of the Public Counsel ("Public Counsel") has advised the Signatories that it will not oppose this Agreement. INTRODUCTION The Legislature provided, in Section 393.292 RS Mo 2000, 1 that the Commission may authorize changes to the rates and charges of an electrical corporation as a result of a change in the level or annual accrual of funding necessary for its nuclear power plant decommissioning trust fund. This statute creates a narrow exception to the general requirement that the Commission must consider "all relevant factors," prior to changing any rate charged by a utility under its jurisdiction. See State ex. rel. Utility
- Consumers Council of Missouri. Inc. v. Public Serv. Comm'n., 585 S.W.2d41 (Mo. bane 1979). Under Section 393.292, the Commission may limit its review in nuclear decommissioning trust fund cases to only those factors relevant to the funding level or
.1 All statutory references are to Revised StatUtes of Missouri 2000, unless otherwise noted. Section 393.292 was enacted by the Missouri Legislature in Laws 1989 and has not been amended.
accrual rate of the trust fund when deciding matters related to the rates 'and crarges associated with that fund. Further, Section 393.292 gives the Commission authority to adopt rules and regulations governing the procedures associated with these tariff changes as well as to ensure that the amounts contained in the trust funds will be neither "greater nor lesser than the amounts necessary to carry out the purposes of the trust." In Case No. EX-90-110, the Commission adopted the original decommissioning rule, 4 CSR 240-20.070. Rule 4 CSR 240-3.185(3) states, in part: "On or before September 1, 1990 and every three (3) years after that, utilities with decommissioning trust funds shall perform and file with the commission cost studies detailing the utilities' latest cost estimates for decommissioning their nuclear generating unit(s) along with the funding levels necessary to defray these decommissioning costs." KCP&L established an external nuclear decommissioning trust fund 2 as a result of its ownership interest in the Wolf Creek Generating Station ("Wolf Creek") and the Commission's Report and Order in the rate case authorizing KCP&L to commence recovery of the costs of Wolf Creek. Kansas City Power & Light Co., Case Nos. E0 185 and E0-85-224, 28 Mo.P.S.C. (N.S.) 228 (1986). KCP&L owns 47% of Wolf Creek and approximately 56% of KCP&L's 47% ownership. share is currently allocated to KCP&L's Missouri retail operations. 2 If decommissioning financial assurance is provided by an external sinking fund, 10 CFR 50.75(e)(l)(ii) requires that "the total amount of funds would be sufficient to pay decommissioning costs at the time termination of operation is expected." The operating license for Wolf Creek was initially for 40-years, but the Nuclear Regulatory Commission ("NRC) subsequently extended Wolf Creek's operating license 20-years. Because KCP&L does not contemplate shutting down Wolf Creek prior to the end of its operating license iife, the shutdown date used in the 2011 and 2014 Studies is 2045, the year in which Wolf Creek's operating license now expires. 2
On August 30, 2005, KCP&L filed an Application (Case No. E0-2006-0094) with the Commission for approval of its then-current decommissioning cost estimate and continuation of the then-current authorized funding level for its nuclear decommissioning trust fund for Wolf Creek. A Unanimous Stipulation and Agreement, settling all issues pertaining to Case No. E0-2006-0094 was filed on December 20, 2005. Among other things, said Unanimous Stipulation and Agreement maintained the annual decommissioning expense accrual and trust fund payment at $2,303,856 (Missouri jurisdictional amount). The parties to that agreement further agreed that KCP&L's authorized annual funding level would be addressed in the Company's Rate Filing #1, as contemplated pursuant to the terms of the Stipulation and Agreement approved by the Commission in Case No. E0-2005-0329 ("Regulatory Plan Agreement"). In Rate Filing #1 (Case No. ER-2006-0314), the Commission reduced KCP&L's authorized annual decommissioning expense accrual and trust fund payment to $1,281,264 (Missouri jurisdictional amount). That reduction was primarily caused by recognizing the 20-year life extension of Wolf Creek. On August 29, 2008, KCP&L filed an Application (Case No. E0-2009-0072) with the Commission for approval of its then-current decommissioning cost estimate and continuation of the then-current authorized funding level for its nuclear decommissioning trust fund for Wolf Creek. A Unanimous Stipulation and Agreement, settling all issues pertaining to Case No. E0-2009-0072 was filed on April 7, 2009. Among other things, said Unanimous Stipulation and Agreement maintained the annual decommissioning expense accrual and trust fund payment at $1,281,264 (Missouri jurisdictional amount), with the understanding that any proposed change in the annual Wolf Creek 3
decommissioning cost accrual would be addressed in the context of the then upcoming rate case (now known as File No. ER-2010-0355). KCP&L filed to generally increase its rates in File No. ER-2010-0355. As part of the overall rate increase request, KCP&L proposed to decrease the Missouri jurisdictional annual Wolf Creek decommissioning expense accrual and trust fund payment to $1,158,417 from $1,281,264. In Staff's Cost of Service Report in File No. ER-2010-0355, Staff recommended no change in the decommissioning expense accrual and trust fund payment because Great Plains Energy, Inc. had recently reduced its return expectations for its pension plan assets. Ultimately the annual contribution amount remained at $1,281,264 (Missouri jurisdictional amount) at the conclusion of the rate case. On August 31, 2011, KCP&L filed in File No. E0-2012-0068 an Application for Approval of the Accrual and F.unding of Wolf Creek Decommissioning Costs at Current Levels. Attached to KCP&L's Application was the required cost study detailing the latest estimate for the cost to decommission Wolf Creek. For the purposes of the 2011 Study, the final shutdown date of Wolf Creek was projected to occur in 2045. The calculations set forth in the 2011 Study were performed in a manner consistent with previous filings. KCP&L's 2011 analysis confirmed the adequacy of the annual funding level of $1,281,264 (Missouri jurisdictional amount), given the 2011 Study's then current prediction of decommissioning costs of $630.135 million for the DEGON decommissioning option under what KCP&L believed were a reasonable set of economic, financial, and investment assumptions. Consequently, KCP&L did not seek any changes to its funding level. KCP&L and the Staff entered into a Nonunanimous . 4
Stipulation And Agreement, which Public Counsel did not oppose. As part of the Nonunanimous Stipulation And Agreement in File No. E0-2012-0068, KCP&L and the Staff agreed as follows:
- 5. The Parties agree that it is reasonable to use capital market return expectation information provided by Great Plains Energy's pension plan consultant for purposes of developing expected portfolio returns for KCP&L's nuclear decommissioning trust fund. The Parties agree that any proposed changes to the annual contribution to KCP&L's nuclear decommissioning trust fund shall be based on capital market return expectation information provided by Great Plains Energy's pension plan consultant, unless the Parties agree to use a different source and/or methodology for capital market return expectations or the Commission finds in a contested case that different source and/or methodology for capital market return expectation are more appropriate.
The Commission on May 1, 2012 issued an Order Approving Stipulation And Agreement and directing that the signatories comply with the terms of the stipulation and agreement. THE2014COSTSTUDY Pursuant to 4 CSR 240-3.185(3), on August 29, 2014 KCP&L filed its Application for Approval of the Accrual and Funding of Wolf Creek Generating Station Decommissioning Costs at Current Levels ("Application"). KCP&L filed as Schedule A the Wolf Creek Wolf Creek Generating Station Decommissioning Cost Estimate Update for September 1, 2014 ("2014 Study"). The 2014 Study, with the date August 2014 on its cover, was prepared for the Wolf Creek Nuclear Operating Corporation ("WCNOC") by TLG Services, Inc. ("TLG"), a consulting engineering firm based in Bridgewater, Connecticut. 3 The TLG analysis relies upon site-specific, technical information from a 3 Since 1982, TLG has provided engineering and field services for contaminated facilities including estimates of decommissioning costs for nuclear generating units. TLG also prepared the decommissioning cost estimate for Wolf Creek that was filed with and approved by the Commission in previous KCP&L and Union Electric Company (Footnote continued on the next page.) 5
TLG evaluation prepared in 2011, updated to reflect current assumptions pertaining to the disposition of the nuclear station and relevant industry experience in undertaking such projects. Costs are represented in 2014 Dollars. For the purposes of the 2014 Study, the final shutdown date of Wolf Creek is projected to occur in 2045. The 2014 Study shows the decommissioning cost estimate to be $765.060 million in 2014 Dollars for the DEGON decommissioning option. TLG examined two decommissioning options: (a) DECON, 4 and (b) SAFSTOR. 5 Both alternatives are acceptable to the NRC. KCP&L's Schedule B ("2014 Funding Analysis") to the Application indicates that under current assumptions the present annual trust fund contribution of $1,281,264 is sufficient to meet the estimated decommissioning cost within $28,000 which is less than 0.01 % of the Missouri jurisdictional share of the future estimated total decommissioning costs. Based on its analysis KCP&L has. concluded that its funding level should result in a final decommissioning trust amount which is sufficient to cover the costs estimated in the 2014 Study under what KCP&L believes are a reasonable set of economic, financial, and investment assumptions. KCP&L believes it is reasonable and prudent to continue the annual accruals at the current level of $1,281,264. decommissioning cost studies. 4 DECON assumes decontaminating and decommissioning immediately following conclusion of power operations in 2045. Work is anticipated to be completed by 2053. DECON consists of removal of fuel assemblies, source material, radioactive fission and corrosion products, and other radioactive materials immediately after cessation of power operations. Total estimated cost to decommission in 2014 Dollars is $765,060,000. 5 SAFSTOR places the facility in protective storage for deferred decontamination to levels that permit release for unrestricted use. Delayed decontamination and dismantling activities are initiated once spent fuel and source material are removed, such that license termination is accomplished within the 60-year time period set by the NRC. This process is anticipated to be completed by 2106. Total estimated cost to decommission in 2014 Dollars is $1,034,501,000. 6
Among other things, the 2014 Funding Analysis is based on capital market assumptions dated April 1, 2014 from KCP&L's pension consultants, Towers Watson, as agreed in the Nonunanimous Stipulation And Agreement approved in File No. E0-2012-0068, and a decommissioning cost escalation rate based on inflation assumptions also from Towers Watson dated April 1, 2014 in order to provide consistency with the capital market assumptions. In its Application, KCP&L requests the Commission: (i) find that the 2014 Study and Funding Analysis satisfy the requirements of 4 CSR 240-3.185(3); and (ii) approve the continuation of the annual decommissioning expense accrual and trust fund contribution amount at the current funding level of $1,281,264 (Missouri jurisdictional amount). Because KCP&L is not proposing a change in the funding level, KCP&L has not filed new tariff sheets regarding its funding of decommissioning, is not requesting a hearing, and does not believe that a hearing is required respecting its decommissioning cost study filing. STIPULATIONS AND AGREEMENTS The Signatories to this case have reached certain understandings so that the Staff and KCP&L stipulate and agree as follows:
- 1. KCP&L's Missouri retail jurisdictional operations annual decommissioning expense accrual and trust fund payment was initially set by the Commission at
$2,303,856, first in Case No. E0-91-84, Kansas City Power & Light Co., 1 Mo.P.S.C.3d 353 (1992), again in Case No. E0-94-80, Kansas City Power & Light Co., 3 Mo.P.S.C.3d 60 (1994), again in Case No. E0-97-84, Kansas City Power & Light Co., 7 Mo.P.S.C.3d 124 (1998), again in Case No. E0-2000-210, Kansas City Power & Light 7
Co., 8 Mo.P.S.C.3d 516 (2000), again in Case No. E0-2003-0081, and again in Case No. E0-2006-0094. As part of Rate Filing #1 of the KCPL Experimental Regulatory Plan, the Commission approved in Case No. E0-2005-0329 (Case No. ER-2006-0314) KCP&L's Missouri retail jurisdictional authorized annual decommissioning expense accrual and trust fund payment was reduced to $1,281,264. The authorized Missouri retail jurisdictional annual decommissioning expense accrual and trust fund payment has remained the same in each subsequent triennial decommissioning filing and rate case filed subsequent to Rate Filing # 1. 6
- 2. On August 29, 2014, KCP&L filed its Application along with the 2014 Study. The Signatories request that the Commission recognize in its Report and Order for this case that KCP&L's Application and the 2014 Cost Study meet the requirements of 4 CSR 240-3.185(3).
- 3. The 2014 Study estimates the decommissioning cost for the DEGON alternative to be $765,060,000 in 2014 Dollars, which is 21.41 % higher than the 2011 estimate of $630, 135,000, which represents approximately a 6.68% annualized escalation rate over the 3-year period.
- 4. The current annual contribution of $1,281,264 (Missouri jurisdictional amount) to KCP&L's nuclear decommissioning trust fund is reasonable given the uncertainties in the numerous forecasted assumptions used to determine the contribution level. The forecasted assumptions include, but are not limited to, capital market expectations, projected decommissioning inflation rates and the costs to decommission Wolf Creek.
6 Case/File Nos. ER-2007-0291, ER-2009-0089, E0-2009-0072 and ER-2010-0355. 8
- 5. The Signatories agree that it is reasonable to use capital market return expectation information provided by Great Plains Energy's pension plan consultant for purposes of developing expected portfolio returns for KCP&L's nuclear decommissioning trust fund. The Signatories agree that any proposed changes to the annual contribution to KCP&L's nuclear decommissioning trust fund shall be based on capital market return expectation information provided by Great Plains Energy's pension plan consultant, unless the Signatories agree to use a different source and/or methodology for capital market return expectations or the Commission finds in a contested case that different source and/or methodology for capital market return expectation are more appropriate.
- 6. KCP&L shall continue its Missouri retail jurisdiction expense accruals and trust fund payments at current levels without any change in its Missouri retail jurisdictional rates, unless and until the Commission subsequently approves such a change.
- 7. Annual Missouri retail jurisdictional decommissioning costs in the amount of $1,281,264 are, and should continue to be, included in KCP&L's cost of service and reflected in its current rates for ratemaking purposes. The Signatories request that this finding be specifically recognized in the Commission's Report and Order and note that this finding is required in order for the decommissioning fund to retain its qualified tax status.
- 8. The Signatories agree and acknowledge that this Agreement does not prevent any Signatory from proposing changes to the annual contribution amount to the nuclear decommissioning trust fund in a subsequent rate proceeding.
9
- 9. The Signatories agree that KCP&L shall continue to record and preserve Wolf Creek asset retirement obligation costs, as agreed to by the Staff, Public Counsel, and KCP&L, and authorized by the Commission, in Case No. EU-2004-0294.
- 10. Except as explicitly agreed otherwise herein, none of the Signatories to this Agreement shall be deemed to have approved or acquiesced in any question of Commission authority, decommissioning methodology, ratemaking principle, valuation methodology, cost of service methodology or determination, depreciation principle or method, rate design methodology, cost allocation, cost recovery, or prudence that may underlie this Agreement or for which provision is made in this Agreement.
- 11. If the Commission does not unconditionally approve this Agreement without modification, and notwithstanding its provision that it shall become void thereon, neither this Agreement nor any matters associated with its consideration by the Commission shall be considered or argued to be a waiver of the rights that any Signatory has to a hearing on the issues presented by the Agreement,* regarding cross-examination or a decision in accordance with Section 536.080.1 RSMo or Art. V, Section 18 Mo. Const. The Signatories shall retain all procedural and due process rights as fully as though this Agreement had not been presented for approval, and any testimony or exhibits that may have been offered or received in support of or in opposition to this Agreement shall thereupon become privileged as reflecting the
- substantive content of settlement discussions, and shall be. stricken from and not be considered as part of the administrative or evidentiary record before the Commission for any further purpose whatsoever.
10
- 12. To assist the Commission in its review of this Agreement, the Signatories also request that the Commission advise them of any additional information that the Commission may desire from the Signatories related to the matters addressed in this Agreement, including any procedures for furnishing such information to the Commission.
- 13. If requested by the Commission, the Staff shall submit to the Commission a memorandum responsive to the Commission's request. Each party of record shall be served with a copy of any memorandum and shall be entitled to submit to the Commission within five (5) days of receipt of the Staff's memorandum, a responsive memorandum which shall also be served on all parties. The contents of any memorandum provided by any party are its own and are not acquiesced in or otherwise adopted by the other signatories to this Agreement, whether or not the Commission approves and adopts this Agreement.
- 14. The Staff also shall provide, at any agenda meeting at which this Agreement is noticed to be considered by the Commission, whatever oral explanation the Commission requests. The Staff shall, to the extent reasonably practicable, provide the other parties with advance notice of when the Staff shall respond to the Commission's request for such explanation once such explanation is requested from the
*Staff. The Staff's oral explanation shall be subject to public disclosures, except to the extent it refers to matters that are privileged or protected from disclosure pursuant to any Protective Order issued in this case.
- 15. Because this is an Agreement with the sole purpose of addressing the authority requested by the Application of KCP&L, except as specified herein, the 11
Signatories to the Agreement shall not be prejudiced, bound by, or in any way affected by the terms of this Agreement: (i) in any future proceeding; (ii) in any proceeding currently pending under a separate docket; and/or (iii) in this proceeding, should the Commission decide not to approve the Agreement or in any way condition its approval of the same, except as stated herein. Because this is an Agreement for the purpose of settling matters in this case, it shall not be cited as precedent or referred to in testimony as an assertion of the particular position of any Signatory in any subsequent or pending judicial or administrative proceeding, except that this shall not be construed to prohibit reference to its existence in future proceedings, including proceedings to enforce compliance with its terms.
- 16. The 2014 Study shall be received into evidence.
- 17. Pursuant to Section 393.290 RSMo, the Signatories agree that the Commission may review and authorize changes to KCP&L's Missouri retail jurisdictional rates and charges as a result in a change in the annual accrual of funding for the Missouri jurisdictional sub-account of the Wolf Creek decommissioning trust after a full hearing, including but not limited to any general rate increase case or excess earnings complaint case, and after considering all facts relevant to such accrual rate.
- 18. The provisions of this Agreement have resulted from numerous discussions/negotiations among the Signatories and are interdependent. In the event that the Commission does not approve and adopt the terms of this Agreement in total, it shall be void and no Signatory hereto shall be bound by, prejudiced, or in any way affected by any of the agreements or provisions hereof unless otherwise provided herein.
12
- 19. In the event the Commission accepts the specific terms of this Agreement, the Signatories waive their respective rights: (i) to cross-examine witnesses pursuant to Section 536.070(2) RSMo; (ii) to present oral argument and written briefs pursuant to Section 536.080.1 RSMo; (iii) to the reading of the transcript by the Commission pursuant to Section 536.080.2 RSMo; and (iv) to judicial review pursuant to Section 386.510 RSMo. This waiver applies only to a Commission Report and Order respecting this Agreement issued in this proceeding, and does not apply to any matters raised in any subsequent Commission proceeding, or any matters not explicitly addressed by this Agreement.
WHEREFORE, the Signatories hereto request that the Commission issue an order:
- 1. Approving this Non-Unanimous Stipulation and Agreement;
- 2. Receiving into evidence this Non-Unanimous Stipulation and Agreement, and the 2014 Study;
- 3. Finding that KCP&L's 2014 Cost Study satisfies the requirements of 4 CSR 240-3.185(3);
- 4. Finding, pursuant to this Non-Unanimous Stipulation and Agreement, that KCP&L's Missouri retail jurisdiction annual decommissioning expense accruals and trust fund payments shall continue at the current level of
$1,281,264;
- 5. Finding, in order for the decommissioning fund to retain its qualified tax status, that the current decommissioning costs for Wolf Creek are included in KCP&L's current Missouri cost of service and are reflected in its current Missouri retail rates for ratemaking purposes; and
- 6. Authorizing KCP&L to continue to record and preserve Wolf Creek asset retirement obligation costs, as agreed to by the Staff, Pubic Counsel and KCP&L, and authorized by the Commission, in Case No. EU-2004-0294.
13
Respectfully submitted, Isl Roger W. Steiner Isl Steven Dottheim Roger W. Steiner Steven Dottheim Corporate Counsel Chief Deputy Staff Counsel Missouri Bar No. 39586 Missouri Bar No. 29149 Kansas City Power & Light Company Attorney for the Staff of the 1200 Main Street, 16th Floor Missouri Public Service Commission Kansas City, MO 64105 200 Madison St., Ste. 800 (816) 556-2314 (Telephone) P. 0. Box 360 (816) 556-2787 (Fax) Jefferson City, MO 65102 roger.steiner@kcpl.com (e-mail) (573) 751-8702 (Telephone) (573) 751-9285 (Fax) steve.dottheim@psc.mo.gov (e-mail) CERTIFICATE OF SERVICE I hereby certify that copies of the foregoing have been mailed, hand-delivered, transmitted by facsimile or .electronically mailed to all counsel of record this 9th day of December, 2014. Isl Steven Dottheim I ' 14
Enclosure VI 11 to CO 17-0003 State of Missouri Public Service Commission Order Approving Stipulation and Agreement (4 pages)
STATE OF MISSOURI PUBLIC SERVICE COMMISSION At a session of the Public Service Commission held at its office in Jefferson City on the 22nd day of December, 2014. In the Matter of Application of Kansas City Power ) & Light Company for Approval of the Accrual and ) File No. E0-2015-0056 Funding of Wolf Creek Generating Station ) Decommissioning Costs at Current Levels. ) ORDER APPROVING STIPULATION AND AGREEMENT Issue Date: December 22, 2014 Effective Date: January 21, 2015 This order approves the stipulation and agreement between Kansas City Power & Light Company (KCP&L) and the Staff of the Commission regarding KCP&L's funding for the decommissioning of its Wolf Creek Generating Station. Commission rule 4 CSR 240-3.185 (3) states, in part: On or before September 1, 1990, and every three years after that, utilities with decommissioning trust funds shall perform and file with the commission cost studies detailing the utilities' latest cost estimates for decommissioning their nuclear generating unit(s) along with the funding levels necessary to defray these decommissioning costs. These studies shall be filed along with appropriate tariff(s) effectuating the change in rates necessary to accomplish the funding required. On August 29, 2014, KCP&L filed an application pertaining to Wolf Creek asking the Commission to: (a) find that the 2014 cost study and 2014 funding analysis satisfies the requirements of 4 CSR 240-3.185(3); and (b) approve the continuation of the annual accrual at the current level of $1,281,264. Staff and KCP&L filed a non-unanimous stipulation and agreement on December 9, 2014. Commission rule 4 CSR 240-2.115 provides that if no party objects to a non-
unanimous stipulation and agreement within seven days of its filing, the Commission will treat the stipulation and agreement as unanimous. The Office of the Public Counsel, the only other party, did not sign the stipulation and agreement, but has not opposed the agreement. Therefore, the Commission will treat the stipulation and agreement as unanimous. The stipulation and agreement asks the Commission to:
- Approve the stipulation and agreement;
- Receive into evidence the stipulation and agreement and the 2014 cost study;
- Find that KCP&L's 2014 cost study satisfies the requirements of 4 CSR 240-3.185(3);
- Find that KCP&L's Missouri retail jurisdiction annual decommissioning expense accruals and trust fund payments shall continue at the current level of
$1,281,264;
- Find that the annual decommissioning costs are included in KCP&L's current Missouri cost of service and are reflected in its current Missouri retail rates for ratemaking purposes; and
- Authorize KCP&L to continue to record and preserve Wolf Creek asset retirement obligation costs, as agreed to by the Staff, Public Counsel, and KCP&L, and authorized by the Commission in Case No. EU-2004-0294.
Having considered the 2014 decommissioning cost study for the Wolf Creek Generating Station and the stipulation and agreement, both of which are received into evidence, the Commission determines that the stipulation and agreement should be approved. In doing so, the Commission finds that KCP&L's 2014 cost study satisfies the requirements of 4 CSR 240-3.185(3). In addition, the Commission finds that KCP&L's Missouri retail jurisdiction annual decommissioning expense accruals and trust fund payments shall continue at the current level of $1,281,264. The Commission also finds that 2
the current decommissioning costs for Wolf Creek are included in KCP&L's current Missouri cost of service and are reflected in its current Missouri retail rates for ratemaking purposes. THE COMMISSION ORDERS THAT:
- 1. The stipulation and agreement filed by the Kansas City Power & Light Company and the Staff of the Missouri Public Service Commission on December 9, 2014, is approved.
- 2. The signatories shall comply with the terms of the stipulation and agreement.
- 3. The stipulation and agreement and Kansas City Power & Light Company's 2014 cost study are admitted into evidence.
- 4. Kansas City Power & Light Company's retail jurisdiction annual decommissioning expense accruals and trust fund payments shall continue at the current level of $1,281,264.
- 5. Kansas City Power & Light Company is authorized to continue to record and preserve Wolf Creek asset retirement obligation costs, as agreed by the Commission Staff, the Office of the Public Counsel, and KCP&L and authorized by the Commission in Case No. EU-2004-0294.
- 6. This order shall become effective on January 21, 2015.
- 7. This file shall be closed on January 22, 2015.
BY THE COMMISSION Morris L. Woodruff Secretary 3
R. Kenney, Chm., Stoll, W. Kenney, Hall, and Rupp, CC., concur. Woodruff, Chief Regulatory Law Judge 4
Enclosure IX to CO 17-0003 The State Corporation Commission of the State of Kansas Order Approving Unopposed Stipulation and Agreement (10 pages) ___ _ _ _ J
2015.03.24 14:ce:41 K:ir"i::..=<*::. Cot"Porati*:in Commission THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS Before Commissioners: Shari Feist Albrecht, Chair Jay Scott*Emler Pat Apple In the Matter of the 2014 Wolf Creek * ) Decommissioning Cost Study as Provided by ) Wolf Creek Nuclear Operating Corporation in ) Accordance with the Commission's Order in ) Docket No. 15-WCNE-093-GIE Docket Number 163,561-U on December 9, .) 1992, and the Commission's Order in Docket ) 13-WCNE-204-GIE on June 13, 2013. ) ORDER APPROVING UNOPPOSED STIPULATION AND AGREEMENT The above-captioned matter comes before the State Corporation Commission of the State of Kansas (Commission) for consideration and decision. Having reviewed the files and records, and being duly advised in the premises, the Commission makes the following findings and conclusions:
- 1. On August 29, 2014, Wolf Creek Nuclear Operating Corporation (Wolf Creek) filed its 2014 Decommissioning Cost Analysis for the Wolf Creek Generating Station in accordance with the Commission's December 9, 1992 Order in Docket No. 163,561-U and the Commission's Order in Docket No. 13-WCNE-204-GIE on June 13, 2013. The December 9, 1992 Order directed the filing of a decommissioning cost study every three years after September 1, 1993. The June 13, 2013 Order directed Wolf Creek and the owning utilities to update the estimates of the total capital costs of the Independent Spent Fuel Storage Installation (ISFSI) project at Wolf Creek as part of the triennial decommissioning cost study filings. 1 1
See Docket No. 13-WCNE-204-GIE, Order Closing Docket, Ordering, A (June 13, 2013).
- 2. Kansas Gas and Electric Company d/b/a Westar Energy (Westar), Kansas City Power & Light Company (KCP&L), Kansas Electric Power Cooperative, Inc. (KEPCo), and the Citizens' Utility Ratepayer Board (CURB) filed petitions to intervene, which the Commission granted.
I. Proceedings in the Docket
- 3. The following witnesses submitted pre-filed testimony according to deadlines adopted in the procedural schedule. KCP&L, Westar, and KEPCo filed the direct testimony of Gregg N. Clizer on October 3, 2014. Staff witnesses pre-filed direct testimony on January 5, 2015, as follows: Adam H. Gatewood (Gatewood) and Leo M. Haynos (Haynos).
- 4. The parties. met on February 9, 2015 to discuss settlement of this docket.
Following negotiations, all parties except CURB entered into .a Stipulation and Agreement (Stipulation) for the purpose of determining a reasonable estimate of Wolf Creek decommissioning costs to be used in addressing accrual levels of the respective owner utilities' decommissioning trust accounts and the appropriate escalation factor (inflation rate). The parties also discussed a separate, future issue regarding the content of the 2017 triennial decommissioning cost study filing.
- 5. On February 10, 2015, the parties filed a Joint Motion to Approve Stipulation and Agreement and to Convert the Evidentiary Hearing in this Docket to a Settlement Hearing or Cancel the Hearing (Joint Motion), advising the Commission that an unopposed settlement had been reached in this docket.2 Although CURB is not a signatory to the Stipulation, CURB has advised the other parties that it does not oppose the Stipulation. 3 The Prehearing Officer 2
Joint Motion to Approve Stipulation and Agreement and to Convert the Evidentiary Hearing in this Docket to a Settlement Hearing or Cancel the Hearing (Feb. 10, 2015) (Joint Motion). 3 Joint Motion, p.2. 2
approved the motion to convert the evidentiary hearing to a settlement hearing on February 11, 2015. 4
- 6. The following witnesses filed testimony in support of the Stipulation on February 12, 2015: Mary Britt Turner on behalf of the companies, and Haynos on behalf of Staff.
- 7. The settlement hearing was held before the Commission on February 24, 2015.
- 8. In deciding whether to grant the parties' Joint Motion, the Commission has reviewed and considered the entire record, including all pre-filed testimony of witnesses. The Commission's decision, as reflected in this Order; is based upon a review of all issues raised in this case, taking into account the issues upon which the parties have agreed.
II. Provisions of the Stipulation
- 9. The Stipulation resulted from discussions among the Joint Movants and CURB.
The terms of the Stipulation are briefly summarized as follows:
- a. The Stipulation is entered into for the purpose of determining a reasonable estimate of the Wolf Creek Generating Station decommissioning costs to be used in addressing accrual levels of the respective owner utilities' Decommissioning Trust Accounts.
- b. The cost for decommissioning funding is agreed to be $765,060,000 in 2014 dollars as set forth in the Decommissioning Cost Analysis for the Wolf Creek Generating Station filed in this docket on August 29, 2014. This number will be used by Westar, KCP&L and KEPCo in their respective proposals for setting an accrual level for each company's _Decommissioning Trust Account. This will be done in separate, individual company dockets.
4 Prehearing Officer Order Granting Joint Motion to Convert Evidentiary Hearing to Settlement Hearing (Feb. 11, 2015). 3
- c. Westar, KCP&L, and KEPCo agree to use an escalation rate of 3.15%
per year to escalate the 2014 decommissioning cost estimate of
$765,060,000 from 2014 dollars to the appropriate dollar amount in the year that the decommissioning costs will occur.
- d. The Parties agree that Wolf Creek, KCP&L, Westar, and KEPCo shall jointly file a new decommissioning financing plan that addresses each of the 11 requirements of K.S .A. 66-128m(b) by September 1, 2017.
The utilities may determine to file. certain of the requirements separately at the time of the joint filing so long as all 11 requirements are covered.
- e. The Parties agree that further discussion is necessary regarding the other issues raised by Staff5 and will continue to discuss those issues in this docket. The Parties believe that a resolution of these issues can be achieved and suggest the Commission adopt the following schedule:
- 1. On or before February 15. 2016: The Parties will report to the Commission as to the status of discussions to resolve the separate issues under this docket.
- u. On or before September l, 2016: The Parties will file a
- resolution with the Commission for approval; or, in the event the Parties reach an impasse after good faith efforts to reach consensus on a resolution to the separate issues, the Parties shall file a report with the Commission within 30 days of determining such impasse but no later than October 31, 2016.
5 Direct Testimony of Leo M. Haynos, p. 12, lines 8-23 (Jan. 5, 2015). 4
III. Findings and Conclusions
- 10. The Commission must separately state findings of fact, conclusions of law, and policy reasons for its decision if it is an exercise of its discretion. 6 Any findings of fact must be based exclusively upon the evidence of record in the adjudicative proceeding and on matters officially noticed in the proceeding. 7 Agency action must be based upon evidence that is substantial when viewed in light of the record as a whole. 8 A. Standard of Review
- 11. The Commission evaluates the evidence in the record as a whole regarding the proposed Stipulation in light of the following standards of review. Generally, the law favors compromise and settlement of disputes when parties enter into agreement settling and adjusting a dispute. 9
- 12. Pursuant to K.A.R. 82-1-230a(b), the Commission has authority to approve, reject or modify a settlement agreement. In approving, rejecting or modifying a settlement, the Commission must make an independent finding that its decision regarding the settlement is supported by substantial competent evidence in the record as a whole and that the settlement will establish just and reasonable rates. 10 B. Evaluation oftl1e Stipulation
- 13. The Commission will consider the Stipulation by reviewing the criteria identified for evaluating whether a specific unanimous settlement reached by the parties should be approved. Each criterion will be considered separately.
6 K.S.A. 77-526(c). 7 K.S.A. 77-526{d). 8 K.S.A. 77-621(c)(7), (d). 9 Krantz v. Univ. of Kan., 271Kan.234, 241-42 (2001). 1
°Citizens' Utility Ratepayer Board v. State Corp. Comm 'n, 28 Kan.App.2d 313, 316 (2000).
5
- 1. Is tile Stipulation supported by substantial evidence in t/1e record as a wlwle?
- 14. This Order has listed names of witnesses submitting pre-filed direct testimony, as set forth above in paragraph 3, as well as two witnesses presenting pre-filed testimony to support approval of the Stipulation. After reviewing the record as. a whole, the Commission finds the evidence supports approval of the Stipulation reached by the parties. The Commission will briefly summarize evidence that supports finding substantial evidence exists to approve the Stipulation in its entirety.
- 15. The Joint Movants have provided the decommissioning cost study as well as the testimony of four witnesses, all of which support the Stipulation. The cost for decommissioning funding of $765,060,000 and the escalation rate of 3.15% agreed to in the Stipulation are supported by substantial competent evidence in the record.
- 16. Having reviewed the evidence in the record, the Commission concludes that substantial evidence is present in the record as a whole to support approval of the Stipulation.
The Commission finds evidence in the record as a whole establishes the Stipulation is reasonable and should be approved in its entirety.
- 2. Will tile Stipulation result inj11st and reasonable rates?
- 17. Every electric public utility in Kansas is required to provide reasonably efficient and sufficient service and establish just and reasonable rates. 11
- 18. The Joint Movants state that Commission approval of the Stipulation will not have an immediate effect on rates charged to Kansas customers. 12 Rather, rate impact will not occur until each owner company files its individual dockets wherein the new decommissioning accrual will be included in their revenue requirement. 13 Nonetheless, the Joint Movants state II K.S.A. 66-lOlb.
12 Joint Motion, p. 4-5. 13 Id. 6
because the decommissioning cost elements being stipulated to in this docket are fair, reasonable, and fully supported by the evidence, inclusion of the same in rates later should not cause such rates to become unjust or unreasonable. 14
- 19. The Commission agrees with the Joint Movants' statements that the Stipulation will not have an immediate impact on rates, and any effect they may have on rates in the future will be just and reasonable because they are based on a reasonable settlement of the decommissioning cost elements in this docket.
- 3. Are the results of the Stipulation in the public interest, including the interest oftlte customers represented by any party not consenting to the agreement?
- 20. The Joint Movants agree the terms of the Stipulation are in the public interest and should be approved by the Commission. 15 Each party has a duty to protect its interests: the companies have a duty to both their customers and shareholders; CURB represents the interests of residential and small commercial customers; and Staff has a duty to weigh and balance the interests of the public generally. The fact that these varied interests were able to collaborate and present an unopposed resolution of the issues. in this case is a strong indication that the public interest standard has been met. The Joint Movants stated that the Stipulation reflects a reasonable compromise among the parties and eliminates the need for further costly and time-consummg . procee d"mgs. 16
- 21. In reviewing the Stipulation presented by the parties, the Commission has considered that the agreed-upon and stipulated decommissioning cost elements are fair, reasonable, and in the public interest. The Commission therefore finds that approval of the Stipulation is in the public interest.
14 Id. IS Id., p. 5. 16 Id. 7
C. Conclusion
- 22. The Commission approves of the Stipulation in its entirety, including the portions proposing a procedural schedule for the unresolved issues. The Commission finds that the Stipulation is supported by substantial competent evidence, is in the public interest, and will result injust and reasonable rates.
IT IS, THEREFORE, BY THE COMMISSION ORDERED THAT: A. The Commission grants the Joint Motion and approves the Stipulation in its entirety, for reasons discussed in this Order. By attaching the Stipulation to this Order, the terms are incorporated into this Order. I B. This Order shall be electronically served on all parties of record. Parties have 15 days from the date of electronic service of this Order in which to petition the Commission for reconsideration. 17 C. The Commission retains jurisdiction over the subject matter and parties for the purpose of entering such further order or orders as it may deem necessary. BY THE COMMISSION IT IS ORDERED. Albrecht, Chair; Emler, Commissioner; Apple, Commissioner MAR 2 4 2015 . Ne~sa Thomas EMAILED Actmg Secretary JV MAR 2 4 2015 17 K.S.A. 66-I 18b; K.S.A. 2014 Supp. 77-529(a)(l). 8
MAR 2 4 *zo15 CERTIFICATE OF SERVICE 15-WCNE-093-GIE I, the undersigned, hereby certify that a true and correct copy of the above and foregoing Order Approving Unopposed Stipulation and Agreement was served by electronic mail this 24th day of March, 2015, to the
- following parties who have waived receipt of follow-up hard copies:
NIKI CHRISTOPHER, ATTORNEY DELLA SMITH CITIZENS' UTILITY RATEPAYER BOARD CITIZENS' UTILITY RATEPAYER BOARD 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3116 Fax: 785-271-3116 n.christopher@curb.kansas.gov d.smith@curb.kansas.gov SHONDA SMITH DAVID SPRINGE, CONSUMER COUNSEL CITIZENS' UTILITY RATEPAYER BOARD CITIZENS' UTILITY RATEPAYER BOARD 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3116 Fax: 785-271-3116 sd.smith@curb.kansas.gov d.springe@curb.kansas.gov ROBERT J. HACK, LEAD REGULATORY COUNSEL ROGER W. STEINER, CORPORATE COUNSEL KANSAS CITY POWER & LIGHT COMPANY KANSAS CITY POWER & LIGHT COMPANY ONE KANSAS CITY PL, 1200 MAIN ST (64105) ONE KANSAS CITY PL, 1200 MAIN ST (64105) PO BOX 418679 PO BOX 418679 KANSAS CITY, MO 64141-9679 KANSAS CITY, MO 64141-9679 Fax: 816-556-2787 Fax: 816-556-2787 rob.hack@kcpl.com roger.steiner@kcpl.com MARY TURNER, DIRECTOR, REGULATORY AFFAI~ NICOLE A. WEHRY, SENIOR PARALEGAL KANSAS CITY POWER & LIGHT COMPANY KANSAS CITY POWER & LIGHT COMPANY ONE KANSAS CITY PL, 1200 MAIN ST (64105) ONE KANSAS CITY PL, 1200 MAIN ST (64105) PO BOX 418679 PO BOX 418679 KANSAS CITY, MO 64141-9679 KANSAS CITY, MO 64141-9679 Fax: 816-556-2110 Fax: 816-556-2787 mary. turner@kcpl.com nicole.wehry@kcpl.com SAMUEL FEATHER, LITIGATION COUNSEL JAY VAN BLARICUM, ASSISTANT GENERAL COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604-4027 TOPEKA, KS 66604-4027 Fax: 785-271-3167 Fax: 785-271-3314
- s. feather@kcc.ks.gov j.vanblaricum@kcc.ks.gov
- EMAILED MAR 2 4 2015
MAR 2 4 2015 CERTIFICATE OF SERVICE 15-WCNE-093-GIE WILLIAM G. RIGGINS, SR VICE PRES AND GENERAL CATHRYN J. DINGES, SENIOR CORPORATE COUNSEL COUNSEL WESTAR ENERGY, INC. KANSAS ELECTRIC POWER CO-OP, INC. 818 S KANSAS AVE 600 SW CORPORATE VIEW (66615) PO BOX889 PO BOX4877 TOPEKA, KS 66601-0889 TOPEKA, KS 66604-0877 Fax: 785-575-8136 Fax: 785-271-4884 cathy.dinges@westarenergy.com briggins@kepco.org DEBBIE L HENDELL, GENERAL COUNSEL AND WARREN WOOD SECRETARY WOLF CREEK NUCLEAR OPERATING CORPORATION WOLF CREEK NUCLEAR OPERATING CORPORATION 1550 OXEN LANE NE 1550 OXEN LANE NE PO BOX411 PO BOX411 BURLINGTON, KS 66839 BURLINGTON, KS 66839 Fax: 620-364-4017 Fax: 620-364-4017 wawood@wcnoc.com dehende3@wcnoc.com Sheryl L. Sparks Administrative Specia 1st EMAILED MAR 2 4 2015
Enclosure X to CO 17-0003 The State Corporation Commission of the State of Kansas Order Approving Stipulation and Agreement (51 pages)
2015.09.24 10:47:44 f<.ans.:i=* CorPora-!:ii:*n Commi:5sii:*r1 THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS Before Commissioners: Shari Feist Albrecht, Chair Jay Scott Emler Pat Apple In the Matter of the Application of Westar ) Energy, Inc. and Kansas Gas and Electric ) Docket No. 15-WSEE-115-RTS Company to Make Certain Changes in Their ) Charges for Electric Service ) ORDER APPROVING STIPULATION AND AGREEMENT I. Introduction ........................................................................................................................... 2 A. Procedural History and Entries of Appearance .............................................................*...... 2 B. Jurisdiction, Authority and Legal Standards ........................................................................ 4 C. Prefiled Testimony and Other Documents ........................................................................... 5 D. Public Hearings and Comments ........................................................................................... 8 E. Evidentiary Hearings and Administrative Notice ................................................................ 9 II. Stipulation and Agreement ................................................................................................. 12 A. Agreement and Addendum ................................................................................................ 12 B. Provisions of the Stipulation and Agreement .................................................................... 13 C. s*tandard of Review ............................................................................................................ 25
- l. Was there an opportunity for the opposing party to be heard on the reasons for*
opposition to the_ Stipulation and Agreement? ............................................................... 27
- 2. Is the Stipulation and Agreement supported by substantial competent evidence in the record as a whole? .......................................................................................................... 29
- 3. Does the Stipulation and Agreement conform with applicable law? ............................. 33
- 4. Does the Stipulation and Agreement result in just and reasonable rates? ...................... 36
- 5. Are the results of the Stipulation and Agreement in the public interest, including the interest of customers represented by any party not consenting to the agreement? ........ 40 III. Abbreviated Rate Case ........................................................................................................ 43 IV. Generic Docket ..................................................................................................................... 44 V. Findings and Conclusions ................................................................................................... 45
This matter comes before the State Corporation Commission of the State of Kansas (Commission) for consideration and decision. Having reviewed the pleadings and record, the Commission makes the following findings and conclusions: I. Introduction A. Procedural History and Entries of Appearance
- 1. On July 21, 2014, in Docket No. 15-GIME-025-MIS (15-025 Docket), Westar Energy, Inc. and Kansas Gas and Electric Company Gointly referred to as "Westar") filed a Joint Application with Kansas City Power & Light Company to approve the timing and accounting treatment for their respective rate cases regarding the inclusion of the La Cygne Environmental Project into rate base. The Joint Application also included proposed schedules for the pending Westar rate case.
- 2. On September 9, 2014, in the 15-025 Docket, the Commission issued an Order Approving Joint Application, establishing the accounting treatment and procedural schedule for Westar's general rate case. 1
- 3. On March 4, 2015, the Commission took administrative notice of the procedural schedule set forth in the 15-025 Docket and incorporated it into Westar' s instant general rate case, Docket No. 15-WSEE-115-RTS.
- 4. The Commission modified the procedural schedule on three separate occasions to conduct an additional public hearing, amend settlement procedures, and divide the scheduled evidentiary hearing into two distinct phases. 2 1
A Petition Initiating Docket filed by Westar on September I 5, 2014, gave rise to the present docket, Docket No. 15-WSEE-I 15-RTS. 2 See Order Modifying Procedural Schedule (Apr. I4, 20 I 5); Order Modifying Procedural Schedule and Substituting Prehearing Officers (Jul. 14, 2015); Order On: Interventions, Petition For Leave To Issue Discovery, Motion To 2
- 5. When the Commission modified the procedural schedule to bifurcate the evidentiary hearing into two distinct phases, the Commission separated out certain issues and limited the participation of certain intervenors to certain issues. The Commission placed issues related to Westar' s proposed Residential Demand Plan and Residential Stability Plan, Community Solar proposal, and solar block subscription proposal into "Phase II" of the evidentiary hearing. 3 All other issues to be decided would be heard during "Phase I" of the evidentiary hearing. 4 The Commission granted The Alliance for Solar Choice (TASC),
Cromwell Environmental Inc. (CEI), Brightergy, LLC (Brightergy), Climate and Energy Project (CEP) and the Environmental Defense Fund (EDF), 5 collectively referred to as the "Solar Parties," limited intervention in this proceeding. 6
- 6. On August 6, 2015, parties who had been granted full intervention status, and were thus able to participate in both Phase I and Phase II of the evidentiary hearing, submitted a Stipulation and Agreement (S&A) that resolved all outstanding issues in the matter. 7 Subsequent to the filing of the S&A, Westar engaged in additional settlement talks with the Solar Parties. 8 Upon amending certain language in the S&A, the Solar Parties agreed to not oppose the S&A. 9 Westar *filed an Unopposed Motion for Leave to File Addendum to Stipulation and Agreement Accept Pre-Filed Direct Testimony Out Of Time And Modifying Procedural Schedule (Jul. 23, 2015) [hereinafter Final Procedural Order].
3 Final Procedural Order at 30. 4 Id. 5 The Commission prohibited CEP from participating in the evidentiary hearing. See Final Procedural Order at 25. 6 Final Procedural Order at 14, 18-19, 21-22, 25, 27. The Commission limited TASC, CE!, Brightergy and EDF to only the Phase II issues. See id. The Commission excluded CEP from participation in the hearing but allowed CEP to brief on the fixed rate charge. See id. at 25. 7 See Joint Motion To Approve Stipulation And Agreement at 2. (Aug. 6, 2014) [hereinafter S&AJ. Note: The Joint Motion to Approve Stipulation and Agreement also contained the Stipulation and Agreement as a separate document with separate pagination. For purposes of this order, all references to S&A are to the Stipulation and Agreement attached to the Joint Motion unless otherwise noted. 8 Unopposed Motion For Leave To File Addendum To Stipulation And Agreement Out Of Time at 2 (Aug. 12, 2015) [hereinafter Unopposed Addendum}. 9 Id. at 3. 3
Out of Time (Unopposed Addendum) on *August 12, 2015. The disposition of the S&A is discussed in greater detail below. B. Jurisdiction, Authority and Legal Standards
- 7. The Commission has full power, authority and jurisdiction to supervise and control electric public utilities, as defined in K.S.A. 66-lOla, doing business in Kansas, and is empowered to do all things necessary and convenient for the exercise of such power, authority and jurisdiction. 10 "Electric public utility" means any public utility, as defined in K.S.A. 66-104, which generates or sells electricity. 11 K.S.A. 66-104 defines "public utility" in part as "all compames for the *production, transmission, delivery or furnishing of heat, light, water, or power." 12
- 8. Electric public utilities subject to the Commission's jurisdiction are "required to furnish reasonably efficient and sufficient service and facilities for the use of any and all products or services rendered, furnished, supplied or produced by such electric public utility, to establish just and reasonable rates, charges and exactions and to make just and reasonable rules, classifications and regulations." 13 The Commission thus has the power to require utilities to establish just and reasonable rates and maintain reasonably sufficient and efficient service. 14
- 9. The authority of the Commission is liberally construed, and in the exercise of the Commission's power, authority, and jurisdiction, all incidental powers necessary to carry into
'° K.S.A. 66-101; K.S.A. 66-IOla; K.S.A. 66-104. 11 K.S.A. 66-IOla. 12 . K.S.A. 66-104(a). 13 K.S.A. 66-10 I b. 14 K.S.A. 66-lOlb. 4
effect the provisions of the Electric Public Utilities Act, K.S.A. 66-101 et seq., are expressly granted to and conferred upon the Commission. 15
- 10. Pursuant to K.S.A. 66-117, a public utility over which the Commission has jurisdiction cannot make effective any changed rate, joint rate, toll, charge or classification or schedule of charges, or any rule or regulation or practice pertaining to. the service of a public utility except by filing with the Commission.
- 11. On March 2, 2015, Westar filed its Application to make changes to its charges for electric service pursuant to K.S.A. 66-117 and K.A.R. 82-1-231. 16 Accordingly, the Commission has jurisdiction to exercise control and jurisdiction over Westar for, among other things, this particular rate request.
C. Prefiled Testimony and Other Documents
- 12. Commission regulations address filing requirements for rate proceedings, and require utilities such as Westar to provide appropriate schedules and competent testimony when filing a rate change application. 17
- 13. Throughout the course of this proceeding, parties submitted direct testimony, rebuttal testimony, and cross-answering testimony, exhibits and evidence. With its Application of March 2, 2015, Westar filed direct testimony from twenty-two witnesses in addition to two volumes of data that numbered over 700 pages. On July 9, 2015, multiple parties to this docket submitted direct testimony in accordance with the procedural schedule. Shortly thereafter, on July 24, 2015, eight witnesses submitted cross-answering testimony. On July 29, 2015, Westar submitted rebuttal testimony from eighteen witnesses and the U.S. Department of Defense and 15 K.S.A. 66-IO!g.
16 Joint Application of Westar Energy, Inc. and Kansas Gas and Electric Company (Mar. 2, 2015) [hereinafter Application]. 17 See K.A.R. 82-1-231. 5
all Federal Executive Agencies submitted rebuttal testimony from one witness. The following table identifies and outlines these filings: Direct Testimony Cross- Rebuttal Witnesses Answering Testimony Testimony Witnesses Witnesses
-*"~*~'"~~tt~f::i~:~L...:;,'..~Y.!!~L
- Staff 1. Leo Haynos 1. Robert Glass
- 2. Adam Gatewood 2. Justin Grady
- 3. William E. Baldry
- 4. Timothy Rehagen
- 5. Luis M. Solorio
- 6. Tyler J. Page
- 7. Dorothy J. Myrick
- 8. Katie L. Figgs
- 9. Kristina Luke-Fry
- 10. Andy Fry
- 11. Robert Glass
- 12. Justin Grady 6
r~ff~~~~;,.~,,~: Kanas Industrial 1. Stephen M. Rackers I. Brian C. Consumers Group 2. Brian C. Andrews Andrews
- 3. Michael P. Gorman 2. Michael P.
- 4. Christopher C. Gorman Walters t':.:-~,~,,.,_,_;~Il.~;;~~~*7::>1** *.,J~.:~~~1~;:-~:~:~-~':;v;;~~:.~~:1;:"~?~::'~-~.-~.~*-*
Climate & Energy I. Ashok Guptaon Project
~~li**-~¥~s:t>~~Jtw:t~;~r,_;.~_,\_ ~ ,; '" "'"-* -'"
U.S. Department of 1. Jeff Hoppe 1. Jeff Hoppe
. *.c--.;*:*.-----..*-*
- 1. Jeff Hoppe Defense and all Federal Executive Wal-Mart Stores, I. Steve Chriss Inc.
[~~~~l~];~~~1Jf:=~'.r*::;::~~~:~i~~ali~f~~~~;~:~;;_~-~:~:: Unified School I. John Allison District # 259 2 91
~~~rK~~~:r~~i~~*:;:iiri;~i.::RB~~~:,~ ~~~~~¥~1; ::?*'.:~~1~~~~~~g~~:E~v~/---* - -*
- 14. In summation, by July 29, 2015, fifty-one witnesses from thirteen separate parties had placed into the administrative record for this docket seventy-eight iterations of direct, cross-answering, or rebuttal testimony that established and defended the basis and rationale for their respective initial positions. Parties and witnesses further supplemented the testimony with additional schedules and exhibits.
7
D. Public Hearings and Comments
- 15. The Commission, though not required by statute, has established a history of directly reaching out to and receiving comments from individual members of the public. Public hearings provide the citizens of Kansas an opportunity to address the Commission directly.
- 16. The procedural schedule set a public hearing for July 21, 2015, at Farley Elementary School, Topeka, Kansas, with video conferencing available at satellite locations in Emporia, Kansas, and Salina, Kansas. The Commission scheduled a second public hearing later in the proceeding for July 23, 2015, at Wichita State University, Wichita, Kansas, 18 with video conferencing available at satellite locations in Hutchinson, Kansas, and Pittsburg, Kansas.
- 17. Westar customers and the general public.received notification by way of multiple newspapers throughout the state, as well as mailers included in every Westar customer's bill. 19
- 18. The Commission took comments from the public regarding Westar's Application from the commencement of Westar's general rate case up through August 11, 2015, as directed by the procedural schedule. The Commission received comments via telephone, traditional mail, and electronic mail. These comments were in addition to any comments received at the public hearings.
- 19. On August 13, 2015, the Commission's Public Affairs and Consumer Protection Division (PACP) caused to be filed in the record a report summarizing the public comments
. d.20 receive 18 Order Modifying Procedural Schedule, 2 (Apr. 14, 2015). .
19 See Affidavit of Publication (Jul. 8, 2015); See also Affidavit of Cindy Wilson Regarding Customer Notice, I (Jul. 8, 2015).
- 20 Notice ofFiling of Public Comment (Aug. 13, 2015).
8
- 20. On August 14 and 25, 2015, PACP caused to be filed in the record an Addendum and a subsequent Supplement, respectively, to its initial report. 21 Fifteen additional comments were received via regular mail that had been postmarked by the August 11, 2015, cutoff date, 22 and four comments were received via electronic mail after 5:00 p.m. on August 11, 2015, but before midnight. 23
- 21. To summarize, the Commission received 1,458 comments from March 2, 2015, through August 11, 2015. Additionally, the Commission received thirty-two comments during the July 21, 2015, Topeka public hearing, and forty-three comments during the July 23, 2015, Wichita public hearing. The overwhelming public response received in this docket indicated general opposition to Westar's initial Application.
E. Evidentiary Hearings and Administrative Notice
- 22. On August 3, 2015, the Prehearing Officers filed and served notice of the prehearing conference upon counsel of record. 24 On August 12, 2015, the Prehearing Officers held a prehearing conference to discuss preliminary matters prior to the Commission convening the scheduled evidentiary hearing.
- 23. On August 17, 2015, in accordance with the procedural schedule set forth in this docket, the Commission convened an evidentiary hearing to receive testimony in support of the S&A. In total, twenty-three parties participated in the evidentiary hearing. Entries of appearance for counsel were as follows:
21 Notice ofFiling Addendum to Public Comment (Aug. 14, 2015); Notice of filing Supplement to Addendum to Public Comment, 2 (Aug. 25, 2015). 22 Notice of Filing Addendum to Public Comment at 2. 23 Notice of filing Supplement to Addendum to Public Comment at 2. 24 Notice of Prehearing Conference (Aug. 3, 2015). 9
Party Entry of Appearance at Evidentiary Hearin L ..9.~..~":~~~l!~~11i; ,' Commission Staff 1. Amber Smith
- 2. Michael Neele rr The Alliance for Solar Choice
*:-. *~n;,~A'*'.i~::t~~f:I~~~~~~f~~~~~~I~~ .i 1 Kansas Industrial Consumer Group and its 1. James P. Zakoura Member Companies: Occidental Chemical Corporation, CCPS Transportation, LLC, Spirt AeroSystems, Inc., Coffeyville Resources Refining & Marketing, LLC, The Goodyear Tire & Rubber Company 1
1 ~~ ~""'.*:*a~'*~rlf;~~~~~£~~~6r~,~~ '"'?'!!,~:*4;~/:~:'.~,*;* 'Zy"lril11,~~!~~~--*-~***:;2~~!.Jc~'.'.* Frontier El Dorado Refining, LLC 1. Jam es Flaherty ~t~~W~~~,~i~\f~~~~El~~~~;*::< Wal-Mart Stores, Inc., Tyson Foods, Cargill, 1. David Woodsmall Inc.
- 1. Robert Eye
~tll~~~~;~l~~[i Kroger Co. 10
- 24. Counsel for all parties to this docket appeared at the evidentiary hearing. After inquiring with Commission Staff (Staff) Counsel and hearing no objections, the Commission found that notice of the evidentiary hearing was proper. 25
- 25. Upon the finding that notice was proper, the Commission took up certain preliminary matters. The Commission approved Mr. Jacob Schlesinger's Verified Application for admission pro hac vice on behalf of TASC.26 The Kansas Industrial Consumers Group, Occidental Chemical Corporation, and the U.S. Department of Defense and all Federal Executive Agencies withdrew their motion to strike the testimony of the Citizen's Utility Ratepayer Board (CURB) witness Brian Kalcic. 27 The Commission denied the International Brotherhood of Electric Workers, Local 304's (IBEW's) motion to file testimony out of time. 28 Due to the settlement of all issues, the Commission waived the previously ordered bifurcation of the evidentiary hearing. 29
- 26. Following the preliminary matters and opening statements, Westar called Greg Greenwood to testify in support of the S&A30 and moved for admission into the record the prefiled testimony of Westar's remaining witnesses. 31 No party opposed the motion and the Commission admitted the testimony. 32 25 Transcript of Evid. Hearing at 9-10.
26 Id. at 10. 27 Id at 10-11. 28 Id at 11-12. 29 Id at 12-13. 30 Transcript ofEvid. Hearing at 47-55. 31 Id at 55-56. 32 Id at 56. 11
- 27. Staff called Justin T. Grady and Dr. Robert Glass to testify in support of the 33 S&A and moved for admission into the record the prefiled testimony of Staffs remaining 34 N witnesses.
- o party oppose d the motion
. and the Commission
. . admitte
. d the testimony.
. 35
- 28. CURB called Andrea C. Crane to testify in support of the S&A36 and moved for admission into the record the prefiled testimony of CURB's remaining witnesses. 37 No party objected to this motion and the Commission admitted the testimony. 38
- 29. All remaining parties who had previously filed direct, cross-answenng, and rebuttal testimony in this proceeding, as described
- above, moved to have their respective witnesses' testimonies entered into the record. 39 No party objected to the admittance of the testimony into the record and the Commission admitted the same. 40 IL Stipulation and Agreement A. Agreement and Addendum
- 30. On August 6, 2015, Staff, Westar, CURB, Kansas Industrial Consumers on its own behalf and behalf of its member companies, Unified School District No. 259, the Kansas Association of School Boards, Kroger Co., the U.S. Department of Defense and all other Federal Executive Agencies, Frontier El Dorado Refining LLC, Occidental Chemical Corporation, Wal-Mart Stores, Inc., Tallgrass Pony Express Pipeline, LLC., Cargill, Inc., and Tyson Foods, 33 Id. at 57-65.
34 Id. at 65-66. 35 Id. at 66. 36 Transcript of Evict. Hearing at 66-68. 37 Id. at 68. 38 Id. 39 Id. at 68-72. 40 Id. 12
collectively referred to as the "Joint Movants" filed a Joint Motion to Approve Stipulation and Agreement. 41
- 31. Upon the filing of the S&A, Westar reached out to the Solar Parties. 42 The Solar Parties indicated that although they could file formal comments indicating their disagreement with certain provisions of the S&A, if certain changes were made to paragraph 39 of the S&A, the Solar Parties would agree not to oppose the S&A. 43 As a result of this, Westar proposed these changes in the Unopposed Addendum. 44 Westar received confirmation that no party to the docket objected to the filing of the Unopposed Addendum. 45 B. Provisions of the Stipulation and Agreement
- 32. The S&A begins with a recitation of the Joint Movant's initial positions. 46 As described above, the entirety of the terms contained within the S&A, described below, have been unanimously subscribed to by the Joint Movants to the S&A. 47 Additionally, the terms of the S&A are not opposed by any of the Solar Parties. 48
- 33. Stipulated Revenue Requirement: The Joint Movants propose that Westar's net overall annual revenue increase should be set at $78,000,000. 49 This revenue requirement does not include costs recoverable through Commission-approved riders. 50
- 34. Rebasing: The Joint Movants propose that Westar roll into base rates the existing balance in the Environmental Cost Recovery Rider (ECRR), including the amount updated in 41 See S&A.
42 Unopposed Addendum at 2. 43 Id 44 See id. at 2-3. 45 See id at 3. 46 S&A at 2-3. 47 See id. 48 Unopposed Addendum at 3. 49 S&A at if 12. 5o Id 13
June, 2015, and the existing balance in the property tax surcharge and allocate the discount provided to Interruptible Service Rider (ISR) customers to the other customer classes. 51 By including the roll-in of the ECRR, property tax surcharge, and allocation of the ISR discount, the total base revenue requirement increase is $185, 100,000. 52 These rebasing amounts to be rolled into base rates are reflected in Appendix A to the S&A. 53
- 35. Rate case expense: The Joint Movants propose that rate case expense in excess of the actual amount included in Staffs filed revenue requirement should be trued up at the end of the case to the actual amount of rate case expense incurred and be added to the agreed-upon revenue requirement. 54 Westar agreed to submit these expenses to Staff for review within 14 days of the close of the record in this case. 55 Staff reportsthat Westar's total rate case expense is
$1,536,649. Of that amount, Staff and CURB costs account for $493,631. This adjustment for rate case expense causes an increase in the revenue requirement of $225,264.
- 36. Bad debt expense: The Joint Movants propose that bad debt expense in excess of that included in Staffs filed revenue requirement recommendation be calculated as .43% of the net increase in revenue requirement and be added to the stated net increase in revenue requirement. 56 When .the Joint Movants drafted the S&A using the agreed-upon revenue requirement increase described above, before accounting for the increase in rate case expenses the bad debt expense amounted to $86,700. 57 Using the revised rate case expense indicated by Staff, the bad debt expense now totals $87,658.
51 Id. at~ 13. 52 Id. at~ 13. 53 Id. at~ 13; S&A at Appendix A. 5
~ S&A at~ 14.
5s Id. 56 Id. at~ 15. 57 Id. at~ 15. 14
- 37. Inclusion of Pension and Other Post Employment Benefit (OPEB) Expense: The Joint Movants propose that the $78,000,000 net increase in the annual revenue requirement include a $5,000,000 increase in Pension and OPEB expense from Staffs filed position as stated in the Direct Testimony of Bill Baldry. 58
- 38. Nuclear Decommissioning Trust Fund: The Joint Movants propose that Westar utilize Staffs recommendation as stated in the Direct Testimony of Staff Witness Adam Gatewood regarding the appropriate funding level for Westar's nuclear decommissioning trust fund, e.g. $5,772,700. 59
- 39. Analog Meter Regulatory Asset: As Westar retires analog meters between October 28, 2015, and the effective date of rate changes in Westar's next general rate case, the Joint Movants proposed that Westar place the unrecovered investment in a retired analog meter regulatory asset. 60 The Joint Movants propose Westar be permitted to amortize the balance of the regulatory asset account over five years and recover that amortization amount in the base rates established in Westar's next general rate case. 61 No return on the regulatory asset will be allowed. 62 The Joint Movants agree that this particular ratemaking treatment should have no precedential value. 63
- 40. Discontinuance of Environmental Cost Recovery Rider: The Joint Movant's propose that Westar's ECRR should be discontinued. 64 The Joint Movants agree that Westar would do a final update of environmental costs for 2015 that would have been recovered through 58 Id. at if 16.
59 Direct Testimony of Adam Gatewood Direct on Behalf of Commission Staff at 70 (Jul. 9, 2015); S&A at if 17. 60 S&A at 'If 18. 61 Id at if 18. 62 Id at if 18. 63 Id. at if 18. 64 Id. at if 19. 15
the ECRR previously noticed to the Commission, and roll them into base rates established in a proposed abbreviated rate case discussed below. 65
- 41. Grid Resiliency: The Joint Movants propose that Westar be permitted to recover up to $50,000,000 of capital investment in grid resiliency improvements completed between October 28, 2015, and March 1, 2017, consistent with improvements proposed as part of the Electric Distribution Grid Resiliency (EDGR) program discussed in the Direct Testimony of Westar witness Bruce Akin and the report sponsored in Westar witness Jeffrey Cummings' Direct Testimony. 66 Plant in-service, less the associated accumulated depreciation and deferred income taxes, would be reflected in rates as a result of the abbreviated rate case discussed below.
Westar will work with Staff to develop a process for periodic reporting regarding the investments being made and periodic meetings to provide updates and discussion on such investments. 67
- 42. RENEW Tariff: The Joint Movants propose the Commission approve Westar's proposal as discussed in the Direct Testimony of Westar witness Chad Luce to change the pricing of the RENEW tariff to $0.25 per 100 KWh block, 68 a reduction to 1/4 of the current rate. 69
- 43. Wind Capacity Programs: The Joint Movants propose the Commission approve Westar's Wind Energy and Wind Capacity Programs discussed in the Direct Testimony of Westar Witness Chad Luce with the modification to the calculation of avoided cost agreed to in the Rebuttal Testimony of Westar Witness John Wolfram. 70 Specifically, the avoided cost for customers participating in these programs shall be Westar's Retail Energy Cost Adjustment 65 Id. at if 19.
66 S&A at if 20; See Direct Testimony of Jeffrey W. Cummings on Behalf of Westar Energy, exhibit JC-I, as amended (Jun. 10, 2015). 67 S&A at if 20. 68 Id. at if 21. 69 Direct Testimony of Chad Luce on Behalf of Westar Energy, 13 (Mar. 2, 2015). 70 S&A at if 22. 16
(RECA) rate increased by 5% of the [Medium General Service] base energy charge. The Joint Movants agree to add language to the RECA tariff to allow the revenues and costs from the program to be included in the RECA calculation. 71
- 44. Solar Energy & Capacity Tariff: The Joint Movants propose the Commission approve Westar's solar energy and solar capacity tariff as described in the Direct Testimony of Chad Luce with the following conditions: (1) Westar will require the initial subscription of a solar project to equal 100% of the capacity of the project before beginning construction; (2) the minimum size for Westar's solar projects under this program shall be 1 MW; and, (3) the rates charged to initial participants will cover 100% of the direct costs of the project. 72
- 45. . Residential Stability Plan and Residential Demand Plan: The Joint Movants agree that Westar will not implement these proposed tariffs at this time. 73
- 46. Community Solar: The Joint Movants agree that Westar will not implement the Community Solar program discussed in the Direct Testimony of Hal Jensen at this time. 74
- 47. Subdivision Policy: The Joint Movants propose that the Commission approve the subdivision policy changes in the Direct Testimony of Westar witness Mike Heim (increasing the allowance given to developers for residential subdivisions for the overhead distribution system from $30,000 to $40,000). 75
- 48. Street Lighting (SL). Private Area Lighting (PAL), Restricted Institution Time of Day CRITODS): The Joint Movants propose the Commission approve the changes in the Direct 71 Id at if 22.
72 Id at if 23. 73 Id. at if 24. 74 Id. at if 25. 75 Direct Testimony of Mike Heim on Behalf of Westar Energy, 21 (Mar. 2, 2015) [hereinafter Heim Direct]; S&A at if 26. 17
Testimony of Westar witness Mike Heim to the SL, PAL and RITODS tariffs as filed. 76 These changes will allow for the implementation of LED lighting options and expand the types of organizations that could take service under Westar' s current RITODS tariff. 77
- 49. Economic Discount Sharing: The Joint Movants propose that customers and shareholders share the costs equally (50-50) associated with any discount awarded in the future, as long as that discount affects future test year revenues in a rate case pursuant to Westar' s Economic Development Rider (EDR). 78 The Joint Movants propose that the EDR tracker described in the Direct and Rebuttal Testimony of Westar witness Terrance D. Wilson not be adopted at this time. 79
- 50. Security Tracker: The Joint Movants propose that Westar be permitted to implement a Security Tracker as discussed in Staff witness Justin Grady's Direct Testimony, the Rebuttal Testimony of Westar Witness John Wolfram, and as specifically described in Appendix C to the S&A. 80
- 51. Return on Equity: There is no stated return on equity included in the S&A. The Joint Movants propose that until Westar's next general rate proceeding, Westar be authorized to use 10.926% as its overall pretax rate of return for regulatory accounting purposes, including the calculation of the equity component of Allowance for Funds Used During Construction (AFUDC), and for the abbreviated rate case discussed below. 81 This pre-tax rate of return assumes Westar's filed capital structure to be 46.3% Long-Term Debt, 53.1% Common Equity, 76 S&A at if 27.
77 Heim Direct at 19-21. Note: Under Westar's current RlTODS tariff, the "R" is an abbreviation for "Religious." Westar's proposed changes also change this abbreviation to "Restricted" to make the tariff available to other customers with similar usage patterns of religious institutions. See Heim Direct at 20. 78 S&A at if 28. 79 Id at if 28. 80 Id at if 29. 81 1d.atif30. 18
and .6% Post 1970 [Investment Tax Credit] as discussed in the Direct Testimony of Westar Witness Susan North. 82 The Joint Movants agreed to the use of the indicated overall pretax rate ofreturn for settlement purposes only, and do not view such return on equity as precedential. 83
- 52. Jurisdictional Non-Transmission Related Retail Property Tax Expense: The Joint Movants propose upon approval of the agreed-upon rate increase, that the Kansas jurisdictional, non-transmission related, retail property tax expense in base rates be $106,671,011. This amount would be the basis for determining property tax balance used in future property tax surcharge filings for the time-period when the proposed new rates would be applicable. 84 In order 'to calculate future property tax surcharges, the property tax surcharge expense assumed to be collected in base rates will begin with the effective date of the rate increase resulting from this docket, until the amount is reset in a Commission order. 85
- 53. Cost-of-Service Deferred Income Tax Expense: The Joint Movants propose that Westar's cost-of-service deferred income tax expense and amortization of investment tax credits comply with the tax normalization requirements of the Internal Revenue Code of 1986 as amended. 86
- 54. Amortization Periods: The Joint Movants propose the following amortization periods:
- a. Westar' s actual rate case expense - three years;
- b. Regulatory asset associated with SmartStar Lawrence - three years;
- c. Regulatory asset associated with SCR Catalyst - fifty-four months; 82 Id. at if 30.
83 Id. at if 30. 8
"' S&A at if 3 I.
85 Id. at if 31. 86 Id. at if 32. 19
- d. Regulatory asset associated with Baghouse - six years;
- e. Regulatory liability associated with Stateline purchased power - three years;
- f. Pension tracker authorized by Docket No. 10-WSEE-135-ACT in the annual amount of $3,423,867- five years. 87
- 55. Going Forward Pension Tracking: The Joint Movants propose that base rates agreed to in the S&A include the following expenses associated with Westar' s pension plan:
- a. Westar Pension Expense - $33,403,818
- b. Westar FAS 106 Expense - $841,864
- c. Westar FAS 112 Expense - $431,737
- d. WCNOC Pension Expense - $9,934, 193 88
- 56. Abbreviated Rate Proceeding: The Joint Movants propose that Westar be allowed to use the abbreviated rate setting process contained in K.A.R. 82-1-231 (b )(3) to update rates to include capital costs related to the environmental projects at LaCygne Energy Center that were preapproved by the Commission in Docket No. 11-KCPE-581-PRE, up to the amount of costs approved by the Commission in said docket, but not included in rates set as a result of this proceeding. 89 The Joint Movants also propose that Westar use the abbreviated rate setting process to update rates to include capital costs related to projects at the Wolf Creek Generating Station described in the Direct Testimony of Westar witness John Bridson. 90 The Joint Movants request the Commission expressly grant Westar prior approval to file this abbreviated rate case 87 Id at if 33.
88 Id at if 34. 89 Id. at if 35. 90 S&A at if 35. 20
pursuant to K.A.R. 82-l-23l(b)(3). The cost of capital to be used for purposes of such proceeding is to be the overall rate ofretum stated in paragraph 30 of the S&A. 91
- 57. Inclusion of Grid Resiliency Projects & Final Roll-in of Environmental Cost Recovery Rider Costs: The Joint Movants propose that Westar use the abbreviated rate setting process contained in K.A.R. 82-1-231 (b)(3) to include in Westar's rates the costs associated with investments in grid resiliency projects discussed in paragraph 20 of the S&A, 92 and the final roll-in ofECRR costs discussed in paragraph 19 of the S&A. 93
- 58. Allocation Among Classes: The Joint Movants propose that the rate increase be allocated among the respective classes of customers according to the amounts indicated for each class as shown in Appendix A of the S&A, and that rates should be adjusted as shown in Appendix B of the S&A. 94
- 59. Creation of Standard Residential Distributed Generation Tariff: The Joint Movants propose that Westar be allowed to create a Standard Residential Distributed Generation Tariff. 95 Residential customers who install distributed generation after October 28, 2015, would be required to take service pursuant to the terms of this new tariff. 96 The initial rates and rate structure for the Standard Residential Distributed Generation Tariff would be identical to Westar's Standard Residential Tariff, as determined in this rate case. 97 Residential customers who install distributed generation after October 28, 2015, and are placed on the Standard Residential Distributed Generation Tariff, will not be considered grandfathered or exempt from future changes in rates or rate structures for distributed generation customers approved by the 91 Id. at if 35.
92 Id. at if 36. 93 Id at if 36. 94 Id at if 37. 95 Id at if 38. 96 S&A at if 38. 97 Id. at if 38. 21'
Commission in either a generic docket proposed in paragraph 39 of the S&A (as amended), or in any other Commission proceeding. 98 Westar would provide notice to all customers applying for service under the Standard Residential Distributed Generation Tariff that the rates and rate structures contained therein are subject to change, and that any such future rate or rate structure change could impact the economics of the customer's distributed generation. 99
- 60. Generic Docket Proposal as Amended by Addendum: The Joint Movants and Solar Parties agree that the issue of whether a separate Residential Standard Distributed Generation Tariff is necessary, and, if so, how to structure the Residential Standard Distributed Generation Tariff in order to properly recover just and reasonable costs from customers with distributed generation should be deferred to a generic docket. 100 Westar and Staff proposed working together to develop a procedural schedule for a generic docket in order to ensure timely resolution of distributed generation issues to be addressed. 101 The Joint Movants agree that they will not oppose or seek to limit the participation of the Solar Parties in the generic proceeding. 102
- 61. Residential Customer Charge: The Joint Movants propose that the monthly basic service fee be $14.50 for all residential classes except for the Peak Management. 103 The Joint Movants proposed the monthly basic service fee for the Peak Management Rate be $16.50. 104 These basic service fees would not be adjusted in the abbreviated rate case discussed in paragraphs 35-36 of the S&A.
- 62. Elimination of High Load Factor (HLF) schedule and creation of new schedules:
The Joint Movants propose that the HLF rate schedule be eliminated and two new rate classes be 98 Id. at if 38. 99 Id. at if 38. 100 Unopposed Addendum, Addendum to Stipulation and Agreement. 101 Id. 102 Id. 103 S&A at if 40. 104 ld. at if 40. 22
created as proposed in the Direct Testimony of Westar witness John Wolfram. 105 Customers with billing demands greater than 1,000 kW and up to 25,000 kW would qualify for the Large General Service (LGS) class and customers with billing demands greater than 25,000 kW would qualify 106 for the Industrial & Large Power (ILP) class. As proposed, customers moving to a new class as a result of this change would be moved at the beginning of the first complete billing cycle following the issuance of the Commission's order in this docket. 107 This provision was further clarified at the evidentiary hearing to mean the first billing cycle occurring after the effective date of the final order in this docket. 108 In order to miilimize the impact on customers that are required to move to the LGS class as a result of the Joint Movant's S&A proposed changes, the Joint Movants proposed that Westar's next Transmission Delivery Charge (TDC) filing use the recalculated 12 Coincidental Peak (CP) which takes into account CP data from these customers being moved to the appropriate class. 109
- 63. Small General Service Basic Service Fee: The Joint Movants propose that the monthly basic service fee for the small general service customer class be set at $22.50. 110
- 64. Separation of Grid Resiliency Costs: The Joint Movants propose that no part of the increase in revenue requirement in the abbreviated rate case associated with investments in grid resiliency be allocated to the LGS, ILP, large tire manufacturer (LTM), interruptible service (IS) classes, or special contract customers. 111 Grid Resiliency Costs would be allocated to the remaining customer classes in the abbreviated rate case based on the same percentages reflected 105 Id. at, 41.
106 Id. at, 41. 107 Id. at~ 41. 108 Transcript of Evict. Hearing at 50. 109 S&A at ~ 41 (a).
- 110 Id. at, 42.
111 Id. at~ 43. 23
in Appendix A of the S&A but adjusted proportionally to reflect the exclusio~ of the LGS, ILP, LTM, IS, and special contract customers from the allocation. 112
- 65. Remainder of Revenue Increase: The Joint Movants propose that the remainder of the increase in revenue requirement in the abbreviated rate case will be allocated based on the same percentages reflected in Appendix A of the S&A. 113
- 66. Continuin~ Discussions: The Joint Movants propose that Westar agree to continue discussions regarding a potential multi-site rate for medium general service customers, and, if appropriate, propose such a rate structure in the abbreviated rate case. 114
- 67. Study Delivery Voltage Cost: The Joint Movants propose that Westar agree to study the potential of making further changes to the delivery voltage cost differences and, if appropriate, make any changes in the next general rate case. 115 If Westar determines no additional changes are appropriate, Westar will present evidence explaining the reason for that determination. 116
- 68. Miscellaneous Provisions: The Joint Movants propose several miscellaneous provisions to the S&A that indicate nothing in the S&A is intended to impinge or restrict in any manner the exercise by the Commission of any statutory right, including the right of access to information, or any statutory obligation, including the obligation to ensure that Westar is providing efficient and suffident service at just and reasonable rates. The S&A also detailed a number of privileges regarding the filing of testimony to support positions, the cross-examination of witnesses, and standard language typically included in S&As. 117 112 Id.
113 Id. at, 44. 114 Id. at, 45. 115 S&A at, 46. 116 Id. 117 Id. at~, 47-51. 24
C. Standard of Review
- 69. Rates, fares, tolls, and charges imposed by a public utility upon its customers are required to be just and reasonable, not unjustly or unreasonably discriminatory and not unduly preferential. 118
- 70. The Commission, in setting rates for an electrical utility, must fix rates within a "zone of reasonableness" after balancing interests of the utility's investors, ratepayers, and
. 119 publ lC.
- 71. The Kansas Supreme Court mandates the Commission consider and balance the interests of the utility's investors vs. the ratepayers, the present ratepayers vs. the future ratepayers, and the public interest. 120 "[C]ases in this area clearly indicate that the goal should be a rate fixed within the zone of reasonableness after the application of a balancing test in which the interests of all concerned parties are considered." 121 "There is an elusive zone of reasonableness Kansas courts have recognized when reviewing utility rate decisions. [A] court can only concern itself with the question as to whether a rate is so unreasonably low or so unreasonably high as to be unlawful. The in-between point, where the rate is most fair to both the utility and its customers, is a matter for the Commission's determination." 122
- 72. In addition to Kansas' own statutes and case law on the subject, the U.S. Supreme Court has established certain principles for the Commission to follow when reviewing rate change applications. Bluefield Watenvorks & Imp. Co. v. Pub. Serv. Comm 'n of W Va., 262 U.S.
679 (1923), and Fed. Power Comm 'n v. Hope Natural Gas Co., 320 U.S. 591 (1944), provide what 118 Grindsted Products, Inc. v. Kansas Corp. Com 'n, 262 Kan. 294, 309 (1997); K.S.A. 66-lOld. 119 Kansas Gas and Elec. Co. v. State Corp. Com 'n, 239 Kan. 483, 488 (1986). 120 Id. at 488. 121 See id. (internal quotation omitted) 122 Aquila, Inc. v. State Corp. Comm 'n ofState, No. 94,326, 2005 WL 1719705 at *2 (Kan. App. Jul. 22, 2005). 25
this Commission has referred to as the "capital attraction standard." 123 "The return [on investment] should be reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties." 124 "That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital." 125 The court has also stated however, "a rate of return may be reasonable at one time and become too high or too low by changes affecting opportunities for investment, the money market and business conditions generally. 126 Also in Hope Natural Gas, the U.S. Supreme Court promulgated what this Commission refers to as the "comparable earnings standard." 127 "By that standard the return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks" which would include not only service on a utility's debt but also dividends on the stock. 128 This, as Westar noted in its Application, does not guarantee it will actually earn its authorized return. 129 "[R]egulation does not insure that the business shall produce net revenues, nor does the Constitution require that the losses of the business in one year shall be restored from future earnings by the device of capitalizing the losses and adding them to the rate base on which a fair return and depreciation allowance is to be eamed." 130 These standards taken together stand for the general idea that the return provided to a 123 Order Approving Non unanimous Stipulation and Agreement with Modification at 3, Joint Application of Westar Energy, Inc. and Kansas Gas and Electric Co.for Approval to Make Certain Changes in Their Charges/or Electric Service, Docket No. 12-WSEE-112-RTS (Apr. 18, 2012) [hereinafter 12-112 Docket]. 124 Bluefield Waterworks & Imp. Co. v. Pub. Serv. Comm 'n of W. Va., 262 U.S. 679, 693 (1923) (emphasis added). 125 Fed. PowerComm'nv. Hope Natural Gas Co., 320 U.S. 591, 603 (1944). 126 Bluefield Waterworks, 262 U.S. at 693. 127 12-112 Docket at 3. 128 Hope Natural Gas, 320 U.S. at 603. 129 Application at I 0. 13
°Fed. Power Comm'n v. Natural Gas Pipeline Co. ofAm., 315 U.S. 575, 590 (1942).
26
utility's investors should (1) be consistent with other businesses having similar risks and (2) the adequacy of the return for servicing debt and paying dividends be able to support a utility's credit quality, access to capital, and financial integrity. "The KCC is required to balance the public need for adequate, efficient, and reasonable service with the public utility's need for sufficient revenue to meet the cost of furnishing service and to earn a reasonable profit." 131
- 73. The Commission may accept a settlement agreement provided an independent finding is made, supported by substantial evidence in the record as a whole, that the settlement will establish just and reasonable rates. 132 The Commission may utilize a five-element test to aid in the review of settlement agreements. 133
- 1. Was there an opportunity for the opposing party to be heard on the reasons for opposition to the Stipulation and Agreement?
- 74. For a variety of reasons discussed in previous Commission Orders in this docket, not every party to this proceeding was able to participate in initial settlement discussions. 134 Notwithstanding the fact that the S&A is unanimously supported by the Joint Movants, it would be premature for the Commission to conclude from this fact alone that there were no opposing parties. The Commission must also tum to the parties who were not permitted to engage in settlement discussions to gauge their support or opposition to such agreement. Westar in the Unopposed Addendum-established the first instance that all parties were either: (1) in support of the S&A or, 135 (2) unopposed to the S&A's approval. 136 131 Danisco Ingredients USA, lnc. v. Kansas City Power & light Co., 267 Kan. 760, 773 (1999).
132 Citizens' Util. Ratepayer Bd v. State Corp. Comm 'n ofState of Kansas, 28 Kan. App. 2d 313, 316 (2000). 133 Order Approving Contested Settlement Agreement at 5-6, Application of Atmos Energy for Adjustment of Its Natural Gas Rates in the State of Kansas, Docket No. 08-ATMG-280-RTS (May 12, 2008). 134 See e.g. Final Procedural Order. 135 See S&A at 14-19. 136 Unopposed Addendum at 3. 27
- 75. The majority of the parties who were unable to participate in the creation of the S&A were the Solar Parties. However, as noted in Westar's Unopposed Addendum, the Solar Parties agreed not to oppose the S&A, and not to cross-examine any witnesses who may have testified in support of the S&A at the evidentiary hearing. 137 These were rights that the Commission had expressly granted to TASC, CEI, Brightergy, and EDF. 138 CEP was not allowed to participate at the evidentiary hearing and was thus not conferred these rights. 139 However, CEP also concurred with the other Solar Parties that it did not oppose the S&A. 140 Westar's Unopposed Addendum makes it clear to the Commission that the Solar Parties are not opposed to the S&A.
- 76. Settlement agreements revolve around compromise to reach reasonable outcomes.
The S&A presented by the Joint Movants is a global settlement. It resolves all outstanding issues between the Joint Movants. 141 A careful review of the S&A, and the detail to which it discusses dozens of separate items, makes it clear to the Commission that the Joint Movants to the S&A intended to resolve all disputes between them, and had ample opportunity to advocate their respective interests. Every signatory to the S&A is in favor of the agreement. There are no parties opposed to the S&A who were allowed to participate in either its creation, or the subsequent filing of an addendum as Westar noted in its Unopposed Addendum. 142 Additionally, no party to this proceeding has logged an objection to the S&A as required by K.A.R. 82-1-230a. 137 Id. 138 Final Procedural Order at 14, 18-19, 22, 27. 139 Id. at 25. 140 Unopposed Addendum at 3. 141 S&A at 12. 147
- Unopposed Addendum at 3.
28
- 77. The only remaining party who did not participate in settlement discussions is the IBEW. IBEW had previously indicated it had no position regarding Westar's Application, 143 and when granted intervention, they were prohibited from participatin~ at the evidentiary hearing. 144 IBEW did not petition the Commission for reconsideration of its intervenor status, and made no motion or argument despite being present at the evidentiary hearing through counsel that would otherwise indicate IBEW's opposition to the S&A.
- 78. No party has offered any formal objection to any term contained within the S&A.
Pursuant to K.A.R. 82-1-230a(c), a party objecting to a settlement agreement must file a written objection within 10 days after the filing of the settlement agreement unless a shorter time-period is ordered by the Commission. Failure to do so constitutes a waiver of a party's right to object to a settlement agreement. 145
- 79. Therefore, after examining all of the parties' respective roles and degrees of participation in this proceeding, the Commission finds that all parties had an opportunity to be heard on any opposition to the S&A, and that no parties are opposed to the adoption and approval of the S&A.
- 2. Is the Stipulation and Agreement supported by substantial competent evidence in the record as a whole?
- 80. The record to this proceeding is extensive and comprehensive. The Commission will not attempt to summarize the entire record as established in this proceeding. As discussed above, dozens of witnesses have filed testimony outlaying and defending positions while criticizing others. The Commission has reviewed the direct, cross-answering and rebuttal testimony as supplied by the parties. Further, the Commission has taken into* consideration over 143 Petition to Intervene at 3 (Jul. 16, 2015).
l4-I Order Granting Limited Intervention at 2-3 (Aug. 11, 2015). 145 See K.A.R. 82-l-230a(c). *
. 29
1,500 public comments submitted in this proceeding. Because all parties to this docket are either in support of or unopposed to the adoption and approval of the S&A as amended, the Commission will undertake a more comprehensive review of the four witnesses who testified in support of the S&A.
- 81. Mr. Greenwood testified that the S&A is supported by substantial competent evidence when viewing the record as a whole. 146 Mr. Greenwood detailed the initial position of Westar, and how accounting adjustments proposed by other parties later became reflected in Westar's rebuttal testimony. 147 Mr. Greenwood detailed how the S&A in terms of the net revenue requirement incorporates pieces from and is supported or agreed to by a number of parties. 148 Mr. Greenwood expanded upon individual terms contained within the S&A, and provided ample evidence indicating multiple witnesses from diverse parties supported the variety of positions. 149
- 82. Mr. Grady submitted testimony in support of the S&A. Mr. Grady noted the S&A "resolves all contested issues related to the revenue requirement [class cost of service] and rate design in this docket." 150 Specifically, Mr. Grady testified to: Westar's net overall annual revenue increase, the re basing of rates, rate case expense true-up, bad debt expense, Pension and OPEB Expenses, the Nuclear Decommissioning Trust Fund, the analog retirement and regulatory asset, the discontinuance of the ECRR, grid resiliency projects and ratemaking treatment, the proposed security tracker, return on equity and capital structure, Kansas-jurisdictional non-transmission related retail property tax expense, deferred income tax expense and amortization of 146 Testimony of Greg A. Greenwood in Support of Stipulation and Agreement at l I-I4 (Aug. I I, 2015) [hereinafter Greenwood S&A Testimony].
147 Id. at l I-12. 148 Id. at I2. 149 See id. at I2-I4. 150 Testimony in Support of Stipulation and Agreement Prepared by Justin T. Grady at 3 (Aug. 11, 2015) [hereinafter Grady S&A Testimony]. 30
investment tax credits, amortization periods, pension trackers, and abbreviated rate case procedures and issues. 151
- 83. Mr. Grady detailed that Westar's initial Application, and the rigorous scrutiny that it was subject to from not only Staff, but also CURB and other intervenors created a body of evidence for the Commission to consider. 152 The Joint Movants accordingly relied on this body of evidence when they negotiated the terms of the S&A. 153 Mr. Grady noted that the terms contained in the S&A are comparable with an outcome that could be expected if the case were to be fully litigated. 154
- 84. Mr. Grady concluded that the S&A represents a reasonable resolution of the issues and matters contained within this docket, is in the public interest, is supported by substantial competent evidence in the record, and falls within the realm of reasonable debate and the zone of reasonableness. 155
- 85. Dr. Glass submitted testimony in support of the S&A. Specifically, Dr. Glass testified to numerous rate design issues such as: class revenue allocation, rate consolidation for High Load Factor North & South customers, structural problems between Medium General Service and High Load Factor classes, secondary primary and transmission service for High Load Factor Customers, renewable resource tariffs, customer charges, distributed generation issues, the Economic Development Rider, revenue requirement allocation in the proposed abbreviated rate case, and miscellaneous non-controversial issues.
151 Id. at 3-9. 152 Id. at 10-11. 153 Id. at 11. 154 Id. 155 Id. at 16. 31
- 86. Dr. Glass concluded in his testimony that the S&A represents a realistic resolution of rate design issues, and that the proposed rate design in the S&A will result in just and reasonable rates. 156 Ultimately, Dr. Glass states that the S&A is in the public interest, is supported by substantial competent evidence in the record, and should be approved by the Commission in total. 157
- 87. Ms. Crane, on behalf of CURB, testified that the S&A is supported by substantial competent evidence when viewed from the record as a whole. 158 Ms. Crane first testified to the parties' initial positions. 159 Ms. Crane explained that using the capital structure and cost of debt as provided by Westar that was adopted by CURB, and utilizing a 9.35% cost of equity, would increase CURB's net revenue requirement from $50.80 million to $72.31 million. 160 Ms. Crane expanded on this by saying it was difficult to provide an item-by-item settlement on issues contained within the S&A as some issues increased the net revenue requirement while some issues decreased the net revenue requirement. 161 Taking into account the pre-tax return of 10.926% as contained within the S&A, Ms. Crane stated the net revenue increase was close to CURB's recommended increase, and fell within the range provided by other parties to the proceeding. 162 Ms. Crane then undertook a review of how the net revenue increase would be allocated amongst the classes as well as the monthly service charges for residential and small commercial customers. 163 Ms. Crane indicated that the revenue allocations contained within the 156 Testimony in Support of Stipulation and Agreement Prepared by Robert H. Glass, PhD at 3 (Aug. 11, 2015)
[hereinafter Glass S&A Testimony]. 157 Id. at 3. 158 Testimony in Support of Stipulation and Agreement Andrea C. Crane on Behalf of CURB at 9-11 (Aug. 11, 2015) [hereinafter Crane S&A Testimony]. 159 Id. at 2-3. 160 Id. at 10 161 Id. 162 Id. at 10-11. 163 Id. at 11. 32
S&A appear to be reasonable, and that the proposed customer charges fall within ranges provided by the parties. 164
- 88. The Commission finds that the record established prior to settlement discussions, and supplemented with testimony and evidence in support of the S&A, establishes a thorough and complete record to fully and adequately prepare an S&A. Parties to this proceeding relied on data provided either by their individual institutions, or by others. As parties to this proceeding engaged in attentive settlement discussions, they relied on the information contained within this docket to strike a realistic compromise that could be supported or defended with information contained in the record. To supplement the parties' respective positions in support of the terms of the S&A, the parties to this proceeding submitted additional testimony.
- 89. The testimony and evidence submitted throughout the entirety of this proceeding provided a substantive body of evidence on which to base compromises struck within the S&A.
The witnesses who testified and submitted evidence are experts in their respective fields. As such, they provided competent information not only for parties to use when negotiating, but also for the Commission to review when determining the reasonableness of the S&A and its terms. Therefore, the Commission concludes that substantial competent evidence supports the S&A as amended when viewed through the record as a whole.
- 3. Does the Stipulation and Agreement conform with applicable law?
- 90. At the outset, it is important to note that no party to this proceeding has raised the slightest concern that the proposed S&A may be unlawful. Regardless, the Commission is required to undertake its own independent review. 165 Determining whether an S&A conforms with applicable law requires the Commission to assume that the S&A would be approved and be 164 Crane S&A Testimony at 11.
165 See Citizens' Util. Ratepayer Bd. v. State Corp. Comm 'n ofState ofKansas, 28 Kan. App. 2d 313, 316 (2000) .
.J.J
subject to judicial scrutiny the same as any other order of the Commission. In other words, would the S&A conform to applicable law and survive judicial review if the Commission had established the terms of the S&A under its own judgment? Such an inquiry requires the Commission to examine the reasonableness and lawfulness of the order.
- 91. An order of the Commission is lawful if it is within the statutory authority of the Commission, and if the prescribed statutory and procedural rules are followed in the making of the order. 166 The Commission has wide discretion from the legislature regarding rates for public utilities.1 67 Sp*ecifically, K.S.A. 66-117 requires public utilities, such as Westar, seek Commission approval prior to changing any rate for which it charges customers for the use of electricity. After reviewing the testimony,. it is undeniable that parties to this proceeding had disputes among their respective initial positions. However, *"the law favors the amicable settlement of disputes." 168 It follows that if parties come to such a resolution, their resolution could seek to adjust rates for a public utility. The adjustment of rates agreed to via compromise between parties is still subject to Commission approval. Therefore, it is well within the lawful authority and jurisdiction of the Commission to consider this S&A as amended as it adjusts rates for a public utility subject to the Commission's jurisdiction and oversight.
- 92. Rates established by the Commission must be just and reasonable. 169 In developing five questions to review settlement agreements, the Commission dedicated one question to examine the "just and reasonable" standard alone. As such, the Commission defers discussion of that item to a separate part of this order.
166 Cent. Kansas Power Co. v. State Corp. Comm 'n, 221 Kan. 505, 511. ( 1977). 161 Id. .
- 168 Int'l Motor Rebuilding Co. v. United Motor Exch., Inc., 193 Kan. 497, 499 (1964).
169 K.S.A. 66-IOlb. 34
- 93. The Parties and the Commission complied with all procedural rules within this docket. The Parties and the Commission complied with the procedural schedules, the issuance of orders and the disposition of preliminary matters in accordance with the Kansas Administrative Procedure Act, K.S.A. 77-501 et seq., which K.S.A. 66-117 requires the Commission to follow when reviewing a public utility's application to change rates. The Commission may therefore find that the prescribed statutory and procedural rules for reviewing the* S&A and issuing .this order have been followed.
- 94. Orders issued by the Commission are considered reasonable if they are based upon substantial competent evidence. 170 Applying the same standard to the S&A that is applied to orders issued by the Commission, it is clear to see that the S&A is based upon substantial competent evidence. The Commission's standard has been to review settlement agreements in light of the record as a whole. This allows the Commission to determine where such an agreement and its terms lie in relation to the terms of the previously articulated positions of the parties. Upon examining the record as a whole, it is clear that there is ample evidence used to support the parties' initial positions, and ample evidence to support how the parties were able to reach a negotiated settlement. The proceedings established the scope and breadth of the record in this case as discussed above. 171 The Commission finds that such a thorough record, and supplementary filings used to support the S&A as amended, establishes that substantial .
competent evidence necessary to support such an S&A as amended.
- 95. The Commission therefore finds that the S&A as amended complies with applicable law.
17
°Cent. Kansas Power Co., 221 171 Kan. at 511.
See supra Part I.C. 35
- 4. Does the Stipulation and Agreement result in just and reasonable rates?
- 96. Electric Public Utilities, such as Westar, are required to provide reasonably efficient and sufficient service at just and reasonable rates. 172 In determining what constitutes a just and reasonable rate, the Commission has broad discretion. 173 As promulgated by the U.S.
Supreme Court and adopted by the Kansas Court of Appeals, just and reasonable rates must fall within a "zone of reasonableness" 174 As Dr. Glass testified, the initial filed positions from all of the signatories to the S&A represents the "zone of reasonableness" for the Commission to consider. 175
- 97. Westar Witness Mr. Greenwood testified in support of the S&A. 176 Ultimately, Mr. Greenwood testified that the rates proposed in Appendix B to the S&A would either remain in-line or below 2014 national averages. 177 Mr. Greenwood testified that he expected national electric rates to rise in the future, which in tum would mean Westar's electric rates (as proposed by the Joint Movants) would be even lower than national averages. 178 Mr. Greenwood states he believed the rates proposed in Appendix B to the S&A were just and reasonable, and requested this Commission approved them. 179 The Commission concurs with Mr. Greenwood's summation and rationale.
- 98. Dr. Glass testified on the "Balancing Test" that Kansas courts have developed when reviewing the zone of reasonableness standard. 180 Specifically, Dr. Glass conducted a 172 K.S.A. 66-IOlb.
173 Citi:;ens' Util. Ratepayer Bd. v. State Corp. Comm 'n of State, 47 Kan. App. 2d 1112, 1131 (2012). 174 Kansas Gas and Elec. Co., 239 Kan. at 488. 175 Glass S&A Testimony at 15. 176 Greenwood S&A Testimony at 2. 177 Id. at 16. 178 Id. 179 Id. 180 Glass S&A Testimony at 14. 36
review of the interests of: investors vs. ratepayers, present ratepayers vs. future ratepayers, and the public interest. 181 Dr. Glass' testimony in support of the proposed S&A compels a finding favorable on these specific items. 182
- 99. Ultimately, Dr. Glass concluded that the S&A was a realistic resolution of rate design issues outlined in this proceeding, that the proposed rate design is just and reasonable, that the agreement is supported by substantial competent evidence, and should be approved. 183 The Commission concurs with Dr. Glass' summation and rationale.
100. Mr. Grady testified that he believed the rates established in the S&A would result in rates that fall within the "zone of reasonableness." 184 Mr. Grady testified that the agreed-to revenue requirement increase struck the appropriate balance between Westar's desire to have assurance that it could earn sufficient revenue and cash flow to meet its financial obligations, and the desire of the ratepayer to keep rates low while maintaining reliable electric service. 185 Mr. Grady further theorized that if any particular party to settlement negotiations took issue with an unfavorable term related to their respective interest, they would not have joined or conceded to the S&A. 186 Therefore, because multiple rate classes with widely different interests were represented and later joined together to become signatories to the S&A, Mr. Grady concluded that the proposed terms of the S&A, specifically the revenue increase, could be viewed as reasonable from the viewpoint of the signatories. 187 As Mr. Grady postulates, if the terms were 181 Id. at 14-16. 182 Id. 183 Id. at 16. 184 Grady S&A Testimony at 13. 185 Id. at 13-14. 186 Id. at 14. 181 Id. 37
not just or reasonable, then a unanimous S&A could not have been reached. 188 The Commission concurs with this summation. 101. Ms. Crane testified m support of the S&A on behalf of CURB. Like Mr. Greenwood, Dr. Glass, and Mr. Grady, Ms. Crane testified that approval of the S&A would result in just and reasonable rates. 189 Ms. Crane spoke specifically to the terms of the S&A, and how Westar' s net revenue increase in the S&A was approximately 51 % of what Westar had initially proposed in its Application, and only 8% above CURB's net revenue increase as adjusted. 190 102. Ms. Crane also testified positively in support of the elimination of the ECRR, reduced customer charges, grid resiliency, retired analog meters, and the EDR. 191 Taken together, Ms. Crane testified as to how these terms as outlined in the S&A are beneficial to Kansas ratepayers, and ultimately concluded that the S&A would result in just and reasonable rates. 192 103. The requirement that just and reasonable rates fall within a zone of reasonableness is used to determine whether a particular rate is contained within an "elusive range of reasonableness in calculating a fair rate of return." 193 The Commission acts within the discretion granted to it when it searches for and finds an iq.-between point "where the rate is most fair to the utility and the customers." 194 The Commission has reviewed the filed positions of the parties. The Commission has also examined in detail the impact to individual customer classes as outlined to the various appendices to the S&A. The Joint Movants are unanimously in support of 188 /d. 189 Crane S&A Testimony at 13. 190 Id. 191 Id. at 13-14. 192 Id. at 14.
- 19'~Kansas Gas and Elec. Co., 239 Kan. at 490.
19.i Id. 38
the S&A as amended and neither the Solar Parties nor the IBEW are opposed to the amended S&A's approval. No evidence has been presented to the Commission suggesting that approval of the rates as described by the S&A would in any way be unjust or unreasonable, or make service unaffordable to customers. Therefore, the terms of the S&A as amended will result in rates that are not unduly burdensome, unduly preferential, or unreasonably discriminatory. 104. The Commission has also reviewed the terms of the S&A and its impact on the relationship between the utility's investors, the present ratepayer's and future ratepayers, and the public interest. The Commission has set aside as a separate question whether the S&A is in the public interest and will defer discussion on that item until the next section of this order. 105. The Commission finds the terms contained within the S&A fall within a zone of reasonableness and appropriately balance the interests of the Westar's investors with ratepayers, and with present ratepayers vs. future ratepayers .. The evidence submitted in this proceeding has compelled the Commission to find that the S&A as amended will allow the utility to continue to meet its financial obligations while earning a return on investment that is commiserate with businesses of similar risks. The Commission further finds that ratepayers will benefit from the S&A as amended as they will continue to have access to affordable electricity. at or below national average costs with the confidence that Westar will continue to be able to provide such service. Moreover, the Commission finds the S&A as amended protects and balances the interests of current and future ratepayers. Terms contained within the S&A as amended are designed to maintain or improve service quality while maintaining low costs. Additionally, the S&A takes proactive steps to ensure cross-subsidization is mitigated (e.g. grid resiliency cost allocation and the deferment of unique distributed generation terms until the completion of a generic docket). 39
106.
- The Commission has taken into consideration the competing interests as described by the Court when the Commission exercises its power in the setting of rates. The Commission finds that the agreed-upon net revenue increase and terms of the S&A as amended fall within the zone of reasonableness to which the Commission must adhere. The S&A as amended represents a series of compromises set and agreed to by the Joint Movants, and upon further concession, unopposed by the Solar Parties and IBEW. The rates established by the S&A will allow Westar to continue to meet its financial obligations, as well as its statutory obligation to provide efficient and sufficient service at just and reasonable rates. Therefore, the Commission finds the S&A, the rates and rate structures contained within, and specific terms of the S&A will result in just and reasonable rates for Westar's customers.
- 5. Are the results of the Stipulation and Agreement in the public interest, including the interest of customers represented by any party not consenting to the agreement?
107. Mr. Greenwood testified that the rates Westar customers would pay if the S&A were to be approved included approximately 96% of the expected La Cygne investments. 195 Mr. Greenwood also testified that the rate specific classes customers would pay, as proposed by the S&A is supported by the numerous class cost of service studies that had been provided in this
- docket, and that the increased customer charge helped better align customer rates with Westar's costs. 196 108. Mr. Greenwood testified that Westar's customers would see benefits from additional investments in grid resiliency programs, digital meters, approval of certain solar 195 Greenwood S&A Testimony at 17.
196
/d. at 17-18.
40
programs and reductions in prices for renewable investment options. 197 Regarding specific tariffs, Mr. Greenwood testified in support of a generic docket to study distributed generation issues, and also explained how changes to industrial and commercial rate structures would better reflect the principles of cost causation in rate designs for larger customers. 198 Mr. Greenwood concluded that the approval of the S&A and the rates identified in Appendix A to the S&A would be in the public interest. 199 The Commission concurs with Mr. Greenwood's assessment. 109. Dr. Glass testified that the public interest is served when the utility remains a "healthy, viable business able to provide reliable service."200 Dr. Glass stated that under the proposed rate plan, ratepayers would be protected from unrealistic price increases, undue discrimination, and unreliable service while at the same time allowing Westar to recover the revenues necessary to comply with environmental mandates. 201 While the end result of distributed generation has not been settled within the S&A, Dr. Glass noted that the generic docket outlined in the S&A provides* a path forward to reach potentially better decisions. 202 Ultimately, Dr. Glass concluded that the S&A is in the public interest. 203 The Commission concurs with Dr. Glass' assessment. 110. Mr. Grady testified that the public interest is served "when ratepayers are protected from unnecessarily high prices, discriminatory prices and/or unreliable service."204 According to Mr. Grady, because varied interests were able to collaborate and present a 191 Id. 198 Id. at 19. 199 Id. 200 Glass S&A Testimony at 16. 2ot Id. 202 Id. 203 Id. 20
-1 Grady S&A Testimony at 15.
41
unanimous resolution of the issues in this case, the public interest standard has been met. 205 Mr. Grady then detailed five examples on how the public interest would be satisfied. 206 For example, Wes tar's requested revenue is reduced to a level that Westar still finds reasonable while at the same time decreasing the proposed cost customer~ would bear. The public will not have to potentially absorb _the cost of a fully-litigated hearing, and the utility will continue to meet its financial obligations while providing sufficient and efficient service. 207 The Commission concurs with Mr. Grady's assessment. 208 111. Ms. Crane also testified that approval of the S&A is in the public interest. Ms. Crane described how the S&A was a significant reduction from Westar' s initial request, and how the customer charge would be set much lower than Westar's initial request and remain at that level until Westar's next general rate case. 209 Ms. Crane further expanded on the importance of rate stability, how the S&A withdraws certain proposals CURB took particular opposition to, how the S&A authorizes a return on investment that is significantly lower than Westar's present authorized return, the elimination of riders and how Westar's grid resiliency program costs would be recovered. 210 Ms. Crane concluded her remarks by stating "while the S&A represents a compromise of the positions put forth by the parties in this case, on balance I believe the S&A is in the public interest."211 The Commission concurs with Ms. Crane's assessment. 112. To support a finding that the S&A is in the public interest the Commission must examine the information as filed in this docket and conclude that the interests of the ratepayers and Kansans will continue to be promoted if the S&A were to be approved. Westar, Staff 20s Id. 206 Id. 207 Id. at 16. 208 Crane S&A Testimony at 14. 209 Id. at 14-15. 210 Id. at 14-16. 211 Id. at 16. 42
(submitting testimony for multiple signatories), and CURB have all testified regarding dozens of provisions contained within the S&A and detailed how those terms are in the public's interest. The Commission's focus for this inquiry turns on the result or total effect of the S&A as amended. The manner in which the terms of the S&A were constructed evidences the S&A is in the public interest. Multiple parties from a diverse set of interests encompassing large ranges of
- industrial, commercial, residential and specialty customers have all concluded that the terms of the S&A will allow them to continue to take service from Westar in a manner acceptable to them. The S&A as amended will allow multiple entities to undertake a review of distributed generation concerns before any changes in service are proposed. The S&A allows Westar to recover costs from prudently incurred expenses and continue to make reliability enhancements to Kansas' electric grid. Based upon the wide ranging support and lack of opposition to the S&A, as well as how the S&A will affect ratepayers if approved, the Commission is confident in finding that approval of the S&A is in the public interest.
Ill. Abbreviated Rate Case 113. The Joint Movants request Westar be granted preapproval to file an abbreviated rate case. Pursuant to K.A.R. 82-1-23 l(b)(3), a utility proposing to change rates within 12 months after a Commission order is issued in a general rate proceeding may do so without submitting duplicative information provided certain conditions are met. 114. First, the utility must be willing to adopt all regulatory procedures, principles, and rate of return established by the Commission in the order setting rates from the general rate 43
case. 212 Second, the utility must receive prior approval from the Commission before filing such an abbreviated rate case. 213 115. Consistent with the terms contained within the S&A, the Commission grants Westar's request to file an abbreviated rate case no later.than one year from the effective date of this order. 116. The Commission hereby limits matters to be addressed during Westar's abbreviated rate case to items specifically listed and identified in the S&A as being subject to the abbreviated rate proceeding. IV. Generic Docket 117. As contemplated by the S&A, the parties to this proceeding wish to conduct a general investigation to research and evaluate specific issues related to distributed generation (particularly solar distributed generation). The Commission concurs that a generic docket is the appropriate m_ethod of identifying and discussing issues related to distributed generation before a public . utility implements distributed generation-specific rates in the public utility's service territory. The Commission hereby directs Staff to file a Report and Recommendation outlining specific issues to discuss, research and evaluate in a manner consistent with the terms of the S&A as amended. The Commission directs Staff to coordinate with the parties to this proceeding and other Kansas-jurisdictional public utilities on the initial outlaying of issues. The Commission understands that such an evaluation will take considerable time, and therefore directs Staff begin such an undertaking with all due haste. 212 See K.A.R. 82-1-23 l(b)(3)(A). 213 K.A.R. 82- 1-23 I (b )(3)(8). 44
V. Findings and Conclusions 118. The Commission has examined the statutory and legal standards the Commission must consider when reviewing a request for rate changes, and has examined the voluminous record as a whole developed in this proceeding. 119. Upon reviewing the terms contained within the S&A, the Commission accepts the terms detailed within the S&A and as amended by the Unopposed Addendum. 120. The Commission finds that approval of the S&A as amended by Addendum would result in just and reasonable rates that would enable Westar to continue to provide sufficient and efficient service. The Commission finds that the rates established by the S&A conform and fall within the zone of reasonableness that properly balances the interests of the parties to this proceeding, the ratepayers, and the public. 121. The Commission finds that there was ample opportunity for parties to this proceeding to voice opposition to such agreement, and that the end result of unanimous support, or agreement not to oppose, provides evidence for such a conclusion. Therefore, the Commission concludes that all parties have had the opportunity to fully examine and critique the S&A as amended. 122. The Commission finds that the S&A is supported by substantial competent evidence from not only witnesses who testified in support of the S&A, but also how the terms of the S&A were constructed as a compromise from each party's respective initial position. Therefore, the Commission concludes that the S&A is supported by substantial competent evidence as filed in this proceeding. 123. The Commission finds that approval of the S&A as amended is in the public interest. 45
124. Upon reviewing the S&A, its terms individually, the parties' filed positions in this proceeding, testimony and evidence in support of the S&A, and amendments to the S&A as late filed by Westar, the Commission finds that the Joint Motion to Approve Stipulation and Agreement and amendments thereto should be granted. 125. The procedural schedule set October 28, 2015, as the effective date of the proposed rate change to take effect. 214 Pursuant to K.S.A. 66-:-11 ?(b), the Commission may elect to hold a hearing on a public utility's proposed rate change. Pursuant to K.S.A. 66-117(c), the Commission cannot delay the effective date of a proposed rate change beyond 240 days from the date of the filing unless certain exemptions exist. The Commission finds that, having concluded approval of the S&A as amended is appropriate, the Commission must now set an effective date for such proposed changes. The Commission finds that given the date suggested in the notice of proposed rate changes that Westar sent to its customers, the effective date of any proposed rate change must remain October 28, 2015. This date complies with K.S.A. 66-117(c) in terms of suspension periods, is permitted by K.S.A. 66-1l7(b) as Westar would have to submit new rate schedules subject to a Commission-set effective date, and is consistent with the proposed effective date as detailed in the 15-025 Docket. Westar may file schedules necessary to implement the terms of the S&A as amended at any time. However, no schedule filed in accordance with the S&A as amended will become effective until October 28, 2015. 214 Prehearing Officer Order Taking Administrative Notice of Procedural Schedule Adopted in Docket No. 15-GIME-025-MIS at 3 (Mar. 4, 2015). 46
IT IS, THEREFORE, BY THE COMMISSION ORDERED THAT: A. The Joint Motion to Approve Stipulation and Agreement as amended is hereby granted. The terms, conditions, rates and schedules contained within the Stipulation and Agreement as filed on August 6, 2015, and as amended by Westar's Unopposed Motion For Leave to File Addendum to Stipulation and Agreement Out of Time filed on August 12, 2015, is hereby approved. Accounting for revised final rate case expense and bad debt expense figures, Westar's net overall annual revenue increase shall be set at $78,312,992. B. The effective date of this order shall be October 28, 2015. C. The parties have 15 days, plus three days if service of this Order is by mail, to petition the Commission for reconsideration of any issue or issues decided herein. 215 D. The Commission retains jurisdiction over the subject matter and parties for the purpose of entering such further orders as it deems necessary. BY THE COMMISSION IT IS SO ORDERED. Albrecht, Chair; Emler, Commissioner; Apple, Commissioner SEP 2 4 2D15 REV/DLK Secretary to the Commission ElVIAILED SEP 2 4 2015 215 K.S.A. 66-l ISb; K.S.A. 77-529(a)(l). 47
CERTIFICATE OF SERVICE 15-WSEE-115-RTS I, the undersigned, certify that the true copy of the attached Order has been served to the following parties by means of Electronic Service on __S_E_P_2_4_20_1_5____ JAMES G. FLAHERlY, ATTORNEY KURTJ.BOEHM,ATTORNEY ANDERSON & BYRD, L.L.P. BOEHM, KURTZ & LOWRY 216 S HICKORY 36 E SEVENTH ST STE 1510 PO BOX 17 CINCINNATI, OH 45202. OTTAWA, KS 66067 Fax: 513-421-2764 Fax: 785-242-1279 kboehm@bkllawfirm.com jflaherty@andersonbyrd.com JODY KYLER COHN, ATTORNEY ANDREW J ZELLERS, GEN COUNSELNP REGULATORY BOEHM, KURTZ & LOWRY AFFAIRS 36 E SEVENTH ST STE 1510 BRIGHTERGY, LLC CINCINNATI, OH 45202 1617 MAIN ST 3RD FLR Fax: 513-421-2764 KANSAS CllY, MO 64108 jkylercohn@bkllawfirm.com Fax: 816-511-0822 andy.zellers@brightergy.com GLENDA CAFER, ATTORNEY TERRI PEMBERTON, ATTORNEY CAFER PEMBERTON LLC CAFER PEMBERTON LLC 3321 SW 6TH ST 3321SW6TH ST TOPEKA, KS 66606 TOPEKA, KS 66606 Fax: 785-233-3040 Fax: 785-233-3040 glenda@caferlaw.com terri@caferlaw.com NIKI CHRISTOPHER, ATTORNEY DELLA SMITH CITIZENS' UTILllY RATEPAYER BOARD CITIZENS' UTILllY RATEPAYER BOARD 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3116 Fax: 785-271-3116 n.christopher@curb.kansas.gov d.smith@curb.kansas.gov SHONDA SMITH DAVID SPRINGE, CONSUMER COUNSEL CITIZENS' UTILllY RATEPAYER BOARD CITIZENS' UTILllY RATEPAYER BOARD 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3116 Fax: 785-271-3116 sd.smith@curb.kansas.gov d.springe@curb.kansas.gov EMAILED SEP 2 4 2015
CERTIFICATE OF SERVICE SEP 2 4 2015 15-WSEE-115-RTS ARON CROMWELL KEVIN HIGGINS CROMWELL ENVIRONMENTAL, INC. ENERGY STRATEGIES, LLC 615 VERMONT ST PARKSIDE TOWERS LAWRENCE, KS 66044 215 S STATE ST STE 200 acromwell@cromwellenv.com SALT LAKE CITY, UT 84111 Fax: 801-521-9142 khiggins@energystrat.com JOHN FINNIGAN, LEAD COUNSEL WILLIAM R. LAWRENCE ENVIRONMENTAL DEFENSE FUND FAGAN EMERT & DAVIS LLC 128 WINDING BROOK LANE 730 NEW HAMPSHIRE SUITE210 TERRACE PARK, OH 45174 LAWRENCE, KS 66044 jfinnigan@edf.org Fax: 785-331-0303 wlawrence@fed-firm.com C. EDWARD PETERSON, ATTORNEY JULIE B. HUNT FINNEGAN CONRAD & PETERSON LC HOLLYFRONTIER CORPORATION 1209 PENNTOWER OFFICE CENTER 2828 N HARWOOD STE 1300 3100 BROADWAY DALLAS, TX 75201 KANSAS CITY, MO 64111 julie.hunt@hollyfrontier.com Fax: 816-756-0373 ed.peterson201 O@gmail.com JOHN GARRETSON, BUSINESS MANAGER JOHN R. WINE, JR. IBEW LOCAL UNION NO. 304 410 NE 43RD 3906NW16TH STREET TOPEKA, KS 66617 TOPEKA, KS 66615 Fax: 785-246-0339 johng@ibew304.org jwine2@cox.net DUSTIN KIRK, ASSISTANT GENERAL COUNSEL MICHAEL NEELEY, LITIGATION COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604-4027 TOPEKA, KS 66604-4027 Fax: 785-271-3354 Fax: 785-271-3167 d.kirk@kcc.ks.gov m. neeley@kcc.ks.gov AMBER SMITH, CHIEF LITIGATION COUNSEL ROBERT VINCENT, ASSISTANT GENERAL COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604-4027 TOPEKA, KS 66604-4027 Fax: 785-271-3167 Fax: 785-271-3354 a.smith@kcc.ks.gov r. vincent@kcc.ks.gov EMAILED SEP 2 4 2015
SEP 2 4 2015 CERTIFICATE OF SERVICE 15-WSEE-115-RTS ROBERTV. EYE, ATTORNEY AT LAW JACOB J SCHLESINGER, ATTORNEY KAUFFMAN & EYE KEYS FOX & WIEDMAN LLP 123 SE 6TH AVE STE 200 140016TH ST THE DIBBLE BUILDING 16 MARKET SQUARE, STE 400 TOPEKA, KS 66603 DENVER, CO 80202 Fax:785-234-4260 jschlesinger@kfwlaw.com bob@kauffmaneye.com ANNE E. CALLENBACH, ATTORNEY FRANK A. CARO, JR., ATTORNEY POLSINELLI PC POLSINELLI PC 900 W 48TH PLACE STE 900 900 W 48TH PLACE STE 900 KANSAS CllY, MO 64112 KANSAS CllY, MO 64112 Fax: 913-451-6205 Fax: 816-753-1536 acallenbach@polsinelli.com fcaro@polsinelli.com LUKE A. HAGEDORN, ATTORNEY JAMES P. ZAKOURA, ATTORNEY POLSINELLI PC SMITHYMAN & ZAKOURA, CHTD. 900 W 48TH PLACE STE 900 7400W 110TH ST STE 750 KANSAS CllY, MO 64112 OVERLAND PARK, KS 66210-2362 Fax: 913-451-6205 Fax: 913-661-9863 lhagedorn@polsinelli.com jim@smizak-law.com MARTIN J. BREGMAN, ATTORNEY DUSTIN BASHFORD, MANAGER - SYSTEM DESIGN STINSON LEONARD STREET LLP TALLGRASS PONY EXPRESS PIPELINE, LLC 1201WALNUT ST STE2900 370 Van Gordon Street KANSAS CllY, MO 64106 Lakewood, CO 80228 Fax: 81EK391-3495 dustin.bashford@tallgrassenergylp.com marty.bregman@stinsonleonard.com Stefan Evanoff, VICE-PRESIDENT, PIPELINE ADAM SCHICHE, SENIOR ATTORNEY MANAGEMENT TALLGRASS PONY EXPRESS PIPELINE, LLC TALLGRASS PONY EXPRESS PIPELINE, LLC 370 Van Gordon Street 370 Van Gordon Street Lakewood, CO 80228 Lakewood, CO 80228 adam.schiche@tallgrassenergylp.com stefan.evanoff@tallgrassenergylp.com KATHERINE COLEMAN PHILLIP OLDHAM THOMPSON & KNIGHT LLP THOMPSON & KNIGHT LLP 98 SAN JACINTO BLVD STE 1900 98SAN JACINTO BLVD STE 1900 AUSTIN, TX 78701 AUSTIN, TX 78701 Fax: 512-469-6180 Fax: 512-469-6180 katie.coleman@tklaw.com phillip.oldham@tklaw.com EMAILED SEP 2 4 2015
SEP 2 4 2015 CERTIFICATE OF SERVICE 15-WSEE-115-RTS TIMOTHY E. MCKEE, ADORNEY SAMUEL D. RITCHIE, ADORNEY TRIPLED, WOOLF & GARRETSON, LLC TRIPLED, WOOLF & GARRETSON, LLC 2959 N ROCK RD STE 300 2959 N ROCK RD STE 300 WICHITA, KS 67226 WICHITA, KS 67226 Fax: 316-630-8101 Fax: 316-630-8101 temckee@twgfirm.com sdritchie@twgfirm.com DAVID BANKS, ENERGY MANAGER THOMAS R. POWELL, GENERAL COUNSEL UNIFIED SCHOOL DISTRICT 259 UNIFIED SCHOOL DISTRICT 259 201 N WATER 201 N WATER ST RM 405 WICHITA, KS 67202 WICHITA, KS 67202-1292 Fax: 316-973-2150 tpowell@usd259.net dbanks@usd259.net KEVIN K. LACHANCE, CONTRACT LAW ADORNEY MADHEW DUNNE, GENERAL ADORNEY UNITED STATES DEPARTMENT OF DEFENSE US ARMY LEGAL SERVICES AGENCY ADMIN & CIVIL LAW DIVISION REGULATORY LAW OFFICE (JALS-RUIP) OFFICE OF STAFF JUDGE ADVOCATE 9275 GUNSTON RD STE 1300 FORT RILEY, KS 66442 FORT BELVOIR, VA 22060-5546 Fax: 785-239-0577 matthew.s.dunne.civ@mail.mil kevin.k.lachance.civ@mail.mil CATHRYN J. DINGES, SENIOR CORPORATE COUNSEL JEFFREY L. MARTIN, VICE PRESIDENT, REGULATORY WESTAR ENERGY, INC. AFFAIRS 818 S KANSAS AVE WESTAR ENERGY, INC. PO BOX889 818 S KANSAS AVE TOPEKA, KS 66601-0889 PO BOX889 Fax: 785-575-8136 TOPEKA, KS 66601-0889 cathy.dinges@westarenergy.com jeff. martin@westarenergy.com CINDY S. WILSON, DIRECTOR, RETAIL RATES DAVID L. WOODSMALL WESTAR ENERGY, INC. WOODSMALL LAW OFFICE 818 S KANSAS AVE 308 E HIGH ST STE 204 PO BOX889 JEFFERSON CITY, MO 65101 TOPEKA, KS 66601-0889 Fax:573-635-7523 cindy.s.wilson@westarenergy.com david.woodsmall@woodsmalllaw.com
.BMAILED SEP 2 4. 2015 .
Enclosure XI to CO 17-0003 Before the State Corporation Commission of the State of Kansas Direct Testimony (129 pages)
BEFORE THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS In the Matter of the Application
- of )
Westar Energy, Inc. and Kansas Gas ) and Electric Company to Make ) DocketNo.15-WSEE-115-RTS Certain Changes in Their Charges for ) Electric Service. ) DIRECT TESTIMONY PREPARED BY Adam H. Gatewood UTILITIES DIVISION KANSAS CORPORATION COMMISSION JULY9,2015
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Contents Introduction ................................................................................................................................................ 3 Executive Summary ................................................................................................................................... 4 Standards for a Reasonable Rate of Return ............................................................................................. 12 ICCC Proxy Group .................................................................................................................................... 17 Discounted Cash Flow (DCF) Model ...................................................................................................... 20 Application of the DCF Model ................................................................................................................ 24 Forecasted Growth Rates for the DCF Model ......................................................................................... 25 DCF Results ............................................................................................................................................. 32 Internal Rate of Return Analysis .............................................................................................................. 37 Capital Asset Pricing Model Analysis ..................................................................................................... 38 Staff Response to Mr. Somma's Direct Testimony ................................................................................. 46 Response to Westar Proxy Group ............................................................................................................ 48 Response to Westar DCF Analysis .......................................................................................................... 48 Response to Westar' s Capital Asset Pricing Model ................................................................................ 52 Response to Westar's Risk Premium Study............................................................................................. 56 Response to Westar's Request for Flotation Costs .................................................................................. 59 Response to Westar's Claim of Needing a Premium on its ROE ............................................................ 60 Response to Proposed ROE Adjustment Mechanism .............................................................................. 63 Capital Structure ...................................................................................................................................... 63 Cost ofDebt ......................................... .-................................................................................................... 65 Wolf Creek Decommissioning Trust Annual Accrual.. ........................................................................... 65 2
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS SCHEDULES Data and Chart of A and Baa Rated Public Utility Bond Yields: 1919 to 2015 AHG-1 Regulatory Research Associates Reports on Major Rate Case Decisions AHG-2 Proxy Company Selection and Screening AHG-3 KCC Proxy Group AHG-4 Value Line Investment Survey Reports for KCC Proxy Group AHG-5 Prices and 2015 Dividends for KCC Proxy Group AHG-6 Forecasted 2016 Dividend Yields for KCC Proxy Group AHG-7 Summary of Historic and Forecasted Earnings Growth for KCC Proxy Group AHG-8 Internal Rate of Return (IRR) Calculation for KCC Proxy Group AHG-9 Annual Decommissioning Accrual Calculation Based on KCC Inputs AHG-10 1 Introduction 2 Q Would you please state your name and business address? 3 A My name is Adam H. Gatewood. My business address 1s 1500 Southwest 4 Arrowhead Road, Topeka, Kansas, 66604. 5 Q Who is your employer and what is your title? 6 A I am employed in the Utilities Division of the Kansas Corporation Commission as 7 a Managing Financial Analyst. 8 Q What is your educational and professional background? 9 A I graduated from Washburn University with a B.A. in Economics and a Masters 10 of Business Administration. I have filed testimony before the Commission in 11 more than 100 proceedings. I have also filed testimony before the Federal Energy 12 Regulatory Commission. 13 Q What is the purpose of your testimony? 14 A My testimony addresses the appropriate rate of return (ROR) for Westar Energy 15 (Westar or WR). I also address Westar's annual funding level of its Wolf Creek 3
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Decommissioning Trust Fund and the related testimony filed by Susan North. 2 Executive Summary 3 Q Please Summarize Westar's requested ROR? 4 A Westar is requesting a 7.99% rate of return that consists of the components in the 5 following table: I
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................. -- ! 46:2_5.%.l 5.69%1 2.63%!
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0.63%1 ;i.99%1 " 0.05%1 i 6 I Sources: i Section 7 T i i 7 Q Please summarize your response to Westar's Application. 8 A I do not agree with Westar' s proposed return on equity capital. Westar is 9 requesting a 10.00% return for its shareholders; my analysis determined that a 10 9.25% return for shareholders is appropriate in the current capital markets. 11 Regarding the issue of Westar's annual funding of its Decommissioning Trust, I 12 recommend Westar increase its annual accrual from $3,150,000 to $5,772,700. 13 This change is accounted for in Adjustment IS-4 of Staff Schedules. 14 Q. Please Summarize Staff's proposed range of return on equity (ROE) and rate 15 of return (ROR). 16 A. As shown in the following table, Staff is proposing that the Commission set 17 Westar's ROE in a range of 9.00% to 9.50%. Staff has set a 50 basis point range 4
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 and recommends an ROR of 7.59% and an ROE of 9.25%, which is the mid-point 2 of Staff's range. I I
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3 I 4 Q Please summarize why you believe 9.25% is a reasonable ROE. 5 A I have completed an analysis of Westar' s capital costs using traditional financial 6 models and applying the Hope and Bluefield benchmarks. My analysis 7 demonstrates that capital costs have declined since the Commission set Westar's 8 allowed ROE at 10.00% by the Commission in Docket No. 05-WSEE-981-RTS. 9 As I discussed in Docket 15-KCPE-116-RTS (15-116 Docket), I am also applying 10 a degree of gradualism or moderation in that I do not recommend a reduction in 11 the ROE that reflects the full extent of the decline in capital costs. I apply a 12 degree gradualism by recommending Westar's ROE be set in the range of 9.00% 13 to 9.50%. I am setting only a 50 basis point range - as opposed to the 100 basis 14 point range that I typically use- primarily because I believe 9.00% is appropriate 15 as the low-end of my range. 16 Q What is the dollar amount of the difference in ROE positions? 17 A Using Staff's capital structure and cost of debt, a 10 basis point change in the 18 allowed ROE results in about a $4.4 million change in Staff's revenue 19 requirement for Westar. This relationship is an approximation and assumes 5
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Staffs proposed rate base shown in Staff Schedule REV REQ. 2 Q. Why should gradualism be considered in this case. 3 A. I am applying the same principle of gradualism to Westar as I did in my 4 recommendation for KCPL filed on May 11th in the 15-116 Docket. As I 5 discussed in that Docket, I have never recommended gradualism before and only 6 do in these two Dockets because I believe that a 9.00% lower bound for the ROE 7 is appropriate due to three factors. First, Westar's embedded debt costs have 8 declined from 6.25%to 5.69% since the Order in Docket 05-WSEE-981-RTS was 9 issued in December of 2005, Westar's last fully litigated rate case. Capital costs 10 measured by the yield on investment grade utility bonds have also declined. As 11 shown in the following table, the prevailing yield on public utility bonds declined 12 from the 5.80% - 6.00% range in 2005 to 4.50% - 4.91 % range in 2015. Over this 13 time period, the yield on Baa utility bonds has declined by 135 basis points (5.93 14 - 4.58 = 1.35). A longer historical perspective of yields on public utility bonds is 15 shown in Schedule AHG-1 which contains a chart and the underlying data of 16 monthly observations of yields on "A" and "Baa" rated utility bonds from 1919 17 through 2015 reported by Moody's Investor Services. 6
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Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 trades are in the range of 3.98% to 4.36% during the months of May and June of 2 2015. 1 3 Third, and last of all, just as I stated in my 15-116 Docket testiillony, authorized 4 ROEs below 10.00% are a fairly recent development. Before recommending an 5 ROE below 9.00%, I believe it is prudent to wait to see if the cun*ent capital 6 market conditions continue. 7 Q Since 2005, the time of Westar's last litigated rate case, what has been the 8 trend in allowed returns? 9 A For 2005, the average allowed ROE granted to electric utilities was 10.54%. For 10 the first quarter of 2015, that average was 10.37%. It is important to note that the 11 recent average includes four observations from Virginia that are "asset specific" 12 determinations which appear to include some level of incentive or premium that 13 distinguish them from the traditional rate case proceeding that we have before us. 14 Without those four cases, the average for this time period is 9.67%. Attached as 15 Schedule AHG-2 are Regulatory Research Reports: Major Rate Case Decisions 16 publications for 2014 and the first quarter of2015. 17 Q You recently filed testimony in the 15-116 Docket recommending a 9.25% 18 ROE for Kansas City Power & Light (KCP&L). Is your recommendation 19 for Westar based on your analysis of KCP&L in that Docket? 20 A No. My recommendation in this Docket is based on my analysis of Westar and the 21 required return necessary for Westar to attract capital. The 15-116 Docket and 1 Based on the lowest and highest yields to maturity reported by FINRA for Westar debt series 4.625% due 2043; 4.10% due 2043; and 4.125% due 2042 in the months of May and June of2015. 8
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 this Docket are occun-ing at essentially the same time. These two electric utilities 2 risk profiles are similar with nearly identical credit ratings by the major rating 3 agencies. As a result of these Dockets occun-ing in the same capital markets 4 environment and the fact that we are dealing with two electric utilities of nearly 5 identical risk, it is expected that Staffs recommendations would (and should) be 6 the same.
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*- - ~4i~~t.~4il?~g~i--~&0%.! . 9.50% *** 1 1 I ! I 2 As you can see from the table, the models, particularly the DCF model that 3 regulators traditionally rely on, indicate that the cost of equity is less than 9.00%,
4 even with the recent decline in the stock prices of electric utilities. At this time, I 5 am not comfortable advocating for an allowed return below 9.00% for a retail 6 electric utility as it has only been tln*ee years since allowed returns fell below the 7 10% threshold. If capital market conditions persist at the cunent level, I expect 8 we will see challenges to that 9.00% threshold. 9 Q Please summarize your disagreement with Westar's cost of equity estimates. 10 A The primary disagreement is that of estimating growth. This is the same 10
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 disagreement that the Commission has heard in rate cases during the past three 2 years. This disagreement is not confined to electric utilities; it has occurred-and 3 will likely continue to occur-in electric utilities, natural gas distribution, 4 telephony, electric transmission, and natural gas pipeline utilities as well. The 5 table below summarizes the findings of Westar' s cost of equity models and a 6 synopsis of what I believe to be the short comings of each of Westar' s models. I 7 will elaborate on each model later in my testimony. 9 Q. What support do utility executives and equity analysts usually provide when 10 discussing why an ROE should not be lowered below ROE's set for other 11 utilities? 12 A. Commissions and Commission Staff frequently hear from utility executives and 13 equity analysts regarding their belief that Commissions should refrain from 14 lowering allowed returns below those reported for other utilities because such a 15 decision will impair the utility's access to additional capital. Those pleas are 16 devoid of any statistical or factual support. Furthermore, no utility has ever 17 provided Staff empirical evidence to su12p01t its contention that a Commission's 18 decision has impaired its ability to access necessary capital. However, what I 11
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 have observed is that Kansas utilities continue to issue long-term debt at attractive 2 rates. 3 Standards for a Reasonable Rate of Return 4 Q What is the role of rate of return in setting a revenue requirement for public 5 utilities? 6 A The rate of return (ROR) earned on the utility's rate base is part of the revenue 7 requirement equation. The ROR is a cost of providing the utility service. 8 Revenue Requirement = ROR (gross plant- accum. Depr.) + Operating Exp. + Income Taxes 9 In the revenue requirement formula, the ROR expresses the utility's return on its 10 net plant investment. The utility's ROR is its weighted average cost of the 11 capital. That is, the cost of each of the various forms of capital supplied by 12 investors which includes debt, prefened equity, common equity and any hybrid 13 securities multiplied by their respective weight in the utility's capital structure. 14 .The cost or return associated with each of these forms of capital is unique and it is 15 a function of risks associated with that form of capital.
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' I
' I I Return for the Utility I, I, I 16 17 The cost of debt generally relies on a contractual agreement with the investor, 12
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 making its cost relatively easy to determine because the cost is explicit within the 2 contract. Likewise, the ratios of the capital components are relatively easy to 3 determine because, under most circumstances, these ratios are traceable to the 4 utility's financial documents. It is the allowed ROE that requires the most time 5 and attention when setting the ROR because it is a cost that we cannot trace back 6 to a contractual agreement. It is best described as a forward looking discount rate 7 and equates to the rate that is necessary to induce equity investors to commit their 8 capital to the enterprise. 9 Q What standards should commissions apply to making this decision? 10 A The standards used to gauge the fairness and reasonableness of an allowed ROR 11 were announced by courts as the result of appeals of decisions issued by 12 regulatory agencies. Financial analysts and policy-makers rely on the courts' 13 decisions as a guide in estimating the appropriate cost of capital. The opinions do 14 not articulate precisely how to estimate or model a reasonable cost of capital. 15 Instead, the decisions provide critical questions for policy makers and analysts to 16 consider in determining a reasonable return for a regulated utility. 17 In general, United States Supreme Court decisions state that returns granted to 18 regulated public utilities should: 1) be commensurate with returns on investments 19 of similar risk; 2) be sufficient to assure the financial integrity of the utility under 20 economic management; and 3) change over time with changes in the money 21 market and business conditions.2 An important take-away from these decisions is 2 Smyth v. Ames 169 U.S. 466 (1898).Wilcox v. Consolidated Gas Co., 212 U.S. 19, 48-49 (1909). Bluefield Water Works & Improvement Company v. Public Service Commission of West Virginia, 262 U.S. 679, 692-3 (1923). Federal Power Commission v. Hope Natural Gas Company, 320 U.S. 591, 603 (1944). 13
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 that the Court has afforded regulatory agencies a significant amount of latitude in 2 establishing what is an appropriate ROR for a utility. The Kansas Supreme Court 3 has recognized and generally follows this body of law. 3 This Commission has 4 noted that fact in Orders issued in previous Dockets. 4 5 Q Discuss how financial analysts apply the standards established by the Court. 6 A For a ROR to meet the legal standards, the return should be as specific as possible 7 to the utility in question, in that the allowed return should consider the mix of debt 8 and equity capital the subject utility employs to finance its rate base and provide a 9 return for each of those components of its capitalization. 10 There are several court cases that, as a group, are viewed as the keystone to 11 measuring the adequacy of a utility's allowed return. The earliest of these 12 decisions go back to an era when it was not only the "rate of return" at issue but 13 also the fundamental measurement of the investment in the utility enterprise 14 commonly referred to as rate base. This is less of an issue today as regulators, 15 utility management, and investors readily accept actual historic-depreciated value 16 as a measure of investment to estimate the value of a utility's rate base, as 17 opposed to reproduction cost or market value. The Court's decision in Blue.field 18 addressed both rate base and ROR. 5 Treatises on rate of return for public utilities, 19 such as The Cost of Capital - A Practitioner's Guide, generally agree that 20 Blue.field lays out the four standards for a fair return. 3 Kansas Gas & Elec. Co. v. State Corp. Comm'n, 239 Kan. 483, 491, 720 P.2d 1063, 1072 (1986). 4 Order: 1) Addressing Prudence; 2) Approving Application, in Part; & 3) Ruling on Pending Requests, Docket No. 10-KCPE-415-RTS; November 22, 2010; 37-38. 5 Bluefield Water Works & Improvement Co. v. Pub. Svc. Comm 'n of West Virginia, 262 U.S. 679, 692-3 (1923). 14
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 1) Comparable Earnings - a utility is entitled to a return similar to that being 2 earned by other enterprises with similar risks, but not as high as those earned 3 by highly profitable or speculative ventures; 4 2) Financial Integrity - a utility is entitled to a return level reasonably sufficient 5 to assure financial soundness; 6 3) Capital Attraction - a utility is entitled to a return sufficient to support its 7 credit and raise capital; and 8 4) Changing Level of Returns - a fair return can change along with economic 9 conditions and capital markets. 6 10 As a financial analyst preparing rate of return analyses, I take from Bluefield that 11 the Court requires that a rate order allow a utility an opportunity to earn a return 12 that is consistent with the utility's risk profile and consistent with observations in 13 the capital markets. 14 The Court's decision in Hope, 7 like that in Bluefield, dealt with both valuation of 15 rate base as well as rate of return on that rate base. With respect to the rate of 16 return, the Court in Hope affirmed the four standards set out in Bluefield. 17 Q Is a reasonable return necessarily equal to the return granted to other 18 utilities in other jurisdictions? 19 A No. Relying on the allowed returns granted to other utilities in other jurisdictions 6 The Cost of Capital - A Practitioner's Guide by David C. Parcell; Prepared for the Society of Utility and Regulatory Financial Analysts; 1997; pp. 3-13 to 3-14. 7 Federal Power Comm'n. v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944). *603 [8] [9] The rate-making process under the Act, i.e., the fixing of 'just and reasonable' rates, involves a balancing of the investor and the consumer interests. Thus we stated in the Natural Gas Pipeline Co. case that 'regulation does not insure that the business shall produce net revenues.' But such considerations aside, the investor interest has a legitimate concern with the financial integrity of the company whose rates are being regulated. From the investor or company point of view it is important that there be enough revenue not only for operating expenses but also for the capital costs of the business. These include service on the debt and dividends on the stock. By that standard the return to the equity owner should be commensurate with returns on investments in other enterprises having conesponding risks. That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital. The conditions under which more or less might be allowed are not important here. Nor is it important to this case to determine the various permissible ways in which any rate base on which the return is computed might be anived at. For we are of the view that the end result in this case cannot be condemned under the Act as unjust and umeasonable from the investor or company viewpoint. 15
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 runs the risk of overlooking: (1) changes in the capital markets; (2) differences in 2 other state Commissions' ratemaking policies; and (3) political pressures or other 3 state-specific factors. Commissions have to recognize that such a practice also 4 creates a degree of circular reasoning. Such a comparison also requires a 5 commission to place weight on a piece of data as evidence when they simply do 6 not have any specific facts from those reported cases to lmow how other state 7 commissions arrived at their decision or even what evidence was presented in 8 those Dockets. At best, returns authorized at other state commissions serve as a 9 rough benchmark of an average return on equity, as well as an indicator of a 10 downward or upward trend in returns. Simply put, the authorized returns of 11 separate utilities in other jurisdictions facing different risks are of limited 12 evidentiary value and are largely irrelevant to the Hope and Bluefield standards. 13 Q Should the rate of return incorporate a return on equity that contains some 14 level of "cushion" to the cost of equity to compensate for potential future 15 changes in the capital markets? 16 A No, it should not. Utilities seek rate adjustments on a regular basis as 17 demonstrated by the Kansas jurisdictional electric and gas utilities over the past 18 decade. Thus, there are periodic reviews of capital costs, that is, the allowed 19 return on equity and allowed return on debt is not set once and left at the level in 20 perpetuity. This provides protection to consumers and investors alike, in that the 21 periodic reviews eliminate the need for the Commission to inject any forecasting 22 of trends into their decision. As the cost of capital changes over time - and it will 23 change - the allowed return will be updated in future proceedings. In my view, 16
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Court decisions do not require Commissions to speculate about the peaks and 2 troughs of our economy and capital markets; all of the directives from the Court 3 cases focus on the observations of the here and now. 4 KCC Proxy Group 5 Q How did you estimate Westar's cost of equity? 6 A To estimate Westar's cost of equity, I performed DCF and CAPM analyses on a 7 proxy group of similarly situated electric utility companies. 8 Q Why is it necessary to select a proxy group to estimate the cost of equity for 9 Westar? 10 A A proxy group aids us in meeting the standards set out in Hope and Bluefield, as it 11 focuses our analysis on a group of companies that are in the same indust1y and 12 exposed to similar risks. Financial theory tells us that investors require a return 13 that is commensurate with risk. Therefore, a proxy group similar in risk to Westar 14 provides us with a comprehensive picture of investors' expectations. 15 Q Were you able to select a group of electric utilities similar in risk to Westar? 16 A Yes, I found 22 proxy companies. 17 Q How did you select a proxy group for your cost of equity analysis? 18 A Using the following parameters, I was able to select a group of electric utilities 19 similar in risk to Westar (a table of the selection process is shown on Schedule 20 AHG-3): 17
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1
- First, I began with the companies followed by Value Line Investment 2 Survey and categorized as electric utilities. As a starting point, this 3 parameter is important as it assures us the companies generally derive 4 their earnings in the same industry as Westar by operating as ROR 5 regulated electric utilities within the United States. Value-Line coverage 6 also ensures that the common stock of these companies is publicly traded.
7 There are 45 electric utilities followed by Value-Line. 8
- Second, from that group of 45 electric utilities, I selected those with credit 9 ratings similar to Westar's credit rating. Westar's long-term credit rating 10 is Baal by Moody's, BBB+ by Standard & Poors', and BBB by Fitch.
11 The three ratings are relatively similar to each other.
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2 The electric utilities followed by Value-Line fall in the range of AA-/Aa3 3 to BBB-/Baa3. Narrowing the range to one rating above and below that of 4 Westar's rating reduced the proxy group to 35 companies. 5
- Third, I eliminated those companies with pending mergers or acquisitions 6 (M&A). M&A transactions bring about added uncertainty and speculation 7 regarding the financial projections for earnings and dividends, growth 8 potential, and financial health of the surviving entity. This parameter 9 eliminated four companies from my proxy group.
10
- Fourth, the proxy group companies had to exhibit a stable dividend policy 11 both in the recent past and going forward. A stable dividend is an attribute 12 of a financially sound utility company. By any measure, Westar is 19
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 financially sound; members of the proxy group must reflect that same 2 attribute. This parameter did not eliminate any of the remaining 31 3 electric utilities. 4 The four parameters above have been adopted in recent cost of equity 5 analyses filed at the Federal Energy Regulatory Commission (FERC) and I 6 agree that these four parameters generally arrive at a group of companies 7 with commensurate investment risk to that of Westar. For this group of 31 8 electric utilities, I gathered information on their sources of revenues and 9 the focus of their asset base. The intent of this additional parameter is to 10 increase the proxy groups' focus on the electric utility industry. Although 11 each of the companies is categorized as electric utilities by Value-Line, 12 most of them derive some revenues from other industries; some are 13 combination natural gas distribution and electric utilities while others are 14 more diverse with operations outside of the public utility industry. I set 15 the threshold for electric utility revenues at 70%, which eliminated 9 of 16 the 31 electric utilities. The remaining 22 companies derive 73% to 100% 17 of their revenues from the electric utility business. It is these 22 18 companies that I analyzed to estimate Westar's cost of equity capital. The 19 selection process is shown in Schedule AHG-3 and the Proxy Group is 20 shown in Schedule AHG-4. 21 Discounted Cash Flow (DCF) Model 22 Q Does the DCF model meet the legal standards discussed earlier in your 20
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 testimony? 2 A Yes, a cost of equity estimate derived from the DCF model meets the legal 3 standards discussed above if the model incorporates current information from the 4 capital markets via current stock prices and accurate data that investors use to 5 establish their discount rate. The market based information ensures the cost of 6 equity estimates evaluate investors' required rate of return or discount rate that 7 reflects the economic environment. 8 Q Has the DCF model been an accepted model for regulators to estimate the 9 cost of equity? 10 A Yes. The DCF model is the most widely used model for regulatory bodies setting 11 allowed returns. Regulatory agencies may incorporate more than one model to 12 arrive at an estimate. If more than one is used, the DCF model is always one of 13 the models. If only one model is used, it will be the DCF model. Regulatory 14 agencies rely on the DCF analysis because, with reasonable inputs, it is a tool that 15 meets the legal standards that investors have used to value all sorts of investments 16 vehicles. 17 Q What is the underlying basis for the DCF model? 18 A The DCF model is an investment valuation model used to value different and 19 diverse types of investments such as real estate, bonds, and common stocks. The 20 DCF model is a useful tool to value any investment that involves regular, periodic 21 cash flows. The notion of discounting a future receipt of cash back to the present 22 so as to place a price or value on an investment goes back centuries. The fo1mal 21
- Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 presentation of the DCF model as we use it today dates back to the 1930's in 2 Irving Fisher's book The Theory of Interest and John Bun Williams' 1938 text 3 The Theory of Investment Value. These two authors expressed the DCF model in 4 modem economic terms.
5 The premise of the DCF model in the valuation of common stock is that investors 6
- determine the value of a company's common stock by discounting its future 7 dividend payments back to the present. The cornerstone of the DCF model is the 8 process of discounting those future cash flows back to the present at the investors' 9 required ROR. An investor's required rate of return is risk sensitive and sensitive 10 to the returns available on investments of comparable risk throughout the global 11 capital markets. In other words, as the risk of the.investment increases, so will the 12 investors' required return. A higher required rate of return decreases the present 13 value of the stream of dividends that equates to the price of the stock. So, all 14 other variables being equal, investors price the rislder of two common stocks 15 lower because the cash flows or dividends are discounted back to the present at a 16 higher rate.
17 The form of the DCF model that regulatory agencies are accustomed to seeing is 18 often refened to as the Gordon Growth Model, which is a model that values the 19 present value of a stream o( cash flows (dividends) growing at a constant rate into 20 perpetuity. The basic form of this DCF equation is: 21 Stock Price =Annual Dividend I (Req 'd Rate ofReturn -Dividend Growth Rate) D0 (1 + g) Po= (Ke -g) 22 where: 23 Po= the value of the common stock or asset 22
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Do = the current dividend of the stock or annual cash flow from the asset 2 g = the annual growth rate of the dividend or cash flow forever 3 Ke = cost of equity or required rate of return for the stockholders 4 This is the form of the equation commonly found in texts regarding finance, 5 irivestments, and asset valuation, Such texts are inclusive of both theory and 6 practical application. 7 Regulatory agencies responsible for setting rates and revenue requirements want 8 to know the investors' required rate of return or Ke in the equation. So, we solve 9 the equation for that variable. The equation below shows the algebraic isolation 10 of the investors' required rate of return. By isolating investors' required rate of 11 return in the equation, we can estimate it by lmowing the stock's dividend yield 12 and the annual dividend growth rate expected by investors. That form of the 13 equation is: Da(1 + g) Ke= Po . +g 14 This equation is frequently written out as: 15 Req 'd Rate ofReturn = (Current Annual DMdend/Current Stock Price) + Dividend Growth Rate 16 Req'd Rate ofReturn= Dividend Yield+ Dividend Growth Rate 17 Or as commonly abbreviated by regulatory agencies 18 Ke=y+g 19 where: y ~Dividend Yield 20 g = Expected Dividend Growth 21 22 Through *a handful of inputs, the DCF model distills down to an equation, a 23 complex cognitive process performed by investors. As with any equation that 23
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 attempts to model behavior, there are a host of assumptions that come along with 2 it. Generally those assumptions are: 3
- Investors evaluate common stock in the classical economic :framework.
4
- Investors discount the expected cash flows at the same rate (Ke) in every 5 future period.
6
- Ke c01Tesponds only to the specific stream of future dividends, rather than 7 earnings, and constitutes the source of value.
8
- The discount rate (Ke) must exceed the growth rate (g).
9
- The constant growth rate will continue for an indefinite future.
10
- Investors require the same discount rate (Ke) each year.
11
- There is no external financing.
12 Q Why is it reasonable to accept these assumptions? 13 A A certain number of assumptions come along with any financial or economic 14 model, especially ones that are attempting to emulate investors' behavior. The 15 question becomes whether the assumptions are so contrary to investors' behavior 16 in the real-world that the model output becomes meaningless or illogical. I do not 17 believe the assumptions of the DCF model are contrary to investor behavior. 18 Moreover, there are methods I use to evaluate whether an output falls outside of
- 19. the realm of reality. For example, the output can be compared with the returns 20 available on other investments such as long-term corporate bonds.
21 Application of the DCF Model 22 Q How did you calculate the dividend yield (y) component of the DCF model? 23 A The dividend yield (y) is the easiest of the two components to measure. It is 24 calculated by dividing the stock's annual dividend payment per share by its 25 market price per share. For example, a company paying an annual dividend of 26 $2.00 per share with a market price of $76.00 has a dividend yield of2.63%. 24
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Q What is the source of the dividend information? 2 A Historic and current dividend information is easily obtained from public sources.
*3 The DCF model requires a forward looking dividend payment which is often the 4 current year's dividend payment increased by the expected growth rate or the 5 forecasted growth rate for next year. I obtained the dividend per share 6 information from Value-Line Investment Survey. The Value-Line reports for 7 each of the proxy companies are attached as Schedule AHG-5. I obtained the 8 stock prices for the dividend yields from YahooFinance. The stock prices and 9 2015 annual dividend observed for each of the proxy companies appears on 10 Schedule AHG-6. The projected 2016 annual dividend rate and resulting 11 dividend yields appear on Schedule AHG-7. The dividend used to calculate the 12 dividend yield is the 2015 dividend rate multiplied by the projected growth rate so 13 as to reflect the expected 2016 dividend payment.
14 Q Is it proper to use the dividend rate of a full year in the future? 15 A Yes it is a proper application, although this method is likely a slightly higher 16 dividend rate than merely escalating the cmTent quarterly dividend rate by the 17 projected growth estimate. This method ensures that the DCF analysis contains a 18 truly forward dividend rate, throughout the eight month process of setting 19 Westar's new revenue requirement. 20 Forecasted Growth Rates for the DCF Model 21 Q Please discuss the importance of the second component, the growth rate (g) 22 in the DCF equation. 25
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 A The "g" represents the anticipated annual growth rate in cash flows that investors 2 expect to receive through dividends from the stock. This is a difficult and 3 contentious issue in a DCF analysis for two reasons. First, it is a key element in 4 the DCF model because the growth rate has a one-for-one effect on the utility's 5 allowed return. All other factors being equal, a higher growth rate results in a 6 higher return on equity for the utility. Second, there is an element of subjectivity 7 to selecting the growth rate due to the uncertainty about future earnings and 8 dividends. It is difficult to uncover what growth rate estimates investors rely on 9 when they value a stock and where they obtain that information. 10 Q How did you estimate the growth rate in the DCF model? 11 A The appropriate growth estimate is that which is expected by the market and 12 factored into investors' analyses to estimate a stock prices. That is, it is the 13 growth estimate investors used to determine the stock price. Determining 14 precisely how investors estimate the growth rate used in evaluating common 15 stocks is difficult. Earnings per share growth forecasts are commonly 16 incorporated into the DCF model. Investment firms that publish growth forecasts 17 publish three to five-year annual earnings growth estimates and that is about as far 18 into the future as analysts forecast for a specific company. I discussed earlier that 19 the DCF model assumes the growth rate continues in perpetuity, well beyond the 20 three to five-year window of analysts' forecasts for earnings and dividends. 21 Q How do investors estimate the dividend growth rate beyond the three to five 22 year horizon of the short-term growth forecasts? 26
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 A For a long-term perspective of potential growth, investors rely on forecasts of the 2 broad economy. There are sources for long-term growth estimates of this 3 country's gross domestic product (GDP) that extend out more than 20 years. 4 Mathematically, a growth estimate rolled out over 20 years is for all practical 5 purposes a perpetuity in the world of discounting future cash flows. Academic 6 texts and investment professionals use these forecasts in DCF models as a forecast 7 of potential long-term growth. GDP refers to the market value of all final goods 8 and services produced within a country in a given period. Nominal GDP (nGDP) 9 is that measure of goods and services which includes effects of price changes - 10 better known as inflation. Inflation must be included because the DCF analysis is 11 interested in the nominal required return or cost of equity, and investors' 12 expectations of inflation are contained in their required return. Keep in mind that 13 the "head-line" GDP reported in the media is real GDP; GDP less the inflation 14 experienced over the measurement period. 15 Q Is it accepted practice to use nGDP growth estimates in the DCF model? 16 A Yes, in the federal regulatory arena, similar to the responsibilities of the KCC, the 17 FERC uses nGDP to estimate the cost of equity. FERC has reviewed the issue of 18 long-term growth *estimates used in DCF models; it took comments from 19 concerned parties that included state commissions, customers, investment 20 bankers, and interstate pipeline companies. 8 Testimony from these parties made it 21 clear that long-term estimates of nGDP are a common component of valuation 22 analyses conducted by investment professionals. From that proceeding, FERC 23 concluded that long-term growth estimates of nGDP should be the estimate of 8 Transcript from Technical Conference held on January 23, 2008, FERC Docket PL0?.-2-000. 27
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 long-term growth in the DCF models used to estimate required returns for 2 interstate pipeline companies because that is consistent with investor behavior. 9 3 In June of 2014, FERC concluded that the same methodology should be used in 4 setting the required returns for electric transmission companies. 10 5 Q Is there academic support for this issue? 6 A Yes, valuation analysts have carefully considered the long-run growth rates used 7 to value assets. Using an incorrect growth estimate will lead to incorrectly 8 valuing an asset. Academic research supports has shown that nGDP growth 9 forecasts are an imp01iant input to valuation studies because the analyst has to 10 consider whether a company's annual earnings can grow faster than the broad 11 economy. In two of his books devoted to the subject of asset valuation, 12 Investment Valuation: Tools and Techniques for Determining the Value of Any 13 Asset, 2nd Edition and Damodaran on Valuation: Security Analysis for 14 Investment and Corporate Finance, 2nd Edition, Dr. Aswath Damodaran discusses 15 the nature of a stable growth rate for DCF models. He argues for viewing 16 nominal economic growth as the absolute maximum when using a stable-growth 17 model, such as the DCF model we are using. 18 "The stable growth rate cannot exceed the growth rate of the economy in which a 19 firm operates, but it can be lower. There is nothing that prevents us from 20 assuming that mature firms will become a smaller part of the economy and it may, 21 in fact, be the more reasonable assumption to make. Note that the growth rate of 22 an economy reflects the contributions of both young, higher growth firms and 23 mature, stable growth firms. If the former grow at a rate much higher than the 24 growth rate of the economy, the latter have to grow at a rate that is lower. " 25 (Damodaran on Valuation: Security Analysis for Investment and Corporate 26 Finance, 2nd edition; Aswath Damodaran; p.148. 9 Policy Statement, FERC Docket PL07-2-000 (April 17, 2008); FERC Opinion No. 486, FERC Docket RP04-274 (Oct. 19, 2006). 10 0pinion No. 531; June 19, 2014; 147 FERC 61,234; para 36. 28
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 2 "The growth rate of a company cannot be greater than that of the economy but it 3 can be less. Firms can become smaller over time relative to the economy. Thus, 4 even though the cap on the growth rate may be the nominal growth rate of the 5 economy, analysts may use growth rates much lower than this value for individual 6 companies. " (Damodaran on Valuation: Security Analysis for Investment and 7 Corporate Finance, 2nd edition; Aswath Damodaran; p.159) 8 9 It is worth noting that Professor Damodaran cites the nGDP growth projection as 10 a ceiling for long-term growth in most valuation studies. Certainly there are 11 industries that will exceed the average for a period of time, but even for those 12 industries experiencing rapid growth, that would not continue forever. For 13 purposes of my analysis, it is not realistic to place a mature industry like electric 14 utility services in a group of companies that should experience rapid growth over 15 an extended period of years. 16 Q In that discussion, your source states that nominal economic growth is a 17 ceiling for long-term earnings growth. Is the ceiling the appropriate number 18 for an investor to use when valuing a common stock? 19 A There is research that casts doubt on using the forecasted nGDP as the growth 20 ceiling in valuation studies as nGDP may actually overstate the growth potential 21 for a company's earnings. Research by Bernstein and Amott warns practitioners 22 that a portion of nGDP growth is created by new enterprises and that portion of 23 nGDP growth does not contribute to the earnings growth of existing enterprises. 11 11 Earnings Growth: The two Percent Dilution; William J. Bernstein and Robert D. Arnot; Financial Analysts Journal; September/October 2003, pp 47-55. 29
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 71110 i111por/m1f coJ1cepls /'loycd a key tole in /he Intl/ 11wrket of the l990s. Bot/1 reprcse1Tf f1tndm11enln!Jlmus in logic. Bo/Ji arc cte111011sfl'ahly 1111.lrue. First, 11rany investors lwliezied that earnings could grow faster tlum l/1e 111acroeco110111y. l11.fi1ct 1 car11i11gs 11111st grow slowa //um GDP f1ccm1se the growth tf cxisli11s enterprises co11/Tiln1tes only pi1rl (if' GDP growf11; the role l!f c11/reprcne11 rial c11pit11l is111, the crea Iion of' llfi/l l'llfe'rprises, is n kl'y driver i~F GDP grm:ut/1, 1111d ii does 110/ co11frifJ11/c lo /he growth in enmi11gs and dividends l~fcxi~f-ins cn/erprisL'S. D11ri11g lite 20/h ce11lury, growr/1 ill stock prices and dividends 1uos 2 l'ercenl less llu111 1111derlyi11g 11111croeco110111ic grow/It. Seco11d, 111111/y ilrucsfors believed Iha/ stock huyhacks would permit t'arniligs ID srmu/hs/er J/iw1 GDP The ir11pin*tonf mdric is 110/ /ht! 110/u111t! t~f h11ylmcks, however, lJ11f 11ct l111.1tlH1cks----'stock lmylmcks less new share iss11n11ce, wlief/1cr in exiM i11g 1*11/crprises or l/Jroug!t I POs. We de111011strnlc, 11si11g two 111cthodologies1 I/wt during /he 20/h ce11l11ry, new silo re isslllmce i11 111m1y 1111Uo11s almost 11hut1yA exceeded slock lmybac~ks /Jy m1 avem,~e of 2 pace11 I or 1110 re a yen r. 1 2 Q Does their view that nGDP growth is a ceiling on long"term earnings growth 3 exist outside of academia? 4 A Yes, Bernstein and Arnott have both published in peer"reviewed academic 5 journals, books on investment strategy, as well as building careers in the field of 6 asset management and investment strategy. Furthennore, institutions directly 7 involved in asset valuation and asset management that apply valuation models to 8 analyze potential acquisition and merger transactions recognize that estimates of 9 firm-specific growth are a driver to the value of an asset; overstating growth 10 would cause a model to overestimate the value. These expe1is also warn of a 11 ceiling to earnings growth rates as being no more than that of broad economic 12 growth. 13 "Growth rate: Few companies can be expected to grow faster than the economy 14 for long periods. The best estimate is probably the expected long-term rate of 15 consumption growth for the industry's products, plus inflation. " (Valuation: 16 Measuring and Managing the Value of Companies; Tim Koller, Mark Goedhart, 17 and David Wessels; McKinsey & Co; 4th ed; p275.) 30
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 The following quote from J.P. Morgan Asset Management (JPMAM) addresses 2 the limits on earnings growth on a macro-level. This statement by JPMAM 3 addresses the macro or economy-wide measures of profits and it is consistent with 4 the firm-specific view expressed by asset valuation experts in that analysts must 5 be aware of the forecasted growth rates applied in valuation models and how 6 those growth forecasts comport with broad measures of forecasted economic 7 growth. 8 "One common mistake is to assume that earnings and dividends received by 9 investors can grow in line with-or even in excess of-overall economic growth 10 (GDP) in perpetuity. Granted, it is almost a truism that aggregate earnings must 11 grow at the same pace as the overall economy in the very long run; otherwise, 12 profits would eventually outstrip the size of the entire economy or dwindle to an 13 insignificant share of it. But not all of this earnings growth accrues to existing 14 shareholders. On the contrary, a large portion of economic growth comes from 15 the birth of new enterprises. Some commentators suggest (for example, Bernstein 16 and Arnott, 2003; Cornell, 2010) that new enterprises account for more than half 17 of GDP growth in the US., while in some rapidly developing economies new 18 enterprises may account for the lion's share of overall economic growth. " (Long-19 term Capital Market Return Assumptions: 2015 Estimates and Thinking Behind 20 the Numbers; J.P. Morgan Asset Management; p.25 21 https://am. jpmorgan.com/lu/institutional/ltc1ma) 22 23 Q Do you believe this information justifies incorporating long-run nGDP 24 growth forecasts in cost of equity analyses of utility companies? 25 A Yes, in a general rate proceeding such as this, the Commission is attempting to 26 ascertain the discount rate investors apply to the future cash flows from an 27 investment in these utilities; therefore, the Commission should emulate investors' 28 analytical practices as much as possible to determine their discount rate. As noted 29 above, investment professionals include a long-run growth forecast for the general 30 economy when applying valuation models like the DCF and capital asset pricing 31
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 model, and that measure of macro-economic growth serves as the upper bounds of 2 a firm-specific analysis. Therefore, the Commission should consider that same 3 information. 4 DCF Results 5 A Please discuss the results of your DCF analysis. 6 Q The results of my DCF analysis appear in the following table. As I have set out 7 the foundations for the DCF analysis in the previous pages, in this section I will 8 discuss the specific information that I relied on for the DCF model and interpret 9 the results. 32
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 2 To calculate the expected dividend, I multiplied the reported 2015 annual 3 dividend by the forecasted growth rate to move the current 2015 dividend ahead 4 one full year so as to reflect the expected dividend rate in year one. The data for 5 each proxy company is shown on Schedule AHG-7. That 2016 annual dividend is 6 divided by the pricing data gathered for each of the proxy companies from the 7 time period of March 1, 2015, through May 31, 2015, on a weekly basis. The 8 high and low prices for each week are shown on Schedule AHG-6. The low 9 dividend yield is computed using the expected 2016 dividend divided by the 33
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 average of the weekly high prices while the high dividend yield is computed using 2 the weekly low prices. 3 Q How did you arrive at a growth rate for each proxy company? 4 A The growth rate is the average of the short-term growth rates 12 and the long-run 5 forecast of nGDP of 4.38%. Schedule AHG-8 summarizes all of the observed 6 growth forecasts; both historical and forecasted. 7 8 Q What are your observations of the short-run growth forecasts? 9 A The average of the short-run growth forecasts for the proxy group is 5.12% with a 12 For each proxy company, I gathered four short-i'Un, three to five year growth forecasts - earnings and dividend growth projections from Value-Line Investment Survey, analysts' earnings growth projections reported by FactSet through SNL Financial, and earnings growth projections reported by Thomson Financial Network reported by YahooFinance. FactSet and Thomson Financial Network aggregate analysts' earnings forecasts and report the mean of those estimates. Value-Line produces its own growth forecasts and publishes on a quarterly basis. The Value-Line report for each company appears in Schedule AHG-5. 34
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 range of2.50% to 6.90%. 2 Q How do the forecasts compare to historic growth rates realized by the proxy 3 group? 4 A As you can see in the previous table, the averages from each forecast source fall 5 under the ten year historic averages and are greater than the five year historic 6 averages. All of the growth forecasts are positive although there are several 7 individual observations of negative historic growth for both the five and 10 year 8 periods. 9 Q How did you estimate long-run nominal GDP growth? 10 A I averaged the long-run nGDP forecasts of the Energy Information Agency (EIA) 11 in its 2015 Annual Energy Outlook and the Social Security Administration (SSA). 12 Both forecasts extend to 2090. Nominal GDP Forecasts Energy Information Administration-- 2015 Annual Energy Outlook (2013 - 2090) 4.25% Social Security Administration-- 2014 Annual Report to the Board of Trustees 4.50% ofOADSI (2014 - 2090) Average 4.38% 13 14 These two forecasts are consistent with the other long-run forecast for real GDP 15 shown in the following table, as both the BIA and SSA forecasts of nominal GDP 16 incorporate an inflation forecast of 1.8% to 2.0%, thus expecting real growth in 17 the range of 2.4% to 2.6%. The following table is taken from EIA's 2014 Annual 18 Energy Outlook. The first two lines contain EIA's forecasts from 2014 and 2013 19 respectively. Like the EIA and SSA, the Office of Management & Budget 35
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 (OMB) and Congressional Budget Office (CBO) are agencies of the U.S. 2 Government. ISH Global Insight and INFORUM (University of Maryland) are 3 subscription services and, of course, ExxonMobile is one of the largest 4 corporations in the world. From a diverse group of interests, there is some 5 consensus that long-run economic growth in real terms will be in the range of 6 2.5%. Applying the 1.8% to 2.0% inflation forecasts would result in a nominal 7 growth rate of 4.3% to 4.5%. This is in stark contrast to Mr. Somma's growth 8 forecast of 5.62% in his DCF analysis and 11.28% growth used in his CAPM; 9 both dramatically exceed the consensus forecasts from these seasoned, 10 professional services. Mr. Somma's 5.61 % nGDP is built on his unsupportable 11 belief that real GDP will grow at an annual rate of 3.27%, which is about 100 12 basis points greater than any of these professional forecasts. Table CPI. Comparisom of awrnge annual economic growth projectiom, 2012-40 Average annual percentage growth rates Projection 2012-2015 2012-2025 2025-2040 2012-2040 AE02014 (Reference case) 2.6 25 24 24
-**----*------- -*-*-*- .. '--*-**-*** ----**---- ------*----**------ *-------------**-*-*--- --------- ------**--*****--------- -* ------*----*--- ---------- *----------------*-~
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~BO <Fe.bruary 2014)'. 2.6 2-5 INFORUM (November 2013) 2.4 2-6 2.3 24 Social Security Adm*nislra!lon (August 2013) 3.0 2-7 2.2 2-4
-,£A'c2o13)b___________ ------*-------------- - 2.6 28 24 ExxonMobil 25 22 24
__OE~ (Janu~ry2~~~>. _ 2.7 2-7 2-5 2.6
-* = not rnportcd or not applicable.
'OMO and CBO project*ons end In 2024. and growth rates cited are lor 2012-24. AEO projcclions end in 2040.
flEA publishes U.S. gro.,,ih rates for cuta*n Intervals: 2011-15 growth is 26%, 2011-20 growth is 28%, 2nd 2011-35 grcmlh is 2.4%. CP-2 U.S. Energy Jnformatton Administration I Annual Energy Outlook 2014 13 14 This table was published in the 2014 edition of the Annual Energy Outlook. The 15 2015 did not contain a similar table. A check of ExxonMobil's 2015 Energy 16 Outlook indicates its forecasts for GDP growth are 10 basis points higher than 17 those published in 2014. I have not found any evidence that growth projections 36
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 shown in this 2014 table have changed significantly. 2 Q How is the long-run nGDP forecast applied in your DCF analysis? 3 A The long-run nGDP growth forecast of 4.38% is averaged with the short-run 4 growth forecasts. The result is the sustainable growth estimate used in the DCF 5 calculations for each of the proxy companies. In my analysis, I give equal weight 6 to short-run and long-run growth forecasts. The weighting is certainly debatable. 7 At FERC, in both natural gas pipeline and electric transmission rate cases, the 8 short-run growth is afforded a two-thirds weighting. In the regulated electric 9 utility industry, there is seldom a dramatic difference between a well-reasoned 10 short-run growth estimate and a sound long-run forecast of nGDP, so the 11 weighting is not going to cause a significant change in the results. Regardless of 12 the small difference, a long-run nGDP estimate is one component of any sound 13 DCF analysis, as it recognizes the upper-threshold of growth potential. 14 Internal Rate of Return Analysis 15 Q Please discuss the internal rate of return (IRR) analysis that you performed. 16 A An IRR analysis of an investment is a form of a discounted cash flow analysis, 17 only with a more cumbersome equation than the Gordon Growth Model that we 18 applied in the previous section. In the age of spreadsheets, the IRR equation is 19 not that much harder to manage than the dividend yield plus growth DCF model, 20 and as the IRR model allows us to apply the growth forecasts to their respective 21 forecast periods, the IRR model provides important information to policy makers. 22 In the IRR analysis, we are able to apply the five year growth forecasts to the 37
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 intended five years of dividends with the remaining years growing at the long-run 2 nGDP forecasted growth rate. 3 The IRR calculations appear rn Schedule AHG-9. The following table 4 summarizes the results of the IRR. Recognizing that the short-term growth 5 forecasts are given much less weight than in the DCF analysis, the average for the 6 proxy group in the IRR analysis is about 20 basis points higher than the DCF 7 results. I I _j Internal Rate ofReturn ____ __!_ __ _ j;µiit_t:_Ill~ _ _ ____ -I ______ §,~§rai:: _ IA!!~!-~g~rnx~2r}J__________1_ -----~i~~L __ JJ\tnere11C::o.rp _ _ _ . .. J 8,9?.~i _
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9 Capital Asset Pricing Model Analysis 10 Q Please describe the capital asset pricing model (CAPM). 11 A The CAPM offers an explanation of the positive relationship between risk and 38
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 ROR required by investors. 13 It is appealing to regulators because it meets the 2 legal standards I discussed as it incorporates cunent data from the financial 3 markets and the unique risks of the utility in question. 4 Ke = Rf+ Beta (Rm - Rf) or 5 Ke= Rf+ Beta (Rp) 6 where: 7 Ke= required return on equity 8 Rf= return on the risk-free security 9 Rm= expected return from the market 10 Rp= risk premium required by investors to purchase common stocks 11 instead ofrisk-free securities often calculated as Rm - Rf 12 Beta = volatility of the security's or portfolio's return relative to the 13 volatility of the market's return 14 Rf 15 The Rf estimate is the interest rate investors believe represents a riskless return. 16 Although it is a simple concept, the answer is not universally agreed upon. The 17 90-day U.S. Treasury Bill yields are used as the risk-free rate because they 18 possess no default-risk and the time to maturity is short enough to minimize risks 19 from inflation. The 30-year U.S. Treasury Bond is also used as a risk-free rate of 20 return. This is not universally accepted because the value of U.S. Treasury Bonds 21 fluctuates as interest rates change. An investment in U.S. Treasury Bonds is a 22 risk-free investment if the investor plans to hold it until maturity. The risk-free 23 instrument chosen will have an effect on the results of the CAPM analysis. 24 Whichever instrument is selected, it should be used consistently in the equation. 25 Beta 26 The beta coefficient measures the volatility of return eamed by the utility's stock 27 relative to the volatility of the returns eamed by the broader equity market. The 13 The theoretical support for the CAPM is the work done by Hany Markowitz ("Portfolio Selection," Jolll'nal of Finance, March, 1952). W.F. Sharpe added the concept of a risk-free rate of return to the Markowitz model ("A Simplified Model of Po1ifolio Analysis, Management Science, January, 1963). 39
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 broad equity market is frequently measured using the S&P 500 Index. This 2 measure provides a look at the risk and volatility of a stock relative to other 3 investments. A stock with a beta of one is just as volatile as the market, .5 and the 4 stock is half as volatile as the market, and 1.25 it is twenty-five percent more 5 volatile than the market. 6 Rm 7 Rm is the expected return on the stock market as measured by a broad market 8 index such as the S&P 500. This represents the total return consisting of the price 9 change of the index plus dividends earned for the year. 10 Rp 11 The risk premium is the difference between investors' expected return from the 12 stock market and their expected return from the risk-free investment over the 13 same time period. The 1isk premium is written as Rm-Rf. The market return and 14 the risk-free return should be taken from the same time period so as to accurately 15 measure the additional return required by investors to take on the risk of common 16 stocks over the risk-free investment. Rp is calculated using the historic market 17 returns discussed above and the historic returns on U.S. Treasury Bills or Bonds 18 from the same time period. 19 Q Please discuss your CAPM analysis. 20 A . I took two distinct approaches to the CAPM analysis. I performed one analysis 21 using historic measures of returns from the stock and bond markets and a second 22 analysis using forecasted returns. The results using historic returns are drastically 23 higher; 9.20% compared to 6.64%. 24 Both forms of my CAPM analysis incorporate the beta coefficients for the proxy 40
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 group. As you can see in the following table, the average for the group, as well as 2 Westar, is 0.75 meaning the total return of the proxy group on average is about 3 75% of the broad market. This is a clear indication that electric utilities like 4 Westar and the proxy group are less volatile than the broad stock market, and 5 investors expect a return lower than that expected of the market.
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6 7 Q Please describe the forecasted-CAPM analysis. 8 A For the forecasted-CAPM, I relied on the expected returns published JPMAM in 9 its annual publication, Long-Term Capital Market Assumptions. JPMAM 10 publishes 10 to 15 year forecasts of expected returns on dozens of investment 11 asset classes. What is unique about this product is that JPMAM publishes not 12 only the forecasted return, but also an extensive discussion that explains how they 41
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 anived at those forecasted retums. 14 JPMAM provides the following discussion 2 of how it uses the long term capital market return assumptions (LTCMRA) in its 3 own business as well as its intended audience. As you can see in the following 4 table, JPMAM forecasts an annual return on common stocks of 7.60%. The 5 Commission should compare this forecast to Mr. Somma's expectations for the 6 stock market; he expects annual returns of 13.25%. Mr. Somma's expectations 7 are far above the expected. How do investors use the LTCMRAs? The Long-Term Copital Morket Return Assumptions ore used widely by investment teoms throughout J.P. Morgan Asset Management as well os by institutional investors-including pension plons. insuronce companies. endowments and foundations-to ensure that investment policies and strategic asset allocations are developed based on a comprehensive and consistent set of "real world~ views. In addition the LTCMRAs allow the resulting investment characteristics and return profiles to be tested and analysed, facilitating o more effective communication and underwriting of the implied risk and return profile. When used, as is most often the case, to review an existing strategic asset allocation, the LTCMRAs can help investors to better assess and quantify the trade-offs available to them across multiple dimensions. These trade-offs include: the relative risk premia betvveen more and less volatile ossets; the risk premio ossociated with investing outside of their own domestic asset classes: which opportunities exist to increase portfolio diversification: and which nominal or real return target is achievable with a given level of portfolio volatility and vice versa. 8 9 Following the calculations and inputs through the CAPM equation in line 2 of the 10 following table, the forecasted return on a risk-free investment, 10 Year U.S. 11 Treasury Bonds, is subtracted from the expected return on common stocks 14 Long-term Capital Market Return Assumptions: 2015 Estimates and Thinking Behind the Numbers; J.P. Morgan Asset Management; p. 7; https://am. jpmorgan.com/lu/institutional/ltcmra 42
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 resulting in a risk premium of 3.19%. This risk premium is essentially the 2 additional return necessary to induce investors to talce on the added risk associated 3 with common stocks over the risk free investment. The beta coefficient is applied 4 to the risk premium to ascertain how much of a risk premium is necessary for 5 investors to, in this instance, take on risks of investing in electric utility stocks as 6 opposed to the risk :free U.S. Treasury Bond. As the electric utilities like the 7 proxy group and Westar are less risky than common stock in general, their risk 8 premium is 2.39%.
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Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 The expected risk free yield of 4.25% 15 is added to the beta specific risk premium 2 to arrive at the cost of equity for the given beta coefficient of 6.64% 100 basis 3 points less than the returns JPMAM is forecasting for the broad stock market 4 indexes. These results appear low by historical measures, although in the current 5 capital markets investors in Westar, long-term bonds are purchasing bonds with 6 the expectation for returns or around 3.80% to 4.00% in March 2015 through May 7 of2015. 8 Q Please discuss the historical-CAPM analysis. 9 A I performed a CAPM analysis incorporating historic data of returns earned from 10 1926 through 2014. The process is the same as that applied in the Forecasted 11 CAPM. 15 JMAM is one source for forecasted data. Another source is the Survey of Professional Forecasters published by the Federal Reserve Bank of Philadelphia; https://www.philadelphiafed.org/research-and-data/real-time-center/survey-of-professional-forecasters/2015/survq 115 .cfm At page 17 in the February 13, 2015, edition the Survey, it is reported that for the next ten years, the mean expected annual return on the S&P 500 Index is 5.79% (20 forecasts) while the mean expected yield on 10 Year Treasury Bonds is 3.91% (25 forecasts). Forecasters project annual growth in real GDP over the next ten years of2.51% and an annual inflation rate of 1.83% to 2.03%. 44
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS _I
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2 Keep in mind that, in relying on historic data, we are assuming that ce1iain trends 3 observed in the past will continue in the future. Most notably, we would be 4 assuming that the historic risk premium relationship observed in the returns on 5 common stocks versus the returns on U.S. Treasury Bonds continues in the future. 6 The historic risk premium is 5.70% which is drastically greater than the 3.19% 7 risk premium expected by professional forecasters and institutional investors. 8 That difference is an indication that institutional investors and professional 9 forecasters do not expect the future nominal returns to be as great as those 10 experienced in the past. 45
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 Staff Response to Mr. Somma's Direct Testimony 2 Q What is the ROE Westar is requesting? 3 A Westar is requesting an ROE of 10.00%. 4 Q How did Westar arrive at a cost of equity estimate of 10%? 5 A Westar witness Anthony Somma provided a cost of equity analysis. His findings 6 are summarized in this table which is from page 63 of his testimony. Table 11 Adlusted ROE Recommendation Range Wei!lht Weighted Range DCF Results 9.47% 9.52% 50.0% 4.74% 4.76% Forward CAPM Results 10.86% 11.76% 25.0% 2.72% 2.94% Risk Premium Results 10.33% 10.38% 25.0"Ai 2.58% 2.60"/o 10.03% 10.30"/o Issuance Costs 0.12% 0.12% Adjusted ROE 10.15% 10.42% 7 8 His cost of capital study an"ives at a range of 10. 00% to 10 .3 0%. As you can see 9 in the table, Mr. Somma places greatest weight, 50%, on the DCF analysis. He 10 weights the results of his CAPM and Risk Premium at 25% each. 11 Q . Generally, what are your criticisms of Mr. Somma's analysis? 12 A Mr. Somma's DCF analysis assumes an unsustainably high growth rate, adjusting 13 that growth rate to a level that reflects the realities of the current and prospective 14 economy lowers the result closer to Staffs DCF analysis. Mr. Somma's CAPM 15 and Risk Premium analysis contain too many points of disagreement at both the 16 theoretical and application level, that I recommend the Commission place no 17 weight on them. 18 Q IS it reasonable to expect corporate earnings and dividends to grow at a rate 46
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 that is so much greater than forecasted nGDP? 2 A No, it is not a reasonable expectation. As I explained earlier, there is a 3 considerable amount of both academic research and professional application of 4 the DCF model that discuss the growth rate issue. The research from both realms 5 is very clear: the broad measure of economic growth, most always defined as 6 nGDP, is a necessary limit on dividends and earnings growth. 7 Q Did you uncover any other evidence that Mr. Somma's CAPM analysis 8 overstates investors' required returns? 9 A Yes, there are obvious indicators in Mr. Somma's CAPM. For instance, the 10 required return on the market is very high and well above reasonable 11 expectations. Mr. Somma's CAPM assumes that the annual average return on the 12 S&P 500 Index will be 13.25%. His forecasts for the equity market far exceed 13 historic return of 12.10% 16 and far exceed the expected returns for the future. As 14 a point of comparison, J.P. Morgan Asset Management forecasts an annual return 15 of7.60 to 8.80% on common stocks over the next 10 to 15 years.17 16 Q Does Mr. Somma's CAPM analysis provide the Commission with useful data 17 to estimate Westar's cost of equity? 18 A No, it does not. The Commission should not place any weight on Mr. Somma's 19 CAPM analysis as I have demonstrated that the inputs are not representative of 20 the capital markets and would not be relied on by investors. 16 Historic total return on the S&P 500 Index from 1926 through 2014 as reported in Ibbotson SBBI 2015 Classic Yearbook, Market Returns for Stocks, Bonds, Bills & Inflation; Morningstar. 17 Long-Term Capital Market Return Assumptions: 2015 Estimates and the Thinking Behind the Numbers. https://am.jpmorgan.com/us/institutional/ltcmra 47
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Response to Westar Proxy Group 2 Q Do you agree with the proxy group Mr. Somma used in his cost of equity 3 analysis? 4 A No. Mr. Somma incorporates a market capitalization selection parameter that I do 5 not use in my selection. 6 Q Do you believe the proxy group is a cause of the difference in ROE estimates 7 between you and Mr. Somma? 8 A No, it is unlikely the cause of the difference as all of Mr. Somma's proxy 9 companies are in my analysis and, generally, except for the market capitalization 10 parameter, his selection criteria is similar to those that I used. Given these 11 similarities, I will not spend time rebutting his proxy group. 12 Q To be clear, are you using the same proxy group as Mr. Somma? 13 A No. My proxy group is larger, consisting of 22 electric utilities, and it includes all 14 12 of the electric utilities in Mr. Somma's proxy group. 15 Response to Westar DCF Analysis 16 Q On page 45 of his direct testimony, Mr. Somma states that his DCF analysis 17 results in a mean of 9.47% and a median of 9.52%. Why are his estimates so 18 much higher than your DCF analysis? 19 A There are two reasons for the difference: 1) the growth rates he selects; and 2) his 20 exclusion of the results of one company. Mr. Somma shows the result of his DCF 21 analysis in Table 3 on page 45 of his testimony. Oddly enough, there are no 22 tables in his Direct Testimony that show his specific inputs for his DCF model; 23 that information only exists in his work papers .. 48
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Q Why do you disagree with the growth rates in Mr. Somma's DCF analysis? 2 A I disagree because he relies solely on three to five year earnings growth forecasts 3 for his estimate of growth in his DCF model. Throughout his testimony, he refers 4 to securities analysts' three to five year earnings growth forecasts as "long-term 5 forecasts." His methodology is contrary to the fundamentals of the DCF model 6 which views growth prospects well beyond Mr. Somma's three to five year 7 horizon. 8 I discuss growth rate selection for the DCF model earlier in my testimony. 9 Research demonstrates that securities valuation theory and its practical 10 application of the DCF model demands a long-term view of growth. Whether the 11 practitioner uses a two-stage DCF model, as I have or single stage DCF model as 12 Mr. Somma has done, the practitioner has to recognize that the DCF model 13 demands a long-term growth projection; a growth estimate that goes beyond the 14 three to five year window of analysts' earnings growth forecasts. 15 Q What are the sources for Mr. Somma's growth estimates? 16 A He obtains three to five year forecasts of earnings growth from Value-Line 17 Investment Survey, Thomson Reuters, and Bloomberg. I do not object to any of 18 these sources for earnings growth rate estimates. I only object to Mr. Som.ma's 19 position that market participants use a three to five year forecast as that which 20 continues far beyond that time period. 18 21 Q How do his growth forecasts compare to historic growth rates for electric 22 utilities? 18 His DCF calculations and the inputs to his DCF analysis appear only in his work papers (KCC #85). 49
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 A Mr. Somma does not provide any sort of review, analysis, or historical context for 2 his growth rates, nor does he even disclose the growth rates in his testimony. 3 Which is an odd presentation when he in fact acknowledges that the growth rate 4 in the DCF model is " ... the most significant area of controversy among model 5 inputs." 19 Despite his acknowledgment that this is a critical input to a DCF 6 model, he never provides any historical context for this critical input. 7 Q You stated earlier that a 4.38% annual growth in nGDP is forecasted for the 8 coming decades. How does that compare to the growth rates Mr. Somma 9 uses? 10 A As you can see in the following table, the average three to five year annual 11 earnings growth forecast for Westar's proxy group is 5.86%; significantly greater 12 than the forecasted growth rate for the economy. Mr. Somma never attempts to 13 explain why it is reasonable for us to assume that his proxy group of electric 14 utilities will grow at a rate so much greater than the U.S. economy for many 15 decades into the future. 19 SommaDirect 15-WSEE-115-RTS; p43; line 1. 50
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS
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1 2 Q You stated earlier that you disagree with the removal of IDACORP, Inc. 3 from the DCF results. Why do you disagree? 4 A Mr. Somma concluded that the DCF outcomes for IdaCorp were too low to be 5 logically representative of the capital markets, so he removed that result from the 6 average. Mr. Somma stated that he removed IdaCorp from the average because 7 its DCF results " ... yielded a return on equity lower than the cost of debt that 8 Westar is requesting. "20 While that statement is true, it is not a reason for 9 removing that observation from the average. For an appropriate comparison, Mr. 10 Somma should be looking to the market cost of debt in the cmrnnt capital markets 11 as opposed to the embedded or historic cost of debt. In the time period in which 12 Mr. Somma gathered pricing data, the yield on Baa/BBB rated utility debt was 13 about 4.30%. Thus, by a measure of current, market derived bond yields, the 20 Somma Direct p44 51
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 estimates for IdaCorp should remain in the analysis. Leaving IdaCorp in the data 2 set lowers the average. 3 A test such as that applied by Mr. Somma is a common test used in cost of equity 4 studies as means to remove observations that are illogically low relative to other 5 investments. It is common place to assume to use observations on utility bond 6 yields as a benchmark. For instance, FERC has adopted a low-end limit of the 7 prevailing yield on utility bonds plus 100 basis points under the rationale that 8 investors would require a minimum risk premium of 100 basis points over the 9 available bond yield to induce them to purchase the common stock. As I pointed 10 out in the previous paragraph, the widely accepted benchmark is market yield; it 11 is not the historic or embedded yield as Mr. Somma relied on. 12 Q If Mr. Somma had incorporated a long-run perspective in his growth 13 forecast and in IdaCorp, how much would that change the results of his DCF 14 analysis? 15 A Giving the nGDP and his earnings growth rate forecast equal weighting would 16 lower the average of his DCF results 62 basis points. Shown in Table 3 on page 17 45 of Mr. Somma's Testimony, the average of 9.47% would decrease to 8.85% 18 which is comparable to the cost of equity estimates in Staffs DCF analysis. 19 Response to Westar's Capital Asset Pricing Model 20 Q Do you agree with the results of Mr. Somma's CAPM analysis? 21 A No, I do not. His CAPM analysis does not provide an accurate picture of 22 Westar's capital costs because of overly optimistic long-run growth rates. 23 Q What is the result of Mr. Somma's CAPM analysis? 52
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 A Mr. Som.ma's CAPM analysis indicates a cost of equity in the range of 10.86% to 2 11.76%. 3 Q Where is the growth rate applied in the CAPM? 4 A In Mr. Som.ma's CAPM analysis, the three to five year annual earnings growth 5 rate estimate is used to calculate the market return (Rm) used in the CAPM. 6 Thus, the growth rate is a couple layers deep into the CAPM equation, but 7 nonetheless it has a tremendous impact on the end result of the CAPM. The 8 growth rate is used to estimate the expected return on the S&P 500 stock index. 9 The expected return on the market index becomes the foundation for the 10 calculation of the individual company. If the foundation or Rm does not comport 11 with capital market theory and realistic valuation practices, then the CAPM 12 analysis on the individual company will be inaccurate. 13 Q What is the Rm supposed to represent? 14 A In the CAPM the Rm is the return expected by investors through an index of the 15 stock market such as the S&P 500. 16 Q What does Mr. Somma claim the S&P 500 will return in the future? 17 A Mr. Somma estimated that the S&P 500 will return 13.25% annually for many, 18 many years into the future; a dizzyingly high return that is even higher than the 19 often cited historic return on common stocks of 12.10% for 1926 through 2014. 21 20 Economic growth for the foreseeable future is forecast to be significantly lower 21 than that experienced in those 88 years. This forecast for the S&P 500 is solely 22 his own. He does not provide any support for this estimate or provide any 21 Ibbotson SBBI 2015 Classic Yearbood: Market Results for Stocks, Bonds, Bills, and Inflation 1926-2014; Momningstar; p.40. 53
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 corroborating studies indicating that market participants factor estimates similar 2 to his into their decisions. I have not come across any analytical work that could 3 support such a high return on common stocks in the coming decades. 4 Q How does Mr. Somma arrive at his forecast of a 13.25% annual return from 5 the S&P 500? 6 A He performs a DCF analysis on each of the 500 companies in the S&P 500 Index. 7 The calculation requires a dividend yield and a long-run growth rate estimate to 8 apply to each company's dividends. Just as with the DCF estimates for his proxy 9 group, the calculation of the dividend yield is relatively uncontroversial. It is his 10 growth rate estimates that cause an extraordinarily high cost of equity estimate. 11 Q What growth does he apply to each of the 500 companies? 12 A Mr. Somma uses the annual earnings growth rate estimate obtained from 13 Bloomberg, a source he also uses in his DCF analysis of his proxy group. 14 Bloomberg reports the consensus or average of analysts' growth forecasts. These 15 are three to five year earnings growth rate projections. Consensus estimates are 16 an average of growth estimates made by analysts. 17 Q How does he apply the growth forecasts? 18 A Mr. Somma's calculations assume that the three to five year earnings growth for 19 each company continues in perpetuity, forever. For any company with a negative 20 three to five year earnings growth forecast, he applied a growth rate of zero. That 21 is to say, he has biased his growth estimate by assuming that no company in the 22 S&P 500 will ever experience negative earnings growth. He did not provide any 23 support or evidence that market participants share his level of optimism. I have 54
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 not evaluated the effect of Mr. Somma zeromg out the negative growth 2 projections; I find that to be an unusual methodology to use in evaluating the 3 expected return for the market. 4 Q With that unique methodology that Mr. Somma applies, what is the growth 5 rate that Mr. Somma assumes for the S&P 500? 6 A Mr. Somma expects earnings of the S&P 500 Index to grow at annual rate of 7 11.28%; more than two and a half times the expected growth rate of the nation's 8 economy. Mr. Somma's CAPM is highly dependent on this extraordinarily high 9 earnings growth forecast. Incorporating a growth forecast that is more in line 10 with expected long-run growth will lower the results of his CAPM analysis 11 proportionally to the change in forecasted growth. A growth rate estimate that is 12 more in line with expectations will result in a CAPM result that is closer to my 13 CAPM results.* 14 Q Are there any notable data points in Mr. Somma's S&P 500 index? 15 A In Mr. Somma's analysis the forecasted growth rate for ExxonMobile is negative 16 for the next three to five years. That is not smprising given the sudden drop in 17 energy prices; it is conceivable that the company could experience a contraction 18 in earnings for a period of time. Mr. Somma' s CAPM analysis assumes 19 ExxonMobile, the second largest publicly traded corporation in the world, will 20 forever have a growth rate of zero. Mr. Somma does not attempt to reconcile his 21 application of the CAPM with the reality of the financial markets. Under Mr. 22 Somma's analysis, we would expect the price of ExxonMobile to collapse; it has 55
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 not collapsed, it has declined in value as have most energy companies, but it has 2 not collapsed. 3 Q If Mr. Somma is projecting zero growth, in lieu of the negative growth rate 4 reported by Bloomberg, why would ExxonMobile continue to have value and 5 continue to be the second largest investment vehicle in the world? 6 A I would surmise that it is because investors do not apply growth forecasts in the 7 same manner as Mr. Somma has done throughout his analysis. Rather than 8 believing that analysts' three to five year earnings growth forecasts are the sole 9 forecasts for valuation analysis, market participants likely recognize that 10 ExxonMobile's three to five year growth forecast should not be used as an 11 estimate of growth in to perpetuity. That is why the stock has not collapsed and it 12 continues to be one of the largest corporations in the world. ExxonMobile is not 13 the only data point that exhibits a negative growth rate that was zeroed out by Mr. 14 Somma, there are several more examples in his analysis. 15 Response to Westar's Risk Premium Study 16 Q Do you agree with the results of the Risk Premium study that begins on page 17 50 of Mr. Somma's Testimony? 18 A I disagree with using this type analysis in setting Westar's allowed return because 19 this type of analysis has several shortcomings that cast doubt on the applicability 20 of the results. Although the data provides an interesting view of regulatory and 21 financial history, I recommend the Commission disregard it in setting Westar's 22 allowed return. 56
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 Q How is the risk premium study constructed? 2 A Mr. Somma's risk premium analysis is based on observations of allowed returns 3 granted by state regulatory commissions to electric utilities in litigated cases and 4 the yield on 10 Year U.S. Treasury Bonds prevailing at the time of the rate case. 5 From these observations, he established a relationship between the risk premium 6 (the allowed ROE granted by commissions minus the prevailing yield on 10 Year 7 U.S. Treasury Bond) and the yield on the 10 Year U.S. Treasury Bond. 8 Q Is this a new type of analysis for estimating the cost of equity? 9 A Mr. Somma's Risk Premium analysis is similar to that filed by several different 10 Kansas jurisdictional utilities in recent gas and electric rate cases. My criticism of 11 Westar' s risk premium analysis is the same as in those recent dockets. 12 Q Is the reasonable return on equity for Westar equal to the return granted to 13 other utilities in other jurisdictions many years ago? 14 A No, relying on the allowed returns granted to other utilities in other jurisdictions 15 runs the risk of overlooking data in the present day capital markets, setting an 16 allowed return on what could be outdated information. At a minimum, such a 17 practice creates a degree of circular reasoning that could preclude a Commission 18 from setting an allowed return at any level other than some historic average when 19 cmTent economic conditions call for something different. Hope and Bluefield 20 emphasize that an allowed return changes with changes in the capital markets. 21 Q What are your observations of Mr. Somma's risk premium study? 22 A The Commission needs to be cautious in using Mr. Somma's risk premium study 23 because it does not comport with the framework set out in the Hope and Bluefield 57
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 decisions, as there is no comparison of the risk of the electric utilities in the 2 historic data to the risk of Westar today. The Hope and Bluefield decisions state 3 that an allowed return must be commensurate with risks on similar investments; 4 Mr. Somma's risk premium study does not speak to that standard. It would be 5 comparable to merely perfmming a DCF analysis on all of the electric utilities, 6 without attempting to select a proxy group of comparable risk. Both I and Mr. 7 Somma recognize that electric utility companies are different from one another. 8 That is why both of us culled through many publicly traded electric utilities to 9 arrive at our respective proxy groups that we believe are similar in risk to Westar. 10 Keep in mind that research publications such as Value-Line cover about 45 11 companies in the electric utility industry, from which Mr. Somma selected 12 as 12 being of comparable risk to Westar; an indication that he believes that electric 13 utilities are not of equal risk. 14 Q Have the electric utility industry and regulatory policies evolved and changed 15 over this period of time since 1980 that alters its risk profile? 16 A Yes, I believe it has changed over this 35 year time period and Mr. Somma's risk 17 premium analysis fails to recognize any changes to the industry as merely 18 plugging in a recent interest rate does not measure changes in risk. For instance, 19 rate design, and trackers/riders/pass-through mechanisms have evolved over the 20 past two decades; these mechanisms lower the risk of utilities by shifting risk to 21 the consumer. Mr. Somma fails to account for such changes in the industry. 22 Equally important as those formal mechanisms used in Kansas is this Staff's 23 willingness to update Westar's rate base well beyond the test-year balances which 58
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 is a tremendous benefit to Westar. Mr. Somma does not offer his thoughts on 2 whether the Kansas regulatory mechanisms and post-test-year updates are the 3 n01m for the industry either now or over history. Thus, based on Mr. Somma's 4 Testimony we cannot know whether those observations in the 1980's and 1990's 5 provide us with a risk premium measure that is applicable today. 6 Risk premium studies such as these provide some historical perspective of the 7 changes in capital costs that occurred in the past three decades and, for that reason 8 alone, a review of the data is interesting. The findings in this risk premium 9 analysis are not compelling evidence because there is no distinction of risk among 10 the observations in the data. 11 Response to Westar' s Request for Flotation Costs 12 Q Has Westar requested recovery of flotation costs as part of its cost of equity? 13 A Yes, Mr. Somma has requested an additional 12 basis points to recover the 14 flotation costs associated with issuing equity capital. 15 Q Does Staff support the recovery of such expenses added to the allowed return 16 on equity? 17 A No. Staff does not support inclusion of flotation costs in its cost of equity because 18 Westar has not attempted to quantify the amount, if any, of unrecovered costs 19 associated with it issuing common equity. 20 Q How much does Westar's adjustment collect in flotation costs? 21 A In the following table, I calculate the annual revenue requirement of Westar's 22 proposed 12 basis point adjustment to recover flotation costs. 59
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1 2 Westar does not quantify the dollar amount of this element on the revenue 3 requirement, nor does it explain why recovering this expense through the cost of 4 equity is efficient. I contend that it is not efficient because the cost of equity has 5 to be grossed up to recover the associated income taxes. 6 Q Is there a more efficient way to recover those costs? 7 A Yes, simply track the actual costs, and include a pro forma adjustment to the test 8 year operations to include those costs as an expense in the rate case. We could 9 certainly spread recovery of those costs over a several decades. 10 Q If the Commission follows past practices and allows Westar an allowance for 11 flotation costs, does Mr. Somma's estimate of 12 basis points comport that 12 practice? 13 A Yes, it does, as he has applied the flotation cost adjustment to common equity less 14 the retained earnings portion of common equity. Historically, flotation cost 15 adjustments calculated in this manor are in the range of 10 to 12 basis points. 16 Response to Westar's Claim of Needing a Premium on its ROE 17 Q Did you evaluate Mr. Somma's claim that Westar could justify a higher 18 return due to its "small size"? 60
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 A Yes, the issue of higher return or a premium to the allowed return related to 2 "small size" is not new to the Commission, although I believe this is the first time 3 it has been made by one of our major utilities. The Commission is faced with this 4 argument from time to time in testimony from rural telephone companies in 5 Kansas Universal Service Fund audits. 6 Q Has the Commission explicitly agreed that small utilities require a premium 7 on their allowed return? 8 A My recollection of the past decade is that the Commission has not explicitly 9 agreed with the concept of small utilities requiring a premium or higher allowed 10 return solely due to their relative size. Those decisions have almost exclusively 11 been in telecommunications cases dealing with regulated entities that are much, 12 much smaller than Westar. If the Commission is unwilling to accept the notion of 13 a small-size premium on those companies, there would be good reason not to 14 adopt such a premium for a much larger entity like Westar. 15 Q What is your position on the small-size premium? 16 A I have consistently opposed this type of adjustment because it is not a widely 17 accepted premise in public utility finance (or even finance generally) that size as 18 measured by capitalization is a determinant of risk. The data used to support the 19 notion of a small company risk premium has shown that there is a survivorship 20 bias. The survivorship bias stems from the fact that a larger proportion of small 21 companies cease to exist than larger companies. The studies supporting a small 22 company premium frequently fail to measure the full extent of the loss incuned 23 by investors in those small companies that disappear. Accurately measuring those 61
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 losses has been shown to eliminate measured small company premium. 2 There is a tremendous amount of data mining that has taken place on this very 3 topic and similar beliefs of market inefficiencies some believe create 4 opportunities for investors. Professor Burton Malkiel author of A Random Walk 5 Down Wall Street, addresses the measurement of a size premium along with 6 several other alleged measures of market inefficiencies in a 2003 journal article. 7 His conclusion is that if investors cannot replicate or exploit the alleged market 8 inefficiency, it likely does not exist. As this passage discusses, professionals have 9 attempted to profit from these alleged market conditions and it is not profitable. 22 l\fony of the predictable patterns that have been discovered may simply be the result of data mining. The ease ofcxperimentingwith financial clatabanks ofalmost every conceivable dimension makes it quite likely that investigators will find some seemingly significant but wholly spurious correlation between financial variables or among financial and nonfinancial data sets. Given enough time and massaging of data series, it is possible to tease almost any pattern out of most data sets. Moreover, the published literature is likely to be biased in favor of reporting such results. Significant effects are likely to be published in professional journals while negative results, or boring confirmations of previous findings, arc relegated to the file drawer or discarded. Data-mining problems are unique to nonexperimental sci-ences, such as economics, which rely on statistical analysis for their insights and cannot test hypotheses by running repeated controlled experiments. An exchange at a symposium about a decade ago between Robert Shiller, an economist who is sympathetic to the argument that stock prices are partially predictable and skeptical about market efficiency, and Richard Roll, an academic financial economist who also is a portfolio manager, is quite revealing (Roll and Shiller, 1992). After Shiller stressed the importance of inefficiencies in the pricing of stocks, Roll responded as follows: I have personally tried to invest money, my client's money and my own, in every single anomaly and predictive device that academics have dreamed up .... I have attempted to exploit the so-called year-end anomalies and a whole variety of strategics supposedly documented by academic research. And I have )'Cf to mahe a 111'.clwl on any of these supposed mar/wt i'.11ejficiencies ... a true market inefficiency ought to be an exploitable opportunity. IF there's nothing investors can exploit in a systematic way, time in and time out, then it's very hard to say that information is not being properly incorporated into stock 10 prices. 22 The Efficient Market Hypothesis and Its Critics; Burton G. Malkiel; Journal of Economic Perspectives; Volume 17, Number 1, Winter 2003; pp 59-82. 62
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 It is clear from the research on this issue that it is possible to dredge the data 2 banks and find instances where there was some measure of a premium, but 3 investors establish their required return based on risk and there are more reliable 4 measures of the risk in an investment than the size of the company. 5 Response to Proposed ROE Adjustment Mechanism 6 Q At page 71 of his Direct Testimony, Mr. Somma describes an ROE 7 adjustment mechanism. Do you believe the Commission should adopt such a 8 mechanism? 9 A No. I have reviewed Mr. Somma's proposal. Staf:f s objection to this mechanism 10 is not based on the nuances of Mr. Somma' s proposal; it is based on the 11 conceptual notion of an annual adjustment to a utility's allowed return. Staff does 12 not support such a mechanism for Westar because it would set one critical 13 element of the revenue requirement for annual adjustment while there is no annual 14 adjustment for other key drivers of the revenue requirement. Additionally, 15 Westar's allowed return is evaluated in each general rate case and, given the 16 cmTent climate of heavy capital expenditures there have been and will likely 17 continue to be, regularly filed general rate cases. I want to emphasize that 18 Staff is opposed to such a mechanism. If the Commission has an interest in it, 19 Staff recommends that it be considered through a generic proceeding where 20 record is developed for the Commission to assess how this policy change would 21 affect the diverse group of stake-holders in Kansas. 22 Capital Structure 23 Q Have you reviewed the capital structure proposed by Westar? 63
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 A Yes, I reviewed the capital structure Westar proposed in Section 7 and addressed 2 in the Direct Testimony of Susan M. North. Westar calculated its ROR using a 3 capital structure based on the test year ending September 30, 2014, applying 4 adjustments to reflect projected balances to December 31, 2014, and then pro 5 forma adjustments so that the capital structure reflects what it believes is a picture 6 of its capitalization beyond the test year. Staff is accepting of post-test year 7 adjustments to capital accounts as these are relatively easy to verify. 9 Q Do you agree with the capital structure proposed by Westar? 10 A Generally, yes. I would only note that the proposed equity ratio is high relative to 11 Westar's equity ratio reported in the past. It is not outlandishly high, but it is 12 higher than that seen for more than a decade. As the difference is merely a couple 13 percentage points difference than the historic observations, I am not proposing 14 any adjustment to the capital structure. Staff is using Westar's capital structure as 15 shown in Section 7 ofWestar's Application. 64
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS Equity Ratio 51.00% ~------------------ 50.00% _,___ _ __ 49.00% _,___ _ __ 48.00% -l----~ 46.00% 45.00% 44.00% 2010 2011 2012 2013 2014 I 2
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_ IP()~~R~ti()_J _§3,4~_%1. ______ .. 4.9.-4-~o/ol_ .. ___ n,11y.,L _______ 5Q,7~%L ___ 50.§0o/o!- 3
- - - ri 46.54%1 r-IEquityRatio --- 1 -
50.54%1
- - --
- 1 - - - ---r-- -*-49.24%1 48.89%/
-----r-- ---r
-----49.40%1 4 Cost of Debt 5 Q What is Westar asking to recover as its cost of debt capital?
6 A In Section 7, Schedule 7-C Westar calculates an embedded cost oflong-term debt 7 of5.687%. 8 Q Do you agree with Westar's cost of debt? 9 A Yes, that is the value that Staff will use to calculate the ROR. 10 Wolf Creek Decommissioning Trust Annual Accrual 11 Q Please discuss the Wolf Creek Decommissioning issues in this Docket? 12 A In this Docket, we are dealing with what is referred to as Phase-Two of the 13 triennial review of the Wolf Creek decommissioning cost estimate. In Phase-One 65
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 of the review, the Wolf Creek Owners23 submitted a decommissioning cost 2 estimate and a forecasted cost-inflation rate. Those two variables are used in 3 Phase-Two for each of the owners to calculate their annual accrual payment to its 4 decommissioning trust fund. The annual accrual payment is part of the operating 5 expenses recovered through their respective revenue requirements. Susan North 6 presents Westar's proposal for Phase-Two. 7 Q What is Westar's proposal for its annual accrual? 8 A Westar has calculated an annual accrual of $3,150,070 to fund its portion of the 9 decommissioning costs. I disagree with Westar's proposal. 10 Q Please describe the analysis. 11 A The goal of the calculations shown in Exhibit SMN-1 of Susan North's Direct 12 Testimony is to estimate how much Westar must deposit each year in a tmst 13 account so as to have sufficient funds in the future to pay its share of 14 decommissioning Wolf Creek at the end of its operations. Westar's analysis 15 incorporates ten variables to arrive at an estimate for the annual accrual. 16
- Decommissioning cost estimate set in Phase-One (15-WCNE-093-17 GIE) 18
- Decommissioning timing set in Phase-One (l 5-WCNE-093-GIE) 19
- Remaining life of fund 20
- Westar's 47% ownership percentage 21
- Kansas jurisdictional allocation factor 22
- Trust fund investment mix 23
- Trust fund management fees 24
- Taxes on fund earnings 25
- Earnings on fund investments 26
- Current trust fund balance 23 Westar Energy owns 47% of Wolf Creek Nuclear Operating Corporation; Great Plains Energy owns 47%; and Kansas Electric Power Cooperative, Inc. owns the remaining 6%.
66
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 Now that the Commission has adopted a Decommissioning Plan in Phase-One, all 2 but two of the variables are readily discemable. That is to say, for most of the 3 inputs there is not much latitude in what constitutes a realistic input. The two 4 variables, the trust fund investment mix and the earnings on fund investments, are 5 difficult and somewhat speculative to forecast. Fortunately, these forecasts are 6 reviewed every three years; they are not set once and for all. Future Commissions 7 will have the opportunity to make adjustments in the future as new information 8 comes to light. 9 Q Is the proposed investment asset mix reasonable? 10 A The investment mix in Westar's analysis is a reasonable approximation because it 11 presents estimated asset allocation parameters that are likely to apply over the life 12 of the trust. Just as Westar modeled in Exhibit SMN-1, the investment mix 13 should change over time. The trust does not exist into perpetuity; it has a 14 definitive liquidation date and, at the end of its life, it is expected to achieve a 15 specific goal. Thus, as it nears the end-date, the portfolio managers should 16 increase the use of less volatile, fixed income investments so as to protect the 17 value. With the lower volatility investment vehicles comes a lower return. 18 Exhibit SMN-1 coITectly models that facet of the investment strategy. 19 Q Are the forecasted returns reasonable? 20 A I disagree with the forecasted returns that Westar used in Exhibit SMN-1. 21 Westar's forecasted returns are built largely from historic returns from 1985-2013 22 for the equity investments or historic risk premiums for this time period coupled 23 with the cuITent interest rate on the 30 Year Treasury Bonds for the fixed income 67
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 securities. My concern with a reliance on historic returns is that historic returns 2 embody a level of annual economic growth that is considerably higher than what 3 is likely in the future. It is generally the case that long-run projected returns on 4 both debt and equity investments are lower than those experienced in the recent 5 past. This trend is attributed to expectations for lower inflation relative to historic 6 averages and expectations for slower growth in GDP. 7 Q What data did you rely on to review the forecasted returns in SMN-1 and the 8 adequacy of Westar's proposed annual accrual? 9 A I relied on the 10 to 15 year returns forecasted by J.P. Morgan Asset 10 Management. As you can see in the following table, J.P. Morgan's forecasts for 11 equity returns are much lower than Westar' s forecasts, and its forecasts for returns 12 on cash or short-term fixed income securities are higher than Westar's forecast. I * .. . - 1 Comparison of
~~~ecasted
.. r*** * * * * * *
- Retu.lns
- J* * ..
I.I 1.*.......... _ I .. 1 .... J~:E>.)Vlorg~n. J i i Westar* I Forecasted** I I;LargeQ1pitalizati_on Equitie.s I* 11.40% 1... ..... .. . . 7.60% I
\small GapitalizationEqn.ities io.i7%1 . . -. . . j.8i%1 Hnternati.011111 J3quities . I 7.§5%1 ~)Q%1 lc~rre.~2P.ci~_(C()rp()rate.s) I 4.89%1 4.95%!
lfll@Yielci_~ond~ ..... }'.63o/oi ......*.....*. * . 6.4o%J l~e!llJ~sta!e. J 7.73%/ 8.17%1
.. 1 Cash & Equivalents i 6.98% 1 * . . '2~00% I 1 .......... . . . ...... I .......... I I
. I*As :fiJeci in the testimcmy of Susan Ne>rj:ll CS.1'4N)).. I I . . .. ! . .. . I. I
)**Asset class forecasts ()f 10 to 15 year annll<l.l re.'tt!r~; J ILQpg~te.1111GapitaJ Mar~et :tletu.rnAs_sllll1pti()~,_ I 1 ..
/2015 l~ciitioll(lJ. S. );}._I>. :Morgi:tn J\sse.tJvilltJ:age.111e.11t.. .. 1 13 ! I I !
14 Q Why do you believe it is reasonable to use the forecasts from J.P. Morgan to 68
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 estimate the annual accrual? 2 A This information was prepared by JPMAM who manages investments globally. 3 As such, these forecasts represent the expectations of an important market 4 participant that directly manages $1. 7 trillion. As an asset manager, JPMAM 5 does not have an incentive to skew the forecasts, as doing so could harm its ability 6 to effectively manage client money. In its 2015 publication, it provides the 7 following discussion of how investors can make use of these forecasts.2 4 Our 8 evaluation of the decommissioning trust and capital costs fall within JPMAM 9 intended use. How do investors use the LTCMRAs? The Long-Term Capital Market Return Assumptions are used widely by investment teams throughout J.P. Morgan Asset Management as well as by institutional investors-including pension plans, insurance companies, endowments and foundations-to ensure that investment policies and strategic asset allocations are developed based on a comprehensive and consistent set of "real world" views. In addition the LTCMRAs allow the resulting investment characteristics and return profiles to be tested and analysed, facilitating a more effective communication and underwriting of the implied risk and return profile. When used, as is most often the case, to review an existing strategic asset allocation, the LTCMRAs can help investors to better assess and quantify the trade-offs available to them across multiple dimensions. These trade-offs include: the relative risk premia between more and less volatile assets; the risk premia associated with investing outside of their own domestic asset classes; which opportunities exist to increase portfolio diversification: and which nominal or real return target is achievable with a given level of portfolio volatility and vice versa. 10 11 Q Precisely what changes do you propose making to Exhibit SMN-1? 12 A My recommendation is to change the expected retums on the various asset classes 24 Long-term Capital Market Return Assumptions: 2015 Estimates & Thinking Behind the Numbers; J.P. Morgan Asset Management; p. 7; https://am. jpmorgan.com/lu/institutional/ltcmra 69
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 from those proposed by Westar to the expected returns presented in the JPMAM 2 study shown in the previous table. The market balance of Westar' s trust fund 3 needs to recognize income taxes that must be paid on the net amount of the trust 4 fund's unrealized gains as those taxes will have to be paid sometime in the future. 5 Recognizing the tax liability reduces the balance of the trust fund. 25 6 Q What is the effect of those changes to the trust balance and expected returns? 7 A Changing the returns increases the annual accrual from $3,150,070 proposed by 8 Westar to $5,772,700. 9 Q How has the trust performed? 10 A Westar's Decommissioning Trust, accounting for the annual contributions, the 11 accumulated tax liability, and the market value at December 31, 2014, 12 experienced an annual return of 5.40% for the period of 1985 through 2014. My 13 calculations are shown in Schedule AHG-10. Westar projected returns shown in 14 Exhibit SJ\IIN-1 are substantial!y higher than its experience since 19 85. 15 Q Does this conclude your testimony? 16 A Yes. 25 Inresponse to KCC DR #334, Westar reported that the December 31, 2014, a fair value $185,015,632 that includes net unrealized gains of $20,929,450. At a 20% tax rate, the hust fund has a tax liability of
$4,185,890.
70
Schedule AHG-1 15-WSEE-115-RTS Yield on Moody's Baa Utility Bonds January 1919 -May 2015 0.00
-t-----.-~..-----.---,~-.----r~-.---r-~.---.---.-~..,..--r---ir-----r---.-~-.----.-~r---,---,.~--.----.-~..,..-----.---,.---.----,.~-.----,--~..-----.- ~ ~~~~ ~ ~** ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ -~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
Schedule AHG-1 15-WSEE-115-RTS Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Unlity Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Baa A Baa A Baa A Baa A Baa A Baa A Baa A Jan-19 6.89 6.35 Jan-24 6.73 6.02 Jan-29 5.48 5.05 Jan-34 8.86 6.56 Jao-39 4.66 3.68 Jan-44 3.54 2.99 Jao-49 3.42 2.99 Feb-19 6.91 6.39 Feb-24 6.64 6.00 Feb-29 5.52 5.10 Feb-34 7.58 5.78 Feb-39 4.59 3.59 Feb-44 3.53 2.99 Feb-49 3.40 2.99 Mar-19 6.91 6.41 Mar-24 6.60 5.97 Mar-29 5.62 5.14 Mar-34 7.58 5.66 Mar-39 4.53 3.54 Mar-44 3.52 2.97 Mar-49 3.36 2.97 Apr-19 6.88 6.18 Apr-24 6.55 5.94 Apr-29 5.69 5.14 Apr-34 7.18 5.44 Apr-39 4.62 3.55 Apr-44 3.53 2.99 Apr-49 3.31 2.96 May-19 6.84 6.27 May-24 6.42 5.91 May-29 5.66 5.14 May-34 7.17 5.39 May-39 4.50 3.50 May-44 3.53 2.99 May-49 3.30 2.95 Jun-19 6.84 6.19 Jun-24 6.32 5.79 Jun-29 5.72 5.23 Jun-34 7.20 5.40 Jun-39 4.41 3.47 Jun-44 3.53 2.99 Jun-49 3.28 2.94 Jul-19 6.79 6.16 Jul-24 6.23 5.68 Jul-29 5.79 5.24 Jul-34 7.36 5.29 Jul-39 4.39 3.43 Jul-44 3.51 2.96 Jul-49 3.25 2.90 Aug-19 6.80 6.26 Aug-24 6.24 5.70 Aug-29 5.89 5.30 Aug-34 7.68 5.43 Aug-39 4.39 3.41 Aug-44 3.51 2.94 Aug-49 3.25 2.86 Sep-19 6.94 6.44 Sep-24 6.24 5.71 Sep-29 5.92 5.38 Sep-34 7.62 5.56 Sep-39 4.64 3.71 Sep-44 3.51 2.93 Sep-49 3.22 2.85 Oct-19 7.01 6.41 Oct-24 6.21 5.65 Oct-29 5.91 5.34 Oct-34 7.38 5.40 Oct-39 4.48 3.58 Oct-44 3.51 2.94 Oct-49 3.19 2.83 Nov-19 7.08 6.67 Nov-24 6.24 5.62 Nov-29 6.00 5.29 Nov-34 7.21 5.38 Nov-39 4.38 3.41 Nov-44 3.53 2.96 Nov-49 3.17 2.81 Dec-19 7.25 6.79 Dec-24 6.13 5.63 Dec-29 5.96 5.23 Dec-34 7.03 5.36 Dec-39 4.36 3.38 Dec-44 3.54 2.97 Dec-49 3.16 2.78 Jan-20 7.30 6.85 Jan-25 6.12 5.61 Jan-30 5.92 5.26 Jan-35 6.60 5.18 Jan-40 4.30 3.34 Jan-45 3.50 2.99 Jan-50 3.18 2.76 Feb-20 7.48 7.03 Feb-25 6.08 5.52 Feb-30 5.93 5.29 Feb-35 6.20 4.96 Feb-40 4.23 3.35 Feb-45 3.48 2.98 Feb-50 3.17 2.76 Mar-20 7.59 7.04 Mar-25 6.02 5.53 Mar-30 5.80 5.18 Mar-35 5.99 4.88 Mar-40 4.14 3.34 Mar-45 3.48 2.97 Mar-50 3.16 2.76 Apr-20 7.88 7.36 Apr-25 5.99 5.52 Apr-30 5.77 5.15 Apr-35 5.94 4.79 Apr-40 4.06 3.25 Apr-45 3.49 2.95 Apr-50 3.15 2.77 May-20 8.03 7.72 May-25 5.85 5.25 May-30 5.76 5.04 May-35 5.51 4.61 May-40 4.10 3.30 May-45 3.47 2.92 May-50 3.15 2.79 Jun-20 7.99 7.73 Jun-25 5.82 5.25 Jun-30 5.78 5.01 Juo-35 5.41 4.53 Jun-40 4.15 3.34 Jun-45 3.43 2.87 Jun-50 3.15 2.79 Jul-20 8.21 7.82 Jul-25 5.83 5.37 Jul-30 5.78 4.99 Jul-35 5.22 4.42 Jul-40 3.99 3.23 Jul-45 3.40 2.83 Jul-50 3.18 2.79 Aug-20 8.21 7.96 Aug-25 5.87 5.42 Aug-30 5.70 4.95 Aug-35 5.22 4.44 Aug-40 3.98 3.21 Aug-45 3.37 2.80 Aug-50 3.18 2.76 Sep-20 8.29 7.83 Sep-25 5.85 5.40 Sep-30 5.63 4.86 Sep-35 5.25 4.43 Sep-40 3.94 3.18 Sep-45 3.34 2.79 Sep-50 3.19 2.80 Oct-20 8.27 7.75 Oct-25 5.83 5.39 Oct-:io 5.82 4.88 Oct-35 5.24 4.40 Oct-40 3.92 3.15 Oct-45 3.29 2.79 Oct-50 3.20 2.83 Nov-20 8.28 7.73 Nov-25 5.81 5.43 Nov-30 6.15 4.96 Nov-35 5.12 4.35 Nov-40 3.88 3.11 Nov-45 3.22 2.77 Nov-50 3.21 2.86 Dec-20 8.36 7.96 Dec-25 5.88 5.36 Dec-30 6.56 5.11 Dec-35 5.07 4.29 Dec-40 3.86 3.10 Dec-45 3.15 2.75 Dec-50 3.21 2.86 Jan-21 8.51 7.74 Jan-26 5.81 5.29 Jnn-31 6.36 5.01 Jan-36 4.88 4.21 Jan-41 3.87 3.15 Jan-46 3.07 2.69 Jan-51 3.21 2.83 Feb-21 8.50 7.65 Feb-26 5.76 5.21 Feb-31 6.37 5.01 Feb-36 4.80 4.17 Feb-41 3.90 3.20 Feb-46 3.00 2.67 Feb-51 3.21 2.84 Mar-21 8.51 7.61 Mar-26 5.80 5.23 Mar-31 6.18 4.98 Mar-36 4.78 4.17 Mar-41 3.90 3.16 Mar-46 2.96 2.66 Mar-51 3.23 2.95 Apr-21 8.52 7.61 Apr-26 5.75 5.20 Apr-31 6.19 4.86 Apr-36 4.77 4.17 Apr-41 3.86 3.14 Apr-46 2.98 2.65 Apr-51 3.31 3.09 May-21 8.54 7.66 May-26 5.67 5.15 May-31 6.36 4.84 May-36 4.76 4.14 May-41 3.85 3.08 May-46 3.02 2.69 May-51 3.38 3.13 Jun-21 8.62 7.64 Jun-26 5.61 5.11 Jun-31 6.60 4.87 Jun-36 4.72 4.12 Jun-41 3.83 3.03 Jun-46 3.04 2.70 Jun-51 3.45 3.21 Jul-21 8.64 7.72 Jul-26 5.61 5.13 Jul-31 6.47 4.83 Jul-36 4.62 4.07 Jul-41 3.82 3.00 Jul-46 3.03 2.69 Jul-51 3.49 3.26 Aug-21 8.66 7.67 Aug-26 5.62 5.15 Aug-31 6.60 4.81 Aug-36 4.59 4.06 Aug-41 3.80 2.98 Aug-46 3.02 2.71 Aug-51 3.48 3.19 Sep-21 8.30 7.32 Sep-26 5.62 5.17 Sep-31 7.04 5.05 Sep-36 4.54 4.05 Sep-41 3.80 3.00 Sep-46 3.06 2.75 Sep-51 3.44 3.14 Oct-21 8.40 7.04 Oct-26 5.61 5.18 Oct-31 8.01 5.54 Oct-36 4.53 4.04 Oct-41 3.82 3.00 Oct-46 3.06 2.76 Oct-51 3.49 3.17 Nov-21 7.92 6.55 Nov-26 5.58 5.15 Nov-31 7.80 5.51 Nov-36 4.53 3.95 Nov-41 3.82 2.98 Nov-46 3.07 2.76 Nov-51 3.49 3.24 Dec-21 7.68 6.32 Dec-26 5.54 5.12 Dec-31 8.81 6.24 Dec-36 4.53 3.83 Dec-41 3.85 3.06 Dec-46 3.07 2.76 Dec-51 3.53 3.29 Jan-22 7.83 6.41 Jan-27 5.51 5.10 Jan-32 8.18 6.17 Jan-37 4.50 3.82 Jan-42 3.83 3.09 Jan-47 3.05 2.72 Jan-52 3.57 3.29 Feb-22 7.74 6.32 Feb-27 5.54 5.13 Feb-32 8.33 6.41 Feb-37 4.55 3.89 Feb-42 3.81 3.09 Feb-47 3.03 2.72 Feb-52 3.55 3.23 Mar-22 7.55 6.22 Mar-27 5.54 5.13 Mar-32 8.31 6.06 Mar-37 4.76 4.00 Mar-42 3.84 3.12 Mar-47 3.04 2.72 Mar-52 3.55 3.25 Apr-22 7.29 6.06 Apr-27 5.49 5.04 Apr-32 9.56 6.83 Apr-37 4.98 4.07 Apr-42 3.79 3.09 Apr-47 3.04 2.70 Apr-52 3.54 3.23 May-22 6.86 5.93 May-27 5.50 5.04 May-32 10.21 7.36 May-37 5.02 4.00 May-42 3.76 3.10 May-47 3.03 2.70 May-52 3.54 3.22 Jun-22 6.92 5.91 Jun-27 5.51 5.05 Jun-32 10.70 7.57 Jun-37 5.17 3.99 Jun-42 3.73 3.12 Jun-47 3.04 2.71 Jun-52 3.55 3.22 Jul-22 6.83 5.89 Jul-27 5.48 5.05 Jul-32 10.11 7.28 Jul-37 5.08 3.94 Jul-42 3.68 3.10 Jul-47 3.03 2.73 Jul-52 3.53 3.22 Aug-22 6.88 5.86 Aug-27 5.43 5.02 Aug-32 7.92 6.35 Aug-37 5.04 3.89 Aug-42 3.67 3.10 Aug-47 3.02 2.73 Aug-52 3.50 3.24 Sep-22 6.77 5.69 Sep-27 5.41 4.98 Sep-32 7.48 5.91 Sep-37 5.25 3.96 Sep-42 3.66 3.08 Sep-47 3.06 2.80 Sep-52 3.50 3.24 Oct-22 6.51 5.83 Oct-27 5.39 4.95 Oct-32 7.87 5.81 Oct-37 5.53 4.09 Oct-42 3.66 3.08 Oct-47 3.13 2.88 Oct-52 3.50 3.26 Nov-22 6.56 5.87 Nov-27 5.38 4.92 Nov-32 8.32 5.88 Nov-37 5.59 4.08 Nov-42 3.67 3.07 Nov-47 3.18 2.93 Nov-52 3.47 3.24 Dec-22 6.56 5.95 Dec-27 5.32 4.88 Dec-32 8.41 5.85 Dec-37 5.60 4.03 Dec-42 3.68 3.06 Dec-47 3.25 3.05 Dec-52 3.50 3.22 Jan-23 6.59 5.85 Jan-28 5.24 4.85 Jan-33 8.86 5.39 Jan-38 5.59 4.01 Jan-43 3.65 3.05 Jan-48 3.30 3.05 Jan-53 3.51 3.25 Feb-23 6.60 5.83 Feb-28 5.20 4.85 Feb-33 7.58 5.77 Feb-38 5.79 4.03 Feb-43 3.61 3.02 Feb-48 3.31 3.05 Feb-53 3.53 3.30 Mar-23 6.73 6.06 Mar-28 5.18 4.82 Mar-33 7.58 6.34 Mar-38 5.80 3.99 Mar-43 3.58 3.01 Mar-48 3.29 3.02 Mar-53 3.56 3.36 Apr-23 6.78 6.04 Apr-28 5.18 4.82 Apr-33 7.18 6.89 Apr-38 5.82 4.08 Apr-43 3.60 3.00 Apr-48 328 2.97 Apr-53 3.62 3.47 May-23 6.78 6.00 May-28 5.23 4.87 May-33 7.17 6.50 May-38 5.32 3.95 May-43 3.60 3.00 May-48 3.27 2.94 May-53 3.76 3.63' Jun-23 6.80 6.06 Jun-28 5.38 4.99 Jun-33 7.20 6.11 Jun-38 5.33 3.95 Jun-43 3.60 2.98 Jun-48 3.29 2.94 Jun-53 3.80 3.71 Jul-23 6.79 6.02 Jul-28 5.38 5.04 Jul-33 7.36 5.91 Jul-38 5.01 3.86 Jul-43 3.55 2.96 Jul-48 3.34 2.99 Jul-53 3.83 3.66 Aug-23 6.77 5.77 Aug-28 5.43 5.08 Aug-33 7.68 5.98 Aug-38 4.93 3.84 Aug-43 3.55 2.96 Aug-48 3.40 3.03 Aug-53 3.88 3.61 Sep-23 6.81 5.95 Sep-28 5.45 5.05 Sep-33 7.62 6.36 Sep-38 5.05 3.88 Sep-43 3.55 2.96 Sep-48 3.42 3.05 Sep-53 3.93 3.62 Oct-23 6.79 5.98 Oct-28 5.43 4.99 Oct-33 7.38 6.36 Oct-38 4.90 3.79 Oct-43 3.53 2.97 Oct-48 3.44 3.03 Oct-53 3.86 3.49 Nov-23 6.78 6.00 Nov-28 5.38 4.98 Nov-33 7.21 7.06 Nov-38 4.77 3.73 Nov-43 3.55 2.98 Nov-48 3.48 3.07 Nov-53 3.78 3.40 Dec-23 6.80 6.05 Dec-28 5.32 5.05 Dec-33 7.03 7.22 Dec-38 4.77 3.74 Dec-43 3.55 2.99 Dec-48 3.47 3.06 Dec-53 3.72 3.38
Schedule AHG-1 15-WSEE-115-RTS Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Baa A Baa A Baa A Baa A Baa A Baa A Baa A Jan-54 3.72 3,32 Jan-S9 4.71 4.52 Jan-64 4.74 4.49 Jan-69 7.42 7.04 Jan-74 8.58 8.36 Jan-79 10.29 9.90 Jan-84 14.05 13.39 Feb-54 3.69 3.23 Feb-59 4.77 4.50 Feb-64 4.74 4.50 Feb-69 7.39 7.13 Feb-74 8.68 8.42 Feb-79 10.27 9.84 Feb-84 14.05 13.41 Mar-54 3.SS 3.16 Mar-59 4.69 4.47 Mar-64 4.73 4.51 Mar-69 7.61 7.27 Mar-74 8.81 8.46 Mar-79 10.53 10.D4 Mar-84 14.56 13.87 Apr-S4 3.S3 3.16 Apr-S9 4.68 4.56 Apr-64 4.75 4.52 Apr-69 7.68 7.30 Apr-74 9.04 8.77 Apr-79 10.56 10.10 Apr-84 14.82 14.16 Mizy-54 3.SI 3.14 May-59 4.87 4.77 May-64 4.73 4.53 May-69 7.56 7.16 May-74 9.23 9.00 Mizy-79 10.70 10.30 May-84 15.28 14.90 Jun-54 3.50 3.16 Jun-59 4.97 4.86 Jun-64 4.74 4,55 Jun-69 7.77 7.41 Jun-74 9.48 9.32 Jun-79 10.56 10.14 Jun-84 15.50 15.09 Jul-54 3.48 3.14 Jul-S9 5.03 4.88 Jul-64 4.75 4.54 Jul-69 7.92 7.52 Jul-74 9.72 9.66 Jul-79 10.48 9.98 Jul-84 15.50 14.82 Aug-54 3.47 3.13 Aug-S9 S.04 4.89 Aug-64 4.75 4.54 Aug-69 7.82 7.44 Aug-74 10.14 10.03 Aug-79 10.50 10.14 Aug-84 14.79 14.43 Sep-S4 3.44 3.12 Sep-S9 5.17 5.03 Sep-64 4.73 4.53 Sep-69 8.11 7.63 Sep-74 10.59 ID.45 Sep-79 10.78 10.36 Sep-84 14.51 14.17 Oct-54 3.41 3.12 Oct-59 5.29 4.96 Oct-64 4.72 4.51 Oct-69 8.47 8.02 Oct-74 11.03 10.78 Oct-79 11.89 11.40 Oct-84 14.17 13.80 Nov-S4 3.39 3.11 Nov-S9 5.20 4.90 Nov-64 4.72 4.53 Nov-69 8.53 8.00 Nov-74 11.38 10.46 Nov-79 12.48 11.89 Nov-84 13.72 13.23 Dec-S4 3.38 3.11 Dec-59 S.13 4.96 Dec..64 4.72 4.54 Dec-69 8.89 8.59 Dec-74 11.40 10.27 Dec-79 12.SI 11.79 Dec-84 13.46 13.11 Jan-SS 3.37 3.13 Jan-60 5.20 5.02 Jan-65 4.71 4.53 Jan-70 9.00 8.69 Jan-75 11.57 10.37 Jan-80 12.92 12.27 Jan-85 13.36 12.99 Feb-SS 3,38 3.14 Feb-60 5.23 5.00 Feb-65 4.69 4.51 Feb-70 8.96 8.51 Feb-75 11.32 9.99 Feb-80 14.42 13.55 Feb-85 13.44 13.08 Mar-55 3.38 3.IS Mar-60 5.11 4.91 Mar-65 4.68 4.50 Mar-70 8.81 8.31 Mar-75 10.94 9.72 Mar-80 15.26 14.65 Mar-85 14.19 13.87 Apr-55 3.40 3.15 Apr-60 4.96 4.79 Apr-65 4.69 4.49 Apr-70 8.94 8.31 Apr-75 10.86 10.06 Apr-80 14.35 13.87 Apr-85 14.ll 13.61 May-SS 3.40 3.19 May-60 S.08 4.86 May-65 4.71 4.50 May-70 9.20 8.67 May-75 10.95 10.23 May-80 12.93 12.S3 May-85 13.62 13.12 Jun-SS 3.41 3.21 Jun-60 5.0S 4.84 Jun-65 4.77 4.52 Jun-70 9.52 9.04 Jun-75 10.85 ID.JO Jun-80 12.63 12.21 Jun-85 12.66 12.13 Jul-SS 3.43 3.21 Jul-60 S.03 4.79 Jul-65 4.78 4.54 Jul-70 9.48 9.06 Jul-75 10,80 10.01 Jul-80 12.75 12.26 Jul-85 12.70 12.07 Aug-SS 3.46 3.24 Aug-60 4.81 4.64 Aug-65 4.79 4.58 Aug-70 9.34 8.88 Aug-75 10.87 10.12 Aug-SO 13.SO 12.96 Aug-85 12.73 12.13 Sep-SS 3.48 3.27 Sep-60 4.71 4.57 Sep-65 4.82 4.63 Sep-70 9.32 8.82 Sep-75 10.89 10.19 Sep-80 14.07 13.43 Sep-85 12.72 12.13 Oct-SS 3.47 3.30 Oct-60 4.82 4.61 Oct-65 4.85 4.66 Oct-70 9.27 8.76 Oct-75 10.89 10.16 Oct-80 14.43 13.58 Oct-85 12.52 12.01 Nov-SS 3.48 3.32 Nov-60 4.80 4.62 Nov-65 4.89 4.71 Nov-70 9.29 8.79 Nov-75 10.78 10.04 Nov-80 14.79 14.12 Nov-85 12.04 11.49 Dec-SS 3.50 3.35 Dec-60 4.78 4.65 Dec-65 4.97 4.83 Dec-70 9.04 8.48 Dec-75 10.79 10.ll Dec-80 15.29 14.63 Dec-85 11.48 10.97 Jan-56 3.SO 3.31 Jan-61 4.79 4.64 Jan-66 4.99 4.86 Jan-71 8,76 8.15 Jan-76 10.55 9.90 Jan-81 15.30 14.26 Jan-86 11.24 10.79 Feb-S6 3.50 3.29 Feb-61 4.76 4.59 Feb-66 5.02 4.92 Feb-71 8.55 7.89 Feb-76 10.31 9.71 Feb-SI 15.86 14.91 Feb-86 10.74 10.26 Mar-S6 3.SI 3.29 Mar-61 4.72 4.48 Mar-66 5.19 S.14 Mar-71 8.63 8.0S Mar-76 10.17 9.67 Mar-81 IS.83 15.14 Mar-86 9.91 9.48 Apr-56 3.59 3.40 Apr-61 4.74 4.48 Apr-66 5.39 5.25 Apr-71 8.58 8.07 Apr-76 9.95 9.53 Apr-81 16.14 15.48 Apr-86 9.63 9.14 May-S6 3.62 3.48 May-61 4.77 4.52 May-66 5.44 5.25 May-71 8.68 8.34 May-76 9.91 9.55 May-81 16.66 16.25 May-86 10.02 9.S9 Jun-S6 3.65 3.49 Jun-61 4.78 4.57 Jun-66 5.52 5.40 Juo-71 8.79 8.45 Jun-76 10.01 9.54 Juo-81 16.30 15.74 Jun-86 10.03 9.62 Jul-56 3.70 3.SS Jul-61 4.84 4.65 Jul-66 5.61 5.45 Jul-71 8.78 8.45 Jul-76 9.88 9.37 Jul-81 16.98 16.21 Jul-86 9.69 9.37 Aug-56 3.84 3.63 Aug-61 4.90 4.73 Aug-66 5.79 5.58 Aug-71 8.80 8.40 Aug-76 9.67 9.13 Aug-81 17.19 16.58 Aug-86 9,70 9.29 Sep-S6 4.02 3.72 Sep-61 4.91 4.73 Sep-66 6.06 5.81 Sep-71 8.59 8.18 Sep-76 9.47 8.90 Sep-81 17.76 17.16 Sep-86 9.96 9.52 Oct-56 4.15 3.79 Oct-61 4.92 4.71 Oct-66 6.07 5.74 Oct-71 8.48 8.10 Oct-76 9.41 8.79 Oct-81 17.71 1721 Oct-86 9.52 9.52 Nov-56 4.15 3.82 Nov-61 4.89 4.68 Nov-66 6.06 5.63 Nov-71 8.47 7.96 Nov-76 9.34 8.76 Nov-81 16.49 16.20 Nov-86 9.69 9.28 Dec-56 4.18 3.91 Dec-61 4.88 4.6S Dec-66 6.09 5.67 Dec-71 8.44 7.90 Dec-76 9.21 8.62 Dec-SI 17.02 16.29 Dec-86 9.49 9.12 Jan-57 4.26 3.96 Jan-62 4.86 4.6S Jan-67 5.83 5.46 Jan-72 8.37 7.79 Jan-77 9.17 8.61 Jan-S2 17.83 16.83 Jan-87 927 8.95 Feb-57 4.26 4.05 Feb-62 4.86 4.66 Feb-67 5.63 528 Feb-72 8.32 7.78 Feb-77 9.19 8.65 Feb-82 17.83 16.84 Feb-87 9.24 9.00 Mar-S7 4.2S 4.05 Mar-62 4.85 4.64 Mar-67 5.69 5.44 Mar-72 8.26 7.77 Mar-77 9.20 8.70 Mar-S2 17.16 16.50 Mar-87 9.19 8.93 Apr-S7 424 4.01 Apr-62 4.81 4.59 Apr-67 5.74 5.42 Apr-72 8.30 7.82 Apr-77 9.17 8.71 Apr-82 17.00 16.31 Apr-87 9.85 9.38 May-57 4.28 4.01 May-62 4.74 4.51 May-67 5.93 5.66 May-72 8.30 7.84 May-77 9.13 8.71 May-S2 16.68 16.04 May-87 ID.40 9.91 Juo-57 4.33 4.09 Jun-62 4.68 4.48 Jun-67 6.14 5.84 Jun-72 8.31 7.77 Juo-77 9.02 8.58 Jun-82 17.21 16.42 Jtm-87 10.46 10.02 Jul-57 4.41 420 Jul-62 4.68 4.50 Jul-67 6.23 5.94 Jul-72 8.36 7.82 Jul-77 8.97 8.Sl Jul-82 17.09 16.42 Jul-87 10.62 10.15 Aug-57 4.19 4.37 Aug-62 4.72 4.53 Aug-67 6.29 S.96 Aug-72 8.22 7.64 Aug-77 8.91 8.49 Aug-82 16.37 15.83 Aug-87 10.90 10.45 Sep-S7 4.66 4.S5 Sep-62 4.74 4.51 Sep-67 6.32 6.05 Sep-72 8.01 7.61 Sep-77 8.85 8.46 Sep-82 15.68 15.40 Sep-87 11.58 11.22 Oct-57 4.73 4.61 Oct-62 4.71 4.49 Oct-67 6.42 6.18 Oct-72 7.94 7.66 Oct-77 9.01 8.61 Oct-82 15.10 14.79 Oct-87 11.29 10.75 Nov-57 4.82 4.62 Nov-62 4.65 4.45 Nov-67 6.63 6.48 Nov-72 7.86 7.60 Nov-n 9.06 8.64 Nov-S2 14.81 14.46 Nov-87 11.18 10.61 Dec-57 4.81 4.36 Dec-62 4.66 4.44 Dec-67 6.91 6.67 Dec-72 7.78 7.48 Dec-77 9.08 8.64 Dec-82 14.69 14.43 Dec-87 11.09 10.54 Jan-58 4.60 3.93 Jan-63 4.65 4.39 Jan-68 6.76 6.54 Jau-73 7.77 7.S2 Jan-78 9-27 8.92 Jan-83 14.56 1424 Jan-88 ID.SO 9.96 Feb-58 423 3.96 Feb-63 4.65 4.37 Feb-68 6.68 6.37 Feb-73 7.88 7.62 Feb-78 9.29 8.97 Feb-83 14.61 14.26 Feb-88 10.23 9.70 Mar-58 4.2S 4.13 Mar-63 4.66 4.37 Mar-68 6.75 6.41 Mar-73 7.95 7.66 Mar-78 9.37 8.98 Mar-83 14.33 13.94 Mar-88 10.43 9.84 Apr-58 4.25 3.95 Apr-63 4.67 4.37 Apr-68 6.94 6.58 Apr-73 7.96 7.63 Apr-78 9.54 9.09 Apr-83 14.07 13.61 Apr-88 11.08 ID.40 May-S8 4.23 4.01 May-63 4.67 4.37 May-68 6.99 6.62 May-73 7.91 7.63 May-78 9.70 9.22 May-S3 14.05 13.50 May-88 1128 10.72 Juo-S8 4.20 3.99 Jun-63 4.67 4.37 Juo-68 7.01 6.62 Jun-73 7.94 7.71 Juo-78 9.78 9.40 Jun-S3 14.16 13.64 Juo-88 II.DO 10.53 Jul-S8 4.19 4.04 Jul-63 4.67 4.39 Jul-68 6.92 6.53 Jul-73 8.10 7.82 Jul-78 9.73 9.SI Jul-83 14.01 13,58 Jul-88 1!22 10.75 Aug-S8 4.44 429 Aug-63 4.66 4.38 Aug-68 9.72 6.27 Aug-73 8.47 8.04 Aug-78 9.S3 9.32 Aug-83 14.21 13.57 Aug-88 11.39 10.89 Sep-S8 4.69 4.55 Sep-63 4.69 4.40 Sep-68 6.67 6.27 Sep-73 8.61 8.04 Sep-78 9.47 9.28 Sep-83 14.10 13.42 Sep-88 10.92 10.41 Oct-SS 4.74 4.S6 Oct-63 4.66 4.41 Oct-68 6.74 6.40 Oct-73 8.44 8.02 Oct-78 9.69 9.46 Oct-83 13.95 1325 Oct-88 10.31 10.01 Nov-58 4.67 4.47 Nov-63 4.68 4.42 Nov-68 7.01 6.59 Nov-73 8.44 8.IS Nov-78 9.99 9.68 Nov-83 14.12 13.38 Nov-88 10.35 9.90 Dec-S8 4.6S 4.49 Dec-63 4.73 4.46 Dec-68 7.23 6.87 Dec-73 8.51 8.24 Dec-78 10.08 9.70 Dec-83 14.23 13.52 Dec-88 10.44 10.06
Schedule AHG-1 15-WSEE-115-RTS Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Moody's Public Utility Bond Data Baa A Baa A Baa A Baa A Baa A Baa A Jan-89 10.38 10.08 Jan-94 7.66 7.33 Jan-99 7.30 6.97 Jan-04 6.47 6.16 Jan-09 7.90 6.39 Jon-14 5.09 4.63 Feb-89 10.38 10.07 Feb-94 7.76 7.47 Feb-99. 7.41 7.09 Feb-04 6.28 6.15 Feb-09 7.74 6.30 Feb-14 5.01 4.53 Mar-89 10.50 10.23 Mar-94 8.11 7.85 Mar-99 7.55 7.26 Mar-04 6.13 5.97 Mar-09 8.00 6.42 Mar-14 5.00 4.51 Apr-89 10.49 10.18 Apr-94 8.47 8.22 Apr-99 7.51 7.22 Apr-04 6.46 6.35 Apr-09 8.03 6.48 Apr-14 4.85 4.41 May-89 10.29 9.99 May-94 8.61 8.33 May-99 7.74 7.47 May-04 6.75 6.62 May-09 7.76 6.49 May-14 4.69 4.26 Jun-89 9.80 9.64 Jun-94 8.64 8.31 Jun-99 8.03 7.74 Jun-04 6.84 6.46 Jun-09 7.30 6.19 Jun-14 4.73 4.29 Jul-89 9.64 9.50 Jul-94 8.80 8.47 Jul-99 7.97 7.71 Jul-04 6.67 6.27 Jul-09 6.87 5.97 Jul-14 4.66 4.23 Aug-89 9.64 9.52 Aug-94 8.74 8.41 Aug-99 8.16 7,91 Aug-04 6.45 6.14 Aug-09 6.36 5.71 Aug-14 4.65 4.13 Sep-89 9.70 9.58 Sep-94 8.98 8.64 Sep-99 8.19 7.93 Sep-04 6.27 5.98 Sep-09 6.12 5.53 Sep-14 4.79 4.24 Oct-89 9.64 9.54 Oct-94 924 8.86 Oct-99 8.32 8.06 Oct-04 6.17 5.94 Oct-09 622 5.64 Oct-14 4.67 4.06 Nov-89 9.64 9.51 Nov-94 9.35 8.98 Nov-99 8.12 7.94 Nov-04 6.16 5.96 Nov-09 6.16 5.64 Nov-14 4.15 4.09 Dec-89 9.60 9.44 Dec-94 9.16 8.76 Dec-99 8.28 8.14 Dec-04 6.10 5.92 Dec-09 6.27 5.83 Dec-14 4.70 3.95 Jan-90 9.74 9.56 Jan-95 9.15 8.73 Jan-00 8.40 8.35 Jan-05 5.95 5.78 Jan-10 6.13 5.77 Jan-15 4.39 3.58 Feb-90 9.96 9.76 Feb-95 8.93 8.52 Feb-00 8.33 8.25 Fel>-05 5.76 5.61 Feb-10 6,27 5.88 Fel>-15 4.44 3.67 Mar-90 10.Q6 9.85 Mar-95 8.78 8.37 Mar-00 8.40 8,28 Mar-05 6.00 5.83 Mar-10 6.24 5.88 Mar-15 4.51 3.74 Apr-90 10.13 9.92 Apr-95 8.67 8.27 Apr-00 8.40 8.29 Apr-05 5.95 5.64 Apr-10 6.06 5.66 Apr-15 4.51 3.75 May-90 10.16 10.00 MaY-95 8.30 7.91 May-00 8.86 8.70 May-05 5.88 5.53 May-10 5.97 5.44 May-15 4.91 4.17 Jun-90 9.96 9.80 Jun-95 8.01 7.60 Jun-00 8.47 8.36 Jun-05 5,70 5.40 Juo-10 6.18 5.46 Jul-90 9.92 9.75 Jul-95 8.11 7.70 Jul-00 8.33 &.25 Jul-05 5.80 5.51 Jul-10 5.98 5.26 Aug-90 10.12 9.92 Aug-95 8.24 7.83 Aug-00 8.25 8.13 Aug-05 5.80 5.50 Aug-10 5.55 5.01 Sep-90 10.32 10.12 Sep-95 7.98 7.62 Sep-00 8.32 8.23 Sep-05 5.83 5.52 Sep-10 5.53 5.01 Oct-90 10.28 10.05 Oct-95 7.82 7.46 Oct-00 8.29 8.14 Oct-05 6.08 5.79 Oct-10 5.62 5.10 Nov-90 10.12 9.90 Nov-95 7.81 7.43 Nov-00 8.25 8.11 Nov-05 6.19 5.88 Nov-10 5.85 5.37 Dec-90 9.96 9.73 Dec-95 7.63 7.23 Dec-00 8.01 7.84 Dec-05 6.14 5.79 Dec-10 6.04 5.56 Jan-91 9.96 9.71 Jan-96 7.64 7.22 J:in-01 7.99 7.80 Jan-06 6.06 5.74 Jan-II 6.06 5.57 Feb-91 9.68 9.47 Feb-96 7.78 7.37 Feb-01 7.94 7.74 Feb-06 6.11 5.82 Feb-11 6.10 5.68 Mar-91 9.74 9.55 Mar-96 8.15 7.73 Mar-01 7.85 7.68 Mar-06 6.26 5.98 Mar-11 5.97 5.56 Apr-91 9.64 9.46 Apr-96 8.32 7.89 Apr-01 8.06 7.93 Apr-06 6.54 6.29 Apr-11 5.98 5.55 May-91 9.64 9.44 May-96 8.45 7.98 May-01 8.11 7.99 May-06 6.59 6.41 May-11 5.74 5.32 Jun-91 9.79 9.59 Jun-96 8.51 8.06 Jun-01 8.02 7.85 Jun-06 6.61 6.40 Jun-11 5.67 5.26 Jul-91 9.69 9.55 Jul-96 8.44 8.02 Jul-01 8.05 7.78 Jul-06 6.61 6.37 Jul-11 5.70 S.27 Aug-91 9.47 9.29 Aug-96 8.25 7.84 Aug-01 7.95 7.59 Aug-06 6.43 6.20 Aug-11 5.22 4.69 Sep-91 9.35 9.15 Sep-96 8.41 8.01 Sep-01 8.12 7.75 Sep-06 626 6.00 Sep-11 5.11 4.48 Oct-91 9.32 9.12 Oct-96 8.15 7.77 Oct-01 8.02 7.63 Oct-06 624 5.98 Oct-11 5.24 4.52 Nov-91 9.28 9.05 Nov-96 7.87 7.49 Nov-OJ 7.96 7.57 Nov-06 6.04 5.80 Nov-11 4.93 425 Dec-91 9.07 8.88 Dec-96 7.98 7.59 Dec-01 8.27 7.83 Dec-06 6.05 5.81 Dec-11 5.07 4.33 Jan-92 8.98 8.84 Jan-97 8.18 7.77 Jan-02 8.13 7,66 Jan-07 6.16 5.96 Jan-12 5.06 4.34 Feb-92 9.09 8.93 Feb-97 8.02 7.64 Feb-02 8.18 7.54 Feb-07 6.10 5.90 Feb-12 5.02 4.36 Mar-92 9.16 8.97 Mar-97 826 7.87 Mar-02 8.31 7.76 Mar-07 6.10 5.85 Mar-12 5.13 4.48 Apr-92 9.11 8.93 Apr-97 8.42 8.03 Apr-02 8.25 7.57 Apr-07 6.24 5.97 Apr-12 S.11 4.40 May-92 9.01 8.87 MaY-97 828 7.89 MaY-02 8.33 7.52 MaY-07 6.23 5.99 May-12 4.97 4.20 Jun-92 8.90 8.78 Juo-97 8.12 7.72 Jun-02 8.25 7.41 Jun-07 6.54 6.30 Jun-12 4.91 4.08 Jul-92 8.69 8.57 Jul-97 7.87 7.48 Jul-02 8.08 7.31 Jul-07 6.49 6.25 Jul-12 4.85 3.93 Aug-92 8.58 8.44 Aug-97 7.93 7.51 Aug-02 7.74 7.17 Aug-07 6.51 6.24 Aug-12 4.88 4.00 Sep-92 8.54 8.40 Sep-97 7.84 7.58 Sep-02 7.62 7.08 Sep-07 6.45 6.18 Sep-12 4.81 4.02 Oct-92 8.76 8.54 Oct-97 7.67 7.35 Oct-02 7.99 7.23 Oct-07 6.36 6.11 Oct-12 4.54 3.91 Nov-92 8.86 8.63 Nov-97 7.49 7.25 Nov-02 7.75 7.14 Nov-07 6.27 5.97 Nov-12 4.42 3.84 Dec-92 8.69 8.43 Dec-97 7.41 7.16 Dec-02 7.60 7.06 Dec-07 6.51 6.16 Dec-12 4.55 4.00 Jan-93 8.57 821 Jan-98 728 7.04 Jan-03 7.47 7.06 Jan-08 6.35 6.02 Jan-13 4.66 4.15 Feb-93 8.31 S.04 Feb-98 7.36 7.12 Feb-03 7.17 6.93 Feb-08 6.60 621 Feb-13 4.74 4.18 Mar-93 8.10 7.90 Mar-98 7.37 7.16 Mar-03 7.05 6.79 Mar-08 6.68 6.21 Mar-13 4.72 4.20 Apr-93 8.11 7.81 Apr-98 7.37 7.16 Apr-03 6,93 6.64 Apr-08 6,81 6.29 Apr-13 4.49 4.00 May-93 8.18 7.86 May-98 7.34 7.16 May-03 6.47 6.36 May-08 6.79 6.28 MaY-13 4.65 4.17 Jun-93 8.05 7.75 Jun-98 721 7.03 JurHJ3 629 6.21 Jun-08 6.93 6.38 Jun-13 5.08 4.53 Jul-93 7.93 7.54 Jul-98 7.24 7.03 Jul-03 6.65 6.56 Jul-08 6.97 6.40 Jul-13 521 4.68 Aug-93 7.59 125 Aug-98 7.20 7.00 Aug-03 7.09 6.79 Aug-08 6.98 6.37 Aug-13 5.2& 4.73 Sep-93 7.35 7.04 Sep-98 7.13 6.93 Sep-03 6.87 6.56 Sep-08 7.15 6.49 Sep-13 S.31 4.80 Oct-93 7.27 7.03 Oct-98 7.13 6.96 Oct-03 6.78 6.42 Oct-08 8.58 7.56 Oct-13 5.17 4.70 Nov-93 7.69 7.30 Nov-98 7.31 7.03 Nov-03 6.69 6.37 Nov-08 8.98 7.60 Nov-13 5.24 4.77 Dec-93 7.73 7.34 Dec-98 7.24 6,91 Dec-03 6.61 6.27 Dec-08 8.11 6.52 Dec-13 5.25 4.81
0 Schedule AHG- 2
~:~Regulatory Research Associates 15-WSEE-115-RTS RE April 13, 2015 s
MAJOR RATE CASE DECISIONS--January-March 2015 The average return on equity (ROE) authorized electric utilities was 10.37% In the first quarter of 2015, compared to 9.91% in calendar-2014. There were nine electric ROE determinations for the first three months of 2015, versus 38 in all of 2014. We note that the data Includes several surcharge/rider generation cases in Virginia that incorporate plant-specific ROE premiums. Virginia statutes authorize the State Corporation Commission to approve ROE premiums of up to 200 basis points for certain generation projects (see the ( --;J, C\_ lO I _,,, ft 0 Virginia Commission Profile). ~-~l.t:Jcji~~ ~-~e~e \f'ir~inla_~_i::charge/rid_~_generation ~ases.!.:_om t~e dat~, the __ ~ O- I ayerage authorized electric ROE was 9.67% in the first qu.arter o_f?,9l?"Y~!.§.IJ_§,__~_2]'~Z9Jo~?IfJ4',~TA!~.J;iY~J:i@:l.~,*' (7) \ ROE authorized .llilli utilities was 9 .47°io for the. firsf three--mOntfis iff2Cff5ci5rffp'area~tc:f~978'%-rrrcalenaaf'.:':l(fr4. '-\ There were three gas cases that included an ROE determination in the first quarter of 2015, versus 26 in 2014. The 2014 averages do not include a Feb. 20, 2014 New York Public Service Commission steam rate decision for Consolidated Edison Co. of New York that adopted a 9.3% ROE. (We note that this report utilizes the simple mean for the return averages.) Graph 1: Average Authorized RO Es - Electric and Gas Rate Decisi()ns 13~---------~-~----~----~ 11 -Electric
-Gas 10+-----------~-----~~:-"~'-~ Q12015 Efec.-10.37%
9.5 +-----------------------"\-<~ Gas-9.47% 9+-~~-~-~~---~~---~~---~
'90 '91 '92'93'94 '95'96 '97'98 '99 '00'01 '02'03 '04 '05 '06'07'08 '09'10 '11 '12 '13 '1401
. ~5 Source: SNL Energy/RRA As shown in Graph 2 below, after reaching a low in the early-2000s, the number of rate case decisions for energy companies generally increased for the next several years, peaking in 2010 at more than 125 cases.
Graph 2: Volume of Electric and Gas Rate Case Decisions 120 1~----- "~ I 100 Tl 80 /
- ,*~ **~ ~ _ 1 1- t-l LL,_ 1-l L,~ .l','* L[l
'90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 Source: SNL Energy/RRA a.gatewood@kcc.ks,gov;printed 7/ 1/2015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS April 13, 2015 Since 2010, the number of cases has moderated somewhat but has approximated 100 In three of the last four calendar years. There were 98 electric and gas rate cases resolved In 2014 versus 99 in 2013, 111 In 2012, and 87 back in 2011. There are currently about 50 electric and gas rate cases pending nationwide, indicating a somewhat more modest level of activity in 2015, but this level of activity remains robust when compared to the late-1990s/early-2000s. Increased costs for environmental compliance, generation and delivery infrastructure upgrades and expansion, renewable generation mandates, and employee benefits argue for the continuation of an active rate case agenda over the next few years. As a result of electric industry restructuring, certain states unbundled electric rates and implemented retail competition for generation. Commissions in those states now have jurisdiction only over the revenue requirement and return parameters for delivery operations (which we footnote in our chronology beginning on page 5), thus complicating historical data comparability. We note that despite the heightened business risk associated with the less-than-robust economy, average authorized ROEs have declined modestly since 2008. We also note the increased utilization of limited issue rider proceedings that allow utilities to recover certain costs outside of a general rate case and that typically incorporate previously-determined return parameters. The table on page 3 shows the average ROE authorized in major electric and gas rate decisions annually since 1990, and by quarter since 2010, followed by the number of observations in each period. The tables on page 4 indicate the composite electric and gas industry data for all maj()r cases summarized annually since 2001 and by quarter for the past nine quarters. The individual electric and ga5 c:ases decided In the first quarter of 2015 are listed on pages 5-6, with the decision date shown first, fo(lowed)JY the company name, the abbreviation for the state issuing the decision, the authorized rate of return (ROR.), ROE, ar:id percentage of common equity in the adopted capital structure. Next we indicate the month and year.In which the ~d.opted test year ended, whether the commission utilized an average or a year-end rate base,' and the amount of the permanent rate change authorized. The dollar amounts represent the permanent rate char:ige ordered at the time decisions were rendered. Fuel adjustment clause rate changes are not re.flec:ted . **. . *.... * .. ir:i this study Please note: Historical data provided In this report may not match data provided on RRA's website due to certain differences in presentation. Dennis Sperduto ©2015, Regulatory Research Associates, Inc. All Rights Reserved. Confldent!al Subject Matter. WARNING! This report contains copyrighted subject matter and confldentlal Information owned solely by Regulatory Research Associates, Inc. ("RRA"). Reproduction, distribution or use of this report In violation of this license constitutes copyright Infringement In violation of federal and state law. RRA hereby provides consent to use the "email this story" feature to redistribute articles within the subscriber's company. Although the Information In this report has been obtained from sources that RRA believes to be rellable, RRA does not guarantee Its accuracy. a.gatewood@kcc.hgov;printed 7/1/2015
RRA-REGULATORY FOCUS April 13, 2015 Schedule AHG-2 15-WSEE-115-RTS Average Equitv Returns Authorized January 1990 - March 2015 Electric Utilities Gas Utilities Year Period ROE% (#Cases) ROE % (#Cases) 1990 Full Year 12.70 (44) 12.67 (31) 1991 Full Year 12.55 (45) 12.46 (35) 1992 Full Year 12.09 (48) 12.01 (29) 1993 Full Year 11.41 (32) 11.35 (45) 1994 Full Year 11.34 (31) 11.35 (28) 1995 Full Year 11.55 (33) 11.43 (16) 1996 Full Year 11.39 (22) 11.19 (20) 1997 Full Year 11.40 (11) 11.29 (13) 1998 Full Year 11.66 (10) 11.51 (10) 1999 Full Year 10.77 (20) 10.66 (9) 2000 Full Year 11.43 (12) 11.39 (12) 2001 Full Year 11.09 (18) 10.95 (7) 2002 Full Year 11.16 (22) 11.03 (21) 2003 Full Year 10.97 (22) 10.99 (25) 2004 Full Year 10.75 (19) 10.59 (20) 2005 Full Year 10.54 (29) 10.46 (26) 2006 Full Year 10.36 (26) 10.43 (16) 2007 Full Year 10.36 (39) 10.24 (37) 2008 Full Year 10.46 (37) 10.37 (30) 2009 Full Year 10.48 (39) 10.19 (29) 1st Quarter 10.66 (17) 10;24 (9) 2nd Quarter 10.08 (14) 9.99 (11) 3rd Quarter 10.26 (11) 9.93 (4) 4th Quarter 10.30 (17) 10.09 (12) 2010 Full Year 10.34 (59) 10.08 (37) 1st Quarter 10.32 (13) 10.10 (5) 2nd Quarter 10.12 (10) 9.88 (5) 3rd Quarter 10.36 (8) 9.65 (2) 4th Quarter 10.34 (11) 9.88 (4) 2011 Full Year 10.29 (42) 9.92 (16) 1st Quarter 10.84 (12) 9.63 (5) 2nd Quarter 9.92 (13) 9.83 (8) 3rd Quarter 9.78 (8) 9.75 (1) 4th Quarter 10.10 (25) 10.07 (21) 2012 Full Year 10.17 (58) 9.94 (35) 1st Quarter 10.24 (15) 9.57 (3) 2nd Quarter 9.84 (7) 9.47 (6) 3rd Quarter 10.06 (7) 9.60 (1) 4th Quarter 9.90 (21) 9.83 (11) 2013 Full Year 10.02 (50) 9.68 (21) 1st Quarter 10.23 (8) 9.54 (6) 2nd Quarter 9.83 (5) 9.84 (8) 3rd Quarter 9.87 (12) 9.45 (6) 4th Quarter 9.78 (13) 10.28 (6) 2014 Full Year 9.91 (38) 9.78 (26) 2015 1st Quarter 10.37 (9) 9.47 (3) agatewood@kcc.ks.gov;printed 7/1/2015
Schedule AHG-2 l 5-WSEE-115-Rrs RRA-REGULATORY FOCUS April 13, 2015 Electric utilities--Summa!Jl Table Eq. as 0/o Amt. Period ROR % (# Cases) ROE % (# Cases) Cap. Struc. (# Cases) $ Mil. (#Cases) 2001 Full Year 8.93 (15) 11.09 (18) 47.20 (13) 14.2 (21) 2002 Full Year 8,72 (20) 11.16 (22) 46.27 (19) -475.4 (24) 2003 Full Year 8.86 (20) 10.97 (22) 49.41 (19) 313.8 (12) 2004 Full Year 8.44 (18) 10.75 (19) 46.84 (17) 1,091.5 (30) 2005 Full Year 8.30 (26) 10.54 (29) 46.73 (27) 1,373.7 (36) 2006 Full Year 8.24 (24) 10.36 (26) 48.67 (23) 1,465.0 (42) 2007 Full Year 8.22 (38) 10.36 (39) 48.01 (37) 1,401.9 (46) 2008 Full Year 8,25 (35) 10.46 (37) 48.41 (33) 2,899.4 (42) 2009 Full Year 8,23 (38) 10.48 (39) 48.61 (37) 4,192.3 (58) 2010 Full Year 7.99 (59) 10.34 (59) 48.45 (54) 5,567.7 (77) 2011 Full Year 8.00 (43) 10.29 (42) 48.26 (42) 2,853.5 (56) 2012 Full Year 7.95 (51) 10.17 (58) 50.55 (52) 3,131.5 (70) 1st Quarter 7.81 (13) 10.24 (15) 49.02 (13) 765.8 (16) 2nd Quarter 7.64 (7) 9.84 (7) 50~~(j (6) 653.6 (10) 3rd Quarter 7.86 (8) 10.06 (7) 50.77 ..Cf3) 734.4 (11) 4th Quarter 7.46 (17) 9.90 (21) 48.20 (16) 1,315.8 (25) 2013 Full Year 7.66 (4S) 10.02 (SO) 49~2S (43) 3,469.6 (62) 1st Quarter 7.71 (6) 10.23 {8) 51:08 * (8) 251.4 (9) 2nd Quarter 7.81 (3) 9.83 (5) 49.:12 (4) 92.5 (6) 3rd Quarter 7.55 (11) 9.87 (12) 50.12 (11) 651.5 (16) 4th Quarter 7.61 (12) 9.78 (13) 50.96 (11) 1,039.1 (19) 2014 Full Year 7.63 (32) 9.91 (38) so.so (34) 2,034.S (SO) 201S 1st Quarter 7.79 (9) 10.37 (9) Sl.91 (9) 222.s (11) Gas Utilitles--Summa!:ll Table Eq. as D/o Amt. Period ROR 0/0 (#Cases). ROE O/o (#Cases) Cap. Struc. (#Cases) 1-M!h (#Cases) 2001 Full Year 8.51 (6) 10.95 (7) 43.96 (5) 114.0 (11) 2002 Full Year 8.80 (20) 11.03 (21) 48.29 (18) 303.6 (26) 2003 Full Year 8.75 {22) 10.99 (25) 49.93 (22) 260.1 (30) 2004 Full Year 8.34 (21) 10.59 {20) 45.90 (20) 303.5 (31) 2005 Full Year 8.25 (29) 10.46 (26) 48.66 (24) 458.4 (34) 2006 Full Year 8.51 (16) 10.43 (16) 47.43 (16) 444.0 (25) 2007 Full Year 8.12 (32) 10.24 (37) 48.37 (30) 813.4 (48) 2008 Full Year 8.48 (30) 10.37 (30) 50.47 (30) 884.8 (41) 2009 Full Year 8.15 (28) 10.19 (29) 48.72 (28) 475.0 (37) 2010 Full Year 7.95 (38) 10.08 (37) 48.56 (38) 816.7 (49) 2011 Full Year 8.09 (18) 9.92 (16) 52.49 (14) 436.3 (31) 2012 Full Year 7.98 (30) 9.94 (35) 51.13 (32) 263.9 (41) 1st Quarter 7.31 (3) 9.57 (3) 48.80 (3) 39.0 (6) 2nd Quarter 7.21 (5) 9.47 (6) 51.21 (5) 259.1 (12) 3rd Quarter 7.53 (1) 9.60 (1) 53.84 (1) 6.1 (3) 4th Quarter 7.47 (11) 9.83 (112 50.52 (11) 189.5 (16) 2013 Full Year 7.39 (20) 9.68 {21) S0.60 (20} 493.7 (37) 1st Quarter 7.67 (6) 9.54 (6) 51.14 (6) 23.5 (9) 2nd Quarter 7.76 (8) 9.84 {8) 52.12 (8) 62.2 (12) 3rd Quarter 7.40 (8) 9.45 (6) 49.51 (8) 329.1 (11) 4th Quarter 7.96 (7) 10.28 (6) 52.35 (7) 115.5 (16) 2014 Full Year 7.69 (29) 9.78 (26) S1.25 (29) 530.3 (48) 2015 1st Quarter 6.41 (2) 9.47 (3) 50.41 (2) 168.7 (9) a.gatewood@kcc.ks.gov;printed 7/1/20 l 5
Schedule AHG-2
;15-WSEE-115-RTS RRA-REGULATORY FOCUS April 13, 2015 ELECTRIC UTILITY DECISIONS Common Test Year ROR ROE Eq. as D/o & Amt.
Date Comoany (State) ___..?!!!.__ ___..?!!!.__ Cap. Str. Rate Base t...M!h 2014 FULL-YEAR: AVERAGES/TOTAL 7.63 9.91 50.50 2,034.5 OBSERVATIONS 32 38 34 50 1/23/15 PacifiCorp (WY) 7.41 9.50 51.43 6/15-A 20.2 2/4/15 Monongahela Power/Potomac Ed. (WV) 12/13 124.3 (B,1) 2/18/15 Virginia Electric and Power (VA) 7.88 11.00 52.03 3/16-A 36.9 (LIR,B,2) 2/24/15 Public Service Co. of Colorado (CO) 7.55 9.83 56.00 12/13-YE -39.4 (I,B) 3/2/15 Black Hills Power (SD) 7.76 9/13-A 6.9 (I,B)
"3/12/15 Virginia Electric and Power (VA) 8.40 12.00 52.03 3/16-A -6.4 (LIR,3) 3/12/15 Virginia Electric and Power (VA) 7.88 11.00 52,03 3/16-A 11.4 (LIR,B,4) 3/12/15 Virginia Electric and Power (VA) 7.88 11.00 52.0~ 3/16-A 5.8 (LIR,5) 3/18/15 Jersey Central Power & Light (NJ) 8.01 9.75 50.00 (Hy) 12/11-YE -115.0 (D) 3/25/15 PacifiCorp (WA) 7.30 9.50 49.10 12/13-A 9.6 3/26/15 Northern States Power-Minnesota (MN) 9.72 52.50 12/14 168.2 (I,Z) 2015 lST QUARTER: AVERAGES/TOTAL 7.79 10.37 51.91 222.5 OBSERVATIONS 9 9 9 11 GAS UTILITY DECISIONS Common Test Year ROR ROE Eq. as 0/o & Amt.
Date Company (State) ___..?!!!.__ ___..?!!!.__ Cap. Str. Rate Base t...M!h 2014 FULL-YEAR: AVERAGES/TOTAL 7.69 9.78 51.25 530.3 OBSERVATIONS 29 26 29 48 1/13/15 Consumers Energy (MI) 10.30 12/15 . 45.0 (I,B) 1/14/15 Indiana Gas (IN) 6/14-YE 5.7 (LIR,6) 1/14/15 Southern Indiana Gas & Electric (IN) 6/14-YE 1.5 (LIR,6) 1/21/15 North Shore Gas (IL) 6.26 9.05 50.48 12/15-A 3.5 (R) 1/21/15 Peoples Gas Light & Coke (IL) 6.56 9.05 50.33 12/15-A 71.1 (R) 1/26/15 Piedmont Natural Gas (NC) 10/14 26.6 (LIR,7) 1/27/15 Atmos Energy (KS) 9/14-YE 0.3 (LIR,8) 1/27/15 Northern States Power-Minnesota (MN) 12/15 14. 7 (LIR,9) 1/28/15 Northern Indiana Public Service (IN) 6/14-YE 0.3 (LIR,10) 2015 1ST QUARTER: AVERAGES/TOTAL 6.41 9.47 50.41 168.7 OBSERVATIONS 2 3 2 9 a.gatewood@kcc.ks.gov;printed 7/1/2015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS April 13, 2015 FOOTNOTES A- Average B- Order followed stipulation or settlement by the parties. Decision particulars not necessarily precedent-setting or speclflcally adopted by the regulatory body. COC- Case Involved only the determination of cost-of-capltal parameters. CWIP- Construction work In progress D- Applles to electric delivery only DCt Date certain rate base valuation E- Estimated F- Return on fair value rate base Hy- Hypothetical capital structure utlllzed I- Interim rates Implemented prior to the Issuance of final order, normally under bond and subject to refund. LIR Limited-Issue rider proceeding M- "Make-whole" rate change based on return on equity or overall return authorized In previous case. R- Revised Te- Temporary rates Implemented prior to the Issuance of final order. U- Double leverage capital structure utlllzed. W- Case withdrawn YE- Year-end Z- Rate change Implemented In multiple steps.
- Capital structure Includes cost-free Items or tax credit balances at the overall rate of return.
(1) Consolidated rate proceeding for Monongahela Power and Potomac Edison, whose rate schedules were combined. (2) Increase authorized through a surcharge, Rider W, which r~ftects In ratesthe Investment Jn the Warren County Power Station and associated transmission facllltles. New rates effective 4/1/15: The Indicated overall return and capital structure are place-holders pending a 2015 biennial review. (3) This proceeding determines the revenue requirement for Rider B, which Js the mechanism through which the company recovers costs associated with Its plan to convert the Altavista, Hopewell, and Southampton Power Stations to burn biomass fuels. The Indicated overall return and capital structure are placeholders pending a 2015 biennial review. (4) Represents rate Increase associated with the company's Rider R proceeding, which Is the mechanism through which the company recovers the Investment In the Bear Garden gen,eratlng faclllty. The Indicated overall return and capital structure are placeholders pending a 2015 biennial review. (5) This proceeding determines the revenue requirement for Riders, which recognizes In rates the company's Investment In the Virginia City Hybrid Energy Center. The Indicated overall return and capital structure are placeholders pending a 2015 biennial review. (6) Initial proceeding to establish the rates to be charged to customers under the company's "compliance and system Improvement adjustment" (CSIA) mechanism. (7) Case Involves the company's Integrity Management Rider (!MR), under which It Is authorized to track and recover prudently Incurred capital Investments and associated costs Incurred to comply with federal pipeline safety and Integrity requirements outside of a general rate case. (8) Case Involves an update to the company's gas system reliability surcharge (GSRS) rider. (9) Case represents the company's first filing under Its Gas Utlllty Infrastructure Cost (GUIC) Rider. (10) This Is the Initial proceeding to establish the rates to be charged to customers under the company's transmission, distribution, and storage system Improvement charge (TOSIC) rate adjustment mechanism. Dennis Sperdute a.gatewood@kcc.ks.gov;printed 7/1/2015
co Schedule AHG-2
~=~Regulatory Research Associates 15-WSEE-115-RTS R UL RYF cus January 15, 2015 MAJOR RATE CASE DECISIONS--CALENDAR 2014 The average return on equity (ROE) authorized electric utilities was 9.92% in 2014, compared to 10.02% in 2013. There were 37 electric ROE determinations in 2014, versus 50 in 2013. We note that the data includes several surcharge/rider generation cases in Virginia that incorporate plant-specific ROE premiums. a <"J_ (o Virginia statutes authorize the State Corporation Commission to approve ROE premiums of up to 200 basis -(/ 7 t points for certain generation projects (see the Virginia Commission Profile). Excluding these Virginia c(1*- 2,.tJ / 1 surcharge/rider generation cases from the 9~ta,_~he -~':..~~~thori?'._e<:I electric ppE V".~ jn 2011;~ 1
- compared to 9.8% in 2013. The average ROE autfiorlzea fill§ utilities was 9.78% in 2014 compared to 9.68% in 2013. There were 26 gas cases that included an ROE determination in 2014, versus 21 in 2013. The 2014 averages do not include a Feb. 20, 2014 New York Public Service Commission steam rate decision for Consolidated Edison Co. of New York that adopted a 9.3% ROE. (We note that this report utilizes the simple mean for the return averages.)
Graph 1: Average Authorized ROEs - Electric and Gas Rate Decisipns 13~---------------------
-Electric
-Gas 10.5 t - - - - - - - - - - - - - - - - 3 , Q : : : : - - = " " " " - - - - -
ZQH E/ec.-9.92% 10 - i - - - - - - - - - - - - - - - - - - . . . , - - - - . . . - - : - r Gas-9.78% 9.5 +-~-~~~~-~~~~-~~~~-~~--,-~
'90 '91 '92 '93 '94 '95'96 '97'98 '99'00'01 '02'03 '04 '05'06'07 '08 '09'10 '11 '12 '13'14 Source: SNL Energy/RRA After reaching a low in the early-2000s, the number of rate case decisions for energy companies has generally increased over the last several years, as shown in Graph 2 below. There were 97 electric and gas rate Graph 2: Volume of Electric and Gas Rate Case Decisions 120 100-'~-------------------~ Ir-~
r, !
. fl -*1 - *-1 I- i .
- :[l[t((Ht~h~ ![( llllftli. It 1
'90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 Source: SNL Energy/RRA a.gatewood@kcc.ks.gov;printed 7/1/2015
Schedule AHG-2 l 5-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 201::> cases resolved in 2014 versus 99 in 2013, 111 in 2012, and only 32 back in 2001. Increased costs for environmental compliance, generation and delivery Infrastructure upgrades and expansion, renewable generation mandates, and employee benefits, argue for the continuation of an active rate case agenda over the next few years. As a result of electric industry restructuring, certain states unbundled electric rates and implemented retail competition for generation. Commissions in those states now have jurisdiction only over the revenue requirement and return parameters for delivery operations (which we footnote in our chronology beginning on page 5), thus complicating historical data comparability. We also note that despite the heightened business risk associated with the less-than-robust economy, average authorized ROEs have declined mooestly since 2008. In fact, some state commissions have cited the economy and customer hardship as factors influencing their equity return authorizations. The table on page 3 shows the average ROE authorized in major electric and gas rate decisions annually since 1990, and by quarter since 2009, followed by the number of observations in each period. The tables on page 4 show the composite electric and gas industry data for all major cases summarized annually since 2000 and by quarter for the past eight quarters. The individual electric and gas cases decided in 2014 are listed on pages 5-10, with the decision date shown first, followed by the company name, the abbreviation for the state issuing the decision, the authorized rate of return (ROR), ROE, and percentage of common equity In the adopted capital structure. Next we show the month and year in which the adopteic:Ltest year ended, whether the commission utilized an average or a year-end rate base, and the amount oftbe permanent rate change authorized. The dollar amounts represent the permanent rate change ordered at the time decisions were rendered. Fuel adjustment clause rate changes are not reflected in this ~tudy. *. *. * * **. **
- The table below tracks the average equity return authorized for all electric and gas rate cases combined, by year, for the last 25 years. As the table indicates, since 1990 the authorized ROEs have generally trended downward, reflecting the significant decline in lnter.~st rates, anq .<:apitalcosts that has occurred over this time frame. The combined average equity returns authqrlzed for electric and gas utilities in each of the years 1990 through 2014, and the number of observations for each year are as follows:
1990 12.69% (75) 2003 10.98% (47) 1991 12.51 (80) 2004 10.67 (39) 1992 12.06 (77) 2005 10.50 (55) 1993 11.37 (77) 2006 10.39 (42) 1994 11.34 (59) 2007 10.30 (76) 1995 11.51 (49) 2008 10.42 (67) 1996 11.29 (42) 2009 10.36 (68) 1997 11.34 (24) 2010 10.24 (96) 1998 11.59 (20) 2011 10.21 (59) 1999 10.74 (29) 2012 10.08 (93) 2000 11.41 (24) 2013 9.92 (71) 2001 11.05 (25) 2014 9.86 (63) 2002 11.10 (43) Please note: Historical data provided In this report may not match data provided on RRA's website due to certain differences In presentation. Dennis Sperduto ©2015, Regulatory Research Associates, Inc. All Rights Reserved. Confidential Subject Matter, WARNING I This report contains copyrighted subject matter and confidential Information owned solely by Regulatory Research Associates, Inc. ("RRA"). Reproduction, distribution or use of this report In violation of this license constitutes copyright Infringement In violation of federal and state law. RRA hereby provides consent to use the "emall this story" feature to redistribute articles within the subscriber's company. Although the information In this report has been obtained from sources that RRA believes to be relfable, RRA does not guarantee Its accuracy. a.gatewood@kcc.ks.gov;printed 7/1/2015
RRA-REGULATORY FOCUS January 15, 2015 Schedule AHG-2 15-WSEE-115-RTS Average Equitv Returns Authorized Januarv 1990 - December 2014 Electric Utilities Gas Utilities Year Period ROE% (#Cases) ROE% (#Cases) 1990 Full Year 12.70 (44) 12.67 (31) 1991 Full Year 12.55 (45) 12.46 (35) 1992 Full Year 12.09 (48) 12.01 (29) 1993 Full Year 11.41 (32) 11.35 (45) 1994 Full Year 11.34 (31) 11.35 (28) 1995 Full Year 11.55 (33) 11.43 (16) 1996 Full Year 11.39 (22) 11.19 (20) 1997 Full Year 11.40 (11) 11.29 (13) 1998 Full Year 11.66 (10) 11.51 (10) 1999 Full Year 10.77 (20) 10.66 (9) 2000 Full Year 11.43 (12) 11.39 (12) 2001 Full Year 11.09 (18) 10.95 (7) 2002 Full Year 11.16 (22) 11.03 (21) 2003 Full Year 10.97 (22) 10.99 (25) 2004 Full Year 10.75 (19) 10.59 (20) 2005 Full Year 10.54 (29) 10.46 (26) 2006 Full Year 10.36 (26) 10:43 (16) 2007 Full Year 10.36 (39) 10.24 *. .. (37) 2008 Full Year 10.46 (37) 10.37 (30) 1st Quarter 10.29 (9) 10.24 (4) 2nd Quarter 10.55 (HI) 10.11 (8) 3rd Quarter 10.46 (3) 9.88 (2) 4th Quarter 10.54 (17) 10.27 (15) 2009 Full Year 10.48 (39) 10.19 (29) 1st Quarter 10.66 (17) 10.24 (9) 2nd Quarter 10.08 (14) 9.99 (11) 3rd Quarter 10.26 (11) 9.93 (4) 4th Quarter 10.30 (17) 10.09 (12) 2010 Full Year 10.34 (59) 10.08 (37) 1st Quarter 10.32 (13) 10.10 (5) 2nd quarter 10.12 (10) 9.88 (5) 3rd Quarter 10.36 (8) 9.65 (2) 4th Quarter 10.34 (11) 9.88 (4) 2011 Full Year 10.29 (42) 9.92 (16) 1st Quarter 10.84 (12) 9.63 (5) 2nd Quarter 9.92 (13) 9.83 (8) 3rd Quarter 9.78 (8) 9.75 (1) 4th Quarter 10.10 (25) 10.07 (21) 2012 Full Year 10.17 (58) 9.94 (35) 1st Quarter 10.24 (15) 9.57 (3) 2nd Quarter 9.84 (7) 9.47 (6) 3rd Quarter 10.06 (7) 9.60 (1) 4th Quarter 9.90 (21) 9.83 (11) 2013 Full Year 10.02 (50) 9.68 (21) 1st Quarter 10.23 (8) 9.54 (6) 2nd Quarter 9.83 (5) 9.84 (8) 3rd Quarter 9.90 (11) 9.45 (6) 4th Quarter 9.78 (13) 10.28 (6) 2014 Full Year 9.92 (37) 9.78 (26) a.gatewood@kcc.ks.gov;printcd 711/2015
Schedule AHG-2 I
'15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 Electric Utilities--Summa01 Table Eq. as 0/o Amt.
Period ROR % (#Cases) ROE"/o (#Cases) Cap. Struc. (#Cases) $ Mil. (#Cases) 2000 Full Year 9.20 (12) 11.43 (12) 48.85 (12) -291.4 (34) 2001 Full Year 8.93 (15) 11.09 (18) 47.20 (13) 14.2 (21) 2002 Full Year 8.72 (20) 11.16 (22) 46.27 (19) -475.4 (24) 2003 Full Year 8.86 (20) 10.97 (22) 49.41 (19) 313.8 (12) 2004 Full Year 8.44 (18) 10.75 (19) 46.84 (17) 1,091.5 (30) 2005 Full Year 8.30 (26) 10.54 (29) 46.73 (27) 1,373.7 (36) 2006 Full Year 8.24 (24) 10.36 (26) 48.67 (23) 1,465.0 (42) 2007 Full Year 8.22 (38) 10.36 (39) 48.01 (37) 1,401.9 (46) 2008 Full Year 8.25 (35) 10.46 (37) 48.41 (33) 2,899.4 (42) 2009 Full Year 8.23 (38) 10.48 (39) 48.61 (37) 4,192.3 (58) 2010 Full Year 7.99 (59) 10.34 (59) 48.45 (54) 5,567.7 (77) 2011 Full Year 8.00 (43) 10.29 (42) 48.26 (42) 2,853.5 (56) 2012 Full Year 7.95 (51) 10.17 (58) 50.55 (52) 3,131.5 (70) 1st Quarter 7.81 (13) 10.24 (15) 49.02 (13) 76!).8 (16) 2nd Quarter 7.64 (7) 9.84 (7) 50.56 (6) 653.6 (10) 3rd Quarter 7.86 (8) 10.06 (7) 50.77 (8) 734.4 (11) 4th Quarter 7.46 (17) 9.90 (21) 48.20 (16) 1,315;8 (25) 2013 Full Year 7.66 (45) 10.02 {50) 49.25 (43) 3,469.6 {62) 1st Quarter 7.71 (6) 10.23 (8) 51.08 (8) 251.4 (9) 2nd Quarter 7.81 (3) 9.83 (5) 49.12 (4) 92.5 (6) 3rd Quarter 7.67 (10) 9.90 (11) 50.63 (10) 563.7 (15) 4th Quarter 7.61 (12) 9.78 (13) 50.96 (11) 1,039.1 (19) 2014 Full Year 7.67 {31) 9.92 (37) 50.67 (33) 1,946.7 (49) Gas Utilities--Summa!Jl Tabl!:l Eq. as 0/o Amt. Period ROR D/o (# Cases) ROE% (#Cases) Cap. Struc. (#Cases) $Mil. (#Cases) 2000 Full Year 9.33 (13) 11.39 (12) 48.59 (12) 135.9 (20) 2001 Full Year 8.51 (6) 10.95 (7) 43.96 (5) 114.0 (11) 2002 Full Year 8,80 (20) 11.03 (21) 48.29 (18) 303.6 (26) 2003 Full Year 8,75 (22) 10.99 (25) 49.93 (22) 260.1 (30) 2004 Full Year 8.34 (21) 10.59 (20) 45.90 (20) 303.5 (31) 2005 Full Year 8.25 (29) 10.46 (26) 48.66 (24) 458.4 (34) 2006 Full Year 8.51 (16) 10.43 (16) 47.43 (16) 444.0 (25) 2007 Full Year 8.12 (32) 10.24 (37) 48.37 (30) 813.4 (48) 2008 Full Year 8.48 (30) 10.37 (30) 50.47 (30) 884.8 (41) 2009 Full Year 8.15 (28) 10.19 (29) 48.72 (28) 475.0 (37) 2010 Full Year 7.95 (38) 10.08 (37) 48.56 (38) 816.7 (49) 2011 Full Year 8.09 (18) 9.92 (16) 52.49 (14) 436.3 (31) 2012 Full Year 7.98 (30) 9.94 (35) 51.13 (32) 263.9 (41) 1st Quarter 7.31 (3) 9.57 (3) 48.80 (3) 39.0 (6) 2nd Quarter 7.21 (5) 9.47 (6) 51.21 (5) 259.1 (12) 3rd Quarter 7.53 (1) 9.60 (1) 53.84 (1) 6.1 (3) 4th Quarter 7.47 (11) 9.83 (11) 50.52 (11) 189.5 (16) 2013 Full Year 7.39 (20) 9.68 (21) 50.60 (20) 493.7 (37) 1st Quarter 7.67 (6) 9.54 (6) 51.14 (6) 23.5 (9) 2nd Quarter 7.76 (8) 9.84 (8) 52.12 (8) 62.2 (12) 3rd Quarter 7.40 (8) 9.45 (6) 49.51 (8) 329.1 (11) 4th Quarter 7.96 (7) 10.28 (6) 52.35 (7) 115.5 (16) 2014 Full Year 7.69 {29) 9.78 {26) 51.25 (29) 530.3 (48) a.gatewood@kcc.ks.gov;printed 7/l/2015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 ELECTRIC UTILITY DECISIONS Common Test Year ROR ROE Eq. as 0/o & Amt. Date Comoany (State) _%i_ ~ Cao. Str. Rate Base !.M1h 2/20/14 Consolidated Edison of New York (NY) 7.05 9.20 48.00 12/14-A -76.2 (D,B,1) 2/26/14 Northern States Power-Minnesota (ND) 7.45 9.75 52.56 9.0 (I,B,2} 2/28/14 MidAmerican Energy (IA) 12/12 263.6 (I,B,Z) 2/28/14 Virginia Electric and Power (VA) 7.95 11.00 50.00 3/15 14.8 (3) 3/14/14 Virginia Electric and Power (VA) 12.00 50.00 3/15 3.3 (4) 3/14/14 Virginia Electric and Power (VA) 11.00 50.00 3/15 -9.0 (5) 3/17/14 Liberty Utilities (EnergyNorth NG) (NH) 7.92 9.55 55.00 12/12-YE 9.8 (D,B,I,6) 3/26/14 Potomac Electric Power (DC} 7.65 9.40 49.19 12/12-A 23.4 (D) 3/26/14 Southwestern Public Service (NM) 8.26 9.96 53.89 12/14-A 12.7 2014 1ST QUARTER: AVERAGES/TOTAL 7.71 10.23 SLOB 251.4 OBSERVATIONS 6 8 8 9 4/2/14 Delmarva Power & Light (DE) 7.26 9.70 49.22 12/12-A 15.1 (I) 4/23/14 Duquesne Light (PA) 4/15 48.0 (D,B) 5/16/14 Entergy Texas (TX) 9.80 3/13 18.5 (I,B,7) 5/30/14 Fitchburg Gas & Electric Light (MA) 8.28 9.70 47.78 12/12-YE 5.6 (D) 6/6/14 Wisconsin Power and Light (WI) 7.90 (8) 10.40 50.46 12/15-A 0.0 (8) 6/30/14 Emera Maine (ME) 9.55 49.00 12/12 5.3 (D,B,9) 2014 2ND QUARTER: AVERAGES/TOTAL 7.81 9.83 49.12 92.5 OBSERVATIONS 3 5 4 6 7/2/14 Potomac Electric Power (MD) 7.61 9.62 49.18 9/13-A 8.8 (D) 7/8/14 Virginia Electric and Power (VA) 7.95 11.00 50.00 8/15-A 41.1 (10) 7/10/14 Entergy Louisiana (LA) 9.95 9.3 (B,Z) 7/17/14 Kansas City Power & Light (KS) 12/11-YE 11.5 (B,11) 7/23/14 Rockland Electric (NJ) 7.83 9.75 50.35 3/14-YE 13.0 (D,B) 7/29/14 Central Maine Power (ME) 7.06 9.45 50.00 12/12-A 24.3 (D,B,12) 7/31/14 Cheyenne Light, Fuel and Power (WY) 7.98 9.90 54.00 6/13-YE 8.4 (B) 8/14/14 Pacific Gas and Electric (CA) 12/14-A 196.0 (13) 8/20/14 Atlantic City El ectrl c (NJ) 7.75 9.75 49.83 12/13-YE 19.0 (D,B) 8/25/14 Green Mountain Power (VT} 7.46 9.60 50.00 9/13-A -8.B (B,14) 8/29/14 PacifiCorp (UD 7.57 9.80 51.43 6/15 54.2 (B,Z) 9/15/14 Florida Public Utilities (FL) 10.25 9/15 3.8 (I,B} 9/18/14 Avista Corp. (ID) 0.0 (B,15) 9/24/14 South Carolina Electlc & Gas (SC} 8.53 53.52 6/14-YE 66.2 (16) 9/25/14 NorthWestern Corp. (MT) 6.91 9.80 48.00 12/14-A 116.9 (17) 2014 3RD QUARTER: AVERAGES/TOTAL 7.67 9.90 50.63 563.7 OBSERVATIONS 10 11 10 15 a.gatewood@kcc.ks.gov;printed 7/ 1/2015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 ELECTRIC UTILITY DECISIONS (continued) Common Test Year ROR ROE Eq. as 0/o & Amt. Date Company (State) ~ ~ Cap. Str. Rate Base !..Ml!.. 10/9/14 Nevada Power (NV) 8.09 9.80 48.17 12/13 0.0 (B) 11/6/14 MidAmerican Energy (IL) 7.14 9.56 51.73 12/12-YE 16.4 (R) 11/6/14 Wisconsin Public Service (WI) 8.39 10.20 50.28 12/15-A 24.6 11/12/14 Potomac Electric Power (DC) 4.7 (18) 11/14/14 Wisconsin Electric Power (WI) 8.60 10.20 51.90 12/15-A 15.4 11/25/14 Avista Corp. (WA) 6/13 7.0 (B) 11/26/14 Appalachian Power (VA) 9.70 12/13 0.0 11/26/14 Madison Gas and Electric (WI) 7.96 10.20 58.96 12/15-A 15.4 12/4/14 Portland General Electric (OR) 7.56 9.68 50.00 12/15-A 44.3 (B) 12/10/14 Ameren Illinois. (IL) 8.08 9.25 51.00 (Hy) 12/13-YE 200.6 (D) 12/10/14 Commonwealth Edison (IL) 7.06 9.25 45.77 12/13-YE 232.8 (D) 12/11/14 Entergy Mississippi (MS) 7.51 10.07 12/1.5-A 177.7 (B) 12/12/14 Baltimore Gas and Electric (MD) 8/14 22.0 (B) 12/12/14 Northern States Power-Wisconsin (WI) 10.20 52.54 12/15 14.2 12/18/14 Arizona Public Service (AZ) 6.09 (F) 57.1 (19) 12/17/14 Connecticut Light and Power (CT) 7.31 9.17 50.38 12/13-A 134.1 (20) 12/18/14 Black Hills Colorado Electric (CO) 7.55 9.83 49.83 12/13-A 9.2 12/18/14 Georgia Power (GP) 12/15 26.6 (21) 12/18/14 Southwestern Public Service (TX) 6/13 37.0 (B) 2014 4TH QUARTER: AVERAGES/TOTAL 7.61 9.78 50.96 1,039.1 OBSERVATIONS 12 13 11 19 2014 FULL-YEAR: AVERAGES/TOTAL 7.67 9.92 50.67 1,946.7 OBSERVATIONS 31 37 33 49 a.gatewood@kcc.ks.gov;printed 7/l/2015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 GAS UTILITY DECISIONS Common Test Year ROR ROE Eq. as 0/o & Amt* Date Company CStatel ~ ~ Cap. Str. Rate Base .l.M.!h 1/21/14 Avista Corp. (OR) 7.47 9.65 48.00 12/14-A 5.6 (B,Z) 1/22/14 Connecticut Natural Gas (CT) 7.88 9.18 52.52 12/12-A 7.3 (R) 1/28/14 Atmos Energy (KS) 9/13-YE 1.2 (22) 1/29/14 Baltimore Gas and Electric (MD) 12/18-A 34.1 (Z,23) 1/31/14 Columbia Gas of Maryland (MD) -- (24) 2/20/14 Consolidated Edison of New York (NY) 7.10 9.30 48.00 12/14-A -54.6 (B,25) 2/21/14 Questar Gas (UT) 7.64 9.85 52.07 12/14-A 7.6 (B) 2/28/14 Bay State Gas (MA) 7.83 9.55 53.68 12/12-YE 19.3 3/16/14 Atmos Energy (CO) 8.07 9.72 52.57 12/12-A 1.3 (I,B) 3/19/14 Missouri Gas Energy (MO) 9/13-YE 1.7 (26) 20.14 .1ST QUARTER: AVERAGES/TOTAL 7.67 9.54 51.:1,_4: 23.5 OBSERVATIONS 6 6 6_ 9 4/2/14' Laclede Gas (MO) 12/13~YE 7.0 (26) 4/21/14 Northern Utilities (NH) 8.28 9.50 51.76 12/12-YE 4.6 (I,B,27) 4/22/14 Atmos Energy (KY) 7.71 9.8() 49,g; 11/14-A 8.6 (I) 4/23/14 Missouri Gas Energy (MO) 4/13 7.8 (B) 5/8/14 CenterPoint Energy Resources (MN) 7.42 9.59 52.60 9/14-A 32.9 (I) 5/8/14 National Fuel Gas Distribution (NY) 7.56 9.10 48.00 9/14-A -3.6 (B,28) 5/15/14 Delta Natural Gas (KY) 12/13-YE 1.1 (29) 6/4/14 Washington Gas Light (MD) 9/14-A 1.7 (23) 6/6/14 Wisconsin Power and Light (WI) 7.90 (30) 10.40 50.46 12/15-A -5.0 (30) 6/12/14 Southwest Gas (So. California) (CA) 6.83 10.10 55.00 12/14-A 1.9 6/12/14 Southwest Gas (No. California) (CA) 8.18 10.10 55.00 12/14-A 2.5 6/12/14 Southwest Gas (So. Lake Tahoe) (CA) 8.18 10,10 SS.OD 12/14-A 2.7 20.14 2ND QUARTER: AVERAGES/TOTAL 7.76 9.84 52.12 62.2 OBSERVATIONS 8 8 8 12 7/3/14 CenterPoint Energy Resources (OK) 8.64 5o.cio 12/13-YE 0.3 (B,31) 7/7/2014 SourceGas Arkansas (AR) 5.71 9.30 41.60
- 9/13-YE 13.8 (B) 7/25/14 Arkansas Oklahoma Gas (AR) 6.18 9.30 39.94
- 12/13-YE 4.2 (B) 7/31/14 Cheyenne Light, Fuel and Power (WY) 7.98 9.90 54.00 6/13-YE 0.8 (B) 8/5/14 Oklahoma Natural Gas (OK) 8.54 55.30 12/13-YE 13.7 (B,32) 8/14/14 Pacific Gas and Electric (CA) 12/14-A 264.0 (33) 8/18/14 Columbfa Gas of Maryland (MD) 12/14 0.4 (34) 9/4/14 Atmos Energy (KS) 7.75 9.10 (35) 53.00 9/13-YE 4.3 (B,35) 9/18/14 Avista Corp. (ID) 0.0 (B,15) 9/24/14 Minnesota Energy Resources (MN) 7.30 9.35 50.31 12/14-A 7.6 (I) 9/30/14 South Jersey Gas (NJ) 7.10 9.75 51.90 6/14-YE 20.0 (B) 20.14 3RD QUARTER: AVERAGES/TOTAL 7.40 9.45 49.51 329.1 OBSERVATIONS 8 6 8 11 a.gatewood@kcc.ks.gov;printed 7/1120 I5
Schedule AHG- 2 15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 GAS UTILITY DECISIONS (continued) Common Test Year ROR ROE Eq. as D/o & Amt. Date Comoanv (State) ~ ~ Cap. Str. Rate Base .t.M!1. 10/7/14 Black Hills Kansas Gas Utility (KS) 4/14-YE 0.6 (22) 10/8/14 Missouri Gas Energy (MO) 6/14-YE 2.0 (26) 10/10/14 Atmos Energy (KY) 9/15-YE 4.4 (29) 10/15/14 Laclede Gas (MO) 6/14-YE 2.8 (B,26) 10/15/14 South Carolina Electric & Gas (SC) 8.13 53.52 3/14-YE -2.6 (M) 10/29/14 summit Natural Gas of Missouri (MO) 7.54 10.80 57.00 9/13-YE 7.1 11/6/14 Wisconsin Public Service (WI) 7.95 10.20 50.28 12/15-A -15.4 11/13/14 Columbia Gas of Pennsylvania (PA) 12/15 32.5 (B) 11/14/14 Wisconsin Electric Power (WI) 8.60 10.20 51.90 12/15-A -10.7 11/14/14 Wisconsin Gas (WI) 8.36 10.30 48.91 12/15-A 38.S (Z) 11/25/14 Kansas Gas Service (KS) 6/14-YE 3.5 (22) 11/25/14 Avista Corp. (WA) 6/13 8.5 (B) 11/26/14 Madison Gas and Electric (WI) 7.98 10.20 58.96 12/15~A -3.8 12/5/14 Liberty Utllltles (Mldstates NG) (MO) 7.16 10.00 45.89 9/13-YE 4.9 12/12/14 Baltimore Gas and Electric (MD) 8/14 38.0 (B) 12/16/14 Black Hills Kansas Gas Utility (KS) 12/13 5.2 (B) 2014 4TH QUARTER: AVERAGES/TOTAL 7.96 10.28 52.35. 115.5 OBSERVATIONS 7 6 7 16 2014 FULL-YEAR: AVERAGES/TOTAL 7.69 9.78 51.25 530.3 OBSERVATIONS 29 26 29 48 a.gatewood@kcc.ks.gov;printed 7I112015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 FOOTNOTES A- Average B- Order followed stipulation or settlement by the parties. Decision particulars not necessarily precedent-setting or specifically adopted by the regulatory body. COC- Case Involved only the determination of cost-of-capital parameters. CWIP- Construction work In progress D- Applles to electric dellvery only DCt Date certain rate base valuation E- Estimated F- Return on fair value rate base Hy- Hypothetical capital structure utlllzed I- Interim rates Implemented prior to the Issuance of final order, normally under bond and subject to refund. M- "Make-whole" rate change based on return on equity or overall return authorized In previous case. R- Revised Te- Temporary rates Implemented prior to the Issuance of final order. U- Double leverage capital structure utilized. W- Case withdrawn YE- Year-end Z- Rate change Implemented In multiple steps.
- Capital structure includes cost-free Items or tax credit balances at the overall rate of return.
(1) Approved joint proposal (stipulation) includes two-year rate plan that specifies a second-year $124 million revenue requirement Increase. (2) Approved settlement Includes a four-year electric rate plan. In adcll.tlon to the $9 million first-year rate Increase, an Incremental
$9.3 million second-step Increase based on a 10% ROE Is to be Implemented.In 2014, and an Incremental $10.1 million third-step Increase based on a 10% ROE Is to be Implemented In 2015. Rates are to remain unchanged In 2016 based on a 10.25% ROE.
(3) Increase authorized through a surcharge, Rider W, which reflects In rates the Investment In the Warren County Power Station and associated transmission facllltles. * (4) This proceeding determines the revenue requirement for Rider B, which Is the mechanism through which the company recovers costs associated with Its plan to convert the Altavista, Hopewell, and Southampton Power Stations to burn biomass fuels. (5) This proceeding determines the revenue requirement for Rider S for the year ending 3/31/15. Rider S recognizes the company's Investment In the Virginia City Hybrid Energy Center. (6) An additional step Increase of about $1.1 million was authorized to be effective 4/1/14. (7) The rate increase Is effective retroactive to 3/31/14. (B) Return on capital. The Commission approved the company's proposal to freeze electric base rates In 2015 and 2016. (9) Settlement and order provld.e for an additional $1.2 million Increase for the recovery of costs associated with winter 2013 Ice and snow storms. (10) Increase authorized through a surcharge, Rider BW, which reflects In rates the Investment In the Brunswick County Power Station. (11) "Abbreviated" rate case that addressed only the Incremental revenue requirement associated with the Installation of emissions-control equipment at a generation plant. (12) Rate Increase authorized retroactive to 7/1/14. (13) Rate Increase authorized retroactive to 1/1/14. Additional "attrition" Increases of $230 million and $285 million authorized for 2015 and 2016, respectively. (14) Rate reduction effective 10/1/14. (15) The approved settlement extends the terms of the company's existing rate plan approved In March 2013, for one year through 12/31/15, thereby keeping base electric and gas rates unchanged. (16) Case Involves company's request for a cash return on Incremental V.C. Summer Units 2 and 3 CWIP and Incorporates the 11% ROE that was Initially authorized In 2009 for use In Summer CWIP-related proceedings. (17) Case Is a limited-Issue proceeding associated with the company's purchase of certain hydroelectric facilltles. (18) Rate Increase Is to flow through the company's "undergroundlng surcharge" as permitted by law. (19) Rate Increase Is through a new rider associated with company's acquisition of a 48% share of Four Corners 4 and 5 from another utility. ROR represents return on a fair value rate base. (20) Inltlal rate Increase to be $130.2 million to relect a one-year, 15-basls-polnt equity return penalty. (21) Rate Increase represents a cash return on Incremental 2015 CWIP and a preliminary true-up of the cash return on 2014 CWIP for Plant Vogtle Units 3 and 4 under the company's leglslatlvely-enabled nuclear construction cost recovery tariff. (22) Case represents the company's gas system rellablllty surcharge rider. (23) Case Involves the strategic Infrastructure replacement (STRIDE) rider, a surcharge associated with the company's lnfrastrucure replacement program. a.gatewood@kcc.ks.gov;printed 7II/2015
Schedule AHG-2 15-WSEE-115-RTS RRA-REGULATORY FOCUS January 15, 2015 FOOTNOTES (continued) (24) Company's proposed strategic Infrastructure replacement (STRIDE) program and an associated rider were rejected by the Commission. (25) Approved joint proposal (stipulation) Includes a three-year rate plan that specifies second-year $38.6 mllllon and third-year
$56.B mllllon revenue requirement Increases, (26) Case Involves the company's lnfrastrucure system replacement surcharge rider.
(27) Additional "step Increases" of about $1.4 million to be effective on 5/1/14 and 5/1/15. (28) Two-year rate plan adopted. A $6.1 million revenue requirement Increase Is to be effective on 10/1/14. (29) Case Involves the company's pipe replacement program (PRP) rider. (30) Return on capital. The Commission approved the company's proposal to reduce gas base rates by $5 million in 2015 and then freeze base rates In 2016. (31) Case involves the company's performance-based ratemaklng plan. (32) Rate Increase authorized pursuant to company's performanced-based ratemaklng plan. (33) Rate Increase authorized retroactive to 1/1/14. Additional "attrition" Increases of $94 mllllon and $87 million authorized for 2015 and 2016, respectively. (34) Case Involves the company's Infrastructure replacement and Improvement plan. (35) The Commission adopted a partial settlement that had resolved all oustandlng Issues In the case, except for ROE and two other matters, and established a 9.1 % ROE for the company. Dennis Sperdute a.gatewood@kcc.ks.gov;printed 7I1/2015
Schedule AHG-3 15-WSEE-115-RTS Proxy Range A3 A-Baal BBB+ Westar Rating Baa2 BBB No Dividends Value-Line: Electric Utilities ***Bond Rating*** Announced No Planned 6mo Company Name Moody's S&P OK Merger Reductions History NOTES Allete Inc ALE A3 BBB+ # # # # Alliant Energy Corp LNT A3 A- # # # # Ameren Corp AEE Baa2 BBB+ # # # # American Electric Pwr Co AEP Baal BBB # # # # Avista Corp AVA Baal BBB # # # # Black Hills Corp BKH Baal BBB # # # # CenterPoint Energy Inc CNP Baal A- # # # # Cleco Corp CNL Baal BBB+ # no Acq'd by Macquarie CMS Energy Corp CMS Baa2 BBB+ # # # # Consolidated Edison Inc ED A3 A- # # # # Dominion Resources Inc D Baa2 A- # # # # DTE Energy Company DTE A3 BBB+ # # # # Duke Energy Corp New DUK A3 BBB+ # # # # Edison International EIX A3 BBB+ # # # # El Paso Electric Co EE Baal BBB # # # # Empire District Electric Co EDE Baal BBB # # # # Entergy Corp ETR Baa3 BBB no Exelon Corp EXC Baa2 BBB # no Proposed acquisition of PepCo. FirstEnergy Corp FE Baa3 BBB- no Great Plains Energy Inc GXP Baa2 BBB+ # # # # Hawaiian Electric Ind. HE BBB- no no Acqu'd by NextEra IDACORP Inc IDA Baal BBB # # # # Integrys Energy Group Inc TEG A3 A- # no Acquisition by WEC MGE Energy Inc MGEE Al AA- no NextEra Energy Inc NEE Baal A- # no HE acquistion NorthWestern Corp. NWE A3 BBB # # # # OGE Energy Corp OGE A3 A- # # # # Otter Tail Corp OTTR Baa2 BBB # # # # Pacific Gas and Electric Co. PCG Baal BBB # # # # Pepco Holdings Inc POM Baa3 BBB+ no no Exelon Merger Pinnacle West Capital Corp PNW Baal A- # # # # PNM Resources Inc PNM Baa3 BBB no Portland General Electric Co. POR A3 BBB # # # # PPL Corporation PPL Baa3 BBB no no Spino ff of energy marketing Pub. Serv. Enterprise Grp Inc PEG Baa2 BBB+ # # # # SCANA Corporation SCG Baa3 BBB+ no Sempra Energy SRE Baal BBB+ # # # # Southern Co so Baal A no TECO Energy TE Baal BBB+ # # # # UIL Holdings Corp. UIL Baa2 BBB # # # # Unitil Corp UTL BBB+ # # # # Vectren Corp vvc A- # # # # Westar Energy Inc WR Baal BBB+ # # # # Wisconsin Energy WEC A2 A- no no Merger w/ TEG Xcel Energy Inc XEL A3 A- # # # #
Schedule AHG-4 15-WSEE-115-RTS l 2 3 4 5 6 7 8 9 10 11 No Dividends Value-Line: Electric Utilities ***Bond Rating*** Announced No Planned 6 mo Electric Operations Reg. Company Name Moody's S&P OK Merger Reductions History %Rev %Assets Rev% Allete Inc ALE A3 BBB+ # # # # 88% 89% Alliant Energy Corp LNT A3 A- # # # # 81% 80% Ameren Corp AEE Baa2 BBB+ # # # # 99% 97% American Electric P\vr Co AEP Baal BBB # # # # 84% 81% Avista Corp AVA Baal BBB # # # # 68% 73% CMS Energy Corp CMS Baa2 BBB+ # # # # 62% 60% 95% Consolidated Edison Inc ED A3 A- # # # # 90% 96% Dominion Resources Inc D Baa2 A- # # # # 74% Duke Energy Corp New DUK A3 BBB+ # # # # 90% 88% Edison International EIX A3 BBB+ # # # # 100% El Paso Electric Co EE Baal BBB # # # # 100% 100% Empire District Electric Co EDE Baal BBB # # # # 91% 95% Great Plains Energy Inc GXP Baa2 BBB+ # # # # 100% 100% IDACORP Inc IDA Baal BBB # # # # 100% 98% NorthWestern Corp. NWE A3 BBB # # # # 73% 69% 100% OGE Energy Corp OGE A3 A- # # # # 79% 87% 100% Pacific Gas and Electric Co. PCG Baal BBB # # # # 80% 74% Pinnacle West Capital Corp PNW Baal A- # # # # 100% 100% Portland General Electric Co. POR A3 BBB # # # # 100% 100% TECO Energy TE Baal BBB+ # # # # 79% 75% 92% Westar Energy Inc WR Baal BBB+ # # # # 100% 100% Xcel Energy Inc XEL A3 A- # # # # 81% 84% 99% 1 & 2) Electric utilities followed by Value-Line Investment Survey 3, 4, & 5) Long-term credit rating repotied at SNL.com
- 6) No mergers or acquistions 7 & 8) Histoty of consistent dividend paymenst and expectations of continued dividend payment
- 9) % of revenues from electric operations reported in SNL templated financial data I 0) % of assets associated with electric operations reported in SNL templated financial data
- 11) % of revenues from regulated (gas & electric) operations reported in SNL templated financial data
Schedule AHG-5 15-WSEE-115-RTS May 22, 2015 ELECTRIC UTILITY (EAST) INDUSTRY 140 All of the major electric utilities located in the INDUSTRY TIMELINESS: 13 (of 96) eastern region of the United States are reviewed in this Issue; western electrics, in Issue 11; and the and cost overruns stemming from the construction of a remaining utilities, in Issue 5. coal-gasification plant in Mississippi. Two investor-owned utilities in the Southeast are building nuclear plants. Each project has run Deal Update into delays and cost overruns. Even so, the situa- Several electric utilities whose stocks are covered in tion is hardly dire for either company. Issue 1 are involved in an acquisition or a spinoff. PPL Corporation has received all approvals needed to sepa-Several electric utilities in the East are involved rate its nonregulated operations into a new company. in significant deals. The move is planned for June 1st. On the other hand, investors are worried about the regulatory process for Most electric utility stocks have declined in the takeover of Pepco Holdings by Exelon. A ruling in value so far in 2015. This is understandable, fol- Maryland, where the deal has received much criticism, lowing two years of stellar performance. was expected shortly after this report went to press. Similarly, the proposed takeover by NextEra Energy of the three utilities owned by Hawaiian Electric Indus-Nuclear Construction tries (reviewed in Issue 11) is facing opposition in The electric utility industry had an unfavorable expe- Hawaii. The other company in the East involved in a rience with nuclear construction in the 1980s. Numerous major deal is UIL Holdings, which is being acquired by projects experienced delays and cost overruns, and sev- the U.S. affiliate of a Spanish utility. eral utilities had to take sizable write-offs-in some cases, for projects that were never completed. As a result, it became conventional wisdom that no investor- Conclusion owned utility in the United States would ever build In contrast to 2013 and 2014, this has not been a good another nuclear plant. year for electric utility stocks. The broader market averages are up slightly for the year, while the prices of The conventional wisdom proved correct for many most electric utility equities have declined at a high years. Then, changes in the regulatory approval process single-digit or low double-digit percentage rate. Consid-last decade (including the approval of certain plant ering that this has followed a year in which most electric designs) prompted some companies to take another look utility issues advanced more than 20%, some reversion at nuclear construction. Two utilities took the plunge to the mean could be expected. We believe some inves-several years ago, when they asked the Nuclear Regu- tors are also worried about the possibility that the latory Commission to grant a construction and operating Federal Reserve will begin raising interest rates in license for new nuclear units. Georgia Power (a subsid- several months. iary of Southern Company) is adding a third and fourth unit at the site of its Vogtle station, and South Carolina Even after this group's underperformance year to Electric & Gas (a subsidiary of SCANA) is building a date, electric utility stocks aren't cheap. Most are still second and third unit at the site of its Summer plant. trading within their 3- to 5-year Target Price Range. The Each utility benefits from state regulatory laws that average dividend yield of 3.8% is higher than in recent provide for preapproval of these projects and allow months, but still low, by historical standards. The me-recovery of construction work in progress. dian long-term total return potential of this industry is just 5%. Initially, Georgia Power expected its new units to Paul E. Debbas, CFA begin commercial operation in 2016 and 2017, and SCE&G expected its new units to come on line in 2016 and 2019. However, each project has had multiple delays while the utilities have waited for key components of the plants to be manufactured and delivered. The companies and their contractors are disputing which party is re- Electric Utility sponsible for the delays. When-and how-these dis- RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.) agreements will be resolved is not known. The utilities 150 may still be able to recover the higher costs from ratepayers, if they can show to their state regulatory 120 105 commissions that the costs were prudently incurred. 90 IA. Coincidentally, the latest schedule for each project calls 75 \ y ~
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for the new units to be completed in the second quarter "'-.,.
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of 2019 and 2020. 60 These delays and cost overruns are worrisome, but not 45 disastrous. Investors should keep in mind that when these projects were conceived several years ago, interest 30 rates were much higher than they are today. Thus, financing costs have been much lower than expected. The latest troubles appear to have hadjust a small effect on the price of SCANA stock, while the price of Southern 15 2009 2010 2011 2012 2013 2014 2015 Company stock has been hurt by more-serious delays Index: June, 1967 = 100 <> 2015 Value Line Publisrung LLC. All rights reseried. Factual material Is obtained from sources believe<! lo be refiable and Is provided v;llloul wairanties or any ~nd. THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSlONS HEREIN. TI1isJ'ubf<ation is strictly for subscrilier's ov.n. non-commercial, lnleroal use. No part of ~ may be reproduce<!, resold, s\0<ed or transmitte<l III any printed, elec~onic or oiller ronn, 0< use f0< generating or marketing any prin~d or elec~onic pubfication, selvice or produtL
Schedule AHG-5 15-WSEE-115-RTS March 20, 2015 ELECTRIC UTILITY (CENTRAL) INDUSTRY 901 All of the major electric utilities located in the INDUSTRY TIMELINESS: 54 (of 97) western region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the a utility is holding back profit growth. OGE is facing this remaining utilities, in Issue 5. problem this year. So is Great Plains Energy. Some-times, the year-ago tally provides for a difficult compari-Electric utility stocks, as a group, have declined son. In the first quarter of 2014, Entergy benefited from sharply in value so far in 2015. We discuss why this a spike in power prices in New England, since it had has happened. nonregulated generating assets that were well posi-tioned to take advantage of the favorable market condi-The earnings of some electric utilities are likely tions. Because the comparison is tough, the company's to decline this year. profits will probably decrease in 2015. DTE Energyfaces a tough comparison, as well, because weather patterns Even after the falloff so far this year, electric were favorable for its gas utility in 2014. Another prob-utility equities are not cheap. lem facing utilities (or any company that has pensions) is higher pension expense. Beginning this year, the calculations are based on increased life expectancy. The Up In 2014, Down In 2015 decline in interest rates at the end of 2014 means that Last year was outstanding for electric utility stocks, as future pension benefits will be discounted at a lower a whole. According to an index provided by the Edison rate. Entergy expects higher pension expense this year. Electric Institute (a group representing investor-owned There are exceptions: A few companies, such as Ameren electric companies), electric utility equities produced a in Missouri and Eversource (formerly Northeast Utili-total return of 28.9%. Moreover, this followed a solid ties) in Massachusetts, have regulatory mechanisms to (though less spectacular) showing in 2013, which saw a track pension costs. Finally, subscribers should note that 13.0% total return. Electric utility stocks benefited from we include mark-to-market accounting gains or losses in investors who are reaching for dividend yields in an our earnings presentation because they are an ongoing environment of very low interest rates. The decline in part of quarterly and annual results. This was another interest rates helped, too. The yield on 10-year U.S. positive factor for DTEs profits in 2014. Treasury notes fell more than three-quarters of a per-centage point. A few stocks (including Integrys Energy Conclusion and Cleco) were boosted by takeover agreements. With the decline in the price of most. electric utility stocks so far this year, the average dividend yield for the This year has been a different story. The price of industry has risen. From a low of 3.2%, this figure rose almost every electric utility issue has declined in 2015, to 3.7% in the week we went to press. This is well above and several have fallen by more than 10%. This is in the median for dividend-paying stocks under our cover-sharp contrast to the broader market averages, which age, but still low by historical standards (a reflection of are near where they were at the start of the year. current interest rates). Nevertheless, this doesn't mean Investors are worried about the possibility that the that electric utility equities are cheap. We recommend Federal Reserve will raise interest rates later this year. that readers look at our projections for interest rates in Indeed, the yield on the 10-year Treasury note, which the Quarterly Economic Review in Selection & Opinion, declined in early 2015, has risen to the point where it is or in each issue of Ratings & Reports. We estimate that higher than at the end of 2014. Even if interest rates had the rate on the 10-year Treasury note-which is used to remained stable, though, it would not have been surpris- calculate the dividend line in the price charts of utility ing to see a reversion to the mean after two years of stocks-will climb by more than a percentage point in significant outperformance. 2016, and still more by 2018-2020. Such a move would likely hurt the prices of electric utility equities, which There are also company-specific reasons why some remain sensitive to interest rates. utility stocks have weakened. For instance, the decline Paul E. Debbas, CFA in oil prices since mid-2014 has hurt CenterPoint Energy and OGE Energy. Each of these companies has a stal<e in Enable Midstream Partners, an oil and gas master limited partnership. The decline in oil prices has re- Electric Utility duced rig activity where Enable operates. Even in 2014, RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.) CenterPoint and OGE were outliers among utility issues, 150 and the underperformance has continued this year. 120 For Some Companies, Lower Earnings 90 Electric utilities normally aren't fast-growing compa-75
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creases more often than not. For instance, Wisconsin 60 y \..-
"-A Energy has seen its earnings rise for 10 consecutive 45 years, and we expect the streak to continue in 2015 and 2016. CMS Energy has a five-year streak going. This year, however, there are more exceptions than usual. 30 The profits of CenterPoint and OGE, mentioned above, will probably wind up lower in 2015 due to the indus-trywide conditions affecting Enable. In some cases, regu- 15 2009 2010 2011 2012 2013 2014 2015 latory lag (higher costs that aren't reflected in rates) at Index: June, 1967 = 100
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Schedule AHG-5 15-WSEE-115-RTS May 1, 2015 ELECTRIC UTILITY (WEST) INDUSTRY 2230 All of the major electric utilities located in the INDUSTRY TIMELINESS: 8 (of 97) western region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the and has swallowed the costs of fixing deficiencies in its remaining utilities, in Issue 5. system. In April, the California Public Utilities Commis-sion (CPUC) hit the utility with $1.6 billion in fines, rate Several acquisitions are pending in the Electric credits, and other penalties. This was greater than the Utility Industry. Not every buyer is a domestic initial proposal of $1.4 billion. Moreover, the new presi-utility. dent of the CPUC expressed frustration that some of the penalties (other than the fine) are tax-deductible and The regulatory climate in California appears to suggested that the CPUC take steps to alert state and be taking a turn for the worse. federal tax authorities about the disallowances "so that they can evaluate PG&E's potential future tax filings The prices of most electric utility stocks have appropriately." declined so far in 2015. However, this does not mean that they have become cheap. PG&E and Southern California Edison (SCE), a sub-sidiary of Edison International, have disclosed some ex Electric Utility Acquisitions parte communications between their company and The past few years have seen a lot of takeover activity CPUC employees, including the former president. in the Electric Utility Industry. Some of the deals were PG&E replaced some executives as a result. Even so, traditional utility acquisitions, such as Duke Energy's this might affect the outcome of its gas transmission and takeover of Progress Energy in 2012 or MidAmerican storage rate case before the CPUC. Regarding SCE, two Energy's buyout of NV Energy in 2013. Pending deals groups that signed a settlement in 2014 regarding along these lines involve Exelon buying Pepco Holdings; regulatory treatment of the San Onofre nuclear station Wisconsin Energy acquiring Integrys Energy; and Nex- (which is now closed) want the utility to face penalties tEra Energy taking over Hawaiian Electric Industries. due to the improper communications. The company Low interest rates have facilitated acquisitions, and the believes the settlement was enacted fairly and should be high valuations of most utility equities have encouraged retained. Note that SCE still has a general rate case some companies to issue stock for part of the transac- pending (as do the two California utilities owned by tion. Sempra Energy). Before we make a change to Califor-nia's regulatory climate, we want to see how these Not every buyer is a traditional domestic utility. matters are resolved. Fortis, a Canadian utility company covered in the Diver-sified Company Industry in Issue 9, made an unsuccess- Conclusion ful attempt for Central Vermont Public Service in 2011. Electric utility stocks, in general, performed ex-Two subsequent bids for U.S. utilities were completed. tremely well in 2013 and 2014. A decline in interest rates Fortis bought CH Energy in New York in 2013 and from an already low level helped. By contrast, the prices followed by acquiring UNS Energy in Arizona in 2014. of most electric utility equities have retreated so far in We wouldn't rule out additional transactions from For- 2015. We believe this is due, in part, to investor concerns tis. Iberdrola, a Spanish utility that already owns U.S. that the Federal Reserve will finally start raising inter-utilities in New York and New England, has agreed to est rates later this year, and due partly to a simple take over UIL Holdings. (If the deal goes through, reversion to the mean. Iberdrola USA will be listed on the New York Stock Exchange following the closing.) Finally, Cleco Corpora- Even after this year's weak performance, these stocks tion in Louisiana has agreed to be acquired by a consor- can hardly be considered cheap. The average dividend tium led by Macquarie Infrastructure Partners and yield of 3. 7% is low, by historical standards. Most issues British Columbia Energy. are trading within their 2018-2020 Target Price Range. Over that time frame, the total return potential for this Investors should be aware that this industry has a industry, as a group, is just 4%. high failure rate when it comes to proposed deals. Paul E. Debbas, CFA Obtaining state regulatory approval is often challeng-ing. NextEra has made two unsuccessful merger at- Electric Utility tempts. Exelon, Pepco Holdings, and Wisconsin Energy RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.) have each struck out once. And UIL Holdings tried to 150 buy the municipal gas utility that serves Philadelphia, but was unsuccessful. 120 90
- 1. . .
The Regulatory Climate In California 75
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climate. Volume and revenues have been decoupled, and 60 a utility's earnings growth has depended on increases in 45 its rate base. Allowed returns on equity are reasonable. However, the recent experiences of two companies in the Golden State have raised concerns for utility investors. 30 In September of 2010, an explosion of a PG&E gas pipeline in San Bruno, California caused eight deaths, dozens of injuries, and extensive property damage. The 15 2009 2010 2011 2012 2013 2014 2015 company has made payments to the victims and the city, Index: June, 1967 = 100
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Schedule AHG-5 15-WSEE-115-RTS ALLETE NYSE-ALE IRECENT
- PRICE 5212 , E 181 IP'RATIO , eramng:1a.o)
Median: 16.0 RELATIVE P/E RATIO 098 DIV'YLDD 3.9%i!ifi I TIMELINESS 3 lowered 9/19n4 High: 37.5 51.7 49.3 51.3 49.0 35.3 37.9 42.5 42.7 54.1 58.0 59.7 Target Price Range Low: 30.8 35.7 42.6 38.2 28.3 23.3 30.0 35.1 37.7 41.4 44.2 51.2 2018 2019 2020 SAFETY 2 Newl0/1/04 LEGENDS 0.76 x Dividends f sh 120
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TECHNICAL 3 Raised 3120/15 divided b~ Interns Rate
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THIS 2Ql0t4 3Ql014 4Q2014 Percent 15 STOCK INDEX
.1111 1 yr. 12.9 8.2 mt:
lo Buy 98 104 97 shares '"' Ill. 60.8 - Ill ~""" 10 '111111111 ol.1111 3yr. 48.9 11111.1.1 '" 1~~~~11~1~~~~1 lo Seti 75 75 90 traded *"'" Hld's/000) 29801 29758 32344 5 11111111111 11111111111 1111111111 1111111111111111111111 5 yr. 116.2 110.1 - 1999 2000 2001 2002 2003 2004 2005 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20
.. *- .. .. .. 25.30 24.50 25.23 27.33 24.57 21.57 25.34 24.75 24.40 24.60 24.77 28.20 30.15 Revenues per sh 35.00
.. .. .. .. .. 2.97 3.85 4.14 4.42 4.23 3.57 4.35 4.91 5.01 5.35 5.68 6.15 6.60 "Cash Flow" per sh 8.00
.. .. .. .. .. 1.35 2.48 2.77 3.08 2.82 1.89 2.19 2.65 2.58 2.63 2.90 3.05 3.25 Earnings per sh A 4.00
.. .. .. .. .. .30 1.25 1.45 1.64 1.72 1.76 1.76 1.78 1.84 1.90 1.96 2.02 2.10 Div'd Decl'd per she* t 2.40
.. .. -- .. .. 2.12 1.95 3.37 6.82 9.24 9.05 6.95 6.38 10.30 7.93 12.48 5.90 4.90 Cap'I Spenalng per sh 5.50
.. .. .. .. . . 21.23 20.03 21.90 24.11 25.37 26.41 27.26 28.78 30.48 32.44 35.06 36.55 37.80 Book Value per sh c 42.25
.. .. -- .. .. 29.70 30.10 30.40 30.80 32.60 35,20 35.80 37.50 39.40 41.40 45.90 47.50 47.75 Common Shs Outst'g o 48.50
.. .. .. .. .. 25.2 17.9 16.5 14.8 13.9 16.1 16.0 14.7 15.9 18.6 17.2 Boldflg res are Avg Ann'i P/E Ratio 13.5
.. .. -- .. .. 1.33 .95 .89 .79 .84 1.07 1.02 .92 1.01 1.05 .91 Value Line Relative P/E Ratio .85
.. .. .. .. . . .9% esl/n ates 2.8% 3.2% 3.6% 4.4% 5.8% 5.0% 4.6% 4.5% 3.9% 3.9% Avg Ann'I Dlv'd Yield 4.5%
CAPITAL STRUCTURE as of 12131/14 737.4 767.1 841.7 801.0 759.1 907.0 928.2 961.2 1018.4 1136.8 1340 1440 Revenues ($mill) 1700 Total Debt $1377.2 mill. Due In 5 Yrs $285.6 mill. 68.0 77.3 87.6 82.5 61.0 75.3 93.8 97.1 104.7 124.8 140 155 Net Prom ($mill) 190 LT Debt $1272.8 mill. LT Interest $57.3 mill. 28.4% 37.5% 34.8% 34.3% 33.7% 37.2% 27.6% 28.1% 21.5% {LT Interest earned: 3.9x) 22.6% 15.0% 15.0% Income Tax Rate 15.0% Leases, Uncapitalized Annual rentals $13.4 mill. .4% 1.4% 6.6% 5.8% 12.8% 8.9% 2.7% 5.3% 4.4% 6.3% 4.0% 2.0% AFUDC %to Net Prom 2.0% 39.1% 35.1% 35.6% 41.6% 42.8% 44.2% 44.3% 43.7% 44.6% 44.2% 44.0% 43.0% Long-Term Debt Ratio 42.0% Pension Assets-12/14 $544.2 mill. 60.9% 64.9% 64.4% 58.4% 57.2% 55.8% 55.7% 56.3% 55.4% 55.8% 56.0% 57.0% Common Equity Ratio 58.0% Obllg. $714.5 mill. 990.6 1025.6 1153.5 1415.4 1625.3 1747.6 1937.2 2134.6 2425.9 2882.2 3090 3155 Total Capital ($m!ll) 3525 Pfd Stock None 860.4 921.6 1104.5 1387.3 1622.7 1805.6 1982.7 2347.6 2576.5 3286.4 3565 3640 Net Plant ($mill) 3975 Common Stock 45,953,851 shs. 8.0% 8.6% 8.6% 6.7% 4.8% 5.4% 6.0% 5.6% 5.3% 5.2% 5.5% 6.0% Return on Total Cap'I 6.5% as of2/1/15 11.3% 11.6% 11.8% 10.0% 6.6% 7.7% 8.7% 8.1% 7.8% 7.8% 8.0% 8.5% Return on Shr. Equity 9.5% 11.3% 11.6% 11.8% 10.0% 6.6% 7.7% 8.7% 8.1% 7.8% 7.8% 8.0% 8.5% Return on Com Equity E 9.5% MARKET CAP: $2.4 billion {Mid Cap) 5.2% 5.0% 5.8% 3.9% .5% 1.5% 2.9% 2.3% 2.2% 2.5% 2.5% 3.0% Retained to Com Eq 3.5% ELECTRIC OPERATING STATISTICS 54% 57% 51% 61% 93% 81% 66% 71% 72% 67% 67% 65% Ail Dlv'ds to Net Prof 61% 2012 2013 2014
%Change Re~n Sales (Kl/111) +1.1 -1.1 +.5 BUSINESS: ALLETE, Inc. Is the parent of Minnesota Power, which projects. Acq'd U.S. Water Services 2/15. Has real eslate operation A1g. IOOusl Use ~l'llH~ NA NA NA supplies electricity to 146,000 customers in northeastern MN, &Su- in FL. Generating sources: coal & lignite, 56%; wind, 7%; other, A1g. loousl Re~. per IH (¢) 5.24 5.45 6.09 parlor Water, Light &Power in northwestern WI. Electric rev. break- 3%; purchased, 34%. Fuel costs: 31% of revs. '14 deprec. rate: ~!~t~!a:1 1790 1793 1985 down: !aconite mining/processing, 27%; paper/wood products, 9%; 2.9%. Has 1,600 employees. Chairman, President & CEO: Alan R.
1633 1646 1637 other industrial, 7%; resldenlial, 12%; commercial, 13%; wholesale, Hodnik. Inc.: MN. Address: 30 West Superior St., Duluth, MN 79.0 NA NA
+.5 NA NA 10% other, 22%. ALLETE Clean Energy owns renewable energy 55802-2093. Tel.: 218-279-5000, Internet: www.allete.com.
F~ed Chaige C-Ov. ANNUAL RATES Past 1%1 341 306 Past Est'd '12*'14 345 ALLETE's earnings are likely to ad-vance in 2015. Minnesota Power, the lators do not approve the deal, then Min-nesota Power will sell the output under a or change (per sh) 10Yrs. 5Yrs. to '18.'20 company's primary utility subsidiary, will long-term purchased-power contract. Revenues "Cash Flow"
-.5%
6.0% 5.5%
-- 6.0%
7.0% benefit from a full year of income from a 205-megawatt wind project that was com-ALLETE has made an acquisition. The company paid $168 million for an 87% in-Earnings 7.0% 1.0% 7.0% Dividends NMF 2.0% 4.0% pleted in December at a cost of $333 mil- terest in U.S. Water Services, which pro-Book Value 4.5% 5.0% 4.5% lion. The utility gets current cost recoveJ; vides water management for industrial Cal* QUARTERLY REVENUES($ mill.) Full for certain kinds of capital spending, sue customers. Revenues were about $120 mil-endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year as a $250 million environmental upgrade lion last year, and the company expects 2012 240.0 216.4 248.8 256.0 961.2 to a coal-fired generating unit. In addition, top-line growth of 10%-15% annually. 2013 263.8 235.6 251.0 268.0 1018.4 Minnesota Power is experiencing load However, due to amortization that AL-2014 296.5 260.7 288.9 290.7 1136.8 growth as some of its large industrial cus- LETE will record under purch(lse account-2015 320 325 345 350 1340 tamers expand their operations. Most ing rules, the deal isn't likely to contribute 2016 360 345 365 370 1440 notably, Essar Steel expects to begin to profits this year. Cai* EARNINGS PER SHARE A Full producing taconite pellets in the second We forecast solid earnings growth in endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year half of 2015. Finally, the company's real 2016. Current recovery of some capital 2012 .66 .39 .78 .75 2.58 estate assets in Florida (which ALLETE spending and the ongoing effects of Indus-2013 .83 .35 .63 .82 2.63 intends to sell) should break even this trial expansion should help. We figure 2014 .80 .40 .97 .73 2.90 year. It lost $2 million in 2014. Our esti- U.S. Water Services will also make a con-2015 .85 .45 .85 .90 3.05 mate is within management's guidance of tribution . 2016 .95 .45 .90 .95 3.25 $3.00-$3.20 a share. The board of directors raised the divi-Cal* QUARTERLY DIVIDENDS PAID 8
- t Full There is some upside potential to dend this quarter. The board increased endar Mar.31 Jun.30 Seo.30 Dec.31 Year profits this year. Minnesota Power plans the annual disbursement by $0.06 a share 2011 .445 .445 .445 .445 1.78 to build a wind project for a utility in {3.1%).
2012 .46 .46 .46 .46 1.84 North Dakota, which would then {if the The dividend yield and 3- to 5-year to-2013 .475 .475 .475 .475 1.90 state regulators approve) buy the project. tal return potential for ALLETE are 2014 .49 .49 .49 .49 1.96 Prospective income from the sale is not in- about average, by utility standards. 2015 .505 eluded in ALLETE's guidance. If the regu- Paul E. Debbas, CFA March 20, 2015 (A) Diluted EPS. Exel. nonrec. gain {loss): '04, due early May. (8) Div'ds historically paid in $7.78/sh. {D) In mill. (E) Rate base: Orig. cost Com~any's Flnanclal Strength A 2¢; '05, ($1.84); gain (losses) on disc. ops.: early Mar., June, Sept. and Dec.
- Div'd rein- deprec. Rate allowed on com. eq. In '10: Sloe 's Price Stability 95
'04, $2.57, '05, (16¢J; '06, (2¢); loss from ac- veslment plan avail. t Shareholder inveslment 10.38%; earned on avg. com. eq., '14: 8.6%. Price Growth Persistence 35 counting change: 'O , 27¢. Next egs. report plan avail. (C) Incl. deferred chgs. In '14: Reg. Clim.: Avg. (F) Summer peak In '12 &'13. Earnings Predictability 80 " 2015 Value Line Publishln~ LLC. All ri~hts reserved. Factual material Is obtained from sources believed to be reliable and Is provided vrithout warranties of an~ kind. THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thl~ublication is slricUy for subscribers O'lln, non*commercial, lnlemal use. o Rart
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Schedule AHG-5 15-WSEE-115-RTS ALLIANT ENERGY NYSE-LNT I 60 67 / 17 1 RECENT PRICE , P/E RATIO , (trailing: 17.5) RELATIVE Median: 14.0 PIE RATIO I 093 DIV'YLDD 3.6%- TIMELINESS 3 Lov1ered 8122114 High: 28.8 30.6 40.0 46.5 42.4 31.5 37.7 44.5 47.7 54.2 69.8 70,8 Target Price Range Low: 23.5 25.6 27.5 34.9 22.8 20.3 29.2 33.9 41.9 43.7 50.0 60.1 2018 2019 2020 SAFETY 2 Raised 9128/07 - LEGENDS 0.90 x Dividends sh r 120 I TECHNICAL 3 Raised 3120n 5 divided b~ Jnteres Rate ,.,.*1 100
* * *
- Relative ~ce SltengUt ~
--- .......... ......... 80 BETA .ao (1.00 = Markel) 2018*20 PROJECTIONS O~~~~~~V:r~a Indicates recession _ / "' 1'1111111 * - -- .. .. .. .. . .......... 64 If.II *1 48 Price Gain Ann'I Total Return **. ,11* !11111*' - 11.11" 1' 111111p111 11111 1111 32 High 75 (+25%1 9% 1111 11' Low 55 (-10% 2% ... *i. ,11 1111 111!1 24 Insider Decisions 20
,1 AMJ J AS 0 ND 16 to Buy 0 0 0 0 0 0 0 0 0
.......... .......... ........... ........... . **....:1 12 Optlon1 0 0 0 0 0 0 0 0 0 i~I to Sell o o a o 1 o o 1 a I ~~j.
% TOT. RETURN 2/15 Institutional Decisions -8 I THIS VLAAITH.'
202014 3Q2014 402014 I I 11111 ,I I 11 STOCK INDEX to Buy Percent 12 III " -g;
" I .I ill! 1 yr. 21.3 8.2 llllffil ~III 111 160 152 154 ,11! I to Sell shares 8 II .ldl di.111111 Ill 11111 1111111111 1111111111 3yr. 64.9 60.8 -
5yr. 142.5 110.1 - 134 151 158 traded 4 Hld'slOOOI 67528 67088 68200 I ltiilllllll 11111111111 II Ill 1111111111 1111111111 1111111111 Alliant Energy, formerly called Interstate En* 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 ergy Corporation, was formed on April 21, 28.02 28.93 31.15 33.33 31.02 30.81 33.02 27.88 29.54 30.20 31.55 32.15 Revenues per sh 34.80 1998 throuQh the merger of WPL Holdings, 5.46 4,33 5.12 4.56 4.21 5.21 5.51 5.90 6,68 6.88 7.05 7.45 "Cash Flow" per sh 8.00 IES lndustnes, and Interstate Power. WPL 2.21 2.06 2.69 2.54 1.89 2.75 2.75 3.05 3.29 3.48 3.60 3.85 Earnings per sh A 4.25 stockholders received one share of Inter- 1.05 1.15 1.27 1.40 1.50 1.58 1.70 1.80 1.88 2.04 2.20 2.36 Dlv'd Decl'd per sh a* t 2.85 state Energy stock for each WPL share, IES 4.51 3.42 4.91 7.96 10.87 7.82 6.07 10.43 6.63 7.56 8.85 9.00 Cap'I Spending per sh 9.80 stockholders received 1.14 Interstate Ener- 20.85 22.83 24.30 25.56 25.07 26.09 27.14 28.25 29.58 31,09 31.75 32.45 Book Value per sh c 34.65 gy shares for each IES share, and Interstate 117.04 116.13 110.36 110.45 110.66 110.89 111.02 110,99 110.94 110.94 111.00 112.00 Common Shs Outsl'g o 115.00 Power stockholders received 1.11 Interstate 12.6 16.8 15.1 13.4 13.9 t2.5 14.5 14.5 15.3 16.6 BoldUg res are Avg Ann'I PIE Ralio 15.0 Energy shares for each Interstate Power .67 .91 .80 .81 .93 .80 .91 ,92 .86 .88 Value Line Relative P/E Ratio .95 share. esll* ates Avg Ann'! Div'd Yield 3.8% 3.3% 3.1% 4.1% 5.7% 4.6% 4.3% 4.1% 3.7% 3.5% 4.0% CAPITAL STRUCTURE as of 12/31/14 3279.6 3359.4 3437.6 3681.7 3432,8 3416.1 3665.3 3094.5 3276.8 3350.3 3500 3600 Revenues ($mlll) 4000 Total Debt$3789.7 mill. Due in 5 Yrs $1100.0 mill. 337.8 260.1 320.8 280.0 208.6 303.9 304.4 337.8 382.1 385.5 400 430 Net Profil ($mlll) 490 LT Debt $3606. 7 mill. LT interest $60.0 mill. 19.0% 43.8% 44.4% 33.4% -- 30.1% 19.0% 21.5% 12.4% 10.1% 15.0% 20.0% Income Tax Rate 20.0% (LTinterest earned: 1a.Ox) 3.0% 3.1% 2.4% -- -- -- -- *- 8.8% 6.5% 7.0% 7.0% AFUDC %to Net Profit 7.0% Pension Assets-12114 $1022.9 mill. Obllg. 41.6% 31.4% 32.4% 36.3% 44,3% 46.3% 45.7% 48.4% 46.1% 49.7% 47.5% 47.5% Long-Term Debi Ralio 47.5%
$1301.5 mill. 53.1% 62.9% 61.9% 58.6% 51,2% 49,5% 50.9% 48.4% 50.8% 47.5% 49.5% 49.5% Common Equltv Ralio 49.5%
Pfd Stock $200.0 mill. Pfd Dlv'd $10.2 mill. 4599.1 4218.4 4329.5 4815.6 5423.0 5840.8 5921.2 6476.6 6461.0 7257.2 7500 7500 Total Capllal ($mill) 7800 8,000,000 shs. 4866.2 4944.9 4679.9 5353.5 6203.0 6730.6 7037.1 7838.0 7147.3 6442.0 8000 8000 Net Plant 1$mlll\ . 9000 8.9% 7.5% 8.6% 7.0% 5.1% 6,6% 6.4% 6.3% 7.0% 6.3% 6.5% 6.5% Return on Total Cap'I 7.0% Common Stock 110,935,680 shs. 12.6% 9.0% 11.0% 9.1% 6.9% 9.7% 9,5% 10.1% 11.0% 10.6% 11.0% 11.0% Return on Shr. Eqully 11.5% 13.1% 9.1% 11.3% 9.3% 6.8% 9.9% 9.5% 10.3% 11.3% 10.9% 11.5% 11.5% Return on Com Eqully E 12.0% MARKET CAP: $6.7 billion (Large Cap) 8.1% 4.0% 5.9% 3.8% .9% 3.8% 3.3% 3.9% 4.9% 4.3% 4.5% 4.5% Relalned to Com Eq 5.0% ELECTRIC OPERATING STATISTICS 42% 59% 50% 62% 88% 64% 67% 64% 57% 61% 61% 61% All Dlv'ds lo Net Prof 67% 2012 2013 2014 BUSINESS: Alliant Energy Corp., formerly named Interstate Ener- sources, 2014: coal, 47%; nuclear, 17%; gas, 4%; other, 32%. Fuel
%Ola~ Reial S~es (K'Ml) +.3 +.1 +.1 Avg.I lUse(Mlllj~ 11555 11471 11821 gy, Is a holding company formed through the merger of WPL Hold- cosls: 50% of revs. 2014 depreclallon rate: 5.5%. Estimated plant Avg. lndust Revs~ (¢) 6.42 6.75 6.85 Jngs, IES lnduslries, and Interstate Power. Supplies electricily, gas, age: 12 years. Has 4,200 employees. Chairman & Chief Executive capacity al Peak ~ 5886 5820 5426 and other services Jn Wisconsin, Iowa, and Minnesota. Elect. revs. Officer. Patricia L. Kampling. Incorporated: Wisconsin. Address:
Peak LOad, Summer ~) 5886 5820 5426 by state: WI, 44%; IA, 55%; MN, 1%. Elect. rev.: residential, 39%; 4902 N. Billmore Lane, Madison, Wisconsin 53718. Telephone: Anru~ load Factor(~& NA NA NA
%Change CUslomera -end) +.3 +.4 +.4 commercial, 24%; Industrial, 30%; wholesale, 6%; olher, 1%. Fuel 608-458-3311. Internet: www.alliantenergy.com, Rxed Chaille Cov.(%) 332 295 320 Alliant Energy is investing heavily in share-net guidance of $3.45-$3.75, reflect-ing a slight increase in revenue and fur-ANNUAL RATES Past Past Est'd '12*'14 infrastructure. The Madison, Wisconsin-of change (per sh) 10Yrs. 5Yrs. to '18-'20 based utility deployed roughly $1 billion in ther CapEx plans. Moreover, Alliant Revenues 0.5% -1.5% 4.0% capital expenditures last year. According should benefit from the certainty of "Cash Flow" 4.0% 7.0% 6.0% to management, it was one of the most ac- several rate settlements that it achieved Earnings 8.0% 6.5% 6.0%
Dividends 3.5% 6.5% 4.5% tive construction years in company his- during the past year for its retail division. Book Value 3.5% 3.5% 4.0% tory, with over $335 million poured into For 2016, we think the company will try QUARTERLY REVENUES($ mill.) energy delivery systems alone. The goal of for further rate increases. We're basing Cal- Full our forecast on reasonable regulatory endar Mar.31 Jun.30 Sep.30 Dec.31 Year that considerable investment was to keep 2012 765.7 690.3 887.6 750.9 3094.5 pace with customer growth, and bring nat- treatment from state officials. 2013 859.6 718.0 866.6 832.6 3276.8 ural gas services to communities which did The board of directors has raised the 2014 952.8 750.3 843.1 804.1 3350.3 not have access before. dividend. The quarterly distribution was 2015 950 800 950 800 3500 Carbon emission reductions remain a increased $0.04 a share (8%), and the an-2016 975 850 975 800 3600 top hriority. During 2014, Alliant made nualized payout is now $2.20. For the util-EARNINGS PER SHARE A signi leant progress transitioning its coal- ity sector, the equity's current yield of Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year fired facilities to produce higher levels of around 3.6% is about average for the in-2012 .50 .58 1.34 .63 3.05 natural gas fueled generation (which is dustry. The company is targeting a payout 2013 .72 .59 1.43 .55 3.29 safer for the environment). The company ratio of 60%-70%. 2014 .97 .56 1.40 .55 3.48 also increased its use of renewable energy These shares may appeal to some 2015 .85 .60 1.55 .60 3.60 in many of its plants. Additionally, Alliant income-oriented investors. The divi-2016 .90 .65 1.65 .65 3.85 is constructing several new installations dend is well supported by Alliant's predic-Cal* QUARTERLY DIVIDENDS PAID 0 *t Full known as wetland systems that will im- table cash flows, and the yield is decent, endar Mar.31 Jun.30 SeP.30 Dec.31 Year prove the treatment of wastewater around though unspectacular. However, at Us its facilities. most recent quotation, the issue offers be-2011 .425 .425 .425 .425 1.70 2012 .45 .45 .45 .45 1.80 We estimate earnings growth will be low average long-term capital appreciation 2013 .47 .47 .47 .47 1.88 in the low-to mid-single-digit range potential. As such, subscribers seeking 2014 .51 .51 .51 .51 2.04 over the next two years. Our 2015 fore- upside may want to look elsewhere. 2015 .55 cast is at the midpoint of management's Daniel Henigson March 20, 2015 I (A) Diluted EPS. Exel. nonrecur. gains (losses): ~l Div'ds historically rid in mid-Feb., May, $0.77/sh. jDl In mill. (El Rate base: Orig. cosl. Com~any's Financial Strength '03, net 24¢; '04, (58¢); '05, ($1.05); '06, 83¢; ug., and Nov.
- Div' reinvest. plan avail. t Rates all' on com. eq. In IA In '14: 10.9%; in Sloe 's Price Stability 100 A
'07, $1.09; '08, 7J.; '09, (88¢); '10, (15¢); '11, Shareholder Invest plan avail. WI In '14 Regul. Clim.: WI, Above Avg.; IA, Price Grow1h Persistence 95 (1¢); '12, (16¢). ext egs. rpt. due early May. (C) Incl. deferred chgs. In '14: $90.0 mill., Avg. Earnings Predlctabillty 75 1'11111""'~"- c 2015 Value Llne Publishln[ LLC. All ri!j!'ls reseived. Factual material Is obtained from sources believed to be reliable and Is provided without warranties of an~ kind. I THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thi~ublicatlon Is slrictly for subscriber's own, non*commerclal, internal use. o~*~ 111-, "'",""' '-or, ol it may be reproduced, resold, stored or ~ansmnted in any printed, electronic or other fmm, or us lor generating or marketing any printed or elecltonlc publication, seivice or pro~ucl
Schedule AHG-5 15-WSEE-115-RTS AMEREN NYSE-AEE IRECENT PRICE 41 ,4 IPIERATIO 16, 7 7eralllng:17.2) RELATIVE Median: 15.0 P/E RATIO 091 DIV'YLDD 4.0%_11161 I TIMELINESS 3 Raised 316115 High: 50.4 56.8 55.2 55.0 54.3 35.3 29.9 34.1 35.3 37.3 48.1 46.8 Target Price Range Low: 40.6 47.5 48.0 47.1 25.5 19.5 23.1 25.5 28.4 30.6 35.2 40.5 2018 2019 2020 2 Raised 6120114 - LEGENDS SAFETY 0.69 x Dividends f sh !<X¥.'7 ~-2rn TECHNICAL 2 Raised 3120115 divided b~ lnteres Rate 80 BETA .75 (1.00 =Markel)
.. *
- Relative rice Strength ';/J ,,.. ........ 60 O~~~~~~ V:r~a 2018*20 PROJECTIONS Ann'! Total "'
Indicates recession
.... , 1 1-:*:1
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50 40 Price Gain Return 30 I, I JI 1111 High 45 (+10%! 6% 25 Low 35 (-15% Insider Decisions AMJ J A S 0 ND 1%
.........***** ...****** .. .. ........ 20 15 lo Buy 0 1 0 0 0 0 0 0 0 OpUons 0 0 0 0 0 0 0 0 0 .. . .......
10 to Sell 0 2 0 0 0 0 0 0 0 lnstltullonal Decisions I " *..... ... ****....... i~*****..*
%TOT. RETURN 2/15
,_7,5 jl!'~~"
THIS VLAR!Tlt' I 11.' 'j"" '" ... 2Q2014 302014 4Q20tl Percent 15 ... STOCK INDEX
- ~~~ 1~g 1~~
Hld's!OOO 159084 160810 157366 1gg shares traded 10 5 1111111 II II 11111 II Ill 11111 111 111 II II 11111 Ill 11111 Ill 11111111
~ II 1111111111 111111111111 1 yr.
3 yr. 5yr. 119.7 9.2 51.5 8.2 60.8 f-110.1 f-1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 25.68 28.10 32.64 24.93 28.20 26.43 33.12 33.30 36.23 36.92 29.87 31.77 31.04 28.14 24.06 24.95 26.15 27.20 Revenues per sh 30.00 5.36 6.11 6.33 5.28 6.29 5.57 6.10 6.02 6.76 6.44 6.06 6.33 5.87 5.87 5.25 5.75 6.10 6.50 "Cash Flow" per sh 7.75 2.81 3.33 3.41 2.66 3.14 2.82 3.13 2.66 2,98 2.88 2.78 2.77 2.47 2.41 2.10 2.40 2.55 2.75 Earnings per sh A 3.25 2.54 2.54 2.54 2.54 2.54 2.54 2.54 2.54 2.54 2.54 1.54 1.54 1.56 1.60 1.60 1.61 1.65 1.69 Dlv'd Decl'd per sh a
- 1.85 4.16 6.77 7.99 5.11 4.19 4.13 4.63 4.99 6.96 9.75 7.51 4.66 4.50 5.49 5.87 7.65 8.10 7.15 Cap'I Spending per sh 7.00 22,52 23.30 24.26 24.93 26.73 29.71 31.09 31.86 32.41 32.80 33.08 32.15 32.64 27.27 26.97 27.65 28.60 29.65 Book Value per sh c 34.00 137.22 137.22 138.05 154.10 162.90 195.20 204.70 206.60 208.30 212.30 237.40 240.40 242.60 242.63 242.63 242.65 242.65 242.65 Common Shs Oulsl'g o 250.00 13.5 11.0 12.1 15.8 13.5 16.3 16.7 19.4 17.4 14.2 9.3 9.7 11.9 13.4 16.5 16.7 Botdl/g res are Avg Ann'I PIE Ratio 12.5
.77 .72 ,62 .86 .77 .86 .89 1.05 .92 .85 .62 .62 .75 .85 .93 .88 Value Lino Relative PIE Ratio ,80 eslln ates 6.7% 6.9% 6.2% 6.1% 6.0% 5.5% 4.9% 4.9% 4.9% 6.2% 6.0% 5.8% 5.3% 5.0% 4.6% 4.0% Avg Ann'I Div'd Yield 4.5%
CAPITAL STRUCTURE as of 9130114 6780.0 6880.0 7546.0 7839.0 7090.0 7638.0 7531.0 6828.0 5838.0 6053.0 6350 6600 Revenues ($mill) 7500 Total Debt $6697 mill. Due In 5 Yrs $2276 mill. 628.0 547.0 629.0 615.0 624.0 669.0 602.0 589.0 518.0 593.0 630 675 Net Profit ($mill) 830 LTDebt $5825 mill. LT Interest $317 rnlll. 35.6% 32,7% 33.5% 33.7% 34.7% 36.8% 37.3% 36.9% 37.5% 38,9% 38.0% 38.5% Income Tax Rate 38.5% (LT lnlerest earned: 3.6x} Leases, Uncapitalized Annual rentals $14 mill. 2.9% .7% .8% 4.6% 5.8% 7.8% 5.6% 6.1% 7.1% 6.0% 7.0% 6.0% AFUDC %to Net Profit 4.0% Pension Assets-12/13 $3461 mill. 44.9% 43.8% 45.0% 47.8% 49.7% 48.2% 45.3% 49.5% 45.2% 47.0% 47.0% 45.5% Long-Term Debt Ratio 45.0% Obllg. $3900 mill. 53.3% 54.6% 53.4% 50.8% 49.1% 50.9% 53,7% 49.4% 53.7% 51.5% 52,0% 53.0% Common Equity Ratio 54.0% Pfd Stock $142 mill. Pfd Dlv'd $8 mill. 11932 12063 12654 13712 15991 15185 14738 13384 12190 12975 13300 13525 Total Capllal ($mlll) 15700 807,595 sh, $3.50 to $5.50 cum. (no par}, $100 13572 14286 15069 16567 17610 17853 18127 16096 16205 17424 18525 19350 Net Plant ($mill) 21500 slated val., redeem, $102.176-$110/sh.; 616,323 sh. 4.00% to 6.625%, $100 par, redeem. $100- 6.5% 5.7% 6.2% 5.7% 5.3% 6.0% 5.6% 6.0% 5.6% 5.5% 6.0% 6.0% Return on Total Cap'I 6.5%
$104/sh. 9.5% 8.1% 9.0% 8.6% 7.8% 8.5% 7.5% 8.7% 7.7% 8.5% 9.0% 9.0% Return on Shr. Equity 9.5%
Common Stock 242,634,798 shs. as of 10131/14 9.7% 8.1% 9.2% 8.7% 7.8% 8.6% 7.5% 8.8% 7.8% 8.5% 9.0% 9.5% Return on Com Eqully E 9.5% MARKET CAP: $10.1 billion (Large Cap) 1.7% .2% 1.3% 1.0% 3.5% 3.8% 2.8% 3.0% 1.9% 3.0% 3.0% 3.5% Retained lo Com Eq 4.5% ELECTRIC OPERATING STATISTICS 83% 97% 86% 88% 56% 56% 63% 66% 76% 67% 64% 61% All Dlv'ds to Net Prof 56% 2011 2012 2013 BUSINESS: Ameren Corp. Is a holding company formed through 9%. Generating sources: coal, 70%; nuclear, 11%; hydro, 2%; gas,
%Change Rela~ Sales {KWH) -1.9 -.7 -.5 Ai~. lndusl Use (M'llH~ NA NA NA the merger of Union Electric and CIPSCO. Acquired CILCORP 1%; purchased, 16%. Fuel cosls: 32% of revs. '13 reported depr.
A1~.lnduslRevs.~1 IH(¢) 4.93 4.80 4.96 1/03; Illinois Power 10/04. Has 1.2 mill. electric and 127,000 gas rates: 3%-4%. Has 8,500 employees. Chairman: Thomas R. Voss. Gapao;itya!Peak( Y( NA NA NA cuslomers In Missouri; 1.2 mill. electric and 811,000 gas customers President & CEO: Warner L. Baxter. Inc.: MO. Address: One Peak load, Summer! ivi) NA NA NA in Illinois. Discon!. power-generation op, In '13. Electric rev. break- Ameren Plaza, 1901 Chouteau Ave., P.O. Box 66149, SI. Louis, AnnuailoadFactor(~I NA NA NA
%Change Customera yr-end) NA NA NA down: residential, 46%; commercial, 33%; Industrial, 12%; other, MO 63166-6149. Tel.: 314-621-3222. Internet: www.ameren.com.
faed Charge Cov. (%) 295 291 289 Ameren has rate cases pending in Missouri. Spending on electric transmis-ANNUAL RATES Past Past Est'd '11-'13 Missouri and Illinois. In Missouri, the sion is another plus, as Ameren earns a re-of change (per sh} 10Yrs. 5Yrs. lo '18.'20 utility is seeking an electric rate increase turn on its current investment through a Revenues -.5% -5.0% 1.0% of $190 million, based on a return of 10.4% federally regulated formula rate plan. Our "Cash Flow" -.5% -2.5% 4.5% on a common-equity ratio of 51.8%. estimate is at the midpoint of manage-Earnings -2.5% -4.0% 5.0% Dividends -4.5% -9.0% 2.0% Ameren is asking for a continuation of var- ment's guidance of $2.45-$2.65 a share. Book Value 1.5% -2.0% 2.5% ious regulatory mechanisms, such as a fuel We forecast high single-digit profit QUARTERLY REVENUES ($mill.) aqjustment clause and a tracker for storm growth in 2016. Additional rate relief Cal* Full costs. The staff of the Missouri commission should be the primary factor. endar Mar.31 Jun.30 Sep.30 Dec.31 Year 2012 1658 1660 2001 1509 6828.0 is recommending an allowed ROE of just Electric transmission is a key growth 2013 1475 1403 1638 1322 5838.0 9.25%, and intervenor grnups are propos- area for Ameren. The company's capital 2014 1594 1419 1670 1370 6053,0 ing similar figures; A decision is expected budget calls for spending of $2.3 billion 2015 1650 1475 1800 1425 6350 in May, with new tariffs taking effect in through 2019. Although it appears almost 2016 1725 1550 1850 1475 6600 June. In Illinois, Ameren is asking for a certain that its allowed ROE on transmis-EARNINGS PER SHARE A gas rate hike of $53 million, based on a sion will be cut from 12.38% currently (in Cal* Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year 10.0%-10.5% return on a 50% common* fact, Ameren took an undisclosed reserve 2012 d.11 .87 1.54 .11 2.41 equity ratio. The utility is also requesting in the fourth quarter of 2014), the utility 2013 .22 .44 1.25 .19 2.10 a regulatory mechanism to decouple reve- will be able to make up for part of the re-2014 .40 .62 1.20 .19 2.40 nues from volume for small customers. An duction through a half-percentage-point 2015 .25 .70 1.35 .25 2.55 order is expected by December, with new incentive "adder." Moreover, the allowed 2016 .30 .70 1.45 .30 2.75 tariffs taking effect in January. ROE will probably still be above its al-Cal- QUARTERLY DIVIDENDS PAID e
- Full Earnings will probably advance this lowed ROEs in Missouri and Illinois.
endar Mar.31 Jun.30 Sen,30 Dec,31 Year year. Ameren will benefit from the ab* The dividend yield of Ameren stock is sence of a refueling outage at the Cal- about average for a utility. The compa-2011 .385 .385 .385 .40 1.56 2012 .40 .40 .40 .40 1.60 laway nuclear plant, a full year's benefit ny has good earnings growth prospects 2013 .40 .40 .40 .40 1.60 from the refinancing of high-cost debt last through 2018-2020, but in our view, these 2014 .40 .40 .40 .41 1.61 May, and (assuming reasonable regulatory are reflected in the quotation . treatment) a partial year of rate relief in Paul E. Debbas, CFA March 20, 2015 2015 .41 I (A} Diluted EPS. Exel. nonrecur. gain (losses}: early May. (B) Div'ds hlslor. paid in lale Mar., com. eq. In MO In '13: 9.8% elec., In '11: none Comkany's Financial Strength '03, 11¢; '05, (11¢); '10, ($2.19); '11, (32¢); '12, June, Sepl., & Dec.* Div'd reinvest frlan avail. specified gas; In IL in '14: 8.7% alee., 9.06% Stoc 's Price Stablllty B++ 100 ($6.42); loss from disc. ops.: '13, 92¢. '14 EPS (C) Incl. intang. In '13: $6.90/sh. (D} n mill. (E) gas; earned on avg. com. eq., '13: 7.6%. Regu- Price Growth Persistence 10 don't add due to rounding. Next egs. report due Rate base: Orig. cos! deprec. Rate allowed on latory Climate: MO, Avg.; IL, Below Avg. Earnings Predlctablllty 85 " 2015 Value Line Publishln~ LLC. Alt ri~ts reserved. Factual material Is obtained from sources believed 10 be reliable and Is provided without warranlles of any kind. THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thi~ublicallon Is strlcUy for subscribe~s own, non-commercial, Internal use. No ~art 1IIf'£*" I n.fj iT**~ :UllP\1/llllilm of il may be reproduced, resold, stored or transmilled in any printed, electronic or other fonn, or us for generating or marketing any printed or electronic pubficallon, service or proilucl.
Schedule AHG-5 15-WSEE-115-RTS AMERICAN ELEC PWR NYSE-AEP RECENT 1 1 PRICE 55,26 IPIERATIO 16, 5(Traillng:16.1) Median: 13.0 RELATIVE PIE RATIO 0,90 DIVYLDD 3.9%1 TIMELINESS 3 Raised 316/15 High: 35.5 40.8 43.1 51.2 49.1 36.5 37.9 41.7 45.4 51.6 63.2 65.4 Target Price Range Low: 28.5 32.3 32.3 41.7 25.5 24.0 28.2 33.1 37.0 41.8 45,8 54.7 2018 2019 2020 2 Raised 9119114 SAFETY TECHNICAL 3 Raisell 3/20/15 - LEGENDS
~i~~~~vi1~1~~~,r~~1e
. . . . Relative Pnce S~englh
' (-'"-.:-,-
I c:;--+---j---f----1---+---!----l---+-~f---+---+128 ,_e_E_TA~.7~0 ~(~1.0=0==~Ma=rk=et=)~----' O~~~~~/ir~a indicares recession 2018*20 PROJECTIONS Ann'I Total 1 .. Price Gain Return - - - - - - t - - - - t ,"'1"""*1=11* High 70 (+25:1Jij 10% 1... ,,1 11 ... "1" " ,, .. 1 Low 45 (-20 Yo Nil ('Ir". *1 Insider Decisions lh.1r.l1'!....:.....:+"'---IF=~-+---f=:.._;i AMJJASOND 1
~p~~S g1g g g g g g g gL*,-...-.,-..-, t-.-
. --lf----+----+-- ._ ~~
to Sell o 6 o o 2 o o oo **.:*'*"' " %TOT. RETURN 2115 Institutional Decisions 11 l* ""' *., *"'* ".... ,......, .* ...
- THis VLARrrH.'
1 2Q2014 302014 402014 Percent 15 f * * " ** '"'** STOCK INDEX t-to Buy 338 325 361 shares 10 ;,,, ' 1 yr. 19.1 8.2 to Sell 267 301 308 t d d 5 .h .1111 11111 .11 ltlllllh 11111111 3 yr. 73.3 60.8 r-Hld's(OOO 323714 326207 326985 ra e lllllllllll 111111111111111111111111111111 5yr. 114.1 110.1 ~ 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 VALUELINEPUB.LLC 1' 8-20 35.63 42.53 190.10 42.96 36.82 35.51 30.76 31.82 33.41 35.56 28.22 30.01 31.27 30.77 31.48 34.75 34.55 35.85 Revenues per sh 41.00 6.36 5.11 7.65 6.99 5.76 5.89 5.96 6.67 6,80 6.84 6.32 6.29 6.83 6.64 6.75 7.25 7.50 7.85 "Cash Flow per sh 9.25 2.69 1.04 3.27 2.86 2.53 2.61 2.64 2.86 2.86 2.99 2.97 2.60 3.13 2.98 3.18 3.34 3.50 3.65 Earnings per sh A 4.50 2.40 2.40 2.40 2.40 1.65 1.40 1.42 1.50 1.58 1.64 1.64 1.71 1.85 1.88 1.95 2.03 2.15 2.27 Div'dDecl'dpersh 8
- 2.65 4.47 5.51 5.69 5.08 3.44 4.28 6.11 8.89 8.88 9.83 6.19 5.07 5.74 6.45 7.75 8.65 9.30 8.05 Cap'I Spending per sh 8.50 25.79 25.01 25.54 20.85 19.93 21.32 23.08 23.73 25.17 26.33 27.49 28.33 30.33 31.37 32.98 34.35 35.75 37.25 BookValuepersh c 42.25 194.10 322.02 322.24 338.84 395.02 395.86 393.72 396.67 400.43 406.07 478.05 480.81 483.42 485.67 487.78 490.00 492.00 494.00 Common Shs Outst'g 0 500.00 14.3 34.3 13.9 12.7 10.7 12.4 13.7 12.9 16.3 13.1 10.0 13.4 11.9 13.8 14.5 15.9 Bold Ilg res are Avg Ann'I P/E Ratio 13.0
.82 2.23 .71 .69 .61 .66 .73 .70 .87 .79 .67 .85 .75 .88 ,81 .84 Value Lin* Relative P/E Ratio .BO 6.2% 6.7% 5.3% 6.6% 6.1% 4.3% 3.9% 4.1% 3.4% 4.2% 5.5% 4.9% 5.0% 4.6% 4.2% 3.8% esl/n ates Avg Ann'i Dlv'd Yleld 4.5%
CAPITAL STRUCTURE as of 9/30/14 12111 12622 13380 14440 13489 14427 15116 14945 15357 17020 17000 17700 Revenues ($mlll) 20450 Total Debt $19340 mill. Due in 5 Yrs $9356 mill. 1036.0 1131.0 1147.0 1208.0 1365.0 1248.0 1513.0 1443.0 1549.0 1634.0 1675 1755 Net Profit ($mill) 2185 LTDebt $15677 mill. LTlnterest $713 mill. 29.3% 33.0% 31.1% 31.3% 29.7% 34.8% 31.7% 33.9% 36.2% 37.8% 36.0% 36.0% Income Tax Rate 36.0% Incl. $2230 mill. securitized bonds. {LT interest earned: 3.7x) 5.4% 9.9% 9.8% 9.9% 10.9% 10.4% 10.6% 11.2% 7.3% 9.0% 10.0% 7.0% AFUDC %to Net Profit 7.0% 54.8% 56.7% 58.3% 59.1% 54.4% 53.1% 50.7% 50.6% 51.1% 49.0% 50.0% 49.0% Long-Term Debt Ratio 48.5% Leases, Uncapitalized Annual rentals $288 mill. 44.9% 43.0% 41.4*/~ 40.7% 45.4% 46.7% 49.3% 49.4% 48.9% 51.0% 50.0% 51.0% Common Equily Ralio 51.5% Pension Assets-12/13 $4711 mill. 20222 21902 24342 26290 28958 29184 29747 30823 32913 34050 35300 36050 Total Capital ($mlll) 41100 Oblig. $4841 mill. 24284 26781 29870 32987 34344 35674 36971 38763 40997 44117 46750 48650 Net Plant !$mill\ 54300 Pfd Stock None 6.6% 6.7% 6.3% 6.2% 6.2% 5.7% 6.6% 6.1% 6.0% 6.0% 6.0% 6.0% Relurn on Tola! Cap'I 6.5% Common Stock489,240,481 shs. 11.3% 11.9% 11.3% 11.2% 10:3% 9.1% 10.3% 9.5% 9.6% 9.5% 9.5% 9.5% Return onShr. Equity 10.5% as of 10/23/14 11.3% 12.0% 11.4% 11.3% 10.4% 9.1% 10.3% 9.5% 9.6% 9.5% 10.0% 10.0% Return on Com Equity E 10.5% MARKET CAP: $27 billion (Large Cap) 5.2% 5.7% 5.1% 5.1% 4.6% 3.1% 4.2% 3.5% 3.7% 4.0% 4.0% 4.0% Retained to Com Eq 4.5% ELECTRIC OPERATING STATISTICS 54% 53% 55% 55% 56% 66% 60% 63% 62% 64% 63% 64% All Dlv'ds to Net Prof 61%
%Change Retail Sales (KWH)
A1~.industUse(MWHI
~1~1 2 NA
?d.1 NA 2
?n NA BUSINESS: American Electric Power Company, Inc. (AEP),
through 10 operating utilities, serves 5.3 mill. customers in Arkan-utility) '01; sold SEEBOARD (British umily) '02; sold Houston Pipeline '05. Generating sources not available. Fuel costs: 36% or A1~.lndustReis.ierKl/IH(¢) 4.95 4.69 NA sas, Kentucky, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Ten* revenues. '13 reported deprec. rates (utillly): 1.1%*7.9%. Has CapaciiyatPeak(IJw) NA NA NA nessee, Texas, Virginia, and West Virginia. Electric revenue break- 18,500 employees. Chairman, President & CEO: Nicholas K. Akins.
~~a\~~1ctor(%) ~~ ~~ ~~ down: residential, 40%; commercial, 23%; industrial, 19%; whole- Inc.: New York. Address: 1 Riverside Plaza, Columbus, Ohio %Char.geCustomera(yr*end) NA NA NA sale, 15%; other, 3%, Sold 50% stake In Yorkshire Holdings (British 43215-2373. Tel.: 614*716-1000. Internet: www.aep.com.
F~edChaigeCov.(%) 286 280 326 What will American Electric Power do cline in 2015 and 2016. Even so, rising ANNUAL RATES Past Past Est'd *11-' 13 with its nonregulated generating as- profits from the regulated operations ofchange(persh) 10Yrs. 5Yrs. to'18-'20 sets in Ohio? The company had proposed should outweigh this falloff. Some of AEP's Revenues -10.0% -1.5% 4.0% a purchased-power agreement with four utilities are asking for rate increases, and
~~~~i~~!ow" . -;,;.
5 15
. % i:g~ plants, which was intended to provide the company's electric transmission opera-Dividends -1.5% 4.0% 5.0% these assets with a stable source of in- tions are increasing their contribution as Book Value 3.5% 4.5% 4.5% come. The state commission rejected AEP's more capital is invested in this area. Over Cal* QUARTERLYREVENUES($mill.) Full proposal, but did not prohibit purchased- the next three years, AEP has budgeted endar Mar.31 Jun.30 Sep.30 Dec.31 Year power contracts. Now, the company must more than $4.8 billion for transmission 2012 3625 3551 41 56 3613 14945 decide whether to put forth a revised pro- capital expenditures. Our earnings esti-2013 3826 3582 4176 3773 15357 posal, or sell the assets. In fact, AEP has mates for 2015 and 2016 are at the mid-2014 4648 4044 4302 4026 17020 hired an investment-banking firm to point of management's targeted ranges of 2015 4350 4100 4500 4050 17000 evaluate a sale. Another company with $3.40-$3.60 a share and $3.45-$3.85 a 2016 4550 4250 4700 4200 17700 nonregulated generating units in Ohio, share, respectively.
Cal- EARNINGSPERSHAREA Full Duke Energy, reached an agreement to Rate cases are pending in West Vir-endar Mar.31 Jun.30 Sep.30 Dec.31 Year sell these plants last year. Duke fared bet- ginia and Kentucky. In West Virginia, 2012 2013
.80
.75
.75
.73 1.00 1.10
.43
.60 2.98 tehr thhanh it had original ly e xdpected, al-3.18 t oug t e units were sti11 so1 at a 1ass.
Appalachian Powber isd seeking a ~~te hike of $226 million, ase on a 10 . 70 return 62 2014 1.15 .80 1.01 .39 3.34 In any case, AEP has been striving to on equity. An order is due on May 26th. 2015 1.00 .80 1.15 .55 3.50 make itself a more regulated company in Kentucky Power filed for a rate increase of 2016 1.05 .85 1.20 .55 3.65 recent years. We don't know when man- $70 million, based on the same 10.62% Cal* QUARTERLY DIVIDENDS PAID Ba Full agement will announce its plans. ROE. New tariffs should take effect in endar Mar.31 Jun.30 Sea,30 Dec.31 Year We estimate mid-single-digit earnings mid-2015. 2011 46 46 46 47 1.B 5 growth this year and next. We are This stock has a dividend yield and 3-2012 :47 :47 :47 :47 1.88 basing o ur edstimates on retention oDf AEP's to 5-ybear total returnb potcc;n.tial that 2013 .47 .49 .49 .50 1.95 nonregu 1ate generating assets. ue to are a out average, y uti1ity stan-2014 .50 .50 .50 .53 2.03 conditions in the power markets, the in- dards. 2015 .53 come from these assets will probably de- Paul E. Debbas, CFA March 20, 2015 (A) Diluted EPS. Exel. nonrec. gains (losses1: (57¢); '03, (32¢); '04, 15¢; '05, 7¢; '06, 2¢; '08, invest. plan avail. IC/ Incl. lntang. In '13: Company's Financial Strength A '02, ($3.86); '03, ($1.92); '04, 24¢; '05, (62¢; $¢. '11 EPS don't add due to rounding. Next $18.20/sh. (D) In mill. E) Rate base: various, Stock's Price Stability 100 '06, (20¢); '07, (20¢); '08, 40¢; '10, (7¢); '1 , egs. report due late Apr. (B) Div'ds historically Rates all'd on com. eq.: 9.65%-10.9%; earned Price Growth Persistence 60 89¢; '12, (38¢); '13, (14¢); discont. ops.: '02, paid early Mar., June, Sept., & Dec.* Dlv'd re- on avg. ccm. eq., '13: 9.9%. Regul. Clim.: Avg. Earnings Predictability 90 <> 2015 Value Line Publishing LLC. All rtghts reserved. Factual matenal Is oblained from sources believed to be reliable and Is provided without warranties of any kind.
- THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication Is strictly for subscribe(s own, non-commercial, Internal use. No ~art ll 11*~ 11 1<'<M I* '--,11
- ctillil " 111111 of it may be reproduced, resold, slored or transmnted Jn any prinled, eleclronic or o!her form, or used for generating or marketing any printed or electronic publication, service or proouct.
Schedule AHG-5 15-WSEE-115-RTS AVISTA CORP. NYSE-AVA IRECENT PRICE 33.39 P/E RATIO 17 ,3 (!railing: 18.0) Median: 16.0 RELATWE PIE RATIO 089 DW'YLDD 4.0%j I TIMELINESS 3 Lowered 11114n4 High: Low: 19.4 15.4 20.2 16.3 27.5 17.6 25.8 18.2 23.6 15.5 22.4 12.7 22.8 18.5 26.5 21.1 28.0 22.8 29.3 24.1 37.4 27.7 38.3 32.1 Target Price Range 2018 2019 2020 SAFETY 2 Raised 5n/10 - LEGENDS 0.86 x Dividends shr I ---- :.;c;c'.'-o 'i'O:I-"::~ 64 TECHNICAL 2 Lowered 4/24/15 divided b~ lnteres Rate
* * . . Relative rice Stren91h ! '.tq /"'--
-- 48 111-- -- --
BETA .80 (1.00 = Marlee!) -*-:1 o~g~~~yir~a Indicates recession 40
/
2018*20 PROJECTIONS Ann'I Total Ii lo'
- '::**1 1 _/
** i..1.1 111 1 111 11111111111 11 -...... - .-...... 32 24 Price Gain Return High 40 (+2004 9% 1 1l 11)11i J 1 111* *111 1 1
{I '11 ' ~ *.;
'>~i 11 ...
I
------111 I 20 16 Low 30 (-10% 2%
Insider Decisions ttl' 1"' "j!'.f 12 JJASON D J F 8 to Buy 000000 0 0 0 Options 0 0 0 0 0 0 0 0 0 r-6 to Seit 6 0 1 1 0 1 0 0 1
'" %TOT. RETURN 3/15 Institutional Decisions lHIS VlARllH.'
2Ql014 3Q20t4 4Q20tl Percent 18 I i';* STOCK INDEX to Buy 97 99 104 shares 12~* 1yr. 3yr. 15.9 52.0 7.7 57.2 ""
~
to Sell 92 Hld'slOOO 40836 41104 41419 107 106 traded 6 ;;;;;;!Ill 11111 1111;;;;;;- Ill" 11111 5yr. 106.3 94.5
~
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 221.75 167.59 126.17 20.41 23.24 23.76 27.98 28.68 26.80 30.77 27.58 27.29 27.73 25.86 26.94 23.66 25.30 25.30 Revenues per sh 30.00 2.28 3.31 2.71 2.19 2.63 2.35 2.72 4.27 2.93 3.98 4.45 3.62 3.78 3.70 4.36 4.36 4.65 4.85 "Cash Flow" per sh 5.75
.12 1.76 1.20 .67 1.02 .73 .92 1.47 .72 1.36 1.58 1.65 1.72 1.32 1.85 1.84 1.95 2.05 Earnings per sh A 2.50
.48 .48 .48 .48 .49 .52 .55 .57 .60 .69 .81 1.00 1.10 1.16 1.22 1.27 1.32 1.31 Dlv'd Decl'd per sh e
- 1.55 3.30 4.24 5.92 1.74 2.21 2.47 3.23 3.14 4.04 4.09 3.86 3.64 4.20 4.61 5.05 5.47 6.55 6.05 Cap'I Spending per sh 6.25 10.69 15.34 15.12 14.84 15.54 15.54 15.87 17.46 17.27 18.30 19.17 19.71 20.30 21.06 21.61 23.84 24.50 25.15 Book Value per sh c 27.50 35.65 47.21 47.63 48.04 48.34 48.47 48.59 52.51 52,91 54.49 54.84 57.12 58.42 59.81 60.08 62.24 62.30 62.50 Common Shs Outst'g o 64.00 NMF 13.6 13.7 19.3 13.8 24.4 19.4 15.4 30.9 15.0 11.4 12.7 14.1 19.3 14.6 17.3 Bold fig res are Avg Ann'I P/E Ratio 14.0 NMF .88 .70 1.05 .79 1.29 1.03 .83 1.64 .90 .76 .81 .88 1.23 .82 .91 vacuo Line Relative P/E Ratio .90 esccn ates 2.8% 2.0% 2.9% 3.7% 3.5% 2.9% 3.0% 2.5% 2.7% 3.4% 4.5% 4.8% 4.5% 4.6% 4.5% 4.0% Avg Ann'I Dlv'd Yleld 4.5%
CAPITAL STRUCTURE as of 12131/14 1359.6 1506.3 1417.8 1676.8 1512.6 1558.7 1619.8 1547.0 1618.5 1472.6 1575 1650 Revenues ($mill) 1925 Total Debt $1656.5 mill. Due In 5 Yrs $590.6 mill. 47.2 75.1 38.5 73.6 87.1 92.4 100.2 78.2 111.1 114.2 125 130 Net Profit ($mlll} 155 LT Debt $1543.6 mill. LTlnterest $76.1 mill. 35.4% 35.9% 38.7% 38.3% 34.3% 35.0% 35.4% 34.4% 36.0% 37.6% 36.5% 36.5% Income Tax Rate 36.5% Incl. $51.5 mill. debt to affiliated trusts. (LT Interest earned: 3.4x} 3.6% 3.9% 22.4% 14.0% 4.2% 4.0% 5.2% 8.3% 8.8% 11.1% 11.0% 10.0% AFUDC %to Net Profit 8.0% 58.0% 53.7% 41.0% 48.1% 50.9% 51.6% 51.4% 50.8% 51.4% 51.0% 51.0% 53.0% Long-Tenn Debt Ratio 52.5% Pension Assets-12/14 $539.3 mill. 40.6% 46.3% 59.0% 51.9% 49.1% 48.4% 48.6% 49.2% 48.6% 49.0% 49.0% 47.0% Common Equity Ratio 47.5% Obllg. $634.7 mill. 1900.B 1980.1 1548.9 1919.5 2139.0 2325.3 2439.9 2561.2 2669.7 3027.3 3105 3335 Total Capital ($mill) 3700 Pfd Stock None 2126.4 2215.0 2351.3 2492.2 2607.0 2714.2 2860.8 3023.7 3202.4 3620.0 3860 4065 Net Plant ($mlll) 4625 Common Stock 62,344.484 shs. 4.8% 6.1% 5.2% 5.8% 5.5% 5.4% 5.5% 4.3% 5.4% 4.9% 5.0% 5.0% Return on Total Cap'I 5.5% as of1/31/15 5.9% 8.2% 4.2% 7.4% 8.3% 8.2% 8.5% 6.2% 8.6% 7.7% 8.0% 8.0% Return on Shr. Equity 9.0% 5.9% 8.0% 4.2% 7.4% 8.3% 8.2% 8.5% 6.2% 8.6% 7.7% 8.0% 8.0% Return on Com Equity E 9.0% MARKET CAP: $2.1 billion (Mid Cap} 2.4% 4.9% .8% 3.7% 4.1% 3.3% 3.1% .8% 2.9% 2.4% 2.5% 2.5% Retained to Com Eq 3.0% ELECTRIC OPERATING STATISTICS 60% 40% 82% 50% 51% 60% 64% 88% 66% 69% 67% 67% All Dlv'ds to Net Prof 64% 2012 2013 2014 BUSINESS: Avista Corporation (formerly The Washington Water 30%; Industrial, 11%; wholesale, 14%; other, 11%. Generating
%Change Reta! Sales (KWH) -1.8 +.4 +.8 Avg.lnduslUse(tl'M1i 1505 1428 1349 Power Company) supplies electricity & gas In eastern Washington sources: hydro, 32%; gas, 12%; coal, 11 %; wood waste, 2%; pur*
A1~.lnduslRevs.~ /It(¢) 5.69 5.74 5.93 & northern Idaho. Supplies electricity to part of Alaska & gas to part chased, 43%. Fuel costs: 46% of revs. '14 reported deprec. rate Capacity at Peak I hi} 3060 2767 2594 of Oregon. Customers: 386,000 electric, 330,000 gas. Acq'd Alaska Paik Load. hnual loadvkiter "'1r Factor(% 2485 2223 2223 Electric Light and Power 7/14. Sold Ecova energy-management 58.0 59.0 64.0 (Avista): 3.0%. Has 1,900 employees. Chairman, President & CEO: Scott L. Morris. Inc.: WA. Address: 1411 E. Mission Ave., Spokane,
%Change Cuslomera ~00) +.6 +1.1 +5.5 sub. 6/14. Electric rev. breakdown: residential, 34%; commercial, WA 99202-2600. Tel.: 509-489-0500. Web: www.avistacorp.com.
F~ed Charge Crl1. (%} 245 308 322 Avista has filed a general rate case in 2015. Rate relief and modest customer ANNUAL RATES Past Past Est'd '12*'14 Washington. The utility is seeking elec- growth should be positive factors. In addi-or change (per sh) 10Yrs. 5Yrs. to '18*'20 tric and gas rate hikes of $33.2 million tion, the company will have a full year's Revenues 1.5% -2.0% 3.0% (6.6%) and $12.0 million (7.0%), respec- contribution from Alaska Electric Light &
"Cash Flow" 5.5% 2.0% 5.5% tively, based on a 9.9% return on a 48% Power. Our earnings estimate is within Earnings 7.5% 6.5% 7.0%
Dividends 9.5% 11.5% 4.0% common-equity ratio. Avista is also hlan- Avista's targeted range bf $1.86-$2.06 a Book Value 4.0% 4.0% 3.5% ning to file a general rate case in Ida o on share. QUARTERLY REVENUES($ mill.) or after June 1, 2015. New tariffs in each We forecast further profit growth in Cal* Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year state should take effect in early 2016. 2016. We assume reason1:J:ble reguTatory 2012 452.3 343.6 340.6 410.5 1547.0 The Oregon commission approved a treatment in the pe!jding and upcoming 2013 482.9 352.0 335.9 447.7 1618.5 regulatory settlement. The regulators rate cases in Washington and Idaho, 2014 446.6 312.6 301.6 411.8 1472.6 had rejected the original agreement. The respectively. Our estimate of $2.05 a share 2015 490 335 325 425 1575 new agreement provided for a gas rate would produce a 5% earnings increase, at 2016 515 350 340 445 1650 boost of $5.0 million (4.9%), based on a the upper end of Avista's 4%-5% goal. Cal- EARNINGS PER SHARE A Full 9.5% return on a 51 % common-equity ra- The board of directors raised the divi-endar Mar.31 Jun.30 Sep.30 Dec.31 Year tio. New tariffs took effect on April 16th. dend in the first quarter. The board 2012 .65 .31 .10 .26 1.32 Frequent regulatory activity is neces- hiked the annual disbursement by $0.05 a 2013 .71 .43 .19 .53 1.85 sary for Avista. As costs increase, the share (3.9%). We project similar dividend 2014 .79 .43 .16 .48 1.84 utility feels the effects of regulatory lag. rowth over the 3- to 5"year period. 2015 .85 .45 .15 .50 1.95 That's why earned ROEs have generally vista's goal for dividend growth equals 2016 .90 .45 .15 .55 2.05 been unimpressive in recent years. Avista that for earnings growth . Cal* QUARTERLY DMDENDS PAID s
- Full also expects its rate base to climb by 5%- Avista stock has a dividend yield that endar Mar.31 Jun.30 Sen.30 Dec.31 Year 6% annually through 2017, which is an- is just slightly above the industry 2011 .275 .275 .275 other factor driving the need for rate average. Like many utility equities, it is
.275 1.10 2012 .29 .29 .29 .29 1.16 cases. Alaska Electric Light & Power, trading within our 2018-2020 Target Price 2013 .305 .305 .305 .305 1.22 which Avista acquired in mid-2014, will Range, and offers unspectacular total re-2014 .3175 .3175 .3175 .3175 1.27 probably file a rate application in 2016. turn potential over that time frame .
2015 .33 Earnings are likely to increase in Paul E. Debbas, CFA May 1, 2015 (A} Oil. EPS. Exel. nonrec. gain (losses}: '02, or chg. in shs. Next egs. due early May. orig. cost. Rate all'd on com. e~ In WA Jn '15: Comkany's Financial Strength A (9¢}; '03, (3~); '14, 9¢; gains (losses~ on disc. (B} Div'ds paid in mid-Mar., June, Sept. & Dec. none; Jn ID in '13: 9.8%; Jn O in '15: 9.5%; Sloe 's Price Stability 95 ops.: '01, $1.00); '02, 2¢; '03, ( 0¢); '14,
- Div'd reinv. plan avail. (C! Incl. defd chgs. In earn. on avg. com. e~, '14: 8.2%. Reg. Clim.: Price Growth Persistence 65
$1.17. '13 & '14 EPS don't add due to rounding '14: $9.70/sh. (D} In mill. E) Rate base: Net WA, Avg.; ID, Above vg. (F) Summer pk. '12. Earnings Predictability 70 o 2015 Value Line Publishin~ LLC. Nt n~ts reseived. Factual material Is obtained from sources befieved to be reliable and Is provided without warranties of any kind. I II :!Ill !1IU:ll THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thi:J'ublication Is stricUy for subscriber's own, non-commercial, Internal use. No ~art 111 ...i.i 11..~w*11 *'- or.1 lllll'li 11'11/! I1111::. of it may be reproduced, resold, stored or ~ansmitted In any printed, ete<:~onic or olher Imm, or us fm generating or malketing any printed or ele<:~onic pubicaUon, seivice or prooucL
Schedule AHG-5 15-WSEE-115-RTS ~C_M_$_E]~R~1~~B_P~~~-'L....,-REc_EN_r ~ 1 NYSE-CMS PRICE ~3-~8lP_/E , RATIO~11~ir_ramn-g:1_9.0)-4-R-ELAT-NE_Q_9~_,__Dlv-*o
, Median: 15.0 PIE RATIO , YLD _3_.6~01 /(0~ ~-------<
TIMELINESS 3 Lowered12IS/14 High: 10.6 16.8 17.0 19.5 17.5 16.1 19.3 22.4 25.0 30.0 36.9 38.7 Target Price Range RaisedJll1/l >-"t=~~~~~N~D-S~7~.8~~9~.7~--;12.1 15.0 8.3 10.0 14.1 17.0 21.1 24.6 26.0 32.9 2018 2019 2020 SAFETY 2 4 TECHNICAL 3 Ral'sed Jl20llS - dividedx Dividends 0.80 r by lnleres Rate sh >----+---' cc+-+---f-----1--+---+--+---+--1!--+---!---+-64
* * *
- Relalive Price S~ength "--+--l--+---+--+---+--j---J---1---+--+48
,_B_E_rA_.1_s_11_.o_o_=M-a~rt=et)=~__, o~~~~~~".:'r~a indicates recession I--+---- ==t==:t=j2/:::'.::'JS;:;;;!;~-~-;-Jl!;r-;::=--s-t==t==t:::=t::14302 2018*20 PROJECTIONS 11_,11_,1-t_11'_'1_11 _'+---+----+--!-*-*_*_**-t--*-*._._.-t-Ann'! Total -+---+...,,,/-r-,,.,..,,.'t'f-- 24 Price Gain Return 1- - - i - - - + - - + - - - + - - ---+---;;,, ~.~._,,"""crtt"r'"-'1'_-t----t---t---1---+---t----lr--+20 High 40 (+20%1 9% 11"11 --:n....itL---~--l--'---+--1!--+---+--+---+--+--+--+ 1 16 Low .1111 i,, '111,1"' Insider30 Decisions(*10% 2% 1 ..-J+-_1"-+--+--+----1--+---!---+---+--1!--+12 1 A M J J A S 0 N D 1 11j,1if'1I loBuy O 0 0 0 0 0 0 0 0 11-*_,.m--.-i 1 1flf-"-~--+--+---+--- ---+----+--+----+-------!----+---+---+---t----<f----t-8 OpUons o O O O o o O o O 11 11 -6 toSell 1 O O O 4 o 1 O O ll--l~Jf-'-'-----t----+-- ...-.+---+--
%TOT. RETURN 2/15 lnstltutlonal Decisions 202 014 3Ql01 4 4020 11 Percent
,I 30 "
-:-&* ******..* ** *. ******f*** ...-**.......................***. THIS STOCK Vl ARITH.'
l/lDEX .... 197 shares ~'"ltrllot'trr'-tt-...---TI-ttr.r-h-,-,--,t--+.----+----l 1 yr. 0 to Buy 177 174 27.8 8.2 _ m:.::~oo 234m 237J~g 237m traded 10 20 11111111 ,,, 11 '-' " 1111111 , 11 ; 111i 11111111111 11111111111111111111111111111
- tl!l!Mt!l-l-ll1W)lUl)l 3 yr.
6 yr. 83.3 179.6 60.8 _ 110.1 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 VALUELINEPUB.LLC 8-20 52,59 74.24 72.16 60.28 34.21 28.06 28.52 30.57 28.95 30.13 27.23 25.77 25.59 23.90 24.68 26.09 25.65 26.00 Revenues per sh 28.50 7.87 7.61 5.24 d.09 2.39 2.87 3.43 3.22 3.08 3.88 3.47 3.70 3.65 3.82 4.06 4.22 4.40 4.65 "Cash Flow" per sh 5.50 2.85 2.53 1.27 d2.99 d,29 .74 1.10 .64 .64 1.23 ,93 1.33 1.45 1.53 1.66 1.74 1.88 2.00 Earnings per sh A 2.25 1.39 1.46 1.46 1.09 -- -- -- ** .20 .36 .50 .66 .84 .96 1.02 1.08 1.16 1.24 Dlv'dDecl'dpersh 8
- 1.50 9.69 8.51 9.49 5.18 3.32 2.69 2.69 3.01 5.61 3.50 3.59 3.29 3.47 4,65 4.98 5.73 5.75 5.60 Cap'I Spending per sh 5.50 21.17 19.48 14.21 7.86 9.84 10.63 10.53 10.03 9.46 10.88 11.42 11.19 11.92 12.09 12.98 13.34 14.15 15.05 BookValuepersh c 17.75 116.04 121.20 132.99 144.10 161.13 195.00 220.50 222.78 225.15 226.41 227.89 249.60 254.10 264.10 266.10 275.20 277.00 279.00 Common Shs Outst'g 0 285.00 13.9 9.6 20.8 ** -- 12.4 12.6 22.2 26.8 10.9 13.6 12.5 13.6 15.1 16.3 17.3 Boldtig resar* AvgAnn'IP/ERatlo 15.0
.79 .62 1.07 *- *- .66 .67 1.20 1.42 .66 ,91 .80 ,85 ,96 .92 .92 Vatue Line Relative PIE Rallo .95 3.5% 6.0% 5.5% 7.5% -* -- -- ** 1.2% 2.7% 4.0% 4.0% 4.3% 4.2% 3.8% 3.6% estinates AvgAnn'IDiv'dYleld 4.5%
CAPITAL STRUCTURE as of 12/31/14 6288.0 6810.0 6519.0 6821.0 6205.0 6432.0 6503.0 6312.0 6566.0 7179.0 7100 7250 Revenues ($mill) 8100 Total Debt $8739 mill. Due In 5 Yrs $4047 mill. 247.0 158.0 168.0 300.0 231.0 356.0 384.0 413.0 454.0 479.0 530 570 Net Profit ($mllll 690 LTDebt$8139mlll. LT1nterest$371 mill. 25.6% .. 37.6% 31.6% 34.6% 38.1% 36.8% 39.4% 39.9% 34.3% 39.5% 39.5% Income Tax Rate 39.5%
~~~*l~t~~;s~~~;':cl~aJ'.~~~ leases. 15.4% 6.3% 3.6% 1.3% 13.0% 2.2% 2.6% 2.9% 2.0% 2.3% 2.0% 2.0% AFUDC %to Ile! Profit 1.0%
Leases, Uncapitalized Annual rentals $25 mill. 73.5% 71.7% 70.5% 69.4% 67.9% 70.1% 66.9% 67.9% 67.5% 68.7% 68.0% 67.0% Long-Term Debt Ratio 65.5% Pension Assets-12/14 $1979 mill. 23.4% 24.9% 25,9% 27.4% 29.0% 29.5% 32.6% 31.6% 32.2% 31.0% 32,0% 32.5% Common Equity Ratio 34.5% Oblig, $2547 mill. 9913.0 8961.0 8212.0 8993.0 8977.0 9473.0 9279,0 10101 10730 11846 12300 12825 Tola! Capital ($mill) 14800 Pfd Stock $37 mill. Pfd Dlv'd $2 mill. 7845 O 7976 O 8728 O 9190 O 9682 O 10069 10633 11551 12246 13412 14325 15150 Net Plant ($mllll 17400 Incl. 373, 148 shs. $4.50 $100 par, cum., callable at 1--=-=*,,____----:--::'.*~----,--,""*,-+-----=-:,,-'-t-7=.,--+----=-:~-=-~+----,c=c,,__~~-:-:=-t-----:,-,.,.,-t-'77.,.--t,---,------';;:-,-,'-::,-,,-t-----:,---,-;;--;-l
$110.00. 5.0% 4.5% 4.5% 5.4% 4.7% 5.8% 6.3% 5.9% 6.0% 5.7% 6.0% 6.0% Return on Total Cap'I 6.0%
Common Stock 275,200,000 shs. 9.4% 6.2% 6.9% 10.9% 8.0% 12.5% 12.5% 12.8% 13.0% 12.9% 13.5% 13.5% Return on Shr. Eqully 13.5% 9.9% 6.4% 7.2% 11.7% 8.5% 12.5% 12.6% 12.9% 13.1% 13.0% 13.5% 13.5% Return on Com Equity E 13.5% MARKET CAP: $9.1 billion (Large Cap) 9.9% 6.4% 5.1% 8.4% 4.1% 6.9% 5.6% 5.0% 5.2% 5.0% 5.5% 5.5% Retained lo Com Eq 5.0% ELECTRIC OPERATING STATISTICS 6% 10% 35% 31% 54% 46% 55% 61% 60% 62% 61% 61% AllDlv'dstoNetProf 62% 2012 2013 ~~1.~ 1--B-U-Sl_N,_ES_S_:-C-M~S-E-n-er~g-y-C-or-po_._ra_ll_on-ls~a-ho-ld-ln,_g_c_om-p-'a~ny-fo-r--+---7°-Yo-._G... en-e-ra-tln-g~s-o-ur-ce_s,_:-co_a_I,-4~4*..,Yo-;-ga_s_,-6°-Yo;_o_th_e_r,-1...%,---;-p-ur- %Change Relai Sales !KWH} +.6 -3.1 A1~. lndust Use IMVJHl 1113 1000 NA Consumers Energy, which supplies electricity and gas to lower chased, 49%. Fuel costs: 54% of revenues. '14 reported deprec. A1~. lndusl Revs. per KWH(¢) 8.06 8.93 8.79 Michigan (excluding Detroit). Has 1.8 million electrtc, 1.7 million gas rates: 3.5% electrtc, 2.8% gas, 7.7% other. Has 7,700 employees. CaP1clYatPe<k(f.lwl 8607 8603 NA customers. Has 1,034 megawatts of nonregulated generating cape- Chairman: David W. Joos. President & CEO: John G. Russell. In-Peak Load, Summer !Mv1) 9006 8509 ~~ city. Sold Palisades nuclear plant in '07. Eiectrtc revenue break* corporated: Michigan. Address: One Energy Plaza, Jackson, Michi-Annual Load Factor(~) 48.7 52.5
%Change Cust0111ers jyr-end) -- +.1 down: residenlial, 43%; commercial, 31%; Industrial, 19%; other, gan 49201. Tel.: 517-788-0550. Internet: www.cmsenergy.com.
F~ed Charge C-Ov. (%) 268 282 278 CMS Energy's utility subsidiary has narrow range of $1.86-$1.89 a share. CMS' ANNUAL RATES Past Past Est'd '12-'14 received a gas rate increase. Con- goal is for annual earnings growth of 5%- of change (per sh) 10 Yrs. 5Yrs. to '18"20 sumers Energy had filed for a tariff hike of 7%, and our 2016 forecast of $2.00 a share Revenues -5.0% -3.0% 2.5% $88 million, based on a return on equity of would produce an increase within this "Cash Flow" g,0% 3.0% 5.5% 10.7%. The utility reached a settlement range. Earnings * - 12.0% 5.5% calling for a $45 million raise, based on a The boai*d of directors raised the divi-Dividends * - 23.5% 6.5% Book Value 3.0% 4.0% 5.5% 10.3% ROE. The Michigan Public Service dend in the first quarter. The board Cai- QUARTERLY REVENUES($ mill.) Full Commission (MPSC) approved the settle- boosted the quarterly payout by $0.02 a endar Mar.31 Jun.30 Sep.30 Dec.31 Year ment in late January. share (7.4%). We project continued good 2012 1802 1333 1507 1670 6312.0 An electric rate case is pending. Con- dividend growth through the 2018-2020 2013 1979 1406 1445 1736 6566.0 sumern Energy is seeking an increase of period. CMS Energy is targeting a payout 2014 2523 1468 1430 1758 7179.0 $163 million, based on a 10.7% ROE. Un- ratio of 60%-70%. 2015 2300 1500 1500 1800 7100 der Michigan regulatory law, the utility Finances are adequate. Consistent 2016 2300 1550 1550 1850 7250 will self-implement a rate hike in mid* earnings growth is a plus. The company's Cal- EARNINGS PER SHARE A Full 2015, and the MPSC's final order is due in cash flow is stronger than our "cash flow" endar Mar.31 Jun.30 Sep.30 Dec.31 Year late 2015. This will enable Consumers En- figures (which do not include deferred 2012 .36 .37 .55 .25 1.53 ergy to place a 540-megawatt gas-fired taxes) suggest. On the other hand, the 2013 .53 .29 .46 .37 1.66 generating plant, which it has agreed to common-equity ratio is subpar due to debt 2014 .75 .30 .34 .35 1.74 purchase for $155 million, in the rate base. that is held at the parent level, and the 2015 .68 .40 .45 .35 1.88 The transaction is scheduled to close in fixed-charge coverage is a bit below the in-2016 .60 .45 .55 .40 2.00 late 2015. dustry norm, CMS Energy merits a Finan-Cal* QUARTERLY DIVIDENDS PAID 8
- Full We expect CMS Energy to continue to cial Strength rating of B++.
endar Mar.31 Jun.30 Sea,30 Dec. 31 Year produce steady earnings growth in CMS Energy's strengths are adequate-2015 and 2016. The company should be* ly reflected in the stock's quotation. 2011 .21 .21 .21 .21 .84 nefit from rate relief, reductions in operat- This issue does not stand out among utili-2012 .24 .24 .24 ,24 ,96 2013 .255 .255 .255 .255 1.02 ing and maintenance expenses, and mod- ties for its dividend yield. Its 3- to 5-year 2014 .27 .27 .27 .27 1.08 erate volume grnwth. Our 2015 profit esti- total return potential is unspectacular. 2015 .29 mate is within management's typically Paul E. Debbas, CFA March 20, 2015
!Al Diluled EPS. Exel. nonrec. gains (losses): '10, (8¢); '11, 1¢; '12, 3¢. '13 EPS don't add (C) Incl. lntang. In '14: $7.11/sh. ID) Jn mill. (E) Company's Financial Strength B++
05, ($1.61); '06, ~$1.08); '07, ($1.26); '09, (7¢); due to rounding. Next earnings report due late Rate base: Net ortg. cost. Rate allowed on Stock's Price Stability 100
'10, 3¢; '11, 12¢; 12, (14¢): gains (losses) on Apr. (B) Div'ds historically paid late Feb., May, ccm. eq. in '15: 10.3%; earned on avg. com. Price Growth Persistence 90 disc. ops.: '05, 7¢; '06, 3¢; '07, (40¢); '09, 8¢; Aug., & Nov.* Div'd reinvestment plan avail. eq., '14: 13.4%. Regulatory Climate: Average. Earnings Predictability 75 " 2015 Value Line Publishing llC. All righls reserved. Factual malerial Is obtained from sources believed lo be reliable and Is provided without warranlies of any kind. , * ,-
THE PU BUSHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publlcalion is stf!Gtly for subscriber's own, non-commercial, Internal use. No ~art 111-.~ 111>.," 111 '--..,I IIi! ~iif lll'll/11111 ~I h\191 of it may be reproduced, resold, stored or ~ansmilled in any printed, elec~onlc or olher form, or used for genernling or marteUng any prinled or electronic pub[calion, service or prooucL - ,, - '-'
Schedule AHG-5 15-WSEE-115-RTS i--C_Q_N_.E---,,D_l_SQ_N_N_Y..-SE_-Eo-r----.-~_._/~~~~e-eNT~6_1_.1_3..._ /~~_r10_1_5._3(_lie_a~1~n_il~_:O-l-~fu_L~_7ia_0_.8~1..._~~~~_4_.3~%JB_--. 1 9 0 TIMELINESS 3 Raised 511115 High: 45.6 49.3 49.3 52.9 49.3 46.3 51.0 62.7 66.0 64.0 68.9 72.3 Target Price Range i-=L"'-ow"':'-'--'3""7_,,.2'-'--_4'"'1~.1_,__,41.2 43.1 34.1 32.6 41.5 48.6 53.6 54.2 52.2 58.7 2018 2019 2020 SAFETY 1 New 7127190 TECHNICAL 4 Lowered5122115 - LEGENDS x ~vi1~,~~~r~~te r---r---;t, =T=T.>""-t----t---t---t---+--t----t----1--+---+--+-1~~ BETA .60 (1.00 =Market) Op;';ns* es ~rice Sttenglh ;\ii*
... . ~ . . . . .____ -... * -, 80 Shaded area indicates recession 1---+--- "
1
' * **-- * **** 64
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1 1 11 2018*20 PROJECTIONS ..* +-"-*-+----+--!-*-*_-_-*+*-**-*-*+ 4o Price Gain An~~t~~~al 111,11111*11 1*1,,,,.*" ,,,* '*1". ~ i .ff(\1*'' ***111*
~~w &g (trn~l ~~
Insider Decisions '*,
*. *J: ~!
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- 12
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Institutional Decisions +-c-.\-;-j-r---.r-----t--+-~*...,*.r..,.,..;:-:,.-::',,'~'M*..-,--+---t THIS VlARITH.' 202014 3Q2014 402014 Percent 21 +--+--+--t.+--:ft.'411'i"li+----l--+--+.-+--l---h-++,...--+---I STOCK INDEX - lo Buy 306 291 321 shares 14 - II 1.. I 11 1yr. 10.7 9.1 toSell 262 252 265 1 d d 7 1 .1, lo 11.1111 t. t I 11,1111 1111111,11 lt1 3yr. 17.5 58.8 Hl~s{OOO) 144306 146934 152674 ra e llllllllll lilllllll 1111111111 1111111111 1111111111 Ill 5 yr. 59.6 84.6 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 VALUELINEPUB.LLC 8-20 35.04 44.48 45.41 39.65 43.51 40.24 47.66 47.14 48.23 49.62 46.36 45.69 44.17 41.62 42.27 44.11 44.70 46.10 Revenues per sh 50.25 5.74 5.51 5.70 5.44 5.12 4.54 5.27 5.28 5.77 5.99 5.86 6.24 6.61 7. 15 7.45 7.30 8.05 8.40 "Cash Flow per sh 9.75 3.13 2.74 3.21 3.13 2.83 2.32 2.99 2,95 3.48 3.36 3.14 3.47 3.57 3.86 3.93 3.62 4.00 4.10 Earnings per sh A 4.50 2.14 2.18 2.20 2.22 2.24 2.26 2.28 2.30 2.32 2.34 2.36 2.38 2.40 2.42 2.46 2.52 2.60 2.68 Dlv'd Decl'd per sh e
- 2.90 3.17 4.52 5.20 5.68 5.72 5.60 6.59 7.17 7.09 8.50 7.80 6.96 6.72 7.06 8.67 8.26 9.95 10.95 Cap'i Spenalng per sh 10.50 25.31 25.81 26.71 27.68 28.44 29.09 29.80 31.09 32.58 35.43 36.46 37.93 39.05 40.53 41.81 42.94 44.35 45.80 Book Value per sh c 50.75 213.81 212.03 212.15 213.93 225.84 242.51 245.29 257.46 272.02 273.72 281.12 291.62 292.89 292.87 292.87 292.88 293.00 293.00 Common Shs Outst'g o 293.00 14.0 12.0 12.0 13.3 14.3 18.2 15.1 15.5 13.8 12.3 12.5 13.3 15.1 15,4 14.7 15.9 Bald fig res are Avg Ann'I P/E Ratio 14.0
.80 .78 .61 .73 .82 .96 .80 .84 .73 .74 .83 .85 .95 .98 .83 .84 Value Line Relative P/E Rallo .90 4.9% 6.6% 5.7% 5.3% 5.5% 5.3% 5.0% 5.0% 4.8% 5.7% 6.0% 5.2% 4.5% 4.1% 4.3% 4.4% estln ates Avg Ann'! Dlv'd Yield 4.6%
CAPITAL STRUCTURE as of 12/31114 11690 12137 13120 13583 13032
- 13325 12938 12188 12381 12919 13100 13500 Revenues ($mlll) 14750 Total Debt $12991 mill. Due In 5 Yrs $3897 mlll. 719.0 749.0 936.0 933.0 868.0 992.0 1062.0 1141.0 1157.0 1066.0 1180 1215 Net Profit ($mill) 1355 LT Debt $11631 mill. LT Interest $559 mill. 33.6% 35.2% 32.6% 36.0% 34.2% 36.0% 36.1% 34.5% 31.8% 34.0% 34.0% 34.0% Income Tax Rale 34.0%
(LT interest earned: 3.8x) 2.2% 1.6% 1.9% 1.7% 2.6% 2.4% 1.6% .5% .5% .3% 1.0% NII AFUDC %lo Nel Prom NII Leases, Uncapitalized Annual rentals $18 mill. 49.6% 50.2% 45.6% 48.3% 48.5% 48,6% 46.5% 45.9% 46.1% 48.0% 48.5% 49.5% Long-Term Debt Ratio 48.5% 49.0% 48.5% 53.1% 50.6% 50.4% 50.4% 52.5% 54.1% 53,9% 52.0% 51.5% SD.5% Common Eaulty Rallo 51.5% Pension Assets-12/14 $11495 mlll. 14921 16515 16687 19160 20330 21952 21794 21933 22735 24207 25150 26550 Total Capital ($mill) 28700 Obllg, $15081 mill. 17112 18445 19914 20874 22464 23863 25093 26939 28436 29827 31575 33525 Net Plant !$mill) 38700 Pfd Stock None 6.3%. 6.0% 7.0% 6.2% 5.7% 5.9% 6.2% 6.5% 6.4% 5.6% 6.0% 5.5% Return on Total Cap'I 6.0% Common Stock 292,888,812 shs. 9.6% 9.1% 10.3% 9.4% 8.3% 8.8% 9.1% 9.6% 9.4% 8.5% 9.0% 9.0% Relurn on Shr. Eqully 9.0% as of 1/30/15 9.7% 9.2% 10.4% 9.5% 8.4% 8.9% 9.2% 9.6% 9.4% 8.5% 9.0% 9.0% Return on Com Eaultv E 9.0% MARKET CAP: $18 billion (Large Cap) 2.6% 2.6% 3.9% 3.1% 2.5% 3.2% 3.1% 3.6% 3.6% 2.6% 3.0% 3.0% Retained lo Com Eq 3.5% ELECTRIC OPERATING STATISTICS 74% 73% 63% 67% 71% 65% 66% 62% 62% 69% 65% 65% All Dlv'ds to Net Prof 63%
%ChangeRe~ilSales(Kl'IH} 2~B 2 ~:~ 2~:11--B-US-l-NE._S_S_:_C_,on-s-ol-id-at...Led-Ed-is_o....
n,-l-nc-.-ls.L..a-ho-ld-ln._g_co_m_p_,a-ny-fo_r_.__er-s.-P-u_,_rs-ue_s_c_omi...p_e_tlt_lve-'-en-e-rg_y_,op_p_ort_u_n_llle_s_th_ro_u_g_h-th-re_,_e_w-ho-lly--l A1y. lndusl Use ~II/IHI NA NA NA Consolidated Edison Company of New York, Inc. {CECONY), which owned subsldlartes. Purchases most of ils power. Fuel costs: 35% A1g. loousl Revs. per Kl'lll (¢) NA NA NA sells electricity, gas, and steam In most of New York City and of revenues. '14 reported depreciation rates: 2.9%-3.1 %. Has Ca~alPeak(l.tw~ NMF NMF ~ ~~ Weslchester County. Also owns Orange and Rockland UUlities 14,600 employees. Chairman, President & CEO: John McAvoy,
~~~f~~:~l~l 11 1 t1J~ 1 t~~ 1 NMF 5 (O&R, acquired 7/99), which operates In New York, New Jersey, Inc.: New York. Address: 4 Irving Place, New York, New York %Chall'Je Customers (yr-end) NA NA NA f--an_d_P_e_nn_s'-ylv_a_nl_a._H_a_s_3._6_m_lll_io_n_el_ec_lri_*c_,1_.2_m_illi_on_g::...a_s_cu_s_to_m-__10_0_03_._Te_I._:2_1_2-4_60_-4_6_00_._ln_te_rn_e_t:_1wrw_._co_ne_d_ls_on_.c_o_m_.----l medChatgeCov.1%1 382 385 366 Consolidated Edison's largest utility cause colder-than-normal winter weather t-A_N_N_U~A~L-RA~T~E-S-P-as-t--P-as_t_E-st-'d-,--
12 .* - 14-J subsidiary has reached a settlement helped ConEd's steam business. (The elec-tric and gas operations have regulatory ofchange(persh) 10Yrs. 5Yrs. to'18-'20 with the staff of the New York State Revenues .5% -2.5% 3.0% Public Service Commission (NYSPSC) mechanisms that decouple revenues and "Cash Flow" 4.0% 4.5% 5.0% and some intervenors. Consolidated volume.) The company revised its earnings Earnings 3.5% 2.5% 3.0% E C N guidance from $3.80-$4.00 a share to Dividends 1.0% 1.0% 2.5% dison ompany of ew York reached an Book Value 4.0% 3.5% 3.5% agreement that would not raise base elec- $3.90-$4.05, and our estimate of $4.00 is 1----.-...,.,.,.--,..,-----,--,...-,----J tric rates next year, but would benefit its within this range. Cal* QUARTERLY REVENUES($ mlll.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year earnings by allowing the utility to retain We forecast a modest bottom-line in-2012 3078 2771 3438 2901 12188 $123 million of regulatory amortization in crease in 2016. We assume that the 2013 3306 2767 3440 2868 12381 2016. The agreement calls for an allowed aforementioned regulatory settlement is 2014 3789 2911 3390 2829 12919 ROE of 9.0% and a common-equity ratio of approved, and that O&R gets a reasonable 2015 3616 2984 3500 3000 13100 48%. The NYSPSC must still issue a deci- order in its pending rate case. 2016 3750 3050 3600 3100 13500 sion on the settlement. The company faces uncertainty about Cal* EARNINGS PER SHARE A Full Orange and Rockland Utilities is seek- a pipeline explosion in New York in endar Mar.31 Jun.30 Sep.30 Dec.31 Year ing electric and gas rate increases. March of 2014. The accident killed eight 2012 .94 .73 1.49 .70 3.86 O&R wants electric and gas tariff hikes of people and injured dozens more. The Na-2013 1.16 .49 1.49 .79 3.93 $34.0 million and $44.2 million, respec- tional Transportation Safety Board and 2014 1.23 .63 1.49 .28 3.62 tively, based on a 9.75% return on a 48% the NYSPSC are conducting investiga-2015 1.26 .65 1.50 .59 4.00 common-equity ratio. However, the tions. ConEd is facing some litigation, but 2016 1.20 .70 1.55 .65 4.10 NYSPSC's staff is recommending an elec- believes its insurance is sufficient to cover Cal* QUARTERLY DIVIDENDS PAID e
- Full tric decrease of $0.2 million and a gas this, and has not yet taken a reserve.
endar Mar.31 Jun.30 Sen.30 Dec.31 Year raise of $14.7 million, based on an 8.5% This high-quality stock offers a re-2011 .60 .60 .60 .60 2.40 ROE. New rates should go into place on spectable dividend yield. The yield is 2012 .605 .605 .605 ,605 2.42 November 1st. above the utility average. Total return 2013 .615 .615 .615 .615 2.46 We have raised our 2015 earnings esti- potential to 2018-2020 is average for a 2014 .63 .63 .63 .63 2.52 mate by a nickel a share. First-quarter utility. 2015 .65 profits were greater than we expected be- Paul E. Debbas, CFA May22, 2015 (A) Diluted EPS. Exel. nonrec, gain (losses): Aug. (B) Dlv'ds historically paid in mid*Mar., all'd on com. eq. for CECONY In '14: 9.2% Company's Financial Strength A+ '02, 111¢); '03, 145¢); '13, (32¢); '14, 9¢; gain June, Sept., and Dec.
- Div'd reinvestment elec., 9.3% ~as & steam; O&R in '12 (elec.) Stock's Price Stability 100 on disc. ops.: '08, $1.01. 14 EPS don't add plan avail. (C) Incl. intang. In '14: $33.50/sh. 9.4%, In '09 gas) 10.3%; earned on avg. com. Price Growth Persistence 50 due to rounding. Next earnings report due early (D) In mill. (E) Rate base: net orig. cost. Rate eq., '14: 8.6'0. Regulatory Climate: Below Avg. Earnings Predictability 85
" 2015 Value Une Publishing LLC. All rights reseived. Factual material Is obtained lrom sources believed to be reliable and Is provided whhout warranlles of any kind. THE PUBLISHER IS NOT RESPONSIBLEFORANY ERRORS OR OMISSIONS llEREIN. This publication Is stricUy for subscriber's own, non.commercial, Internal use. No P.art 111a.~111~' ""' '.__~,ll*a:U!l!il/!Ult:ll llll:ml ol hmay be reproduced, resold, stored or transmilled in any printed, electronic or olher form, or used for generating or marketing any printed or electronic publication, service or prooucl
Schedule AHG-5 15-WSEE-115-RTS DOMINION RES. NYSE-D IRECENT PRICE 71 ,09 IP/ERATIO 20 ,0 ea111ng:24.3) Median: 18.0 RELATIVE PIE RATIO 106 DIV'YLDD 3.8%M& I TIMELINESS 2 Raised 3127/15 High: 34.4 43.5 42.2 49.4 48.5 39.8 45.1 53.6 55.6 68.0 80.9 79.9 Target Price Range Low: 30.4 33.3 34.4 39.8 31.3 27.1 36.1 42.1 48.9 51.9 63.1 68.3 2018 2019 2020 SAFETY 2 Raised 9111198 - LEGENDS 0.81 x Dividends f sh 120 It::!!' TECHNICAL 4 Loweied 5122/15 divided bJiJnteres Rate
* ..
- Relative "ce SUength
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.......... .... -. - 100 BETA .70 (1.00 =Markel) 2-for-1 SRlit 11/07
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- 111 11 1 ' ~ I 11 ct .......... . .... .. .. 60 64 2018*20 PROJECTIONS O~~~~~~~~a indicates recession V. .. ,, ., ** 1111111 1**'" 40 Ann'I Total n*1111i1 ,1*111 1" 111111 Price Gain Return ,.,, *** 11.1.1111**1111 ,,11 High 95 (+35°4 11% 1111 , ** 32 Low 70 (NII 4% ~ t~\/;~ 24 I:/*:. "':*:.*!
Insider Decisions 20 t :;.::.{::*. ~, -'< ~h~ JJASON D J F **
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iii."'*' I 1 yr. 3yr. 2.3 53.7 5yr. 108.7 9.1 58.8 84.6 1999 2000 2001 2002 2003 2004 2005 2006 2007 2006 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 14.81 18.84 19.94 16.58 18.57 20.54 25.96 23.61 27.17 27.93 25.24 26.17 25.24 22.73 22.56 21.25 20.65 20.40 Revenues per sh 21.50 3.68 3.71 3.92 4.45 3.97 4.18 3.70 4.91 5.08 5.07 4.82 5.11 5.04 5.24 5.47 5.71 6.35 6.65 "Cash Flow" per sh 8.50 1.50 1.25 1.49 2.41 1.96 2.13 1.50 2.40 2.13 3.04 2.64 2.89 2.76 2.75 3.09 3.05 3.55 3.75 Earnings per sh A 4.75 1.29 1.29 1.29 1.29 1.29 1.30 1.34 1.38 1.46 1.58 1.75 1.83 1.97 2.11 2.25 2.40 2.59 2.80 Dlv'd Decl'd per sh e
- 3.50 2.16 2.82 2.31 2.17 5.20 3.88 4.83 5.81 6.89 6,09 6.40 5.89 6.41 7.20 7.06 9.13 9.80 9.10 Cap' ISpending per sh 7.25 12.75 14.22 15.81 16.57 16.20 16.79 14.96 18.50 16.31 17.28 18.66 20.66 20.09 18.34 20.02 19.74 21.70 24.15 Book Value per sh c 28.00 372.64 491.60 529.40 616.20 650.40 680.40 695.00 698.00 576.80 583.20 599.40 580.80 569.70 576.10 581.50 585.30 596.00 618.00 Common Shs Outst'g o 630.00 14.5 19.4 20.9 12.0 15.2 15.1 24.9 16.0 20.6 13.8 12.7 14.3 17.3 18.9 19.2 23.0 Bold fig res are Avg Ann'I P/E Ratio 17.5
.83 1.26 1.07 ,66 .87 .80 1.33 .86 1.09 .83 .85 .91 1.09 1.20 1.08 1.22 Value Line Relative PIE Ratio 1.10 es tin ates 5.9% 5.3% 4.1% 4.4% 4.3% 4.0% 3.6% 3.6% 3.3% 3.8% 5.2% 4.4% 4.1% 4.1% 3.8% 3.4% Avg Ann'I Dlv'd Yield 4.2%
CAPITAL STRUCTURE as of 12/31/14 18041 16482 15674 16290 15131 15197 14379 13093 13120 12436 12300 12600 Revenues ($mill) 13500 Total Debt $25955 mill. Due In 5 Yrs $10806 mill. 1050.0 1704.0 1414.0 1781.0 1585.0 1724.0 1603.0 1594.0 1806.0 1793.0 2120 2305 Net Prom ($mill) 3100 LT Debt $21805 mill. LT Interest $892 mill. 35.7% 35.5% 33.4% 37.1% 33.2% 38.6% 34.6% 36.2% 33.0% 28.1% 34.0% 32.5% Income Tax Rate 31.0% (LT Interest earned: 3.9x) 9.7% 7.9% 7.3% 4.9% 4.8% 5.9% 5.3% 5.7% 3.7% 4.5% 7.0% 6.0% AFUDC %to Net Profll 4.0% Leases, Uncapitalized Annual rentals $63 mill. 57.9% 52.9% 57.8% 59.1% 57.5% 56.3% 59,8% 60.9% 61.9% 65.4% 63.5% 61.0% Long*Tenn Debt Ratio 58.5% 41.1% 46.2% 41.1% 39.8% 41.5% 42.8% 39,3% 38.2% 37.3% 34.6% 36.5% 39.0% Common Equity Ratio 41.5% Pensron Assets-12/14 $6480 mill. 25307 27961 22898 25290 26923 28012 29097 27676 31229 33360 35275 38475 Total Capital ($mill) 42400 Obllg. $6667 mill 28940 29382 21352 23274 25592 26713 29670 30773 32628 36270 40425 44250 Net Plant 1$mlll\ 51700 Pfd Stock None 6.1% 7.9% 8.0% 8.7% 7.5% 7.7% 7.0% 7.5% 7.3% 6.6% 7.5% 7.0% Return on Total Cap'I 8.5% Common Stock 588, 138,107 shs. 9.9% 12.9% 14.6% 17.2% 13.9% 14.1% 13.7% 14.7% 15.2% 15.5% 16.5% 15.5% Return on Shr. Equity 17.5% as of 1/31/15 9.9% 13.1% 14.9% 17.5% 14.0% 14.2% 13.9% 14.9% 15.4% 15.4% 16.5% 15.5% Return on Com EQuity E 17.5% MARKET CAP: $42 billion (Large Cap) 1.1% 5.6% 5.0% 8.4% 4.7% 5.3% 4.0% 3.5% 4.2% 3.3% 4.5% 4.0% Retained to Com Eq 5.0% ELECTRIC OPERATING STATISTICS 89% 58% 67% 52% 67% 63% 71% 77% 73% 79% 72% 74% All Dlv'ds to Net Prof 72% 2012 2013 2014 BUSINESS: Dominion Resources, Inc. Is a holding company for dentlal, 45%; commercial, 32%; Industrial, 7%; other, 16%. Genera-
%Ch~eRelailSales(K'lill] -2.3 +2.7 +1.6 Ai~. I usl Use ~!'Ml~ 15241 14444 13847 Virginia Power & North Carolina Power, which serve 2.5 mill. cus- ting sources: nuclear, 33%; coal, 30%; gas, 15%; other, 3%; purch.,
Al~. lndusl RM~ l1i (¢) 6.13 6.00 6.12 tamers in Virginia & northeastern North Carolina. Acq'd Consolidat* 19%. Fuel costs: 41% of revs. '14 reported depr. rates: 2.3%-3.6%.
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NA NA NA ed Natural Gas (1.3 mill. customers In Ohio & West Virginia) 1/00. Has 14,400 employees. Chairman, Pres. & CEO: Thomas F. Farrell NA NA NA Nonulilily operations Include Independent power production. Owns II. Inc.: VA. Address: 120 Tredegar St., P.O. Box 26532, Richmond, NA NA NA
'tlnd) +,9 +.9 +1.0 70.9% of Dominion Midstream Partners. Elec, rev, breakdown: resl- VA 23261-6532. Tel.: 804-819-2000. Internal: www.dom.com.
F~ed Charge Cn/, (%) 316 339 266 Dominion Resources' utility subsidia- well above the company's target of 5%-6% ANNUAL RATES Past Past Est'd '12-'14 ry has a lot of significant projects un- annually because the comparison is eash or change (per sh) 10Yrs. 5Yrs. to '18-'20 der way. Virginia Power is building a due to some unusual charges in the fourt Revenues 2.0% -3.5% -.5% 1,358-megawatt gas-fired plant that quarter of 2014. (Note that Dominion usu-
"Cash Flow" 2.5% 2.0% 7.5% should commence commercial operation in ally has some charges, including an $0.08-Earnings 3.0% 2.5% 8.0%
Dividends 5.5% 7.0% 7.5% mid-2016 at a cost of $1.2 billion. The util- a-share write-off of deferred fuel costs in Book Value 1.5% 2.0% 6.5% ity recovers the cost of most of its capital the first period of 2015, that we include in QUARTERLY REVENUES ($mill.) spending through a surcharge on custom- our earnings presentation.) The aforemen-Cal* Full ers' bills. This means it doesn't have to file tloned factors are the reason for our profit endar Mar.31 Jun.30 Sep.30 Dec,31 Year 2012 3462 3053 3411 3167 13093 a general rate case. Virginia Power plans expectation. 2013 3523 2980 3432 3185 13120 to ask the state commission soon for a cer- Dominion Midstream Partners should 2014 3630 2813 3050 2943 12436 tificate of need to build a 1,600-mw plant provide a good deal of cash through 2015 3409 2800 3100 2991 12300 for late 2018 at a cost of $1.3 billion. The the end of the decade. Dominion Re-2016 3550 2850 3150 3050 12600 company intends to build 400 mw of solar sources owns 70.9% of the midstream gas EARNINGS PER SHARE A Full projects for $700 million. Finally, Virginia master limited partnership. Dominion Cal* endar Mar.31 Jun.30 Sep.30 Dec.31 Year Power plans to spend an average of more Midstream Partners owns a gas pipeline 2012 .86 .48 .80 .61 2.75 than $700 million a year on electric trans- that its parent bought in April for $495 2013 .86 .47 1.02 .74 3.09 mission through the end of the decade. million and a preferred equity interest in a 2014 1.03 .60 .95 .46 3.05 Farmout agreements are a new source $3.4 billion-$3.8 billion project to convert a 2015 .91 .69 1.05. .90 3.55 of profits for Dominion. The company is liquefied natural gas terminal into an e;i<:- 2016 .95 .75 1.10 .95 3.75 leasing the mineral rights covering its port facility. Another potential asset is Do-Cal* QUARTERLY DIVIDENDS PAID B
- Full acreage in the Marcellus and Utica shale minion Resources' 45% stake in a proposed endar Mar.31 Jun.30 Seo.30 Dec.31 Year regions. It receives upfront and royalty $4.5 billion-$5.0 billion gas pipeline.
2011 .4925 .4925 .4925 .4925 1.97 payments. This has the potential to pro- Timely Dominion stock offers greater 2012 .5275 .5275 .5275 .5275 2.11 vide $450 million-$500 million of pretax 3- to 5-year total return potential than 2013 .5625 .5625 .5625 .5625 2.25 income through 2020 . most utility equities. The dividend yield 2014 .60 .60 .60 .60 2.40 We estimate solid earnings growth in is average for the lj!;oup . 2015 .6475 2015 and 2016. This year's growth rate is Paul E. Debbas, C 'A May22, 2015 r~ Oil. egs. Exel. nonrec. gains (losses): '01, '06, 26¢; '07, 1¢; '10, 26¢; '12, 4¢; '13, 16¢. '14 (C) Incl. lntang, In '14: $8.98/sh. (DJ In mill., Com~any's Financial Strength B++ 4 ¢); '03, ~$1.46); '04, (22¢); '06, (18¢); '07, EPS don't add due to rounding. Next egs. due adJ. for 1111. (E) Rate base: Net orig. cost, adj. Stoc 's Price Stability 100 1.67; '06, 2¢; '09, (47f,l; '10, $2.18; '11, (7¢); late July. (Bl Div'ds hlstor. paid In mid-Mar., Rate ail' on com. eq. in '11: 10.9%; earned on Price Growth Persistence 80 '12, ($1.70); '14, (76¢); asses from disc. ops.: June, Sept., & Dec.* Div'd reinvest. plan avail. avg. com. eq., '14: 15.1%. Regul. Climate: Avg. Earnings Predictability " 2015 Value line PublishlnS LLC. All ri~ts reserved. Factual material Is obtained from sources believed to be reliable and Is provided without warranties of an~ kind. THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thl~ublicatlon Is s!Jiclly for subscriber's own, non-commercial, Internal use. o P.art I ua.'"'"'" ""'~* of it may be reproduced, resold, ~ored or transmitted in any printed, electronic or other form, or us for generating or marketing any printed or electronic pubTication, service or proi!ucL II - :U!ll'IU!I 80
Schedule AHG-5 15-WSEE-115-RTS 60 , 50 /PIERATIO *14, seralling:13.9) RELATIVE 076DIV'D EDISON INTERNAT'L NYSE-EIX /RECENT PRICE High: 32.5 49.2 47.2 60.3 55.7 36.7 39.4 41.6 48.0 54.2 68.7 69.6
*
- Median: 12.0 PIE RATIO I YLD 2.9%-
TIMELINESS 3 Lowered 1111n4 Low: 21.2 30.4 37.9 42.8 26.7 23.1 30.4 32.6 39.6 44.3 44.7 60.4 Target Price Range 2018 2019 2020 SAFETY 2 Raised 5/J/13 LEGENDS 120 JJ~:d ~v11~1~~!sr 3 Lowered 4124ns . . . . Relative ~nee Strength
- ~~1e I 100 TECHNICAL I§"*>>:
- 80 BETA .75 (1.00* Malkel) 2018*20 PROJECTIONS o_m:ons: Yes haded area lnaicares recession
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liiiii THIS VlARITH.' 2Q2014 JQ2014 4Q2014 Percent 15 STOCK INDEX lo Buy 200 206 259 shares 10 1111 ~ ' 1 yr. 13.2 7.7 lo Sell 221 217 191 lraded l!olll ,Id 11111 Ill 3yr. 58.5 57.2 >-- Hl~slOOO 258418 260974 260904 5 I 11111111111 1111111111 111111111 5yr. 111.0 94.5 >-- 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC '8-20 27.85 35.96 35.10 35.26 37.25 31.30 36.38 38.74 40.25 43.31 37.98 38.09 39.16 36.41 38.61 41.17 43.60 46.05 Revenues per sh 54.75 7.20 d.52 4.35 4.79 5.88 3.79 6.99 7.25 7.60 8.08 7.96 8.41 9.03 9.63 8.80 9.95 9.45 9.95 "Cash Flow" per sh 11.50 2.03 d5.84 1.30 1.82 2.38 .69 3.34 3.28 3.32 3.68 3.24 3.35 3.23 4.55 3.78 4.33 3.70 4.00 Earnings per sh A 5.00 1.08 .83 .. *- *- .80 1.02 1.10 1.18 1.23 1.25 1.27 1.29 1.31 1.37 1.48 1.71 1.89 Dlv'd Decl'd per sh e
- 2.45 3.55 4.57 2.86 4.88 3.95 5.32 5.73 7.78 8.67 8.67 10.07 13.94 14.76 12.73 11.05 11.99 12.95 15.05 Cap'! Spending per sh 13.25 15.01 7.43 10.04 13.62 16.52 18.57 20.30 23.66 25.92 29.21 30.20 32.44 30.86 28.95 30.50 33.64 35.50 37.50 Book Value per sh c 44.25 347.21 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325,81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 Common Shs Outst'g u 325.81 12.9 -* 10.0 7.8 7.0 NMF 11.7 13.0 16.0 12.4 9.7 10,3 11.8 9.7 12.7 13.0 Bold ng res are Avg Ann'i P/E Ratio 14.0
.74 *- .51 .43 .40 NMF .62 .70 .85 .75 .65 ,66 .74 .62 .71 .68 Value Line estin ates Relative PIE Ratio .90 4.1% 3.9% *- -- *- 3.1% 2.6% 2.6% 2.2% 2.7% 4.0% 3.7% 3.4% 3.0% 2.8% 2.6% Avg Ann'! Div'd Yield 3.5%
CAPITAL STRUCTURE as of 12/31/14 11852 12622 13113 14112 12374 12409 12760 11862 12581 13413 14200 15000 Revenues {$mill) 17850 Total Debt $12029 mill. Due In 5 Yrs $3710 mill. LT Debt $10234 mill. LT Interest $491 mill. 1132.0 1134.0 1151.0 1266.0 1115.0 1153.0 1112.0 1594.0 1344.0 1539.0 1345 1450 Net Profit {$mllll ms (LT Interest earned: 4.9x) 26.0% 31.4% 27.3% 30.7% 33.0% 32.1% 25.7% 14.3% 25.2% 22.4% 30.0% 30.0% Income Tax Rate 30.0% Leases, Uncapitalized Annual rentals $473 mill. 4.9% 5.1% 8.2% 8.9% 10.5% 16.9% 14.8% 8.5% 7.8% 5.8% 10.0% 10.0% AFUDC %to Net Profit 7.0% Pens. Assets-12/14 $3454 mill. Obllg. $4517 mill. 54.6% 51.3% 49.1% 51.2% 49.3% 51.8% 55.3% 45.2% 45.7% 44.1% 44.5% 43.5% Long-Term Debt Ratio 43.5% Pfd Stock $2022 mill. Pfd Dlv'd $113 mlll. 40.9% 43.5% 46.0% 44.5% 46.5% 44.3% 40.6% 46.2% 46.2% 47.2% 47.0% 48.0% Common Equity Ratio 49,0% 4,800,198 sh, 4.08%-4.78%, $25 par, call. $25.50- 16167 17725 18375 21374 21185 23861 24773 20422 21516 23216 24625 25400 Total Capital ($mill) 29400
$28.75/sh.; 3,250,000 sh. variable, noncum., call. 14469 15913 17403 18969 21966 24778 32116 30273 30455 32981 35350 38325 Net Plant ($mill) 45400 $100; 1,250,000 sh. 6.5%, cum., $100 liq. value; 350,000 sh. 6.25%, $1000 liq. value; 460,012 sh. 9.4% 8.6% 8.3% 7.4% 6.9% 6.3% 6.0% 8.9% 7.3% 7.7% 6.5% 6.5% Return on Total Cap'I 7.0%
5.1%-5.75%, $2500 liq. value. 15.4% 13.1% 12.3% 12.1% 10.4% 10.0% 10.0% 14.2% 11.5% 11.9% 10.0% 10.0% Return on Shr. Equity 10.5% Common Stock 325,811,206 shs. as of 2/20/15 16.7% 14.0% 13.0% 12.8% 10.8% 10.4% 10.5% 15,9% 12.5% 13.0% 10.5% 11.0% Return on Com Equity E 11.5% MARKET CAP: $20 billion (Large Cap) 12.2% 10.1% 9.2% 8.6% 6.7% 6.5% 6.3% 11.4% 8.1% 8.8% 5.5% 6.0% Retained to Com Eq 6.0% ELECTRIC OPERATING STATISTICS 29% 31% 33% 35% 41% 40% 43% 32% 40% 37% 51% 51% All Dlv'ds to Net Prof 52% 2012 2013 2014 BUSINESS: Edison International (formerly SCECorp) Is a holding commercial, 44%: Industrial, 6%; other, 13%. Generating sources:
%Ch;:s Reloil S~es (KWH) +2.6 -.3 +2.1 Ai~. I usl Use (M'llH~ 763 791 788 company for Southern California Edison Company (SCE), which gas, 8%; nuclear, 6%; hydro, 2%; purchased, 84%. Fuel costs:
A111.lndustRev;.~ IHI¢) 7.50 8.00 8.86 supplies electricity to 4.9 mill. customers in a 50,000 sq. ml. area in 42% of revs. '14 reported deprec. rate: 4.0%. Has 13,700 employ-Ca~ at Peak( .t.vk NA NA NA central, coastal, and southern Cali£omia (excl. Los Angeles and ees. Chairman, President & CEO: Theodore F. Craver, Jr. Inc.: CA. Peak Load, Summer I 1) 21981 22534 23055 San Diego). Discontinued Edison Mission Energy (independent Address: 2244 Walnut Grove Ave., P.O. Box 976, Rosemead, CA Annual Load Factor (~/i 52.7 52.1 52.3
%Chan~ Cuslomers yr-end) +.4 +.6 +.6 power producer) In '12. Elec. revenue breakdown: residential, 37%; 91770. Tel.: 626-302-2222. lntemel: www.edlson.com.
F~ed Chaige C-Ov. (%) 308 295 306 Edison International's utility subsidi- The San Onofre ~roblem hasn't gone ANNUAL RATES Past Past Est'd '12-'14 ary is awaiting an order on its general away. In 2013, SC decided to retire the of change (per sh) 10Yrs. 5Yrs. to '18-'20 rate case. Southern California Edison is nuclear station after damage was found in Revenues 1.0% *1.0% 6.0% asking the California Public Utilities Com- both units following steam generator re-
"Cash Flow" 7.0% 3.5% 3.5% m.isslon (CPUC) for rate increases of $80 placements. The utility had to take a siz-Earnings 10.0% 4.5% 3.0%
Dividends . - 2.5% 10.0% million in 2015, $286 million in 2016, and able writedown, but is recovel"ing some Book Value 6.5% 2.0% 6.0% $315 million in 2017. On the other hand, costs associated with the plant in accord-QUARTERLY REVENUES ($mill.) the Office of Ratepayer Advocates (ORA) is ance with a settlement that the CPUC ap-Cal* Full proposing a large rate decrease for 2015. proved last November. However, the ORA endar Mar.31 Jun.30 Sep.30 Dec.31 Year 2012 2415 2653 3734 3060 11862 Whenever the CPUC issues its order, it and an intervenor group (each of which 2013 2632 3046 3960 2943 12581 will be retroactive to the start of this year. signed the settlement) want to overturn it 2014 2926 3016 4356 3115 13413 Note that management is not providing due to the disclosure of an ex parte com-2015 3100 3200 4700 3200 14200 earnings guidance while the rate case is munication between a former SCE execu-2016 3300 3400 4900 3400 15000 pending. tive and the former CPUC president in Cal* EARNINGS PER SHARE A Regardless of the -outcome of the rate March of 2013, In fact, the ORA is propos-Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year case, earnings are likely to decline Ing that the utility should be forced to re-2012 .54 .55 1.09 2.39 4.55 this year. In 2014, Edison International turn a minimum of $648 million to rate-2013 .78 .78 1.41 .81 3.78 had some cost reductions that are not payers. The company believes the settle-2014 .61 1.07 1.51 1.15 4.33 sustainable and booked some tax benefits. ment is fair and was negotiated properly. 2015 .70 .70 1.55 .75 3.70 This made the year-to-year comparison We aren't assuming an additional penalty. 2016 .80 .BO 1.60 .80 4.00 difficult. We think results in 2015 will be We are concerned about the regula-Cal- QUARTERLY DIVIDENDS PAID e
- Full closer to normal. tory risk the utility is facing-for both endar Mar.31 Jun.30 Sen.30 Dec.31 Year We forecast solid profit growth in the rate case and San Onofre. Thus, we 2011 .32 .32 .32 1.28 2016. SCE has a large capital budget advise investors to look elsewhere, despite
.32 2012 .325 .325 .325 .325 1.30 (funded in part with debt), and projects the company's superior dividend growth 2013 .3375 .3375 .3375 .3375 1.35 rate base growth of 7%-9% annually prospects through 2018-2020. Meanwhile, 2014 .355 .355 .355 .355 1.42 through 2017. This should produce similar the dividend yield is low for a utility.
2015 .4175 .4175 earnings growth . Paul E. Debbas, CFA May 1, 2015 (A) Diluted EPS. Exel. nonrec. gains (lossesl: 57¢. '12 & '14 EPS don'I add due to rounding. In '14: $23.36/sh. (0) In mill. (E) Rate base: net Camkany's Financial Strength A '02, $1.48; '03, (12f;l; '04, $2.12; '09, (64¢; Next earnings report due late July. {B) Div'ds or1g. cosl Rale allowed on com. e2. In '15: Sloe 's Price Stabltlty 100 '10, 54¢; '11, ($3.33; '13, ($1.12); gains (loss) paid late Jan., Apr.. July, & Oct.
- Dlv'd rein- 10.45%; earned on avg. com. eq., '1 : 13.8%. Price Growth Persistence 50 from dlscont. ops.: '12, ($5.11); 13, 11¢; '14, vestment plan avail. (C) Incl, deferred charges. Regulatory Climate: Above Average. Earnings Predictability 65 0 2015 Value Line Publishln~ LLC. All rifts reserved. Factual material Is obtained lrom sources believed lo be reliable and Is pro~ded 1~1houl warranlies or any kind.
THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thi~ublicalion Is striclly for subscrlbe(s own, non*commerdal, Internal use. No Eart 111-..* 11 1~,*111 1 '--<..-, 11 *,.:illllll/ll or ii may be reproduced, resold, stored or Uansmilled in any printed, elecrronlc or olher rorm, or us for generating or marketing any printed or elecrronic puhfication, see.ice or prooucL
Schedule AHG-5 15-WSEE-115-RTS
., ... =-
EL PASO ELECTRIC NYSE-EE 3.1% TIMELINESS 3 Loweredl2/Sl14 t-=L=ow=:~.,,1=3~.1'-'----'1-'-7'-=.B-'--;18.2 High: 19.1 22.4 25.0 28.2 21.521.1 28.7 35.7 35.3 39.1 42,2 41.3 20.8 15.2 11.6 18.7 26.7 29.2 31.8 33.4 35.4 Target Price Range 2018 2019 2020 SAFETY 2 Raised 5111101 -LEGENDS 5.0 x "Cash Flovl' p sh , ' 1 80 TECHNICAL 3 Lowered 511115 0* * *
- Relative Prlce Streng1h r--t----if,:,+-,::_, ~+--+--+---+----1---t-----+--+---+---lf--+
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1s 202014 302014 402014 Percent 21 , ... .... .... ........... .. STOCK INDEX "" IBJ.~00\ 396~~ 40J! 390~~ ~~~:J 1i- * ::i::I:::l 1:::\1il 111i;;,;;,I .:.1111 11:i11u11 1111111111111 r;1~9~99?,-;2~0°"'00,_,_,2~0""'o1~2'°"0""'02~2~00=3-;-,2~00~4,,,1¥2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 1 2016 1H:~ ~u :8-20 rn:VALUELINEPUB.LLC 9.96 13.70 15.40 13.91 13.97 14.95 16.70 17.75 19.43 23.15 18.85 20.61 22.97 21.26 22.11 22.74 23.45 24.60 Revenues per sh 28.00 2.79 3.21 3.43 2.99 3.00 3.27 3.05 3.44 3.86 4.16 4.07 5.15 6.05 5.66 5.65 5.87 6.05 6,35 "Cash Flow" per sh 7.75
.86 1.09 1.27 .57 .64 .69 .76 1.27 1.63 1.73 1.50 2.07 2.48 2.26 2.20 2.27 2.05 2.20 Earnings per sh A 2.75
.. .. -* -- ** -- -- ** -* ** ** .66 .97 1.05 1.11 1.17 1.23 Dlv'dDeci'dpersh 8 1.40 1.28 1.70 1.85 1.75 2.03 1.94 2.28 2.73 4.63 5.36 5.95 5.27 5.90 6.70 7.18 8.50 7.90 7.75 Cap'I Spending per sh 7.25 7.36 8.05 9.01 9.20 10.51 11.23 11.56 12.60 14.76 15.47 16.45 19.04 19.03 20.57 23.44 24.39 25.20 26.10 BookValuepersh c 29.50 57.26 51.20 49.99 49.61 47.56 47.40 48.14 46.00 45.15 44.88 43.92 42.57 39.96 40.11 40.27 40.36 40.50 40.65 Common Shs Outst'g o 41.10 9.9 10.6 11.0 23.0 18.3 22.0 26.7 16.9 15.3 11.9 10.8 10.7 12.6 14.5 15.9 16.4 Boldfig resare AvgAnn'IP/ERatlo 14.5
.56 .69 .56 1.26 1.04 1.16 1.42 .91 .81 .72 .72 .68 .79 .92 .89 .86 Value Line Relative P/E Ratio .90
.. .. .. .. .. .. .. .. .. -* -* 2.1% 3.0% 3.0% 3.0% estln ates Avg Ann'I Div'd Yield 3.5%
CAPITAL STRUCTURE as of 12131114 803.9 816.5 877.4 1038.9 828.0 877.3 918.0 852.9 890.4 917.5 950 1000 Revenues ($mill) 1150 Total Debt $1163.7 mill. Due In 5 Yrs $112.8 m\11. 36.6 61.4 74.8 77.6 66.9 90.3 103.5 90.8 88.6 91.4 85.0 90.0 Net Profit {$mill) 110 LT Debt $1134.2 mill. LT Interest $68.2 mill. 33.7% 29.8% 31.6% 32.8% 33.1% 36.1% 34.2% 34.1% 33.0% 31.0% 33.0% 33.0% Income Tax Rate 33.0% (LT Interest earned: 2.8x) 15.8% 8.0% 15.9% 20.4% 24.3% 22.1% 17.6% 22.4% 24.1% 30.8% 24.0% 22.0% AFUDC 'lo lo Net Profit 18.0% Leases, Uncapitalized Annual rentals $1.4 mill. 52.3% 51.5% 49.6% 53.8% 52.7% 51.2% 51.8% 54.8% 51.4% 53.5% 55.5% 56.0% Long-Term Debt Ratio 56.5% Pension Assets-12114 $272.9 mill. 47.7% 48.5% 50.4% 46.2% 47.3% 48.8% 48.2% 45.2% 48.6% 46.5% 44.5% 44.0% Common Equity Ratio 43.5% Oblfg. $341.1 mill. 1167.5 1195.8 1321.6 1503.9 1527.7 1660.1 1576.7 1824.5 1943.5 2118.4 2305 2420 Total Capital ($mill) 2800 Pfd Stock None 1291,7 1332.2 1450.6 1595.6 1756.0 1865.8 1947.1 2102.3 2257.5 2488.4 2645 2790 Net Plant ($mill) 3050 Common Stock 40,352,478 shs. 4.9% 6.6% 7.1% 6.7% 6.0% 7.0% 8.3% 6.5% 6.1% 5.7% 5.0% 5.5% Return on Total Cap'I 5.5% as of 1/31/15 6.6% 10.6% 11.2% 11.2% 9.3% 11.1% 13.6% 11.0% 9.4% 9.3% 8.0% 8.5% Return on Shr. Equity 9.0% 6.6% 10.6% 11.2% 11.2% 9.3% 11.1% 13.6% 11.0% 9.4% 9.3% 8.0% 8.5% Return on Com Equity E 9.0% MARKET CAP: $1.5 billion (Mid Cap) 6.6% 10.6% 11.2% 11.2% 9.3% 11.1% 10.0% 6.3% 4.9% 4.8% 3.5% 4.0% Retained to Com Eq 4.5% ELECTRIC OPERATING STATISTICS -- -- .. .. -- .. 26% 43% 47% 49% 56% 55% All Dlv'ds to Net Prof 51% 2 2 2
%ChangaRelailS~es(Kl'IH) ~} ~~~ ~/i BUSINESS: El Paso Electrtc Company (EPE) provides electric able. Generating sources: nuclear, 47%; gas, 35%; coal, 5%; pur-A1~.lnduslUse(M'l/HI 21659 21908 21505 service to 400,000 customers In an area of approximately 10,000 chased, 13%. Fuel costs: 34% of revenues. '14 reported depreci-A1~.lnduslRevs.~l\'/Af(j) NA NA NA square miles in the Rio Grande valley In 'Western Texas (68% of atlon rate: 2.6%. Has about 1,000 employees. Chairman: Chartes CapacityatPeak(hl~ 1765 1852 1879 revenues) and southern New Mexico (19% of revenues), including A. Yamarone. CEO: Thomas V. Shockley, Ill. President: Mary Kipp.
~;~~~d~:"o;'(~,{l 16
~~ 17
~2 17
~X El Paso, Texas and Las Cruces, New Mexico. Wholesale Is 13% of Inc.: Texas. Address: Stanton Tower, 100 North Stanton, El Paso,
%ChangeCuslomera(yr-end) +1.5 +1.3 +1.3 revenues. Electric revenue breakdown by customer class not avail- Texas 79901. Tel.: 915-543-5711. Internet: www.epelectrtc.com.
F~edChaigeCov.(%) 302 280 251 El Paso Electric Company has com- credit to income, will be below the 2014 ANNUAL RATES Past Past Est'd *12 .* 14 pleted the first two of four 88- level now that the first two facilities are ofchange(persh) 10Yrs. 5Yrs. to'18-'20 megawatt gas-fired peaking units it complete. El Paso Electric's earnings guid-Revenues 4.5% 1.5% 4.0% plans to construct. Units 1 and 2 at- ance is in a range of $1.75-$2.15 a share.
~~~l~g~ow" &~~ ~ ~~ . ~.~~ tained commercial ope(ration in March at The top end of this range would produce a Dividends ._ ** 5.0% an estimated cost including common 5% earnings decline, the bottom end a 23%
Book Value 8.5% 8.0% 4.5% plant) of just under $200 million. The utili- falloff. We are sticking with our estimate Cai* QUARTERLYREVENUES($mill.) Full ty will soon begin building the other two of $2.05 a share. endar Mar.31 Jun.30 Sep.30 Dec.31 Year units. Unit 3 is expected to come on line in Profits should make at least a partial 2012 168.6 228.3 26 7.2 188.8 952,9 2016, followed by Unit 4 in late 2016 or recovery in 2016. We assume reasonable 2013 177.3 240.1 282.7 190.3 890.4 early 2017. The cost of the entire project is regulatory treatment in each state. Note, 2014 185.5 251.8 283.6 196.6 917.5 estimated at $373 million. though, that El Paso Electric will still be 2015 195 255 295 205 950 As this report went to press, the utili- hurt by some regulatory lag next year, just 2016 205 270 310 215 1000 ty was about to file a rate case in New not as much as in 2015. Cal* EARNINGSPERSHAREA Full Mexico. Similarly, a rate application in We look for a dividend hike in the endar Mar.31 Jun.30 Sep.30 Dec.31 Year Texas is planned for July or August. These current quarter. This has been the pat-2012 .08 .77 1.29 .12 2.26 filings will seek recovery of the two new tern since the board of directors initiated a 2013 .19 .72 1.26 .03 2.20 units and other capital expenditures that dividend four years ago. We estimate that 2014 .11 .75 1.30 .10 2.27 are not currently part of the rate base. the annual payout will be raised by $0.06 2015 .15 .65 1.15 .10 2.05 New tariffs will take effect in March of a share (5.4%), the same increase as in 2016 .15 .70 1.20 .15 2.20 2016. each of the past two years. Cal* QUARTERLY DIVIDENDS PAID e Full Regulatory lag will hurt earnings this The stock's dividend yield is on the endar Mar.31 Jun.30 Sep.30 Dec.31 Year year. El Paso Electric will incur costs low side, for a utility. This reflects the 2011 _. .22 .22 .22 .66 (such as depreciation) associated with the company's above-average dividend growth 2012 .22 .25 .25 .25 .97 aforementioned new units, but won't re- potential over the 3- to 5-year period. To-2013 .25 .265 .265 .265 1.05 cover these expenses until receiving rate tal return potential over that time frame is 2014 .265 .28 .28 .28 1.11 relief next year. The Allowance for Funds modest. 2015 .28 Used During Construction, a noncash Paul E. Debbas, CFA May J, 2015 {A) Diiuted earnings. Exel. nonrecurring gains earnings report due earty May. (B) Initial divl- millions. (E) Rate allowed on common equity in Company's Financial Strength B++ (losses): '99, (38¢); '01, (4¢); '03, 81¢; '04, 4¢; dend declared 4/11; payment dates Jn late '12: none specified; earned on average com* Stock's Price Stablilty 90 '05, (2¢); '06, 13¢; '10, 24¢. '14 earnings don't March, June, Sept., and Dec. (C) Incl. deferred man equity, '14: 9.5%. Regulatory Climate: Price Growth Persistence 80 add to full-year total due to rounding. Next charges. In '14: $112.1 mill., $2.78/sh. (D) In Average. Earnings Predictability 85 <> 2015 Value Line Publishing LLC. All righ!S reserved. faclual malerlal Is oblalned from sources believed lo be reliable and Is piovlded without warranties of any kind. THE PUBLISHER IS NOT RESPONSIBLEFOR ANY ERRORS OR OMISSIONS HEREIN. This publication Is slrlcUy lor subscriber's own, non-commerc\al, lnlernal use. No part I ua.~ Ill"'" I "'IH'o :u111111*111'.lill ol ii may be reproduced, resold, stored or transmilled In any prinled, eleotrcnic or 0U1er form, or used for geneiating or marketing any printed or eleotronic pubflcation, seniice or prooucL
Schedule AHG-5 15-WSEE-115-RTS EMPIRE4 DISTRICT NYSE-EDE RECENT IPRICE 23 ,96 PIERATIO 17, 0(Tralllng:15.5) PIE RATIO 0, 92 DIV' Median: 16.0 RELATIVE YLDD 4.4o'omrg-"'1*11=-
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TIMELINESS Loweiedl21S/l 4 High: 23.5 25.o 25.1 26.1 23.5 19.4 22.5 23.3 22.0 24.3 31.2 31.5 Target Price Range Low: 19.5 19.3 20.3 21.1 14.9 11.9 17.6 18.0 19.5 20.6 22.0 23.7 2018 2019 2020 SAFETY 2 Raised J/13112 LEGENDS TECHNICAL 3 Raised 3/10115 -. * . . Si~~:d ~vi1~,~~~r ~~IC Relative ~rice Streng1h f---+---'l"""*'"""**'"".,,."'.,.,:t*'"-'*'*""".,-t-----1-----1---+---+--t----+-----1~-+---+--.i-64 [ ~t.;i.*~;;': ~~~ 4B 0 70 BETA * (1.00 =Market) ~Z~~~~r~a indicates recession
- 40 2018*20 PROJECTIONS I/~ ,.._, ..... ..... 32 Ann'I Total " * *', 24 Price Gain Return .111*111~1*1 I' 111 11 1. 11111111
- 1111 '-1*
- 111 ..... ,,11, r.111 ....
20 High 30 (t25%l 10% 11,,r I'" 1.11,r 1-..'v"Y' Low 20 1-15% 1% ¥--+-'---P.,,+---1-----l---+---+--t-----1-----1---+---+-16 Insider Decisions 1
- 12
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- 1:eJ:*;,~*.,*1;~ % TOT. RETURN 2115 Institutional Decisions I{: :it.*: " *.,,....... ... *" **
2Q201l 3Q2014 4Q2014 Percent 12- ** lii':i*cJ,,i; .11 "" '"* .....,., '"* sfo~K ~mJ~x"*"""" l~~~ ~~ ~~ ~~ ih'd:J ~
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Hld'sfOOOI 20869 20897 21381 a illll 1111111111 II 1111111111 11111mn m11!Illl IT 5 yr. 77.3 110.1 1999 2000 2001 2002 2003 2004 2005 2006 2007 200B 2009 2010 2011 2012 2013 2014 2015 2016 VALUELINE PUB. LLC 8-20 13.81 15.00 17.50 3.14 3.45 4.25 1.48 1.55 1.75 1.01 1.03 1.20 3.60 4.91 3.50 17.43 18.02 20.25 43.04 43.48 47.50 15.0 16.2 13.5
.84 .86 .85 4.5% 4.1% 5.0%
594.3 652.3 830 63.4 67.1 85.0 37.1% 36.9% 9.4% 14.6% 49.8% 50.6% 50.2% 49.4% 1493.6 1586.5 Pfd Stock None 1751.9 1910.3 Common Stock43,517,285 shs. 4.7% 5.9% 4.7% 5.2% 5.2% 5.1% 5.5% 5.4% 5.6% 5.5% 5.0% 5.0% Return on Total Cap'I 5.5% as of 2/2/15 6.0% 8.5% 6.2% 7.5% 6.9% 7.2% 7.9% 7.8% 8.5% 8.6% 7.5% 7.5% Return on Shr. Equity 8.5% 6.0% 8.5% 6.2% 7.5% 6.9% 7.2% 7.9% 7.8% 8.5% 8.6% 7.5% 7.5% Return on Com Equity E 8.5% MARKET CAP: $1.0 billion (Mid Cap) NMF .8% NMF NMF NMF NMF 4.1% 1.9% 2.7% 2.9% 2.0% 2.0% Retained to Com Eq 3.0% ELECTRIC OPERATING STATISTICS NMF 90% 117% 109% 109% 110% 49% 76% 68% 66% 74% 74% All Dlv'ds to Net Prof 68% 2012 2013 ~~~ 1--B-US-l-NE~S-S-:-Th~e~E-m_p_lre..l-Dl-s~-c-l~El-ec-trl_c_C~o-m-pa-ny--'-su-pp-ll-es-'e-le_c_lrl---'-cl-al-,-32~%-;-in-d-us~lrl_a_l,-1-6%~,;-o-lh-e-'r.~7-%-.-G-en_e_ra_lln_g_s_o_ur-ce~s-:-co-al-1,
'h Change Relai Sales IK'llH) -3.2 +1.3 A1~. lllduslrial Use (Ml'/H) 2913 2943 2981 city lo 169,000 customers in a 10,000 sq. mi. area In southwestern 47%; gas, 27%; hydro, 1%; purch., 25%. Fuel costs: 37% of reve-A1~. lllduslrial Revi!(VIH (¢) 7.66 7.93 8.21 Missouri (90% of retail elec. revs.), Kansas (5%), Oklahoma (3%), nues. '14 reported depr. rate: 3.0%. Has about 750 employees, Ca~ al Pe<k (!Jill 1391 1377 j~~~ & Arkansas (2%). Acquired Missouri Gas (44,000 customers) 6/06. Chairman: D. Randy Laney. President & CEO: Bradley P. Beecher.
Pe<k Load, Summer !Mw) 1142 1080 Annual Load Faclor (~) 52.2 56.2 52.8 Supplies waler service (4,000 customers) and has a small fiber- Inc.: KS. Address: 602 S. Joplin Ave., P.O. Box 127, Joplin, MO
%Cha111Je Custome~ (avg.) +.6 +.5 +.3 1--'op'-tl_cs_o.;.p_er_a_tio_n._E_le_c_._re_v._b_re_ak_d_ow_n_:_re_sl_de_n_tia-'l,_4_5'_Yo;'-c_o_m_m_er_-_64_8_02_-0_1_27_._T_el_.:_41_7_-6_25_-5_1_00_._ln_te_m_e_t:_www_._em_,p_lr_ed_ls_tri_ct_.co_m_.-l F~e<IChargeC-Ov.('h) 314 331 334 Empire District Electric is awaiting taxes associated with the Asbury upgrade, ANNUAL RATES Past Past Est'd '12*'14 an order on its electric rate applica- but won't receive rate relief for a few more of change(persh) 10 Yrs. 5Yrs. lo '18-'20 tion. The utility is seeking a rate hike of months. We underestimated the effects of Revenues .5% *.5% 4.0% $24.3 million (5.5%), based on a 10.15% re- regulatory lag, and have cut our 2015 "Cash Flow" 3.0% 3.0% 5.0% turn on a 51.45% common-equity ratio. earnings estimate by $0.10 a share, to Earnings 2.5% 5.0% 3.0%
Dividends -2.5% -4.5% 3.0% The single-biggest driver of the rate case is $1.40. Our revised estimate is within the Book Value 1.5% 2.0% 2.5% the need to place an envirnnmental up- company's targeted range of $1.30-$1.45. Cal* QUARTERLY REVENUES($ mill.) Full grade to the Asbury coal-fired plant in the We forecast only a partial profit endar Mar.31 Jun.30 Sep.30 Dec.31 Year rate base. This project was completed in recovery in 2016, due to more regula-2012 137.2 131.6 159.2 129.1 557.1 December at a cost of $121 million. Em- tory lag. Empire District is expanding 2013 151.1 136.6 157.5 149.1 594.3 plre District also wants to recover higher Riverton 12's capacity by 100 megawatts 2014 179.7 149.8 171.5 151.3 652.3 property taxes and the cost of a mainte- at an expected cost of $165 million-$175 2015 170 160 180 160 670 nance contract for Unit 12 of the Riverton million. The utility plans to file another 2016 180 170 190 170 710 gas-fired plant. In addition, the utility rate case in Missouri once the current one Cal* EARNINGS PER SHARE A Full proposes to recover changes in transmis- ls concluded, but rate relief won't come un-endar Mar.31 Jun.30 Sep.30 Dec.31 Year sion costs through its fuel adjustment til after the project goes into service in 2012 .23 .25 .60 .23 1.32 clause. New tariffs should take effect by mid-2016. 2013 .30 .27 .56 .35 1.48 July, unless Empire District reaches a set- Empire District stock is untimely, and 2014 .48 .26 .55 .26 1.55 tlement that would allow for new rates has fallen nearly 20% so far in 2015. 2015 .30 .25 .60 .25 1.40 sooner. The company has asked the Kan- We think the recent decline is merely a 2016 .30 .25 .63 .27 1.45 sas and Arkansas commissions to allow it correction. For a while, the price rose Cal* QUARTERLY DIVIDENDS PAID 8 *t Full to recover the cost of this project through a above $30 a share, possibly indicating that endar Mar.31 Jun.30 Sen.30 Dec.31 Year rider on customers' bills, and plans to the company was viewed as a takeover 2011 .32 .32 ** ** .64 make a similar request in Oklahoma. candidate. The dividend yield is a cut 2012 .25 .25 .25 .25 1.00 Due to the effects of regulatory lag, above the utility average, but total return 2013 .25 .25 .25 .255 1.01 earnings will probably decline in potential to 2018-2020 is low, even after 2014 .255 .255 .255 .26 1.03 2015. Empire District is already booking the pullback. 2015 .26 higher depreciation expense and property Paul E. Debbas, CFA March 20, 2015 (A) Diluted earnings. Exel. loss from discontin* Sept. and Dec. Div'ds suspended 3Q '11, $5.93/sh. (D) In mill. (E) Rate base: Depree. Company's Financial Strength B++ ued operations: '06, 2¢. '12 EPS don't add due reinstated 1Q '12.
- Div'd reinvestment plan orig. cost. Rate allowed on com. eq. in MO In Stock's Price Stability 95 lo rounding. Next eamlngs report due late April. avail. (3% discount). t Shareholder Investment '13: none specified; earned on avg. com. eq., Price Growth Persistence 35 (B) Dlv'ds historically paid In mld*Mar., June, plan avail. (C) Incl. Intangibles. In '14: '14: 8.7%. Regulatoiy Climate: Average.
" 2015 Value Une Publishing LLC. All righls reserved. Faclual malerlal Is obtained from sources believed 10 be rellablc and Is provided without warranlies or any kind. THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publicalion Is strictly for subscribers own, non*commerdal, lntemal use. No ~art ll'jW'llliNiliJ1 ' of 11 may be reproduced, resold, stored or kansmitled in any printed, eleckonic or other form, or used for generating or marlceling any prinled or electronic pubficalion, service or prooucL Earnings Predictability
- 1111111
- !111" 1111 85
Schedule AHG-5 15-WSEE-115-RTS DUKE ENERGY NYSE-DUK TIMELINESS 3 Raised 4/10h5 High: IRECENT PRICE 76 , 30 RATIO 17 , 63.9 61.8 r 53.8 55.8 o(1raillng:18.3) Median: NMF 66.4 71.1 RELATIVE P/E RATIO 75.5 090 DIV'YLDD 4.2%- I 87.3 90.0 Target Price Range Low: 50.7 40.5 35.2 46.4 50.6 59.6 64.2 67.1 73.6 2018 2019 2020 SAFETY 2 New6/1/07 - LEGENDS r 0.56 x Dividends sh 128 TECHNICAL 4 Lowered Sh5NS divided b~ lnleres Rate
* * *
- Relative nee S~ength ...... -. ... .... .. 96 BETA .60 (1.00 =Markel) 2018*20 PROJECTIONS Ann'I Total 1-for*3 Rev split 7112 O~~~~~~".;,~a indicates recession *1'1111111
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80 64 Price Gain Return I .fnr. 48 High 90 (+20%l 8% 40 Dnun*M Low 65 (-15% 1% 32 Insider Decisions 24 JJASON D J F to Buy 0 0 0 0 0 0 a o 0 Options o o 1 o o a a a 9 **:** ...... .... ...... .... ...*** ........ 16 to Sell 1 1 3 0 0 4 0 0 3 Institutional Decisions
........****.. %TOT. RETURN 4/15 THIS VLARITH.'
...-12 2Q2014 3Q20H mo14 Percent 15
.I S'~i STOCK INDEX to Buy to Sell 434 441 431 423 469 shares 460 traded 10 5
11 Ill
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"'"' 111111111 111111111 " ... Iii 1 yr.
3yr. 8.6 37.7 9.1 58.8 ""
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Hl~slOOOl 386233 392694 390171 1111111111 111111111 111111111 ;111111 Ill 5yr. 95.7 84.6 Duke Energy Corporation, in its current con- 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 figuration, began trading on January 3, .. 25.32 30.24 31.15 29.18 32.22 32.63 27.88 34.84 33.84 35.25 36.65 Revenues per sh 41.50 2007, the day after it spun off its midstream .. 7.86 8.11 7.34 7.58 8.49 8.68 6.80 8.56 9.11 9.80 10.15 "Cash Flow" per sh 11.25 gas operations into a new company, Spec- -* 2.76 3.60 3.03 3.39 4.02 4.14 3.71 3.98 4.13 4.50 4.75 Earnings per sh A 5.25 tra Energy (NYSE: SE). Duke Energy share- *- *- 2.58 2.70 2.82 2.91 2.97 3.03 3.09 3.15 3.21 3.27 Dlv'd Decl'd per sh e
- 3.55 holders received half a share of Spectra En- -- 8.07 7.43 10.35 9.85 10.84 9.80 7.81 7.83 7.62 11.05 11.85 Cap'J Spending per sh 11.50 ergy for each Duke share held. In July of -- 62.30 50.40 49.51 49.85 50.84 51.14 58.04 58.54 57.81 58.65 60.10 Book Value per sh c 65.00 2012, Duke acquired Progress Energy and -* 418.96 420.62 423.96 436.29 442.96 445.29 704.00 706.00 707.00 688.00 689.00 Common Shs Outst'g o 692.00 effected a 1-for-3 reverse split. Data for the -- -- 16.1 17.3 13.3 12.7 13.8 17.5 17.4 17.9 Bold Ilg res are Avg Ann'I P/E Ratio 15.0 "old" Duke are not shown because they are -* *- .85 1.04 .89 .81 .87 1.11 .98 .95 Value Line Relative PIE Ratio .95 not comparable. -- .. 4.4% 5.2% 6.2% 5.7% 5.2% 4.7% 4.4% 4.3%
es tin ates Avg Ann'I Dlv'd Yield 4.5% CAPITAL STRUCTURE as of 12/31114 -- 10607 12720 13207 12731 14272 14529 19624 24598 23925 24250 25250 Revenues ($mlll) 28750 Tota! Debt $42534 mill. Due in 5 Yrs $16770 mill. LT Debt $37213 mill. LT Interest $1704 mill.
-- 1080.0 1522.0 1279.0 1461.0 1765.0 1839.0 2136.0 2813.0 2934.0 3130 3285 Net Profit ISmllll 3695 Incl. $1428 mill. capitalized leases. Incl. $1265 mill. -- 29.4% 31.9% 32.5% 34.4% 32.6% 31.3% 30.2% 32.6% 30.6% 32.5% 32.5% Income Tax Rate 32.5%
nonrecourse LT debt of variable interest entllies. *- 6.9% 7.2% 16.0% 17.5% 22.7% 23.2% 22.3% 8.8% 7.2% 9.0% 9.0% AFUDC %to Net Profit 8.0% (LTinterest earned: 3.6x) *- 41.0% 30.9% 38.7% 42.6% 44.3% 45.1% 47.0% 48.0% 47.7% 48.0% 49.0% Long-Term Debt Ratio 51.5%
*- 59.0% 69.1% 61.3% 57.4% 55.7% 54.9% 52.9% 52.0% 52.3% 52.0% 51.0% Common Equity Ratio 48.5%
Leases, Uncapitalized Annual rentals $205 mill. .. 44220 30697 34238 37863 40457 41451 77307 79482 78088 77750 81275 Total Capital ($mlll) 92600 Pension Assets*12/14 $8498 mill. Oblig. $7966 mill. *- 41447 31110 34036 37950 40344 42661 68558 69490 70046 74050 78500 Net Plant ($mill) 90700 Pfd Stock None -- 3.1% 6.0% 4.8% 4.9% 5.5% 5.6% 3.6% 4.6% 4.8% 5.0% 5.0% Return on Total Cap'I 5.0% Common Stock 707,554,168 shs. -- 4.1% 7.2% 6.1% 6.7% 7.8% 8.1% 5.2% 6.8% 7.2% 8.0% 8.0% Return on Shr. Equity 8.0% as of 2/24/15 .. 4.1% 7.2% 6.1% 6.7% 7.8% 8.1% 5.2% 6.8% 7.2% 8.0% 8.0% Return on Com EQulty E 8.0% MARKET CAP: $54 blltlon (Large Cap) .. 4.1% 2.0% .6% 1.1% 2.1% 2.2% .9% 1.5% 1.7% 2.0% 2.5% Retained to Com Eq 3.0% ELECTRIC OPERATING STATISTICS *- -- 72% 89% 84% 73% 72% 82% 78% 76% 72% 69% All Dlv'ds to Net Prof 66% 2012 2013 2014
%Clia~eRetaJ1Saies(Kl\\i) -2.8 +1.3 +2.2 BUSINESS: Duke Energy Corporation Is a holding company for utll* tlal, 44%; commercial, 30%; Industrial, 15%; other, 11%. Genera!-
Avg.I ustUse(Mll'H~ 2675 2687 2876 ities with 7.1 mill. alee. customers In North Carolina, Florida, lndl- Ing sources: coal, 37%; nuclear, 28%; gas, 21%; other, 1%; pur-Avg. ln<lust Revs~r (¢) 5.84 5.89 6.15 ana, South Carolina, Ohio, & Kentucky, and over 500,000 gas cus- chased, 13%. Fuel costs: 35% of revs. '14 reported deprec. rates: Cspadly at Peak w~ NA NA NA tamers in Ohio & Kentucky. Owns independent power plants & has 2.4%-3.3%. Has 28,300 empls. Chairman: Ann Gray. Pres. & CEO: Peak LOad, Summer lw) NA NA NA Lynn J. Good. Inc.: DE. Address: 550 South Tryon St., Chartotte, Annual Load Factor(~/ NA NA NA International ops. Acq'd Cinergy 4/06; spun off midstream gas ops.
%CliangeCllslomera a\~.) +.8 +.8 +1.0 1/07; acq'd Progress Energy 7/12. Elec. rev. breakdown: residen- NC 28202-1803. Tel.: 704-382-3853. Web: www.duke-energy.com.
F~ed Charge Cllt (%) 263 327 315 Duke Enerfru has completed a major development. In South Carolina, Duke is ANNUAL RATES Past Past Est'd '12*'14 asset sale. ue to unfavorable conditions adding 650 megawatts of gas-fired genera-or change (per sh) 10Yrs. 5Yrs. to '18-'20 in the power markets, the company sold ting capacity at a cost of $600 million. In Revenues -- 1.5% 4.5% its nonregulated generating assets in the Florida, the utility plans to build a 1,685-
"Cash Flow" Earnings 1.0%
3.5% 5.5% 5.0% Midwest and its retail energy marketing mw gas-fired plant at a cost of $1.5 billion, Dividends -- 2.5% 2.5% business in Ohio for $2.8 billion. It is and wants to add further capacity beyond Book Value -. 3.0% 2.0% using $1.5 billion of the proceeds for an ac- this facility. Duke has a 40% stake in a QUARTERLY REVENUES ($ mill.) celerated stock buyback, and retaining the proposed $4.5 billion-$5.0 billion gas Cal* Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year rest of the cash in place of debt issuances. pipeline. However, the company had a set-2012 3630 3577 6722 5695 19624 Duke wrote down this discontinued opera- back in Indiana, where the reiulators re-2013 5898 5879 6709 6112 24598 tion last year in anticipation of a sizable jected a proposed seven-year, 1.9 billion 2014 6263 5708 6395 5559 23925 loss on the sale. system modernization plan. 2015 6065 5600 6800 5785 24250 The company has decided to retain its We look for solid earnings growth in 2016 6300 5850 7100 6050 25250 international operations. However, this 2015 and 2016. Duke is seeing modest Cal- EARNINGS PER SHARE A segment faces a challenging year due to growth at its regulated utility operations. Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year the stronger dollar and unfavorable condi- The use of the cash from the aforemen-2012 .86 .99 1.01 .59 3.71 tions (both hydro and economic) in Brazil. tioned asset sale is another plus. The com-2013 .89 .74 1.40 .94 3.98 Duke expects to complete an asset ac- pany is still incurring some costs assocla-2014 1.05 1.02 1.25 .81 4.13 quisition by rearend. The company has ted with the takeover of Progress Energy 2015 1.09 .90 1.60 .91 4.50 agreed to pay 1.2 billion for another utili- in 2012 ($0.18 a share last year and $0.02 2016 1.20 .95 1.65 .95 4.75 ty's 700-megawatt stake in nuclear and a share in the first quarter of 2015), but Cal* QUARTERLY DIVIDENDS PAID e
- coal-fired facilities in North Carolina. Var- these are diminishing, while the merger-Full endar Mar.31 Jun.30 Sen.30 Dec.31 Year ious regulatory approvals are required. related benefits should ramp up.
Management expects the purchase to boost The dividend yield of this stock is a 2011 .735 .735 .75 .75 2.97 2012 .75 .75 .765 .765 3.03 annual earnings by $0.05-$0.10 a share. cut above the utility mean. Total return 2013 .765 .765 .78 .78 3.09 We will not reflect this in our figures until potential to 2018-2020 is only about aver-2014 .78 .78 .795 .795 3.15 after the deal has been completed. age for the group. 2015 .795 Other projects are in various stages of Paul E. Debbas, CFA May22, 2015 (A) Dil. EPS. Exel. nonrec. losses: '12, 70¢; Next egs. report due early Aug. (B) Div'ds paid orig. cost. Rates all'd on com. e~. In '13 in Com~any's Financial Strength A '13, 24¢; '14, 67¢; gains (loss) on disc. ops.: mid-Mar., June, Sept., & Dec.
- Div'd reinv. NC/SC: 10.2%; in '09 In OH: 10.63~; In '04 In Stoc 's Price Stability 100
'12, ~; '13, 2¢; '14, (80¢); '15, 13¢. '12 & '13 filan avail. (C} Incl. intang. In '14: $38.94/sh. IN: 10.3%; earned on avg. com. eq., '14: 7.0%. Price Growth Persistence 55 EPS on'! add due to chng. In shs. or rounding. D) In mill., ad. for rev. split. (E) Rate base: Net Reg. Climate: NC Avg.; SC, OH, lN Above Avg. Earnings Predictabltlty 75 <> 2015 Value Line Publishing LLC. All lights reserved. Factual material Is ob1ained from sources believed to be reliable and Is provided without warranties of any kind. *, * ' THE PUBLISHER IS NOT RE PONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This Jublication Is slricUy for subscriber's own, non-commerdal, lntemal use. No part 111-..~ 1 *'~Ill"*-* ll*f'l;tllll'll/!1111:11 11 of it may be reproduced, resold, stored or ~nsmiued In any printed, elecuonlc or olher Imm, or use for generating or maiketing any printed or elecuonic pubficallon, service or proouct. * '
Schedule AHG-5 15-WSEE-115-RTS GREAT PLAINS EN'GY NYSE-GXP RECENT
/PRICE 26 ,09 /P/ERATIO 17 ,7(Trailing: 16.7) RELATIVE 096 DIV'D Median: 15.0 PIE RATIO , YLD 3.9%
._, *** ;;m TIMELINESS 3 Lowered 9/19/14 High: 35.7 32.8 32.8 33.4 29.3 20.5 19.9 22.1 22.8 24.9 29.5 30.3 Target Price Range t-=L=ow=:ccL-~2=7"".9'-'---"2,,,_7"'.1_,_.:;27. 1 26.9 15.6 10.2 16.6 16.3 19.5 20.4 23.8 25.6 201B 2019 2020 SAFETY 3 Lowered 11/26/08 LEGENDS 0.70 x Dividends sh r <
"1--l-~---l~-+-~-l---+--l--+---1-----lf---+---+64 TECHNICAL 3 Raised 3/20/15 divided by Interns Rate
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2018*20 PROJECTIONS """ * " ,.. * * * * * * * * *
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('"* ..* ........ .,,. % TOT. RETURN 2115 Institutional Decisions * ....... TH 202014 3Q2014 4Q20fl Percent 18 * ,,. ** ...... '*' * ....... .. ...... 1.-
- sro~K VL&:rf ..
to Buy 125 124 132 shares 12 Ill .I 1.,1 I l l - - 1 yr. 5.1 8.2 ,_ loSell 117 122 125 traded 6 I 11111 111111111 11111 11 3yr. 51.0 60.8 _ Hld'slOOO 118540 117299 119797 1111111111111 1111111111 1111111111 11111 1111111111 11111 :II .II II 5yr. 83.0 110.1 1999 2000 2001 2002 2003 2004 2005 2009 2010 2011 2012 2013 2014 2015 2016 VALUELINEPUB.LLC 8-20 14.50 18.02 23.61 26.91 31.04 33.13 34.85 14.51 16.62 17.03 15.05 15.90 16.65 17.50 18.40 Revenues per sh 19.50 3.63 4.63 4.70 4.40 4.69 4.75 4.54 3.27 4.12 3.51 3.45 4.01 4.01 4.10 4.65 "Cash Flow per sh 5.50 1.26 2.05 1.59 2.04 2.27 2.46 2.18 1.03 1.53 1.25 1.35 1.62 1.57 1.45 1.75 Earnings per sh A 2.00 1.66 1.66 1.66 1.66 1.66 1.66 1.66 .83 .83 .84 .86 .88 .94 1.00 1.06 Div'd Decl'd per sh
- 8 1.20 2.97 6.67 4.38 1.91 2.19 2.66 4.49 6.49 4.76 3.40 4.01 4.42 5.10 5.25 3.90 Cap'I Spending per sh 3.75 13.97 14.88 12.59 13.58 13.82 15.35 16.37 20.62 21.26 21.74 21.75 22.58 23.25 23.70 24.40 Book Value per sh 0 26.75 61.91 61.91 61.91 69.20 69.26 74.37 74.74 135.42 135.71 136.14 153.53 153.87 154.20 154.50 154.75 Common Shs Outst'g 0 155.50 20.0 12.4 15.9 11.1 12.2 12,6 14.0 16.0 12.1 16.1 15.5 14.2 16.5 Boldflg res are AvgAnn'IP/ERatlo 13.5 1.14 .81 .81 .61 ,70 .67 .75 1.07 .77 1.01 ,99 ,80 .87 ValueLlne RelativeP/ERatlo .85 6.6% 6.5% 6.6% 7.3% 6.0% 5.4% 5.5% 5.0% 4.5% 4.1% 4.1% 3.8% 3.6% estlnates Avg Ann'I Dlv'd Yield 4.6%
3200 315 Cal- QUARTERLY REVENUES ($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year 2012 479.7 603.6 746.2 480.4 2309.9 2013 542.2 600.3 765.0 538.8 2446.3 2014 585.1 648.4 782.5 552.2 2568.2 2015 600 650 850 600 2700 2016 625 700 900 625 2850 Cal* EARNINGS PER SHARE A Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year 2012 d.07 .41 .95 .03 1.35 2013 .17 .41 .93 .11 1.62 2014 .15 .34 .95 .12 1.57 2015 .15 .30 .90 .10 1.45 2016 .20 .40 1.00 .15 1.75 Cal* QUARTERLY DIVIDENDS PAID a* Full endar Mar.31 Jun.30 Sep,30 Dec.31 Year 2011 .2075 .2075 ,2075 .2125 .84 2012 .2125 .2125 .2125 .2175 .86 2013 .2175 .2175 .2175 .23 .88 2014 .23 .23 .23 .245 .94 2015 .245 (A) Oil. EPS. Exel. nonrec. ~ains (losses): '00, due to change In shs., '14 due lo rounding. 1'13: $6.62/sh. jD) In mill. (E) Rate base: Fair Company's Financial Strength B+ 49¢; '01, ($2.01); '02, (5¢); 03, 29¢; '04, (?¢); Next earnings report due early May. (B) Div'ds value. Rate alld on com. eq, in MO in '13: Stock's Price Stability 95 '09, 12¢; gain (losses) on disc. ops.: '03, 1,13¢); historically paid In mid-Mar., June, Sept. & Dec. 9.7%; In KS In '13: 9.5%; earned on avg. com. Price Growth Persistence 5 '04, 10¢; '05, (~¢); '08, 35¢. '12 EPS don I add
- Div'd reinvest. plan avail. (C) Incl. lntang. In eq., '13: 7.3%. Regulatory Climate: Average. Earnings Predictability 70
" 2015 Value Line Publishing LLC. All rights reseived. Factual material Is obtained from sources believed to be reliable and Is pmvlded 1*nlhout warranties or any kind. i!ll!lr!IWlllglii THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication Is stricily for subscriber's ovm, non-<:ommerclal, lnlernal use. No Rart I ta.""'~ ,,,_w,11 :Ull!m!llll:ll I or ii may be reproduced, resold, stored or transmitted in any printed, eleckonic or other l0<m, or used for generating or ma<keting any printed or electronk pubfication, service or prooucl.
Schedule AHG-5 15-WSEE-115-RTS IDACORP, INC. NYSE-IDA IRECENT PRICE 62 , 28 \P/E RATIO 15 , serailing:16.1) RELATIVE 081 Median: 14.0 PIE RATIO I DIV'D YLD 3.0%-- TIMELINESS 2 Raised 316115 High: 32.9 32.1 40.2 39.2 35.1 32.8 37.8 42.7 45.7 54.7 70.1 70.5 Tarfiet Price Range Low: 25.3 26.2 29.0 30.1 21.9 20.9 30.0 33.9 38.2 43.1 50.2 59.2 20 8 2019 2020 SAFETY 2 Raised 812113 - LEGENDS 1.00 x Dividends shr 120 t:::::d TECHNICAL 3 Lowered 511115 divided b~ lnleres Rale :'~:::_:.] 100
* * *
- Relalive rice Suenglh BETA .80 (1.00 "Markel) 0
.fil:~~~/i,~a Indicates recession
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""" ... 32 High 70 (+10%!
Low 55 (-10% Insider Decisions 6% NII ,, ..
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I ii lo Buy 2Q20U 3Q2014 4Q20!4 Percent 66 70 93 shares 15 .. II 1 yr. STOCK 16.8 INDEX 7.7 1~1w~111~~~t1111~,~~1~111,~~~~,111~~~1~015 10 " 3yr. 68.1 57.2 to Sell 106 106 97 traded 5 "'""'" 1111111 "' Hld'slOOO' 36553 36655 36077 I lllltllltt 1111111111 Ii 5yr. 112.7 94.5 1999 2000 2001 2002 2003 2004 2005 2006 2007 2 1
- 2016 ©VALUE LINE PUB. LLC 8-20 17.50 27.10 150.10 24.43 20.41 20.00 20.15 21.23 19.51 20.47 21.92 20.97 20.55 21.55 24.81 25.51 25.75 26.05 Revenues per sh 27.95 4.50 5.63 5,63 4.08 3.50 4.12 3.87 4.58 4.11 4.27 5.07 5.23 5.74 5.84 6.21 6.49 6.55 6.70 "Cash Flow" per sh 7.15 2.43 3.50 3.35 1.63 .96 1.90 1.75 2.35 1.86 2.18 2.64 2.95 3.36 3.37 3.64 3.85 3.75 3.80 Earnings per sh A 3.90 1.86 1.86 1.86 1.86 1.70 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.37 1.57 1.76 1.88 1.95 Dlv'd Decl'd per sh Bt. 2.25 2.95 3.73 4.78 3.53 3.89 4.73 4.53 5.16 6.39 5.19 5.26 6.85 6.76 4.78 4.68 5.45 6.05 6.05 Cap'I Spending per sh 6.00 20.02 21.82 23.15 23.01 22.54 23.88 24.04 25.77 26.79 27.76 29.17 31.01 33.19 35.07 36.84 38.85 40.70 42.60 Book Value per sh c 47.05 37.61 37.61 37.63 38.02 38.34 42.22 42.66 43.63 45.06 46.92 47.90 49.41 49.95 50.16 50.23 50.27 50.30 50.30 Common Shs Oulst'g o 50.30 12.7 10.9 11.4 18.9 26.5 15.5 16.7 15.1 18.2 13.9 10.2 11.8 11.5 12.4 13.4 14.7 Bold fig ~res are Avg Ann'I PIE Ratio 16.0
.72 .71 .58 1.03 1.51 .82 .89 .82 .97 .84 .68 .75 .72 .79 .75 .78 Value Line Relative P/E Ratio 1.00 eslln ales 6.0% 4.9% 4.9% 6.0% 6.7% 4.1% 4.1% 3.4% 3.5% 4.0% 4.5% 3.4% 3.1% 3.3% 3.2% 3.1% Avg Ann'I Dlv'd Yield 3.6%
CAPITAL STRUCTURE as of 12/31/14 859.5 926.3 879.4 960.4 1049.8 1036.0 1026.8 1080.7 1246.2 1282.5 1295 1310 Revenues ($mill) 1405 Total Debt $1615.5 mill. Due In 5 Yrs $223 mill. 63.7 100.1 82,3 98.4 124.4 142.5 166.9 168.9 182.4 193.5 190 190 Net Profit /$mill) 195 LT Debt$1614.4 mill. LT Interest $81.0 mill. 16.9% 13.3% 14.3% 16.3% 15.2% NMF NMF 13.4% 28.3% 8.1% 23.0% 23.0% Income Tax Rate 30.0% (LT Interest earned: 3.4x) 4.7% 4.0% 9.7% 10.2% 10.5% 19.7% 22.8% 7.1% 4.2% 4.4% 7.5% 8.0% AFUDC %lo Net Profit 9.5% Pension Assets-12/14 $559.7 mill. 50.0% 45.2% 48.9% 47.6% 50.2% 49.3% 45.6% 45.5% 46.6% 45.3% 45.0% 45.0% Long-Term Debt Ratio 45.0% Obllg. $844.8 mill. 50.0% 54.8% 51.1% 52.4% 49.8% 50.7% 54.4% 54.5% 53.4% 54.7% 55.0% 55.0% Common Eaulty Ratio 55.0% 2048.8 2052.8 2364.2 2485.9 2807.1 3020.4 3045.2 3225.4 3465,9 3567.6 3660 3840 Total Capital ($mill) 4330 Pfd Stock None 2314.3 2419.1 2616.6 2758.2 2917.0 3161.4 3406.6 3536.0 3665.0 3833.5 4095 4300 Net Plant 1$mlll) 4975 Common Stock 50,259,292 shs. 4.5% 6.2% 4.7% 5.3% 5.7% 6.0% 6.7% 6.5% 6.4% 6.6% 6.5% 6.0% Return on Tola! Cap'I 5.5% as of 2/13/15 6.2% 8.9% 6.8% 7.6% 8.9% 9.3% 10.1% 9.6% 9.9% 9.9% 9.5% 9.0% Return on Shr. Equity 8.5% 6.2% 8.9% 6.8% 7:6% 8.9% 9.3% 10.1% 9.6% 9.9% 9.9% ' 9.0% 9.0% Return on Com Equity E 8.5% MARKET CAP: $3.1 billion (Mid Cap) 1.3% 4.3% 2.4% 3.4% 4.8% 5.5% 6.5% 5.7% 5.6% 5.4% 4.5% 4.0% Retained to Com Eq 3.5% ELECTRIC OPERATING STATISTICS 80% 51% 64% 55% 46% 41% 36% 41% 43% 46% 49% 51% All Dlv'ds to Net Prof 58% 2012 2013 2014 BUSINESS: IDACORP, Inc. Is lhe holding company for Idaho enue breakdown: resldenlial, 45%; commercial, 27%; Industrial,
'h Cha1ue Re~il Sales (KWH) +2.6 +3.8 +1.4 Avg. In usl Use (MWHJim N/A NIA NIA Power, a utility thal operates 17 hydroeleclric generation develop- 16%; olher, 12%. Fuel sources: hydro, 35%; thermal, 40%; pur-Avg. lndusl Re~.~ (¢) 4.63 5.21 5.68 ments, 3 natural gas-fired plants, and partly owns three coal plants chased power, 24%. '14 depr rate; 3.8%. Has 2,021 employees.
Ci~ al Peak (Ml( NIA NIA NIA Peak Load, Swnmer ! ~1) 3245 3407 3407 across Idaho, Oregon, Wyoming, a_nd Nevada. Service territory Chairman: Robert A. Tinstman. President & CEO; Darrel T. Ander-hlnu~ Load Fador (~/i NIA NIA NIA covers 24,000 square miles, serving 516,000 business cuslomers. son. lncorp: Idaho. Address: 1221 W. Idaho Sl., Boise, ID 83702.
'h Change Cuslome~ yr-end) +1.1 +1.5 +1.4 Sells eleclrlclty in Idaho (95% of revenues) and Oregon (5%). Rev- Telephone: 208-388-2200. Internet: www.ldacorpinc.com.
F~edChruge Cov. ('~) 283 329 287 We are increasing our 2015 share-net quarterly dividend last September by 9.3% ANNUAL RATES Past Past Est'd '12-'14 estimate for IDACORP to $3.75. The to $0.47 per share. IDA is attempting to ol change (per sh) 10Yrs. 5Yrs. 10 '18-'20 Idaho-based utili~ delivered strong re- keep its ta1:et payout ratio between 50% Revenues 1.0% 3.0% 2.5% sults in 2014. In eed, per-share earnings and 60%. nnual dividend increases of "Cash Flow" 4.5% 6.5% 2.5% of $3.85 were well ahead of our call of over 5% are likely, until the payment Earnings 9.0% 10.0% 1.0% DMdends -- 6.0% 5.5% 6.0% $3.75. The outperformance was largely reaches the higher end of the *targeted Book Value 5.0% 4.0% driven by lower income tax expense during range. Further improvements on this front QUARTERLY REVENUES($ mill.) the year. In the fourth quarter of 2014, are likely to bring the company's payout Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year IDA completed the adoption of the new tax ratio closer to the industry average. 2012 241.1 254.7 334.0 250.9 1080.7 method related to Idaho Power's capital- IDACORP made some progress re-2013 264.9 303.9 381.1 296.3 1246.2 ized repairs reduction for all years prior to lated to the Boardman to Hemingway 2014 292.7 317.7 382.2 289.8 1282.5 2013. Going forward, based on the nature transmission line in 2014. On December 2015 295 335 395 270 1295 of annual capital additions, the method 19th, the Bureau of Land Management 2016 295 335 395 285 1310 change is expected to result in a small released the draft environmental impact Cal- EARNINGS PER SHARE A Full amount of continued benefit. Indeed, man- statement for the project. The proposed endar Mar.31 Jun.30 Sep.30 Dec.31 Year agement's earnings guidance for 2015 of 300-mile J:roject, which is to be developed 2012 .50 .71 1.84 .33 3.37 $3.65 to $3.80 per share was higher than on the regon-Idaho border, remains a 2013 .70 .93 1.46 .55 3.64 expected and reflects lower tax expense priority for IDA. After some roadblocks, 2014 .55 .89 1.73 .69 3.85 and improved cost management. The com- construction is now expected to begin in 2015 .65 .BO 1.80 .50 3.75 pany also does not expect to amortize any 2018 and completed after 2021. 2016 .70 .80 1.80 .50 3.80 Accumulated Deferred Investment Tax The Timeliness rank (2) of these Cal* QUARTERLY DIVIDENDS PAID st. Full Credits (ADITCs) in 2015. shares has risen* a notch. However, al-endar Mar.31 Jun.30 Seo.30 Dec.31 Year The company does not intend to file though we project strong dividend growth 2011 .30 .30 .30 .30 1.20 for a rate case. Indeed, no new requests over the 3~ to 5-year period, total return 2012 .33 .33 .33 .38 1.37 for rate increases are expected in Idaho or potential out to 2018-2020 is low at pres-2013 .38 .38 .38 .43 1.57 Oregon during 2015. ent, as the stock is already trading within 2014 .43 .43 .43 .47 1.76 Dividend hikes are likely in the year our Target Price Range. 2015 .47 ahead. The company increased its Saumya Ajlla May 1, 2015 !A) EPS diluted. Exel. nonrecurring gains Div'ds historically paid In late Feb., May, Aug., (E) Rate Base: Net original cost. Rale allowed Company's Financial Strength B++ loss): '00, 22¢; '03, 26¢; '05, (24¢); '06, 17¢. and Jale Nov.
- Dlv'd reinvestment plan avail. t on com. eq. In Idaho In '11: 9.5%-10.5%; Stock's Price Stability 95 Egs. may not sum to total due lo rounding. Shareholder lnveslmenl plan avail. (C) Incl. earned on avg. system com. eq., '14: 9.9%. Price Growth Persistence 85 Next earnings report due In earty May. (B) deferred debits. In '14: $25.26/sh. (D) In mill. Regulatory Cllmale: Above Average. Earnings Predictability 90 THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thi:J'ublication Is strlctly for subscribe(s own, noo-commercial. lnlemal use. No ~art l11a.~ l*,M I ' .11-~:fllll'll/!-
<> 2015 Value Une PublishinS LLC. All riii.t'ls reseived. Factual malerial Is ob1alned from sources believed to be reliable and Is provided 1~1hout warranties of any kind. of it may be ieproduced, resold, stored or uansmilled in any pnnled, elecuonic or olher form, or us [or generating or marketing any prinled or elecuonic pubfication, service or proouct
Schedule AHG-5 15-WSEE-115-RTS t--N_O_R_TH--=-W_E_S_T_E--.R-,--N-,--Nv.---sE_*N--.we_.------'l._,~~f_J~r--.--52_.8-r-8~1~_Xr10.----1_8--.--.0_(li----.:~:~_~;1_~:0-+-~1_eLil__,~b_0_.9.---2~~r_,.~_3_.7.------%----l TIMELINESS 2 Loweied 5/l/lS High: 28.2 32.5 35.8 36.7 29.7 26.8 Target Price Range
>-=L=ow=:~~2~4=.8~~2=5=.5~_,30.1 24.5 16.5 18.5 2018 2019 2020 SAFETY 3 New 514112 -
LEGENDS 0.77 x Dividends sh r TECHNICAL 3 towered 511/15 divided by Interns Rate -T.,_,-r---+----+--+----+--t----+----+---t---+--+-80
.. .. Relative Pnce Strength J * * * * * * * * *
- 60 t-B_E_TA~.7~ 0
=(l~.OO===M~a=rke=t)=>=---1 o,m;~~~/ir~a Indicates recession t--+-- -+--t--,,f----p.__..,.,.i.,,,,.rrnt"P..._-'t-.-,,---t---+--1--+ 50 2018*20 PROJECTIONS -+---l="""--t-~-hr~-'f---t---+--+---1----.,1---t-40 Ann'I Total ,1........ "*r,,
High P~~e (+~a~i.) R~~n 1---+----1=,1"11',l"-'Ti"c'l-'"'----+--"11-,,., =~rr.n;;mlirt'-"l=t----+----t---t---+--+---t----tl----+-~~ Low 40 (*25%) *2% __..- --t---+--+---+----t---t---+--+---t----!1---+20 Insider Decisions - i --t---+--+---+----t---t---+--+---t----!l---+15 JJASONDJF
~p~l~s gggggg 6 ~ g1---t-----::!,.or.,.-.....;;:;.,,:""'"-..ok:,:o.,,~ --t---+--+---+----t---t---+--+---t----!l---+10 to Sell a 0 a a a 0 a 0 0 1---+----t---t---+--',r:--T.,, .. * * ...........*........ ........... ** %TOT. RETURN 3/15 -7.5 Institutional Decisions " ..... .., ,.,... rn 1s VLARITH.'
to Buy lQ2~~ 0 ~~ ~~~~ Percent 30 +---+-+--+-,,.1111+.-;~1",,"'"""-- , , 71 3 2 1 yr. s~~~~ IN~~ :: to Sell 84 93 77 shares 20 10 II "'" "' *. 3 yr. 69.5 57.2 ,__ Hld'slOOO 38301 38766 46223 traded hlltlllill '"!II "'""ill 1111111111 1111111111 1111111111 1111111111 1111111111 11111111111 ii 5 yr. 145.8 94.5 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUELINEPUB.LLC ~8-20 29.18 32.57 31.49 30.79 35.09 31.72 30.66 30.80 28.76 29.80 25.68 27.65 29.80 Revenues per sh 33.50 3.20 4.00 3.62 3.70 4.40 4.62 4.76 5.42 5.18 5.45 5,39 6.25 6.65 "Cash Flow" per sh 7.75
-- d14.32 1.71 1.31 1.44 1.77 2.02 2.14 2.53 2.26 2.46 2.99 3.10 3.30 Earnings per sh A 3.75 1.00 1.24 1.28 1.32 1.34 1.36 1.44 1.48 1.52 1.60 1.92 2.00 Div'd Decl'd per sh a* t 2.25 2.25 2.26 2.81 3.00 3.47 5.26 6.30 5.20 5.89 5.95 5.76 6.50 6.50 Cap'I Spending per sh 5.75 19.92 20.60 20.65 21.12 21.25 21.86 22.64 23.68 25.09 26.60 31.50 32.65 34.00 Book Value per sh c 38.50 35.60 35.79 35.97 38.97 35.93 36.00 36.23 36.28 37.22 38.75 46.91 47.00 47.00 Common Shs Outst'g o 47.00 17.1 26.0 21.7 13.9 11.5 12.9 12.6 15.7 16.9 16.2 Bold fig res are Avg Ann'I P/E Ratio 14.0
.91 1.40 1.15 .84 .77 .82 .79 1.00 .95 .85 Value Line Relative PIE Ratio .90 3.4% 3.6% 4.1 % 5.4% 5.7% 4.9% 4.5% 4.2% 3.7% 3.3% estln ates Avg Ann'I Div'd Yield 4.3%
CAPITAL STRUCTURE as of 12/31/14 1165.8 1132.7 1200.1 1260.8 1141.9 1110.7 1117.3 1070,3 1154.5 1204.9 1300 1400 Revenues ($mill) 1575 Total Debt $1959.8 mill. Due In 5 Yrs $732.8 mill. 61,5 49,2 53.2 67.6 73.4 77.4 92.6 83,7 94.0 120.7 145 155 Net Profit 1$mlll) 180 LT Debt $1690.3 mill. LT Interest $81.6 mill. 38.5% 40.3% 37.8% 37.3% 17.2% 25.0% 9.8% 9.6% 13.2% 13.2% 16.0% 18.0% Income Tax Rate 22.0% Incl. $28.2 mill. capitallzed leases. (LT interest earned: 2.5x) 2.1% 3.3% 2.5% 2.3% 7.2% 22.7% 5.4% 15.2% 14.1% 14.4% 10.0% 10.0% AFUDC %to Net Profit 6.0% 44.3% 49.9% 50.1% 46.8% 56.4% 57.2% 52.2% 53.8% 53.5% 53.4% 50.0% 51.5% Long-Term Debt Ratio 48.5% Leases, Uncapitalized Annual rentals $2.0 mill. 55.7% 50.1% 49.9% 53.2% 43.6% 42.8% 47.8% 46.2% 46.5% 46.6% 50.0% 48.5% Common Eauity Ratio 51,5% Pension Assets-12114 $556.1 mill. 1324.0 1482.2 1648.4 1434.3 1803.9 1916.4 1797.1 2020.7 2215.7 3168.0 3075 3290 Total Capital ($mill) 3500 Oblig. $688.4 mill. 1409.2 1491.9 1770.9 1839,7 1964,1 2118.0 2213.3 2435.6 2690.1 3758.0 3920 4070 Net Plant {$mill\ 4375 Pfd Stock None 7.0% 5.2% 5.0% 7.0% 6.0% 6.0% 7.1% 5.5% 5.5% 4.8% 6.0% 6.0% Return on Total Cap'l 6.5% Common Stock 46,933,953 shs. 8.3% 6.6% 6.5% 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 9.5% 10.0% Return on Shr. Equity 10.0% as of 2/6/15 8.3% 6.6% 6.5% 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 9.5% 10.0% Return on Com Eaultv e 10.0% MARKET CAP: $2.5 billion (Mid Cap) 3.5% .7% .7% 2.3% 3.2% 3.5% 4.7% 3.2% 3.5% 3.8% 3.5% 4.0% Retained to Com Eq 4.0% ELECTRIC OPERATING STATISTICS 58% 90% 89% 74% 66% 63% 56% 65% 61% 54% 61% 60% All Dlv'ds to Net Prof 59% 2012 2013 201 ~ 1--B-U-Sl-NE~S-S_:_N~ort_h_W_e_soo-"rn-Co-~-o~ra-tl-on-(d~ol-ng_b_u_sl~ne_s_s-as_,___No_rt_h___,_5*-v.,-*o-lh~e-~-4-%-.G~e-n-er_a_lln~g-s-ou-r~_,___s_ar_e_n-ot_p_m-~-de_d_b_y_c~om_p_a-ny--l.
+.3 +1.3 %Change Relail Sales (K\\ll)
A1~. lndusL Use ~!'//HJ A1~. lndusL Revs. per K'lt\l (¢) NMF 29162 NA NA 28ta1 Western Energy) supplies electricity & gas In the Upper Midwest Fuel costs: 40% of revenues. '14 reported depreciation rate: 2.9%. NA and Northwest, serving 416,000 electric customers In Montana and Has 1,600 employees. Chairman: Dr. E. Linn Draper Jr. President & ci~ al Peak (f.lw) NA NA NA South Dakota and 277,000 gas customers In Montana (83% of CEO: Robert C. Rowe. incorporated: Delaware. Address: 3010 Peik Load, V.lnter~l~I 2108 2056 20~t gross margin), South Dakola (15%), and Nebraska (2%). Electric West 69th Street, Sioux Falls, South Dakota 57108. Telephone: A1mualloadFaclor(%) NA NA
%ChangeCuslomera [yr-end) +.8 +.7 +1.0 1--re_ve_n_ue_br_ea_k_do_wn_:_r_es_id_en_ti_al_,4_0_%_;_co_m_m_e_rc_ia_I,_51_%-'-;_ln_du_s_lri_al_,_60_5-_9_78_-_29_0_0._ln_te_rn_e_t:_www_._no_rt_hw_e_s_le_m_en_e-"rg.:..y._co_m_.- - - - - l -fa-ed-Ch-ar-ge-Cov-.(-%)_ _ _ _2_10--2-17--20-1 NorthWestern's earnings are likely to 10% on a common-equity rntio of 53.61%.
f-'A-N-N""u-'A'-L-RA_,,J_,,E_S_P_as-t-"'""'P-as-t--"-E'"'"st-'d-,1-2""_,1""4--l rise in 2015. This should occur despite a The utility expects to implement interim ofchange(persh) 10Yrs. 5Yrs. to'W20 tough comparison in the third quarter, rates in mid-2015. A full year of rate relief Revenues -.5% -3.0% 3.0% which was boosted by a $0.43-a-share tax should help lift the bottom line in 2016.
"Cash Flow" 5.5'."~ 4.5% 6.5% benefit in 2014. The key factor is the ac- NorthWestern's request for rehearing 5~7J1~~J5 _. ~:8~ ~:~~ quisition (for $900 million) of hydro gener- before the Federal Energy Regulatory BookValue 3.5% 5.5% 5.5% ating assets in late 2014. The utility re- Commission (FERC) has been pending t--Ca-l-~-QU-A-RT-E-Rl-Y-RE_VE_N_U_ES_(_$m-ll-l.)~-F-ul-1I ceived a $117 million rate hike in order to for almost a year. In 2011, a gas-fired endar Mar.31 Jun.30 Sep.30 Dec,31 Year place the newly purchased assets in the plant began commercial operation. The 201 2 309.1 244.6 235.8 280 .8 1070.3 rate base. Putting it all together, North- company believes that 80% of the facility's 2013 313.0 260.2 262.2 319.1 1154.5 Western is targeting share earnings of costs should be allocated to its Montana 2014 369.7 270.3 251.9 313.0 1204.9 $3.10-$3.30 this year. We have reduced ratepayers, with the remainder allocated 2015 346.0 305 300 349 1300 our estimate by $0.10 a share because the to its FERC-regulated wholesale custom-2016 400 320 310 370 1400 weather conditions in the first quarter ers. However, FERC ruled that only 4% of Cal* EARNINGS PER SHAREA Full were milder than normal. the costs should be allocated to wholesale endar Mar.31 Jun.30 Sep.30 Dec.31 Year The board of directors raised the divi- users. NorthWestern had already taken a 2012 .88 .31 .30 .7? 2.26 dend significantly in the first period. $0.12-a-share reserve in the second quar-2013 1.01 .37 .40 .68 2.46 The board raised the quarterly dividend by ter of 2012. The utility might appeal the 2014 1.17 .20 .77 .85 2.99 $0.08 a share (20%). This was designed to decision to the courts if FERC denies its 2015 1.09 .45 .55 1.01 3.10 produce a 60% payout ratio at the mid- request for rehearing. A favorable ruling 2016 1.25 .45 .55 1.05 3.30 point of management's earnings guidance. would allow NorthWestern to reverse some Cal* QUARTERLYDIVIDENDSPAIDB*t Full NorthWestern is targeting a payout ratio or all of the reserve.
endar Mar.31 Jun.30 Seo.30 Dec.31 Year of 60%-70%. Timely NorthWestern stock has an An electric rate case is pending in average valuation for a utility. The 2011 .36 *36 *36 *36 t 44 South Dakota. This is the company's first dividend yield and 3- to 5-year total return 2012 2013
.37
.38
.37
.38
.37
.38
.37
.38 1.48 1.52 e l ectnc . fil" ' mg in th e state since 1981 . potentia1 are near th e norms fior t h"1s m-
- 2014 .40 .40 .40 .40 1.60 NorthWestern is seeking a tariff hike of dustry.
2015 .48 $26.5 million (20.2%), based on a return of Paul E. Debbas, CFA May 1, 2015 (A) Diluted EPS. Exel. gain (loss) on disc. ops.: paid In late Mar., June, Sept. & Dec.* Div'd re-least. Rafe allowed on com. eq. in MT In '14 Company's Financial Strength B+ '05, (6¢); '06, 1¢; nonrec. gain: '12, 39¢ nel. Investment plan avail. t Shareholder Invest- (elec.): 9.8%; in '13 (gas): 9.8%; in SD In '11: Stock's Price Stability 100 '12 EPS don't add due to rounding. Nexl earn- ment plan avail. (C) Incl. defd charges. In '14: none specified; In NE In '07: 10.4%; earned on Price Growth Persistence 75 lngs report due late July. (B) Dlv'ds historically $17.28/sh. (D) In mill. (E} Rafe base: Net orig. avg. com. eq., '14: 10.8%. Regul. Climate: Avg. Earnings Predlctabllity 95 " 2015 Value Une Publishing LLC. All rights reserved. Factual material Is oblalned from sources believed lo be reliable and Is provided without warranties ol any kind. , THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's O\YO, non-oommerclal, Internal use. No ~art I 11a.i111 "~Ill".. -.11
- rl:fllil'llll1 lll(:Uj111_::11!
or it may be reproduced, resold, stored or transmillerl In any printed, electronic or other form, or used for generating or marketing any pnnled or electronic pubfication, service or proouct. -
Schedule AHG-5 15-WSEE-115-RTS OGE ENERGY CORP. NYSE-OGE RECENT
/PRICE 31 ,38 /PIERATIO 16, 2(Trailing:15.8) RELATIVE 088 DIV'D 3.4iJ/o-*
Median: 14.0 P/E RATIO , YLD /(
~1*l1;;m TIMELINESS 3 Raised 5/9/14 High: 13.5 15.3 l--"L""ow"":'-'-_1~1"-.4:...L-_1.,,2"".2'-'---\13.2 20.3 20.7 14.6 18.1 9.8 18.9 9.9 23.1 16.9 28.6 20.3 30.1 25.1 40.0 27.7 39.3 32.8 36.5 31.4 Target Price Range 2018 2019 2020 SAFETY 1 Raised 9119/14 LEGENDS TECHNICAL 3 Raised WJ/15 - 3:~~:d ~vi1~t~1~r ~~te 1i';1'1:'" ;-:- 1 00
* * *
- Relative ~rice Strength lt #"':: > :O'i 60 BETA .90 (1.00=Marl<et) 2*for*1 s~lit 7/13 ~;<'*-.< *: * -I L"*uo-50 1--~20~1~a.=2o~p=R~O~J=Ec=r=10=1N=s--;_~W:'.!!!*~~~~'!!./f'!.a'~~'"'a~in~dt~ca~1es~'~ec:=es~slo'!!'.nJ--t--:'f'"-t;-*.:~;.c:"::::..:"'i*l:::**c;*.1,----r--t---r-:;:::--r-::-.'r;;nr.;;;;r,;;;:t;~-t--i---r--ir---r40 0
Price Gain An~~t~~~al 1---t---l--+---+--'!l"~""'.2""~'"'*;:..;i'~i+*f~.:!c-+--l---..<;...,,,i< 1 1 11 111 1 10 11 1 1 ~=-.
-,.."""**"'*,cit*!>-' ;_-~':====-~L_'µ-1"-'r:L-----..+>----+--+-*-*_*_**+*-*_**-*+~~
~~~ ~g l!~8~l t~~ I ?-:Zic'{'; ;o.f "c!-- I" 20 11 l-=$.~~;;;:;;:~~~1='=':J=:.::::1:;11 11 1~1;:~*"*. . . . -~:;j* :f i*~*~*1~'"'-j'-'"-1-1--r--1-1--1-1--r--1-1-15 Insider Decisions 1
~~1;JJJJ1t! ~ ~\,. . . . . . ~., '.~I. . . . . . . . .*. . ~..:*~-. -. . %TOTi~,~rn~A~~!. f-~ 5 1
2Ql0H 302014 402014 Percent 18 I ; ( ,.....
- I I I 1 yr. ST~~~ IN~~ -
loBuy 134 147 171 shares 12 - loSell 141 125 134 traded 6 " L.111.lo' * * ,,f, 111 11 .1. *'"* ... 3yr. 33.4 60.8 ~ Hld's(ll-00 116179 117222 122042 111111111111111111111111111111111 5yr. 104.3 110.1 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 VALUELINEPUB.LLC '8-20 13.95 21.17 20.40 19.26 21.62 27.37 32.83 21.96 20.68 21.77 14.79 19.04 19.96 18.58 14.45 12.30 12.75 13.45 Revenues per sh 15.00 2.03 2.07 1.81 1.87 1.82 1.87 1.94 2.23 2.39 2.40 2.69 3.01 3.31 3.69 3.46 3.40 3.40 3.60 "Cash Flow" per sh 4.00
.97 .95 .65 .72 .87 .89 .92 1.23 1.32 1.25 1.33 1.50 1.73 1.79 1.94 1.98 1.85 2.00 Earnings per sh A 2.25
.67 .67 .67 .67 .67 .67 .67 .67 .68 .70 .71 .73 .76 .80 .85 .95 1.05 1.16 Div'd Decl'd per sh a* 1.55 1.16 1.15 1.44 1.49 1.04 1.51 1.65 2.67 3.04 4.01 4.37 4.36 6.48 5.85 4.99 2.85 2.75 2.80 Cap'ISpendlngpersh 2.50 6.55 6.83 6.67 6.27 6.87 7.14 7.59 8.79 9.16 10.14 10.52 11.73 13.06 14.00 15.30 16.25 17.10 17.95 BookValuepersh c 20.25 155.73 155.84 155.98 157.00 174.80 180.00 181.20 182.40 183.60 187.00 194.00 195.20 196.20 197.60 198.50 199.50 200.00 200.50 Common Shs Outst'g " 202.00 12.1 10.6 17.4 14.1 11.8 14.1 14.9 13.7 13.8 12.4 10.8 13.3 14.4 15.2 17.7 18.3 Bold fig res are Avg Ann'I PIE Rallo 17.0
.69 .69 ,89 .77 .67 .74 .79 .74 .73 .75 .72 ,85 .90 .97 .99 .97 Value Lin* Relative PIE Ratio 1.05 5.7% 6.6% 5.9% 6.6% 6.5% 5.3% 4.9% 4.0% 3.8% 4.5% 5.0% 3.7% 3.1% 2.9% 2.5% 2.6% *sllnates AvgAnn'IDlv'dYleld 4.1%
5948.2 4005.6 3797.6 2869.7 3716.9 166.1 226.1 244.2 258.3 295.3 30.2% 34.8% 32.3% 31.7% 34.9% 1.3% 3.8% 1.6% 9.1% 5.7% Leases, Uncapitalized Annual rentals $6.7 mill. 49.5% 45.6% 44.4% 50.6% 50.8% 50.5% 54.4% 55.6% 49.4% 49.2% Pension Assets-12/13 $654.9 mill. 2726.6 2950.1 3025.5 4058.6 4129.7 4652.5 5300.4 5615.8 5337.2 6000 6175 6555 Total Capital ($mill) 7975 Obllg. $658.1 mill. 3567.4 3867.5 4246.3 5249.8 5911.6 6464.4 7474.0 8344.8 6672.8 6979.9 7220 7465 Net Plant 1$mllll 8300 Pfd Stock None 7.6% 9.1% 9.5% 7.0% 7.9% 7.8% 7.8% 7.7% 8.6% 8.0% 7.5% 7.5% Return on Total Cap'I 7.0% Common Stock 199,319,096 shs. 12.1% 14.1% 14.5% 12.2% 12.7% 12.9% 13.4% 12.8% 12.8% 12.0% 11.0% 11.0% Return on Shr. Equity 11.0% 12.1% 14.1% 14.5% 12.2% 12.7% 12.9% 13.4% 12.8% 12.8% 12.0% 11.0% 11.0% Return on Com Equltv E 11.0% MARKET CAP: $6.3 blltlon (Large Cap) 3.4% 6.6% 7.1% 5.4% 6.0% 6.7% 7.7% 7.2% 7.3% 6.5% 5.0% 4.5% Retained to Com Eq 3.5% ELECTRIC OPERATING STATISTICS 72% 53% 51% 55% 53% 48% 43% 44% 43% 47% 56% 58% All Dlv'ds to Net Prof 68%
%Change Relail Sales (Kl'IH) 2011 2012 2211
+3.4 -1.8 .1 BUSINESS: OGE Energy Corp. Is a holding 779 ma Gas and Electric Company {OG&E), which supplies electricity to company for Oklaho- olher, 13%. Generallng sources: coal, 42%; gas, 32%; wind, 5%;
purchased, 21%. Fuel costs: 50% of revenues. '13 reported depre-A1~. lndusl Use ~\'/IHI 752 776 A1~. lndusl Re~. pet Kl\\i (¢) 5.37 5.07 5~i, 815,000 customers in Oklahoma (86% of eieclric revenues) and ciation rate (utlllty): 2.8%. Has 2,400 employees. Chairman &CEO: Ca~ al Pe<k (~ti\ 7115 7139 western Arkansas (9%); wholesale is (3%). Owns 26.3% of Enable Peter B. Delaney. President: Sean Trauschke. Inc.: Oklahoma. Ad-Peikload,Sumrnei!lll1) 7057 7000 6341 NA Midstream Partners. Acquired Transok 6/99. Eleclric revenue dress: 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma Annual Load Fador(~) 52.2 51.6
%Change Cuslome~ ~r-er,d) +.8 +1.1 +1.1 breakdown: residential, 42%; commercial, 26%; industrial, 19%; 73101-()321. Tel.: 405-553-3000. lntemet: www.oge.com.
F~edChargeC-Ov.(%) 427 404 367 OGE Energy's earnings are likely to New tariffs would take effect six months 1-A-N_N_u""AL_R_A~:r~E-S-P-as-t-"-'-P-as-t-'-Es...:.t'-d-,-.-,--i 1 1 1 3 decline this year. One reason is a proba- later, meaning that any rate relief the ofchange(persh) 10Yrs. 5Yrs. to'18-'20 ble falloff in equity income from the com- company gets this year will come too late Revenues -1.5% -4.0% NMF pany's 26.3% stake in Enable Midstream to help lift profits much in 2015. OG&E is "Cash Flow" 6.5% 8.5% 2.0% Partners, an oil and gas master limited also planning a rate case in Arkansas, pos-Earnings 9.5% 7.5% 3.0% h E l sibly by the end of the current quarter. Dividends 2.0% 3.0% 10.0% partners ip. nable has seen a dee ine in BookValue 8.0% 8.5% 5.5% the rig count in its operating area, and al- We look for earnings to recover next t-C-al*--r-QU"'A-RT-E-RL.,.,Y-R-,-EVE:-N-U-ES-(.,...$m-ll-l.)--.-F-ul--1I though most of its business is fee-based, year. We assume reasonable regulatory endar Mar.31 Jun.30 Sep.30 Dec.31 Year the drop in commodity prices is another treatment, and that the contribution from 35~7 1.,....2.,-1 1-2""0-12-r~a4""0""'.7---,8""55,.....0,........,1-11,...,3~.4-8-,-62.,....1,-\.,... negative factor. *Another reason is regula- Enable will be greater than in 2015 (but not back to the 2014 level). 2013 901.4 734.2 723.2 508.9 2867.7 tory lag at Oklahoma Gas and Electric, 2014 560.4 611.8 754.7 526.2 2453.1 due to higher depreciation, unrecovered OGE still intends to increase the divi-2015 575 625 800 550 2550 transmission costs, and the ending of a dend at an annual rate of 10% through 2016 600 675 850 575 2700 wholesale power contract. We have 2019. We note that the percentage decline ,_Ca-l*--+---E-A-RN-IN_G_S_PE_R_SH_AR_E_A_ __,_F-ul-<I slashed our earnings estimate by $0.25 a in expected distributions from Enable isn't endar Mar.31 Jun.30 Sep.30 Dec.31 Year share, to $1.85. Our revised estimate is nearly as large as that of expected equity f-2-0-12-+--.19--.4-8-~.9-4--.2-0-+--1-.79_, within OGE's guidance of $1. 76-$1.89. income. In addition, OGE's low payout 2013 .12 .46 1.08 .29 1.94 The utility is awaiting a ruling from ratio and solid finances give the board of 2014 .25 .50 .94 .29 1.98 the Oklahoma Corporation Commis- directors the wherewithal to increase the 2015 .20 .50 .95 .20 1.85 sion (OCC) on its envil'onmental com- disbursement rapidly. 2016 .20 ,55 1.05 .20 2.00 pliance plan, OG&E plans to spend $1.1 This high-quality stock is suitable for 1-C-al---1--QU_AR_T_E-RL-Y-Dl-VID-E-ND_S_P_Al_Da-._,1--F-ul-ll billion through 2019 to comply with EPA investors seeking dividend growth. endar Mar.31 Jun.30 Seo.30 Dec,31 Year mandates. The utility would recover these The quotation has fallen 12% so far in ,__20-11--+=.1=8~75~=.1=87~5~.~1B=~~.=="-l--_, 75 1 87 5 75 costs through riders on customers' bills. 2015, which has been a weak year for most utility issues. Even after the pullback, 2012 .19675 .19675 .19675 .19675 °79 After the OCC has issued its decision, 2013 .20875 .20875 .20875 .20875 :04 OG&E will file a general rate case (proba- though, the dividend yield is a cut below 2014 .225 .225 .225 .25 .93 bly in the June quarter) to address the the utility average. 2015 .25 aforementioned reasons for regulatory lag. Paul E. Debbas, CFA March 20, 2015 (A) Diluted EPS. Exel. nonrecurring losses: '02, 20¢; '03, 7¢; '04, 3¢; gains on discontinued op-Iduelate Jan., early May, (B) Dlv'ds historically paid In I(E) Rate base: Net original cost. Rate allowed Apr., July, Ocl.
- Div'd reinvest-
& on com. eq. In Oklahoma In '12: 10.2%; In Company's Flnanclal Strength Stock's Price Stability A+
90 erallons: '02, 6¢; '05, 25¢; '06, 20¢. '13 EPS ment plan available. (C) Incl. deferred charges. Arkansas In '11: 9.95%: earned on avg. com. Price Growth Persistence 90 don't add due to rounding. Next earnings report In '13: $1.91/sh. (D) In millions, adj. for split. eq., '13: 13.2%. Regulatory Climate: Average. Earnings Predlctablllty 95 0 2015 Value line Publishing LLC. All rights reseived. Factual material Is oblalned from sources believed to be reliable and Is provided v*thout warranties of any kind. THE PUBLISHER IS NOT RESPONSIBLEFOR ANY ERRORS OR OMISSIONS HEREIN. This publication Is strictly for subscribers own, nan-commercial, internal use. No P.art I 11 . .i111.,.111 ftllfl*I'
- I l~:lllll\11!111 l:llh11:ml cl it may be reproduced, resold, stored or transnulled In any printed, electronic or other (orm, or used for generating or marl<eting any prinled or electronic pubficaUon, service or proilucl
Schedule AHG-5 15-WSEE-115-RTS PG&E CORP. NYSE-PCG IRECENT PRICE 52 ,03 P/ERATIO 22 , oeailing:17.1) Median: 15.0 RELATIVE P/E RATIO 113 DIV'YLDD 3.5%1~~- I TIMELINESS 3 lowered 11119114 High: 34.5 40.1 48.2 52.2 45.7 45.8 48.6 48.0 47.0 48.5 55.2 60.2 Target Price Range Low: 25.9 31.8 36.3 42.6 26.7 34.5 34.9 36.8 39.4 39.9 39.4 51.1 2018 2019 2020 SAFETY 3 lowered 2/3/12 - LEGENDS 0.92 x Dividends f sh 120
~ ~:".k.':,;;: :>".:* '0:...;1 TECHNICAL 2 Raised 4/10/15 divided b~ lnteres Rate
* * * . Relative rice Strength '~?\
,,,,........ 100 80 BETA .65 (1.00
- Marl<el) 2018-20 PROJECTIONS o~~~~~/.i~a lndica/es recession .!
l 1 1
./ -- '
1,. ' ' ' - -.- .-... - 64
" 48 Ann'! Total 1111 111**
,*!,11111 1**111* '1111111111 111 ' 1101 1 1 1111 I 11* 11111 Price Gain Return 1
*111*'1 111
,11111
_...f~I 32 High 55 (+5~1 (-25Yo 5% ,,1lp11 1 VI Low 40 -2% 24 Ill 20 Insider Decisions ,-,.
.1 J J A S 0 ND J F lo Buy 0 0 0 0 0 0 0 0 0 1111 ... .. I ,." 16
.***** ........ ***** **..*****. ......*... .... 12 Options 0 0 1 0 0 0 0 0 0 to Sell 0 0 0 0 0 0 0 0 0 .. t : ~;! ....
Institutional Decisions 11 I I~ '
'-"l
"'j**,.. *1.,* .. ... % TOT. RETURN 3/15 -8 THIS VLARUH.'
2Q2014 3Q2014 4Q2014 Percent 12 I Ir ,1 I STOCK INDEX to Buy 206 210 270 shares Ill II Ill llllllllll 11111 1yr. 27.4 7.7 lo Sell 205 186 182 traded 8 Ill 3 yr. 36.7 57.2 -- Hld's/0001387652 390623 381385 4 ll 111111 11111111 lillllllllllll'"""" 5yr. 52.2 94.5 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 57.74 67.75 63.18 32.74 25.05 26.47 31.78 36,02 37.42 40.51 36.15 35.02 36.28 34.92 34.16 35,91 34.20 36.45 Revenues per sh 41.25 7.15 .80 5,66 1.14 4.80 5.71 7.12 7.76 8.02 8.44 8.37 8.22 8.08 7.32 6.33 8.13 7.60 8.30 "Cash Flow" per sh 9.50 2.24 d9.21 3.02 d2.36 2.05 2.12 2.35 2.76 2.78 3.22 3,03 2.82 2.78 2.07 1.83 3.06 2.60 3.05 Earnings per sh A 3.75 1.20 1.20 -- .. -* .. 1.23 1.32 1.44 1.56 1.68 1.82 1.82 1.82 1.82 1.82 1.82 1.82 Dlv'd Decl'd per sh
- t 2.10 6 4.39 4.54 7.33 7.94 4.08 3,72 4.90 6.90 7.83 10.05 10.68 9.62 9.79 10.74 11.40 10.16 11.00 11.00 Cap'I Spending per sh 11.00 19.10 8.19 11.89 9.47 10.12 20.62 19.60 22.44 24.18 25.97 27.88 28.55 29.35 30.35 31.41 33.09 34.55 35.95 Book Value per sh c 40.75 360.59 387.19 363.38 381.67 416.52 418.62 368.27 348.14 353.72 361.06 370.60 395.23 412.26 430.72 456.67 475.91 500.00 505.00 Common Shs Outst'g o 520.00 13.1 -- 4.8 -- 9.5 13.8 15.4 14.8 16.8 12.1 13.0 15.8 15.5 20.7 23.7 15.0 Bold Ilg res are Avg Ann'I P/E Ratio 12.5
.75 -* .25 .. .54 .73 .82 .80 .89 .73 .87 1.01 .97 1.32 1.33 .79 Value Line Relative PIE Ratio .BO 4.1% 4.8% *- .. -- .. 3.4% 3.2% 3.1% 4.0% 4.3% 4.1% 4.2% 4.2% 4.2% 4.0% es tin ates Avg Ann'I Dlv'd Yield 4.4%
CAPITAL STRUCTURE as of 12/31/14 11703 12539 13237 14628 13399 13841 14956 15040 15598 17090 17100 18400 Revenues ($mill) 21500 Total Debt $15683 mill. Due In 5 yrs $3406 mill. 904.0 1005.0 1020.0 1198.0 1168.0 1113.0 1132.0 893.0 828.0 1450.0 1290 1565 Net Profit ($mllll 1980 LT Debt$15050 mill. LT Interest $714 mill. 37.6% 35.5% 34.6% 26.2% 31.1% 33.0% 30.3% 23.9% 24.5% 19.2% 24.5% 25.0% Income Tax Rate 26.5% Incl. $69 mill. capitalized leases. (LT lnleresl earned: 3.5x) 5.6% 6.7% 9.4% 9.5% 11.9% 14.4% 11.2% 17.5% 17.9% 10.0% 12.0% 10.0% AFUDC %to Net Profit 8.0% Pension Assets-12/14 $14216 mill. 48.3% 51.7% 52.6% 52.2% 51.4% 49.6% 48.8% 48.7% 46,6% 48.5% 48.5% 49.5% Long-Tenn Debt Ratio 48.5% Obllg. $16696 mill. 50.0% 46.8% 46.1% 46.5% 47.4% 49.3% 50.2% 50.4% 52,5% 50,7% 51.0% 49,5% Common Equity Ratio 51.0% Pfd Stock $252 mill. Pfd Dlv'd $14 mill. 14446 16696 18558 20163 21793 22863 24119 25956 27311 31050 33925 36575 Total Capital ($mill) 41700 4,534,958 shs. 4.36% to 5%, cumulalive and $25 19955 21785 23656 26261 28892 31449 33655 37523 41252 43941 46900 49825 Net Plant ($mllll 58300 par, redeemable from $25.75 to $27.25; 5,784,825 shs. 5.00% to 6.00%, cumulative nonredeemable 8.1% 7.6% 7.4% 7.8% 6.7% 6.2% 5.9% 4.7% 4.2% 5.8% 5.0% 5.5% Return on Total Cap'I 6.0% and $25 par. 12.1% 12.5% 11.6% 12.4% 11.0% 9.6% 9.2% 6.7% 5.7% 9.1% 7.5% 8.5% Return on Shr. Equity 9.0% Cammon Stock 475,913,404 shs. 12.3% 12.7% 11.8% 12.6% 11.2% 9.7% 9.2% 6.7% 5.7% 9.1% 7.5% 8.5% Return on Com Equity e 9.5% MARKET CAP: $25 billion (Large Cap) 7.7% 6.8% 6.0% 6.8% 5.5% 3.9% 3.4% 1.0% .2% 3.9% 2.0% 3.5% Retained to Com Eq 4.0% ELECTRIC OPERATING STATISTICS 39% 47% 50% 47% 52% 61% 63% 85% 96% 58% 70% 59% All Dlv'ds to Net Prof 56% 2012 2013 2014 BUSINESS: PG&E Corporation Is a holding company for Pacific 8%; gas, 7%; purchased, 64%. Fuel costs: 38% of revenues, '14
°h Ch~e Re~il Sales (KWH) +6.0 +,5 -.2 Al'!J.I ustUse~IVt\i~ NA NA NA Gas and Electric Company and nonutility subsidiaries, Supplies reported depreciation rate (utility): 3.8%. Has 22,600 employees.
A1~. loousl Rew. fief (¢) 9.17 9,28 9.98 electricity and gas to most or northern and central Calirornla. Has Chairman, President & Chief Execulive Officer: Anthony F. Earley, Ca~alPeak~lw( NMF NMF NMF 5.3 million electric and 4.4 million gas customers. Electric revenue Jr. Incorporated: California. Address: One Market, Spear Tower, Peak load, Summeq t11) NMF NMF NMF breakdown: residential, 38%; ccmmercial, 40%; Industrial, 12%; ag- Suite 2400, San Francisco, California 94105. Telephone: 415-267-AnnualloadFaclor(~I NMF NMF NMF
%ChangeCusl<J1rera If-end) +.5 +.3 +.6 ricultural, 9%; olher, 1%. Generating sources: nuclear, 21%; hydro, 7000. Internet: www.pgecorp.com.
F~ed Charge Cov. (%) 231 223 304 PG&E was hit with heavy penalties of the penalties. Along with $400 million-ANNUAL RATES Past Past Est'd '12*'14 stemming from a gas /tipeline explo- $600 million of new equity for other pur-or change (per sh) 10Yrs. 5Yrs. to '18*'20 sion in San BJ."uno, Ca ifoJ."nia in Sep- poses, PG&E will probablf wind up issu-Revenues 2.0% -1.5% 3.0% tember of 2010. The accident ldlled eight ing more than $1 billion o stock this year.
"Cash Flow" 6.5% -2.5% 4.5% people, injured dozens more, and caused All of tWs makes earnings in 2015 and Earnings 14.5% -5.0% 8.5%
Dividends -- 3.0% 2.5% extensive property damage. The California 2016 more unpredictable than usual. Book Value 9.0% 4.0% 5.0% Public Utilities Commission fined the utlli- A gas transmission and storage rate QUARTERLY REVENUES ($ mlll.) ty $300 million; ordered a $400 million case is pending. PG&E asked for in-Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year one-time bill credit to PG&E's gas custom- creases of $555 million in 2015, $61 mil-2012 3641 3593 3976 3830 15040 ers, to be paid in February of 2016; or- lion in 2016, and $168 million in 2017. 2013 3672 3776 4175 3975 15598 dered the company to swallow $850 mil- New rates will be retroactive to the start 2014 3891 3952 4939 4308 17090 lion of future gas safety work that other- of 2015. However, the discovery of ex parte 2015 3750 4150 4850 4350 17100 wise would have been collected in rates; communications between PG&E and the 2016 4350 4350 5100 4600 18400 and imposed some remedies on the utili- commission might well affect the decision. Cal- EARNINGS PER SHARE A ty's gas operations, which will amount to We expect no dividend increase any-Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year an estimated $50 million. Note that PG&E time soon. Ui;iderstandably, the board 2012 .66 .55 .87 d.01 2.07 has already incurred or committed to $2.8 hasn't raised the payout since the acci-2013 .55 .74 .36 .19 1.83 billion of p;peline safety enhancement dent. The size of the penalties might well 2014 .49 .57 1.71 .27 3.06 costs over an above these penalties . preclude any change in the near future. 2015 .35 .70 1.05 .50 2.60 How will this affect earnings? PG&E We advise investors to look elsewhere. 2016 .65 .75 1.10 .55 3.05 has already taken a reserve for a $200 mil- Despite the heavy penalties that PG&E Cal* QUARTERLY DIVIDENDS PAID a* t Full lion fine, and the additional $100 million was hit with, the uncertainty about the endar Mar.31 Jun.30 Sea.30 Dec.31 Year will be excluded from our earnings presen- aforementioned rate case, and the lack of 2011 .455 .455 .455 .455 1.82 tation as a nonrecurring item. Be~ond visibility for the next dividend hike, the 2012 .455 .455 .455 .455 1.82 that, we do not know how (and when the yield is only average for a utility. The 2013 .455 .455 .455 ,455 1.82 rest of the penalties will be accounted for, share price is down slightly this year, in 2014 .455 .455 .455 .455 1.82 but will include them in our presentation . line with most utility issues. 2015 .455 .455 The company will issue equity as a result Paul E. Debbas, CPA May 1, 2015 I I (A) Diluted EPS. Exel, nonrec. gains Oossesf '14 due to change in shs. Next earnings report Incl. intang. In '14: $13,28/sh. (DJ In mill. Comf any's Financial Strength '99, ($2.44); '04, $6.95; '09, 18¢; '11, (68¢ ; due late July. (B) Div'ds historically rrald In mid- (E) Rate base: net orig. cosl. Rate a lowed on Sloe 's Price Stability B+ 100 '12, (15¢); 10 '15, (21¢); gain from disc. o s.: Jan., Apr., Jul , and Ocl.
- Div'd re nvest. plan com. eq. In '15: 10.4%; earned on avg. com. Price Growth Persistence 45
'08, 41¢. '13 EPS don't add due to roundfng, avail. t Shareholder inveslment plan avail. (CJ eq., '14: 9.5%. Regulatory Climate: Above Avg. Earnings Predictability 70 " 2015 Value Line Publlshin~ LLC. Alf rtghls reserved. Factual material Is obtained from sources befleved 10 be renable and is provided without warranties of an~ kind. THE PUBLISHER IS NOT RE PONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. Thl~ublication Is strictly for subscriber's ovm, non-commercial, lnlemal use. o~art I I of ii may be reproduced, resold, stored or kansmilled in any printed, eleckonic or other form, or us for generating or marl<eting any printed or efeckonic pubUcation, service or pro<fucl.
,~, ... t I llllJ*maE
Schedule AHG-5 15-WSEE-115-RTS ~~-;-7~~;-;-;;;~;;;------,-::::;:;;:----:--:-T.::=-----:---z-.::---::-:'1r:::-:=::---::--:-=-r::::::----::--::-:--:'li...,. ...'l'!"m,--* -** PINNACLE WEST NYSE-PNW l~~fJeNT 62.91l~rio17.00:~i~~;K~H~L~~~ 0.87 ~~~o 3.9%1ii1__-i TIMELINESS 3 Lowered 10110ll4 High: 45.8 46.7 51.0 51.7 42.9 38.0 42.7 48.9 54.7 61.9 71.1 73.3 Target Price Range t-=L=ow=:~_,.3=6=.3~~3=9=.8~_,38.3 36.8 26.3 22.3 32.3 37.3 45.9 51.5 51.2 61.5 2018 2019 2020 SAFETY 1 Raised 513113 LEGENDS TECHNICAL 3 lowered 511115 - dividedx Dividends 0.70 r by Interns Rate
. . . . Relative Price Strength sh '=+==m~:(SB;:~+=~==+:;;::;;;=+==1==+=~==+==+==+==+120 t- ~c.,~.:~ *
-- '>I: :*: I
/ ..._
100 80 1-B_E_TA=20~~~~-=2~~*~=oR==;~Ja=:c=ei""io=JN.,.:S--i ~~~~~~~r~a indicales recession :;:~:=::!=~-f_/=:,-;:,,..,mt--/rt"-'-'""l'f-~-"'--111_,,-t-'-1'_"'_1 ~_,i-t' _*_-*_,'-+*----+--+-=-=-=---=+=-=:_:_:+:: 0 1 11 t-+---: Ann'I Total ,,1* ** 11* 1 11 11 ,, 1111 1 11 I i *-- 1 II"' Price Gain Return .. !'I 11 1* ii 11 11 1 11* 111 "'*'\ _,, 1 1n 11 ii" ' ' ** High 70 (+10%! 7% ltit"=':::::j===l===l:=='i--=- '*"'1-t-"---+--t---t----t---t---+--t---+---t--+32 Low 55 (*15% 1% ., C---t----1---+---+---l--+---l---+---+---l--+24 Insider Decisions , .. --+---+--+----+----t---+---+--+----+---t--+-20 J J A S 0 N D J F t-'"""->r.**'"""',.-:;*""'"'"'*--,,.,,,.,,,,--,,,-,,+,- - + - - --+---+--+---+---!---+---+--+---+---l---t-16 loBuy Options 0 0 0 0 0 0 0 0 0 1 O O O O O O O a a ---+----+---fr. ***"'**'""I *.,
-+"-'~.,......,.,,.
--+---+--+---:--+---!---+---+--+---t----l---t-12 lo Sell o a o a a 5 3 a a '**" '*, ,*"*., ,.,.*. .,.' ""'*.,, ,, % TOT. RETURN 3115 _ 8 Institutional Decisions * ~""""
202014 3Q2014 402014 '
- I I 11. , s1~~K VLiffri~f _
lo Buy 169 171 191 Phrcenl ~5 111u11 1yr. 21.2 7.7 _
"' 000 tHold~*s',11 11 1 163 878 0 7 887 91 884 01 18 8 ~~~J 5 11111111111 11111111111 111 t1 1111111111 1111111111111111111111 Ill 11 11111111111 111
- - + - - i 3 yr.
syr. 49,8 110.1 57_2 _ 94.5 l-'1;:;;9:,,::99?.:2:-;:0::::00::-.:2"=0'="01~2"=0~02=-i-,2=0=03~2=0-=--04.,J¥1!21!'0-!!'05,J!.l/J!21!'0-!!'06~21!'0¥!07Ll,ll/.1!21!'01!!108~21!'01!!109!li/J,2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 30.16 34.03 35,07 33,37 32.50 30.01 29.67 30.09 31.35 31.58 5.76 9.70 9.29 8.13 8.08 6.85 7.52 7.92 8.15 8.09 2.24 3.17 2.96 2.12 2.26 3.08 2.99 3.50 3.66 3.58 1.93 2.03 2.10 2.10 2.10 2.10 2.10 2.67 2.23 2.33 6.39 7.59 9.37 9.46 7.64 7.03 8.26 8.24 9.36 8.38 34.57 34.48 35.15 34.16 32.69 33.86 34.98 36.20 38.07 39.50 99.08 99.96 100.49 100.89 101.43 108.77 109.25 109.74 110.18 110.57 19.2 13.7 14.9 16.1 13.7 12.6 14.6 14.3 15.3 15.9 1.02 .74 .79 .97 .91 .80 .92 .91 .86 .84 4.5% 4.7% 4.8% 6.2% 6.8% 5.4% 4.8% 5.3% 4.0% 4.1% CAPITAL STRUCTURE as of 12/31114 2988.0 3401.7 3523.6 3367.1 3297.1 3263.6 3241.4 3301.8 3454.6 3491.6 3600 3750 Revenues ($mill) 4400 Total Debt $3562.2 mill. Due In 5 Yrs $1577.0 mlll. 223.2 317.1 298.8 213.6 229.2 330.4 328.2 387.4 406.1 397.6 430 450 Net Profit ($mllll 540 LT Debt $3031.2 mill. LT Interest $160.4 mill. t-::-=-=,.-+=--:=-'!-:::-:-=--+-o~c-+-=-=-+"-=-c=-+~~'"=~-+-o'7"Ccc+"77"~+-=-=-=%.,-+-=--:,.,.,.,,,__--::T~,...,...--+-=-=-=7-t 36.2% 33.0% 33.6% 23.4% 36.9% 31.9% 34.0% 36.2% 34.4% 34.2% 35.0'o 35.0% Income ax Rate Incl. $13.4 mlll. Palo Verde sale leaseback lessor 35.0% notes. 10.4% 11.1% 14.8% 17.5% 11.2% 11.7% 12.8% 9.7% 10.0% 11.6% 9.0% 11.0% AFUDC %to Net Profll 7.0% (LT interest earned: 4.8x) 43.2% 48.4% 47.0% 46.8% 50.4% 45.3% 44.1% 44.6% 40.0% 41.0% 44.0% 45.0% Long-Term Debt Ratio 44.0% Leases, Uncapitalized Annual rentals $18.0 mill. 56.8% 51.6% 53.0% 53.2% 49.6% 54.7% 55.9% 55.4% 60,0% 59.0% 56.0% 55.0% Common Eaulty Ratio 56.0% Pension Assets-12/14 $2615.4 mill. 6033.4 6678.7 6658.7 6477.6 6686.6 6729.1 6840.9 7171.9 6990.9 7398.7 8150 8565 Total Capital ($mlll) 9975 Obllg. $3078.7 mill. 7577.1 7881.9 8436.4 8916.7 9257.8 9578.8 9962.3 10396 10889 11194 11785 12530 Net Plant 1$mllll 14100 Pfd Stock None 5.0% 6.2% 5.9% 4.7% 4.8% 6.5% 6.4% 6.8% 7.1% 6.4% 6.5% 6.5% Return on Total Cap'I 6.5% Common Stock 110,475,189 shs. 6.5% 9.2% 8.5% 6.2% 6.9% 9.0% 8.6% 9.8% 9.7% 9.1% 9.5% 9.5% Return on Shr. Equity 9.5% as of 2/13/15 6.5% 9.2% 8.5% 6.2% 6.9% 9.0% 8.6% 9.8% 9.7% 9.1% 9.5% 9.5% Return on Com Equity E 9.5% MARKET CAP: $6.9 billion (Large Cap) 1.0% 3.4% 2.5% .3% .7% 3.1% 2.8% 4.1% 4.1% 3.5% 3.5% 3.5% Retained to Com Eq 3.5% ELECTRIC OPERATING STATISTICS 85% 63% 70% 96% 89% 66% 68% 58% 58% 62% 63% 63% All Dlv'ds to Net Prof 64% 2012 2013 2~:i t-.,-B~U-Sl-N~ES_S_:_P-in~na,-cl_e_W~e-st-C-ap-lt~al_C_or_p_or~af,-lo_n_ls-a~h-ol-dln-g~c~om_p_a--~co-m-m-e~~-la-l,-3-9o/c~,;-l-nd,-u-str~la,-l,-5-%~;~ot-he-r-,9,-o/c,-o.-G-e-ne-ra-ti-ng~so-ur-ce-s-;:
%Change Re~il Sales (KWH) -.2 *.2 A1~. lndusl Use (l.IWHl 647 644 659 ny for Arizona Public Service Company (APS), which supplies elec- coal, 34%; nuclear, 27%; gas & olher, 17%; purchased, 22%. Fuel A1~. lndusl Revs. {lei KWH(¢) 7.86 8.21 8.26 tricity to 1.1 milflon customers In most of Arizona, except about half costs: 34% of revenues. Has 6,400 employees. '14 reported Capa¢)' al Peak(l.hvl 8864 8398 9259 of lhe Phoenix metro area, lhe Tucson metro area, and Mohave deprec. rate: 2.8%. Chairman, President & CEO: Donald E. Brandl.
Peak load, Summei \Mn) 7207 6927 7 °£~ County in northwestern Arizona. Discontinued Suncor real estate Inc.: AZ.. Address: 400 North Fifth SI., P.O. Box 53999, Phoenix, AZ. Annualloadfaclor(~) 48.8 50.0 4
%Change Cuslcmeis (yr-end) +1.3 +1.4 +1.2 subsidiary In '10. Electric revenue breakdown: residential, 48%; 85072-3999. Tel.: 602-250-1000. Internet: WIWl.pfnnaclewest.com.
1Pinnacle
- - - - -West's ---- ------------------------------i earnings should ad- The cost of the project would be $600 foed Charge Cov. (%\ 397 419 404 ANNUAL RATES Past Past Est'd '12*'14 vance solidly this year. At the start of million-$700 million, and completion is of change (per sh) 10 Yrs. 5 Yrs. to '18-'20 2015, the company's Arizona Public Ser- targeted for the second quarter of 2018.
Revenues * - -1.5% 3.0% vice (APS) subsidiary received a $57.1 mil* However, APS had to conduct a request for "Cash Flow" 1.5% -1.0% 4.0% lion rate hike in order to place its newly proposals for about 300 mw in case there Earnings 3.5% 8.0% 4.0% purchased stake in Units 4 and 5 of the is a more attractive alternative. The win-Dividends 3.5% 3.0% 3.5% Book Value 2.0% 2.0% 3.5% Four Corners coal-fired plant into the rate ning bidder should be determined soon. Cal* QUARTERLY REVENUES($ mill.) Full base. (Note that APS has reached a deal to The company seeks to increase the endar Mar.31 Jun.30 Sep.30 Dec.31 Year buy another utility's 7% stake in these grid access charge for solar users. 2012 620.6 878.6 1109.5 693.1 3301.8 units.) The company benefits from regula* Now about $5 a month, APS wants the 2013 686.6 915.8 1152.4 699.8 3454.6 tory mechanisms that provide for current state commission to raise this to $21. The 2014 686.2 906.3 1172.7 726.4 3491.6 cost recovery of some ldnds of capital utility is concerned about the subsidiza* 2015 700 950 1200 750 3600 spending, such as transmission. Customer tion of solar customers by nonsolar cus-2016 725 1000 1250 775 3750 growth is above the industry average. We tamers. There is no timetable for the regu-Cal* EARNINGS PER SHARE A Full assume normal weather patterns - unfa- lators to act on APS' request. endar Mar.31 Jun.30 Sep.30 Dec.31 Year vorable weather reduced earnings by $0.10 The stock price is down 13% since our 2012 d.07 1.12 2.21 .24 3.50 a share last year. Our earnings estimate is January report. We think this is merely 2013 .22 1.18 2.04 .22 3.66 at the midpoint of management's targeted a correction. Three months ago, the quota* 2014 .14 1.19 2.20 .05 3.58 range of $3.75-$3.95 a share. tion was above our 3- to 5-year Target 2015 .20 1.25 2.20 .20 3.85 We forecast a modest p1*ofit increase Price Range. Even following the recent 2016 .20 1.30 2.30 .20 4.00 in 2016. The utility will benefit from the falloff, however, the stock is trading near Cal* QUARTERLY DIVIDENDS PAID 0
- Full same regulatory mechanisms as men- the midpoint of our long-term price projec-endar Mar.31 Jun.30 Seo.30 Dec.31 Year tloned above. Customer growth should be tion, thereby making total return pros-2011 .525 .525 .525 .525 2.10 another plus, as well. pects unexciting. Conservative accounts 2012 .525 .525 .525 .545 2.12 The utility wants to add some gas- stressing income might like this equity for 2013 .545 .545 .545 .5675 2.20 fired generating capacity. APS would its dividend yield (slightly above the utili-2014 .5675 .5675 .5675 .595 2.30 build 510 megawatts and retire 220 mw of ty average) and top-notch Safety rank.
2015 .595 old facilities, for a net increase of 290 mw. Paul E. Debbas, CFA May 1, 2015 (A) Diluted EPS. Exel. nonrec. losses: '02, 77¢; Nexl earnings report due early Aug. (Bl Div'ds charges. In '14: $12.30/sh. (D) In mill. (E) Rate Company's Financial Strength A+ '09, $1.45; excl. gains (losses) from disconlin- historically paid In early Mar., June, Sept., & base: Fair value. Rate allowed on com. eq. In Stock's Price Stablllty 100 ued ops.: '00, 22¢; '05, (36¢); '06, 10¢; '08, Dec. There were 5 declarations In '12.
- Div'd '12: 10%; earned on avg. com. eq., '14: 9.3%. Price Growth Persistence 28¢; '09, (13¢); '10, 18¢; '11, 10¢; '12, (5¢). relnveslment plan avail. (C) Incl. deferred Regulatory Climate: Average.
" 2015 Value Une Publishing LLC. NI rights reserved. Factual material Is oblalned from sources believed to be reliable and Is provided ,;thout warranties or any kind. THE PUBLISHER IS NOT RESPONSIBLEFOR ANY ERRORS OR OMISSIONS HEREIN. This pubfication Is strkUy for subscriber's o,m, non-commercial, Internal use. No ~art I 111. *~
- 11<:mw, of it may be reproduced, resold, stored or uansmitted in any printed, electron!( or other form, or used !or geneiating or nrarketing any printed or elecUonlc pubfication, service or proifucl.
rm Earnings Predictability ifllf " 111 1111 :I I II 60 65
TIMELINESS SAFETY TECHNICAL 24.32 27.87 27.89 23.99 23.67 24.06 23.89 23.18 24.29 25.25 4.64 5.21 4.71 4.07 4.82 4.96 5.15 4.93 6.08 7.00 1.14 2.33 1.39 1.31 1.66 1.95 1.87 1.77 2.18 2.75
.68 .93 .97 1.01 1.04 1.06 1.08 1.10 1.12 1.55 5.94 7.28 6.12 9.25 5.97 3.98 4.01 8.40 12.87 3.50 19.58 21.05 21.64 20.50 21.14 22.07 22.87 23.30 24.43 30.50 62.50 62.53 62.58 75.21 75.32 75.36 75.56 78.09 78.23 89.50 23.4 11.9 16.3 14.4 12.0 12.4 14.0 16.9 15.3 13.0 1.26 .63 .98 .96 .76 .78 .89 .95 .81 .BO 2.5% 3.3% 4.3% 5.4% 5.2% 4.4% 4.1% 3.7% 3.3% 4.4%
CAPITAL STRUCTURE as of 12/31/14 1446.0 1520.0 1743.0 1745.0 1804.0 1783.0 1813.0 1805.0 1810.0 1900.0 1975 2075 Revenues ($mill) 2250 Total Debt $2501 mill. Due in 5 Yrs $875 mill. 64.0 71.0 145.0 87.0 95.0 125.0 147.0 141.0 137.0 175.0 195 220 Net Prom ($mill) 245 LT Debt $2126 mill. LT Interest $115 mill. 40.2% 33.6% 33.8% 28.7% 28.8% 30.5% 28.3% 31.4% 23.2% 26.0% 20.0% 20.0% Income Tax Rate 20.0% (LT interest earned: 2.5x) Leases, Uncapitalized Annual rentals $1 Omill. 18.8% 33.8% 17.9% 17.2% 31.6% 17.6% 5.4% 7.1% 14.6% 33.7% 13.0% 7.0% AFUDC 'lo to Net Profit 3.0% 42.3% 43.4% 49.9% 46.2% 50.3% 53.0% 49.6% 47.1% 51.3% 52.7% 48.5% 48.5% Long-Term Debt Ratio 48.5% Pension Assets-12/14 $591 mill. 57.7% 56.6% 50.1% 53.8% 49.7% 47.0% 50.4% 52.9% 48.7% 47.3% 51.5% 51.5% Common Eaulty Ratio 51.5% Obllg. $777 mill. 2076.0 2161.0 2629.0 2518.0 3100.0 3390.0 3298.0 3264.0 3735.0 4037.0 4420 4650 Total Capital ($mill) 5300 Pfd Stock None 2436.0 2718.0 3066.0 3301.0 3858.0 4133.0 4285.0 4392.0 4880.0 5679.0 6025 6125 Net Plant 1$mllll 6050 Common Stock 78,228,827 shs. 4.6% 4.7% 6.9% 5.0% 4.5% 5.4% 6.2% 5.9% 5.1% 5.8% 5.5% 6.0% Return on Total Cap'I 6.0% as of 2/10/15 5.3% 5.8% 11.0% 6.4% 6.2% 7.9% 8.8% 8.2% 7.5% 9.2% 8.5% 9.0% Return on Shr. Equity 9.0% 5.3% 5.8% 11.0% 6.4% 6.2% 7.9% 8.8% 8.2% 7.5% 9.2% 8.5% 9.0% Return on Com Eaultv E 9.0% MARKET CAP: $2.9 billion (Mid Cap) 5.3% 3.5% 6.6% 2.0% 1.5% 3.0% 4.1% 3.5% 2.9% 4.6% 4.5% 4.5% Retained to Com Eq 4.0% ELECTRIC OPERATING STATISTICS
%Change Retail Sales (KWH) 2012 2013 20
-.8 +1.2
!a 39% 40% 69% 76% 62% 54% 57% 61% 50% 50% 50% All Dlv'ds to Net Prof 56%
f--8-U-Sl-NE,_S_S_:_P..,ortl_a_n_d_G...J.e-ne_ra_l_E_.._le-ct-rlc-Co.._m_p_a_ny_(,_P_G_E)_p_,r_ov-ld-es-"-21-°/c-,;-g-'-as-,-16-0!.-,;.._hy-d-ro-,-6°/c'-,;-wi_n_d_,,6-%-.;-p-ur-ch-a-se-d,_4_9_%_.F-u"'"e1_co_s_ts-1: Al'J. lndust Use ~IWHI 16409 16258 16577 electricity to 843,000 customers in 52 cities In a 4,000-square-mlle 38% of revenues. '14 reported depreciation rate: 3.6%. Has 2,600 Al!J. lnd!ist. Revs. 110r KWH (¢) 5.26 4.84 5.13 area of Oregon; Including Portland and Salem. The company Is in employees. Chairman: Jack E. Davis. President and Chief Execu-
- ~~~&.
4173 4380 ~~~g pJfi~, F 3597 3869 NA the process of decommissioning the Trojan nuclear plant, which It live Officer: James J. Piro. Incorporated: Oregon. Address: 121 closed in 1993. Electric revenue breakdown: residential, 47%; com- S.W. Salmon Street, Portland, Oregon 97204. Telephone; 503-464-Ca "' Annu~Loa NA NA
%Change CUslomera -end) +.7 +.9 +.7 mercial, 34%; lnduslrlal, 12%; other, 7%. Generating sources: coal, 8000. Internet: www.portlandgeneral.com.
t----------------------------------------1 Portland General Electric has filed a within the company's guidance of $2.20-Faed Charge Cov. (%) 270 239 248 ANNUAL RATES Past Past Est'd '12-'14 general rate case. The utility ls seeking $2.35 a share. We forecast solid profit of change (per sh) 10Yrs. 5Yrs. to '18*'20 a base tariff hike of $39 million at the growth, to $2.45 a share, in 2016. Revenues -- -2.0% 1.0% start of 2016. After a 440-megawatt gas- The share count will climb signifi-.
"Cash Flow" Earnings
-- 3.0%
3.0% 4.5% 6.0% fired base-load generating plant is com- cantly this year. PGE still has 10.4 mil-Dividends -- 2.5% 6.0% pleted (probably in the second quarter of lion common shares to issue from a for-Book Value -- 2.0% 4.5% 2016) at an expected cost of $450 million, ward stock sale. This should raise about f--C-al-~-QU-A-RT-ER-LY_R_EV_E_N-UE-S-($_m_lll.)-~F-ul~J PGE would receive an additional $83 mil- $275 million for the company, which it will endar Mar.31 Jun.30 Sep.30 Dec.31 Year lion raise. PGE is basing its filing on a use to retire debt. Future equity issuances 1--2-0-12--+-4-79-.0-4-1-3.-0-4~50-.0-4-6-3.-0-+-18 5 .--< 0 9.9% return on a 50% common-equity will depend on the utility's capital spend-2013 473.0 403.0 435.0 499.0 1810.0 ratio. A ruling is expected in late 2015. ing needs. PGE will have to replace its 2014 493.0 423.0 484.0 500.0 1900.0 Note that some charges the company is stake in the Boardman coal-fired plant at 2015 525 445 485 520 1975 now collecting from customers will end by the end of 2020 and will need additional 2016 540 470 515 550 2075 next year, thereby offsetting $56 million of renewable capacity in order to meet state f--C-'-a"".-+-'-'-'-E-AR-N'"'"1N""G-S-PE...:.R.:..:S:...HA_R_E.:..:Ac:.....-l".:..:F..:..ul-1I 1 whatever rate hike is granted. This will mandates. endar Mar.31 Jun.30 Sep.30 Dec.31 Year not affect PGE's earnings. We think the board of directors will ,_2_0-12--+-.6-5--.3-4-~.-0--.3-8-+--1-.8--< 5 7 Rate relief should be the main driver soon raise the dividend. We expect a 2013 .65 .13 .40 .59 1.77 of the company's expected profit larger increase than in recent years. 2014 .73 .43 .47 .55 2.18 growth this year and next. At the start PGE's payout ratio is now near the low 2015 .75 .45 .50 .60 2.30 of 2015, PGE received a rate increase to end of its targeted range of 50%-70%. 2016 .80 .47 .53 .65 2.45 place two plants, which went in service in This stock has a high valuation for a 1--Ca-l*-+-Q-UA-R-TE-RL_Y_Dl_VID-E-ND-S-PA-ID_B_*_t_,__F_ul-<I late 2014, in the rate base: a 267-mw wind utility. The dividend yield and 3- to 5-endar Mar.31 Jun.30 Sen.30 Dec.31 Year project that cost $530 million and a 220- year total return potential are below the r-~-~-g-t=:=~i=s~=:~=is~"":""~~""5"'--"':~""~""s"-+-...:.1.:..::~-1~ ~~li~~~-~~~ Zte:i~~;gi; 1 ~~~oth:;P~~~~;c~~~ ~~i~~7e~~~~:~~~:e;~~~o~~~es~~~~~tl~~~ 2013 .27 .27 .275 .275 1.09 modest load growth (about 1%) as its ser- but we wouldn't purchase the stock based 2014 .275 .275 .28 .28 1.11 vice area's economy expands. Our 2015 on the possibility of a buyout. 2015 .28 .28 earnings estimate of $2.30 a share is Paul E. Debbas, CFA May 1, 2015 {A) Diluted EPS. Exel. nonrecurring loss: '13, Shareholder Investment plan avail. {C) Incl. eq., '14: 9.4%. Regulatory Climate: Below Company's Financial Strength B++ 42¢. Next earnings report due late July. deferred charges. In '14: $6.31/sh. (D) Jn mill. Average. (F) Summer peak In '12. (G) '05 per- Stock's Price Stabllity 100 (B) Dividends paid mid-Jan., Apr., July, and {E) Rate base: Net original cost Rate allowed share data are pro forma, based on shares out- Price Growth Persistence 60 Oct.
- Dividend reinvestment plan avail. t on com. eq. in '15: 9.68%; earned on avg. com. standing when stock began trading In '06. Earnings Predictablllty 65 "2015 Value Line Publishing LLC. All righlS reserved. Factual material Is obtained from sources believed to be reliable and Is provided without warranties of any kind. ,**,, l!l'-""l'""""-
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication Is sliicUy for subscribe(s own, non-commercial, Internal use. No Rart lrl._~1111.'fMi I '
- 1Lrn ".,.,,. '"""-
of nmay be reproduced, resold, stored or l/ansmnted ln any printed, elecl/onic or other fonn, or used for generating or marketing any printed or e!ecuonic publication, service or pro~uct.
Schedule AHG-5 15-WSEE-115-RTS 18 , 35 P/ERATIO 16 , 7eralllng:18.7) RELATIVE 088 /Dl\PD
.,, .. ,=-
TECO ENERGY. INC. NYSE-TE YLD 5.0%
/RECENT PRICE Median: 15.0 P/E RATIO I TIMELINESS 3 Lowered lOIJ/14 High: 15.5 19.3 17.7 18.6 22.0 16.7 18.1 19.7 19.4 19.2 21.3 22.0 Target Price Range Low: 11.3 14.9 14.4 14.8 10.5 8.4 14.5 15.8 16.1 16.2 16.1 18.2 2018 2019 2020 SAFETY 2 Raised W4/12 -
LEGENDS 0.68 x Dividends sh r "2'1 TECHNICAL 4 Lowered 5/12115 divided b~ lnteres Rate
* * . . Relative rice Strength ~~~(l 40 32 BETA .85 (1.00 = Markel)
O~~~~~d'ir~a Indicates recession 1"*_,-,,..
- o,_'J ,,v ...... ..._
........ 24 2018*20 PROJECTIONS ~
Ann'I Total 1 l h111
*1"* l"'i11ar<1111 *1111*11*1, 111 1111*11 l.1111111' "* .......... .......... 16 Price Gain Return (J,,11 1 High 25 (+35°4 12% 111111"'it; 1*1. *** 1* ' 12 Low 18 (NII 5% I 10
~ I-Insider Decisions 8 J J As o N D J F ... .... . .......... .... i 6 to Buy o o o o o 0 0 0 0 OpUons 0 1 0 0 0 4 0 0 1 ........... ****. .. .. -4 i-to Sell 0 0 0 0 0 5 0 0 0
**~.
Institutional Decisions .11 :!",
- i l %TOT. RETURN 4/15 THIS VLARITH.'
I -*!r I ' 9.1 .... 2QlOH 3Q20tl lQ2014 Percent 18 STOCK INDEX to Buy 155 200 172 shares 12 I.II. I .1111111 1111 11111 .. 1 yr. 10.7 to Sell 144 101 137 traded """ ... 1111111'111 till 1111111 11111 Ill 3 yr. 22.0 58.8 I - Hld'slOOO 134541 144601 145752 6 ! lllllllllll 11111111111 1111111111111 ,1111 1111111 11111 Ill II 5yr. 42.9 84.6
~
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 15.01 18.17 18.97 15.22 14.59 13.37 14.46 16.46 16.77 15.85 15.48 16.23 15.49 13.83 13.12 10.93 12.10 12.55 Revenues per sh 14.50 3.28 4.11 4.31 3.20 1.96 2.14 2.37 2.51 2.51 2.01 2.35 2.59 2.77 2.69 2.43 2.36 2.55 2.70 "Cash Flow" per sh 3.25 1.53 1.97 2.24 1.95 d.08 .71 1.00 1.17 1.27 .77 1.00 1.13 1.27 1.14 .92 ,95 1.10 1.15 Earnings per sh A 1.40 1.29 1.33 1.37 1.41 .93 .76 .76 .76 .78 .BO .80 .82 .85 .88 .88 .88 .90 .92 Dlv'd Decl'd per sh e
- 1.00 3.23 5.45 6.92 6.06 3.14 1.37 1.42 2.18 2.34 2.77 2.99 2.28 2.10 2.33 2.45 3.04 3.20 2.95 Cap'I Spending per sh 2.25 10.73 11.93 14.12 14.86 8.93 6.43 7.65 8.25 9.56 9.43 9.75 10.10 10.50 10.58 10.74 10.96 11.10 11.30 Book Value per sh c 12.25 132.10 126.30 139.60 175.80 187.80 199.70 208.20 209.50 210.90 212.90 213.90 214.90 215.80 216.60 217.30 234.90 236.00 237.00 Common Shs Outst'g o 240.00 14.2 11.9 12.9 11.0 -- 19.3 17.1 13.8 13.3 21.2 12.6 14.6 14.4 15.5 18.9 18.8 Bold fig ros are Avg Ann'I PJE Ratio 15.0
.81 .77 .66 .60 -* 1.02 5.9% 5.7% 4.8% 6.6% 7.4% 5.5% 4.4% 4.7% 4.6% 4.9% 6.3% 4.9% 4.6% 5.0%
.91 .75 .71 1.28 .84 .93 .90 .99 1.06 5.1% 4.9%
,99 Value Line est/' ates Relative P/E Ratio Avg Ann'I Dlv'd Yield
.95 4.8%
CAPITAL STRUCTURE as of 12/31/14 3010.1 3448.1 3536.1 3375.3 3310.5 3487.9 3343.4 2996.6 2851.3 2566.4 2850 2975 Revenues ($mill) 3450 Total Debt $3767.5 mill. Due in 5 Yrs $1401.1 mill. 211.0 244.4 265.8 162.4 213.9 242.9 272.6 246.0 197.8 213.1 255 270 Net Profil ($mill) 330 LT Debt $3354.0 mill. LT Interest $166.4 mill. 45.1% 40.4% 40.7% 36.8% 31.6% 34.8% 36.1% 35.9% 35.5% 38.3% 38.5% 38.5% Income Tax Rale 38.5% (LT lnlerest earned: 3.0x)
.0% 1.6% 2.3% 5.4% 6.5% 1.2% .6% 1.7% 5.0% 7.4% 8.0% 6.0% AFUDC 0/o to Nel Profit 2.0%
Leases, Uncapitalized Annual rentals $8.9 mill. 70.0% 65,0% 61.0% 61.5% 60.6% 59.2% 54.2% 56.5% 54.9% 56.6% 57.5% 58.0% Long-Term Debt Ratio 57.0% 30.0% 35.0% 39.0% 38.5% 39.4% 40.8% 45.8% 43.5% 45.1% 43.4% 42.5% 42.0% Common Eaultv Rallo 43.0% Pension Assets-12/14 $648.0 mm. 5300.9 4941.6 5175.4 5214.3 5287,0 5317.8 4953.9 5264.5 5171.5 5928.7 6190 6395 Total Capita! ($mill) 6850 Oblig. $728.9 mill. 4566.9 4766.9 4888.2 5221.3 5544.1 5841.0 5967.8 5990.1 6170.1 7088.2 7495 7835 Net Plant ($mill) 8200 Pfd Stock None 6.5% 7.3% 7.3% 5.1% 6.0% 6.4% 7.4% 6.1% 5.4% 5.0% 5.5% 5.5% Relurn on Total Cap'I 6.5% Common Stock 235,528,791 shs. 13.3% 14.1% 13.2% 8.1% 10.3% 11.2% 12.0% 10.7% 8.5% 8.3% 9.5% 10.0% Return on Shr. Eqully 11.0% as of 2/13/15 13.3% 14.1% 13.2% 8.1% 10.3% 11.2% 12.0% 10.7% 8.5% 8.3% 9.5% 10.0% Return on Com Equilv E 11.0% MARKET CAP: $4.3 billion (Mid Cap) 3.3% 5.0% 5.1% NMF 2.1% 3.1% 3.9% 2.4% .3% .5% 1.5% 2.0% Retained to Com Eq 3.0% ELECTRIC OPERATING STATISTICS 75% 65% 61% 104% 80% 72% 67% 77% 97% 93% 83% 80% All Dlv'ds to Net Prof 72% 2012 2013 2014 BUSINESS: TECO Energy, Inc. Is a holding company for Tampa down: residential, 50%; commercial, 30%; Industrial, 8%; other,
%Ch::S Relail Sales (Kl\li) -.8 -- +.6 Electric, which seives 706,000 cuslomers In west central Florida, 12%. Generating sources: coal, 59%; gas, 36%; purchased, 5%.
Ai~. I usl Use (l~Y) NA NA NA A1~. loousl Revs.~ K'llH (¢) 8.84 8.50 8.65 and Peoples Gas, which seives 354,000 customers In Florida. Fuel costs: 38% of revs. '14 reported deprec. rate (utility): 3.6%. Ca~alPeak( lw) 4668 4668 4668 Acq'd New Mexico Gas (513,000 customers) 9/14. Sold TECO Has 4,400 employees. Chairman: Sherrill W; Hudson. Pres. & CEO: Peik l.Oad, VAfl!er~i1 NA NA NA Transport 12/07; discontinued generation Investments in Guate- John B. Ramil. Inc.: FL. Address: TECO Plaza, 702 N. Franklin St., Annual load Fador (% NA NA NA
%Chanse Cuslomera avg.) +1.3 +1.5 +1.6 mala In '12; discontinued TECO Coal in '14. Electric revenue break* Tampa, FL 33602. Tel.: 813*228-1111. Web: www.lecoenergy.com.
F~ed Charge Cov. (%) 301 272 287 The sale of TECO Energy's coal- million increase in November. Each Flor-ida utility is likely to earn a return on ANNUAL RATES Past Past Est'd '12*'14 mining subsidiary still hasn't been of change (per sh) 10Yrs. 5Yrs. to '18-'20 completed. When the initial agreement equity in the upper half of its allowed Revenues -1.5% -4.5% 2.5% was announced in October, the deal was . range (as shown in Footnote E) this year.
"Cash Flow" .5% 1.5% 4.5% expected to close by the end of 2014. How- Finally, the company plans to replace ma-Earnings Dividends 1.5%
-1.5% 2.0%
-- 6.0%
2.0% ever, the buyer has had trouble obtaining turing high-cost debt with borrowings that Book Value .5% 2.5% 2.0% financing, so the closing date has been ex- have a much lower interest rate. All told, QUARTERLY REVENUES($ mill.) tended multiple times. The latest date is our earnings estimate is within manage-Cal* Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year June 5th. The transaction calls for TECO ment's guidance of $1.08-$1.11 a sh<J.I"e. 2012 697.1 752.5 858.6 688.4 2996.6 Energy to receive $80 million in cash, plus We forecast continued bottom-line 2013 661.1 7:>5.9 765.9 688.4 2851.3 a contingency payment of up to $60 mil- growth in 2016. We expect the favorable 2014 578.0 605.7 687.2 695.5 2566.4 lion depending on the price of coal over the trends at the Florida utilities to persist, 2015 693.0 700 757 700 2850 next five years. The company is talking to and New Mexico Gas is also experiencing 2016 750 725 775 725 2975 other prospective buyers in case the sale some growth, albeit modest. We estimate EARNINGS PER SHARE A falls through. TECO Coal has been ac- that earnings will rise 4%-5%, to $1.15 a Cal* Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year counted for as a discontinued operation share. A more significant increase is likely 2012 .20 .30 .42 .22 1.14 since last year. in 2017, as Tampa Electric's rates will be 2013 .19 .24 .29 .20 .92 Earnings are likely to advance consid- raised by $110 million once an upgrade to 2014 .22 .27 .28 .18 .95 erably this year. The acquisition of New a power plant is completed. 2015 .27 .25 .32 .26 1.10 Mexico Gas should be accretive to earn- TECO Energy stock is appealing for 2016 .29 .26 .33 .27 1.15 ings, over and above the fact that merger- income-oriented investors. The divi-Cal- QUARTERLY DIVIDENDS PAID e
- Full related expenses reduced share profits by dend yield is among the highest for any endar Mar.31 Jun.30 Seo.30 Dec.31 Year $0.08 in 2014. Tampa Electric and Peoples utility, and we project modest dividend Gas are experiencing strong customer growth over the 3- to 5-year period, too.
2011 .205 .215 .215 .215 .85 2012 .22 .22 .22 .22 .88 growth as tlie Florida economy expands. Accordingly, total return potential over the 2013 .22 .22 .22 .22 .88 Tampa Electric is benefiting from a $7.5 3- to 5-year period is better than the in-2014 .22 .22 .22 .22 .88 million rate hike that took effect last No- dustry average. vember, and will receive an additional $5.0 Paul E. Debbas, CFA May22, 2015 2015 .225 (A) Diluted EPS. Exel. nonrec. gain (losses): '15, (2¢). Next earnings report due late July. ortg. cost. Rate allowed on com. eq. in '13 '99, (11tJ; '03, ($4.97); '07, 63¢; '10, (2¢); '14, (B) Div'ds paid in late Feb., May, Aug., & Nov. (elec.): 10.25%-12.25%; In '09 ~rias): 9.75%* I Com~any's Financial Strength Sloe 's Price Stablllty B++ 95 (3¢); ga ns (losses) on disc. ops.: '04, (77¢);
- Div'd reinv. plan avail. (C) Incl. Intangibles. In 11.75%; In NM In '12: 10% (imp ed ; earned on Price Growth Persistence 40
'05, 31¢; '06, 1¢; '07, 7¢; '12, (15¢); '14, (34¢); '14: $3.50/sh. (D) In mill. (E) Rate base: Ne! avg. com. eq., '14: 8.7%. Regul. crlmate: Avg. Earnings Predictability 80 <> 2015 Value Line Publishing LLC. All rights reserved. Factual material Is obtained from sources believed 10 be reliable and Is provided without warranties of any kind. Tl!E PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publlcaUon is slrlcUy for subscriber's own, non-commercial, inlemal use. No Rart To *suhscrib~ .cal1 *1-aoo-vAL'ufiiNE -* ~*o"e:_~ ** -; of ~ may be reproduced, resold, stored or transmilled in any prinled, electronic or olher foim, or used for generating or marketing any printed or electronic pubication, selVice or pro~uct. ' ".""~':_";;., ~ .. ~.. .:0
Schedule AHG-5 15-WSEE-115-RTS 087DIV'YLDD 3.9%1 WESTAR ENERGY NYSE-WR 'RECENT PRICE 37 ,20 'PRATIOIE 16, ocraillng:15.8) Median: 14.0 RELATIVE PIE RATIO I TIMELINESS 3 Lowered 11111114 High: 22.9 25.0 27.2 28.6 25.9 22.3 25.9 29.0 33.0 35.0 43.2 44.0 Target Price Range Low: 18.1 21.1 20.1 22.8 16.0 14.9 20.6 22.6 26.8 28.6 31.7 36.6 2018 2019 2020 2 Raised 411/05 SAFETY TECHNICAL 3 Raised 3/20115 LEGENDS 0.80 x Dividends sh r dMded b~ lnteres Rate BO
* * *
- Relative rice Strenglh 60 BETA .75 (1.00 =Market) 2018*20 PROJECTIONS O~~~~~~"ir~a indicates recess/on /
50 Ann'I Total ~ _.., / 11111 11" 1 '*11 * 40 Price Gain Return I* 30 High Low 50 40 !+35%l +10% 11% 6% 11 1 111 11 111 1111"' I ~ 11 'I
... 11* 1111" 1'*1 .. 111 *111 25 20 Insider Decisions ,tr!- I c.--
15 AMJJASON D l'I' to Buy 0 0 0 0 0 0 0 0 0
...... ..... .... 10 Optlons 0 0 0 0 0 0 0 0 0 to Sell 00001001 0 ~7.5
% TOT. RETURN 2/15 Institutional Decisions .,.*
2Q2014 3Q2014 4Q20t4 Percent 24 I ... ************ THIS STOCK VLARITH.' INDEX to Buy 161 155 157 shares 16 '" 1111 1 yr. 18.0 8.2 {,.' II
~
to Sell 116 117 136 traded 8 11. .ollLllll .II.II ,,1,,1111 I 3 yr. 60.4 60.8 Hld's{OOOl 93488 95815 96912 hlllllilll 111 M1111111 1111111111 1111111111 I 5 yr. 128.6 110.1 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 © VAlUE LINE PUB. LLC 8-20 30.21 33.80 31.20 24.77 20.06 17.02 18.23 18.37 18.09 16.98 17.04 18.34 17.27 17.88 18.48 19.76 19.85 19.75 Revenues per sh 20.75 7.51 6.96 5.32 4.77 3.77 3.12 3.28 3.94 3.77 3.14 3.59 4.24 3.97 4.30 4.41 4.55 4.70 4.95 "Cash Flaw" per sh 5.25 1.48 ,89 d.58 1.00 1.48 1.17 1.55 1.88 1.84 1.31 1.28 1.80 1.79 2.15 2.27 2.35 2.35 2.55 Earnings per sh A 3.00 2.14 1.44 1.20 1.20 .87 .80 .92 .98 1.08 1.16 1.20 1.24 1.28 1.32 1.36 1.40 1.44 1.50 Dlv'd Decl'd per sh B*t 1.65 4.09 4.40 3.37 1.89 2.06 2.19 2.45 3.95 7.84 8.65 5.26 4.82 5.55 6.40 6.08 6.47 7.00 7.20 Cap'I Spending per sh 8.15 27.83 27,20 25.97 13.68 14.23 16.13 16.31 17.62 19.14 20.18 20.59 21.25 22.03 22.89 23.88 25.02 25.60 26.35 Book Value per sh c 29.25 67.40 70.08 70.08 71.51 72.84 86.03 86.84 87.39 95.46 108.31 109.07 112.13 125.70 126.50 128.25 131.69 130.00 135.00 Cammon Shs Outst'g E 140.00 17.2 20.6 .. 14.0 10.8 17.4 14.8 12.2 14.1 17.0 14.9 13.0 14.8 13.4 14.0 15.4 8oldffg res are Avg Ann'I P/E Ratio 15.0
.98 1.34 .. .76 .62 .92 .79 .66 .75 1.02 .99 .83 .93 .85 .79 .81 Value Line Relative PIE Ratio .95 estin ates 8.4% 7.9% 5.8% 8.6% 5.5% 3.9% 4.0% 4.3% 4.2% 5.2% 6.3% 5.3% 4.8% 4.6% 4.3% 3.9% Avg Ann'! Div'd Yield 3.7%
CAPITAL STRUCTURE as of 12/31/14 1583.3 1605.7 1726.8 1839.0 1858.2 2056.2 2171.0 2261.5 2370.7 2601.7 2580 2665 Revenues ($mill) 2800 Total Debt $3667.6 mill. Due In 5 Yrs $725.0 mill. 134.9 165.3 168.4 136.8 141.3 203.9 214.0 275.1 292.5 313.3 305 345 Net Profit ($mill) 420 LTDebt $3382.1 mill. LT Interest $170.0 mill. 31,0% 25.4% 27.5% 24.8% 29.4% 29.0% 35.2% 30.9% 33.1% 31.9% 30.0% 30.0% Income Tax Rate 30.0% (LT Interest earned: 2.8x) .. .. 10.4% ..
-* -- -* .. 10.4% 10.0% 10.0% 10.0% AFUDC 'lo to Net Prolit 10.0%
Pension Assets 12/14 $661 mill. Obllg. $914 mill. 52.1% 50.0% 50.6% 49.8% 53.4% 53.6% 49.5% 51.2% 50.0% 50.0% 50.0% 50.0% Long.Tenn Debt Ratio 50.0% 47.2% 49.3% 48.9% 49.7% 46.1% 46.0% 50.1% 48.8% 50.0% 50.0% 50.0% 50,0% Common Eauity Ratio 50.0% 3000.4 3124.2 3738.3 4400.1 4866.8 5180.9 5531.0 5938.2 6131.1 6596.2 6650 6800 Total Capita! ($mill) 7500 Pfd Stock None 3947.7 4071.6 4803.7 5533.5 5771.7 6309.5 6745.4 7335.7 7848.5 8441.5 8500 8500 Net Plant ($mlll) 9000 6.2% 6.7% 5.8% 4.2% 4.4% 5.5% 5.3% 6.0% 6.1% 6.0% 6.0% 6.0% Return on Total Cap'I 6.0% Common Stock 132, 137,563 shs. 9.4% 10.6% 9.1% 6.2% 6.2% 8.5% 7.7% 9.5% 9.6% 9.5% 9.5% 9.5% Return on Shr. Equity 9.5% MARKET CAP: $4.9 billion (Mid Cap) 9.5% 10.7% 9.2% 6.2% 6.3% 8.5% 7.7% 9.4% 9.6% 9.5% 9.5% 9.5% Return on Com Eaulty o 9.5% ELECTRIC OPERATING STATISTICS 4.3% 5.5% 4.3% 1.2% .8% 3.1% 2.7% 4.0% 4.2% 4.3% 4.0% 4.0% Retained to Com Eq 4.0% 2012 2013 2014 55% 49% 53% 80% 87% 63% 65% 57% 56% 55% 61% 59% All Dlv'ds to Net Prof 55%
%Cliange Re~i Sales (KWH) -1.5 +3.6 +1.5 A1~. lndusl US<! (M'lli 5588 5407 5747 BUSINESS: Weslar Energy, Inc., formerly Western Resources, is plant age: 15 years. Fuels: coal, 52%; nuclear, 8%; gas, 40%. Has A1~. loousl Revs. ~er iH (¢) 6.60 6.47 6.72 the parent of Kansas Gas & Electric Company. Westar supplies 2,302 employees. BlackRock Inc owns 7.0% of common; The CaP,3cityalPeak( i~ 6557 6671 6698 electricity to 700,000 customers in Kansas. Electric revenue Vanguard Group owns 5.8%; JP Morgan owns 5.2% (3/14 proxy).
Peikload,Summer~ i) 5411 5489 5226 sources: residential and rural, 34%; commercial, 38%; industrial, CEO and Pres.: Mark A. Ruelle. Inc.: Kansas. Addr.: 810 South kinualloedFaclor( Ii 56.0 55.9 56.2 Kansas Avenue, Topeka, Kansas 66612. Telephone: 785-575-
%Change Cullomera yr-end) +.2 +.2 +.2 28%. Sold Investment in ONEOK In 2003 and 85% ownership In Protection One in 2004. 2013 depreciation rate: 3.8%. Estimated 6300. Internet: www.westarenergy.com.
faed Charge Cov. (%) 319 323 332 Westar Energy announced 2014 re- business environment. Our 2016 forecast ANNUAL RATES Past Past Est'd '12-'14 suits. The Topeka, Kansas-based utility is based on the expectation of reasonable of change (per sh) 10Yrs. 5Yrs. to'18-'20 Revenues -1.0% 1.5% 2.5% posted profits of $2.35 a share for the year treatment from regulators, pending the "Cash Flow" 1.5% 5.0% 4.5% just ended. Higher net income was driven submitted rate request. Earnings 6,5% 9.0% 6.0% by greater pricing power, resulting from The board of directors authorized a Dividends 3.5% 3.5% 3.0% Book Value 5.0% 3.5% 5.0% investments in air quality controls and dividend increase. The quarterly distri-transmission infrastructure. An increase bution was raised $0.01 a share, to an an-Cal* QUARTERLY REVENUES($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year in retail sales, led by industrial customers, nualized rate of $1.44. The yield of 3.9% is also contributed to the underlying results. slightly above the median yield for the 2012 475.7 566.3 695.8 523.7 2261.5 The company filed a report to in- electric utility industry. Westar Energy is 2013 546.2 569.6 695.0 559.9 2370.7 2014 628.6 612.7 764.0 596.4 2601.7 crease rates. The request was submitted targeting a payout ratio of 50%-60%. 2015 630 620 750 580 2580 in early February. Management believes Capital expenditures could total $3.5 2016 650 645 775 595 2665 that the magnitude of the investments it billion over the next five years. Trans-EARNINGS PER SHARE A has made over the past few years justifies mission investments, the largest com-Cal* Full a meaningful rate increase in the upper ponent, will likely exceed $1 billion. That endar Mar.31 Jun.30 Sep.30 Dec.31 Year single-digit percent range. If granted, the should allow Westar to more efficiently 2012 .21 .48 1.09 .37 2.15 2013 .52 1.04 .31 2.27 schedule calls for an adjustment to prices deliver electricity to customers.
.40 2014 .52 .40 1.10 .33 2.35 in November of thls year, allowing the This neutrally ranked issue is a 2015 .50 .40 1.10 .35 2.35 utility to take full advantage of the rate decent choice for income-oriented in-2016 .55 .45 1.15 .40 2.55 hike in 2016. vestors. Although future capital fapreci-QUARTERLY DMDENDS PAID 8 *t We expect the bottom line to be flat in ation is muted, we think income- ocused Cal* Full 2015, followed by a strong up-tick in accounts would do well owning this stock endar Mar.31 Jun.30 Seo.30 Dec.31 Year 2016. Our profit forecast for the current for its decent dividend yield. And, the 2011 .31 .32 .32 .32 1.27 year matches the midpoint of mana.,fe- stock's lower-than-market Beta, combined 2012 .32 .33 .33 .33 1.31 2013 .33 .34 .34 .34 1.35 ment's share-net guidance of $2.25-$2. 5 . with its good marks for Price Stability and 2014 .34 .35 .35 .35 1.40 Westar Energy should continue to benefit Earnings Predictability, provides some 2015 .36 from higher electric retail sales, driven by added peace of mind.
increasing demand from an improving Daniel Henigson March 20, 2015 (A) EPS diluted from 2010 onward. Exel. non-, lo rounding. Nexl egs. rep't due early May. I$6.48/sh. (~Rate base delennlned: fair value; Company's Financial Strength recur. rins {losses): '98, ($1.45); '99, ($1.31); (B) Div'ds daid in eat Jan., April, July, and Rate allow on common e~uity In '14: 10.0%; Stock's Price Stablllty B++ 100 '00, $ .07; '01, 27¢; '02, ($12.06); '03, 77¢; Oct* Div' reinvest. fr an avail. t Shareholder earned on avg. com. eq., 14: 9.5%. Regul. Price Growth Persistence 75 '08, 39¢; '11, 14¢. Earnings may not sum due invest. plan avail. {C) ncl. reg. assets. In 2014: Clim.: Avg. (E) In mill. Earnings Predictability 80 " 2015 Value line Publishin~ LLC. All nrts reserved. Faclual material Is obtained from sources believed to be reliable and ts provided without warrantles of an~ kind. TIJE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thl!J'ublication Is strictly for subscribers own, non-commercial, Internal use. o P.art 111-...,111*.,~1 11:..-, Hlll"1111111:111l11 ol it may be reproduced, resold, slored or transmilled In any printed, electronic or other fom1, or us for generating or marl<eting any prinled or electronic pubITcation, service or proouct.
Schedule AHG-5 15-WSEE-115-RTS XCEL ENERGY NYSE-XEL IRECENT PRICE 34 28 IP/ERATIO 16 1 2ealling:16.9) RELATIVE
, Median: 15.0 PIE RATIO 0,83 DIVD YLD 3.8%1ii1_
TIMELINESS 3 Raised 12117/13 High: 18.8 20.2 23.6 25.0 22.9 21.9 24.4 27.8 29.9 31.8 37.6 38.3 Target Price Range Low: 15.5 16.5 17.8 19.6 15.3 16.0 19.8 21.2 25.8 26.8 27.3 33.4 2018 2019 2020 SAFETY 1 Raised 5/1/15 - LEGENDS 0.74 x Dividends shr ~ '.' 64 TECHNICAL 3 Lowered 4124115 divided b~ lnleres Rate
* * *
- Relative rice Suength 48 BETA .65 (1.00 = Markel)
O~~~~~/ir~a indicates recession
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- . --. 40 2018-20 PROJECTIONS Ann'I Total
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- THIS VLARITH.'
lo Buy lo Sell 202014 239 181 3Q20t4 233 189 402014 Percent 249 shares 202 traded 15 10
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I I. I 11111111 11111111 I 1 yr. 3 yr. STOCK 19.0 44.7 INDEX 7.7 57.2 -- 5 '" Hld'slOOOl 351983 351672 343268 11111111111 11111 1111 111111111111 1111111111 1111111111 1111111111 1111111111 II 5 yr. 94.3 94.5 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 ©VALUE LINE PUB. LLC 8-20 18.42 34.11 43.56 23.89 19.90 20.84 23.86 24.16 23.40 24.69 21.08 21.38 21.90 20.76 21.92 23.11 23.60 24.50 Revenues per sh 27.25 4.13 4.12 5.09 3.14 3.35 3.27 3.28 3.61 3.45 3.50 3.48 3.51 3.79 4.00 4.10 4.28 4.60 4.85 "Cash Flow" per sh 5.50 1.43 1.60 2.27 .42 1.23 1.27 1.20 1.35 1.35 1.46 1.49 1.56 1.72 1.85 1.91 2.03 2.05 2.15 Earnings per sh A 2.50 1.45 1.48 1.50 1.13 .75 .81 .85 .88 .91 .94 .97 1.00 1.03 1.07 1.11 1.20 1.28 1.36 Dlv'd Decl'd per sh e
- 1.60 13.87 3.63 7.40 6.04 2.49 3.19 3.25 4.00 4.89 4.66 3.91 4.60 4.53 5.27 6.82 6.33 6.65 5.45 Cap'I Spending per sh 5.50 16.42 16.37 17.95 11.70 12.95 12.99 13.37 14.28 14.70 15.35 15.92 16.76 17.44 18.19 19.21 20.20 20.85 21.75 Book Value per sh c 24.50 155.73 339.79 345.02 398.71 398.96 400.46 403.39 407.30 428.78 453.79 457.51 482.33 486.49 487.96 497.97 505.73 508.00 510.00 Common Shs Outst'g o 516.00 16.6 14.3 12.4 NMF 11.6 13.6 15.4 14.8 16.7 13.7 12.7 14.1 14.2 14.8 15.0 15.4 Bold fig res are Avg Ann'I P/E Ratio 14.0
.95 .93 .64 NMF .66 .72 .82 .80 .89 .82 .85 .90 .89 .94 .84 .81 Value Line Relative P/E Ratio .90 eslln at as 6.1% 6.4% 5.3% 6.6% 5.2% 4.7% 4.6% 4.4% 4.0% 4.7% 5.1% 4.5% 4.2% 3.9% 3.9% 3.8% Avg Ann'! Div'd Yield 4.5%
CAPITAL STRUCTURE as of 12/31/14 9625.5 9840.3 10034 11203 9644.3 10311 10655 10128 10915 11686 12000 12500 Revenues ($mill) 14000 Total Debt $12777 mill. Due In 5 Yrs $3933.2 mill. 499.0 568.7 575.9 645.7 685.5 727.0 841.4 905.2 948.2 1021.3 1030 1105 Net Profit 1$mlll) 1290 LT Debt$11500 mill. LT Interest $555.4 mill. 25.8% 24.2% 33.8% 34.4% 35.1% 37.5% 35.8% 33.2% 33.8% 33.9% 35.0% 35.0% Income Tax Raia 35.0% Incl. $172.2 mill. capitalized leases. (LT lnlerest earned: 3.6x) 8.5% 9.8% 12.5% 15.9% 16.8% 11.7% 9.4% 10.8% 13.4% 12.5% 9.0% 9.0% AFUDC %to Net Profit 10.0% 51.7% 52.1% 49.7% 52.2% 51.6% 53.1% 51.1% 53.3% 53.3% 53.0% 54.0% 54.0% Long*Tenn Debt Ratio 51.5% Leases, Uncapitalized Annual renlals $254.5 mill. 47.3% 47.0% 49.4% 47.1% 47.7% 46.3% 48.9% 46.7% 46.7% 47.0% 46.0% 46.0% Common EQultv Ratio 48.5% Pension Assets-12/14 $3083.8 mill. 11398 12371 12748 14800 15277 17452 17331 19018 20477 21714 22925 24075 Total Capital ($m!ll) 26100 Obllg. $3476.7 mill. 14696 15549 16676 17689 18508 20663 22353 23809 26122 28757 30825 32225 Net Plant 1$mllll 36000 Pfd Stock None 6.2% 6.2% 6.3% 6.0% 6.2% 5.7% 6.5% 6.1% 6.0% 6.0% 5.5% 6.0% Return on Total Cap'! 6.0% Common Stock 505,984,840 shs. 9.1% 9.6% 9.0% 9.1% 9.3% 8.9% 9.9% 10.2% 9.9% 10.0% 9.5% 10.0% Return on Shr. Equity 10.0% as of 2/16/15 9.2% 9.7% 9.1% 9.2% 9.4% 8.9% 9.9% 10.2% 9.9% 10.0% 9.5% 10.0% Return on Com EQUl!v E 10.0% MARKET CAP: $17 bllllon (Large Cap) 2.9% 3.6% 3.1% 3.8% 3.7% 3.6% 4.3% 4.7% 4.5% 4.5% 3.5% 3.5% Retained to Com Eq 3.5% ELECTRIC OPERATING STATISTICS 69% 63% 66% 59% 61% 59% 56% 54% 54% 55% 63% 63% All Dlv'ds to Net Prof 64% 2012 2013 2014 BUSINESS: Xcel Energy Inc. Is the parent of Northern States mill. electric, 1.9 mill. gas. Elec. rev. breakdown: residential, 32%;
%Clia119e Relail Sales (KWH) -.3 +.3 +.2 large C&I Use (MWrl~ 24074 23875 24475 Power, which supplies electricity to Minnesota, Wisconsin, North sm. comm'! & ind'I, 36%; lg. comm'I & lnd'I, 19%; other, 13%. Gen-largeC&IRe\S.~ 'Ill(¢) 5.60 6.23 6.47 Dakota, South Dakola & Michigan & gas to Minnesota, Wisconsin, eratlng sources not available. Fuel costs: 49% of revs. '14 reported Ca~alPeak[ ~t NA NA NA North Dakota & Michigan; Public Service of Colorado, which sup- depr. rate: 2.7%. Has 11,700 employees. Chairman, Pres. & CEO:
Peak load, Sum~~! ~1) 21429 21258 21429 plies electrtcity & gas to Colorado; & Southwestern Public Service, Ben Fowke. Inc.: MN. Address: 414 Nicollet Mall, Minneapolis, MN Annual load Factor (~~ NA NA NA
%Clia119eCust01rera ..ind) +.7 +.8 +.9 which supplies eleclriclty to Texas & New Mexico. Customers: 3.5 55401. Tel.: 612-330-5500. Internet www.xcelenergy.com.
faed Charge Cov. [%) 303 321 344 Xcel Energy's utility subsidiary in wants an allowed ROE of 10.1% this year ANNUAL RATES Past Past Est'd '12*'14 Minnesota received a regulatory deci- and next, rising to 10.3% in 2017, with a of change (per sh) 10 Yrs. 5Yrs. to'18-'20 sion. The state commission granted common-equity ratio of 56%. Revenues .. -1.0% 3.5% Northern States Power electric rate in- Freduent regulatory activity is "Cash Flow" 2.5% 3.5% 5.0% creases of $58.6 million for 2014 and nee ed to reduce the effects of regula-Earnings 7.0% 6.0% 4.5% Dividends 2.5% 3.5% 6.0% $127.8 million for 2015, based on a return tory lag. As a group, Xcel's utilities have Book Value 4.5% 4.5% 4.0% of 9.72% on a common-equity rntio of been earning an ROE about one percent-Cal- QUARTERLY REVENUES($ mill.) 52.5%. (NSP has been booldng an interim age point below their allowed ROE. The Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year rate hike since the start of 2014.) How- company has set a goal to cut this gap in 2012 2578 2275 2724 2551 10128 ever, in a separate matter, the regulators half by 2018. This would boost its annual 2013 2783 2579 2822 2731 10915 did not allow the utility to earn a return earning power by more than $0.10 a share. 2014 3203 2685 2870 2928 11686 on some spending to upgrade a nuclear We expect modest earni11s improve-2015 3200 2750 3100 2950 12000 plant because the project had significant ment this year, followe by better 2016 3400 2850 3200 3050 12500 cost overruns. Accordingly, Xcel expects to growth in 2016. Favorable weather add-Cal- EARNINGS PER SHARE A Full take a pretax charge of $125 million ed a few cents to share net in 2014, and endar Mar.31 Jun.30 Sep.30 Dec.31 Year against March-quarter results, which we the utilities aren't seeing much volume 2012 .38 .38 .81 .29 1.85 will exclude from our earnings presenta- growth. Rate relief should be a positive 2013 .48 .40 .73 .30 1.91 tion as a nonrecurring item. This cut the factor each year. 2014 .52 .39 .73 .39 2.03 total tariff increase by $18.2 million, and Finances are sound. The fixed-charge 2015 .50 .44 .78 .33 2.05 ongoing pretax profits will be reduced by coverage is improving, and the common-2016 .53 *47 .80 .35 2.15 an estimated $16 million annually. equity ratio is solid. We have raised the Cal* QUARTERLY DIVIDENDS PAID e
- Full Public Service of Colorado received company's Financial Strength rating and endar Mar.31 Jun.30 Seo.30 Dec.31 Year an electric rate hike and filed a gas the stock's Safety rank a notch each, to A 2011 .253 .253 rate application. Tariffs were boosted by and 1 (Highest), respectively.
.26 .26 1.03 2012 .26 .26 .27 .27 1.06 $53.3 million, based on a 9.83% ROE. The Neither the dividend yield nor the 3-2013 .27 .27 .28 .28 1.10 utility is asking for a gas tariff increase of to 5-year total return potential stand 2014 .28 .30 .30 .30 1.18 $40.5 million (3.5%) this year, followed by out among utilities.
2015 .30 .32 smaller raises in 2016 and 2017. PSCo Paul E. Debbas, CFA May 1, 2015 (A) Diluted EPS. Exel. nonrec. gain (losses): add due lo rounding. Next egs. report due lale base: Varies. Rate all'd on com. eq.: MN '13 Comkany's Financial Strength A '02, ($6.27); '10, 5¢; 1Q '15, (16¢); gains Jul. (B) Div'ds histor. paid mid-Jan., Apr., July, 9.83%; WI '1510.2%; CO '15 (elec.) 9.83%; Sloe 's Price Stability 100 (losses) on disc. ops.: '03, 27¢; '04, (30¢); '05, and Oct.* Div'd reinvest plan avail. (C) Incl. CO '07 (gas) 10.25%; TX '14 10.4%; earned Price Growth Persistence 60 3¢; '06, 1¢; '09, (1¢); '10, 1¢. '12 EPS don't lntang. In '14: $5.49/sh. (D) In mill. (E) Rate an avg. com. eq., '14: 10.3%. Reg. Clim.: Avg. Earnings Predictability 100 "2015 Value Line Publlshln~ LLC. All ri~IS reseived. Factual material is obtained from sources believed lo be reliable and is provided without wairanties or any kind. - * ;af!:Ull!'ll/!1llJ::n THE PUBLISHER IS NOT RE PONSIBLE OR ANY ERRORS OR OMISSIONS HEREIN. Thl~ublicatlon Is slJfcUy for subscn'be(s own, non-commerdal, lntemal use. No ~art I I H . .11:11
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Schedule AHG-6 15-WSEE-115-RTS Allete Inc (ALE) Alliant Energy Corp (LNT) Ameren Corp (AEE) Am Elect Pwr Co. (AEP) Date High Low High Low High Low High Low 2015-05-26 $50.53 $49.14 $61.69 $60.19 $40.67 $40.01 $56.45 $54.92 2015-05-18 $49.74 $48.10 $61.77 $60.64 $41.21 $40.27 $56.27 $55.26 2015-05-11 $49.13 $47.83 $61.07 $59.28 $40.80 $39.66 $56.17 $54.06 2015-05-04 $50.87 $48.43 $62.38 $59.62 $41.93 $39.70 $57.72 $54.36 2015-04-27 $51.88 $49.75 $63.72 $60.08 $42.84 $40.67 $58.11 $56.42 2015-04-20 $52.06 $50.21 $63.76 $62.20 $42.73 $41.25 $58.35 $55.67 2015-04-13 $52.17 $50.70 $63.54 $61.72 $42.42 $40.96 $56.77 $55.51 2015-04-06 $52.95 $51.11 $64.14 $61.87 $43.00 $41.27 $57.51 $55.38 2015-03-30 $53.30 $51.86 $63.38 $61.60 $42.70 $41.39 $57.07 $55.63 2015-03-23 $53.86 $52.01 $63.92 $61.06 $42.90 $40.85 $58.28 $55.09 2015-03-16 $54.23 $52.39 $63.68 $60.76 $43.12 $41.31 $57.98 $55.48 2015-03-09 $53.26 $51.74 $61.40 $59.92 $41.96 $40.51 $56.23 $54.70 2015-03-02 $54.90 $51.16 $63.55 $60.07 $42.41 $40.75 $57.58 $54.66 Mean $52.22 $50.34 $62.92 $60.69 $42.21 $40.66 $57.27 $55.16 Max/Min $54.90 $47.83 $64.14 $59.28 $43.12 $39.66 $58.35 $54.06 2015 Dividend $2.02 $2.20 $1.65 $2.15 2016 Dividend $2.10 $2.36 $1.69 $2.27 AvgYileld 4.02% 4.17% 3.75% 3.89% 4.00% 4.16% 3.96% 4.11% Min Max 3.83% 4.39% 3.68% 3.98% 3.92% 4.26% 3.89% 4.20% Avista Corp (AVA) CMS Energy Corp (CMS) Con. Edison Inc. (ED) Dominion Resources Inc (D) Date High Low High Low High Low High Low 2015-05-26 $32.24 $31.61 $34.33 $33.76 $62.17 $60.54 $71.99 $70.31 2015-05-18 $32.65 $31.90 $34.41 $33.63 $61.72 $60.52 $72.47 $71.55 2015-05-11 $32.48 $31.51 $34.13 $32.63 $61.82 $60.03 $72.38 $70.27 2015-05-04 $33.26 $31.60 $34.60 $32.87 $62.54 $60.35 $72.57 $70.07 2015-04-27 $34.31 $32.28 $35.34 $33.62 $62.64 $60.92 $73.90 $70.85 2015-04-20 $34.26 $33.12 $35.47 $34.51 $63.03 $61.02 $74.34 $71.62 2015-04-13 $33.78 $32.96 $35.23 $34.13 $61.48 $60.15 $72.56 $71.02 2015-04-06 $34.49 $33.02 $35.83 $34.28 $61.96 $59.91 $73.00 $70.81 2015-03-30 $34.32 $33.21 $35.37 $34.23 $61.55 $59.77 $71.83 $70.13 2015-03-23 $34.31 $33.02 $35.88 $33.93 $62.05 $58.65 $72.55 $70.08 2015-03-16 $34.32 $32.91 $35.70 $33.51 $62.67 $60.65 $72.62 $69.03 2015-03-09 $33.39 $32.13 $34.20 $32.80 $61.66 $59.51 $70.22 $68.25 2015-03-02 $33.98 $32.10 $35.15 $32.99 $63.07 $59.67 $72.09 $69.19 Mean $33.68 $32.41 $35.05 $33.61 $62.18 $60.13 $72.50 $70.24 Max/Min $34.49 $31.51 $35.88 $32.63 $63.07 $58.65 $74.34 $68.25 2015 Dividend $1.32 $1.16 $2.60 $2.59 2016 Dividend $1.37 $1.24 $2.68 $2.80 AvgYileld 4.07% 4.23% 3.54% 3.69% 4.31% 4.46% 3.86% 3.99% Min Max 3.97% 4.35% 3.46% 3.80% 4.25% 4.57% 3.77% 4.10%
Schedule AHG-6 15-WSEE-115-RTS Duke Energy Corp (DUK) Edison International (ElX) El Paso Electric Co (EE) Empire Distr. Electric (EDE) Date High Low High Low High Low High Low 2015-05-26 $76.40 $75.30 $61.34 $59.91 $36.77 $36.01 $23.63 $23.15 2015-05-18 $76.98 $75.56 $61.34 $60.11 $36.98 $36.09 $23.85 $23.38 2015-05-11 $77.73 $74.04 $61.42 $58.57 $36.32 $34.48 $23.78 $22.93 2015-05-04 $78.85 $75.74 $62.31 $59.05 $38.09 $35.13 $24.14 $23.07 2015-04-27 $79.73 $76.87 $62.97 $60.42 $38.77 $36.81 $24.62 $23.25 2015-04-20 $79.88 $77.51 $62.28 $59.78 $38.94 $37.61 $24.91 $23.81 2015-04-13 $78.57 $76.74 $63.59 $60.77 $38.33 $37.33 $25.05 $24.43 2015-04-06 $78.73 $76.53 $64.55 $63.09 $39.26 $37.71 $25.41 $24.30 2015-03-30 $77.39 $75.09 $63.42 $61.58 $38.89 $37.28 $25.28 $24.52 2015-03-23 $77.27 $73.63 $64.56 $61.65 $38.81 $37.13 $25.55 $24.40 2015-03-16 $77.14 $74.79 $65.99 $63.00 $38.73 $36.42 $25.57 $24.02 2015-03-09 $75.48 $73.98 $63.48 $61.20 $36.79 $35.50 $24.54 $23.67 2015-03-02 $78.48 $74.55 $64.34 $61.02 $37.67 $35.43 $25.37 $23.69 Mean $77.89 $75.41 $63.20 $60.78 $38.03 $36.38 $24.75 $23.74 Max/Min $79.88 $73.63 $65.99 $58.57 $39.26 $34.48 $25.57 $22.93 2015 Dividend $3.21 $1.71 $1.17 $1.05 2016 Dividend $3.27 $1.89 $1.23 $1.07 AvgYileld 4.20% 4.34% 2.99% 3.11% 3.23% 3.38% 4.32% 4.51% Min Max 4.09% 4.44% 2.86% 3.23% 3.13% 3.57% 4.18% 4.67% Great Plains Energy (GXP) IdaCorp, Inc (IDA) Northwestern Corp (NWE) OGE Energy Corp (OGE) Date High Low High Low High Low High Low 2015-05-26 $26.26 $25.61 $59.97 $58.61 $52.80 $51.70 $31.67 $31.13 2015-05-18 $26.46 $25.74 $60.40 $59.14 $52.76 $51.79 $32.17 $31.45 2015-05-11 $26.18 $25.34 $59.73 $58.07 $52.15 $50.22 $32.13 $31.08 2015-05-04 $26.72 $25.51 $60.96 $58.46 $52.93 $50.98 $32.77 $31.78 2015-04-27 $27.14 $25.88 $62.97 $59.19 $53.74 $51.66 $32.95 $31.90 2015-04-20 $27.15 $26.36 $63.36 $61.65 $53.85 $51.75 $33.21 $32.15 2015-04-13 $27.12 $26.42 $62.97 $61.13 $53.70 $52.04 $32.93 $31.81 2015-04-06 $27.63 $26.56 $64.22 $61.43 $54.65 $52.30 $32.49 $31.34 2015-03-30 $27.10 $26.11 $63.57 $61.13 $54.27 $53.00 $32.14 $31.45 2015-03-23 $27.05 $25.79 $63.06 $60.73 $55.02 $52.52 $32.60 $31.23 2015-03-16 $27.31 $25.98 $63.14 $60.21 $54.73 $52.00 $32.54 $31.19 2015-03-09 $26.40 $25.58 $61.45 $59.48 $52.51 $50.75 $31.99 $30.82 2015-03-02 $26.61 $25.62 $62.70 $59.21 $54.23 $51.44 $32.49 $31.50 Mean $26.86 $25.88 $62.19 $59.88 $53.64 $51.70 $32.47 $31.45 Max/Min $27.63 $25.34 $64.22 $58.07 $55.02 $50.22 $33.21 $30.82 2015 Dividend $1.00 $1.88 $1.92 $1.05 2016 Dividend $1.06 $1.95 $2.00 $1.16 AvgYileld 3.95% 4.10% 3.14% 3.26% 3.73% 3.87% 3.57% 3.69% Min Max 3.84% 4.18% 3.04% 3.36% 3.64% 3.98% 3.49% 3.76%
Schedule AHG-6 15-WSEE-115-RTS Pacific Gas & Electric (PCG) Pinnacle West Cap (PNW) Portland Gen Electric (POR) TECO Energy (TE) Date High Low High Low High Low High Low 2015-05-26 $53.82 $51.98 $61.43 $60.24 $35.20 $34.67 $19.05 $18.74 2015-05-18 $53.32 $51.87 $61.47 $59.63 $35.47 $34.68 $19.22 $18.70 2015-05-11 $52.94 $50.75 $60.52 $58.37 $35.34 $34.02 $18.87 $18.14 2015-05-04 $54.32 $51.43 $61.76 $58.82 $36.04 $34.62 $19.27 $18.37 2015-04-27 $54.05 $51.56 $63.95 $60.13 $37.49 $34.85 $19.76 $18.77 2015-04-20 $53.01 $51.72 $64.30 $62.46 $37.34 $36.35 $19.85 $19.27 2015-04-13 $53.26 $51.40 $64.12 $62.13 $36.88 $35.95 $19.75 $19.19 2015-04-06 $54.69 $52.17 $64.95 $62.36 $37.69 $36.00 $19.94 $19.21 2015-03-30 $53.73 $52.07 $64.34 $62.77 $37.32 $36.29 $19.71 $19.14 2015-03-23 $54.79 $51.79 $65.08 $62.29 $37.40 $35.62 $20.15 $19.15 2015-03-16 $54.75 $52.06 $65.43 $62.44 $37.17 $35.48 $19.97 $18.89 2015-03-09 $52.61 $51.11 $63.29 $61.56 $35.76 $34.72 $19.23 $18.55 2015-03-02 $54.28 $52.02 $64.09 $61.53 $37.29 $35.31 $19.55 $18.70 Mean $53.81 $51.69 $63.44 $61.13 $36.65 $35.27 $19.56 $18.83 Max/Min $54.79 $50.75 $65.43 $58.37 $37.69 $34.02 $20.15 $18.14 2015 Dividend $1.82 $2.44 $1.17 $0.90 2016 Dividend $1.82 $2.56 $1.23 $0.92 Avg Yileld 3.38% 3.52% 4.04% 4.19% 3.36% 3.49% 4.70% 4.89% MinMax 3.32% 3.59% 3.91% 4.39% 3.26% 3.62% 4.57% 5.07% Westar Energy Inc (WR) Xcel Energy Inc (XEL) Date High Low High Low 2015-05-26 $36.85 $36.04 $34.31 $33.80 2015-05-18 $36.79 $35.95 $34.85 $33.61 2015-05-11 $36.45 $35.42 $33.98 $32.71 2015-05-04 $38.39 $35.72 $34.66 $33.12 2015-04-27 $38,99 $37.26 $35.01 $33.51 2015-04-20 $38.97 $37.59 $35.09 $34.12 2015-04-13 $38.95 $37.54 $34.89 $33.87 2015-04-06 $39.65 $37.94 $35.35 $34.01 2015-03-30 $39.15 $38.11 $35.01 $34.30 2015-03-23 $39.08 $37.62 $35.39 $33.93 2015-03-16 $39.09 $37.56 $35.22 $33.94 2015-03-09 $37.94 $36.58 $34.60 $33.41 2015-03-02 $38.86 $36.90 $35.29 $33.45 Mean $38.40 $36.94 $34.90 $33.68 Max/Min $39.65 $35.42 $35.39 $32.71 2015 Dividend $1.44 $1.28 2016 Dividend $1.50 $1.36 AvgYileld 3.91% 4.06% 3.90% 4.04% Min Max 3.78% 4.23% 3.84% 4.16%
Schedule AHG-7 15-WSEE-115-RTS Calculation of Forecasted 2016 Dividend Yield for DCF Analysis 1 2 3 4 5 6 7 Rep01ied KCC Forecasted 2016 Dividend 2015 Forecasted 2016 Prices Yields for DCF Dividends Growth Dividends Max Min Low High Allete Inc ALE $ 2.02 5.36% $ 2.13 $ 54.90 $ 47.83 3.88% 4.45% Alliant Energy Corp LNT $ 2.20 5.12% $ 2.31 $ 64.14 $ 59.28 3.61% 3.90% Ameren Corp AEE $ 1.65 5.20% $ 1.74 $ 43.12 $ 39.66 4.03% 4.38% American Electric Pwr Co AEP $ 2.15 4.79% $ 2.25 $ 58.35 $ 54.06 3.86% 4.17% Avista Corp AVA $ 1.32 5.19% $ 1.39 $ 34.49 $ 31.51 4.03% 4.41% CMS Energy Corp CMS $ 1.16 5.23% $ 1.22 $ 35.88 $ 32.63 3.40% 3.74%
- Consolidated Edison Inc ED $ 2.60 3.44% $ 2.69 $ 63.07 $ 58.65 4.26% 4.59%
Dominion Resources Inc D $ 2.59 5.49% $ 2.73 $ 74.34 $ 68.25 3.68% 4.00% Duke Energy Corp New DUK $ 3.21 4.61% $ 3.36 $ 79.88 $ 73.63 4.20% 4.56% Edison International EIX $ 1.71 3.72% $ 1.77 $ 65.99 $ 58.57 2.69% 3.03% El Paso Electric Co EE $ 1.17 4.82% $ 1.23 $ 39.26 $ 34.48 3.12% 3.56% Empire District Electric Co EDE $ 1.05 4.36% $ 1.10 $ 25.57 $ 22.93 4.29% 4.78% Great Plains Energy Inc GXP $ 1.00 5.29% $ 1.05 $ 27.63 $ 25.34 3.81% 4.16% IDACORP Inc IDA $ 1.88 3.69% $ 1.95 $ 64.22 $ 58.07 3.04% 3.36% No1ihWestem Corp. NWE $ 1.92 4.94% $ 2.01 $ 55.02 $ 50.22 3.66% 4.01% OGE Energy Corp OGE $ 1.05 4.19% $ 1.09 $ 33.21 $ 30.82 3.29% 3.55% Pacific Gas and Electric Co. PCG $ 1.82 5.26% $ 1.92 $ 54.79 $ 50.75 3.50% 3.77% Pinnacle West Capital Corp PNW $ 2.44 4.47% $ 2.55 $ 65.43 $ 58.37 3.90% 4.37% Po1tland General Electric Co. POR $ 1.17 4.88% $ 1.23 $ 37.69 $ 34.02 3.26% 3.61% TECO Energy TE $ 0.90 5.64% $ 0.95 $ 20.15 $ 18.14 4.72% 5.24% Westar Energy Inc WR $ 1.44 4.29% $ 1.50 $ 39.65 $ 35.42 3.79% 4.24% Xcel Energy Inc XEL $ 1.28 4.54% $ 1.34 $ 35.39 $ 32.71 3.78% 4.09% Column 1&2 KCC Proxy Group 3 2015 repo1ied dividends from Value-Line Investment Survey 4 KCC Forecasted growth rate 5 2016 annual dividend= 2015 dividend x (1 +growth estimate) 6 Observed price range from March 02, 2015 through May 26, 2015 7 2016 Forecasted dividend range
Schedule AHG-8 15-WSEE-115-RTS 10 Year Value-Line Historic Data DPS Growth 5Year EPSGrowth IO Year 5Year I
~t1.~\Ji P~01?1 Forecasted Earnings Growth Rates Value Line DPS EPS IBES FactSet nGDP Average DCF EPS Growth Growth Rate l\.llete Inc ALE 2.00% 7.00% 1* OOo/c0 ~~Wli i~~\i.1~ 4.00% 7.00% 6.00% 6.00% 4.38% 6.33% 5.36%
t\lliant Energy Corp l\.meren Corp LNT 3.50% 6.50% 8.00% 6.50~1\~l 4.50% 6.00% 5.45% 6.10% 4.38% 5.85% 5.12% AEE -4.50% -9.00% -2.50% -4.00 Vo ;1~1 2.00% 5.00% 5.85% 7.22% 4.38% 6.02% 5.20% l\.merican Electric Pwr Co. AEP -1.50% 4.00% 0.50% i' 1* 50o/c0 l1lij~~;\'I 1'11i: 5.00% 5.50% 5.10% 5.00% 4.38% 5.20% 4.79% I\.vista Corp AVA 9.50% 11.50% 7.50% 6 *5 Oo/c0 ~'.ji{(\fu 4.00% 7.00% 5.00% 4.38% 6.00% 5.19%
- MS Energy Corp CMS 23.50% 12 OOo/c ~Xiii 6.50% 5.50% 6.73% 6.00% 4.38% 6.08% 5.23%
- 0 ~~'.~j
- onsolidated Edison Inc. ED 1.00% 1.00% 3.50% 2.50%!:.j 2.50% 3.00% 2.48% 2.00% 4.38% 2.49% 3.44%
i:~>;f; )ominion Resources Inc D 5.50% 7.00% 3.00% 2.50% f!fi)l:1 7.50% 8.00% 5.89% 5.90% 4.38% 6.60% 5.49% Juke Energy Corp DUK 2.50% 3.50%!1~' 2.50% 5.00% 4.49% 5.00% 4.38% 4.83% 4.61% Edison International EIX 2.50% 10.00% ~~* 4 *50o/co 1:Mi:1 10.00% 3.00% 0.70% 5.50% 4.38% 3.07% 3.72% El Paso Electric Co EE 13.50% 6 *50o/co~ L.A~ 5.00% 3.50% 7.00% 4.38% 5.25% 4.82% Empire Distr. Electric EDE -2.50% -4.50% 2.50% 5.00%~;;1 3.00% 3.00% 5.00% 5.00% 4.38% 4.33% 4.36% Jreat Plains Energy Inc GXP -6.50% -12.50% -3.50% -2.00%!,J~j 5.50% 5.00% 6.80% 6.80% 4.38% 6.20% 5.29% [daCorp, Inc IDA 5.50% 9.00% 10.00%ri:I 6.00% 1.00% 4.00% 4.00% 4.38% 3.00% 3.69%
;u:1MH
- -.Jorthwestem Corp NWE 3.00% 8.00%',i)\i 6.50% 6.50% 5.00% 5.00% 4.38% 5.50% 4.94%
JGE Energy Corp OGE 2.00% 3.00% 9.50% 7.50% 11::::1 10.00% 3.00% 4.00% 5.00% 4.38% 4.00% 4.19%
-5 00% t~!i~~
?acific Gas & Electric Co ?innacle West Capital Corp PCG PNW 3.50% 3.00% 3.00% 14.50% 3.50%
. r 8 OOo/c ~~j 2.50%
3.50% 8.50% 4.00% 4.71% 4.70% 5.20% 5.00% 4.38% 4.38% 6.14% 4.57% 5.26% 4.47%
. o!~\;j
- >ortland General Electric Co POR 2.50% 3.00%~:~'~ 6.00% 6.00% 4.72% 5.40% 4.38% 5.37% 4.88%
9.00%~1~ rECOEnergy TE -1.50% 2.00% 1.50% 2.00% 6.00% 9.20% 5.50% 4.38% 6.90% 5.64% Westar Energy Inc WR 3.50% 3.50% 6.50% 3.00% 6.00% 3.40% 3.20% 4.38% 4.20% 4.29% )(eel Energy Inc XEL 2.50% 3.50% 7.00% 6.00%F~i1 6.00% 4.50% 4.58% 5.00% 4.38% 4.69% 4.54% Mean 1.12% 3.02% 5.61% 4 ..40o/co ]i1Jr~
"ii1"1 4.89% 5.09% 5.04% 5.19% 5.12% 4.75%
:'!*~
5.00 Vo j~~l 0 Median 2.00% 3.00% 6.75% 4.75% 5.25% 5.00% 5.10% 5.31% 4.85% Min -6.50% -12.50% -3.50% -5.00% ~~ 2.00% 1.00% 0.70% 2.00% 2.49% 3.44% Max 9.50% 23.50% 14.50% 12.00%~~ 10.00% 8.50% 9.20% 7.22% 6.90% 5.64%
Schedule AHG-9 15-WSEE-115-RTS Internal Rate of Return Analysis Summary 2 3 4 5 6 7 8 9 10 11 12 13 14 Short-Tenn Growth EPS Growth Long-Tenn Growth Years 5 Through 250 Average ST Growth LT Growth 2015 2015 2016 2017 2018 2019 2020 2021 2021 through 2264 IRR Price Estimate Estimate Dividends YearO Yearl Year2 Year3 Year4 Years Year6 Year 7 through Year 250 Allele Inc 8.96% $ 51.37 6.33% 4.38% $ 2.02 $ (49.35) $ 2.15 $ 2.28 $ 2.43 $ 2.58 $ 2.70 $ 2.81 $ 2,338,911 Alliant Energy Corp 8.45% $ 61.71 5.85% 4.38% $ 2.20 $ (59.51) $ 2.33 $ 2.46 $ 2.61 $ 2.76 $ 2.88 $ 3.01 $ 2,501,329 Ameren Corp 8.98% $ 41.39 6.02% 4.38% $ 1.65 $ (39.74) $ 1.75 $ 1.85 $ 1.97 $ 2.08 $ 2.18 $ 2.27 $ 1,888,315 American Electric Pwr Co 8.66% $ 56.20 5.20% 4.38% $ 2.15 $ (54.05) $ 2.26 $ 2.38 $ 2.50 $ 2.63 $ 2.75 $ 2.87 $ 2,384,988 Avista Corp 8.99% $ 33.00 6.00% 4.38% $ 1.32 $ (31.68) $ 1.40 $ 1.48 $ 1.57 $ 1.67 $ 1.74 $ 1.82 $ 1,509,323 CMS Energy Corp 8.27% $ 34.26 6.08% 4.38% $ 1.16 $ (33.10) $ 1.23 $ 1.31 $ 1.38 $ 1.47 $ 1.53 $ 1.60 $ 1,330,216 Consolidated Edison Inc 8.73% $ 60.86 2.49% 4.38% $ 2.60 $ (58.26) $ 2.66 $ 2.73 $ 2.80 $ 2.87 $ 2.99 $ 3.13 $ 2,598,606 Dominion Resources Inc 8.64% $ 71.29 6.60% 4.38% $ 2.59 $ (68.70) $ 2.76 $ 2.94 $ 3.14 $ 3.34 $ 3.49 $ 3.64 $ 3,028,719 Duke Energy Corp New 9.01% $ 76.75 4.83% 4.38% $ 3.21 $ (73.54) $ 3.37 $ 3.53 $ 3.70 $ 3.88 $ 4.05 $ 4.22 $ 3,511,010 Edison International 7.18% $ 62.28 3.07% 4.38% $ 1.71 $ (60.57) $ 1.76 $ 1.82 $ 1.87 $ 1.93 $ 2.01 $ 2.10 $ 1,747,647 El Paso Electric Co 7.91% $ 36.87 5.25% 4.38% $ 1.17 $ (35.70) $ 1.23 $ 1.30 $ 1.36 $ 1.44 $ 1.50 $ 1.56 $ 1,300,346 Empire District Electric Co 9.10% $ 24.25 4.33% 4.38% $ 1.05 $ (23.20) $ 1.10 $ 1.14 $ 1.19 $ 1.24 $ 1.30 $ 1.36 $ 1,126,851 Great Plains Energy Inc 8.75% $ 26.48 6.20% 4.38% $ 1.00 $ (25.48) $ 1.06 $ 1.13 $ 1.20 $ 1.27 $ 1.33 $ 1.39 $ 1,152,080 IDACORP Inc 7.52% $ 61.15 3.00% 4.38% $ 1.88 $ (59.27) $ 1.94 $ 1.99 $ 2.05 $ 2.12 $ 2.21 $ 2.31 $ 1,916,423 NorthWestern Corp. 8.50% $ 52.62 5.50% 4.38% $ 1.92 $ (50.70) $ 2.03 $ 2.14 $ 2.25 $ 2.38 $ 2.48 $ 2.59 $ 2,154,248 OGE Energy Corp 7.87% $ 32.01 4.00% 4.38% $ 1.05 $ (30.96) $ 1.09 $ 1.14 $ 1.18 $ 1.23 $ 1.28 $ 1.34 $ 1,112,519 Pacific Gas and Electric Co. 8.35% $ 52.77 6.14% 4.38% $ 1.82 $ (50.95) $ 1.93 $ 2.05 $ 2.18 $ 2.31 $ 2.41 $ 2.52 $ 2,091,789 Pinnacle West Capital Corp 8.69% $ 61.90 4.57% 4.38% $ 2.44 $ (59.46) $ 2.55 $ 2.67 $ 2.79 $ 2.92 $ 3.04 $ 3.18 $ 2,642,090 Portland General Electric Co. 8.03% $ 35.85 5.37% 4.38% $ 1.17 $ (34.68) $ 1.23 $ 1.30 $ 1.37 $ 1.44 $ 1.51 $ 1.57 $ 1,306,452 TECO Energy 10.01% $ 19.14 6.90% 4.38% $ 0.90 $ (18.24) $ 0.96 $ 1.03 $ 1.10 $ 1.18 $ 1.23 $ 1.28 $ 1,064,481 Westar Energy Inc 8.52% $ 37.54 4.20% 4.38% $ 1.44 $ (36.10) $ 1.50 $ 1.56 $ 1.63 $ 1.70 $ 1.77 $ 1.85 $ 1,537,510 Xcel Energy Inc 8.50% $ 34.05 4.69% 4.38% $ 1.28 $ (32.77) $ 1.34 $ 1.40 $ 1.47 $ 1.54 $ 1.61 $ 1.68 $ 1.392.742 Mean 8.53% Min 7.18% Max 10.01% Column:
- 1) Prm1.-y group
- 2) Internal rate ofretum calcuation - Investors' discount rate that equates the stock price to the stream of future dividends
- 3) Average stock price
- 4) Average of short-term growth rates used in first 4 years
- 5) Long-term nGDP growth rate used after 2019
- 6) 2015 dividends reported by Value-Line
- 7) Year 0 Cashflow; stock price Jess 2015 dividend 8 through 11 ) Annual cashflow growing at short-term growth rate 12 through 250 ) Annual cashflow growing at long-term growth rate
Schedule AHG-10 l 5-WSEE-115-RTS WOLF CREEK DECOMl\IISSIONING COSTS EXTERNAL TRUST FUND Review of2014 Cost Estimate
.. *ADJUSTED TO REFLECT KCC STAFF INPUTS* ..
in 2014 $ In 2045 $ TOTAL COST DECON method $765,060,000 $1,939,869,279 KGE'S SHARE OF TOTAL COST $359,578,200 $911,738,561 CURRENTVALUEOFTRUST(12/31/14) $ 180,829,742 Adjusted to Reflect Taxes on Unrenliz EQUIVALENT BEFORE TAX RETURN: THE EXPECTED INVESTMENT RETURNS ARE SHOWN ON PAGE 2 OF 2 PAYMENT GROWrH AMOUNT $0 GROWTH RATE FOR COSTS (INFLATION) 3.15%
# OF PERIODS FOR ANALYSIS 30
# OF PERIODS - 1 29 PERIOD OF PAYMENTS MIDYEAR DECOMMISSIONING PERIOD IN YEARS 9 FUND MANAGER FEES 0.576%
BEGIN YR. DECOM ANNUAL EARNINGS ENDYR. LINE YEAR BALANCE EXPENSE CONTRIB. AFTER FEES BALANCE AND TAXES 20I2 20I3 2014 2015 $180,829,742 $2,762,483 $9,I6I,452 $192,753,677 2 2016 192,753,677 5,772,700 9,844,745 $208,371,I22 3 20I7 208,37I,122 5,772,700 10,629,297 $224,773,119 4 2018 224,773,I I9 5,772,700 11,453,263 $24 l ,999,082 5 20I9 24 I,999,082 5,772,700 12,318,620 $260,090,402 6 2020 260,090,402 5,772,700 13,227,450 $279,090,552 7 2021 279,090,552 5,772,700 14,181,935 $299,045,187 8 2022 299,045, I 87 5,772,700 15,I84,369 $320,002,257 9 2023 320,002,257 5,772,700 16,237,I62 $342,012, I I 8 10 2024 342,0I2,I I8 5,772,700 17,342,842 $365,127,660 11 2025 365,127,660 5,772,700 18,504,066 $389,404,427 I2 2026 389,404,427 5,772,700 I6,702,987 $4I 1,880,114 I3 2027 41 I,880,114 5,772,700 17,659,005 $435,311,819 I4 2028 435,3Il,819 5,772,700 I8,655,688 $459,740,207 15 2029 459,740,207 5,772,700 19,694,766 $485,207,673 I6 2030 485,207,673 5,772,700 20,778,042 $511,758,415 17 20:31 51 I,758,415 5,772,700 21,907,395 $539,438,510 I8 2032 539,438,510 5,772,700 23,084,786 $568,295,997 19 2033 568,295,997 5,772,700 24,312,259 $598,380,956 20 2034 598,380,956 5,772,700 25,591,943 $629,745,598 2I 2035 629, 745,598 5,772,700 26,926,059 $662,444,357 22 2036 662,444,357 5,772,700 21,663,615 $689,880,672 23 2037 689,880,672 5,772,700 22,556,274 $718,209,645 24 2038 718,209,645 5,772,700 23,477,976 $747,460,321 25 2039 747,460,321 5,772,700 24,429,666 $777,662,687 26 2040 777,662,687 5,772,700 25,412,320 $808,847;707 27 2041 808,847,707 5,772,700 26,426,945 $841,047,352 28 2042 841,047,352 5,772,700 27,474,582 $874,294,634 29 2043 874,294,634 5,772,700 28,556,305 $908,623,638 30 2044 908,623,638 5,772,700 29,673,222 $944,069,560 31 2045 944,069,560 76,742,I07 I,443,175 15,496,37I $884,266,999 32 2046 884,266,999 I 70,390,309 13,361,348 $727,238,039 33 2047 727,238,039 209,293,207 l0,I89,8I8 $528, I34,650 34 2048 528,I34,650 I56,404,173 7,349,097 $379,079,574 35 2049 379,079,574 127,253,390 5,lOI,820 $256,928,004 36 2050 256,928,004 114,089,268 3,I36,287 $145,975,022 37 2051 145,975,022 58,558,037 1,854,229 $89,271,2I3 38 2052 89,271,2I3 54,764,209 915,049 $35,422,054 39 2053 35,422,054 35,623,IOI 202,618 $I,571
Schedule AHG-10 15-WSEE-115-RTS KCC Adjustments to ExRected Returns FEDERAL TAX RATE 20.00% FOR THE YEARS 2012 THROUGH 2025 EXPECTED WEIGHTED AFTER INVESTMENT MIX RETURNS RATIO RETURN TAX Large Cap 7.60% 30% 2.28% 1.82% Small Cap 8.81% 8% 0.70% 0.56% International Equities 8.14% 16% 1.30% 1.04% Core Fixed Income 4.95% 21% 1.04% 0.83% High Yield Bonds 6.40% 20% 1.28% 1.02% Real Estate 8.17% 5% 0.41% 0.33% Cash and equivalents 2.00% 0% 0.00% 0.00% 100% 7.01% 5.60% FOR THE YEARS 2026 THROUGH 2035 EXPECTED WEIGHTED AFTER INVESTMENT MIX RETURNS RATIO RETURN TAX Large Cap 7.60% 20% 1.52% 1.22% Small Cap 8.81% 5% 0.44% 0.35% International Equities 8.14% 12% 0.98% 0.78% Core Fixed Income 4.95% 44% 2.18% 1.74% High Yield Bonds 6.40% 8% 0.51% 0.41% Real Estate 8.17% 3% 0.25% 0.20% Cash and equivalents 2.00% 8% 0.16% 0.13% 100% 6.04% 4.83% FOR THE YEARS 2036 THROUGH 2044 EXPECTED WEIGHTED AFTER INVESTMENT MIX RETURNS RATIO RETURN TAX Large Cap 7.60% 10% 0.76% 0.61% Small Cap 8.81% 2% 0.18% 0.14% International Equities 8.14% 3% 0.24% 0.19% Core Fixed Income 4.95% 65% 3.22% 2.58% High Yield Bonds 6.40% 0% 0.00% 0.00% Real Estate 8.17% 0% 0.00% 0.00% Cash and equivalents 2.00% 20% 0.39% 0.31% 100% 4.79% 3.83% FOR THE YEARS 2045 THROUGH COMPLETION OF DECOMMISSIONING EXPECTED WEIGHTED AFTER INVESTMENT MIX RETURNS RATIO RETURN TAX Large Cap 7.60% 0% 0.00% 0.00% Small Cap 8.81% 0% 0.00% 0.00% International Equities 8.14% 0% 0.00% 0.00% Core Fixed Income 4.95% 30% l.49% 1.19% High Yield Bonds 6.40% 0% 0.00% 0.00% Real Estate 8.17% 0% 0.00% 0.00% Cash and equivalents 2.00% 70% 1.40% 1.12% 100% 2.89% 2.31%
CERTIFICATE OF SERVICE 15-WSEE-115-RTS I, the undersigned, hereby certify that a true and correct copy of the above and foregoing Direct Testimony was served by electronic service on this 9th day of July, 2015, to the following parties who have waived receipt of follow-up hard copies. JAMES G. FLAHERTY, ATTORNEY KURT J. BOEHM, ATTORNEY ANDERSON & BYRD, L.L.P. BOEHM, KURTZ & LOWRY 216 S HICKORY 36 E SEVENTH ST STE 1510 PO BOX 17 CINCINNATI, OH 45202 OTTAWA, KS 66067 Fax: 513-421-2764 Fax: 785-242-1279 kboehm@bkllawfirm.com jflaherty@andersonbyrd.com JODY KYLER COHN, ATTORNEY ANDREW J ZELLERS, GEN COUNSELNP REGULATORY BOEHM, KURTZ & LOWRY AFFAIRS 36 E SEVENTH ST STE 1510 BRIGHTERGY, LLC CINCINNATI, OH 45202 1617 MAIN ST 3RD FLR Fax: 513-421-2764 KANSAS CITY, MO 64108 jkylercohn@bkllawfirm.com Fax: 816-511-0822 andy .zellers@brig htergy .com GLENDA CAFER, ATTORNEY TERRI PEMBERTON, ATTORNEY CAFER PEMBERTON LLC CAFER PEMBERTON LLC 3321SW6TH ST 3321 SW 6TH ST TOPEKA, KS 66606 TOPEKA, KS 66606 Fax: 785-233-3040 Fax: 785-233-3040 glenda@caferlaw.com terri@caferlaw.com NIKI CHRISTOPHER, ATTORNEY DELLA SMITH CITIZENS' UTILITY RATEPAYER BOARD CITIZENS' UTILITY RATEPAYER BOARD 1500 SWARROWHEAD RD 1500 SWARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3116 Fax: 785-271-3116 n.christopher@curb.kansas.gov d.smith@curb.kansas.gov SHONDA SMITH DAVID SPRINGE, CONSUMER COUNSEL CITIZENS' UTILITY RATEPAYER BOARD CITIZENS' UTILITY RATEPAYER BOARD 1500 SW ARROWHEAD RD 1500 SWARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3116 Fax: 785-271-3116 sd.smith@curb.kansas.gov d.springe@curb.kansas.gov
CERTIFICATE OF SERVICE 15-WSEE-115-RTS KEVIN HIGGINS JULIE B. HUNT ENERGY STRATEGIES, LLC HOLLYFRONTIER CORPORATION PARKSIDE TOWERS 2828 N HARWOOD STE 1300 215 S STATE ST STE 200 DALLAS, TX 75201 SALT LAKE CITY, UT 84111 julie.hunt@hollyfrontier.com Fax: 801-521-9142 khiggins@energystrat.com JOHN R. WINE, JR. MICHAEL NEELEY, LITIGATION COUNSEL 410 NE 43RD KANSAS CORPORATION COMMISSION TOPEKA, KS 66617 1500 SWARROWHEAD RD Fax: 785-246-0339 TOPEKA, KS 66604-4027 jwine2@cox.net Fax: 785-271-3167 m.neeley@kcc.ks.gov AMBER SMITH, LITIGATION COUNSEL JAY VAN BLARICUM, ASSISTANT GENERAL COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SWARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604-4027 TOPEKA, KS 66604-4027 Fax: 785-271-3167 Fax: 785-271-3314 a.smith@kcc.ks.gov j.vanblaricum@kcc.ks.gov ROBERT V. EYE, ATTORNEY AT LAW JACOB J SCHLESINGER, ATTORNEY KAUFFMAN & EYE KEYS FOX & WIEDMAN LLP 123 SE 6TH AVE STE 200 1400 16TH ST THE DIBBLE BUILDING 16 MARKET SQUARE, STE 400 TOPEKA, KS 66603 DENVER, CO 80202 Fax: 785-234-4260 jschlesinger@kfwlaw.com bob@kauffmaneye.com ANNE E. CALLENBACH, ATTORNEY FRANK A. CARO, JR., ATTORNEY POLSINELLI PC POLSINELLI PC 900 W 48TH PLACE STE 900 900 W 48TH PLACE STE 900 KANSAS CITY, MO 64112 KANSAS CITY, MO 64112 Fax: 913-451-6205 Fax: 816-753-1536 acallenbach@polsinelli.com fcaro@polsinelli.com LUKE A. HAGEDORN, ATTORNEY JAMES P. ZAKOURA, ATTORNEY POLSINELLI PC SMITHYMAN & ZAKOURA, CHTD. 900 W 48TH PLACE STE 900 7400W110TH ST STE 750 KANSAS CITY, MO 64112 OVERLAND PARK, KS 66210-2362 Fax: 913-451-6205 Fax: 913-661-9863 lhagedorn@polsinelli.com jim@smizak-law.com
CERTIFICATE OF SERVICE - 15-WSEE-115-RTS MARTIN J. BREGMAN, ATTORNEY Stefan Evanoff, VICE-PRESIDENT, PIPELINE STINSON LEONARD STREET LLP MANAGEMENT 1201 WALNUT ST STE 2900 TALLGRASS PONY EXPRESS PIPELINE, LLC KANSAS CITY, MO 64106 370 Van Gordon Street Fax: 816-691-3495 Lakewood, CO 80228 marty.bregman@stinsonleonard.com stefan.evanoff@tallgrassenergylp.com ADAM SCHICHE, SENIOR ATTORNEY KATHERINE COLEMAN TALLGRASS PONY EXPRESS PIPELINE, LLC THOMPSON & KNIGHT LLP 370 Van Gordon Street 98 SAN JACINTO BLVD STE 1900 Lakewood, CO 80228 AUSTIN, TX 78701 adam.schiche@tallgrassenergylp.com Fax: 512-469-6180 katie.coleman@tklaw.com PHILLIP OLDHAM TIMOTHY E. MCKEE, ATTORNEY THOMPSON & KNIGHT LLP TRIPLETT, WOOLF & GARRETSON, LLC 98 SAN JACINTO BLVD STE1900 2959 N ROCK RD STE 300 AUSTIN, TX 78701 WICHITA, KS 61226 Fax: 512-469-6180 Fax: 316-630-8101 phillip.oldham@tklaw.com temckee@twgfirm.com SAMUEL D. RITCHIE, ATTORNEY DAVID BANKS, ENERGY MANAGER TRIPLETT, WOOLF & GARRETSON, LLC UNIFIED SCHOOL DISTRICT 259 2959 N ROCK RD STE 300 201 N WATER WICHITA, KS 67226 WICHITA, KS 67202 Fax: 316-630-8101 Fax: 316-973-2150 sdritchie@twgfirm.com dbanks@usd259.net THOMAS R. POWELL, GENERAL COUNSEL KEVIN K. LACHANCE, CONTRACT LAW ATTORNEY UNIFIED SCHOOL DISTRICT 259 UNITED STATES DEPARTMENT OF DEFENSE 201 N WATER ST RM 405 ADMIN & CIVIL LAW DIVISION WICHITA, KS 67202-1292 OFFICE OF STAFF JUDGE ADVOCATE tpowell@usd259.net FORT RILEY, KS 66442 Fax: 785-239-0577 kevin.k.lachance.civ@mail.mil MATTHEW DUNNE, GENERAL ATTORNEY CATHRYN J. DINGES, SENIOR CORPORATE COUNSEL US ARMY LEGAL SERVICES AGENCY WESTAR ENERGY, INC. REGULATORY LAW OFFICE (JALS-RUIP) 818 S KANSAS AVE 9275 GUNSTON RD STE 1300 PO BOX889 FORT BELVOIR, VA 22060-5546 TOPEKA, KS 66601-0889 matthew.s.dunne.civ@niail.mil Fax: 785-575-8136 cathy.dinges@westarenergy.com
CERTIFICATE OF SERVICE 15-WSEE-115-RTS JEFFREY L. MARTIN, VICE PRESIDENT, REGULATORY CINDY S. WILSON, DIRECTOR, RETAIL RATES AFFAIRS WESTAR ENERGY, INC. WESTAR ENERGY, INC. 818 S KANSAS AVE 818 S KANSAS AVE PO BOX889 PO BOX889 TOPEKA, KS 66601-0889 TOPEKA, KS 66601-0889 cindy.s.wilson@westarenergy.com jeff.martin@westarenergy.com DAVID L. WOODSMALL WOODSMALL LAW OFFICE 308 E HIGH ST STE 204 JEFFERSON CITY, MO 65101 Fax: 573-635-7523 david.woodsmall@woodsmalllaw.com Pamela Griffeth Pamela Griffeth Administrative Specialist
Enclosure XI I to CO 17-0003 Decommissioning Cost Analysis for the Wolf Creek Generating Station (133 pages) _J
Document Wll-1697-001, Rev. 0 DECOMMISSIONING COST ANALYSIS for the WOLF CREEK GENERATING STATION prepared for the Wolf Creek Nuclear Operating Corporation prepared by . TLG Services, Inc. Bridgewater, Connecticut August 2014
Wolf Creeh Genemting Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Page ii of xvii APPROVALS Project Manager Z8 A1J 2()tY William A. Cloutier, J . Date Project Engineer Project Engineer LtV1=1f-Th01na~. Garrett Technical Manager TLG Services.* Inc.
Wolf Creel? Generating Station Document Wl 1-1697-001, Rev. {) Decommissioning Cost Analysis Page iii of xix TABLE OF CONTENTS SECTION PAGE EXECUTIVE SUl\!Il\!Lt\RY ................................................................................... vii-xix
- 1. INTRODUCTION ..................................................................................................... 1-1 1.1 Objectives of Study ........................................................................................... 1-1 1.2 Site Description ................................................................................................. 1-1 1.3 Regulatory Guidance ........................................................................................ 1-2 1.3.l High-Level Radioactive Waste Management ...................................... 1-4 1.3.2 Low-Level Radioactive Waste Management ....................................... 1-7 1.3.3 Radiological Criteria for License Termination .................................... 1-8
- 2. DECOMl\tIISSIONING ALTERNATIVES .............................................................. 2-1 2.1 DECON .............................................................................................................. 2-1 2.1.1 Period 1 - Preparations ......................................................................... 2-1 2.1.2 Period 2 - Decommissioning Operations .............................................. 2-3 2.1.3 Period 3 - Site Restoration .................................................................... 2-7 2.2 SAFSTOR .......................................................................................................... 2-8 2.2.1 Period 1 - Preparations ......................................................................... 2-8 2.2.2 Period 2 - Dormancy .............................................................................. 2-9 2.2.3 Periods 3 and 4 - Delayed Decommissioning ..................................... 2-10 2.2.4 Period 5 - Site Restoration .................................................................. 2-11
- 3. COST ESTIMATE ..................................................................................................... 3-1 3.1 Basis of Estimate .............................................................................................. 3-1 3.2 Methodology ...................................................................................................... 3-1 3.3 Financial Components of the Cost Model ....................................................... 3-3 3.3.1 Contingency ........................................................................................... 3-3 3.3.2 Financial Risk ........................................................................................ 3-5 3.4 Site-Specific Considerations ............................................................................. 3-6 3.4. l Spent Fuel Management ....................................................................... 3-6 3.4.2 Reactor Vessel and Internal Components ........................................... 3-8 3.4.3 Primary System Components ............................................................... 3-9 3.4.4 Main Turbine and Condenser .............................................................. 3-10 3.4.5 Transportation Methods ..................................................................... 3-10 3.4.6 Low-Level Radioactive Waste Disposal ............................................. 3-11 3.4. 7 Site Conditions Following Decommissioning .................................... 3-12 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev.() Decommissioning Cost Analysis Page iv of xix TABLE OF CONTENTS (continued) SECTION PAGE 3.5 Assumptions .................................................................................................... 3-13 3.5.1 Estimating Basis ................................................................................. 3-13 3.5.2 Labor Costs .......................................................................................... 3-13 3.5.3 Design Conditions ................................................................................ 3-14 3.5.4 General ................................................................................................. 3-15 3.6 Cost Estimate Summary ............................................................................... 3-17
- 4. SCHEDULE ESTIIVIATE ..............................................._......................................... 4-1 4.1 Schedule Estimate Assumptions ..................................................................... 4-1 4.2 Project Schedule ................................................................................................ 4-2
- 5. RADIOACTIVE WASTES .............................................. .-......................................... 5-1
- 6. RESULTS ................................................................................................................. 6-1
- 7. REFERENCES .......................................................................................................... 7-1 TABLES DECON Cost Summary, Decommissioning Cost Elements ......................... xviii SAFSTOR Cost Summary, Decommissioning Cost Elements ....................... xix 3.1 DECON Alternative, Total Annual Expenditures ........................................ 3-19
- 3. la DECON Alternative, License Termination Expenditures ........................... 3-20 3.lb DECON Alternative, Spent Fuel Management Expenditures ..................... 3-21 3.lc DECON Alternative, Site Restoration Expenditures ................................... 3-22 3.2 SAFSTOR Alternative, Total Annual Expenditures .................................... 3-23 3.2a SAFSTOR Alternative, License Termination Expenditures ........................ 3-25 3.2b SAFSTOR Alternative, Spent Fuel Management Expenditures ................. 3-27 3.2c SAFSTOR Alternative, Site RestOl'ation Expenditures ............................... 3-28 5.1 DECON Alternative, Decommissioning Waste Summary ............................. 5-5 5.2 SAFSTOR Alternative, Decommissioning Waste Summary .......................... 5-6 6.1 DE CON Alternative, Decommissioning Cost Elements ................................. 6-4 6.2 SAFSTOR Alternative, Decommissioning Cost Elements ............................. 6-5 TLG Services, Inc.
Wolf Creek Generating Station Document W11-HJ97-001, Rev. () Decommissioning Cost Analysis Page v of xix TABLE OF CONTENTS (continued) SECTION PAGE FIGURES 4.1 Activity Schedule .............................................................................................. 4-3 4.2 Decommissioning Time line, DE CON Alternative .......................................... 4-4 4.3. Decommissioning Timeline, SAFSTOR Alternative ....................................... 4-5
- 5. 1 . . . UT R a d10act1ve t D. . . ........................................................................ o- ,._ 3 n as e 1spos1t10n 5.2 Decommissioning Waste Destinations, Radiological.. .................................... 5-4 APPENDICES A. Unit Cost Factor Development ............................................................................. A-1 B. Unit Cost Factor Listing ...................................................................................... B-1 C. Detailed Cost Analysis, DECON ................................................................ ~ ......... C-1 D. Detailed Cost Analysis, SAFSTOR ...................................................................... D-1 E. Cost Sensitivity of Long-Term, On-Site Spent Fuel Storage ............................. E-1 F. Response to June 13, 2013 Order .......................................................................... F-1 TLG Services, Inc.
Wolf Creek Generating Station Document WH-1697-001, Rev. 0 Decommissioning Cost Ancdysis Page vi of xix REVISION LOG No. Date Item Revised Reason for Revision 0 08-28-2014 Original Issue TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev.() Decommissioning Cost Analysis Page vii of xix EXECUTIVE
SUMMARY
This report presents estimates of the cost to decommission the Wolf Creek Generating Station (Wolf Creek) for the selected decommissioning scenarios following the scheduled cessation of plant operations. The estimates are designed to provide the Wolf Creek Nuclear Operating Corporation (WCNOC), the plant's operator, and its owners: Kansas Gas and Electric Company, a wholly owned subsidiary of Westar Energy, Inc., Kansas City Power & Light Company, a wholly owned subsidiary of Great Plains Energy Incorporated, and Kansas Electric Power Cooperative, Inc., with sufficient information to assess their financial obligations, as they pertain to the eventual decommissioning of the nuclear station. The analysis relies upon site-specific, technical information from an evaluation prepared in 2011,[ll updated to reflect current assumptions pertaining to the disposition of the nuclear station and relevant industry experience in undertaking such projects. The* analysis is not a comprehensive engineering evaluation, but estimates prepared in advance of the detailed planning required to execute the decommissioning of the nuclear station. It may also not reflect the actual plan to decommission Wolf Creek; the plan may differ from the assumptions made in this analysis based on facts that exist at the time of decommissioning. The costs to decommission Wolf Creek are presented at the end of this section. Costs are reported in 2014 dollars and include monies anticipated to be spent for radiological remediation and operating license termination, spent fuel management, and site restoration activities. A complete discussion of the assumptions relied upon in this analysis is provided in Section 3, along with schedules of annual expenditures for the two scenarios. A sequence of significant project activities is provided in Section 4 with a timeline for each scenario. Detailed cost reports used to generate the summary tables contained within this document are provided in the appendices along with the costs for the additional scenarios. Consistent with the 2011 analysis, the current cost estimates assume that the shutdown of the nuclear station is a scheduled and pre-planned event (e.g., there is no delay in transitioning the plant and workforce from operations or in obtaining regulatory relief from operating requirements, etc.). The estimates include the continued operation of the fuel handling building as an interim wet fuel storage facility for approximately five and one-half years after operations cease (years 2045 "Decommissioning Cost Analysis for the Wolf Creek Generating Station," Document No. Wll-1642-001, Rev. 0, TLG Services, Inc., August 2011 TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Page viii of xix through 2050). During this time period, it is assumed that the Department of Energy (DOE) will complete the transfer of the spent fuel from the site to a federal facility. Alternatives and Regulations The ultimate objective of the decommissioning process is to reduce the inventory of contaminated and activated material so that the license can be terminated. The Nuclear Regulatory Commission (NRC or Commission) provided initial decommissioning requirements in its rule adopted on June 27, 1988J2J In this rule, the NRC set forth financial criteria for decommissioning licensed nuclear power facilities. The regulations addressed planning needs, timing, funding methods, and environmental review requirements for decommissioning. The rule also defined three decommissioning alternatives as being acceptable to the NRC: DECON, SAFSTOR, and ENTOMB. DECON is defined as "the alternative in which the equipment, structurns, and portions of a facility and site containing radioactive contaminants are removed or decontaminated to a level that permits the property to be released for unrestricted use shortly after cessation of operations. "[3J SAFSTOR is defined as "the alternative in which the nuclear facility is placed and maintained in a condition that allows the nuclear facility to be safely stored and subsequently decontaminated (deferred decontamination) to levels that permit release for unrestricted use."l4J Decommissioning is to be completed within 60 years, although longer time periods will be considered when necessary to protect public health and safety. ENTOMB is defined as "the alternative in which radioactive contaminants are encased in a structurally long-lived material, such as concrete; the entombed structure is appropriately maintained and continued surveillance is carried out until the radioactive material decays to a level permitting unrestricted release of the property."l5J As 2 U.S. Code of Federal Regulations, Title 10, Parts 30, 40, 50, 51, 70 and 72 "General Requirements for Decommissioning Nuclear Facilities," Nuclear Regulatory Commission, Federal Register Volume 53, Number 123 (p 24018 et seq.), June 27, 1988 3 Ibid. Page FR24022, Column 3 4 Ibid. 5 Ibid. Page FR24023, Column 2 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Page ix of xix with the SAFSTOR alternative, decommissioning is currently required to be completed within 60 years, although longer time periods will also be considered when necessary to protect public health and safety. The 60-year restriction has limited the practicality for the ENTOMB alternative at commercial reactors that generate significant amounts of long-lived radioactive material. In 1997, the Commission directed its staff to re-evaluate this alternative and identify the technical requirements and regulatory actions that would be necessary for entombment to become a viable option. The resulting evaluation provided several recommendations; however, rulemaking has been deferred pending the completion of additional research studies, for example, on engineered barriers. In 1996, the NRC published rev1s10ns to the general requirements for decommissioning nuclear power plants to clarify ambiguities and codify procedures and terminology as a means of enhancing efficiency and uniformity in the decommissioning process.l6J The amendments allow for greater public participation and better define the transition process from operations to decommissioning. Regulatory Guide 1.184,l7l issued in July 2000, further described the methods and procedures acceptable to the NRC staff for implementing the requirements of the 1996 revised rule relating to the initial activities and major phases of the decommissioning process. The costs and schedules presented in this analysis follow the general guidance and processes described in the amended regulations. The format and content of the estimates is also consistent with the recommendations of Regulatory Guide 1.202,181issued in February 2005. ~v'lethodology The methodology used to develop the estimates described within this document follows the basic approach originally presented in the cost estimating guidelinesl9J developed by the Atomic Industrial Forum (now Nuclear Energy Institute). This reference describes a unit factor method for determining decommissioning activity costs. The 6 U.S. Code of Federal Regulations, Title 10, Parts 2, 50, and 51, "Decommissioning of Nuclear Power Reactors," Nuclear Regulatory Commission, Federal Register Volume 61, (p 39278 et seq.), July 29, 1996 "Decommissioning of Nuclear Power Reactors," Regulatory Guide 1.184, Nuclear Regulatory Commission, July 2000 8 "Standard Format and Content of Decommissioning Cost Estimates for Nuclear Power Reactors," Regulatory Guide l.202, Nuclear Regulatory Commission, February 2005 9 T.S. LaGuardia et al., "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates," AIF/NESP-036, May 1986 TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Pagex of xix unit factors used in this analysis incorporate site-specific costs and the latest available information on worker productivity in decommissioning. An activity duration critical path is used to determine the total decommissioning program schedule. The schedule is relied upon in calculating the carrying costs, which include program management, administration, field engineering, equipment rental, and support services, such as quality control and security. Contingencv Consistent with cost estimating practice, contingencies are applied to the decontamination and dismantling costs developed as "specific provision for unforeseeable elements of cost within the defined project scope, particularly important where previous experience relating estimates and actual costs has shown that unforeseeable events which will increase costs are likely to occur."llOJ The cost elements in the estimates are based on ideal conditions; therefore, the types of unforeseeable events that are almost certain to occur in decommissioning, based on industry experience, are addressed through a percentage contingency applied on a line-item basis. This contingency factor is a nearly universal element in all large-scale construction and demolition projects. It should be noted that contingency, as used in this analysis, does not account for price escalation and inflation in the cost of decommissioning over the remaining operating life of the station. Contingency funds are expected to be fully expended throughout the program. As such, inclusion of contingency is necessary to provide assurance that sufficient funding will be available to accomplish the intended tasks. Low-Level Radioactive Waste Disposal The contaminated and activated material generated in the decontamination and dismantling of a commercial nuclear reactor is classified as low-level (radioactive) waste, although not all of the material is suitable for "shallow-land" disposal. With the passage of the "Low-Level Radioactive Waste Policy Act" in 1980,flll and its i\.mendments of 1985,[121 the states became ultimately responsible for the disposition of low-level radioactive waste generated within their own borders. With the exception of Texas, no new compact facilities have been successfully sited, licensed, and constructed. The Texas Compact disposal facility is now operational and 10 Project and Cost Engineers' Handbook, Second Edition, American Association of Cost Engineers, Marcel Dekker, Inc., New York, New York, p. 239 11 "Low-Level Radioactive Waste Policy Act of 1980," Public Law 96-578, 1980 1
~ "Low-Level Radioactive Waste Policy Amendments Act of 1985," Public Law 9B-240, 1986.
TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-0fH, Rev. 0 Decommissioning Cost Analysis Page xi of xix waste is being accepted from generators within the Compact by the operator, Waste Control Specialists (WCS). The facility is also able to accept limited quantities of non-Compact waste. Disposition of the various waste streams produced by the decommissioning process considered all options and services currently available to WCNOC. The majority of the low-level radioactive waste designated for controlled disposal (Class AlI3J) can be sent to EnergySolutions' facility in Clive, Utah. Therefore, disposal costs for Class A waste were based upon WCNOC's "Long Term Waste Disposal Agreement" with EnergySolutions. This facility is not licensed to receive the higher activity portion (Classes B and C) of the decommissioning waste stream. The WCS facility is able to receive the Class Band C waste. As such, for this analysis, Class B and C waste was assumed to be shipped to the WCS facility for disposal. Disposal costs were based upon preliminary and indicative information for the WCS site. The dismantling of the components residing closest to the reactor core generates radioactive waste that may be considered unsuitable for shallow-land disposal (i.e., low-level radioactive waste with concentrations of radionuclides that exceed the limits established by the NRC for Class C radioactive waste (GTCC)). The Low-Level Radioactive Waste Policy Amendments Act of 1985 assigned the federal government the responsibility for the disposal of this material. The Act also stated that the beneficiaries of the activities resulting in the generation of such radioactive waste bear all reasonable costs of disposing of such waste. However, to date, the federal government has not identified a cost for disposing of GTCC or a schedule for acceptance. For purposes of this analysis only, the GTCC radioactive waste is assumed to be packaged and disposed of in a similar manner as high-level waste and at a cost equivalent to that envisioned for the spent fuel. The GTCC is packaged in the same canisters used fo1* spent fuel and shipped directly to a DOE facility as it is generated. A significant portion of the waste material generated during decommissioning may only be potentially contaminated by radioactive materials. This material can be analyzed on site or shipped off site to licensed facilities for further analysis, for processing and/or for conditioning/recovery. Reduction in the volume of low-level radioactive waste requiring disposal in a licensed low-level radioactive waste disposal facility can be accomplished through a variety of methods, including analyses and surveys or decontamination to eliminate the portion of waste that does not require t3 Waste is classified in accordance with U.S. Code of Federal Regulations, Title 10, Part 61.55 TLG Services, Inc.
Wolf Creell Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Page xii of xix disposai as radioactive waste, compaction, incineration or metal melt. The estimates reflect the savings from waste recovery/volume reduction. High-Level Radioactive Waste Management Congl'ess passed the "Nuclear Waste Policy Act"f14J (NWPA) in 1982, assigning the federal government's long-standing responsibility for disposal of the spent nuclear fuel created by the commercial nuclear generating plants to the DOE. The DOE was to begin accepting spent fuel by January 31, 1998; however, to date no progi*ess in the removal of spent fuel from commercial generating sites has been made. Today, the country is at an impasse on high-level waste disposal, even with the License Application for a geologic repository submitted by the DOE to the NRC in 2008. The current administration has eliminated the budget for the repository program while promising to "conduct a comprehensive review of policies for managing the back end of the nuclear fuel cycle ... and make recommendations for a new plan."l 15l Towards this goal, the administration appointed a Blue Ribbon Commission on America's Nuclear Future (Blue Ribbon Commission) to make recommendations for a new plan for nuclear waste disposal. The Blue Ribbon Commission's charter includes a requirement that it consider "[o]ptions for safe storage of used nuclear fuel while final disposition pathways are selected and deployed." l161 On January 26, 2012, the Blue Ribbon Commission issued its "Report to the Secretary of Energy" containing a number of recommendations on nuclear waste disposal. Two of the recommendations that may impact decommissioning planning are:
"' "[T]he United States [should] establish a program that leads to the timely development of one or more consolidated storage facilities"[17J <~ "[T]he United States should undertake an integrated nuclear waste management program that leads to the timely development of one or more u "Nuclear Waste Policy Act of 1982 and Amendments," DO E's Office of Civilian Radioactive Management, 1982 15 Charter of the Blue Ribbon Commission on America's Nuclear Future, "Objectives and Scope of Activities," h ttn:/iwww .brc.govlincle_;,:. phn ?q=page/charter 16 Ibid.
17 "Blue Ribbon Commission on America's Nuclear Future, Report to the Secretary of Energy," http://w\nv. brc.*rov/sitedclefnult/fikMdocuments/brc final report ian2012.12.df, p. 32, January 2012 TLG Services, Inc.
Wolf Crwek Generating Station Document W11-16'9'l-001, Rev. 0 Decommissioning Cost Analysis Page xiii of xix permanent deep geological facilities for the safe disposal of spent fuel and high-level nuclear waste."[181 In January 2013, the DOE issued the "Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste," in response to the recommendations made by the Blue Ribbon Commission and as "a framework for moving toward a sustainable program to deploy an integrated system capable of transporting, storing, and disposing of used nuclear fuel..."l 19l This document states: "With the appropriate authorizations from Congress, the Administration currently plans to implement a program over the next 10 years that: o Sites, designs and licenses, constructs and begins operations of a pilot interim storage facility by 2021 with an initial focus on accepting used nuclear fuel from shut-down reactor sites; e Advances toward the siting and licensing of a larger interim storage facility to be available by 2025 that will have sufficient capacity to provide flexibility in the waste management system and allows for acceptance of enough used nuclear fuel to reduce expected government liabilities; and Makes demonstrable progress on the siting and characterization of repository sites to facilitate the availability of a geologic repository by 2048."[2 0l The NRC's review of DOE's license application to construct a geologic repository at Yucca Mountain was suspended in 2011 when the Administration slashed the budget for completing that work. However, the US Court of Appeals for the District of Columbia Circuit recently issued a writ of mandamus (in August 2013) ordering NRC to comply with federal law and restart its review of DOE's Yucca Mountain repository license application to the extent of previously appropriated funding for the review. Completion of the decommissioning process is dependent upon the DOE's ability to remove spent fuel from the site in a timely manner. DOE's repository program assumed that spent fuel allocations would be accepted for disposal from the nation's commercial nuclear plants, with limited exceptions, in the order (the "queue") in which it was discharged from the reactor. The current spent fuel management plan for the Wolf Creek spent fuel is based in general upon: 1) a 2025 start date for DOE initiating 18 Ibid., p.27 19 "Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste," U.S. DOE, January 11, 2013 20 Ibid., p.2 TLG Services, Inc.
Wolf Creeh Generating Station Document Wl 1-169'!-0{)1, Rev. () Decommissioning Cast A..nalysis Page xiv of xix transfer of commercial spent fuel to a federal facility, and 2) a 2032 start date for the transfer of spent fuel from the vVolf Creek site based on an oldest fuel ftl'st priority, and the DOE achieving an annual rate of transfer (3,000 metric tons of uranium per year) as reflected in DOE's latest Acceptance Priority Ranking and Annual Capacity Report.l21 l The estimates also assume that the DOE would give priority to fuel at shutdown sites, i.e., it is assumed that Congress would "(1) ... direct the Department to take spent nuclear fuel from decommissioned commercial nuclear power reactors as soon as possible; (2) to establish an expedited siting process; and (3) to authorize the Department to construct and operate the facility under its regulatory authority, or, if the facility were to be constructed and operated under a U.S. Nuclear Regulatory Commission license, to provide for an expedited siting and licensing process."l22l It is generally necessary that spent fuel be cooled and stored for a minimum period at the generating site prior to transfer. As such, the NRC requires that licensees establish a program to manage and provide funding for the management of all irradiated fuel at the reactor site until title of the fuel is transferred to the Secretary of Energy, pursuant to 10 CFR Part 50.54(bb).f28J The post-shutdown costs incurred to satisfy this requirement include the isolation and continued operation of the spent fuel pool and the Independent Spent Fuel Storage Installation (ISFSI) during the five and one-half years following the cessation of plant operations. At shutdown, the spent fuel pool is expected to contain freshly discharged assemblies (from the most recent refueling cycles) as well as the final reactor core. Over the following five and one-half years the assemblies axe packaged into multipurpose canisters fox transfer to the DOE. It is assumed that this period provides the necessary cooling for the final core to meet the transportation system requirements for decay heat. Interim storage of the fuel, until the DOE has completed the transfer, will be in the wet storage pool located in the fuel building (as well as on the ISFSI). The pool will be isolated, allowing WCNOC to proceed with decommissioning (or safe-storage preparations) in the shortest time possible. 21 "Acceptance Priority Ranking and Annual Capacity Report," U.S. DOE, Office of Civilian Radioactive Waste Management, DOE/RW-0567, July 2004 22 "Report to Congress on the Demonstration of the Interim Storage of Spent Nuclear Fuel from Decommissioned Nuclear Power Reactor Sites" DOE/RW-0596, December 2008 23 U.S. Code of Federal Regulations, Title 10, Part 50, "Domestic Licensing of Production and Utilization Facilities," Subpart 54 (bb), "Conditions of Licenses" TLG Services, lnc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Page xv of xix Sensitivity of Spent Fuel Management Assumptions The estimates described in this analysis were developed with the assumption that the DOE would give priority to removing spent fuel from shutdown sites. The estimates further assume that the spent fuel would be removed from the Wolf Creek site within five and one-half years of the cessation of plant operations (i.e., five and one-half years would provide sufficient cooling time for the spent fuel to meet DOE transportation requirements). If DOE is unable to remove the spent fuel from the Wolf Creek site within this time period, wet storage pool operations would need to be extended (potentially delaying decommissioning) and/or the ISFSI would be used for the interim storage of the fuel so that decommissioning could proceed. Appendix E evaluates such a scenario (i.e., where spent fuel is accepted from generators in the order in which it was generated or oldest fuel first and the ISFSI is used for interim storage, similar to what has occurred at recently decommissioned reactor sites). The resulting costs for long-term spent fuel management (summarized in Table E) are illustrative only and based upon current regulations and associated constraints that may change as a result of actions taken on the Blue Ribbon Commission's recommendations. It should also be noted that the costs, while incurred by the licensee, may also be recoverable as a result of DOE's breech of its contract to take possession of the spent fuel in a timely manner. However, the analysis described in Appendix E may prove useful as a planning basis should delays continue in the development of a national solution for the disposition of spent fuel and high-level waste. Site Restoration Prompt dismantling of site structures (once the facilities are decontaminated) is clearly the most appropriate and cost-effective option. It is unreasonable to anticipate that these structures would be repaired and preserved after the radiological contamination is removed. The cost to dismantle site structures with a work force already mobilized on site is more efficient than if the process is deferred. Site facilities quickly degrade without maintenance, adding additional expense and creating potential hazards to the public and the demolition work force. Consequently, this study assumes that site structures are removed to a nominal depth of three feet below the local gxade level wherever possible. The site is then to be graded and stabilized. TLG Services, Inc.
Wolf Creek Genemting Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Page xvi of xix Summary The costs to decommission Wolf Creek assume the removal of all contaminated and activated plant components and structural materials such that the owners may then have unrestricted use of the site with no further requirements for an operating license. Low-level radioactive waste, other than GTCC waste, is sent to a commercial processor for treatment/conditioning or to a controlled disposal facility. Decommissioning is accomplished within the 60-year period required by current NRC regulations. The decommissioning scenarios are described in Section 2. The assumptions are presented in Section 3, along with schedules of annual expenditures. The major cost contributors are identified in Section 6, with detailed activity costs, waste volumes, and associated manpower requirements delineated in Appendices C and D. The major cost components are also identified in the cost summary provided at the end of this section. The cost elements in the estimates are assigned to one of three subcategories: 1\TRC License Termination, Spent Fuel Management, and Site R.estoration. The subcategory "NRC License Termination" is used to accumulate costs that are consistent with "decommissioning" as defined by the NRC in its financial assurance regulations (i.e., 10 CFR Part 50.75). The cost reported for this subcategory is generally sufficient to terminate the station's operating license, recognizing that there may be some additional cost impact from spent fuel management. The "Spent Fuel Management" subcategory contains costs associated with the transfer of the spent fuel to the DOE as well as the operation of the spent fuel pool until such time that the transfer is complete. "Site Restoration" is used to capture costs associated with the dismantling and demolition of buildings and facilities demonstrated to be free from contamination. This includes structures never exposed to radioactive materials, as well as those facilities that have been decontaminated to appropriate levels. Structures are removed to a depth of three feet and backfilled to conform to local grade. It should be noted that the costs assigned to these subcategories are allocations. Delegation of cost elements is for the purposes of comparison (e.g., with NRC financial guidelines) or to permit specific financial treatment (e.g., Asset Retirement Obligations determinations). In reality, there can be considerable interaction between the activities in the three subcategories. For example, an owner may decide to i*emove non-contaminated structures early in the project to improve access to highly contaminated facilities or plant components. In these instances, the non-contaminated removal costs TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Page xvii of xix could be reassigned from Site Restoration to an NRC License Termination support activity. However, in general, the allocations represent a reasonable accounting of those costs that can be expected to be incurred for the specific subcomponents of the total estimated program cost, if executed as described. As noted within this document, the estimates were developed and costs are presented in 2014 dollars. As such, the estimates do not reflect the escalation of costs (due to inflationary and market forces) over the remaining operating life of the reactor or during the decommissioning period. TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. (} Decommissioning Cost Analysis Page xviii of xix DECON COST
SUMMARY
DECOMMISSIONING COST ELEMENTS (thousands of 2014 dollars) r~~---~~------~~---~-* -- . *~* - . -.. ~------~~ 1_QQ~~~le!P~E~---**----------* i - - - - - - - * ----------------1--------------1
. -------*---** ______ +-------* QQ~-~------ ,,
~-Q~~_2nta111-i1-!?:!~2p.__ _ ~ _14,§j_'.3 {
! Removal i------- -------------------------------
- - - - -----------------1 115, 134 !
r*~;;-~-;;;:;ti~n :- =~ -:~-~-~=-~- -~- -=---**** ---- __.:~ =- ~- :- ~- :~:-~- -~[- L- *:-~ : -~1: Ir- Wa~te -Disposal H 88,460 !
~~~-j
- ' -Off-site Waste Processing
- - - - - - - - - - - - --~--- -~-------- - ------- -----*----*-------*-i-------*-*-*----'---~i
! 23 328 I I Program Management r 1 .... -*-------*--*J*"*"**- ------------*-----------***--**-*---- **--- .....,;---
~---~----------------*------ --~-------------
1 \ ----******--*---------------! 265,653 l L Sec_~~j!y___~-- _______________________ ----~--- --* --------'--- ________9-_4, 16?_~ j_yO!POl~at~ ~19-~~.t!Q~§_ . ____ . --*-- _ _ j _. !L~?_2 i r-~I?_~~t-~~:}-tf~!i?g~::~~ ~-Di1:~~t*c~~t-~--[2J- -- *--** ---- --- ***!---- ***- --{~*.~-i~
~ *---~---------*-------------------*--*-***-----*--------*----**********-**------*-***-------**-******** ----- ---....... 1-... *-* - -----------..-----t I
! Insurance and Re~la!2_~ Fee~---*------------*-----------**-- __ j______________14,647 J
- l. ~-IJ:!OlFgy_ -***. -*** . *************-*** __ **--- * * *- ............................. **--** i .!'12~-~QJ
! Characterization and Licensing Surveys . !
L:P!2P~!.!YT~'l{~S_______ . . *- . . --=---------*- - - - - - - -*- . - - . I
--::--r*=------*--*--)Q,,~_i1'l
. 21, 182 f-.M.!§.~ell~n-~5ms Egui~ment __ . _. ______ ---------*--*------- *---~--------*-***-------~~-~?-!
rt~t;l_~,.---~-------~-~~~---*~ -~~J~---~--~7-~§J!§J?J
,_g2~t-~.~~J**---.
l.~-------~-----*---___,
---~~-****----~----=~=*******-*-~~=-~~---*==~=********-*****-*******~*********** ----=~~~it.*~=~~l
**---*-r--***"-*****--**--*******-**- --*---------------~------J
! License Termination 656,060 I
[§2E?~~-f~?l~1~!1-_~~!!!~_!!t... * * * * * . . . . . - ....... * * *~ -: :... .. . * *~* * .* * -* * * * * .:.1~~Q!§J
~§i,!e Restor~~~~g____ _ ....... J J~?_,_~§-~j If~----""**-----***-------*- *- ------****-- ***-*--***--*-* --*****-***---* ....... --*********-** . . -'-***""' ---t--*- , . . . . ***-*-*---*----*---~------*--------i I
. I Total
~-- _,..._... . ., ,., . .,.,[8J
__ .~-~-*--*--------"-'*=-=.._. . . . .--,,-...~. . *~--',,_;,,~,._,_,--~=---=~--~="'~.,,,_~-~*_ ,_ _ _,
' 765 060 l
[ 11 Includes engineering costs [21 Excludes program management costs (staffing) but includes costs for spent fuel loading/packaging/spent fuel pool O&M and Emergency Planning fees [3J Columns may not add due to rounding TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev.{) Decommissioning Cost Analysis Page xix of xix SAFSTOR COST SUMl\'IARY DECOMMISSIONING COST ELEMENTS (thousands of 2014 dollars) [g~;~~!~~~!l~~----:~=~-~=-=~~~:~----,~--~-~~------"'~--~~~~=~~--~-~-------~=-L-- _ _ _ -__ *_ {:;~~i:*~=-~=~i: fii~~~;~-f~~;;i~~ti~~- ----------- - ----- ----- - - ------- -- ----------~ 85-2*:5391 fsp~~t F~~iMa~a-g~~~nt -+ ------------- ii9,22i 1 rsit~- R~~to~~ti~-~- -__ ,,_______ ----- - -*--- - - 62~74ol 2***--*--***--*-*** ..... --*---*-**--*------ --.*. *-*-**-** *- ....... i ..-* ... **-* ..... ****** ..... .. .. -**-" -*--**-*******---**-*-*********-, L----- --- --------- -------------- ---- -------- - - -- ------------ - - - - --------------- - - --------------- - - ___________________J
\Total r31
-~-------*-""'"-"~*~---~=.--
. . . .==<-*~""=>'~-"'"--'=-*~ .... --A=----,,..,.,.1...,..,,__,_,.,.._,_.~=AW*~-"'=~.""'>=......
1,034,501 _ , - . - , , . _ . , " I ' _ '-~-_ __ _ , _ i r11 Includes engineering costs r21 Excludes program management costs (staffing) but includes costs for spent fuel loading/packaging/spent fuel pool O&M and Emergency Planning fees rsJ Columns may not add due to rounding TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Sectfonl, Page 1 of 9
- 1. INTRODUCTION This report presents estimates of the cost to decommission the Wolf Creek Generating Station (Wolf Creek) for the selected decommissioning scenarios following the scheduled cessation of plant operations. The estimates are designed to provide the Wolf Creek Nuclear Operating Corporation (WCNOC), the plant's operator, and its owners: Kansas Gas and Electric Company, a wholly owned subsidiary of Westar Energy, Inc., Kansas City Power & Light Company, a wholly owned subsidiary of Great Plains Energy Incorporated, and Kansas Electric Power Cooperative, Inc., with sufficient information to assess their financial obligations, as they pertain to the eventual decommissioning of the nuclear station.
The analysis relies upon site-specific, technical information from an earlier evaluation prepared in 2011,flJ* updated to reflect cunent assumptions pertaining to the disposition of the nuclear station and relevant industry experience in undertaking such projects. The analysis is not a comprehensive engineering evaluation, but estimates prepared in advance of the detailed planning required to execute the decommissioning of the nuclear station. It may also not reflect the actual plan to decommission Wolf Creek; the plan may differ from the assumptions made in this analysis based on facts that exist at the time of decommissioning. 1.1 OBJECTIVES OF STUDY The objectives of this study were to prepare comprehensive estimates of the costs to decommission Wolf Creek, to provide a sequence or schedule for the associated activities, and to develop waste stream projections from the decontamination and dismantling activities. An operating license was originally issued for Wolf Creek in June of 1985. A license renewal application was filed for the nuclear station in Octobe1* 2006. The NRC approved the application and a renewed licensed was issued in November 2008. As such, this analysis is based upon a 60-year operating life, with a final shutdown date (license expiration) in March of 2045. This date was used as input to scheduling the decommissioning activities. 1.2 SITE DESCRIPTION The Wolf Creek site is located approximately 3.5 miles northeast of the town of Burlington, in Coffey County, Kansas, approximately 75 miles southwest of Kansas City, Kansas. The site is on the east side of a man-made lake formed
- References provided in Section 7 of the document TLG Services, Inc.
Wolf Creeh Generating Station Document WU-16.97-001, Rev. 0 Decommissioning Cost Analysis Sectfonl, Page 2 of 9 by impounding \Volf Creek. The station is an 1,170 MWe (nominal) pressurized water reactor with supporting facilities. Westinghouse Electric Company designed the Nuclear Steam Supply System (NSSS). The system consists of a pressurized water reactor with four independent primary coolant loops, each of which contains a reactor coolant pump and a steam generator. An electrically heated pressurizer and connecting piping complete the system. The NSSS is rated at a thermal power level of 3,579 l\1Wt (3,565 MWt reactor core plus 14 MWt for reactor coolant pumps), with a corresponding turbine-generator gross output of 1,267 MWe. The system is housed within a containment structure, a pre-stressed, post-tensioned concrete structure with cylindrical wall, a hemispherical dome, and a flat foundation slab. The wall and dome form a pre-stressed post-tensioned system. The inside surface of the structure is covered with a carbon steel liner, providing a leak tight membrane. A power conversion system converts heat produced in the reactor to electrical energy. This system converts the thermal energy of the steam into mechanical shaft power and then into electrical energy. The turbine-generator is a tandem-compound, six-flow, four element, 1800-rpm unit. The unit consists of one high pressure and three low-pressure turbine elements driving a directly coupled generator. (The four turbine elements were replaced in 2010 with very similar equipment.) The turbine is operated in a closed feedwater cycle that condenses the steam; the feedwater is returned to the steam generators. Heat rejected in the main condensers is removed by the circulating water system. The circulating water system supplies cooling water to the main condenser, condensing the steam exhausted from the turbine. A large cooling lake provides the heat sink requfred for removal of waste heat in the power plant's thermal cycle. 1.3 REGULATORY GUIDANCE The Nuclear Regulatory Commission (NRC or Commission) provided initial decommissioning requirements in its rule "General Requirements for Decommissioning Nuclear Facilities," issued in June 1988.f2J This rule set forth financial criteria for decommissioning licensed nuclear power facilities. The regulation addressed decommissioning planning needs, timing, funding methods, and environmental review requirements. The intent of the rule was to ensure that decommissioning would be accomplished in a safe and timely manner and that adequate funds would be available for this purpose. Subsequent to the rule, the NRC issued Regulatory Guide 1.159, "Assuring the Availability of Funds for Decommissioning Nuclear Reactors,"l3l which TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section1, Page 3 of 9 provided additional guidance to the licensees of nuclear facilities on the financial methods acceptable to the NRC staff for complying with the requirements of the rule. The regulatory guide addressed the funding requirements and provided guidance on the content and form of the financial assurance mechanisms indicated in the rule. The rule defined three decommissioning alternatives as being acceptable to the NRC: DECON, SAFSTOR, and ENTOMB. The DECON alternative assumes that any contaminated or activated portion of the plant's systems, structures and facilities are removed or decontaminated to levels that permit the site to be released for unrestricted use shortly after the cessation of plant operations. The rule also placed limits on the time allowed to complete the decommissioning process. For SAFSTOR, the process is restricted in overall duration to 60 years, unless it can be shown that a longer duration is necessary to protect public health and safety. The guidelines for ENTOIVIB are similar, providing the NRC with both sufficient levexage and flexibility to ensure that these deferred options are only used in situations where it is reasonable and consistent with the definition of decommissioning. At the conclusion of a 60-year dormancy period (or longer for ENTOMB if the NRC approves such a case), the site would still require significant remediation to meet the unrestricted release limits for license termination. The ENTOlVIB alternative has not been viewed as a viable option for power reactors due to the significant time required to isolate the long-lived radionuclides for decay to permissible levels. However, with rulemaking permitting the controlled release of a site,l4l the NRC has re-evaluated this alternative. The resulting feasibility study, based upon an assessment by Pacific Northwest National Laboratory, concluded that the method did have conditional merit for some, if not most reactors. However, the staff also found that additional i*ulemaking would be needed before this option could be treated as a generic alternative. The NRC had considered rulemaking to alter the 60-year time for completing decommissioning and to clarify the use of engineered barriers for reactor entombments.l5l The NRC's staff has recommended that rulemaking be deferred, based upon several factors, e.g., no licensee has committed to pursuing the entombment option, and the NRC's current priorities, at least until after the additional research studies are complete. The NRC concurred with the staffs recommendation. In 1996, the NRC published i*ev1s1ons to the general requirements for decommissioning nuclear power plants.l61 When the decommissioning regulations were adopted in 1988, it was assumed that the majority of TLG Services, Inc.
Wolf Creek Generating Station Document VVll-1697-001, Rev. 0 Decommissioning Cost Analysis Sectionl, Page 4 of 9 licensees would decommission at the end of the facility's operating licensed life. Since that time, several licensees permanently and prematurely ceased operations. Exemptions from certain operating requirements were required once the reactor was defueled to facilitate the decommissioning. Each case was handled individually, without clearly defined generic requirements. The NRC amended the decommissioning regulations in 1996 to clarify ambiguities and codify procedures and terminology as a means of enhancing efficiency and uniformity in the decommissioning process. The amendments allow for greater public participation and better define the transition process from operations to decommissioning. Under the revised regulations, licensees will submit written certification to the NRC within 30 days after the decision to cease operations. Certification will also be required once the fuel is permanently removed from the reactor vessel. Submittal of these notices will entitle the licensee to a fee reduction and eliminate the obligation to follow certain requirements needed only during operation of the reactor. Within two years of submitting notice of permanent cessation of operations, the licensee is requfred to submit a Post-Shutdown Decommissioning Activities Report (PSDAR) to the NRC. The PSDAR describes the planned decommissioning activities, the associated sequence and schedule, and an estimate of expected costs. Prim* to completing decommissioning, the licensee is required to submit an application to the NRC to terminate the license, which will include a license termination plan (LTP). 1.3.1 High-Level Radioactive Waste Management Congrnss passed the "Nuclear VV' aste Policy Actl 7l (NVVPA) in 1982, assigning the federal government's long-standing responsibility for disposal of the spent nuclear fuel created by the commercial nuclear generating plants to the DOE. The DOE was to begin accepting spent fuel by January 31, 1998; however, to date no progress in the removal of spent fuel from commercial generating sites has been made. Today, the country is at an impasse on high-level waste disposal, even with the License Application for a geologic repository submitted by the DOE to the NRC in 2008. The current administration has eliminated the budget for the repository program while promising to "conduct a comprehensive review of policies for managing the back end of the nuclear fuel cycle ... and make recommendations for a new plan." Towards this goal, the administration appointed a Blue Ribbon Commission on America's Nuclear Future (Blue Ribbon Commission) to make recommendations for a new plan for nuclear waste disposal. The Blue Ribbon Commission's charter includes a requirement that it TLG Services, Inc.
Wolf Creeh Generating Station Document WlJ.-16'97-001, Rev. 0 Decommissioning Cost Analysis Sectionl, Page 5 of .9 consider "[o]ptions fox safe storage of used nuclear fuel while final disposition pathways are selected and deployed."[SJ On January 26, 2012, the Blue Ribbon Commission issued its "Report to the Secretary of Energy" containing a number of recommendations on nuclear waste disposal. Two of the recommendations that may impact decommissioning planning are:
~ "[T]he United States [should] establish a program that leads to the timely development of one or more consolidated storage facilities" Iii' "[T]he United States should undertake an integrated nuclear waste management program that leads to the timely development of one or more permanent deep geological facilities for the safe disposal of spent fuel and high-level nuclear waste."[9J In January 2013, the DOE issued the "Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive \Vaste," in response to the recommendations made by the Blue Ribbon Commission and as "a framework for moving toward a sustainable progTam to deploy an integTated system capable of transporting, storing, and disposing of used nuclear fuel..."[lOJ This document states:
"With the appropriate authorizations from Congress, the Administration currently plans to implement a program over the next 10 years that:
Ii! Sites, designs and licenses, constructs and begins operations of a pilot interim storage facility by 2021 with an initial focus on accepting used nuclear fuel from shut-down reactor sites;
@ Advances toward the siting and licensing of a larger interim storage facility to be available by 2025 that will have sufficient capacity to provide flexibility in the waste management system and allows for acceptance of enough used nuclear fuel to reduce expected government liabilities; and
') l\1akes demonstrable progress on the siting and characterization of repository sites to facilitate the availability of a geologic repository by 2048."
The NRC's review of DOE's license application to construct a geologic repository at Yucca Mountain was suspended in 2011 when the Administration slashed the budget for completing that work. However, TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Sectionl, Page 6 of 9 the US Court of Appeals for the District of Columbia Circuit recently issued a writ of mandamus (in August 2013) ordering NRC to comply with federal law and restart its review of DOE's Yucca Mountain repository license application to the extent of previously appropriated funding for the review. Completion of the decommissioning process is dependent upon the DOE's ability to remove spent fuel from the site in a timely manner. DOE's repository program assumed that spent fuel allocations would be accepted for disposal from the nation's commercial nuclear plants, with limited exceptions, in the order (the "queue") in which it was discharged from the reactor. The current spent fuel management plan for the Vvolf Creek spent fuel is based in general upon: 1) a 2025 start date for DOE initiating transfer of commercial spent fuel to a federal facility, and 2) a 2032 start date for the transfer of spent fuel from the \Volf Creek site based on an oldest fuel first priority, and the DOE achieving an annual rate of transfer (3,000 metric tons of uranium per year) as reflected in DOE's latest Acceptance Priority Ranking and Annual Capacity Report.flll The estimates also assume that the DOE would give priority to fuel at shutdown sites, i.e., it is assumed that Congress would "(1) ... direct the Department to take spent nuclear fuel from decommissioned comme1*cial nuclear power reactors as soon as possible; (2) to establish an expedited siting process; and (3) to authorize the Department to construct and operate the facility under its regulatory authority, or, if the facility were to be constructed and operated under a U.S. Nuclear Regulatory Commission license, to provide for an expedited siting and licensing process."l 12 l It is generally necessary that spent fuel be cooled and stored for a minimum period at the generating site prior to transfer. As such, the NRC requires that licensees establish a program to manage and provide funding for the management of all irradiated fuel at the reactor site until title of the fuel is transferred to the Secretary of Energy, pursuant to 10 CFR Part 50.54(bb).f 18l The post-shutdown costs incurred to satisfy this requirement include the isolation and continued operation of the spent fuel pool and the Independent Spent Fuel Storage Installation (ISFSI) during the five and one-half years following the cessation of plant operations. At shutdown, the spent fuel pool is expected to contain freshly discharged assemblies (from the most recent refueling cycles) as well as TLG Services, Inc.
Wolf Cn!ek Generating Station Document Wll-1697-00.~, Rev. 0 Decommissioning Cast Analysis Sectionl, Page 7 of 9 the final reactor core. Over the following five and one-half years the assemblies are packaged into multipurpose canisters for transfer to the DOE. It is assumed that this period provides the necessary cooling for the final core to meet the transportation system requirements for decay heat. Interim storage of the fuel, until the DOE has completed the transfer, will be in the wet storage pool located in the fuel building (as well as on the ISFSI). The pool will be isolated, allowing WCNOC to proceed with decommissioning (or safe-storage preparations) in the shortest time possible. 1.3.2 Low-Level Radioactive Waste Management The contaminated and activated material generated in the decontamination and dismantling of a commercial nuclear reactor is classified as low-level (radioactive) waste, although not all of the mate1*ial is suitable for "shallow-land" disposal. With the passage of the "Low-Level Radioactive Waste Policy Act" in 1980,[14) and its Amendments of 1985,[151 the states became ultimately responsible for the disposition of low-level radioactive waste generated within their own borders. With the exception of Texas (which has issued a license to Waste Control Specialists for the construction of a new facility in Andrews, Texas), no new compact facilities have been successfully sited, licensed, and constructed. With the exception of Texas, no new compact facilities have been successfully sited, licensed, and constructed. The Texas Compact disposal facility is now operational and waste is being accepted from generators within the Compact by the operator, vVaste Control Specialists (WCS). The facility is also able to accept limited quantities of non-Compact waste. Disposition of the various waste streams produced by the decommissioning process considered all options and services currently available to \VCNOC. The majority of the low-level radioactive waste designated for controlled disposal (Class Al 16l) can be sent to EnergySolutions' facility in Clive, Utah. Therefore, disposal costs for Class A waste were based upon WCNOC's "Long Term "\rVaste Disposal Agreement" with EnergySolutions. This facility is not licensed to receive the higher activity portion (Classes B and C) of the decommissioning waste stream. TLG Se1*vices, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Sectfonl, Page 8 of 9 The WCS facility is able to receive the Class Band C waste. As such, for this analysis, Class B and C waste was assumed to be shipped to the WCS facility for disposal. Disposal costs were based upon preliminary and indicative information for the WCS site. The dismantling of the components residing closest to the reactor core generates radioactive waste that may be considered unsuitable for shallow-land disposal (i.e., low-level radioactive waste with concentrations of radionuclides that exceed the limits established by the NRC for Class C radioactive waste (GTCC)). The Low-Level Radioactive Waste Policy Amendments Act of 1985 assigned the federal government the responsibility for the disposal of this material. The Act also stated that the beneficiai*ies of the activities resulting in the generation of such radioactive waste bear all reasonable costs of disposing of such waste. However, to date, the federal government has not identified a cost for disposing of GTCC or a schedule for acceptance. For purposes of this analysis only, the GTCC radioactive waste is assumed to be packaged and disposed of in a similar manner as high-level waste and at a cost equivalent to that envisioned for the spent fuel. The GTCC is packaged in the same canisters used for spent fuel and shipped directly to a DOE facility as it is generated. A significant portion of the waste material generated during decommissioning may only be potentially contaminated by radioactive materials. This material can be analyzed on site or shipped off site to licensed facilities for further analysis, for processing and/or for conditioning/recovery. Reduction in the volume of low-level radioactive waste requiring disposal in a licensed low-level radioactive waste disposal facility can be accomplished through a variety of methods, including analyses and surveys or decontamination to eliminate the
. portion of waste that does not require disposal as radioactive waste, compaction, incineration or metal melt. The estimates reflect the savings from waste recovery/volume reduction.
- 1. 3. 3 Radiological Critei*ia for License Termination In 1997, the NRC published Subpart E, "Radiological Criteria for License Terrnination,"! 171 amending 10 CFR Part 20. This subpart provides i*adiological criteria for releasing a facility for unrestricted use.
The regulation states that the site can be released for unrestricted use if radioactivity levels are such that the average member of a critical group would not receive a Total Effective Dose Equivalent (TEDE) in excess of TLG Services, Inc.
Wolf Creek Generating Station Document WH-1697-001, Rev. 0 Decommissioning Cost Analysis Section], Page 9 of 9 25 millirem per year, and provided that residual radioactivity has been reduced to levels that are As Low As Reasonably Achievable (ALARA). The decommissioning estimates assume that the Wolf Creek site will be remecliated to a residual level consistent with the NRC-prescribed level. It should be noted that the NRC and the Environmental Protection Agency (EPA) differ on the amount of residual radioactivity considered acceptable in site remediation. The EPA has two limits that apply to radioactive materials. An EPA limit of 15 millirem per year is derived from criteria established by the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA or Superfund).l 1Bl An additional and separate limit of 4 millirem per year, as defined in 40 CFR §141.16, is applied to drinking water.fl9J On October 9, 2002, the NRC signed an agreement with the EPA on the radiological decommissioning and decontamination of NRC-licensed sites. The Memorandum of Understanding (l\!IOU)l20J provides that EPA will defer exercise of authority under CERCLA for the majority of facilities decommissioned under NRC authority. The MOU also includes provisions for NRC and EPA consultation for certain sites when, at the time of license termination, (1) ground.water contamination exceeds EPA-permitted levels; (2) NRC contemplates restricted release of the site; and/or (3) residual radioactive soil concentrations exceed levels defined in the MOU. The MOU does not impose any new requirements on NRC licensees and should reduce the involvement of the EPA with NRC licensees who are decommissioning. l\!Iost sites are expected to meet the NRC criteria for unrestricted use, and the NRC believes that only a few sites will have groundwater or soil contamination in excess of the levels specified in the l\tIOU that trigger consultation with the EPA. However, if there are other hazardous materials on the site, the EPA may be involved in the cleanup. As such, the possibility of dual rngulation remains for certain licensees. The present study does not include any costs for this occurrence. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 2, Page 1 of 11
- 2. DECOMMISSIONING AL 'I'ERNATIVES Detailed cost estimates were developed to decommission Wolf Creek for the approved decommissioning alternatives: DECON and SAFSTOR. Although the alternatives differ with respect to technique, process, cost, and schedule, they attain the same result: the ultimate release of the site for unrestricted use.
The following sections describe the basic activities associated with each alternative. Although detailed procedures for each activity identified are not provided, and the actual sequence of work may vary, the activity descriptions provide a basis not only for estimating but also for the expected scope of work, i.e., engineering and planning at the time of decommissioning. The conceptual approach that the NRC has described in its regulations divides decommissioning into three phases. The initial phase commences with the effective date of permanent cessation of operations and involves the transition of both plant and licensee from reactor operations (i.e., power production) to facility de-activation and closure. During the first phase, notification is to be provided to the NRC certifying the permanent cessation of operations and the removal of fuel from the reactor vessel. The licensee is then prohibited from reactor operation. The second phase encompasses activities during the storage period or during major decommissioning activities, or a combination of the two. The third phase pertains to the activities involved in license termination. The decommissioning estimates developed for Wolf Creek are also divided into phases or periods; however, demarcation of the phases is based upon major milestones within the project or significant changes in the projected expenditures. 2.1 DECON The DECON alternative, as defined by the NRC, is "the alternative in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed or decontaminated to a level that permits the property to be released for unrestricted use shortly after cessation of operations." This study does not address the cost to dispose of the spent fuel residing at the site; such costs are funded through a surcharge on electrical generation. 2.1.1 Period 1 - Preparations In anticipation of the cessation of plant operations, detailed preparations a:re undertaken to provide a smooth transition from plant TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. (} Decommissioning Cost Analysis Section 2, Page 2 of 11 operations to site decommissioning. Through implementation of a staffing transition plan, the organization required to manage the intended decommissioning activities is assembled from available plant staff and outside resources. Preparations include the planning for permanent defueling of the reactor, revision of technical specifications applicable to the operating conditions and requirements, a characterization of the facility and major components, and the development of the PSDAR. Engineering and Planning The PSDAR, required within two years of the notice to cease operations, provides a description of the licensee's planned decommissioning activities, a timetable, and the associated financial requirements of the intended decommissioning program. Upon receipt of the PSDAR, the NRC will make the document available to the public for comment in a local hearing to be held in the vicinity of the reactor site. Ninety days following submittal and NRC receipt of the PSDAR, the licensee may begin to perform major decommissioning activities under a modified 10 CFR §50.59 procedure, i.e., without specific NRC approval. Major activities are defined as any activity that results in permanent removal of major radioactive components, permanently modifies the structure of the containment, or results in dismantling components (for shipment) containing GTCC, as defined by 10 CFR §61. Major components are further defined as comprising the reactor vessel and internals, large bore reactor coolant system piping, and other large components that are radioactive. The NRC includes the following additional criteria for use of the §50.59 process in decommissioning. The proposed activity must not: foreclose release of the site for possible unrestricted use, significantly increase decommissioning costs,
"' cause any significant environmental impact, or violate the terms of the licensee's existing license.
Existing operational technical specifications are reviewed and modified to reflect plant conditions and the safety concerns associated with permanent cessation of operations. The environmental impact associated with the planned decommissioning activities is also considered. Typically, a licensee will not be allowed to proceed if the consequences of a pm*ticular decommissioning activity are greater than that bounded by previously evaluated environmental assessments or impact statements. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 2, Page 3 of 11 In this instance, the licensee would have to submit a license amendment for the specific activity and update the environmental report. The decommissioning program outlined in the PSDAR will be designed to accomplish the required tasks within the ALARA guidelines (as defined in 10 CFR §20) for protection of personnel from exposure to radiation hazards. It will also address the continued protection of the health and safety of the public and the environment during the dismantling activity. Consequently, with the development of the PSDAR, activity specifications, cost-benefit and safety analyses, work packages and procedures, would be assembled to support the proposed decontamination and dismantling activities. Site Preparations Following final plant shutdown, and in preparation for actual decommissioning activities, the following activities are initiated:
- i; Characterization of the site and surrounding environs. This includes radiation surveys of work areas, major components (including the reactor vessel and its internals), internal piping, and primary shield cores.
Isolation of the spent fuel storage pool and fuel handling systems, such that decommissioning operations can commence on the balance of the plant. The pool will remain operational for approximately five and one-half years following the cessation of operations before the inventory resident at shutdown can be transferred to the DOE.
<; Specification of transport and disposal requirements for activated materials and/or hazardous materials, including shielding and waste stabilization.
~* Development of procedures for occupational exposure control, control and release of liquid and gaseous effluent, processing of radwaste (including dry-active waste, resins, filter media, metallic and non-metallic components generated in decommissioning), site security and emergency programs, and industrial safety.
2.1.2 Period 2
- Decommissioning Operations This period includes the physical decommissioning activities associated with the removal and disposal of contaminated and activated components and structures, including the successful termination of the TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 2, Page 4 of 11 10 CFR §50 operating license. Significant decommissioning activities in this phase include: (; Construction of temporary facilities and/or modification of existing facilities to support dismantling activities. This may include a centralized processing area to facilitate equipment removal and component preparations for off-site disposal.
& Reconfiguration and modification of site structures and facilities as needed to support decommissioning operations. This may include the upgrading of roads (on- and off-site) to facilitate hauling and transport. Modifications may be required to the containment structure to facilitate access of large/heavy equipment. Modifications may also be required to the refueling area of the building to support the segmentation of the reactor vessel internals and component extraction.
~ Design and fabrication of temporary and permanent shielding to support removal and transportation activities, construction of contamination control envelopes, and the procurement of specialty tooling.
"" Procurement (lease or pm*chase) of shipping canisters, cask liners, and industrial packages for the disposition of low-level :radioactive waste.
Decontamination of components and piping systems as required to control (minimize) worker exposure. Removal of piping and components no longer essential to support decommissioning operations. Removal of control rod drive housings and the head service structure from the reactor vessel head. Segmentation of the vessel closure head. Removal and segmentation of the upper internals assemblies. Segmentation will maximize the loading of the shielded transport casks, i.e., by weight and activity. The operations are conducted under water using remotely operated tooling and contamination controls.
~ Disassembly and segmentation of the remaining reactor internals, including the core shroud and lower core support assembly. Some material is expected to exceed Class C disposal requirements. As such, the segments will be packaged in modified fuel storage canisters for geologic disposal.
TLG Services, Inc.
Wolf Creell Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 2, Page 5 of 11
*~ Segmentation of the reactor vessel. A shielded platform is installed for segmentation as cutting operations are performed in-air using remotely operated equipment within a contamination control envelope. The water level is maintained just below the cut to minimize the working area dose rates. Segments are transferred in-air to containers that are stored under water, for example, in an isolated area of the refueling canal.
0 Removal of the activated portions of the concrete biological shield and accessible contaminated concrete surfaces. If dictated by the steam generator and pressurizer removal scenarios, those portions of the associated cubicles necessary for access and component extraction are removed.
;:\ Removal of the steam generators and pressurizer for material recovery and controlled disposal. The generators will be moved to an on-site processing center, the steam domes removed and the internal components segregated for recycling. The lower shell and tube bundle will be packaged for direct disposal. These components can serve as their own burial containers provided that all penetrations are properly sealed and the internal contaminants are stabilized, e.g.,
with grout. Steel shielding will be added, as necessary, to those external areas of the padrnge to meet transportation limits and regulations. The pressurizer is disposed of intact. At least two years prior to the anticipated date of license termination, an LTP is required. Submitted as a supplement to the Final Safety Analysis Report (FSAR) or its equivalent, the plan must include: a site characterization, description of the remaining dismantling activities, plans for site remediation, procedures for the final radiation survey, designation of the end use of the site, an updated cost estimate to complete the decommissioning, and any associated environmental concerns. The NRC will notice the receipt of the plan, make the plan available for public comment, and schedule a local hearing. LTP approval will be subject to any conditions and limitations as deemed appropriate by the Commission. The licensee may then commence with the final remediation of site facilities and services, including:
- i Removal of remaining plant systems and associated components as they become nonessential to the decommissioning program or worker health and safety (e.g., waste collection and treatment systems, electrical power and ventilation systems).
- TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-fHJl, Rev. 0 Decommissioning Cost Analysis Section 2, Page 6 of 11
" Removal of the steel liners from refueling canal, disposing of the activated and contaminated sections as radioactive waste. Removal of any activated/ contaminated concrete.
" Surveys of the decontaminated areas of the containment structure.
o Remediation and removal of the contaminated equipment and material from the fuel building and any other contaminated facility. Radiation and contamination controls will be utilized until residual levels indicate that the structures and equipment can be released for unrestricted access and conventional demolition. This activity may necessitate the dismantling and disposition of most of the systems and components (both clean and contaminated) located within these buildings. This activity facilitates surface decontamination and subsequent verification surveys required prior to obtaining release for demolition.
~ Routing of material removed in the decontamination and dismantling to a central processing area. Material certified to be free of contamination is released for unrestricted disposition, e.g., as scrap, recycle, or general disposal. Contaminated material is characterized and segregated for additional off-site processing (disassembly, chemical cleaning, volume reduction, and waste treatment), and/or packaged for controlled disposal at a low-level radioactive waste disposal facility.
Incorporated into the LTP is the Final Survey Plan. This plan identifies the radiological surveys to be performed once the decontamination activities a:re completed and is developed using the guidance provided in the "Multi-Age*ncy Radiation Survey and Site Investigation Manual (MARSSIM)."l2IJ This document incorporates the statistical approaches to survey design and data interpretation used by the EPA. It also identifies state-of-the-art, commercially available instrumentation and procedures for conducting radiological surveys. Use of this guidance ensures that the surveys are conducted in a manner that provides a high degree of confidence that applicable NRC criteria are satisfied. Once the survey is complete, the results a:re provided to the NRC in a format that can be verified. The NRC then reviews and evaluates the information, performs an independent confirmation of radiological site conditions, and makes a determination on final termination of the license. The NRC will terminate the operating license if it determines that site remediation has been performed in accordance with the LTP, and that the terminal radiation survey . and associated documentation demonstrate that the facility is suitable for release. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev.() Decommissioning Cost Analysis Section 2, Page 7 of 11 2.1.3 Period 3 - Site Restoration Following completion of decommissioning operations, site restoration activities will begin. Efficient removal of the contaminated materials and verification that residual radionuclide concentrations are below the NRC limits will result in substantial damage to many of the structures. Although performed in a controlled, safe manner, blasting, coring, drilling, scarification (surface removal), and the other decontamination activities will substantially degrade power block structures including the reactor, fuel handling, radioactive waste, solidification facility and condensate polishing buildings. Under certain circumstances, verifying that subsurface radionuclide concentrations meet NRC site release requirements will require removal of grade slabs and lower floors, potentially weakening footings and structural supports. This removal activity will be necessary for those facilities and plant areas where historical records, when available, indicate the potential for radionuclides having been present in the soil, where system failures have been recorded, or where it is required to confirm that subsurface process and drain lines were not breached over the operating life of the station. Immediate dismantling of site structures is clearly the most appropriate and cost-effective option. It is unreasonable to anticipate that these structures would be repaired and preserved after the radiological contamination is removed. The cost to dismantle site structures with a work force already mobilized on site is more efficient than if the process were deferred. Site facilities quickly degrade without maintenance, adding additional expense and creating potential hazards to the public as well as to future workern. Abandonment creates a breeding gi*ound for vermin infestation as well as other biological hazards. This cost study presumes that non-essential structures and site facilities are dismantled as a continuation of the decommissioning activity. Foundations and exterior walls are removed to a nominal depth of three feet below grade. The three-foot depth allows for the placement of gravel for drainage, as well as topsoil, so that vegetation can be established for erosion control. Site areas affected by the dismantling activities are restored and the plant area graded as required to prevent ponding and inhibit the refloating of subsurface materials. Non-contaminated concrete rubble produced by demolition activities is processed to remove reinforcing steel and miscellaneous emhedments. The processed material is then used. on site to backfill foundation voids. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Section 2, Page 8 of 11 Excess non-contaminated materials are trucked to an off-site area for disposal as construction debris. 2.2 SAFSTOR The NRC defines SAFSTOR as "the alternative in which the nuclear facility is placed and maintained in a condition that allows the nuclear facility to be safely stored and subsequently decontaminated (deferred decontamination) to levels that permit release for unrestricted use." The facility is left intact (during the dormancy period), with structures maintained in a sound condition. Systems that are not required to support the spent fuel pool or site surveillance and security are drained, de-energized, and secured. Minimal cleaningiremoval of loose contamination and/or fixation and sealing of remaining contamination are performed. Access to contaminated areas is secured to provide controlled access for inspection and maintenance. The engineering and planning requirements are similar to those for the DECON alternative, although a shorter time period is expected for these activities due to the more limited work scope. Site preparations are also similar to those for the DE CON alternative. However, with the exception of the required radiation surveys and site characte1*izations, the mobilization and preparation of site facilities is less extensive. 2.2.1 Period l - Preparations Preparations for long-term storage include the planning for permanent defueling of the reactor, revision of technical specifications appropriate to the operating conditions and requirements, a characterization of the facility and major components, and the development of the PSDAR. The process of placing the plant in safe-storage includes, but is not limited to, the following activities:
"' Isolation of the spent fuel storage services and fuel handling systems so that safe-storage operations may commence on the balance of the plant. This activity may be carried out by . plant personnel in accordance with existing operating technical specifications. Activities are scheduled around the fuel handling systems to the greatest extent possible.
"' Transfer of the spent fuel from the storage pool to the DOE following the minimum required cooling period in the spent fuel pool.
TLG Services, Inc.
Wolf Creeh Generaiing Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 2, Page 9 of 11
*'.> Draining and de-energizing of the non-contaminated systems not required to support continued site operations or maintenance.
,, Disposing of contaminated filter elements and resin beds not required for processing wastes from layup activities for future operations.
u Draining of the reactor vessel, with the internals left in place and the vessel head secured. 0 Draining and de-energizing non-essential, contaminated systems with decontamination as required for futm*e maintenance and inspection.
$ Preparing lighting and alarm systems whose continued use is required; de-energizing portions of fire protection, electric power, and HVAC systems whose continued use is not required.
"' Cleaning of the loose surface contamination from building access pathways.
I>' Performing an interim radiation survey of plant, posting warmng signs where appropriate.
"' Erecting physical barriers and/or securing all access to radioactive or contaminated areas, except as required for inspection and maintenance.
" Installing security and surveillance monitoring equipment and relocating security fence around secured structures, as required.
2.2.2 Period 2 - Dormancy The second phase identified by the NRC in its rule addresses licensed activities during a storage period and is applicable to the dormancy phases of the deferred decommissioning alternatives. Dormancy activities include a 24-hour security force, preventive and corrective maintenance on security systems, area lighting, general building maintenance, heating and ventilation of buildings, routine radiological inspections of contaminated structures, maintenance of structural integrity, and a site environmental and i*adiation monitoring program. Resident maintenance personnel perform equipment maintenance, inspection activities, routine services to maintain safe conditions, adequate lighting, heating, and ventilation, and periodic preventive maintenance on essential site services. An environmental surveillance program is carried out during the dormancy period to ensure that releases of radioactive material to the TLG Services, Inc.
Wolf Creek Generating Station Document Wll-16'97-0019 Rev.(} Decommissioning Cost Analysis Section 2, Page 10 of 11 environment are prevented and/or detected and controlled. Appropriate emergency procedures are established and initiated for potential releases that exceed prescribed limits. The environmental surveillance program constitutes an abbreviated version of the program in effect during normal plant operations. Security during the dormancy period is conducted primarily to prevent unauthorized entry and to protect the public from the consequences of its own actions. The security fence, sensors, alarms, and other surveillance equipment provide security. Fire and radiation alarms are also monitored and maintained. Consistent with the DECON scenario, the spent fuel storage pool is emptied within five and one-half years of the cessation of operations. The pool is secured for storage and decommissioned along with the power block structures in Period 4. Afte1* a period of storage (such that license termination is accomplished within 60 yeaTs of final shutdown), it is required that the licensee submit an application to terminate the license, along with an LTP (described in Section 2.1.2), thereby initiating the third phase. 2.2.3 Periods 3 and 4 - Delayed Decommissioning Prior to the commencement of decommissioning operations, preparations are undertaken to reactivate site services and prepare for decommissioning. Preparations include engineering and planning, a detailed site characterization, and the assembly of a decommissioning management organization. Final planning for activities and the writing of activity specifications and detailed procedures are also initiated at this time. Much of the work in developing a termination plan is relevant to the development of the detailed engineering plans and procedures. The activities associated with this phase and the follow-on decontamination and dismantling processes are detailed in Sections 2.1.1 and 2.1.2. The primary difference between the sequences anticipated for the DECON and this deferred scenario is the absence, in the latter, of any constraint on the availability of the fuel storage facilities for decommissioning. Variations in the length of the dormancy period are expected to have little effect upon the quantities of radioactive wastes generated from system and structure removal operations. Given the levels of TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 2, Page 11 of 11 radioactivity and spectrum of radionuclides expected from sixty years of plant operation, no plant process system identified as being contaminated upon final shutdown will become releasable due to the decay period alone, i.e., there is no significant reduction in the waste generated from the decommissioning activities. However, due to the lower activity levels, a greater percentage of the waste volume can be designated for off-site processing and recovery. The delay in decommissioning also yields lower working area radiation levels. As such, the estimate for this delayed scenario incorporates reduced ALARA controls for the SAFSTOR's lower occupational exposure potential. Although the initial radiation levels due to 6 °Co will decrease during the dormancy period, the internal components of the reactor vessel will still exhibit sufficiently high radiation dose rates to requirn remote sectioning under water due to the presence of long-lived radionuclides such as 94~1b, 59Ni, and 63 Ni. Therefore, the dismantling procedures described for the DECON alternative would still be employed during this scenario. Portions of the biological shield will still be radioactive due to the presence of activated trace elements with long half-lives (152Eu and 154 Eu). Decontamination will require controlled removal and disposal. It is assumed that radioactive corrosion products on inner surfaces of piping and components will not have decayed to levels that will permit unrestricted use or allow conventional removal. These systems and components will be surveyed as they are removed and disposed of in accordance with the existing radioactive release criteria. 2.2.4 Period 5 - Site Restoration Following completion of decommissioning operations, site-restoration activities can begin. Dismantling, as a continuation of the decommissioning process, is clearly the most appropriate and cost-effective option, as described in Section 2.1.3. The basis for the dismantling cost in this scenario is consistent with that described for DECON, presuming the removal of structures and site facilities to a nominal depth of three feet below grade and the limited restoration of the site. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev.{) Decommissioning Cost Analysis Section 3, Page 1 of 28
- 3. COST ESTIMATE The cost estimates prepared for decommissioning Wolf Creek conside1* the unique features of the site, including the NSSS, power generation systems, support services, site buildings, and ancillary facilities. The basis of the estimates, including the sources of information relied upon, the estimating methodology employed, site-specific considerations, and other pertinent assumptions, is described in this section.
3.1 BASIS OF ESTIMATE The estimates were developed using the site-specific, technical information from the 2011 analysis. This information was reviewed for the current analysis and updated as deemed appropriate. The site-specific considerations and assumptions used in the previous evaluation were also revisited. 1\fodifications were incorporated where new information was available or experience from previously completed decommissioning programs provided viable alternatives or improved processes. 3.2 METHODOLOGY The methodology used to develop the estimates follows the basic approach originally presented in the AIF/NESP-036 study report, "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates,"l 22 l and the DOE "Decommissioning Handbook."l 23 l These documents present a unit factor method for estimating decommissioning activity costs, which simplifies the estimating calculations. Unit factors for concrete removal ($/cubic yard), steel removal ($/ton), and cutting costs ($/inch) are developed using local labor rates. The activity-dependent costs are estimated with the item quantities (cubic yards and tons), developed from plant drawings and inventory documents. Removal rates and material costs for the conventional disposition of components and structures rely upon information available in the industry publication, "Building Construction Cost Data," published by R.S. Means.!2,11 The unit factor method provides a demonstrable basis for establishing reliable cost estimates. The detail provided in the unit factors, including activity duration, labor costs (by craft), and equipment and consumable costs, ensures that essential elements have not been omitted. Appendix A presents the detailed development of a typical unit factor. Appendix B provides the values contained within one set of factors developed for this analysis. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. (} Decommissioning Cost Analysis Section 3, Page 2 of 28 This analysis reflects lessons learned from TLG's involvement in the Shippingport Station Decommissioning Project, completed in 1989, as well as the decommissioning of the Cintichem reactor, hot cells, and associated facilities, completed in 1997. In addition, the planning and engineering for the Pathfinder, Shoreham, Rancho Seco, Trojan, Yankee Rowe, Big Rock Point, Maine Yankee, Humboldt Bay-3, Oyster Creek, Connecticut Yankee, and San Onofre-I nuclear units have provided additional insight into the process, the regulatory aspects, and the technical challenges of decommissioning commercial nuclear units. Work Difficulty Factors TLG has historically applied work difficulty adjustment factors (vVDFs) to account for the inefficiencies in working in a power plant environment. WDFs are assigned to each unique set of unit factors, commensurate with the inefficiencies associated with working in confined, hazardous environments. The ranges used for the WDFs are as follows:
£],
Access Factor 10% to 20%
,;;, Respiratory Protection Factor 10% to 50%
"' Radiation/AL.ARA Factor 10% to 37%
'1l Protective Clothing Factor 10% to 30%
f'._~
\Vork Break Factor 8.33%
The factors and their associated range of values we1*e developed in conjunction with the AIF/NESP-036 study. The application of the factors is discussed in more detail in that publication. Scheduling Program Durations The unit factors, adjusted by the WDFs as described above, are applied against the inventory of materials to be removed in the radiological controlled areas. The resulting man-hours, or crew-hours, are used in the development of the decommissioning program schedule, using resource loading and event sequencing considerations. The scheduling of conventional removal and dismantling activities is based upon productivity information available from the "Building Construction Cost Data" publication. An activity duration c:ritical path is used to determine the total decommissioning program schedule. The schedule is relied upon in calculating the carrying costs, which include program management, administration, field TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Section 3, Page 3 of 28 engineering, equipment rental, and support services such as quality control and security. This systematic approach for assembling decommissioning estimates ensures a high degree of confidence in the reliability of the resulting costs. 3.3 FINANCIAL COMPONENTS OF THE COST MODEL TLG's proprietary decommissioning cost model, DECCER, produces a number of distinct cost elements. These direct expenditures, however, do not comprise the total cost to accomplish the project goal, i.e., license termination and site restoration. Inherent in any cost estimate that does not rely on historical data is the inability to specify the precise source of costs imposed by factors such as tool breakage, accidents, illnesses, weather delays, and labor stoppages. In the DECCER cost model, contingency fulfills this role. Contingency is added to each line item to account for costs that are difficult or impossible to develop analytically. Such costs are historically inevitable over the duration of a job of this magnitude; therefore, this cost analysis includes funds to cover these types of expenses. 3.3.l Contingency The activity- and period-dependent costs are combined to develop the total decommissioning cost. A contingency is then applied on a line-item basis, using one or more of the contingency types listed in the AIF/NESP-036 study. "Contingencies" are defined in the American Association of Cost Engineers "Project and Cost Engineers' Handbook"f25 l as "specific provision for unforeseeable elements of cost within the defined project scope; particularly important where previous experience relating estimates and actual costs has shown that unforeseeable events which will increase costs are likely to occur." The cost elements in this analysis are based upon ideal conditions and maximum efficiency; therefore, consistent with industry practice, contingency is included. In the AIF/NESP-036 study, the types of unfor"eseeable events that are likely to occur in decommissioning are discussed and guidelines are provided for percentage contingency in each category. It should be noted that contingency, as used in this analysis, does not account for price escalation and inflation in the cost of decommissioning over the remaining operating life of the station.
- Contingency funds are an integral part of the total cost to complete the decommissioning process. Exclusion of this component puts at risk a
'TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 4 of 28 successful completion of the intended tasks and, potentially, subsequent related activities. For this study, TLG examined the major activity-related problems (decontamination, segmentation, equipment handling, packaging, transport, and waste disposal) that necessitate a contingency. Individual activity contingencies ranged from 10% to 75%, depending on the degree of difficulty judged to be appropriate from TLG's actual decommissioning experience. The contingency values used in this study are as follows: Decontamination 50%
"' Contaminated Component Removal 25%
"' Contaminated Component Packaging 10%
<'! Contaminated Component Transport 15%
~ Low-Level Radioactive Waste Disposal 25%
!ii; Reactor Segmentation 75%
tf-NSSS Component Removal 25%
<!; Reactor Waste Packaging 25%
"'~ Reactor Waste Transport .25%
"' Reactor Vessel Component Disposal 50%
"' GTCC Disposal 15%
f§. Non-Radioactive Component Removal 15% Iii Heavy Equipment and Tooling 15% (} Supplies 25%
~ Engineering 15%
<}
Energy 15% f¥ Characterization and Termination Surveys 30% Construction 15%
" Taxes and Fees 10%
~* Insurance 10%
$ Staffing 15%
The contingency values are applied to the appropriate components of the estimates on a line item basis. A composite value is then reported at the end of each detailed estimate (as provided in Appendix C and D). For example, the composite contingency value reported for the DECON alternative in Appendix C is approximately 18.96%. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 5 of 28 3.3.2 Financial Risk In addition to the routine uncertainties addressed by contingency, another cost element that is sometimes necessary to consider when bounding decommissioning costs relates to uncertainty, or risk. Examples can include changes in work scope, pricing, job performance, and other variations that could conceivably, but not necessarily, occur. Consideration is sometimes necessary to generate a level of confidence in the estimate, within a range of probabilities. TLG considers these types of costs under the broad term "financial i*isk." Included within the category of financial risk are: 0 Transition activities and costs: ancillary expenses associated with eliminating 50% to 80% of the site labor force shortly after the cessation of plant operations, added cost for worker separation packages throughout the decommissioning program, national or company-mandated retraining, and retention incentives for key personnel.
~ Delays in approval of the decommissioning plan due to intervention, public participation in local community meetings, legal challenges, and national and local hearings.
~ Changes in the project work scope from the baseline estimate, involving the discovery of unexpected levels of contaminants, contamination in places not previously expected, contaminated soil previously undiscovered (either :radioactive or hazardous material contamination), variations in plant inventory or configuration not indicated by the as-built drawings.
~' Regulatory changes, for example, affecting worker health and safety, site release criteria, waste transportation, and disposal.
Policy decisions altering national commitments (e.g., in the ability to accommodate certain waste forms for disposition), or in the timetable for such, for example, the start and rate of acceptance of spent fuel by the DOE.
., Pricing changes for basic inputs such as labor, energy, materials, and disposal. Items subject to widespread price competition (such as materials) may not show significant variation; however, others such as waste disposal could exhibit large pricing uncertainties, particularly in markets where limited access to services is available.
This cost study does not add any additional costs to the estimate for financial risk, since there is insufficient historical data from which to TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 6 of 28 project future liabilities. Consequently, the areas of uncertainty or risk are revisited periodically and addressed through repeated revisions 01* updates of the base estimates. 3.4 SITE-SPECIFIC CONSIDERATIONS There are* a number of site-specific considerations that affect the method for dismantling and removal of equipment from the site and the degree of restoration required. The cost impact of the considerations identified below is included in this cost study. 3.4.l Spent Fuel Management The cost to dispose the spent fuel generated from plant operations is not reflected within the estimates to decommission Wolf Creek. Ultimate disposition of the spent fuel is within the province of the DOE's Waste Management System, as defined by the Nuclear \Vaste Policy Act. As such, until recently, the disposal cost was being financed by a 1 mill/kWhr surcharge on nuclear generated energy delivered to customers, the fee being paid into the DOE's waste fund during operations. The D.C. Circuit ruling on November 19, 2013, ordered the DOE *to submit a proposal to Congress to suspend the Nuclear Waste Fund fee "until such time as either the Secretary chooses to comply with the Act as it is currently written, or until Congress enacts an alternative waste management plan". The fee was reduced to 0.0 mill/kWh as of May 16, 2014. The fee is expected to be reinstated in the future. Nonetheless, the NRC does requires licensees to establish a program to manage and provide funding for the management of all irradiated fuel at the reactor until title of the fuel is transferred to the Secretary of Energy. This funding requirement is fulfilled through inclusion of certain high-level waste cost elements within the estimates, as described below. For estimating purposes, WCNOC has assumed that all spent fuel will be removed to a DOE facility within five and one-half years after shutdown. Interim storage of the fuel, until the DOE has completed the transfer, will be in the spent fuel pool located in the fuel building (as well as on the ISFSI). The spent fuel storage pool and fuel handling systems will be isolated (i.e., a spent fuel island created). This will allow WCNOC to proceed with decommissioning (or safe-storage) operations in the shortest time possible. A delay in the start of fuel pickup, or a decrease in the spent fuel acceptance rate, will correspondingly prolong TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Section 3, Page 7 of 28 the transfer process and result in the fuel remaining at the 'Wolf Creek site longer. It is assumed that the five and one-half years also provides the necessary cooling period for the final core to meet DOE's transport system requirements for decay heat. Once the pool is emptied, the spent fuel storage and handling facilities are available for decommissioning. Operation and maintenance costs for the spent fuel pool are included within the estimate as well as the costs to transfer the spent fuel to the DOE. Supplemental Storage It is likely that supplemental spent fuel storage will be required to support continued plant operations (i.e., maintain full core off-load capability). This analysis assumes that an Independent Spent Fuel Storage Installation (ISFSI) is constructed during operations and that 592 spent fuel assemblies (16 equivalent dry storage system modules) are transferred to the ISFSI during plant operations. The fuel will remain in storage until it is off-loaded into a DOE-provided transport cask. The transfer is assumed to occur once the spent fuel pool has been emptied. The estimates include the cost for the transfer only. Canister Loading and Transfer The estimates include the cost to load the spent fuel in the wet storage pool into a DOE-provided multi-purpose canister (e.g., Transport, Aging and Disposal or TAD canister), seal the canisters and place the canister into the DOE transport vehicle. The estimates also include the cost to transfer each canister stored at the ISFSI into the DOE transport vehicle. Operations and Maintenance The estimates include the cost of operating and maintaining the spent fuel pool for approximately five and one half years after the cessation of operations. GTCC The dismantling of the reactor internals is expected to generate radioactive waste considered unsuitable fot shallow land disposal (i.e., low-level radioactive waste with concentrations of radionuclides that TLG Services, Inc.
Wolf Creek Genera.ting Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 8 of 28 exceed the limits established by the NRC for Class C radioactive waste (GTCC)). The Low-Level Radioactive Waste Policy Amendments Act of 1985 assigned the federal government the responsibility for the disposal of this material. The Act also stated that the beneficiaries of the activities resulting in the generation of such radioactive waste bear all reasonable costs of disposing of such waste. Although the DOE is responsible for disposing of GTCC waste, any costs for that service have not been determined. For purposes of this study, GTCC is packaged in the same canisters used to transport spent fuel. The GTCC is assumed to be disposed of as it is generated during reactor vessel segmentation operations. 3.4.2 Reactor Vessel and Internal Components The reactor pressure vessel and internal components are segmented for disposal in shielded, reusable transportation casks. Segmentation is performed in the refueling canal, where a turntable and remote cutter are installed. The vessel is segmented in place, using a mast-mounted cutter supported off the lower head and directed from a shielded work platform installed ove1*head in the reactor cavity. Transportation cask specifications and transportation regulations dictate the segmentation and packaging methodology. Intact disposal of reactor vessel shells has been successfully demonstrated at several of the sites currently being decommissioned. Access to navigable waterways has allowed these large packages to be transported to the Barnwell, South Carolina and Hanford, Washington disposal sites with minimal overland travel. Intact disposal of the reactor vessel and internal components can provide savings in cost and worker exposure by eliminating the complex segmentation requirements, isolation of the GTCC material, and transport/storage of the resulting waste packages. Portland General Electric (PGE) was able to dispose of the Trojan reactor as an intact package (including the internals). However, its location on the Columbia River simplified the transportation analysis since:
" the reactor package could be secured to the transport vehicle for the entire journey, i.e., the package was not lifted during transport,
" there were no man-made or natural terrain features between the plant site and the disposal location that could produce a large drop, and TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 9 of 28
>> transport speeds were very low, limited by the overland transport vehicle and the river barge.
As a member of the Northwest Compact, PGE had a site available for disposal of the package - the US Ecology facility in Washington State. The characteristics of this arid site proved favorable in demonstrating compliance with land disposal regulations. It is not known whether this option will be available when Wolf Creek ceases operation. Future viability of this option will depend upon the ultimate location of the disposal site, as well as the disposal site licensee's ability to accept highly radioactive packages and effectively isolate them from the environment. Consequently, the study assumes the reactm vessel will require segmentation, as a bounding condition. 3.4.3 Primary Svstem Components In the DECON scenario, the reactor coolant system components are assumed to be decontaminated using chemical agents prior to the start of dismantling operations. This type of decontamination can be expected to have a significant AL.ARA impact, since in this scenario the removal work is done within the first few years of shutdown. A decontamination factor (average reduction) of 10 is assumed for the process. In the SAFSTOR scenario, radionuclide decay is expected to provide the same benefit and, thernfore, a chemical decontamination is not included. The following discussion deals with the removal and disposition of the steam generators, but the techniques involved are also applicable to other large components, such as heat exchangers, component coolers, and the pressurizer. The steam generatoxs' size and weight, as well as their location within the reactor building, will ultimately determine the removal strategy. A trolley crane is set up for the removal of the generators. It can also be used to move portions of the steam generator cubicle walls and floor slabs from the reactor building to a location where they can be decontaminated and transported to the material handling area. Interferences within the work area, such as grating, piping, and other components are removed to create sufficient laydown space for processing these large components. The generators are rigged for removal, disconnected from the surrounding piping and supports, and maneuvered into the open area TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. fJ Decommissioning Cost Analysis Section 3, Page 1() of 28 where they are lowered onto a dolly. Each generator is rotated into the horizontal position for extraction from the containment and placed onto a multi-wheeled vehicle for transport to an on-site processing and storage area. The generators are disassembled on-site with the steam dome and lightly contaminated subassemblies designated for off-site recycling. The more highly contaminated tube sheet and tube bundle are packaged for direct disposal. The interior volume is filled with low-density cellular concrete for stabilization of the internal contamination. Reactor coolant piping is cut from the reactor vessel once the water level in the vessel (used for personnel shielding du1*ing dismantling and cutting operations in and around the vessel) is dropped below the nozzle zone. The piping is boxed and transported by shielded van. The reactor coolant pumps and motors are lifted out intact, packaged, and transported for processing and/or disposal. 3.4.4 Main Turbine and Condenser The main turbine is dismantled usmg conventional maintenance procedures. The turbine rotors and shafts are removed to a laydown area. The lower turbine casings are removed from their anchors by controlled demolition. The main condensers are also disassembled and moved to a laydown area. Material is then prepared for transportation to an off-site recycling facility where it is surveyed and designated for either decontamination m volume reduction, conventional disposal, or controlled disposal. Components are packaged and readied for transport in accordance with the intended disposition. 3.4.5 Transportation Methods Contaminated piping, components, and structural material other than the highly activated reactor vessel and internal components will qualify as LSA-I, II or III or Surface Contaminated Object, SCO-I or II, as described in Title 49.l26 l The contaminated material will be packaged in Industrial Packages (IP-1, IP-2, or IP-3, as defined in subpart 173.411) for transport unless demonstrated to qualify as their own shipping containers. The reactor vessel and internal components are expected to be transported in accordance with Part 71, as Type B. It is conceivable that the reactor, due to its limited specific activity, could qualify as LSA II or III. However, the high radiation levels on the outer surface would TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 11 of 28 require that additional shielding be incorporated within the packaging so as to attenuate the dose to levels acceptable for transport. Any fuel cladding failure that occurred during the lifetime of the plant is assumed to have released fission products at sufficiently low levels that the buildup of quantities of long-lived isotopes (e.g., I37Cs, 90Sr, or transuranics) has been prevented from reaching levels exceeding those that permit the major reactor components to be shipped under current transportation regulations and disposal requirements. Transport of the highly activated metal, produced in the segmentation of the reactor vessel and internal components, will be by shielded truck cask. Cask shipments may exceed 95,000 pounds, including vessel segment(s), supplementary shielding, cask tie-downs, and tractor-trailer. The maximum level of activity per shipment assumed permissible was based upon the license limits of the available shielded transport casks. The segmentation scheme for the vessel and internal segments is designed to meet these limits. The transport of large intact components (e.g., large heat exchangers and other oversized components) will be by a combination of truck, rail, and/or multi-wheeled transporter. Transportation costs for Class A radioactive material reqmrmg contrnlled disposal are based upon the mileage to the EnergySolutions facility in Clive, Utah. Transportation costs for the higher activity Class B and C radioactive material are based upon the mileage to the WCS facility in Andrews County, Texas. The transportation cost for the GTCC material is assumed to be contained within the disposal cost. Transportation costs for off-site waste processing are based upon the mileage to Oak Ridge, Tennessee. Truck transport costs are estimated using published tariffs from Tri-State Motor Transit.l27l 3.4.6 Low-Level Radioactive Waste Disposal To the greatest extent practical, metallic material generated in the decontamination and dismantling processes is processed to reduce the total cost of controlled disposal. Material meeting the regulatory and/or site release criterion, is released as scrap, requiring no further cost consideration. Conditioning (preparing the material to meet the waste acceptance criteria of the disposal site) and recovery of the waste stream is performed off site at a licensed processing center. Any material leaving the site is subject to a survey and release charge, at a minimum. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Section 3, Page 12 of 28 The mass of radioactive waste generated during the various decommissioning activities at the site is shown on a line-item basis in the appendices and summarized in Section 5. The quantified waste summaries shown in these tables are consistent with 10 CFR Part 61 classifications. Commercially available steel containers are presumed to be used for the disposal of piping, small components, and concrete. Larger components can serve as their own containers, with proper closure of all openings, access ways, and penetrations. The volumes are calculated based on the exterior package dimensions for containerized material or a specific calculation for components serving as their own waste containers. The more highly activated reactor components will be shipped in reusable, shielded truck casks with disposable liners. In calculating disposal costs, the burial fees are applied against the liner volume, as well as the special handling requirements of the payload. Packaging efficiencies are lower for the highly activated materials (greater than Type A quantity waste), where high concentrations of gamma-emitting radionuclides limit the capacity of the shipping canisters. The cost to dispose of the lowest level waste and the majority of the material generated from the decontamination and dismantling activities is based upon the current cost for disposal at EnergySolutions facility in Clive, Utah. Disposal costs for the higher activity waste (Class B and C) were based upon preliminary and indicative rates for WCS's Andrews County facility. 3.4. 7 Site Conditions Following Decommissioning The NRC will terminate the site license when it determines that site remediation has been performed in accordance with the license termination plan, and that the terminal radiation survey and associated documentation demonstrate that the facility is suitable for release. The NRC's involvement in the decommissioning process will end at this point. Local building codes and state environmental regulations will dictate the next step in the decommissioning process, as well as the owner's own future plans for the site. The estimates presented herein include the dismantling of the major structures to just below ground level, backfilling and the collapsing of below grade voids, and regrading such that the site upon which the power block and supplemental structures are located is transfo1*med into a "grassy plain." TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Section 3, Page 13 of 28 The existing electrical switchyard and access roads will remain in support of the electrical transmission and distribution system. Other structures that will remain are the main dam, cooling lake, makeup water discharge structure (west side of lake), makeup water screen house (located below the John Redmond Dam) and associated underground piping, the Eisenhower Learning Center, and a railroad spur running about 11.5 miles from the plant southeast to near Aliceville, Kansas, where it connects to a Union Pacific Railroad line. The estimates do not assume the remediation of any significant volume of contaminated soil. This assumption may be affected by continued plant operations and/or futm*e regulatory actions, such as the development of site-specific release criteria. 3.5 ASSUMPTIONS The following are the major assumptions made m the development of the estimates for decommissioning the site. 3.5.1 Estimating Basis Decommissioning costs are reported in the year of projected expenditure; however, the values are provided in 2014 dollars. Costs are not inflated, escalated, or discounted over the periods of performance. The estimates rely upon the physical plant inventory that was the basis for the 2011 analysis. The study follows the principles of ALt\.RA through the use of work duration adjustment factors. These factors address the impact of activities such as radiological protection instruction, mock-up training, and the use of respiratory protection and protective clothing. The factors lengthen a task's duration, increasing costs and lengthening the overall schedule. ALARA planning is considered in the costs for engineering and planning, and in the development of activity specifications and detailed procedurns. Changes to worker exposure limits may impact the decommissioning cost and project schedule. 3.5.2 Labor Costs WCNOC, as the operator, will continue to provide site operations support, including decommissioning program management, licensing, i*adiological protection, and site security. A Decommissioning Operations TLG Services, Inc.
Wolf Creek Generating Station Document Wil-1697-001, Rev.() Decommissioning Cost Analysis Section 3, Page 14 of 28 Contractor (DOC) will provide the supervisory staff needed to oversee the labor subcontractors, consultants, and specialty contractors needed to perform the work required for the decontamination and dismantling effort. The DOC will also provide the engineering services needed to develop activity specifications, detailed procedures, detailed activation analyses, and support field activities such as structural modifications. Personnel costs are based upon average salary information provided by WCNOC. Overhead costs are included for site and corporate support, reduced commensurate with the staffing of the project. Security, while reduced from operating levels, is maintained throughout the decommissioning for access control, material control, and to safeguard the spent fuel. The craft labor required to decontaminate and dismantle the nuclear station is acquired through standard site contracting practices. The current cost of labor at the site is used as an estimating basis. 3.5.3 Design Conditions Any fuel cladding failure that occurred during the lifetime of the plant is assumed to have released fission products at sufficiently low levels that the buildup of quantities of long-lived isotopes (e.g., 137Cs, nosr, or transuranics) has been prevented from reaching levels exceeding those that permit the major NSSS components to be shipped under current transportation regulations and disposal requirements. The curie contents of the vessel and internals at final shutdown are derived from those listed in NUREG/CR-34 7 4.l 28l Actual estimates are derived from the curie/gram values contained therein and adjusted for the different mass of the Wolf Creek components, projected operating life, and different periods of decay. Additional short-lived isotopes were derived from CR-0130[29] and CR-0672,f30J and benchmarked to the long-lived values from CR-34 74. The control elements are disposed of along with the spent fuel, i.e., there is no additional cost provided for their disposal. Activation of the containment building structure is confined to the biological shield. TLG Services, ln.c.
Wolf Creek Generating Station Document Wll-1697-0{)1, Rev. () Decommissioning Cost Analysis Section 3, Page 15 of 28 3.5.4 General Transition Activities Existing warehouses are cleared of non-essential material and remain for use by WCNOC and its subcontractors. The plant's operating staff performs the following activities at no additional cost or credit to the project during the transition period:
<a Drain and collect fuel oils, lubricating oils, and transformer oils for recycle and/or sale.
o Drain and collect acids, ca us tics, and other chemical stores for recycle and/or sale. o Process operating waste inventories (i.e., the estimates do not address the disposition of any legacy wastes; the disposal of operating wastes during this initial period is not considered a decommissioning expense). Scrap and Salvage The existing plant equipment is considered obsolete and suitable for scrap as deadweight quantities only. WCNOC will make economically reasonable efforts to salvage equipment following final plant shutdown. However, dismantling techniques assumed by TLG for equipment in this analysis are not consistent with removal techniques required for salvage (resale) of equipment. Experience has indicated that some buyers wanted equipment stripped down to very specific requirements before they would consider purchase. This required expensive rework after the equipment had been removed from its installed location. Since placing a salvage value on this machinery and equipment would be speculative, and the value would be small in comparison to the overall decommissioning expenses, this analysis does not attempt to quantify the value that an owner may realize based upon those efforts. It is assumed, for purposes of this analysis, that any value received from the sale of scrap generated in the dismantling process would be more than offset by the on-site processing costs. The dismantling techniques assumed in the decommissioning estimates do not include the additional cost for size reduction and preparation to meet "furnace ready" conditions. For example, the recovery of copper from electrical cabling may require the removal and disposition of any contaminated insulation, an added expense. With a volatile market, the potential profit margin in TLG Seruices, Inc.
Wolf Creell Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 16 of 28 scrap recovery is highly speculative, regardless of the ability to free release this material. This assumption is an implicit recognition of scrap value in the disposal of clean metallic waste at no additional cost to the project. Furniture, tools, mobile equipment such as forklifts, trucks, bulldozers, and other property is removed at no cost or credit to the decommissioning project. Disposition may include relocation to other facilities. Spare parts are also made available for alternative use. Energy For estimating purposes, the plant is assumed to be de-energized, with the exception of those facilities associated with spent fuel storage. Replacement power costs are used to calculate the cost of energy consumed during decommissioning for tooling, lighting, ventilation, and essential services. Insurance Costs for continuing coverage (nuclear liability and property insurance) following cessation of plant operations and during decommissioning are included and based upon current operating premiums. Reductions in premiums, throughout the decommissioning process, are based upon the guidance provided in SECY-00-0145, "Integrated Rulemaking Plan for Nuclear Power Plant Decommissioning"f 31 l The NRC's financial protection requirements are based on various reactor (and spent fuel) configurations. Taxes Property tax payments are included for the land and those facilities that will continue to be used to support the decommissioning project. When the facilities are no longer needed, the taxes are reduced accordingly. Site Modifications The perimeter fence and in-plant security barriers will be moved, as appropriate, to conform to the Site Security Plan in force during the various stages of the project. TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost ilnalysis Section 3, Page 17 of 28 3.6 COST ESTIMATE
SUMMARY
Schedules of expenditures are provided in Tables 3.1 and 3.2. The tables delineate the cost contributors by year of expenditures as well as cost contributor (e.g., labor, materials, and waste disposal). The cost elements are also assigned to one of three subcategories: "License Termination," "Spent Fuel Management," and "Site Restoration." The subcategory "License Termination" is used to accumulate costs that are consistent with "decommissioning as defined by the NRC in its financial assurance regulations (i.e., 10 CFR §50.75). The cost reported for this subcategory is generally sufficient to terminate the station's operating license, recognizing that there may be some additional cost impact from spent fuel management. These costs are identified in Tables 3. la and 3.2a. The "Spent Fuel l\1anagement" subcategory contains costs associated with the five and one-half years of post-shutdown pool operations, and the management of the spent fuel until such time that the transfer of all fuel from this facility to an off-site location is complete. These costs are identified in Tables 3. lb and 3.2b.
"Site Restoration" is used to capture costs associated with the dismantling and demolition of buildings and facilities demonstrated to be free from contamination. This includes structures never exposed to radioactive materials, as well as those facilities that have been decontaminated to appropriate levels. Structures are removed to a depth of three feet and backfilled to conform to local grade. These costs are identified in Tables 3.lc and 3.2c.
It should be noted that the costs assigned to these subcategories are allocations. Delegation of cost elements is for the purposes of comparison (e.g., with NRC financial guidelines) or to permit specific financial treatment (e.g., Asset Retirement Obligation determinations). In reality,* there can be considerable interaction between the activities in the three subcategories. For example, an owner may decide to remove non-contaminated structutes early in the project to improve access to highly contaminated facilities or plant components. In these instances, the non-contaminated removal costs could be reassigned from Site Restoration to an NRC License Termination support activity. However, in general, the allocations represent a reasonable accounting of those costs that can be expected to be incurred for the specific subcomponents of the total estimated program cost, if executed as described. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. {) Decommissioning Cost A.nalysis Section 3, Page 18 of 28 As discussed in Section 3.4. l, while designated for disposal at the geologic repository along with the spent fuel, GTCC waste is still classified as low-level radioactive waste and, as such, included as a "License Termination" expense. The estimates were developed and costs are presented in 2014 dollars. As such, the estimates do not reflect the escalation of costs (due to inflationary and market forces) over the remaining operating life of the reactor or during the decommissioning period. The schedules are based upon the detailed activity costs reported in Appendices C and D, along with the timeline presented in Section 4. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 19 of 28 TABLE 3.1 DECON ALTERNATIVE TOTAL ANNUAL EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Bui-ial Other Total 2045 53,028 2,343 1,950 32 7,042 64,396 2046 73,415 20,182 3,580 16,739 24,695 138,612 2047 72,126 29,817 2,285 40,310 20,523 165,060 2048 65,594 19,275 1,979 20,158 12,577 ' 119,582 2049 61,762 13,455 1,804 9,103 8,199 94,323 2050 53,339 11,258 1,543 8,674 7,169 81,983 2051 31,298 3,441 656 2,832 2,568 40,794 2052 21,438 13,675 274 4 1,595 36,986 2053 12,504 9,649 150 0 1,023 23,326 Total 444,503 123,095 14,220 97,853 85,389 765,060 Note: Columns may not add due to rounding TLG Services, Inc.
Wolf Creek Generating Station Document W11-1697-001, Rev. () Decommissioning Cost Analysis Section 3, Page 20 of 28 TABLE 3.la DECON ALTERNATIVE LICENSE TERMINATION EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045 52,289 1,550 1,950 32 5,116 60,938 2046 70,590 15,771 3,580 16,739 22,464 129,144 2047 68,949 24,547 2,285 40,310 18,614 154,705 2048 62,311 13,349 1,979 20,158 10,780 108,577 2049 58,435 7,198 1,804 9,103 6,471 83,011 2050 51,042 6,939 1,543 8,674 5,976 74,174 2051 31,298 3,441 656 2,832 2,568 40,794 2052 4,149 242 66 4 171 4,632 2053 84 0 0 0 0 84 Total 399,147 73,037 13,862 97,853 72,161 656,060 Note: Columns may not add due to rounding TLG Services, Inc.
Wolf Creek Generating Station Document W11-Hi97-00J, Rev. O Decommissioning Cost Analysis Section 3, Page 21of28 TABLE 3.lb DECON ALTERNATIVE SPENT FUEL MANAGEMENT EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045 264 793 0 0 1,925 2,983 2046 1,460 4,381 0 0 2,176 8,017 2047 1,724 5,172 0 0 1,727 8,623 2048 1,949 5,846 0 0 1,732 9,526 2049 2,063; 6,188 0 0 1,727 9,978 2050 1,424 4,272 0 0 1,193 6,889 2051 0 0 0 0 0 0 2052 0 0 0 0 0 0 2053 0 0 0 0 0 0 Total 8,884 26,651 0 0 10,481 46,016 Note: Columns may not add due to rounding TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. fJ Decommissioning Cost Analysis Section 3, Page 22 of 28 TABLE 3.lc DECON ALTERNATIVE SITE RESTORATION EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045 474 0 0 0 0 474 2046 1,365 30 0 0 55 1,451 2047 1,453 98 0 0 181 1,732 2048 1,335 80 0 0 64 1,478 2049 1,264 69 0 0 0 1,334 2050 873 48 0 0 0 921 2051 0 0 0 0 0 0 2052 17,288 13,432 208 0 1,424 32,353 2053 12,419 9,649 150 0 1,023 23,241 Total 36,473 23,407 358 0 2,748 62,985 Note: Columns may not add due to rounding TLG Services, inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 23 of 28 TABLE 3.2 SAFSTOR ALTERNATIVE TOTAL ANNUAL EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045 44,926 1,929 1,950' 32 7,042 55,880 2046 45,802 10,322 1,814 1,348 20,203 79,490 2047 22,940 6,229 481 15 5,083 34,747 2048 23,002 6,246 482 15 5,097 34,842 2049 22,940 6,229 481 15 5,083 34,747 2050 16,845 4,399 407 12 3,955 25,619 2051 3,253 320 240 7 1,442 5,261 2052 3,262 320 241 7 1,446 5,276 2053 3,253 320 240 7 1,442 5,261 2054 3,253 320 240 7 1,442 5,261 2055 3,253 320 240 7 1,442 5,261 2056 3,262 320 241 7 1,446 5,276 2057 3,253 320 240 7 1,442 5,261 2058 3,253 320 240 7 1,442 5,261 2059 3,253 320 240 7 1,442 5,261 2060 3,262 320 241 7 1,446 5,276 2061 3,253 320 240 7 1,442 5,261 2062 3,253 320 240 7 1,442 5,261 2063 3,253 320 240 7 1,442 5,261 2064 3,262 320 241 7 1,446 5,276 2065 3,253 320' 240 7 1,442 5,261 2066 3,253 320 240 7 1,442 5,261 2067 3,253 320 240 7 1,442 5,261 2068 3,262 320 241 7 1,446 5,276 2069 3,253 320 240 7 1,442 5,261 2070 3,253 320 240 7 1,442 5,261 2071 3,253 320 240 7 1,442 5,261 2072 3,262 320 241 7 1,446 5,276 2073 3,253 320 240 7 1,442 5,261 2074 3,253 320 240 7 1,442 5,261 2075 3,253 320 240 7 1,442 5,261 2076 3,262 320 241 7 1,446 5,276 2077 3,253 320 240 7 1,442 5,261 TLG Services, Inc.
Wolf Creek Generating Station Document WJJ-1697-001, Rev.() Decommissioning Cost Analysis Section 3, Page 24 of 28 TABLE 3.2 (continued) SAFSTOR ALTERNATIVE TOTAL ANNUAL EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2078 3,253 320 240 7 1,442 5,261 2079 3,253 320 240 7 1,442 5,261 2080 3,262 320 241 7 1,446 5,276 2081 3,253 320 240 7 1,442 5,261 2082 3,253 320 240 7 1,442 5,261 2083 3,253 320 240 7 1,442 5,261 2084 3,262 320 241 7 1,446 5,276 2085 3,253 320 240 7 1,442 5,261 2086 3,253 320 240 7 1,442 5,261 2087 3,253 320 240 7 1,442 5,261 2088 3,262 320 241 7 1,446 5,276 2089 3,253 320 240 7 1,442 5,261 2090 3,253 32.0 240 7 1,442 5,261 2091 3,253 320 240 7 1,442 5,261 2092 3,262 320 241 7 1,446 5,276 2093 3,253 320 240 7 1,442 5,261 2094 3,253 320 240 7 1,442 5,261
.2095 3,253 320 240 7 1,442 5,261 2096 3,262 320 241 7 1,446 5,276 2097 3,253 320 240 7 1,442 5,261 2098 3,253 320 240 7 1,442 5,261 2099 I 46,550 4,019 2,399 36 1,911 54,915 2100 46,415 15,315 2,345 19,371 10,352 93,798 2101 51,415 23,967 2,252 37,140 17,930 132,704 2102 41,756 6,768 1,804 8,569 4,685 63,581 2103 41,756 6,768 1,804 . 8,569 4,685 63,581 2104 34,711 3,882 1,040 3,633 2,554 45,820 2105 21,892 12,877 287 6 1,520 36,582 2106 13,659 10,540 163 0 1,118 25,481 Total 630;864 134,836 29,260 79,082 160,459 1,034,501 TLG Services, Inc.
Wolf Creeh Generating Station Document WlJ-1697-001, Rev.(} Decommissioning Cost Analysis . Section 3, Page 25 of 28 TABLE 3.2a SAFSTOR ALTERNATIVE LICENSE TERlVHNATION EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045 44,662 1,136 1,950 32 5,116 52,897 2046 38,830 5,759 1,741 1,348 17,937 65,614 2047 3,253 463 240 15 3,059 7,030 2048 3,262 464 241 15 3,067 7,049 2049 3,253 463 240 15 3,059 7,030 2050 3,253 418 240 12 2,558 6,482 2051 3,253 320 240 7 1,442 5,261 2052 3,262 320 241 7 1,446 5,276 2053 3,253 320 240 7 1,442 5,261 2054 3,253 I 320 240 7 1,442 5,261 2055 3,253 320 2,:io 7 1,442 5,261 2056 3,262 320 241 7 1,446 5,276 2057 3,253 320 240 7 1,442 5,261 2058 3,253 320 240 7 1,442 5,261 2059 3,253 320 240 7 1,442 5,261 2060 3,262 320 241 7 1,446 5,276 2061 3,253 320 240 7 1,442 5,261 2062 3,253 320 240 7 1,442 5,261 2063 3,253 320 240 7 1,442 5,261 2064 3,262 320 241 7 1,446 5,276 2065 3,253 320 240 I 7 1,442 5,261 2066 3,253 320 240 7 1,442 5,261 2067 3,253 320 240 7 1,442 5,261 2068 3,262 320 241 7 1,446 5,276 2069 3,253 320 I 240 7 1,442 5,261
'7 2070 3,253 320 240 I 1,442 5,261 2071 3,253 320 240 7 1,442 5,261 2072 3,262 320 241 7 1,446 5,276 2073 3,253 320 240 7 1,442 5,261 2074 3,253 320 240 7 1,442 5,261 2075 3,253 320 240 7 1,442 5,261 2076 3,262 320 241 7 1,446 5,276 2077 3,253 320 240 I 7 1,442 5,261 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 26 of 28 TABLE 3.2a (continued) SAFSTOR ALTERNATIVE LICENSE TERMINATION EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2078 3,253 320 240 7 1,442 5,261 2079 3,253 320 240 7 1,442 5,261 2080 3,262 320 241 7 1,446 5,276 2081 3,253 320 240 7 1,442 5,261 2082 3,253 320 240 7 1,442 5,261 2083 3,253 320 240 7 1,442 5,261 2084 3,262 320 241 7 1,446 5,276 2085 3,253 320 240 7 1,442 5,261 2086 3,253 320 240 7 1,442 5,261 2087 3,253 320 240 7 1,442 5,261 2088 3,262 320 241 7 1,446 5,276 2089 3,253 320 240 7 1,442 5,261 2090 3,253 320 240 7 1,442 5,261 2091 3,253 320 240 7 1,442 5,261 2092 3,262 320 241 7 1,446 5,276 2093 3,253 320 240 7 1,442 5,261 2094 3,253 320 240 7 1,442 5,261 2095 3,253 320 240 7 1,442 5,261 2096 3,262 320 241 7 1,446 5,276 2097 3,253 320 240 7 1,442 5,261 2098 3,253 320 240 7 1,442 5,261 2099 45,535 4,019 2,399 36 1,911 53,900 2100 45,169 15,260 2,345 19,371 10,341 92,486 2101 49,755 23,858 2,252 37,140 17,909 130,915 2102 . 40,568 6,703 1,804 8,569 4,685 62,328 2103 40,568 . 6,703 1,804 . 8,569 4,685 62,328 2104 34,210 3,855 1,040 3,633 2,554 45,292 2105 5,754 . 339 92* 6 191 6,381 2106 92 0 0. 0 0 92 Total 514,419 84,786 27,940 79,082 146,312 852,539 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. () Decommissioning Cost Analysis Section 3, Page 2'1 of 28 TABLE 3.2b SAFSTOR ALTERNATIVE SPENT FUEL MANAGEMENT EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045 264 793 0 0 1,925 2,983 2046 6,972 4,563 74 0 2,267 13,875 2047 19,686 5,766 240 0 2,024 27,717 2048 19,740 5,782 241 0 2,030 27, 793 2049 19,686 5,766 240 0 2,024 27,717 2050 13,592 3,981 166 0 1,397 19,136 2051-2106 0 0 0 0 0 0 Total 79,942 26,651 962 0 11,667 119,221 TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 3, Page 28 of 28 TABLE 3.2c SAFSTOR ALTERNATIVE SITE RESTORATION EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2045-98 0 0 0 0 0 0 2099 1,015 0 0 0 0 1,015 2100 1,245 55 0 0 11 I 1,312 2101 1,659 108 0 0 21 1,789 2102 1,188 65 0 0 0 1,253 2103 1,188 65 0 0 0 1,253 2104 501 27 0 0 0 529 2105 16,138 12,538 194 I 0 1,330 30,200 2106 13,567 10,540 163 0 1,118 25,389 Total 36,503 23,400 358 0 2,480 62,740 TLG Services, Inc.
Wolf Creek Generating Station Document Wll-16.97-001, Rev. 0 Decommissioning Cost Analysis Section 4, Page 1 of 5
- 4. SCHEDULE ESTIMATE The schedules for the decommissioning scenarios considered in this study follow the sequences presented in the AIF/NESP-036 study, with minor changes to reflect recent experience and site-specific constraints. In addition, the scheduling has been revised to reflect the spent fuel management plan described in Section 3.4.1.
A schedule or sequence of activities for the DECON alternative is presented in Figure 4.1. The scheduling sequence assumes that fuel is removed from the spent fuel pool within five and one-half years. The key activities listed in the schedule do not reflect a one-to-one correspondence with those activities in the cost tables, but reflect dividing some activities for clarity and combining others for convenience. The schedule was prepared using the "Microsoft Project Professional 2010" computer software .l32l 4.1 SCHEDULE ESTIMATE ASSUMPTIONS The schedule reflects the results of a precedence network developed for the site decommissioning activities, i.e., a PERT (Program Evaluation and Review Technique) Software Package. The work activity durations used in the precedence network reflect the actual man-hour estimates from the cost table, adjusted by stretching certain activities over their slack range and shifting the start and end dates of others. The following assumptions were made in the development of the decommissioning schedule: o The fuel building is isolated until such time that all spent fuel has been transferred from the spent fuel pool to the DOE. Decontamination and dismantling of the storage pool is initiated once the transfer of spent fuel is complete (DECON option).
" All work (except vessel and internals removal) is performed during an 8-hour workday, 5 days per week, with no overtime. There are eleven paid holidays per year.
0 Reactor and internals removal activities are performed by using separate crews for different activities working on different shifts, with a corresponding backshift charge for the second shift.
" Multiple crews work parallel activities to the maximum extent possible, consistent with optimum efficiency, adequate access for cutting,
- rcemoval and laydown space, and with the stringent safety measures necessary during demolition of heavy components and structures.
TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev.{) Decommissioning Cost Analysis Section 4, Page 2 of 5
,,, For plant systems removal, the systems with the longest removal durations in areas on the critical path are considered to determine the duration of the activity.
4.2 PROJECT SCHEDULE The period-dependent costs presented in the detailed cost tables are based upon the durations developed in the schedules for decommissioning. Durations are established between several milestones in each project period; these durations are used to establish a critical path for the entire project. In turn, the critical path dm*ation for each period is used as the basis for determining the period-dependent costs. A second critical path is shown for the spent fuel storage period, which determines the release of the fuel building *for final decontamination. Project timelines are provided in Figures 4.2 and 4.3 with milestone dates based on a 2045 shutdown date. The fuel pool is emptied approximately five and one-half years after shutdown. Deferred decommissioning in the SAFSTOR scenarios is assumed to commence so that the operating license is terminated within a 60-year period from the cessation of plant operations. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 4, Page 3 of 5 FIGURE 4.1 ACTIVITY SCHEDULE Task Name Yl I Y2 I Y3 I Y4 I Y5 I YG i Y7 Y8 I Y9 YlO Wolf Creek Decon Project Schedule Shutck*v...rn plant P~ri~d la - Shutclo~n through transition . Certific21.te of pern10.ne11t CBsDation of opt.rations suhrnitted Fual storage pc*ol opet*ation_s
*f7/,@~1 Reconfigure plant c:::J Prepare activity specifications
- P~ri~~~ sit~ ~ii~;;,,i:~~i~~ti~~. : ::
I P:3DP*.R subn1itted
\i\lritter. . G-::rt1fi*::a. te c_,f pern:.1.anent renE1v-aJ c,f ft.1ei s.11\:.n11tted i*
i+ f-htc. specif1c decon.1ff11ssioning 1~ost e:.::.:tima.te subrn1tted !+ [l()G staff inobili:ed !+ l Perioc! lb - Decommissioning preparations ililil p;~~i . ~to~~~~~. pu~:i. ~r~~r~ti.~~*;*. :~ Reconfigure plant (continued) !rn I Prep,,;~ ~tcii~d ;.,~;k pr~~d;_.r,;; !D Decon NSSS !o Isolate spent fuel pool io Period 2a - Large component removal ' Fuel storage pool operations Prep~*ati~1~* f~Jr r-e~t~~-*~~~sel ~er~*~ovai rqj ! fie~~~t~; v~~~:~i .~ i~-~ t~~*~J~* . Y2-?/0/4
. i Rernainin& large "NSSS co1nponents clispeisjt:ion
~
Non-essential systems Main turbine/generator Main condenser u*~E'~l~e ter:*n~in.a.~i'1;l~J. plr~n ;;\~t:rni,tte*i =_: Period 2b
- De~~n~ination (\Met f,:,_~l). ! i'/hz-'/<<//~/_//(/Jr,.:/41 Fue-1 storage pool operations I &JWf?#AJiW[il Remoiro systems not suppo~ting wet fuel storage i ----~--'
I Decon buildings not supporting wet fuel storage Licer;.se te-nn1natwn pla.n o_ppro*.rad I Fu~*l-storag~ 1;10.of a.~,;aji.;,bi~ -fr:r* ~~c::rnn1is~io~ing I Period 2c : D~~ntari:.i;,,.ation f~iio"'i;,,.g w~t f1~ei ~to~age Remoire remaining systems o! Decon i.r.1et ti.tel st8ragc- area ~ Period 2e
- Plant license termination R'/%1 I Fir1al Site Survey NRC review & a..ppro*uaJ I Pa1*t 56 b~ens>? b?~~:r:-iinated Period ~b - Site r~toration *:
I B1.1ilding -d~n1oli.tions, baci~f*iil and ian&ca.ping Red text indicates critical path activities Blue text indicates milestones TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. {) Decommissioning Cost Analysis Section 4, Page 4 of 5 FIGURE 4.2 DECOMMISSIONING TIMELINE DECON ALTERNATIVE (not to scale) Shutdown March 11, 2045 END L I Penod 1
,'.;."'"."on=s_"*,,=/c-1*
Period2 Decommissioning Period 3 Site 1-~~-~--~-*~~s---cc;---=~-c-:----c-O-:-pc-ier-,-,at"'io,-,ns~-c:-.-,,..,-c-;-~--*""'T~*=---,,-7""7"'"~bcc----;c--"""R""es"'to-,-ra_ti..,,on-;c--"*T""=' Mar-2045 Aug-2053 T Sept-2046 Feb-2052
**-.-1>
Fuel Pool Operations Sept-2050 TLG Services, Inc.
Woll Creeh Genemting Station Document Wll-16'97-001, Rev. 0 Decommissioning Cost Analysis Section 4, Page 5 of 5 FIGURE 4.3 DECOMMISSIONING TIMELINE SAFSTOR ALTERNATIVE (not to scale) Shutdown March 11, 2045 END Sept-2106 Mar-2045 Sept-2046 Jan-2099 Jul-2100 Mar-2105 Fuel Pool Operations Sept-2050 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 5, Page 1 of 6
- 5. RADIOACTIVE WASTES The objectives of the decommissioning process are the removal of all radioactive material from the site that would restrict its future use and the termination of the NRC license. This currently requires the remediation of all radioactive material at the site in excess of applicable legal limits. Under the Atomic Energy Act,[3 31 the NRC is responsible for protecting the public from sources of ionizing radiation. Title 10 of the Code of Federal Regulations delineates the production, utilization, and disposal of radioactive materials and processes. In particular, Part 71 defines radioactive material as it pertains to transportation and Part 61 specifies its disposition.
Most of the materials being transported for controlled burial are categorized as Low Specific Activity (LSA) or Surface Contaminated Object (SCO) materials containing Type A quantities, as defined in 49 CFR Parts 17 3-178. Shipping containers are required to be Industrial Packages (IP-1, IP-2 or IP-3, as defined in 10 CFR §173.411). For this study, commercially available steel containers are presumed to be used for the disposal of piping, small components, and concrete. Larger components can serve as their own containers, with proper closure of all openings, access ways, and penetrations. The destinations for the various waste streams from decommissioning are identified in Figures 5.1 and 5.2. The volumes of radioactive waste generated during the various decommissioning activities at the site are shown on a line-item basis in Appendices C and D, and summa1*ized in Tables 5.1 and 5.2. The quantified waste volume summaries shown in these tables are consistent with Part 61 classifications. The volumes are calculated based on the exterior dimensions for containerized material and on the displaced volume of components serving as their own waste containers. The reactor vessel and internals are categorized as large quantity shipments and, accordingly, will be shipped in reusable, shielded truck casks with disposable liners. In calculating disposal costs, the burial fees are applied against the liner volume, as well as the special handling requirements of the payload. Packaging efficiencies are lower for the highly activated materials (greater than Type A quantity waste), where high concentrations of gamma-emitting radionuclides limit the capacity of the shipping canisters. No process system containing/handling radioactive substances at shutdown is presumed to meet material release criteria by decay alone (i.e., systems radioactive at shutdown will still be radioactive over the time period during which the decommissioning is accomplished, due to the presence of long-lived radionuclides). TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 5, Page 2 of 6 While the dose rates decrease with time, radionuclides such as 137Cs will still control the disposition requirements. The waste material produced in the decontamination and dismantling of the nuclear station is primarily generated during Period 2 of DECON and Period 4 of SAFSTOR. :Material that is considered potentially contaminated when removed from the radiological controlled area is sent to processing facilities in Tennessee for conditioning and disposal. Heavily contaminated components and activated materials are routed for controlled disposal. The disposal volumes reported in the tables reflect the savings resulting from reprocessing and recycling. For purposes of const1*ucting the estimates, the cost for disposal at the EnergySolutions facility was used as a proxy for future disposal facilities. Separate rates were used for containerized waste and large components, including the steam gene1*ators and reactor coolant pump motors. Demolition debris including miscellaneous steel, scaffolding, and concrete was disposed of at a bulk rate. The decommissioning waste stream also included resins and dry active waste. Since EnergySolutions is not currently able to receive the mo1*e highly radioactive components generated in the decontamination and dismantling of the reactor, disposal costs for the Class B and C material were based preliminary and indicative rates for WCS's Andrews County disposal facility. A small quantity of material generated during the decommissioning will not be considered suitable for near-surface disposal, and is assumed to be disposed of in a geologic repository, in a manner similar to that envisioned for spent fuel disposal. Such material, known as Greatel'-Than-Class-C or GTCC material, is estimated to require six spent fuel storage canisters (or the equivalent) to dispose of the most radioactive portions of the reactor vessel internals. The volume and weight reported in Tables 5.1 and 5.2 represent the packaged weight and volume of the spent fuel storage canisters. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. {) DecommissiOning Cast Analysis Section 5, Page 3 of 6 FIGURE 5.1 RADIOACTIVE WASTE DISPOSITION r-----1 I Reactor Waste I I
--(Class A) _J Resin I Filters (Class A}
Direct Burial EnergySolutions Containerized Clive, Utah Waste Oecomrnissioning Bulk Waste (
\ low-levei Radioactive Waste . .J (Contaminated Soil ~~~-_______/
and Concrete) DAW Duratek Oak Ridge, TN 1----------41>1 r - - - , 1 Metal l_. __ Processi: Reactor ~:::~ --i (Classes B/C) ~ Waste Control , Specialists i 1------------~ Andrews County, I Resin I Texas NSSS Decontamination (Class B/C) r***--~eactor Waste Geologic Disposal
!.._ (Class GTCC) Federal Facility TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev.() Decommissioning Cost Analysis Section 5, Page 4. of 6 FIGURE 5.2 DECOlVIIo/HSSIONING WASTE DESTINATIONS RADIOLOGICAL Waste Control Specialists Andrews County, TX TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-16'97-0()1, Rev. 0 Decommissioning Cost Analysis Section 5, Page 5 of 6 TABLE 5.1 DECON ALTERNATIVE DECOMMISSIONING WASTE
SUMMARY
,--- . ~-...........,...-~------- i ---,Waste Volume/ Mass l I Waste 1 Cost Basis i Class l 1l I (cubic feet) r-------------------------------- ------------------------------ --**r------------------------------------------ __ T_____________________ --*-r*--------------------------------r*------------------ ----- -----1
! (pounds) !
------*-*----------_____J___****-**-------*------**-*-----*--------.--.1__________________ * * * -* * --*-**-**--}------** -----**---*---*----- ------ **--- - *~--- -
rLt;;~Le~~iRadioactive ! i I I . . ----- ------1~ I ~aste (near-surface I Ene!_g_ySolutions __j _____ ~-- _ _L _____________!_~9,?_3-.Q_t_ ________9,925,727 ! I disposal) 1 1 I iI WCS
~-- - -------- --------- ---:-, B
------ --* [
t-** --- 1, 750 :
---------- --------c-----
191,469 I
---------------1 1---------------------
I I wcs 1 c
--1-----------,--------------r---------------------------:-----------------------------1 i 393 i 47,411 I l--------~---------+--*,*----------------------+------*------*--------~-*---------~------~--.---*---*----*****- --A-i*-- *A***"-"********---****-*---~---------!
I Greater than Class C 1 Spent Fuel 1
' I 1
Ir-*--(geologic ------**
----~---------
repository)
--- - - - - - - - - - - - * *- --- - --*Equivalent I GTCC
-------- --.. --------------------- ... --+-------*** l
-- --- --********--------- +------. -
2,217 [ 433,180
--------- ... ----- - --- . . . r.. - - - - - - - . . . . - .-------------------------!
It . .i,. . -- . . I t I P1:~~~~~~ci/C~nditio-~~d i Recy~ff~g ' - - . ***** r *. . . - -- ---! ! (off-site recycling center) ! Vendors __ l A . 254,605 i 9,935,532 I ii.-----**---*----------
; --------=:~=~=~=J~~--~---:~~-=~~=:=~*---~]~--*~--=**-~-=:----~------:-=~=-*-***~-;~--- *:*:_~---------, i i
i -- ------***-------*---------_I 1'fo~~--~---~-~-~---~-~--'~-------------'______L 388,299 j 20,533,32.QJ Ill Waste is classified according to the requirements as delineated in Title 10 CFR, Part 61.55 121 Columns may not add due to rounding. TLG Services, Inc.
Wolf Creek Generating Station Document Wll-16'97-001, Rev. 0 Decommissioning Cost Analysis Section fi, Page 6 of 6 TABLE 5.2 SAFSTOR ALTERNATIVE DECOMM:ISSIONING WASTE
SUMMARY
r--~~~-------~*--,~-------* -. ----rw ;~~mer- . - Mas;-l i-----------* ___ YY£:l_S_!~ ________J_____ Qg_s! -~?:_sj:;__ . --+*Class [IJ LI _ {c;!;lQ~c;J_E?_~!l___ J________(k>_Q.~E:c!s) ____JI I!----------* -***--*-*-*--*-**--* ----* *---*-*- ...... -----*-- ---*-- -[--*- -***------*-- -- .. --* . . . *--** * *****-- **- --- *t-! .**-*- * *----*-*---* -* * **---! --- *-***** - -*****-**- --**-***-- --*--*-
. 1 i ; ! I f
---*--**-+------- . - -*--******-* --** *' --*'
! Low-Level Radioactive : !
IWaste (near-surface LEner_gySolutiori,s j _____A __ J ____________!_QO, Q~_L!_L ___J, 4_92, 40Q.j
--:t I disposal) I \ : i I Ir----- ----------~--------*-*----**----------- -----~--_,
- -~ :--,_ - --
'. __________________________ ---r---- -----------~--- *----.-----~
~::::I
-----1------- - - -------------1 rare-ater th~~ Cla~~C- * -* * ,*. --Spent F~~i- ---~:.-. - - --1*.----*** - ------
- t* - --1 I - (geol_Q_gjc re_£g_si!_~ry) _________ +_ _ EgE~valenL ______J____QT_Qg_-[_____ ---------------~2ll+----------~§3,_180l i I
!P;.;.,<.;~;ed/Co;,dit;~,;ed l Recycling Uoff-site rec_:y_cliJ!_g_c~p.ter) __L_____ Ve!!do~~§. __________L_______A_____j_ ____________281 907 _[___
' - *j 1
j 11, 099, 010
--ij i - , , l '
L.______ ***------**-*- . i _____ . . . . . . ___ . _,___ ...... _--***** _____ ~ __ ----------------! i
' T i. '
I IL---*----~* Totals r21 ------*-***~-~--~-~*-~--*---~*-,,-~ i ____:,______*~--~*---*--*~-~-~*-' i 385 051 ---*\ -*--..? 19 062 . ' 260 I' l 1l Waste is classified according to the requirements as delineated in Title 10 CFR, Part 61.55 l 2l Columns may not add due to rounding. TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. (} Decommissioning Cost Analysis Section 6, Page 1 of 5 ft RESULTS The analysis to estimate the costs to decommission vVolf Creek relied upon the site-specific, technical information developed for a previous analysis prepared in 2011. While not an engineering study, the estimates provide the operator and the plant owners with sufficient information to assess their financial obligations, as they pe1*tain to the eventual decommissioning of the nuclear station. The estimates are based on numerous fundamental assumptions that consider current regulations, low-level radioactive waste disposal options, spent fuel management requirements, site restoration practices, and project contingencies. The estimates incorporate a minimum cooling period of approximately five and one-half years for the spent fuel that resides in the plant's wet storage pool when operations cease. During this period, it is assumed that the DOE will complete the transfer of the spent fuel from the site to a federal facility. The cost projected to promptly decommission (DECON) Wolf Creek is estimated to be $765.1 million. The majority of this cost (approximately 85.8%) is associated with the physical decontamination and dismantling of the nuclear station so that the operating license can be terminated. Another 6.0% is associated with the management, interim storage, and eventual transfer of the spent fuel. The remaining 8.2% is for the demolition of the designated structures and limited restoration of the site. The cost projected for deferred decommissioning (SAFSTOR) is estimated to be $1,034.5 million. The majority of this cost (approximately 82.4%) is associated with placing the station in storage, ongoing caretaking of the station during dormancy, and the eventual physical decontamination and dismantling of the nuclear station so that the operating license can be terminated. Another 11.5% is associated with the management, interim storage, and eventual transfer of the spent fuel. The remaining 6.1 % is for the demolition of the designated structures and limited restoration of the site. The primary cost contributors, identified in Tables 6.1 and 6.2, are either labor-related or associated with the management and disposition of the radioactive waste. Program management is the largest single contributor to the overall cost. The magnitude of the expense is a function of both the size of the organization required to manage the decommissioning, as well as the duration of the program. It is assumed, for purposes of this analysis, that WCNOC will oversee the decommissioning program, using a DOC to manage the decommissioning labor force and the associated subcontractors. The size and composition of the management organization varies with the decommissioning phase and associated site activities. TLG Services, Inc.
Wolf Creeh Generating Station Document W.11-1697-001, Rev. () Decommissioning Cost Analysis Section 6, Page 2 of 5 However, once the operating license is terminated, the staff is substantially reduced for the conventional demolition and restoration of the site (fOl' the DECON alternative). As described in this report, the spent fuel pool will remain operational for a minimum of five and one-half years following the cessation of operations. The pool will be isolated and an independent spent fuel island created. This will allow decommissioning operations to proceed in and around the pool area. Over the five and one-half year period, the spent fuel will be packaged into transportable canisters for loading into a DOE-provided transport cask. The cost for waste disposal includes only those costs associated with the controlled disposition of the low-level radioactive waste generated from decontamination and dismantling activities, including plant equipment and components, structural material, filters, resins and dry-active waste. As described in Section 5, disposition of the low-level radioactive material requiring controlled disposal is at licensed facility (e.g., EnergySolutions' or equivalent). Highly activated components, requiring additional isolation from the environment (GTCC), are packaged for geologic disposal. The cost of geologic disposal is based upon a cost equivalent for spent fuel. A significant portion of the metallic waste is designated for additional processing and treatment at an off-site facility. Processing reduces the volume of material requiring controlled disposal through such techniques and processes as survey and sorting, decontamination, and volume reduction. The material that cannot be unconditionally released is packaged for controlled disposal at one of the currently operating facilities. The cost identified in the summary tables for processing is all-inclusive, incorporating the ultimate disposition of the material. Removal costs reflect the labor-intensive nature of the decommissioning process, as well as the management controls required to ensure a safe and successful program. Decontamination and packaging costs also have a large labor component that is based upon prevailing union wages. Non-radiological demolition is a natural extension of the decommissioning process. The methods employed in decontamination and dismantling are generally destructive and indiscriminate in inflicting collateral damage. With a work force mobilized to support decommissioning operations, non-radiological demolition can be an integrated activity and a logical expansion of the work being performed in the process of terminating the operating license. Prompt demolition reduces future liabilities and can be more cost effective than deferral, due to the deterioration of the facilities (and thel'efore the working conditions) with time. TLG Services, Inc.
Wolf Creell Generating Station Document Wll-1697-001, Rev.() Decommissioning Cost Analysis Section 6, Page 3 of 5 The reported cost for transport includes the tariffs and surcharges associated with moving large components and/or overweight shielded casks overland, as well as the general expense, e.g., labor and fuel, of transporting material to the destinations identified in this report. For purposes of this analysis, material is p1*imarily moved overland by truck. Decontamination is used to reduce the plant's radiation fields and minimize worker exposure. Slightly contaminated material or material located within a contaminated area is sent to an off-site processing center, i.e., this analysis does not assume that contaminated plant components and equipment can be decontaminated for uncontrolled release in-situ. Centralized processing centers have proven to be a more economical means of handling the large volumes of material produced in the dismantling of a nuclear station. License termination survey costs are associated with the labor intensive and complex activity of verifying that contamination has been removed from the site to the levels specified by the regulating agency. This process involves a systematic survey of all remaining plant surface areas and surrounding environs, sampling, isotopic analysis, and documentation of the findings. The status of any plant components and materials not removed in the decommissioning process will also require confirmation and will add to the expense of surveying the facilities alone. The remaining costs include allocations for heavy equipment and temporary services, as well as for other expenses such as regulatory fees and the premiums for nuclear insurance. While site operating costs are greatly reduced following the final cessation of plant operations, certain administrative functions do need to be maintained either at a basic functional or regulatory level. TLG Services, Inc.
Wolf Creeh Generating Station Document WU-1697-001, Rev. 0 Decommissioning Cost Analysis Section 6, Page 4 of 5 TABLE 6.1 DECON ALTERNATIVE DECOlVIMISSIONING COST ELEMENTS (thousands of 2014 dollars) F"""""__,,-~_,,._..,..,.,..,..__..,,, __...._,._~....,.--.-..~*-~-------*---_,,,-.,,.,,.""'I"""'"---"""""""~--* -*-*--,.,.. . ..,,,,,.,..,""'2 I Cost Element I Total i Percentage j D;.;~t~ii,-;,ti~~-=--= =~~~-=t===i4;843t~- 1:9 fr*------*--********---**--------*.-------------------- lBBil1oval __________ _ ________ ___ _ ____ _ _ _______ j____________ !_!_~J_?_4:j_ _________!§.:9_____ _J
------~--------*-----
*l l Packaging__ i 23,258 ! 3.0 I
[T~~~-p;~t;~i9n-~-=------=----=--:=:-~~=~=~~=-~:==~~~ I Wa!?te Di~posal ----~--~-------------------J________§§_,_460
-:l==::_ _ l_!L?~-~I=~------=- L________
- 1. 5 ____]
ll.6 ___1 I Off-site Wa~te_Processing . . . l . 23,328 I ....... 3.0 I r:Pr~~:~~a-;;ag~~~-~t}~1*--:___:__ -__ ~-=--: ~:_:_t=~-:_ :2s*5~-66-if_ :_: ____=-34:7~- -} ___ t~~~-:~~:t~--All~~;ti~~~----- ----**- ---* - - ~------ _§J~~}~~-: - 6:;----1
*--~----- --- -----------**--*-***--------------*---4------------~~--------***-----~--~
t-~J~~-!!t_~_ll_?_!_r_()_()!__!_l?Q!_~~~QP: -- .- - . ....L..... 1_?1_1&11 [ ... !Ji____ . . i L~pent Fuel Nlan_9-_ge~_ent - Direct Q_Ql?..~--f~L___J,..___________ g6,0l§.,_____________ 6.0 _j I Insurance and Regulatory Fees
,_ -*------*-* *- - - -* - - -------------*----- --- - - - - - - - - - * - - - - -*- *- * *- *- * * . . l 14,647 i
* - ;-.* * * * * * *- - - . * -* ---------*----,. * * * ' * *----- - - ,. . .,I 1.9 I Energy ! 14,220 i 1.9 I
['Qh9_i:~s;_t_~}~~!i_Q~~ _~--~~~IJ:c~_P:~i~g_~_~!Y~Y':~-----~- ---- . .~-LJ?_?..~ ------- ----- ?_:~. ~--_:j I Property Taxes . - t* . 10,994 1 1.4 I L1Y!.i_~~~U.~!1.891:!f?__~g~!~Q~~-~f- _-_~:=--~-:-~--:*:-- :::::*:-~=--~~::_ :_::§J_.~q6 1------ ---- --~~9:'.~----~J i .. . . . . * - . I L!2t~fr3i=:**-~----~~~~~==~~==~-:-~==~~=i----=---~~Q§Q_I=--__!~--1 r-c;~t--EJ.;;~~--~t ----------~-----~---.,------~- ------------~---- . .... --r--*~--~T~t~i=-:-p;;~~~t;ge ___l
.rn~~~=~~eEt L§_i,~~_ gef-3!91.'~!~<?_f!___ _
~=--* . . ******~***~*~*!~~~~t~~~iJ
--** .1. ..... <?~.~§~-+ ._ _§:~- _... !I
~
L_. -*-~------------------------**--****---~------ -*- -.. -**- * * * *- ***--*-*--------- ---"-- ___ **********----~---. __ *---**--***-*--*-*-----** . *-------*-*----*---**-+* -------** * . . . ------* _-----*--**---------.. -t
! Total [31
...,,_,_'='<_=-<<'_'_,.,,...~_,.,,,_,, .
___ ,.~~""""'°'"~*""'""""~"-'""~..,,...,,.,......,,,~~=..... *-"-'~<'"'........,..,,._,,,.=-"-""'~--~*"""""'~--~="""'~*-~-=-,.,..,----"""'~~- 765,060 i . . . . . . .,. ._ 100 _.,.,~~~""""""~ I l 1l Includes engineering costs [2J Excludes program management costs (staffing) but includes costs for spent fuel loading/packaging costs/spent fuel pool O&M and Emergency Planning fees f3l Columns may not add due to rounding TLG Services, Inc.
Wolf Creek Generating Station Docnment Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Section 6, Page 5 of 5 TABLE 6.2 SAFSTOR ALTERNATIVE DECOMI\USSIONING COST ELEMENTS (thousands of 2014 dollars)
;----.. ------**--**~-------------,,-*-~-----------~-***,---;~** _____________,___,_,_ _ _ _ _ _!
p!o~_t_ Eleme~!---------~--------------------- _J_________ Total _L:P_t3_~~~-!!tag~j L------- ______________________________________ . . . ------------------- ______ _ _ _ _ ___ .......L_ _ _ ------------------------------*----L--------------------------- __________________ _J l__Qe~Q_nt~!P-inati<')_J,.:l_________________________f- ________ 13,0t?1LL___________L~-_J
! Removal _ ___j 118,585 ; 11.5 I rp~~k-~@ii_g____ ___
--~==~-~--~~-: :--~--~~::~~~--:-=*:~-- _ J____ :~.:~~8~474*r--- ~:__---:~-~-_ 1.8_~:~1
._1);_::iE§_£.~!j'.~t_i~!!____ __________ --------- __ L___ --~z.:1-.Q§___L ___ __ Q:.~----1 I \Vaste Dis:Q_Qsal i 66,933 ! 6.5 I Off-sit~-Waste P1:~-;~~~i~g.--*-----------------------r-------------26,084 T-r- .--- -----*-*---*-*-**-----*-*---------*-**----,----*****------- -... ----- . . ...... .. . *-* *
------------2~5-- -1
............... ***** ................ .,.. . . **-****--*-*. ********-**** . . ---- --*-**-*--*---*-...--** . . . . . . ....... *-*- *-* ******-*--*----** * * * * *- ""{-
i
*-~~- *-~
1-PrQgram Manag_e~~!~~ 1_l __________________________j_________?,56,987 j______ --~.1::_§_____ I Security [*****-------* --*-----*-*--****-----***-**-****~----**-*- --*****-*-***-*** . i
*-* ...... {................. .
188,070
-------*--------*-*--**1--
i 18.2 I
-*--*********--*****- -**-********--**i-ir*--C_2!'2orate
- Allocations-*--*-*_---_------ *****t--*---*-* ----- * -* 3,217 :; ** *--- 0.3
---***-*----~*----1 I SpentFuel Pool Isolation 12,434 i 1.2 I f~~:~~!~:i!~i=:~-~:~=~os~ ~ 31~IF: ~}j 121 - ..
! Energy
* - - - - - - - - * *****-*------N,-*----*~----------~---***------*****-**"**--~*-**- **-***
29,260 : 2.8 I
!. _Q4ar~c;!~~:~~-at~()l19:_l1c! 1'icefJ._:S~l1g_~-~~*y~y:s
*"O***"**'f******-"""""* **** -*-----------?******"** *****,**-- * ***---~ -**** 1
~_!,_§_?Q '_ __ . ____ . ?'. ! .J t~~'7;;r:J>c1~1p,,;~Ui 1--------------------**--***-******-**** -- ------**********************-**************** - .
. .*.*.*.~..
.[ .............
~L
-tl- I!
! Total f3l ! 1,034,501 : 100 I L~-------------~---~-~---~"~---------=*~~----~----"'"---~~----------,~-------.-!
Cost Element Total License...... -- *- Termination 852 539
.. ***********-*****- ) .. ... ***--**
~2~_l1t_ J~\1~!J\t~_]!age~~Q~--- !J.~2.?~J _ ;_
Site Restoration ~:?,!_~Q Total [31 501 r11 Includes engineering costs l2l Excludes program management costs (staffing) but includes costs for spent fuel loading/packaging costs/spent fuel pool O&M and Emergency Planning fees (31 Columns may not add due to rounding TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. {) Decommissioning Cost Analysis Section 7, Page 1 of 3
- 7. REFERENCES
- 1. "Decommissioning Cost Analysis for the Wolf Creek Genera.ting Station,"
Document No. Wll-1642-001, Rev. 0, TLG Services, Inc., August 2011
- 2. U.S. Code of Federal Regulations, Title 10, Pai-ts 30, 40, 50, 51, 70 and 72, "Gene1*al Requirements for Decommissioning Nuclear Facilities," Nuclear Regulatory Commission, 53 Fed. Reg., 24018-, June 27, 1988
- 3. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.159, "Assuring the Availability of Funds for Decommissioning Nuclear Reactors," Rev. 2, October 2011
- 4. U.S. Code of Federal Regulations, Title 10, Part 20, Subpart E, "Radiological Criteria for License Termination"
- 5. U.S. Code of Federal Regulations, Title 10, Parts 20 and 50, "Entombment Options for Power Reactors," Advanced Notice of Proposed Rulemaking, 66 Fed.
Reg. 52551, October 16, 2001
- 6. U.S. Code of Federal Regulations, Title 10, Parts 2, 50 and 51, "Decommissioning of Nuclear Power Reactors," Nuclear Regulatory Commission, 61 Fed. Reg. 39278, July 29, 1996.
- 7. "Nuclear Waste Policy Act of 1982 and Amendments," U.S. Department of Energy's Office of Civilian Radioactive Management, 1982
- 8. Charter of the Blue Ribbon Commission on America's Nuclear Future, "Objectives and Scope of Activities,"
http://-.vv1YJ.brc__,gov/index.nhp?q=pa.filllcharter
- 9. "Blue Ribbon Commission on America's Nuclear Future, Report to the Secretary of Energy," _b.ttp:/l~:\Y..YY-brc.go\'.L, p. 32, January 2012
- 10. "Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste," U.S. DOE, January 11, 2013
- 11. "Acceptance Priority Ranking & An.nual Capacity Report," DOE/RW-0567, July 2004 TLG Services, lnc.
Wolf Creek Generating Station. Docnment Wll-1697-001, Rev.() Decommissioning Cost Analysis Section 7, Page 2 of 3
- 7. REFERENCES (continued)
- 12. "Report to Congress on the Demonstration of the Interim Storage of Spent Nuclear Fuel from Decommissioned Nuclear Power Reactor Sites" DOE/RW-0596, December 2008
- 13. U.S. Code of Federal Regulations, Title 10, Part 50, "Domestic Licensing of Production and Utilization Facilities," Subpart 54 (bb), "Conditions of Licenses"
- 14. "Low Level Radioactive Waste Policy Act," Public Law 96-573, 1980
- 15. "Low-Level Radioactive vVaste Policy Amendments Act of 1985," Public Law 99-240, 1986
- 16. vVaste is classified in accordance with U.S. Code of Federal Regulations, Title 10, Part 61.55
- 17. U.S. Code of Federal Regulations, Title 10, Part 20, Subpart E, Final Rule, "Radiological Criteria for License Termination," 62 Fed. Reg. 39058, July 21, 1997
- 18. "Establishment of Cleanup Levels for CERCLA Sites with Radioactive Contamination," EPA Memorandum OSWER No. 9200.4-18, August 22, 1997.
- 19. U.S. Code of Federal Regulations, Title 40, Part 141.16, "Maximum contaminant levels for beta particle and photon radioactivity from man-made radionuclides in community water systems"
- 20. "Memorandum of Understanding Between the Environmental Protection Agency and the Nuclear Regulatory Commission: Consultation and Finality on Decommissioning and Decontamination of Contaminated Sites," OSWER 9295.8-06a, October 9, 2002
- 21. "1V1ulti-Agency Radiation Survey and Site Investigation l\tlanual (MARSSIM),"
l\i"VREG/CR-1575, Rev. 1, EPA 402-R-97-016, Rev. 1, August 2000
- 22. T.S. LaGua1*dia et al., "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates," AIF/NESP-036, May 1986
- 23. vV.J. Manion and T.S. LaGuardia, "Decommissioning Handbook," U.S.
Department of Energy, DOE/EV/10128-1, November 1980 TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost .4nalysis Section 7, Page 3 of 3
- 7. REFERENCES (continued)
- 24. "Building Construction Cost Data 2014," Robert Snow Means Company, Inc.,
Kingston, lVIassachusetts
- 25. Project and Cost Engineers' Handbook, Second Edition, p. 239, American Association of Cost Engineers, Marcel Dekker, Inc., New York, New York, 1984
- 26. U.S. Department of Transportation, Title 49 of the Code of Federal Regulations, "Transportation," Parts 173 through 178
- 27. Tri-State Motor Transit Company, Radioactive Materials Tariff
- 28. J.C. Evans et al., "Long-Lived Activation Products in Reactor Materials" NUREG/CR-347 4, Pacific Northwest Laboratory for the Nuclear Regulatory Commission, August 1984
- 29. R.I. Smith, G.J. Konzek, W.E. Kennedy, Jr., "Technology, Safety and Costs of Decommissioning a Reference Pressurized vVater Reactor Power Station, II NUREG/CR-0130 and addenda, Pacific Northwest Laboratory fo:r the Nuclear Regulatory Commission, June 1978
- 30. H.D. Oak, et al., "Technology, Safety and Costs of Decommissioning a Reference Boiling Water Reactor Power Station, NUREG/CR-0672 and addenda, Pacific 11 Northwest Laboratory for the Nuclear Regulatory Commission, June 1980
- 31. SECY-00-0145, "Integrated Rulemaking Plan for Nuclear Power Plant Decommissioning," June 2000
- 32. "1\1icrosoft P1*oject Professional 2010," Microsoft Corporation, Redmond, WA.
- 33. "Atomic Energy Act of 1954," (68 Stat. 919)
TLG Services, Inc.
Wolf Creell Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix A, Page 1 of 4 APPENDIX A UNIT COST FACTOR DEVELOPMENT TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. {} Decommissioning Cast Analysis Appendix A, Page 2 of 4 APPENDIX A UNIT COST FACTOR DEVELOPMENT Example: Unit Factor for Removal of Contaminated Heat Exchanger< 3,000 lbs.
- 1. SCOPE Heat exchangers weighing< 3,000 lbs. will be removed in one piece using a crane or small hoist. They will be disconnected from the inlet and outlet piping. The heat exchanger will be sent to the waste processing area.
- 2. CALCULATIONS Activity Critical Act Activity Duration Duration ID Description (minutes) (minutes)*
a Remove insulation 60 (b) b l\fount pipe cutters 60 60 c Install contamination controls 20 (b) d Disconnect inlet and outlet lines 60 60 e Cap openings 20 (d) f Rig for removal 30 30 g Unbolt from mounts 30 30 h Remove contamination controls 15 15 1 Remove, wrap, send to waste processing area 60 60 Totals (Activity/Critical) 355 255 Duration adjustment(s):
+ Respiratory protection adjustment (50% of critical duration) 128 + Radiation/A.LARA adjustment (37% of critical duration) _frQ Adjusted work duration 478 + Protective clothing adjustment (30% of adjusted duration) 143 Productive work duration 621 +Work break adjustment (8.33 % of productive duration)
Total work duration (minutes) 673
***Total duration= 11.217 hr***
- alpha designators indicate activities that can be peiformed in parallel TLG Semices, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix A, Page 3 of 4 APPENDIX A (continued)
- 3. LABOR REQUIRED Duration Rate Crew Number (hours) ($/hr) Cost Laborers 3.00 11.217 $17.35 $583.84 Craftsmen 2.00 11.217 $36.09 $809.64 Foreman 1.00 11.217 $39.73 $445.65 General Foreman 0.25 11.217 $44.51 $124.82 Fi.Te Watch 0.05 11.217 $17.35 $9.73 Health Physics Technician 1.00 11.217 $44.00 $547.84 Total Labor Cost $2,521.52
- 4. EQUIPMENT & CONSUMABLES COSTS Equipment Costs none Consumables/l\!laterials Costs Universal Polypropylene Sorbent 50@ $0.62/sq ft [IJ $31.00
" Tarpaulin, oil resistant, fire retardant 50@ $0.28/sq ft r21 $14.00 @ Gas torch consumables 1@ $19.53 x 1 /hr r3 J $19.53 Subtotal cost of equipment and materials $64.53 Overhead & profit on equipment and materials@ 15.30 % $11.71 Total costs, equipment & material $76.24 TOTAL COST:
Removal of contaminated heat exchanger <3000 pounds: $2,597.76 Total labor cost: $2,521.52 Total equipment/material costs: $76.24 Total craft labor man-hours required per unit: 81.88 TLG Services, l nc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Plnalysis Appendix A, Page 4 of 4
- 5. NOTES AND REFERENCES w Work difficulty factors were developed in conjunction with the Atomic Industrial Forum's (now NEI) program to standardize nuclear decommissioning cost estimates and are delineated in Volume 1, Chapter 5 of the "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates," iVF/NESP-036, May 1986.
<& References for equipment & consumables costs:
- 1. 'NW\v.mcnJ_sster.corn online catalog, l\!IcMaster Carr Spill Control (7193T88)
- 2. R.S. Means (2014) Division 01 56, Section 13.60-0600, page 23
- 3. R.S. Means (2014) Division 01 54 33, Section 40-6360, page 698
"' Material and consumable costs were adjusted using the regional indices for Empol'ia, Kansas.
TLG Services, Inc.
Wolf C1*eeh Generating Station Document Wll-Hi97-001, Rev. 0 Decommissioning Cost Analysis Appendix B, Page 1 of 7 APPENDIXB UNIT COST FACTOR LISTING (DECON: Power Block Structures Only) TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix B, Page 2 of 7 APPENDIXB UNIT COST FACTOR LISTING (Power Block Structures Only) Unit Cost Factor Cost/Unit($) Removal of clean instrument and sampling tubing, $/linear foot 0.23 Removal of clean pipe 0.25 to 2 inches diameter, $/linear foot 2.33 Removal of clean pipe >2 to 4 inches diameter, $/linear foot 3.57 Removal of clean pipe >4 to 8 inches diameter, $/linear foot 7.60 Removal of clean pipe >8 to 14 inches diameter, $/lineai* foot 13.92 Removal of clean pipe > 14 to 20 inches diameter, $/linear foot 18.31 Removal of clean pipe >20 to 36 inches diameter, $/linear foot 26.89 Removal of clean pipe >36 inches diameter, $/linear foot 31.86 Removal of clean valve >2 to 4 inches 50.16 Removal of clean valve >4 to 8 inches 76.02 Removal of clean valve >8 to 14 inches 139.24 Removal of clean valve >14 to 20 inches 183.14 Removal of clean valve >20 to 36 inches 268.93 Removal of clean valve >36 inches 318.61 Removal of clean pipe hanger for small bore piping 19.16 Removal of clean pipe hanger for large bore piping 58.99 Removal of clean pump, <300 pound 132.63 Removal of clean pump, 300-1000 pound 377.23 Removal of clean pump, 1000-10,000 pound 1,441.41 Removal of clean pump, > 10,000 pound 2,802.92 Removal of clean pump motor, 300-1000 pound 154.39 Removal of clean pump motor, 1000-10,000 pound 594.17 Removal of clean pump motor, > 10,000 pound 1,336.89 Removal of clean heat exchanger <3000 pound 785.49 Removal of clean heat exchanger >3000 pound 1,998.43 Removal of clean feedwater heater/deaerator 5,552.44 Removal of clean moisture separator/reheater 11,307.46 Removal of clean tank, <300 gallons 170.09 Removal of clean tank, 300-3000 gallon 527.92 Removal of clean tank, >3000 gallons, $/square foot surface area 4.69 Removal of clean electrical equipment, <300 pound 68.99 TLG Se1*vices, Inc.
Wolf Creek Generating Station Document Wll-1697-{}{Jl, Rev.() Decommissioning Cost Analysis Appendix B, Page 3 of 7 APPENDIXB UNIT COST FACTOR LISTING (Power Block Structures Only) Unit Cost Factor Cost/Unit($) Removal of clean electrical equipment, 300-1000 pound 251.38 Removal of clean electrical equipment, 1000-10,000 pound 502.77 Removal of clean electrical equipment, > 10,000 pound 1,230.34 Removal of clean electrical transformer < 30 tons 854.47 Removal of clean electrical transformer > 30 tons 2,460.71 Removal of clean standby diesel generator, <100 kW 872.77 Removal of clean standby diesel generator, 100 kW to 1 MW 1,948.06 Removal of clean standby diesel generator, > 1 MW 4,032.88 Removal of clean electrical cable tray, $/linear foot 6.70 Removal of clean electrical conduit, $/linear foot 2.94 Removal of clean mechanical equipment, <300 pound 68.99 Removal of clean mechanical equipment, 300-1000 pound 251.38 Removal of clean mechanical equipment, 1000-10,000 pound 502.77 Removal of clean mechanical equipment, > 10,000 pound 1,230.34 Removal of clean HVAC equipment, <300 pound 83.41 Removal of clean HVAC equipment, 300-1000 pound 302.06 Removal of clean HVAC equipment, 1000-10,000 pound 602.02 Removal of clean HVAC equipment, > 10,000 pound 1,230.34 Removal of clean HVAC ductwork, $/pound 0.24 Removal of contaminated instrument and sampling tubing, $/linear foot 0.94 Removal of contaminated pipe 0.25 to 2 inches diameter, $/linear foot 14.12 Removal of contaminated pipe >2 to 4 inches diameter, $/linear foot 22.80 Removal of contaminated pipe >4 to 8 inches diameter, $/linear foot 38.15 Removal of contaminated pipe >8 to 14 inches diameter, $/linear foot 70.70 Removal of contaminated pipe> 14 to 20 inches diameter, $/linear foot 84.15 Removal of contaminated pipe >20 to 36 inches diameter, $/linear foot 114.54 Removal of contaminated pipe >36 inches diameter, $/linear foot 134.40 Removal of contaminated valve >2 to 4 inches 284.75 Removal of contaminated valve >4 to 8 inches 337.05 Removal of contaminated valve >8 to 14 inches 653.81 Removal of contaminated valve > 14 to 20 inches 826.33 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis A.ppendix B, Page 4. of 7 APPENDIXB UNIT COST FACTOR LISTING (Power Block Structures Only) Unit Cost Factor Cost/Unit($) Removal of contaminated valve >20 to 36 inches 1,092.27 Removal of contaminated valve >36 inches 1,290.80 Removal of contaminated pipe hanger for small bore piping 92.25 Removal of contaminated pipe hanger for large bore piping 273.64 Removal of contaminated pump, <300 pound 607.53 Removal of contaminated pump, 300-1000 pound 1,398.94 Removal of contaminated pump, 1000-10,000 pound 4,182.46 Removal of contaminated pump, > 10,000 pound 10,185.83 Removal of contaminated pump motor, 300-1000 pound 619.54 Removal of contaminated pump motor, 1000-10,000 pound 1,728.94 Removal of contaminated pump motor, > 10,000 pound 3,881.92 Removal of contaminated heat exchanger <3000 pound 2,597.76 Removal of contaminated heat exchanger >3000 pound 7,619.81 Removal of contaminated tank, <300 gallons 1,015.34 Removal of contaminated tank, >300 gallons, $/square foot 19.19 Removal of contaminated electrical equipment, <300 pound 453.16 Removal of contaminated electrical equipment, 300-1000 pound 1,107.84 Removal of contaminated electrical equipment, 1000-10,000 pound 2,134.34 Removal of contaminated electrical equipment, >10,000 pound 4,228.16 Removal of contaminated electrical cable tray, $/linear foot 22.02 Removal of contaminated electrical conduit, $/linear foot 11.08 Removal of contaminated mechanical equipment, <300 pound 503.94 Removal of contaminated mechanical equipment, 300-1000 pound 1,222.68 Removal of contaminated mechanical equipment, 1000-10,000 pound 2,351.72 Removal of contaminated mechanical equipment, > 10,000 pound 4,228.16 Removal of contaminated HVAC equipment, <300 pound 503.94 Removal of contaminated HVAC equipment, 300-1000 pound 1,222.68 Removal of contaminated HVAC equipment, 1000-10,000 pound 2,351.72 Removal of contaminated HVAC equipment, > 10,000 pound 4,228.16 Removal of contaminated HVAC ductwork, $/pound 1.52 Removal/plasma arc cut of contaminated thin metal components, $/linear in. 2.34 TllG Services, Inc.
Wolf Creeh Generating Station Document W11-169'l-001, Rev. 0 Decommissioning Cost Analysis Appendix B, Page 5 of 7 APPENDIXB UNIT COST FACTOR LISTING (Power Block Strudures Only) Unit Cost Factor Cost!U nit($) Additional decontamination of surface by washing, $/square foot 4.91 Additional decontamination of surfaces by hydrolasing, $/square foot 23.78 Decontamination rig hook up and flush, $/ 250 foot length 4,233.25 Chemical flush of components/systems, $/gallon 20.14 Removal of clean standard reinforced concrete, $/cubic yard 106.89 Removal of grade slab concrete, $/cubic yard 131.22 Removal of clean concrete floors, $/cubic yard 296.88 Removal of sections of clean concrete floors, $/cubic yard 830.62 Removal of clean heavily rein concrete w/#9 rebar, $/cubic yard 199.70 Removal of contaminated heavily rein concrete w/#9 rebar, $/cubic yard 1,568.31 Removal of clean heavily rein concrete w/#18 rebai-, $/cubic yard 252.57 Removal of contaminated heavily rein concrete w/#18 re bar, $/cubic yard 2,072.91 Removal heavily rein concrete w/#18 rebar & steel embedments, $/cubic yard 349.40 Removal of below-grade suspended floors, $/cubic yard 296.88 Removal of clean monolithic concrete structures, $/cubic yard 660.44 Removal of contaminated monolithic concrete structures, $/cubic yard 1,557.24 Removal of clean foundation concrete, $/cubic yard 524.47 Removal of contaminated foundation concrete, $/cubic yard 1,452.16 Explosive demolition of bulk concrete, $/cubic yard 24.57 Removal of clean hollow masonry block wall, $/cubic yard 67.38 Removal of contaminated hollow masonry block wall, $/cubic yard 249.24 Removal of clean solid masonry block wall, $/cubic yard 67.38 Removal of contaminated solid masorny block wall, $/cubic yard 249.24 Backfill of below-grade voids, $/cubic yard 33.64 Removal of subterranean tunnels/voids, $/linear foot 80.79 Placement of concrete for below-grade voids, $/cubic yard 124.80 Excavation of clean material, $/cubic yard 2.97 Excavation of contaminated material, $/cubic yard 36.20 Removal of clean concrete rubble (tipping fee included), $/cubic yard 23.26 Removal of contaminated concrete rubble, $/cubic yard 22.85 Removal of building by volume, $/cubic foot 0.26 TLG Services, Inc.
Wolf Creek Generating Station Document WI 1-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix B, Page 6 of 7 APPENDIXB UNIT COST FACTOR LISTING (Power Block Structures Only) Unit Cost Factor Cost!Unit($) Removal of clean building metal siding, $/square foot 0.83 Removal of contaminated building metal siding, $/square foot 3.20 Removal of standard asphalt roofing, $/square foot 1.08 Removal of transite panels, $/square foot 1.45 Scarifying contaminated concrete surfaces (drill & spall), $/square foot 10.01 Scabbling contaminated concrete floors, $/square foot 5.48 Scabbling contaminated concrete walls, $/square foot 13.89 Scabbling contaminated ceilings, $/square foot 47.11 Scabbling structural steel, $/square foot 4.50 Removal of clean overhead crane/monorail< 10 ton capacity 373.62 Removal of contaminated overhead crane/monorail< 10 ton capacity 1,195.73 Removal of clean overhead crane/monorail> 10-50 ton capacity 896.68 Removal of contaminated overhead crane/monorail > 10-50 ton capacity 2,869.27 Removal of polar crane > 50 ton capacity 3,832.57 Removal of gantry crane > 50 ton capacity 15,379.40 Removal of structural steel, $/pound 0.14 Removal of clean steel floor grating, $/square foot 3.17 Removal of contaminated steel floor grating, $/square foot 9.77 Removal of clean free standing steel liner, $/square foot 7.03 Removal of contaminated free standing steel liner, $/square foot 22.26 Removal of clean concrete-anchored steel liner, $/squa1*e foot 3.52 Removal of contaminated concrete-anchored steel liner, $/square foot 25.99 Placement of scaffolding in clean areas, $/square foot 13.34 Placement of scaffolding in contaminated areas, $/square foot 19.71 Landscaping with topsoil, $/acre 24,509.59 Cost of CPC B-88 LSA box & preparation for use 2,072.95 Cost of CPC B-25 LSA box & preparation for use 1,888.34 Cost of CPC B-12V 12 gauge LSA box & preparation for use 1,521.99 Cost of CPC B-144 LSA box & preparation for use 10,950.90 Cost of LSA drum & preparation for use 173.50 Cost of cask liner for CNSI 8 120A cask (resins) 12,218.74 TLG Services, Inc.
l Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix B, Page 7 of 7 APPENDIXB UNIT COST FACTOR LISTING (Power Block Structures Only) Unit Cost Factor Cost!Unit($) Cost of cask liner for CNSI 8 120A cask (filters) 8,590.78 Decontamination of surfaces with vacuuming, $/square foot 0.56 TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix C, Page 1 of 10 APPENDIXC DETAILED COST ANALYSIS DE CON TLG Services, Inc.
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Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix D, Page 1 of 12 APPENDIXD DETAILED COST ANALYSIS SAFSTOR TLG Services, Inc.
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Wolf Creeh Generating Stat.ion Document Wll-1697-001, Rev.{) Decommissioning Cost Analysis Appendix E, Page 1 of Jl 1 APPENDIXE COST SENSITIVITY OF LONG-TERM, ON-SITE SPENT FUEL STORAGE TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 2 of 111 APPENDIXE COST SENSITIVITY OF LONG-TERM? ON-SITE SPENT FUEL STORAGE Introduction As discussed in the last Decommissioning Cost Analysis for Wolf Creek issued in August 2011, developments in the area of spent nuclear fuel disposal suggest a possibility that the federal government may not have removed all of Wolf Creek's spent nuclear fuel and high-level radioactive waste (hereafter, simply "spent fueY') from the station by the time the plant has been decommissioned. There still is much uncertainty in this area. However, WCNOC asked TLG to consider that possibility, to make some assumptions regarding potential effects of the government's delayed removal of spent fuel from Wolf Creek, and to conduct a cost sensitivity analysis reflecting those assumptions. The following discussion is the result of that analysis. Because the assumptions used in this Appendix E analysis are so speculative at this point, the hypothetical cost effects shown here have not been included in the overall updated cost estimate in this report. Congress passed the "Nuclear Waste Policy Act"[IJ (NWPA) in 1982, assigning the federal government's long-standing responsibility for disposal of the spent nuclear fuel created by the commercial nuclear generating plants to the Department of Energy (DOE). The NWPA provided that DOE would enter into contracts with generators in which DOE would promise to take the generator's spent fuel and high-level radioactive waste and the generators would pay the cost of the disposition services for that material. The NVVPA, along with the individual contracts with the generators, specified that the DOE was to begin accepting spent fuel by January 31, 1998. Since the original legislation, the DOE has announced several delays in the program schedule. By January 1998, the DOE had failed to accept any spent fuel or high level waste, as required by the NWPA and its contracts. Delays continue and, as a result, generators are no closer to shipping spent fuel today than in 1998. Politically, the country is at an impasse on high-level waste disposal. The current administration has cut the budget for the geological repository program while promising to "conduct a comprehensive review of policies fo:r managing the back end of the nuclear fuel cycle ... make recommendations for a new plan."[21 Towards th.is goal, "Nuclear Waste Policy Act of 1982 and Amendments," DO E's Office of Civilian Radioactive Management, 1982 2 Ch2..rter of the Blue Ribbon Commission on America's Nuclear Future, "Objectives and Scope of Activities," h tto ://w\','W. brU"'m'/i 11dex. Dhp} a =page/charter TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost A.nalysis Appendix E, Page 3 of 11 the administration appointed a Blue Ribbon Commission on America's Nuclear Future (Blue Ribbon Commission) to make recommendations for a new plan for nuclear waste disposal. The Blue Ribbon Commission's charter includes a requirement that it consider "[O]ptions for safe storage of used nuclear fuel while final disposition pathways are selected and deployed."[3J On January 26, 2012, the Blue Ribbon Commission issued its "Report to the Secretary of Energy" containing a number of recommendations on nuclear waste disposal. Two of the recommendations that may impact decommissioning planning are:
@ "[T]he United States [should] establish a program that leads to the timely development of one or more consolidated storage facilitiesl4J c "[T]he United States should undertake an integrated nuclear waste management program that leads to the timely development of one or more permanent deep geological facilities for the safe disposal of spent fuel and high-level nuclear waste."[51 In January 2013, the DOE issued the "Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste," in i*esponse to the recommendations made by the Blue Ribbon Commission and as "a framework for moving toward a sustainable prog-.ram to deploy an integrated system capable of transporting, storing, and disposing of used nuclear fuel.. ." 6 This document states:
"With the appropriate authorizations from Congress, the Administration currently plans to implement a program over the next 10 years that: Sites, designs and licenses, constructs and begins operations of a pilot interim storage facility by 2021 with an initial focus on accepting used nuclear fuel from shut-down reactor sites;
"" Advances toward the siting and licensing of a larger interim storage facility to be available by 2025 that will have sufficient capacity to provide flexibility in the waste management system and allows for acceptance of enough used nuclear fuel to reduce expected government liabilities; and 3 Ibid.
- l "Blue Ribbon Commission on America's Nuclear Future, Report to the Secretary of Energy,"
http://wvvw. lwc.go'>/sites/defa ult/fiJes/docnments/b1*c_finalreport_jan2012. pdf, p. 32, January 2012 5 Ibid., p.27 6 "Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste," U.S. DOE, January 11, 2013 TLG Services, Inc.
Wolf Creek Generating Station Document WU-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 4 of 11
- > Makes demonstrable progress on the s1tmg and characterization of repository sites to facilitate the availability of a geologic repository by 2048."
Completion of the decommissioning process (release of the entire site for unrestricted use) is highly dependent upon the DOE's ability to remove spent fuel from the site in a timely manner. DOE's repository program is cunently based upon the premise that spent fuel allocations would be accepted for disposal from the nation's commercial nuclear plants, with limited exceptions, in the order in which it was discharged from the reactor (i.e., establishing a national "queue"). Even if spent fuel could be transferred to a federal facility for interim storage (in the absence of a permanent disposal facility), the nature of the queue would be expected to result in a long backlog of spent fuel at each site. Under the current system, as can be seen at sites where reactors have been decommissioned, the owner(s) can anticipate several decades of continuing, on-site storage of the spent fuel before the transfer could be expected to be complete. It should be noted that the cost to dispose of the spent fuel generated from plant operations is not reflected within the estimates. Ultimate disposition of the spent fuel is within the province of the DOE's Waste Management System, as defined by the Nuclear Waste Policy Act. As such, until recently, the disposal cost was being financed by a 1 mill/kWhr surcharge on nuclear generated energy delivered to customers, the fee being paid into the DOE's waste fund during operations. The D.C. Cixcuit ruling on November 19, 2013, ordered the DOE to submit a proposal to Congress to suspend the
- Nuclear Waste Fund fee "until such time as either the Secretary chooses to comply with the Act as it is currently written, or until Cong1:ess enacts an alternative waste management plan". The fee was reduced to O.Omill/kWh as of May 16, 2014. The fee is expected to be reinstated in the future.
Nonetheless, the NRC requires licensees to establish a program to manage and provide funding for the management of all irradiated fuel at the reactor site until title to the fuel is transferred to the Secretary of EnergyJ7l The post-shutdown costs incurred to satisfy this requirement are described below. Base Analyses The estimates described in the main report (and detailed in Appendix C and D) are based in general upon I) a 2025 start date for DOE initiating transfer of commercial spent fuel to a federal facility, and 2) a 2032 start date for the transfer of spent fuel from the Wolf Creek site based on an "oldest fuel first" priority, and the DOE U.S. Code of Federal Regulations, Title 10, Part 50, "Domestic Licensing of Production and Utilization Facilities," Subpart 54 (bb), "Conditions of Licenses" TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 5 of 11 achieving an annual rate of transfer (3,000 metric tons of uranium per year) as reflected in DOE's latest Acceptance Priority Ranking and Annual Capacity Report.fBJ The assumed 2025 DOE start date is nominally based on the last position stated by the DOE. lVIore importantly, the estimates assume that the DOE would give priority to fuel at shutdown sites,[9J i.e., it assumed that Congress would "(l) ... direct the Department to take spent nuclear fuel from decommissioned commercial nuclear power reactors as soon as possible; (2) to establish an expedited siting process; and (3) to authorize the Department to construct and ope1*ate the facility under its regulatory authority, or, if the facility were to be constructed and operated under a U.S. NucleaT Regulatory Commission license, to provide for an expedited siting and licensing process."[lOJ Under this scenario, once Wolf Creek permanently ceases operation, DOE would expedite the removal of spent fuel from the site. The cost estimates described in the main body of this report assumed that:
., The spent fuel pool would be at capacity following the final core off-load and contain freshly discharged assemblies (from the most recent refueling cycles) as well as the final reactor core II' DOE would give priority to the spent fuel .stored in the pool. $ The spent fuel pool would be emptied within the first five and one-half years following plant shutdown.f 11 l This would allow decommissioning to be completed and the site released fox unrestricted use within a 1*elatively short time (see Figure 4.2) or placed into long-term storage without the need of maintaining/operating a spent fuel storage facility.
8 "Acceptance Priority Ranking and Annual Capacity Report," U.S. DOE, Office of Civilian Radioactive Waste Management, DOE/RW-0567, July 2004 9 "Blue Ribbon Commission on America's Nuclear Future, Report to the Secretary of Energy," _ht;.tp://www. brc.govisit~s/defaultLfile5/do~umentEJ._brc finah:_~J2Ql1.ian 2_Q l 4,Jh1f, p. 42, January 2012: "[A]ccepting spent fuel according to the OFF priority ranking instead of giving priority to shutdown reactor sites could greatly reduce the cost savings that could be achieved through consolidated storage if priority could be given to accepting spent fuel from shutdown reactor sites before accepting fuel from still-operating plants ..... The magnitude of the cost savings that could be achieved by giving priority to shutdown sites appears to be large enough (i.e., in the billions of dollars) to warrant DOE exercising its right under the Standard Contract to move this fuel first." 10 "Report to Congress on the Demonstration of the Interim Storage of Spent Nuclear Fuel from Decommissioned Nuclear Power Reacto1* Sites" DOE/RW-0596, December 2008 11 It is assumed that the five and one-half years provides the necessary cooling for the final core to meet transport requirements for decay heat TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev.(} Decommissioning Cost A.nalysis Appendix E, Page 6 ol 11 e The DOE is assumed to use its Transport, Aging and Disposal canister to empty the wet storage pool.l 12l The canisters would be provided to WCNOC at no cost, however, Wolf Creek staffi'or contractors would load, seal and transfer the multi-purpose canisters into a DOE-provided transport cask.
'11 Once the pool is emptied, the DOE would remove the spent fuel stored at the Wolf Creek Independent Spent Fuel Storage Installation (ISFSI). The current analysis assumes that 592 assemblies would be placed in dry storage during plant operations (i.e., maintain full core off-load capability in the spent fuel pool); 16 equivalent dry storage system modules. $ The ISFSI would be decommissioned in conjunction with the dismantling of the adjacent power block structures. "' Greater-than-Class C (GTCC)f 13J material would be transferred directly to the DOE following the segmentation of the reactor internals.
Alternative Analysis In 2008, the DOE issued a report to Congress in which it concluded that it did not have authority, under present law, to accept spent nuclear fuel for interim storage from decommissioned commercial nuclear power reactor sites.f14J It also concluded that legislation would be required that would eliminate the limitations in the Nuclear Waste Policy Act of 1982, as amended, on taking commercial spent nuclear fuel for interim storage prior to the opening of the Yucca Mountain repository. For illustrative purposes only, this alternative analysis examines the impact of the status quo (i.e., the queue), on decommissioning and the resulting cost for long-term, on-site storage of the spent fuel generated during plant operations.f 1 5J Under this scenario:
"' DOE pickup of spent fuel would continue beyond the cessation of plant operations at the rates published for the Kansas Gas and Electric Company in the latest Acceptance Priority Ranking and Annual Capacity Report 12 "Transport, Aging and Disposal Canister System Performance Specification," U.S. DOE, Civilian Radioactive Waste Management System, DOC ID: WMO-TADCS-000001, Rev.I, March 2008 13 U.S. Code of Federal Regulations, Title 10, Part 61, "Licensing Requirements for Land Disposal of Radioactive Waste" 14 "Report to Congress on the Demonstration of the Interim Storage of Spent Nuclear Fuel from Decommissioned Nuclear Power Reactor Sites" DOE/RW-0596, December 2008 15 This analysis does not consider that the cost incurred would most likely be reimbursable as a result of DO E's breach of contract due to it non-performance TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 7 of 11
@ Pickup of spent fuel beyond the last published date would be based upon the plant avei*age of the previous ten years
"' The residual inventory in the spent fuel pool after the five and one-half years of cooling would be transferred to the ISFSI
@ * \Volf Creek would utilize a dry storage system that can accommodate 37 assemblies per module a The ISFSI would be expanded to accommodate the additional dry fuel storage modules needed to empty the spent fuel pool and the GTCC generated during the decommissioning (on the premise that the GTCC would not be accepted by the DOE until after the transfer of the spent fuel was completed)fl6J
<i \VCNOC would operate the ISFSI and manage the spent fuel until such time that the DOE could complete the transfer to an off-site facility
"' The DOE would accept the multi-purpose canister without the need for repackaging the assemblies, i.e., the DOE transport cask could accommodate the multi-purpose canister without modification
@ \VCNOC staff or WCNOC contracted staff would transfer the multi- purpose canister into the DOE-provided transport cask
" The concrete storage overpack and ISFSI pad would he decommissioned once the transfer is completed (2081)
The impact of these assumptions, as compared to the Base Analysis, is summarized as follows. Base Case .Alternative Spent fuel pool inventory at shutdown (assemblies) 1,774 1,774 ISFSI inventory at shutdown (assemblies) 592 592 Spent fuel transferred to the DOE during decommissioning (assemblies) 1,774 336 Spent fuel transferred to the ISFSI for interim storage within 5-Y2 years after shutdown (assemblies) 0 1,438 Number of additional dry-storage modules need to support decommissioning (including GTCC) - 0 39 Transfer of Spent Fuel to DOE Complete (year) 2050 2081 16 GTCC is assumed to be disposed of as it is generated in the base ~nalysis, avoiding the need for interim storage TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost A.nalysis Appendix E, Page 8 of 11 In essence, spent fuel is on site for additional 28 years after plant decommissioning, during which time WCNOC maintains and operates the ISFSI under a General (10 CFR Part 50) or Site-Specific (Part 72) license. The alternative estimate is based upon a nominal value of $1.0 million for the capital cost of a dry storage module and an associated loading cost and transfer cost of $300,000 (from the wet pool to the ISFSI). A unit cost of $150,000 (one half the wet loading cost) was used for transferring the multipurpose canisters from the concrete overpacks at the ISFSI into the DOE-provided transport cask. All such numbers are based on comparative data. The cost of operating an ISFSI, once decommissioning is complete, is shown in the following schedule, particularly in the years 2054 through 2081 following the decommissioning of Wolf Creek. Annual expenditures include the costs for: o Periodic Spent Fuel Transfer
"' Nucleai* Insurance o Property Taxes ~ NRC ISFSI Licensing Fees and Oversight Costs @. Emergency Planning Fees "' ISFSI Operating Costs (maintenance budget, including energy, lighting, and remote surveillance systems) ~ Security Staff (full time, round-the-clock) "' WCNOC Staff (fo1* ISFSI operations, maintenance, and fuel transfer activities)
The schedule of expenditure in the following table delineates the cost contributors by year of expenditures as well as cost contributor (e.g., labor, materials, and waste disposal). Costs are reported in 2014 dollars and are not inflated, escalated, or discounted over the period of expenditure. Since it is assumed that the DOE would not accept GTCC waste prior to completing the transfer of spent fuel, the cost of GTCC disposal is shown in the final year of ISFSI operation (2081). This same cost is included during the decommissioning phase in the base analyses (e.g., in Table 3.1, during years 2046-2048 for the DECON alternative). While this analysis attempts to capture the cost for long-term spent fuel management at the Wolf Creek site, under the scenai*io outlined above, it is WCNOC's position that the DOE has a contractual obligation to accept Wolf Creek's fuel earlier than the TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 9 of 11 projections set out above consistent with its contract commitments. No assumption made in this analysis should be interpreted to be inconsistent with this claim. TLG Seroices9 Inc.
Wolf Creeh Generating Station Document Wll-16'97-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 10 of 11 TABLEE DECON ALTERNATIVE WITH LONG-TERM SPENT FUEL MANAGEMENT SCHEDULE OF TOTAL ANNUAL Fd""iPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 5_3,G?3 . * -- 4~247 i;956_T _______________32T*:------ --:7-~o-42-L ---6-6~93-41
--~----L 76,316 : 28,804
- 3,58()\ 16,826 ] 22,121 :, 147;647. :
, ---- -74,296 r-------36~065-T - - --2-:2s5-r-* **4a*~-5-92T ----12,-T35_r___ ****165,373 l
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204s 67,272 I 24,217 I i,979 i 20,314 i 9,615 I 123,397 I
!********-*2049---~- . . ---~3~1~§--T----.*x1=66~-T~-*** --jj3o4T--*---*-9;j9iT _______ §,2(??'T- . *. -lQQ-,-Q?§]
- 2050 ! 55,621 ! 14,633 : i,543 I s,12s : 7,438 ' ss,363 :
~---- 2051--.. r-------§_6, l?-s.r-------A~s.ci9-I ----------6-56T - - ** ?~-2~-r------- 4~o9-.YJ:--:--.--1~1@s.-J , ~-Q_5._? -+ :i~~~i~ -j- _ ~-:~-~i I 1
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-~:~i~~- !--- gt -~-:-~-iZ--! - -~-:-~~~--1 2058 . . . . . . . __ g_ 1__!_~? o 378-1 . 7:876- ]
i 2059 _f)Jf)3 0 : 2,378 j 7,8-7§:-] 2060 __ _QL~Q§_ ___ ?.~~ Q j-1~§-~ r_ _* 7,898 i
' 2061 . 5,J!:J? , 2s3
- o* ?,?78 L -7,~7?J
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- 7,898 l 2065 5,Jf}3. : 72 [ 0 . . ... .. . !2 1 3.7~ L -7:§.~76::*1 5 193 ;
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Wolf Creek Generating Station Document Wll-1.697-001, Rev. 0 Decommissioning Cost Analysis Appendix E, Page 11 of 11 TABLE E (continued) DECON ALTERNATIVE WITH LONG-TERM SPENT FUEL MANAGEMENT SCHEDULE OF TOTAL ANNUAL EXPENDITURES (thousands, 2014 dollars) Equipment & Year Labor Materials Energy Burial Other Total 2076 1 - - ---- * * * - - - - - - - - * - *--*--**-------~----**-,-*-*---*------------*--- ---*--'-*******-- -*-- ---*--****-****-.-* -*--~--*r**
..... o T 2,384 1
- ***--**-*-******-----**--*-****----**-*-*--:- -----********-*** --------~- -* -t~---- -*-
__y]_s9s_J., 2077 5,)~3 72 \ 0 i 2078 _~,J~_3___ ,____ 121 -**
- o 2,378+ *-
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2;s'7s r _+/-z_§1§] 7 ,876 \
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. . _§,?Q§ L . . . .*. :.* i~f * * . 9:J . . . . . ?1_9_§41.-.. - * * . . __71_E?-9.§__ J 5,os5 75 1 s19 L 1s,6os 1 . . ??,?12 ;
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Wolf Creek Generating Station Document Wl 1-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix F, Page 1ol3 APPENDIXF RESPONSE TO JUNE 13, 2013 ORDER TLG Services, Inc.
Wolf Creek Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis Appendix F, Page 2 of 3 APPENDIXF RESPONSE TO JUNE 13, 2013 ORDER In its Order dated June 13, 2013, the State Corporation Commission of the State of Kansas closed Docket No. 13-WCNE-204-GIE but required the parties to update its estimate on the total capital costs for the \Volf Creek Independent Spent Fuel Storage Installation (ISFSI) in future decommissioning financing plans. This Order appeared to be predicated on the then-current plan for executing the ISFSI project, which placed requests for quotes and award of contracts in the year 2014. Lower than expected fuel consumption has allowed Wolf Creek to delay implementation of the ISFSI project. WCNOC's current plan for executing the ISFSI project is as follows:
"' 2016: Issue requests for quotes, receive proposals, award contracts, and begin design development.
a 2017-2019: Vendor design and procurement, develop and issue plant design change packages and field work packages, install pad, lighting, security systems, construct necessary additional buildings, and establish haul path.
'"' 2020: Receive system and install components, install Transfer Equipment, perform site acceptance testing, notify the Nuclear Regulatory Commission of the plant's intent to begin dry storage of spent fuel, and prepare for first load campaign in the fall 2020.
As explained below, consequently, it is premature to provide a specific response to the question in the Commission's Order. The Wolf Creek ISFSI project still is at a very preliminary stage with virtually all key project decisions remaining to be made. These decisions involve design, development, installation and operation of the ISFSI. These decisions will affect the ultimate capital and operating costs of the project and the timing of when those costs will be incurred. Some of the major decisions, none of which have yet been made, include:
"' Designer of the project, vendor of the components, and builder of the project. % .A.mount of cooling time for assemblies in the spent fuel pool before moving to dry cask.
0 Number of spent fuel assemblies per canister.
"' One or multiple locations for the ISFSI.
TLG Services, Inc.
Wolf Creeh Generating Station Document Wll-1697-001, Rev. 0 Decommissioning Cost Analysis lippend ix F, Page 3 of 3
"' Full or partial sized pad initially built. ,. Locate the ISFSI inside or outside the plant's current Protected Area Boundary. " Haul path transport method (vehicle or rail). & Number and type of canisters and casks to purchase in a year. °' \Vhether the load team will be site personnel, a "partner" arrangement, or turnkey.
ffEi Whether to own, lease or share transfer equipment. Our review of selected available industry information, and informal inquiries from various industry sources, suggest that the range of total (not annual) capital cost for ISFSI projects has been between $45 million and $85 million. However, these cost differences are highly dependent upon the combination of key decisions made for each project. This cost range is presented here for illustrative purposes only and should not be deemed to be estimates for the Wolf Creek facility because of the vai*ious diverging influences discussed above. In addition to the numerous uncertainties mentioned above, another significant uncertainty is the number of years over which the ISFSI will be needed to store Wolf Creek's spent fuel. That uncertainty is caused in large part by the federal government's continued inability to achieve a workable solution for disposal, or at least temporary storage, of the nation's spent fuel, described in more detail in the main report. TLG Services, Inc.
Enclosure XI 11 to CO 17-0003 McDermott Will & Emery Memorandums (7 pages)
McDermott Will&Emery Boston Brussels Chicago Dallas DOsseldorf Frankfurt Houston London Los Angeles Miami Milan Munich New York Orange County Paris Rome Seoul Silicon Valley Washington, D.C. Strategic alliance with MWE China Law Offices (Shanghai) MEMORANDUM February 27, 2017 ANNUAL NRC CERTIFICATION UPDATE Each year, we provide information necessary for a nuclear licensee to update the "minimum financial assurance amount" for decommissioning a nuclear unit, as required by the Nuclear Regulatory Commission (NRC). This briefing paper includes certain background information concerning this requirement of the NRC as well as the data necessary for a licensee to calculate the minimum financial assurance amount in current dollars. Please note that for 2016, the NRC added the Compact Waste Facility located in Andrews County, Texas as a third burial site and changed the alternative burial factor to apply to generators located in non-compact affiliated states and generators located in compact affiliated states with no disposal facility. It should also be noted that burial costs for 2016 for the Washington disposal site are higher than 2012 costs for both compact-affiliated facilities and non-compact affiliated facilities. With respect to the South Carolina site, burial costs for 2016 are lower than 2012 for both compact-affiliated and non-compact facilities at the site. It should also be noted that in 2016, the fuel component of the energy escalation factor increased from that in 2015, resulting in a rise in the energy factor for
- 2016. These changes could significantly impact a licensee's computation of its adjusted minimum financial assurance amount.
Background
The NRC requires every licensee of a nuclear unit to certify that financial assurance for decommissioning a nuclear unit will be provided in the minimum financial assurance amount prescribed by the regulations of the NRC. See 10 C.F.R. §§ 50.33(k) and 50.75. Typically, a licensee certifies to the NRC that it will make annual, levelized contributions to an external trust fund which, over the remaining license period for the nuclear unit, will accumulate a sum equal to the minimum financial assurance amount. 500 North Capitol Street, N.W .Washington, D.C. 20001 Tel: 202. 756.8000 Fax: 202.756.8087
Each licensee must adjust the minimum financial assurance amount annually to reflect inflation in the estimated costs of decommissioning. See 10 C.F.R. § 50.75(b). In addition, the licensee must adjust its future contributions to the external decommissioning fund to approximate pro rata contributions, over the remaining license term, of the escalated minimum financial assurance amount remaining to be accumulated. See NRC Regulatory Guide 1.159, Revision 2, section 2.2.8. Adjustments to the pro rata contributions may be made to coincide with ratemaking proceedings before a public service commission or to reflect the schedule of ruling amounts issued by the Internal Revenue Service under section 468A of the Internal Revenue Code for a qualified nuclear decommissioning fund. See NRC Regulatory Guide 1.159, Revision 2, section 2.1.5. Such adjustments, in any event, should be made at least once every two years for licensees who are not rate-regulated, or at least once every five years for rate-regulated licensees. Id. 1 The computation of the adjusted minimum financial assurance amount is made by reference to: (1) a formula for determining a base amount expressed in January, 1986 dollars; and (2) an adjustment factor to escalate the base amount to reflect current dollars. See 10 C.F.R. § 50.75(c). The base amount in 1986 dollars is $105 million and $135 million, respectively, for a pressurized water reactor (PWR) and a boiling water reactor (BWR), assuming each has greater than 3,400 MWt. See 10 C.F.R. § 50.75(c)(l). The adjustment factor must be: at least equal to 0.65L + 0.13 E + 0.22 B ... where Land E are escalation factors for labor and energy, respectively, and are to be taken from regional data of U.S. Department of Labor Bureau of Labor Statistics and B is an escalation factor for waste burial and is to be taken from NRC report NUREG-1307, "Report on Waste Burial Charges." See 10 C.F.R. § 50.75(c)(2). Reporting Requirements Pursuant to the NRC rules, a licensee is required to file a report with the NRC on the status of its decommissioning funding at least every two years. See 10 C.F.R. § 50.75(£)(1). Annual reporting is required for a plant that is within five years of the projected end of its operation, or where conditions have changed such that it will close within five years, or already has closed. Id. The information in the report must include (1) the amount of decommissioning funds estimated to be required pursuant to 10 C.F.R. § 50.75(b) and (c); (2) the amount accumulated to the end of the calendar year preceding the date of the report; (3) a schedule of the annual amounts remaining to be collected; (4) the assumptions used regarding rates of escalation in decommissioning costs, rates of earnings on decommissioning funds, and rates of other factors used in funding projections; (5) any contract the licensee is relying upon pursuant to 10 C.F.R. § 50.75(e)(l)(v) for collections of decommissioning monies from customers; (6) any modifications to the method of providing financial assurance since the last submitted report; and (7) any material changes to the decommissioning trust agreement(s). Id. 1 Previously, NRC Regulatory Guide 1.159, Revision 1, dated October 2003, provided that rate-regulated licensees should make adjustments at least every six years.
Escalation Factors In anticipation of the March 31, 2017 reporting deadline on the status of decommissioning funding, we have calculated the current escalation factors as follows: LABOR ENERGY BURIAL PWR BWR Northeast 2.78 PWR 1.870 Washington South 2.50 BWR 1.869 Compact-Affiliated2 8.706 7.290 Midwest 2.61 Combination 8.129 6.668 West 2.65 South Carolina Compact-Affiliated 30.061 26.329 Combination 10.971 12.111 Texas3 Compact-Affiliated 8.508 8.293 Combination 10.672 10.441 Unaffiliated/No Disposal Facility4 12.471 13.132 The data supporting the calculation of these escalation factors is attached. In our calculations, we have data available from the U.S. Department of Labor, Bureau of Labor Statistics (4Q ' 16 for Labor and December '16 for Energy) and from the Draft NRC NUREG-1307 (Revision 16) for Burial. 5 It should be noted that in 2016, the fuel oil value of the fuel component of the energy escalation factor increased from the value in 2015. The final December 2015 fuel oil value was 131.1. The preliminary December 2016 fuel oil value is 152.0. This increase resulted in a rise in the energy factor. For 2016 the NRC also added the Compact Waste Facility located in Andrews County, Texas as a third burial site. The Texas facility is available to generators located in states affiliated with the Texas Compact, which is comprised of Texas and Vermont. In addition, the NRC also 2 Effective with NUREG-1307, Revision 15, the NRC changed the nomenclature for the two disposal options, previously referred to as "Direct Disposal" and "Direct Disposal with Vendors" to "Compact-Affiliated Disposal Facility Only" and "Combination of Compact-Affiliated and Non-Compact Disposal Facilities," respectively, to better describe the options. 3 Effective with the Draft NUREG-1307, Revision 16, the NRC added the Compact Waste Facility located in Andrews County, Texas as a full-service low-level radioactive waste disposal facility for generators located in states affiliated with the Texas Compact. The Texas Compact is comprised of Texas and Vermont. 4 Effective with the Draft NUREG-1307, Revision 16, because the Texas facility is also available to states not affiliated with the Texas Compact, the NRC recomputed the burial factor for generators located in non-compact affiliated states and for generators located in compact affiliated states that have no disposal facility. This new burial factor represents the composite of the disposal rates for the Texas facility and the disposal facility located in Clive, Utah that is available for any Class A low level waste generated in the United States. 5 Draft NRC NUREG-1307 (Revision 16) was published in November 2016. It is our understanding that the report should be finalized soon, and that the burial factors, when finalized, are not expected to change substantially from what is in the draft report.
changed the alternative burial factor to apply to generators located in non-compact affiliated states and generators located in compact affiliated states with no disposal facility. The rise in the energy factor and the changes to the burial factor could impact a licensee's computation of its adjusted minimum financial assurance amount. For additional information regarding the foregoing, please contact Marty Pugh at 202-756-8368 or at mpugh@mwe.com or Gale Chan at 202-756-8052 or gchan@mwe.com. Memoranda to the Utility Decommissioning Tax Group are periodic publications of McDermott Will & Emery LLP designed to alert Group members to tax and regulatory developments concerning nuclear decommissioning funds. The memoranda do not constitute legal advice or a legal opinion on any specific facts or circumstances. ©Copyright 2017 by McDermott Will & Emery LLP.
LABOR FACTOR Base Labor Adjustment 4Q. '163 Current Labor (L) 1 Region Factor (Dec '05)2 (Dec. '05 Base) Adjustment Factor4 Northeast 2.16 128.7 2.78 South 1.98 126.2 2.50 Midwest 2.08 125.7 2.61 West 2.06 128.6 2.65
- 1. The regions consist of the following geographical areas:
Northeast -- Connecticut, Maine, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island and Vermont. South -- Alabama, Arkansas, Delaware, District of Columbia, Florida, Georgia, Kentucky, Louisiana, Maryland, Mississippi, North Carolina, Oklahoma, South Carolina, Tennessee, Texas, Virginia and West Virginia. Midwest -- Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, South Dakota and Wisconsin. West -- Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming.
- 2. The Base Labor Adjustment Factor (December 2005) is contained in column 2 of Table 3-2 of Draft NUREG 1307, Revision 16 (November 2016).
- 3. Values for 4Q 2016 used in this chart were obtained from the "Employment Cost Indexes," published by the U.S. Department of Labor, Bureau of Labor Statistics. Specifically, regional data from Table 6 entitled "Employment Cost Index, for total compensation, for private industry workers, by bargaining status, census region and division and area," has been used. Appendix C to Draft NUREG 1307, Revision 16 (November 2016) states that the requisite information can be obtained on the internet by entering the following URL:
http://www.bls.gov/data/; then clicking on the item labeled "Series Report;" and then entering into the box labeled "Enter series id(s) below," the following four series ids, one id per line: CIU2010000000210I (Total compensation, private industry, Northeast region) CIU20100000002201 (Total compensation, private industry, South region) CIU20100000002301 (Total compensation, private industry, Midwest region) CIU2010000000240I (Total compensation, private industry, West region)
- 4. As discussed in Section 3.1 of Draft NUREG-13 07, Revision 16 (November 2016), the Current Labor Adjustment Factor (L) may be calculated for each region by multiplying the Base Labor Adjustment Factor (December 2005) by the current Employment Cost Index (column 2 above by column 3 above) and then dividing by the reference 100.
500 North Capitol Street, N.W. Washington, D.C. 20001 Tel: 202.756.8000 Fax: 202.756.8087
ENERGY FACTOR P (Dec. '16) IP (Jan. '86) 1 F (Dec. '16) IF (Jan. '86) 1 PWR2 BWR3 215.0/114.2 = 1.883 152.0/82.0 = 1.854 1.870 1.869
- 1. Values for the January 1986 reference data were obtained from Section 3.2 of Draft NUREG-1307, Revision 16 (November 2016). Values for December 2016 for electric power (P) and fuel oil (F) were obtained from the Producer Price Indexes (PPI), available in the "PPI Detailed Report," published by the U.S. Department of Labor, Bureau of Labor Statistics, P is taken from data for industrial electric power (PPI Commodity code 0543), and Fis taken from data for light fuel oils (PPI Commodity code 0573). The values are preliminary and are subject to final adjustment up to four months after original publication.
Appendix C to Draft NUREG 1307, Revision 16 (November 2016) states that the requisite information can be obtained on the internet by entering the following URL: http://www.bls.gov/data/; then clicking on the item labeled "Series Report;" and then entering into the box labeled "Enter series id(s) below," one id per line. The series ids are wpu0543 (industrial electric power) and wpu0573 (light fuel oils).
- 2. E (PWR) = 0.58P + 0.42F. See Section 3.2 ofDraftNUREG-1307, Revision 16 (November 2016).
- 3. E (BWR) = 0.54P + 0.46F. See Section 3.2 of Draft NUREG-1307, Revision 16 (November 2016).
WASTE BURIAL FACTOR6 PWR BWR Washington7 Compact-Affiliated 8.706 7.290 Combination 8.129 6.668 South Carolina8 Compact-Affiliated 30.061 26.329 Combination 10.971 12.111 Texas Compact-Affiliated 8.508 8.293 Combination 10.672 10.441 Unaffiliated/No Disposal Facility 12.471 13.132 DM_US 79711756-2.061735.0011 6 See Table 2-1 of Draft NUREG 1307, Revision 16 (November 2016). 7 Effective January 1, 1993, the Washington site is not accepting waste from outside the Northwest and Rocky Mountain Compacts. 8 Effective July 1, 2000, different price schedules at the South Carolina burial site apply for states within and outside the Atlantic Compact.
McDermott Will&Emery Boston Brussels Chicago Dallas DOsseldorf Frankfurt Houston London Los Angeles Miami Milan Munich New York Orange County Paris Rome Seoul Silicon Valley Washington, D.C. Strategic alliance with MWE China Law Offices (Shanghai) MEMORANDUM March 13, 2017 NRC Issues Final NUREG-1307 (Revision 16) In our mailing dated February 27, 2017, we provided certain background information and data necessary for a nuclear licensee to update the "minimum financial assurance amount" for decommissioning a nuclear unit, as- required by the Nuclear Regulatory Commission (NRC). With respect to the burial escalation factors cited in the February 27, 2017 mailing, the factors were taken from the Draft NRC NUREG-1307 (Revision 16), which was published in November 2016. On March 7, 2017, the NRC finalized NUREG-1307 (Revision 16), and the burial factors in the final NUREG-1307 (Revision.16) did not change from the burial factors cited in the draft NUREG-1307 (Revision 16). Attached is a copy of our February 27, 2017 mailing with the factors necessary to calculate the NRC minimum financial assurance amount. For additional information regarding the foregoing, please contact Marty Pugh at 202-756-8368 or at mpugh@mwe.com or Gale Chan at 202-756-8052 or gchan@mwe.com. Memoranda to the Utility Decommissioning Tax Group are periodic publications of McDermott Will & Emery LLP designed to alert Group members to tax and regulatory developments concerning nuclear decommissioning funds. The memoranda do not constitute legal advice or a legal opinion on any specific facts or circumstances. ©Copyright 2017 by McDermott Will & Emery LLP. DM_US 80438421-1.061735.0011 500 North Capitol Street, N.W. Washington, D.C. 20001 Tel: 202. 756.8000 Fax: 202.756.8087}}